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Home My WebLink About20133080.tiffSTATE OF COLORADO John W. Hickenlooper, Governor Christopher E. Urbina, MD, MPH Executive Director and Chief Medical Officer Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr. S. Denver, Colorado 80246-1530 Phone (303) 692-2000 Located in Glendale, Colorado http://www.cdphe.state.co.us Weld County Clerk & Recorder 1402 N 17th Ave Greeley, CO 80631 October 23, 2013 Laboratory Services Division 8100 Lowry Blvd. Denver, Colorado 80230-6928 (303) 692-3090 Colorado Department of Public Health and Environment RECEIVED WELD COUNTY COMMISSIONERS Dear Sir or Madam: On October 25, 2013, the Air Pollution Control Division will publish a public notice for DCP Midstream, LP — Lucerne Natural Gas Processing Plant, in The Denver Post. A copy of this public notice and the public comment packet are enclosed. Thank you for assisting the Division by posting a copy of this public comment packet in your office. Public copies of these documents are required by Colorado Air Quality Control Commission regulations. The packet must be available for public inspection for a period of thirty (30) days from the date the public notice is published. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health & Environment APCD-SS-B 1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure ono) 0;6 Alt IDLI tiU 2013-3080 Colorado Department of Public Health and Environment Air Pollution Control Division Stationary Sources Program Public Notice of a Proposed Project or Activity Warranting Public Comment Website Title: DCP Midstream, LP — Lucerne Natural Gas Processing Plant — Weld County Applicant: DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Facility: Lucerne Natural Gas Processing Plant 31495 Weld County Road 43 Greeley, CO 80631 NOTICE is hereby given that a Major NSR Construction Permit Application has been submitted to the Colorado Air Pollution Control Division (the Division), 4300 Cherry Creek Drive South, Denver, Colorado 80246-1530, for the following source of air pollution: DCP Midstream, LP has applied for a Major New Source Review (NSR) Construction Permit for the Lucerne Natural Gas in Weld County, CO. This facility is an existing natural gas processing plant. This facility is an existing natural gas processing plant requesting an expansion of eight (8) new permitted sources including two (2) turbines, one (1) hot oil heater, one (1) amine sweetening unit, one (1) TEG glycol dehydrator, condensate storage tanks, condensate truck loadout and associated fugitive component emissions. This project is a Prevention of Significant Deterioration (PSD) major modification for greenhouse gas emissions only. No innovative control technology systems were identified for this project. An impact analysis for pollutants/averaging periods with PSD increments was not conducted since this project is not a major modification for any pollutants with established PSD increments. No comments regarding visibility, AQRVs or increment consumption were received from the Federal Land Managers during their review period specified in Colorado Regulation No. 3, Part D, Section XIII.A. The Division has determined that the proposed activities will show compliance with all applicable Colorado Air Quality Control Commission (AQCC) regulations and ambient air quality standards, and proposes to approve and issue the permit as described in this notice. A copy of the permit application and accompanying data, the Division's analysis, and a draft of Permit Number 12WE2024 have been filed with the Weld County Clerk's office. This material is also available for inspection at the Division's office. A copy of the draft permit and the Division's analysis are available on the Division's website at www.colorado.qov/cdphe/AirPublicNotices. The Division hereby solicits and requests submission of public comments concerning the aforesaid proposed project and activity for a period of thirty (30) days after the date of this publication. Comments are solicited on: 1. The ability of the proposed project/activity to comply with the applicable standards, regulations and requirements 2. The sufficiency of the preliminary analysis 3. The control technology required for the source or modification 4. Alternatives to the source or modification 5. Any other appropriate air quality considerations 6. Whether the permit application should be approved or denied Any such comment must be in writing and must be submitted to the following addressee: Stephanie Chaousy Colorado Department of Public Health and Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Interested persons may obtain information from the Division contact listed above at 303-692-2297. Within thirty (30) days following the thirty (30) -day period for public comment, the Division shall consider comments and, pursuant to Section 25-7-114.5(7)(a), either grant, deny, or grant with conditions, the emission permit. Public comment is solicited to enable consideration of approval of and objections to the proposed project or activity by affected persons. In addition to written public comments, any interested person may submit a written request for a public comment hearing to be held by the AQCC, with regard to the PSD modification. The hearing would be held pursuant to section VII of the AQCC's procedural rules to receive comments regarding the sufficiency of the preliminary analysis and whether the Division should approve or deny the permit application. If requested, the hearing will be held before the AQCC within sixty days of its receipt of the request unless a longer time period is agreed upon by the Division and the applicant, but at least sixty days after receipt by any Federal Land Manager of notice and the permit application required pursuant to Regulation 3, Part D, Section XIII.A. The Division will receive and consider the written public comments and requests for any hearing for thirty calendar days after the date of this Notice. RELEASED TO: The Denver Post on PUBLISHED: October 25, 2013 October 23, 2013 STATE OF COLORADO COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION TELEPHONE: (303) 692-3150 PERMIT NO: 12WE2024 CONSTRUCTION PERMIT Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Lucerne 2 Expansion Project at the Lucerne Gas Processing Plant, located in 31495 WCR 43, Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility Equipment ID AIRS Point Description TURB-1 044 One (1) natural gas fired combustion turbine (Solar Model Taurus 70 serial number: TBD), equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit (WHRU) System. This combustion turbine is used to power a compressor. TURB-2 045 One (1) natural gas fired combustion turbine (Solar Model Taurus 70, serial number: TBD), equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit (WHRU) System. This combustion turbine is used to power a compressor. HT -02 046 Hot oil heater (Optimized Process Furnaces, Inc., model, serial number: TBD), equipped with low NOx burners. The heater is design rated at a heat input of 50 MMBtu/hr. This heater is fueled by natural gas and used to supplement the waste heat recovery unit (WHRU) provided from Points 044 and 045. AIRS ID: 123/0107 Page 1 of 44 NGEngine Version 2009-1 Public Health and Environment Air Pollution Control Division Facility Equipment ID AIRS Point Description AU -02 047 One (1) methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf per day (make, model, serial number: TBD). This emissions unit is equipped with electric amine recirculation pumps with a total limited capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, reflux condenser, a flash tank, still vent and an indirect -fired hot oil (or waste heat from the WHRUs) amine regeneration reboiler (point 046). The amine flash stream is routed to a closed loop system that utilizes a vapor recovery unit (maximum 1% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The acid gas stream from the still vent condenser outlet is routed to a regenerative thermal oxidizer (Anguil, Model 100, SN: TBD) rated at 10,000 scf/min. Destruction efficiency for the RTO is a minimum of 96% for VOC and 99% for CH4. D-01 048 One (1) triethylene glycol (TEG) dehydrator unit with a design capacity of 230 MMscf/day (make, model, serial number: TBD). This emissions unit is equipped with two (2) electric glycol pumps with a limited total combined capacity of 40 gallons per minute. This system includes a BTEX condenser, reboiler, still vent, and a flash tank. The flash gas is routed to a closed loop system that utilizes a vapor recovery unit (maximum 1% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The still vent emissions are routed to a condenser and then to an enclosed combustor with a minimum destruction efficiency of 95%. TANKS 050 Four (4) stabilized atmospheric condensate storage tanks. Eachtank has a capacity of 1000 bbl. Emissions are routed to an enclosed combustor with a minimum destruction efficiency of 95%. LOAD 051 Condensate truck loading. Emissions from the loadout will be controlled by an enclosed combustor with a minimum destruction efficiency of 95%. FUG 052 Fugitive emission component leaks from a natural gas processing plant associated with the expansion project. Points 044 and 045 may be replaced with another like -kind turbine in accordance with the temporary turbine replacement provision or with another Solar Model Taurus 70 turbine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S. (25-7-101 et seq), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: v AIRS ID: 123/0107 Page 2 of 44 Public Health and Environment Air Pollution Control Division REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION 1. YOU MUST notify the APCD no later than fifteen days after commencement of the permitted operation or activity by submitting a Notice of Startup (NOS) form to the APCD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, III.G.2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, II I. F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self -certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self -certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly' Limits: Facility Equipment ID AIRS Point Pounds per Month Tons per Month Emission Type N0x S02 VOC CO PM2.5 H2S C02e2 TURB-1 044 2,552 184 114 2,991 357 -- 3,590 Point TURB-2 045 2,552 184 114 2,991 357 -- 3;590 Point AIRS ID: 123/0107 Page 3 of 44 Dept=-trentcPublic Health and Environment Air Pollution Control Division AU -02 047 85 5,352 1,181 462 -- 118 13,106 Point D-01 048 155 -- 3,262 131 -- -- 444 Point TANKS 050 16 -- 408 13 -- -- 23 Point LOAD 051 16 -- 392 14 -- -- Point FUG 052 -- -- 2,939 -- -- -- 17 Fugitive 1: Monthly limits are based on a 31 -day month. 2: CO2e is carbon dioxide equivalent in tons per year. CO2e is the total sum of the mass of each greenhouse gas emission multiplied by global warming potential for each greenhouse gas. The greenhouse gas emissions from these sources include CO2, CH4 and N2O. Facility -wide emissions of each individual hazardous air pollutant shall be less than 1,359 lb/month. Facility -wide emissions of total hazardous air pollutants shall be less than 3,904 lb/month. Quarterly3 Limits: Facility Equipment ID AIRS Point Pounds per Quarter' Tons per Quarter Emission Type NOx SO2 VOC CO PM2.5 H2S CO2e2 HT -02 046 2971 50 454 6,742 400 -- 5,160 Point 3: Quarterly limits are established beginning with the calendar month of permit issuance. For the first twelve (12) months of operation, monthly emissions from the three calendar months of a quarter shall be summed to demonstrate compliance with the quarterly emission for AIRS Point 046 as well as the annual limitations. After the first twelve (12) months of operation, the operator shall calculate monthly emissions to demonstrate compliance with the annual limits and to maintain the 12 -month rolling total. Annual Limits: Facility Equipment ID AIRS Point Tons per Year Emission Type NOx SO2 VOC CO PM2.5 H2S CO2e2 TURB-1 044 15.0 1.1 0.7 17.6 2.1 -- 42,268 Point TURB-2 045 15.0 1.1 0.7 17.6 2.1 -- 42,268 Point HT -02 046 5.8 0.1 0.9 13.2 0.8 -- 20,250 Point AU -02 047 0.5 31.5 7.0 2.7 -- 0.7 154,337 Point D-01 048 0.9 -- 19.2 0.8 -- -- 5,230 Point AIRS ID: 123/0107 Page 4 of 44 IoraDep Public Health and Environment Air Pollution Control Division TANKS 050 0.1 -- 2.4 0.1 - 275 Point LOAD 051 0.1 -- 2.3 0.1 -- -- --- Point FUG 052 -- -- 17.3 -- -- -- 200 Fugitive See Notes " to Permit Holder #4 for information on emission factors and me calculate limits. Facility -wide emissions of each individual hazardous air pollutant shall be less than 8.0 tpy. Facility -wide emissions of total hazardous air pollutants shall be less than 22.9 tpy. During the first twelve (12) months of operation, compliance with both the monthly, quarterly and yearly emission limitations is required. After the first twelve (12) months of operation, compliance with only the yearly limitation is required. Compliance with the emission limits in this permit shall be determined by recording the facility's annual criteria pollutant and greenhouse gases (GHG) emissions, (including all HAPs above the de-minimis reporting level) from each emission unit, on a rolling (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. 8. The owner or operator shall track emissions from all insignificant activities at the facility on an annual basis to demonstrate compliance with the facility emission limitations as seen below. An inventory of each insignificant activity and associated emission calculations shall be made available to the Division for inspection upon request. For the purposes of this condition, insignificant activities shall be defined as any activity or equipment, which emits any amount but does not require an Air Pollutant Emission Notice (APEN). Total emissions from the facility, including permitted emissions units and insignificant activities, shall not exceed: 25 tons per year of total hazardous air pollutants (HAP). 9. Points 044 and 045: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from fuel gas combustion using equation C -2a in 40 CFR Part 98 Subpart C, CO2 emission factor listed in the Notes to Permit Holder, measured actual heat input (HHV), and measured actual monthly fuel flow volume. 10. Points 044 and 045: The owner or operator shall calculate CH4 and N2O emissions from fuel gas combustion on a monthly basis using equation C -9a of 40 CFR Part 98 Subpart C, CH4 emission factor provided in the Notes to Permit Holder, default N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly fuel flow volume. A complete record of the methods used, the measurements made, and the calculations performed to quantify monthly fuel flow volume shall be kept. AIRS ID: 123/0107 Page 5 of 44 t 11. Point 046: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from fuel combustion using equation C -2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in Table C-1, measured actual heat input (HHV), and measured actual monthly fuel flow volume. Public Health and Environment Air Pollution Control Division 12. Point 046: The owner or operator shall calculate CH4 and N2O emissions from fuel combustion on a monthly basis using equation C -9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly fuel flow volume. A complete record of the methods used, the measurements made, and the calculations performed to quantify monthly fuel flow volume shall be kept. 13. Point 047: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from fuel combustion, combustion of flash tank emissions during VRU downtime, and combustion of the acid gas stream from the still vent using equation C -2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in Table C-1, measured actual heat input (HHV), and measured actual monthly fuel and waste gas flow volumes. 14. Point 047: The owner or operator shall calculate CH4 and NZO emissions from fuel combustion, combustion of the flash tank stream during VRU downtime and combustion of the acid gas stream from the still vent on a monthly basis using equation C -9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly fuel and waste gas flow volumes. A complete record of the methods used, the measurements made, and the calculations performed to quantify monthly fuel and waste gas volumes shall be kept. 15. Points 044, 045, 046 and 047: The owner or operator shall calculate the CO2e emissions based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 16. Point 047: The owner or operator shall calculate CO2 emissions from acid gas sweetening, on a monthly basis, using equation W-3 consistent with 40 CFR Part 98, Subpart W [98.233(d)(2)] along with the most recent measured gas composition of the amine flash tank stream during VRU downtime, most recent measured gas composition of the acid gas stream from the still vent, monthly measured flow volume of amine flash tank stream during VRU downtime, and monthly measured flow volume of acid gas stream from the still vent. 17. Point 047: Total CO2e emissions from the RTO shall be based on the sum of GHG emissions from fuel combustion, combustion of the amine flash tank stream during VRU downtime and combustion of the acid gas stream from the still vent, calculated as per Conditions 13, 14 and 15, plus CO2 emissions from the amine unit acid gas sweetening as calculated per Condition 16. The sum total of CO2e emissions generated from combustion and generated from the amine unit acid gas sweetening shall be compared to the CO2e limits listed in this section above to demonstrate compliance. 18. Point 047: The owner or operator shall calculate uncontrolled VOC, H2S and CH4 emissions on a monthly basis using the most recent measured gas composition of the AIRS ID: 123/0107 Page 6 of 44 Public Health and Environment Air Pollution Control Division amine flash tank stream during VRU downtime, most recent measured gas composition of the acid gas stream from the still vent, monthly measured flow volume of amine flash tank stream during VRU downtime, and monthly measured flow volume of acid gas stream from the still vent. A control efficiency of 96% for VOC and H2S and 99% for CH4, based on maintaining the minimum temperature requirements specified in Condition 30.w), shall be applied to the uncontrolled emissions. 19. Point 047: Emissions from the amine flash tank are routed to a closed loop vapor recovery system back to the plant inlet equipped with a vapor recovery unit (VRU) (1% maximum allowable downtime). During the VRU downtime, emissions generated shall be routed to the flare. Emissions from the still vent shall be collected and controlled by a regenerative thermal oxidizer in order to reduce the emissions of volatile organic compounds, H2S and hazardous air pollutants to the level listed in this section, above. Operating parameters of the regenerative thermal oxidizer are identified in the operation and maintenance plan for this unit. (Reference: Regulation No.3, Part B, Section III.E.) 20. Point 048: The owner or operator shall calculate CO2 and CH4 emissions, on a monthly basis, using GRI-GLYCalc consistent with 40 CFR Part 98, Subpart W [98.233(e)(1)] along with the most recent results from the extended wet gas analysis as required by this permit. 40 CFR Part 98, Subpart W [98.233(e)(1)]. 21. Points 048, 050 and 051: The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The minimum destruction efficiency of this enclosed combustor shall be 95%. 22. Point 048: Compliance with the VOC emission limits in this permit shall be demonstrated by running the GRI GlyCalc model version 4.0.or higher on a monthly basis using the most recent wet gas analysis and recorded operational values (including gas throughput, lean glycol recirculation rate, and other operational values specified in the O&M Plan). Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into GRI GlyCalc and be provided to the Division upon request. 23. Points 050 and 051: Emissions from the condensate tanks and loadout shall be collected and controlled by an enclosed combustor in order to reduce the emissions of volatile organic compounds to the level listed in this section, above. Operating parameters of the enclosed combustor are identified in the BACT requirements in Condition 30. 24. Point 051: All loading operations shall occur in vapor balance service, such that all tanker truck vapors are routed to and controlled by the enclosed combustor. The vapor return hose shall be connected at all times during loading operations. (Reference: Regulation No. 3, Part B, Section III.E.) 25. Point 052: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas analyses, as required in the Compliance Testing and Sampling section of this permit. AIRS ID: 123/0107 Page 7 of 44 ent c .Public Health and Environment Air Pollution Control Division The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that thesecounts and events were completed. These records shall be provided to the Division upon request. PROCESS LIMITATIONS AND RECORDS 26. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Equipment ID AIRS Point Process Parameter Annual Limit Quarterly4 Limits HT -02 046 Natural Gas Combusted 315 MMscf/yr 80.26 MMscf/quarter 4: Quarterly limits will be established beginning with the calendar month of permit issuance. Facility Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limits (31 days) TURB-1 044 Natural Gas Combusted 637.9 MMscf/yr 54.2 MMscf/month TURB-2 045 Natural Gas Combusted 637.9 MMscf/yr 54.2 MMscf/month AU -02 047 Natural Gas Throughput 83,950 MMscf/yr 7,130 MMscf/month D-01 048 Natural Gas Throughput 83,950 MMscf/yr y 7,130 MMscf/month TANKS 050 Condensate Throughput 456,250 bbl/yr 38,750 bbl/month LOAD 051 Condensate Loading 456,250 bbl/yr 38,750 bbl/month During the first twelve (12) months of operaton, compliance with both the monthly, quarterly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the yearly process limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate, monitor, and record monthly natural gas combusted, processed, and condensate throughput and keep a compliance record on site or at a local field office with site responsibility, for Division review. 27. Point 047: This unit shall be limited to a maximum lean amine recirculation pump rate of 945 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4). AIRS ID: 123/0107 Page 8 of 44 Deptment Public Health and Environment 1 Air Pollution Control Division F 0 020 28. Point 048: This source shall be limited to a maximum lean glycol recirculation pump rate as calculated per 40 CFR, Part 63, Subpart HH, §63.764 (d)(2)(i). If the owner or operator requests an alternate circulation rate per §63.764(d)(2)(ii) or an exemption per §63.764(e), then the maximum recirculation rate shall not exceed 40 gallons per minute. The owner or operator shall maintain daily records of the actual lean glycol recirculation rate and make them available to the Division for inspection upon request. 29. Points 047 and 048: The owner or operator shall monitor and record VRU downtime for each emission point. VRU downtime shall be defined as times when the flash gas from the amine unit and the dehydrator are routed to the flare rather than the VRU. The total hours of downtime and volume of gas processed during VRU downtime shall be recorded on a monthly basis. The operator shall demonstrate VRU downtime for each emission point does not exceed 1% of total operational hours and total volume of gas processed on a rolling 12 month total basis. BEST AVAILABLE CONTROL TECHNOLOGY (BACT) REQUIREMENTS 30. The equipment and activities at this facility are subject to the requirements of the Prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Greenhouse Gases (GHG). BACT is determined to be as follows: a. For purposes of BACT, total CO2e emissions from the emission units covered under this permit shall not exceed the annual emission limits contained in condition 7, based on a rolling twelve month total. Turbines b. Points 044 and 045: The turbines shall be equipped with waste heat recovery units (WHRU) to increase the efficient use of waste heat for process heating. c. Points 044 and 045: Fuel for the turbines shall be limited to natural gas with a maximum fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the turbines shall be sampled initially and at least once per every six months as required in Conditions 56 and 69 to determine the fuel gross calorific value (GCV) [high heat value (HHV)]. d. Points 044 and 045: The owner or operator shall install and maintain an operational continuous fuel flow monitor for each turbine at the inlet. Flow measurements must be taken at least once every 15 minutes. Electronic data may be reduced to hourly averages for recordkeeping purposes. The fuel flow monitors shall be calibrated at a minimum frequency of at least once every twelve months and shall be used to measure and record the volume of fuel combusted by each turbine. e. Points 044 and 045: The owner or operator shall install monitoring equipment to measure oil flow rate and inlet and outlet temperature on the hot oil system that uses the recovered heat from the WHRUs system. The oil flow rate and inlet and outlet temperature on the hot oil system shall be recorded on a daily basis. AIRS ID: 123/0107 Page 9 of 44 f. g. ent d€:;;Public Health and Environment Air Pollution Control Division Points 044 and 045: The combustion turbines and the WHRUs system shall meet a BACT limit of 40% minimum thermal efficiency on a 12 -month rolling average basis. Points 004 and 045: Compliance with the BACT limit will be based on the following equations, calculated each day of operation using data collected for Conditions 30 (c), (d), and (e): Equation 1: [Turbine Energy Output + WHRU Energy Recovered] Thermal of iciency (%) = x 100% Total Thermal Energy Input Where: Equation 2: Turbine Energy Output [MMBtuj [ hr 2,544 Btul I[1 MMBtui = [Turbine 1 Power (hp) + Turbine 2 Power (hp)] x [ h hr J x [ 10 Btu J p_106 Btu Turbine power is a measured value. Equation 3: WHRU Energy Recovered [MMBtuI L hr l = Oil Flowrate (hr) x x [Oil Temp Out (°F) - 0.56 Btu Oil Heat Capacity I. lb °F [ 1 MMBtui Oil Temp In (°F)] x [ 106 Btu J Note: Oil heat capacity is from Xceltherm 600 Data Sheet. Equation 4: MMBtu1 MMscf MMBtu Total Thermal Energy Input [NI hr I — Total Turbine Fuel Flow ( hr ) x Fuel LHV ( MMscf) h. Points 044 and 045: All monitors identified in Conditions 30 (d) and (e) shall achieve 95% operational time or greater on a daily average basis. Points 044 and 045: Tune-ups and maintenance shall be required annually for the life of the turbines. The owner or operator shall maintain records of the tune-ups and maintenance activities and implement the manufacturer's recommended comprehensive inspection and maintenance program to comply with this condition. Heater Point 046: The heater shall be limited to a maximum natural gas input rate of 315 MMscf per year on a 12 -month rolling total. AIRS ID: 123/0107 Page 10 of 44 k. Public Health and Environment Air Pollution Control Division Point 046: Fuel for the heater shall be limited to natural gas with a maximum fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the heater shall be sampled initially and at least once per every six months as required in Conditions 56 and 69 to determine the fuel gross calorific value (GCV) [high heat value (HHV)]. Point 046: The owner or operator shall install and maintain an operational continuous fuel flow monitor for the heater. Flow measurements must be taken at least once every 15 minutes. Electronic data may be reduced to hourly averages for recordkeeping purposes. The flow monitor shall be calibrated at a minimum frequency of at least once per every twelve months and shall measure and record the volume of the fuel combusted in this natural gas -fired combustion emission unit. m. Point 046: The heater shall be equipped with low-NOx staged/quenching (flue gas recirculating) burners with burner management systems that include intelligent flame ignition and flame intensity controls or of like -kind approved by the Division. n. Point 046: The heater shall be tuned for thermal efficiency at a minimum frequency of at least once per every twelve months. o. Point 046: The owner or operator shall perform cleaning of the burner tips, at a minimum of, once per every twelve months. p. Point 046: The owner or operator shall install, operate, and maintain an automated air/fuel control system which is part of the burner management system. q. Point 046: The owner or operator shall calibrate and perform preventative maintenance on the air/fuel control analyzer at least once per every three months, at a minimum. r. Point 046: Tune-ups and maintenance shall be required annually for the life of the heater. The owner or operator shall maintain records of the tune-ups and maintenance activities to comply with this condition. s. Point 046: The owner or operator shall utilize insulation materials (e.g. ceramic fiber blankets and KaoliteT) where feasible to reduce heat loss. Amine unit and regenerative thermal oxidizer t. Point 047: The amine flash tank stream shall be routed to a closed loop vapor recovery unit and back to the plant inlet at all times, during amine unit operation. A maximum 1% downtime (based on total gas treated on a rolling 12 month total) is allowable. During VRU downtime flash tank emissions shall be routed to the flare. A minimum 99% control of the flash tank emissions by the VRU system is required. u. Point 047: The still vent emissions from the amine unit shall be collected and routed to a regenerative thermal oxidizer for combustion. The regenerative AIRS ID: 123/0107 Page 11 of 44 lora'1kVDep�t' te'e'n Public ° Health and Environment ALAI. lri Air Pollution Control Division thermal oxidizer shall have a minimum destruction and removal efficiency of methane (CH4) of 99%. v. Point 047: The thermal oxidizer shall have an initial stack test and on -going compliance testing to verify destruction and removal efficiency of at least 99% for CH4. w. Point 047: The combustion temperature of the regenerative thermal oxidizer used to control emissions from the amine unit still vent shall be greater than 1550 °F, or the temperature established during the most recent stack test of the equipment that was approved by the Division. The approved minimum operating temperature shall be maintained at all times that any amine unit emissions are routed to the regenerative thermal oxidizer in order to meet the emission limits in this permit. x. Point 047: The regenerative thermal oxidizers' combustion temperature shall be continuously monitored and recorded when amine unit still vent is directed to the oxidizer. The temperature measurement devices shall reduce the temperature readings to an averaging period of 6 minutes or less and record it at that frequency. Y. Point 047: The owner or operator shall install and maintain a temperature recording device with an accuracy of the greater of ±0.75 percent of the temperature being measured expressed in degrees Fahrenheit or ±4.5°F. z. Point 047: Waste gas from the still vent and flash gas streams of the amine unit will be sampled and analyzed initially and at least once every three months for composition as specified in Conditions 59 and 71. The sample data will be used to calculate GHG emissions as specified in Condition 16. aa. Point 047: The volumetric flow rate of the waste gas (acid gas stream from the still vent) combusted shall be measured and recorded using an operational continuous fuel flow monitor at the inlet to the regenerative thermal oxidizer. The owner or operator shall operate and calibrate the flow monitor in accordance with §98.3(i). bb. Point 047: For burner combustion fuel, the volume of natural gas fuel usage (scf) shall be measured and recorded using an operational continuous fuel flow monitor at the regenerative thermal oxidizer. cc. Point 047: The flash tank stream volume routed to the flare during VRU downtime shall be measured and recorded using an operational continuous flow monitor at the flare. dd. Point 047: Periodic maintenance shall be completed to maintain the efficiency of the regenerative thermal oxidizer and shall be performed at a minimum of once per every twelve months or more often as recommended by the manufacturer specifications. ee. Point 047: An oxygen analyzer shall continuously monitor and record oxygen concentration when acid gas stream from the still vent is directed to the regenerative thermal oxidizer. It shall reduce the oxygen readings to an AIRS ID: 123/0107 Page 12 of 44 ii. 'r Public Health and Environment Air Pollution Control Division averaging period of 6 minutes or less and record it at that frequency, except during periods of downtime, as defined in 40 CFR §60.7 (d)(1). ff. Point 047: The oxygen analyzer shall be quality -assured at least once every six months using cylinder gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 5.1.2, with the following exception: a relative accuracy test audit is not required once every four quarters (i.e., two successive semiannual CGAs may be conducted). The CGAs must be performed at least thirty (30) days apart. Records of the CGAs shall be kept on site and made available to the Division for inspection upon request. Dehydrator and enclosed combustor gg. Point 048: The dehydrator flash stream shall be routed to a closed loop vapor recovery unit (VRU) at all times, during dehydrator operation. A maximum 1% downtime (based on total gas treated on a rolling 12 month total) is allowable. During VRU downtime flash tank emissions shall be routed to the flare. A minimum 99% control of the flash tank emissions by the VRU is required. hh. Point 048: The still vent emissions from the dehydration unit shall be collected and routed through a condenser then controlled by an enclosed combustor. The enclosed combustor shall have a minimum removal and destruction efficiency of methane (CH4) of 95%. ii. Point 048: The condenser outlet temperature shall be recorded as per the frequency required in the approved O&M Plan. This information shall be maintained in a log on site and made available to the Division for inspection upon request. The condenser outlet temperature shall not exceed 145 °F on a monthly average basis. • Point 048: The enclosed combustor shall be operated with a pilot flame present at all times. The presence of a flame in the enclosed combustor shall be continuously monitored with a thermocouple. The ignition system shall send a remote alarm during pilot light outages and be capable of automatically relighting the pilot. Manual ignition of the pilot shall also be possible. kk. Point 048: The enclosed combustor shall be operated with zero visible emissions. An EPA Method 22 shall be conducted daily to monitor compliance with this condition. Fugitives II. Point 052: The owner or operator shall implement the leak detection and repair (LDAR) requirements in New Source Performance Standards of Regulation No. 6, Part A, Subpart OOOO for fugitive emissions of methane. 31. The owner or operator shall maintain the following records for a period of 5 years: a. Operating hours for all emission sources. b. The volume natural gas fuel usage for all combustion sources. This shall include data obtained from continuous fuel flow monitors as well as a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage from unit not equipped with continuous fuel flow monitors. AIRS ID: 123/0107 Page 13 of 44 Mora 1 Depi itrrient c Public Health and Environment -- ` Ia"r' D Air Pollution Control Division c. Annual fuel gas sampling results, quarterly waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) sampling. d. Leak detection and repair (LDAR) program monitoring results, as well as the repair and maintenance records. e. Records, data, measurements, reports, and documents related to the operation of the facility that are required by specific Conditions in this permit, including, but not limited to, the following: all records or reports pertaining to significant maintenance performed on any system or device at the facility; the occurrence and duration of any startup, shutdown, or malfunction, annual tuning of heaters; all records relating to performance tests and monitoring of combustion equipment; calibrations, checks, duration of any periods during which a monitoring device is inoperative, and corresponding emission measurements; and all other information required by this permit recorded in a permanent form suitable for inspection. f. All records required by this Permit shall be retained for not less than 5 years following the date of such measurements, maintenance, and reports. STATE AND FEDERAL REGULATORY REQUIREMENTS 32. The requirements of Colorado Regulation No. 3, Part D shall apply at such time that any modification becomes a major modification solely by virtue of a relaxation in any enforceable limitation that was established after August 7, 1980, on the capacity of the source or modification to otherwise emit a pollutant such as a restriction on hours of operation (Colorado Regulation No. 3, Part D, Section V.A.7.B). With respect to this Condition, Part D requirements may apply to future modifications if emission limits for the following emission units are modified to equal or exceed the following threshold levels. Increases in permit limits for any of these emissions units will require evaluation of the original project net emissions increase to ensure the significant modification thresholds are not exceeded: Facility Equipment ID AIRS Point Equipment Description Pollutant Emissions — tons per year Threshold Current Limit TURB-1 044 Combustion Turbine TURB-2 045 NOx 40 37.4 HT -02 046 Hot Oil Heater VOC 40 33.1 AU -02 047 Amine Unit H2S 10 0.7 0-01 048 TEG Dehy TANKS 050 Condensate tanks AIRS ID: 123/0107 Page 14 of 44 Public Health and Environment Air Pollution Control Division LOAD 051 Condensate loadout 33. The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable). 34. Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. (Reference: Regulation No. 1, Section ll.A.1. & 4.) 35. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 36. Points 044 and 045: The combustion turbines are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart KKKK, Standards of Performance for Stationary Combustion Turbines including, but not limited to, the following: • §60.4320 — Nitrogen Oxide Emissions Limits o (a) NOx emissions shall not exceed 25 ppm at 15% O2 or 1.2 Ib/MW-hr; • §60.4330 - Sulfur Dioxide Emissions Limits o (a)(1) SO2 emissions shall not exceed 0.9 lb/MW-hr gross output; or o (a)(2) Operator shall not burn any fuel that contains total potential sulfur emissions in excess of 0.060 lb SO2/MMBtu heat input. §60.4333 — General Requirements o (a) Operator must operate and maintain your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown and malfunction. §60.4340 — NO, Monitoring o (a) Operator shall perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance with NOx emissions limits. §60.4365 (or §§60.4360 and 60.4370) - SO2 Monitoring o The operator shall comply with §60.4365 or with both §§60.4360 and 60.4370 to demonstrate compliance with SO2 emissions limits. §60.4375 — Reporting o (b) For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test. §§60.4400 and 60.4415 — Performance Tests o Annual tests must be conducted in accordance with §60.4400(a) and (b). AIRS ID: 123/0107 Page 15 of 44 DepMment Public Health and Environment Air Pollution Control Division o Unless operator chooses to comply with §60.4365 for exemption of monitoring the total sulfur content of the fuel, then initial and subsequent performance tests for sulfur shall be conducted according to §60.4415. 37. Points 044, 045 and 046: These units are subject to the Particulate Matter and Sulfur Dioxide Emission Regulations of Regulation 1 including, but not limited to, the following: a. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section III.A.1): For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)"oas Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. (1) b. The owner or operator shall not emit sulfur dioxide in excess of the following combustion turbine limitations. (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates). (Regulation 1, Section VI.B) (1) Points 044 and 045: Combustion Turbines with a heat input of less than 250 Million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input (Regulation 1, Section VI.B.4.c): (2) Point 046: Limit emissions to not more than two (2) tons per day of sulfur dioxide (Regulation 1, Section Vl.B.5.a) 38. Points 044, 045 and 046: These units are subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation 6, Part B, Section II): a: Standard for Particulate Matter — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-626 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. AIRS ID: 123/0107 Page 16 of 44 Public Health and Environment Air Pollution Control Division b. Standard for Sulfur Dioxide — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. 39. Points 044, 045, 046 and 052: The source is subject to the requirements of Regulation No. 6, Part A, Subpart A, General Provisions, including, but not limited to, the following: a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11) b. No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) c. Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. e. Performance tests shall be conducted as required under §60.8. 40. Point 046: These sources are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units including, but not limited to, the following: a. The owner or operator of the facility shall record and maintain records of the amount of fuel combusted during each month (40 CFR Part 60.48c(g)). b. Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record (40 CFR Part 60.48c(i)). 41. Point 047: The amine unit addressed by AIRS ID 047 is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365 — Applicability and Designation of Affected Facilities AIRS ID: 123/0107 Page 17 of 44 Public Health and Environment Air Pollution Control Division o §60.5365(g)(3) - Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). • §60.5423 — Record keeping and reporting Requirements o §60.5423(c) - To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less that 2 LT/D of H2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2 S expressed as sulfur. 42. Point 048: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XII 43. Point 048: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 44. Point 048: This source is subject to the TEG dehydrator area source requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: • §63.760 — Applicability and designation of affected source o (f) The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. • (4) The owner or operator of an affected area source, located in an Urban -1 county, as defined in §63.761, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the provisions of this subpart AIRS ID: 123/0107 Page 18 of 44 Public Health and Environment Air Pollution Control Division immediately upon initial startup or January 3, 2007, whichever date is later. • §63.764 - General Standards o (d)(2) Each owner or operator of an area source not located in a UA plus offset and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2(i) through (iii) of this section. • (i) Determine the optimum glycol circulation rate using the following equation: gal TEG * F*(/ —O) Lop =1:15*3.0 IbH2O (24hr/day Where: Lon- = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) I = Inlet water content (lb/MMSCF) O = Outlet water content (lb/MMSCF) 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/IbH2O) 1.15 = Adjustment factor included for a margin of safety. • (ii) Operate the TEG dehydration unit such that the actual glycol circulation rate does not exceed the optimum glycol circulation rate determined in accordance with paragraph (d)(2)(i) of this section. If the TEG dehydration unit is unable to meet the sales gas specification for moisture content using the glycol circulation rate determined in accordance with paragraph (d)(2)(i), the owner or operator must calculate an alternate circulation rate using GRI—GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). • (iii) Maintain a record of the determination specified in paragraph (d)(2)(ii) in accordance with the requirements in §63.774(f) and submit the Initial Notification in accordance with the requirements in §63.775(c)(7). If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph (d)(2)(i) or (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v). §63.774 - Recordkeeping Requirements o (b) Except as specified in paragraphs (c), (d), and (f) of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1) through (11) of this section: • (1) The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports and notifications) required by this subpart. The AIRS ID: 123/0107 Page 19 of 44 ent Public Health and Environment Air Pollution Control Division files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. • (i) All applicable records shall be maintained in such a manner that they can be readily accessed. • (ii) The most recent 12 months of records shall be retained on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. • (iii) The remaining 4 years of records may be retained offsite. • (iv) Records may be maintained in hard copy or computer - readable form including, but not limited to, on paper, microfilm, computer, floppy disk, magnetic tape, or microfiche. o (f) The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. • §63.775 — Reporting Requirements o (c) Except as provided in paragraph (c)(8), each owner or operator of an area source subject to this subpart shall submit the information listed in paragraph (c)(1) of this section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). (1) The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.9(a), you must also submit a copy of the initial notification to EPA's Office of Air Quality Planning and Standards. Send your notification via e-mail to CCG— ONG@EPA.GOV or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Coatings and Chemicals Group (E143—01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. • (7) The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. • (i) Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the names of the nearest urban cluster with 10,000 people or more and nearest urbanized area. AIRS ID: 123/0107 Page 20 of 44 ent 2 Public Health and Environment o II Air Pollution Control Division • (ii) Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i): • (iii) If applicable, documentation of the alternate glycol circulation rate calculated using GRI-GLYCalcTM, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. • (iv) The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. • (v) Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. o (f) Notification of process change. Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: • (1) A brief description of the process change; • (2) A description of any modification to standard procedures or quality assurance procedures (3) Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and (4) Information required by the Notification of Compliance Status Report under paragraph (d) of this section for changes involving the addition of processes or equipment. 45. Point 048: This unit is subject to the requirements in 40 CFR part 63 Subpart A "General Provisions", as adopted by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart HH § 63.764. These requirements include, but are not limited to the following: a. Prohibited activities and circumvention in § 63.4. b. Operation and maintenance requirements in § 63.6(e)(1). c. Notification requirements in § 63.9(j). d. Recordkeeping and reporting requirements in § 63.10(b), except as provided in § 63.774(b)(1). 46. Point 048: The combustion device used to control emissions of volatile organic compounds from these units to comply with Section XII.D shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from the outside of the enclosed combustion device, or by other means AIRS ID: 123/0107 Page 21 of 44 Iorgh \Dep,,1ment Peblic Health and Environment Air Pollution Control Division approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XII. (Reference: Regulation No. 7, Section XII.C.1.d.) 47. Point 048: The enclosed combustor covered by this permit is subject to Regulation No. 7, Section XVII.B General Provisions (State only enforceable). If a flare or other combustion device is used to control emissions of volatile organic compounds to comply with Section XVII, it shall be enclosed, have no visible emissions during normal operations, and be designed so that an observer can, by means of visual observation from the outside of the enclosed flare or combustion device, or by other convenient means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XVII. 48. The storage tanks covered under AIRS point 050 is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage . Vessels) for which Construction, Reconstruction, or Modification Commenced after July 23, 1984 including, but not limited to, the following: • 40 CFR, Part 60, Subpart A — General Provisions • §60.112b - Standard for volatile organic compounds (VOC) §60.112b(a) The owner or operator of each storage vessel either with a design capacity greater than or equal to 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa but less than 76.6 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa but less than 76.6 kPa, shall equip each storage vessel with one of the following: • §60.112b(a)(3) A closed vent system and control device meeting the following specifications: • §60.112b(a)(3)(i) The closed vent system shall be designed to collect all VOC vapors and gases discharged from the storage vessel and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background and visual inspections, as determined in part 60, subpart VV, §60.485(b). §60.112b(a)(3)(ii) The control device shall be designed and operated to reduce inlet VOC emissions by 95 percent or greater. If a flare is used as the control device, it shall meet the specifications described in the general control device requirements (§60.18) of the General Provisions. • §60.113b — Testing and procedures The owner or operator of each storage vessel as specified in §60.112b(a) shall keep records and furnish reports as required by paragraphs (a), (b), or (c) of this section depending upon the control equipment installed to meet the requirements of §60.112b. The owner or operator shall keep copies of all reports and records required by this section, except for the record required by AIRS ID: 123/0107 Page 22 of 44 Public Health and Environment Air Pollution Control Division (c)(1), for at least 2 years. The record required by (c)(1) will be kept for the life of the control equipment. §60.113b(d) The owner or operator of each source that is equipped with a closed vent system and a flare to meet the requirements in §60.112b (a)(3) or (b)(2) shall meet the requirements as specified in the general control device requirements, §60.18 (e) and (f). • §60.116b— Reporting and recordkeeping requirements §60.115b(d) After installing a closed vent system and flare to comply with §60.112b, the owner or operator shall meet the following requirements. • §60.115b(d)(1) A report containing the measurements required by §60.18(f) (1), (2), (3), (4), (5), and (6) shall be furnished to the Administrator as required by §60.8 of the General Provisions. This report shall be submitted within 6 months of the initial start-up date. • §60.115b(d)(2) Records shall be kept of all periods of operation during which the flare pilot flame is absent. • §60.115b(d)(3) Semiannual reports of all periods recorded under §60.115b(d)(2) in which the pilot flame was absent shall be furnished to the Administrator. • §60.116b — Monitoring of operations §60.116b(a) The owner or operator shall keep copies of all records required by this section, except for the record required by paragraph (b) of this section, for at least 2 years. The record required by paragraph (b) of this section will be kept for the life of the source. • §60.116b(b) The owner or operator of each storage vessel as specified in §60.110b(a) shall keep readily accessible records showing the dimension of the storage vessel and an analysis showing the capacity of the storage vessel. In addition, the following requirements of Regulation No. 6, Part A, Subpart A, General Provisions, apply. a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source., (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11 b. No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) AIRS ID: 123/0107 Page 23 of 44 Public Health and Environment Air Pollution Control Division c. Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. e. Written notification of opacity observation or monitor demonstrations shall be submitted to the Division as required under § 60.7. f. Excess Emission and Monitoring System Performance Reports shall be submitted as required under § 60.7. g. Performance tests shall be conducted as required under § 60.8. h. Compliance with opacity standards shall be demonstrated according to § 60.11. The flare shall be designed and operated, and records and reports shall be furnished, as required under § 60.18. 49. The compressors at this facility that commenced construction, modification or reconstruction after August 23, 2011, are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5385(a) — Owner or operator must replace the reciprocating compressor rod packing according to either paragraph §60.5385(a)(1) or (2). o §60.5385(a)(1) - Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or October 15, 2012, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. o §60.5385(a)(2) - Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced. • §60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(c). • §60.5415 — Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(c). • §60.5420 - Owner or operator must comply with the notification, reporting, and recordkeeping requirements as specified in §60.5420(a), §60.5420(b)(1), §60.5420(b)(4), and §60.5420(c)(3). 50. Point 052: The fugitive component emissions from this point that commenced construction, modification or reconstruction after August 23, 2011, are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: • §60.5365 Applicability: The group of all equipment, except compressors, within a process unit which commenced construction, modification or reconstruction after August 23, 2011 is an affected facility per §60.5365(f). AIRS ID: 123/0107 Page 24 of 44 G; Public Health and Environment !( Air Pollution Control Division • §60.5400 Standards: The group of all equipment, except compressors, within a process unit must comply with the requirements of §60.5400 and §60.5401. • §60.5410: Owner or operator must demonstrate initial compliance with the standards using the requirements in §60.5410(f). • § 60.5415: Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). • § 60.5421: Owner or operator must comply with the recordkeeping requirements of §60.5421(b). • § 60.5422: Owner or operator must comply with the reporting requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). 51. Point 052: This source is subject to Regulation No. 7, Section XII.G.1 (State only enforceable). To comply with Regulation No. 7, Section XII.G.1, the source shall follow the leak detection and repair (WAR) program as provided at 40 C.F.R. Part 60, Subpart OOOO in lieu of following 40 C.F.R. Part 60, Subpart KKK. 52. This source is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2.b. The following requirements were determined to be RACT for this source. Facility Equipment ID AIRS Point Pollutant RACT TURB-1 044 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices TURB-2 045 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices HT -02 046 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices. AU -02 047 VOC Flash Tank: VRU to inlet and downtime to flare Still Vent: Regenerative Thermal Oxidizer O-01 048 VOC Flash Tank: VRU to inlet and downtime to flare Still Vent: Condenser and enclosed combustor TANKS 050 VOC Enclosed combustor LOAD 051 VOC Submerged fill, vapor balance service, enclosed combustor FUG 052 VOC LDAR OPERATING & MAINTENANCE REQUIREMENTS AIRS ID: 123/0107 Page 25 of 44 Public Health and Environment Air Pollution Control Division 53. Points 047, 048, 050 and 051: Upon startup of the points covered by this permit, the applicant shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.) COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 54. Points 044 and 045: The combustion turbines are subject to the initial testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 55. Point 044 and 045: A source initial compliance test shall be conducted on each of the combustion turbines to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Carbon Dioxide using EPA approved methods. This test may be conducted concurrently with the testing required by Condition 54. 56. Points 044, 045, and 046: The owner or operator shall complete the initial fuel sampling for gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the turbines and heaters as required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 57. Point 046: A source initial compliance test shall be conducted on the heater to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Carbon Dioxide using EPA approved methods. 58. Point 047: The operator shall complete the initial annual analysis of the inlet gas to the plant to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that this amine unit qualifies for the AIRS ID: 123/0107 Page 26 of 44 en t d`` Public Health and Environment Air Pollution Control Division exemption from the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution : SO2 Emissions (§60.5365(g)(3)). 59. Point 047: The owner or operator shall complete the initial extended gas analyses of the flash tank stream during VRU downtime and acid gas stream from the still vent as required by this permit and submit the results to the Division as part of the self - certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 60. Point 047: A source initial compliance test shall be conducted on emissions point 047 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specified in Condition 7 in this permit. The operator shall also demonstrate the regenerative thermal oxidizer achieves a minimum destruction and removal efficiency of 96% for VOC and 99% for CH4. The operator shall measure and record, using EPA approved methods, VOC and CH4 mass emission rates at the regenerative thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the regenerative thermal oxidizer (process models shall not be used to determine the flow rate or composition of the waste gas (acid gas stream from the still vent) sent to the regenerative thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, and sulfur content of sour gas entering the amine unit shall be monitored and recorded during this test. The operator shall also measure and record combustion zone temperature during the initial compliance test to establish the minimum combustion temperature. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods Methane using EPA approved methods Carbon Dioxide using EPA approved methods. 61. Point 048: The owner or operator shall complete the initial annual extended wet gas analysis testing required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 62. Points 048 and 050: The owner or operator shall demonstrate compliance with Condition 34 using EPA Method 22 to measure opacity from the enclosed combustor. 63. Points 048, 050 and 051: A source initial compliance test shall be conducted on emissions points 048, 050 and 051 to measure the emission rate(s) for the pollutants AIRS ID: 123/0107 Page 27 of 44 ent Public Health and Environment • Air Pollution Control Division listed below in order to demonstrate compliance with the emission limits in this permit. Total emissions during this compliance test from these emission points will be used to determine compliance with the sum of the emission limits in Condition 7 for Points 048, 050, and 051. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Volatile Organic Compounds using EPA approved methods. Carbon Monoxide using EPA approved methods. Carbon Dioxide using EPA approved methods. 64. Point 052: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of liquids that are representative of methane (CH4), carbon dioxide (CO2), volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas and liquids analyses and emission calculations to the Division as part of the self -certification process to ensure compliance with emissions limits. 65. Point 052: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "light liquid service" and "gas service". The operator shall submit the results to the Division as part of the self - certification process to ensure compliance with emissions limits. Periodic Testing Requirements 66. Points 044 and 045: Replacements of these units completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 67. Points 044 and 045: The combustion turbines are subject to the periodic testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 68. Points 044 and 045: The operator shall conduct, at a minimum, quarterly portable analyzer monitoring of each turbine exhaust outlet emissions of nitrogen oxides (NOx) and carbon monoxide (CO) to monitor compliance with the emissions limits. Emissions of carbon dioxide (CO2) shall be monitored quarterly and either measured from an infrared detector or calculated from the oxygen (O2) reading obtained from portable analyzer results. Results of all tests conducted shall be kept on site and made available to the Division upon request. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of AIRS ID: 123/0107 Page 28 of 44 Public Health and Environment Air Pollution Control Division operating hours for that averaging time (Reference: Regulation No, 3, Part B., Section III.G.3). 69. Points 044, 045, and 046: The fuel gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the turbines and heaters shall be determined, at a minimum, once per every six months with consecutive samples taken at least 4 months apart by the procedures contained in 40 CFR Subpart C, Part 98.34(a)(6) and records shall be maintained of the semiannual fuel GCV for a period of five years. Upon request, the owner or operator shall provide a sample and/or analysis of the fuel that is fired in the units. If sampling is performed more often, the results of all valid fuel analyses shall be used in the GHG emission calculations. 70. Point 047: The operator shall measure the emission rate(s) for the pollutants listed below at least once every 12 months in order to demonstrate compliance with the emissions limits contained in this permit. Periodic testing shall be conducted at a minimum of at least one hundred and eighty (180) days apart. The operator shall also demonstrate the regenerative thermal oxidizer achieves a minimum destruction and removal efficiency of 96% for VOC and 99% for CH4. The operator shall measure and record, using EPA approved methods, VOC and CH4 mass emission rates at the regenerative thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the regenerative thermal oxidizer (process models shall not be used to determine the flow rate or composition of the waste gas (acid gas stream from the still vent) sent to the regenerative thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, sulfur content of sour gas entering the amine unit and combustion zone temperature shall be monitored and recorded during this test. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods Methane using EPA approved methods Carbon Dioxide using EPA approved methods. 71. Point 047: The flash tank stream during VRU downtime and the acid gas stream from the still vent will both be sampled and analyzed from the amine unit including an extended gas analysis at least once every three months for composition in accordance with 40 CFR 98.233(d)(6) and 98.234(b). The sample shall be analyzed for CO2, CH4, VOC, Benzene, Toluene, Ethylbenzene, Xylene n -Hexane, and H2S content. The sampled data will be used to calculate GHG, VOC and H2S emissions to show compliance with the emission limits specified in Condition 7. AIRS ID: 123/0107 Page 29 of 44 Public Health and Environment Air Pollution Control Division 72. Point 047: The operator shall sample the inlet gas to the plant on an annual basis to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that each amine unit qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (§60.5365(g)(3)). 73. Point 048: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the TEG dehydrator on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 74. Points 048, 050 and 051: The owner or operator shall conduct EPA Method 22 visible emission observations to monitor opacity from the enclosed combustor daily. 75. Point 052: On an annual basis, the permittee shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of liquids that are representative of methane (CH4), carbon dioxide (CO2), volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. ADDITIONAL REQUIREMENTS 76. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually whenever a significant increase in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5) tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NO,) in ozone nonattainment areas emitting less than 100 tons of VOC or NO„ per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; or For sources emitting 100 tons per year or more, a change in actual emissions of five percent or 50 tons per year or more, whichever is less, above the level reported on the last APEN submitted; or For any non -criteria reportable pollutant: If the emissions increase by 50% or five (5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. b. Whenever there is a change in the owner or operator of any facility, process, or activity; or c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. AIRS ID: 123/0107 Page 30 of 44 for Public Health and Environment Air Pollution Control Division AA h a� ue f. Points 044 and 045: Within 14 calendar days of commencing operation of a permanent replacement turbine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative -operating scenario and is installing a permanent replacement turbine. 77. This source is subject to the provisions of Regulation Number 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The provisions of this construction permit must be incorporated into the operating permit. The application for the modification to the Operating Permit is due within one year of commencement of operation of the equipment or modification covered by this permit. 78. Points 044 and 045: MACT Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) 79. Points 048 and 052: MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities major stationary source requirements shall apply to this stationary source at any such time that this stationary source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 80. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section 'LB upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 81. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with the provisions of 25-7-114.5(12)(a) C.R.S. and AQCC Regulation No. 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self -certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final authorization. Details for obtaining final authorization to operate are located in the Requirements to Self - Certify for Final Authorization section of this permit. 82. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. AIRS ID: 123/0107 Page 31 of 44 e oloradaDep -trpent c Public Health and Environment Air Pollution Control Division 83. Unless specifically stated otherwise, the general and specific conditions contained in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 25-7-114.5(7)(a), C.R.S. 84. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self -certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 85. Section 25-7-114.7(2)(a), C.R.S. requires that all sources required to file an Air Pollution Emission Notice (APEN) must pay an annual fee to cover the costs of inspections and administration. If a source or activity is to be discontinued, the owner must notify the Division in writing requesting a cancellation of the permit. Upon notification, annual fee billing will terminate. 86. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. By: Stephanie Chaousy, PE Permit Engineer Permit History Issuance Date Description Issuance 1 This Issuance Issued to DCP Midstream. Addition of eight (8) permitted sources at a natural gas processing plant. Sources located at a major facility. AIRS ID: 123/0107 Page 32 of 44 Public Health and Environment Air Pollution Control Division Notes to Permit Holder at the time of this permit issuance: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section VI.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdphe.state.co.us/regulations/airregs/100102agcccommonprovisionsreg.pdf. 4) The following emissions of non -criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. AIRS Point Pollutant CAS # BIN Uncontrolled Emission Rate (lb/yr) Are the emissions reportable? Controlled Emission Rate (Ib/yr) 044 Formaldehyde 50000 A 452 Yes 452 045 Formaldehyde 50000 A 452 Yes 452 047 Benzene 71432 A 139,826 Yes 5,163 Toluene 108883 C 65,700 Yes 2,452 Ethylbenzene 100414 C 2,409 Yes 89 Xylenes 1330207 C 4,940 Yes 186 n -Hexane 110543 C 18,300 Yes 69 048 Benzene 71432 A 140,161 Yes 6,843 Toluene 108883 C 90,456 Yes 4,445 Ethylbenzene 100414 C 5,759 Yes 285 Xylenes 1330207 C 11,970 Yes 594 n -Hexane 110543 C 81,066 Yes 2,623 050 Benzene 71432 A 1,298 Yes 65 Toluene 108883 C 3,597 Yes 180 Xylenes 100414 C 2,719 Yes 136 n -Hexane 110543 C 6,984 Yes 349 051 Benzene 71432 A 1,257 Yes 63 AIRS ID: 123/0107 Page 33 of 44 Dep tment c'Public Health and Environment Air Pollution Control Division Toluene 108883 C 3,483 Yes 174 Xylenes 1330207 C 2,632 Yes 132 n -Hexane 110543 C 6,762 Yes 338 052 Benzene 71432 A 237 Yes 34 n -Hexane 110543 C 4,843 Yes 694 5) The emission levels contained in this permit are based on the following emission factors: Points 044 and 045: CAS Pollutant Emission Factors lb/MMBtu - Uncontrolled Source NOx 0.0472 Manufacturer CO 0.0553 Manufacturer VOC 0.0021 AP -42, Chapter 3.1-2a SO2 0.0034 AP -42, Chapter 3.1-2a PM2.5 0.0066 AP -42, Chapter 3.1-2a 50000 Formaldehyde 0.00071 AP -42, Chapter 3.1 Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 59.85 1 Manufacturer CH4 0.014 21 Manufacturer N2O 0.0001 310 40 CFR 98 Subpart C Emission factors are based on a rated heat input of 72.73 MMBtu/hr, a HHV value of 999 Btu/scf and 8,760 hours of operation a year. Point 046: CAS Pollutant Emission Factors lb/MMscf - Uncontrolled Source NOx 37 Manufacturer CO 84 AP -42, Chapter 1.4 VOC 5.5 AP -42, Chapter 1.4 PM2.5 5.1 Manufacturer Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart C CH4 0.001 21 40 CFR 98 Subpart C N2O 0.0001 310 40 CFR 98 Subpart C Emission factors are based on a rated heat input of 50 MMBtu/hr, a higher heat ng value of 999 Btu/scf, and a limited use scenario of 315 MMscf/yr or the equivalent of 67% of operating capacity. Point 047: Emissions from the amine unit result from venting of acid gas (still vent overhead to the regenerative thermal oxidizer) and flash tank emissions to the flare during VRU downtime. Additionally, emissions result from combustion of supplemental fuel from the burner. Actual VOC, HAP and H2S emissions from venting of still vent acid gas and flash tank emissions shall be calculated based on most recent waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) sampling and most recent monthly waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) flow volume. Controlled emissions are as follows: AIRS ID: 123/0107 Page 34 of 44 Public Health and Environment Air Pollution Control Division Point Source VOC CH4 Controlled Still Vent 96% 99% Controlled Flash Tank during VRU uptime 100% 100% Controlled Flash Tank during VRU downtime 95% 95% SO2 emissions resulting from the control/combustion of H2S emissions in the waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) are based on mass balance and assuming 96% of the H2S is converted to SO2. Additional combustion emissions (from waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)) are calculated using the following emission factors and volume of total gas combusted. Total gas combusted is the sum of most recent waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) flow volume plus most recent burner volume. Total actual emissions are based on sum of emissions calculated for controlled waste gas (flash tank during VRU downtime and still vent) plus combustion (including burner and waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) volumes). CAS Pollutant Emission Factors for flash tank volume sent to flare - Uncontrolled Uncontrolled EF Source NOx 0.068 lb/MMbtu AP -42, Table 13.5-1 CO 0.37 lb/MMbtu AP -42, Table 13.5-1 For RTO Pilot combustion: CAS Pollutant Emission Factors - Uncontrolled Lb/mmscf total gas combusted* Uncontrolled EF Source NOx 100 AP -42, Table 1.4-1 CO 84 AP -42, Table 1.4-1 VOC 5.5 AP -42, Table 1.4-2 SO2 0.6 AP -42, Table 1.4-2 PM10 7.6 AP -42, Table 1.4-2 PM2.5 7.6 AP -42, Table 1.4-2 AIRS ID: 123/0107 Page 35 of 44 Public Health and Environment Air Pollution Control Division *Total gas combusted equals waste gas (acid gas stream from the still vent) volume plus supplemental fuel volume plus fuel volume to burner. Greenhouse Gas Emission Calculations for Amine Units The owner or operator shall calculate CO2 emissions from the amine unit, on a monthly basis, using equation W-3 consistent with 40 CFR Part 98, Subpart W [98.233(d)(2)] along with the most recent waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) sampling composition and most recent monthly waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) flow volume. The owner or operator shall calculate GHG emissions from combustion at the regenerative thermal oxidizer based on procedures in 40 CFR 98 Subparts A and C along with the most recent monthly fuel gas and waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) flow volumes. Total CO2 emissions shall be based on the sum of CO2 emissions from the amine unit plus GHG emissions from combustion at the regenerative thermal oxidizer plus the flare. Greenhouse Gas Emission Factors for Regenerative Thermal Oxidizer Combustion Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart A and C CH4 0.001 21 40 CFR 98 Subpart A and C N2O 0.0001 310 40 CFR 98 Subpart A and C GHG emissions from combustion are based on a heat content of 5.12 Btu/scf and a total heat input for the regenerative thermal oxidizer of 4.0 MMBtu/hr. Point 048: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. For Lopt, the gas flowrate (F) is 230 MMSCF/D, the inlet water content (I) is 7.0 lb/MMSCF and the outlet water content (O) is 5.0 lb/MMSCF. CAS Pollutant Emission Factors - Uncontrolled Uncontrolled EF Source NOx 100 lb/MMscf AP -42, Table 1.4-1 CO 84 lb/MMscf AP -42, Table 1.4-1 Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 -- 1 40 CFR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W" The emission factors are for natural gas with a heat input of 1000 Btu/scf. The emissions for NOx and CO were calculated based on a fuel heat content of 1797 Btu/scf and a flow rate of 1160 scf/hr. The owner or operator shall calculate OO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95% for VOC and CH4. Point 050: Emission Factors Uncontrolled AIRS ID: 123/0107 Emission Factors Controlled Source Page 36 of 44 Public Health and Environment Air Pollution Control Division CAS Pollutant NOx 100 lb/MMScf --- AP -42, Chapter 1.4 CO 84 Ib/MMScf --- AP -42, Chapter 1.4 VOC 0.209 lb/bbl 0.0105 lb/bbl EPA Tanks 4.09d PM10 7.6 Ib/MMscf --- AP -42, Table 1.4-2 PM2.5 7.6 lb/MMscf --- AP -42, Table 1.4-2 71432 Benzene 0.00285 lb/bbl 0.0001 lb/bbl EPA Tanks 4.09d 108883 Toluene 0.00788 lb/bbl 0.0004 lb/bbl Engineering Calculation 1330207 Xylenes 0.00596 lb/bbl 0.0003 lb/bbl Engineering Calculation 110543 n -Hexane 0.015 lb/bbl 0.0008 lb/bbl Engineering Calculation Note: The controlled emissions factors for point 050 are based on the enclosed combustor control efficiency of 95%. Emission factors are based on the condensate tank battery as a combined unit, not per tank. Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 -- 1 40 CFR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W* The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Point 051: CAS Pollutant Emission Factors Uncontrolled Emission Factors Controlled Source NOx 100 lb/MMScf -- AP -42, Chapter 1.4 CO 84 lb/MMScf --- AP -42, Chapter 1.4 VOC 0.2021b/bbl 0.0101 lb/bbl AP -42, Chapter 5.2 PM10 7.6 Ib/MMscf --- AP -42, Table 1.4-2 PM2.5 7.6 lb/MMscf --- AP -42, Table 1.4-2 71432 Benzene 0.0656 lb/1000 gal 0.0033 lb/1000 gal Engineering Calculation 108883 Toluene 0.1817 lb/1000 gal 0.0091 lb/1000 gal Engineering Calculation 1330207 Xylenes 0.1374 lb/1000 gal 0.0069 lb/1000 gal Engineering Calculation 110543 n -Hexane 0.3529 lb/1000 gal 0.0176 lb/1000 gal EngineeCalculationring The uncontrolled VOC emission factor was calculated using AP -42, Chapter 5.2, Equation 1 (version 1/95) using the following values: L = 12.46*S*P*M/T S = 0.6 (Submerged loading: dedicated normal service) P (true vapor pressure) = 5.0032 psia M (vapor molecular weight) = 66 Ib/lb-mol AIRS ID: 123/0107 Page 37 of 44 Depipt ent Public Health and Environment Air Pollution Control Division T (temperature of liquid loaded) = 512.45 °R The uncontrolled non -criteria reportable air pollutant (NCRP) emission factors were calculated by multiplying the mass fraction of each NCRP in the vapors by the VOC emission factor. Controlled emission factors are based on an enclosed combustor efficiency of 95%. Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 -- 1 40 CFR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W* The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Point 052: Equipment Type Gas Gas Control % Light Liquid Light Liquid Control % Connectors 1914 30 6066 30 Flanges 1718 30 1146 30 Open -Ended Lines --- -- --- --- Pump Seals --- --- 38 88 Valves 2522 95 1982 95 Other 148 75 36 75 VOC Content (wt%) 26.92% -- 100% --- Benzene (wt%) 0.06% -- 0.06% --- Toluene (wt%) 0.04% --- 0.04% --- Ethylbenzene (wt%) 0.003% --- 0.003% --- Xylenes (wt%) 0.01% --- 0.01% --- n-hexane (wt%) 1.21% --- 1.21% --- CO2 Content (wt%) 6.65% --- -- --- CH4 Content (wt%) 54.67% --- --- --- *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Light Oil Connectors 2.0E-04 2.1E-04 Flanges 3.9E-04 1.1E-04 Open-ended Lines 2.0E-03 1.4E-03 Pump Seals 2.4E-03 1.3E-02 Valves 4.5E-03 2.5E-03 Other 8.8E-03 7.5E-03 Source: EPA -453/R95-017 AIRS ID: 123/0107 Page 38 of 44 Public Health and Environment Air Pollution Control Division Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas and liquids analyses. For CO2e emissions, the TOC emission factors listed in the table above with representative component count will be multiplied by the CH4 and CO2 content from the most recent gas analysis. CO2e emissions are then calculated based on procedures in 40 CFR 98 Subpart A. 6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-3150. 7) This facility is classified as follows: Applicable Requirement Status Operating Permit Major Source of NOx, VOC, and CO PSD Subject to Regulation of CO2e NANSR Major Source of NOx and VOC 8) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A — Subpart OOOO NSPS Part 60, Appendixes Appendix A — Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A — Subpart Z MACT 63.600-63.1199 Subpart AA — Subpart DOD MACT 63.1200-63.1439 Subpart EEE — Subpart PPP MACT 63.1440-63.6175 Subpart QQQ — Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ — Subpart MMMMM MACT 63.8980 -End Subpart NNNNN — Subpart XXXXXX 9) An Oil and Gas Industry Construction Permit Self -Certification Form is included with this permit packet. Please use this form to complete the self -certification requirements as specified in the permit conditions. Further guidance on self -certification can be found on our website at: http://www.cdohe.state.co.us/ap/oilaaspermittinghtml AIRS ID: 123/0107 Page 39 of 44 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 ATTACHMENT A: a Cole theft of Public Health and Environment =i"ii Air Pollution Control Division ALTERNATIVE OPERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING August 16, 2011 1. Routine Turbine Component Replacements The following physical or operational changes to the turbines in this permit are not considered a modification for purposes of NSPS GG, major stationary source NSR/PSD, or Regulation No. 3, Part B. Note that the component replacement provisions apply ONLY to those turbines subject to NSPS GG. Neither pre-GG turbines nor post GG turbines (i.e. KKKK turbines) can use those provisions. 1) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seals, and shaft packings, provided that they are of the same design as the original. 2) Changes in the type or grade of fuel used, if the original gas turbine installation, fuel nozzles, etc. were designed for its use. 3) An increase in the hours of operation (unless limited by a permit condition) 4) Variations in operating loads within the engine design specification. 5) Any physical change constituting routine maintenance, repair, or replacement. Turbines undergoing any of the above changes are subject to all federally applicable and state only requirements set forth in this permit (including monitoring and record keeping). If replacement of any of the components listed in (1) or (5) above results in a change in serial number for the turbine, a letter explaining the action as well as a revised APEN and appropriate filing fee shall be submitted to the Division within 30 days of the replacement. Note that the repair or replacement of components must be of genuinely the same design. Except in accordance with the Alternate Operating Scenario set forth below, the Division does not consider that this allows for the entire replacement (or reconstruction) of an existing turbine with an identical new one or one similar in design or function. Rather, the Division considers the repair or replacements to encompass the repair or replacement of components at a turbine with the same (or functionally similar) components. 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of combustion turbines and turbine components has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility- Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any turbine or turbine component replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such turbine or turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. AIRS ID: 123/0107/044, 045 Page 40 of 44 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 2.1 Turbine Replacement ofPublic Health and Environment Air Pollution Control Division The following AOS is incorporated into this permit in order to deal with a turbine breakdown or periodic routine maintenance and repair of an existing onsite turbine that requires the use of a temporary replacement turbine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the total number of days that the turbine is in operation. If the turbine operates only part of a day, that day shall count as a single day towards the 90 -day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. Any permanent turbine replacement under this AOS shall result in the replacement turbine being considered a new affected facility for purposes of NSPS and shall be subject to all applicable requirements of that Subpart including, but not limited to, any required Performance Testing. All replacement turbines are subject to all federally applicable and state -only requirements set forth in this permit (including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with the NSPS requirements. Results of all tests shall be kept on site for five (5) years and made available to the Division upon request. The owner or operator shall maintain a log on -site and contemporaneously record the start and stop date of any turbine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the turbine (s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement turbine. 2.1.1 The owner or operator may temporarily replace an existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit, so long as the temporary replacement turbine complies with the emission limitations for the existing permitted turbine and other requirements applicable to the original turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.2 The owner or operator may permanently replace the existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit so long as the permanent replacement turbine complies with the emission limitations and other requirements applicable to the original turbine as well as any new applicable requirements for the replacement turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.3 An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar days of commencing operation of the replacement turbine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement turbine. This AOS cannot be used for permanent turbine replacement of a grandfathered or permit exempt turbine or a turbine that is not subject to emission limits. The owner or operator shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent turbine replacement. AIRS ID: 123/0107/044, 045 Page 41 of 44 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 Colend o D oar me orPublic Health and Environment Air Pollution Control Division The AOS cannot be used for the permanent replacement of an entire turbine at any source that is currently a major stationary source for purposes of Prevention of Significant Deterioration or Non -Attainment Area New Source Review ("PSD/NANSR") unless the existing turbine has emission limits that are below the significance levels in Reg 3, Part D, I I.A.42. Nothing in this AOS shall preclude the Division from taking an action, based on any permanent turbine replacement(s), for circumvention of any state or federal PSD/NANSR requirement. Additionally, in the event that any permanent turbine replacement(s) constitute(s) a circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse the owner or operator from complying with PSD/NANSR and applicable permitting requirements. 2.2 Portable Analyzer Testing Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss streamlining the testing requirements. Note that the testing required by this Condition may be used to satisfy the periodic testing requirements specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer testing, this test conducted under the AOS will serve as the quarterly test and an additional portable analyzer test is not required for another three months). The owner or operator may conduct a reference method test, in lieu of the portable analyzer test required by this Condition, if approved in advance by the Division. The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement turbine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement turbine. All portable analyzer testing required by this permit shall be conducted using the most current version of the Division's Portable Analyzer Monitoring Protocol as found on the Division's website. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement turbine will be subject to, the results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the turbine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO AIRS ID: 123/0107/044, 045 Page 42 of 44 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 Public Health and Environment Air Pollution Control Division emission limitations, the turbine will be considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the turbine is taken offline. 2.3 Applicable Regulations for Permanent Turbine Replacements 2.3.1 NSPS for Stationary Gas Turbines: 40 CFR 60, Subpart GG §60.330 Applicability and designation of affected facility. (a) The provisions of this subpart are applicable to the following affected facilities: All stationary gas turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired. (b) Any facility under paragraph (a) of this section which commences construction, modification, or reconstruction after October 3, 1977, is subject to the requirements of this part except as provided in paragraphs (e) and a) of §60.332. A Subpart GG applicability determination as well as an analysis of applicable Subpart GG monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS GG requirements). 2.3.2 NSPS for Stationary Combustion Turbines: 40 CFR 60, Subpart KKKK §60.4305 Does this subpart apply to my stationary combustion turbine? (a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part. A Subpart KKKK applicability determination as well as an analysis of applicable Subpart KKKK monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is AIRS ID: 123/0107/044, 045 Page 43 of 44 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 o? Public Health and Environment Air Pollution Control Division first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS KKKK requirements). 2.4 Additional Sources The replacement of an existing turbine with a new turbine is viewed by the Division as the installation of a new emissions unit, not "routine replacement" of an existing unit. The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new emission points for any site; a turbine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite turbine has to go through the appropriate Construction/Operating permitting process prior to installation AIRS ID: 123/0107/044, 045 Page 44 of 44 Construction Permit Application Preliminary Analysis Summary Section 1 — Applicant Information Company Name: DCP Midstream LP Permit Number: 12WE2024 Source Location: 31495 Weld County Road 43, Weld County (nonattainment) AIRS ID: 123-0107 Date: December 12, 2012 Review Engineer: Bailey Kai Smith/Stephanie Chaousy Control Engineer: Chris Laplante n 2 — Action Completed Grandfathered Modification APEN Required/Permit Exempt X CP1 Transfer of Ownership APEN Exempt/Permit Exempt Section 3 — Applicant Completeness Review Was the correct APEN submitted for this source type? X Yes No Is the APEN signed with an original signature? X Yes No Was the APEN filled out completely? X Yes No Did the applicant submit all required paperwork? X Yes No Did the applicant provide ample information to determine emission rates? Yes X No If you answered 'no" to any of the above, when did you mail an Information Request letter to the source? Please see Section 14 On what date was this application complete? June 19, 2012 Section 4 — Source Description AIRS Point Equipment Description 044 One (1) natural gas fired combustion turbine (Solar Model Taurus 70 serial number: TBD), equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit (WHRU) System. This combustion turbine is used to power a compressor. 045 One (1) natural gas fired combustion turbine (Solar Model Taurus 70, serial number: TBD), equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is design rated for a heat input of 72.73 MMBtu/hr at 60°F ambient temperature. The turbine will be equipped with a Waste Heat Recovery Unit (WHRU) System. This combustion turbine is used to power a compressor. 046 Hot oil heater (Optimized Process Furnaces, Inc., model, serial number: TBD), equipped with low NOx burners. The heater is design rated at a heat input of 50 MMBtu/hr. This heater is fueled by natural gas and used to supplement the waste heat recovery unit (WHRU) provided from Points 044 and 045. Page 1 047 One (1) methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf per day (make, model, serial number: TBD). This emissions unit is equipped with electric amine recirculation pumps with a total limited capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, reflux condenser, a flash tank, still vent and an indirect -fired hot oil (or waste heat from the WHRUs) amine regeneration reboiler (point 046). The amine flash stream is routed to a closed loop system that utilizes a vapor recovery unit (maximum 1% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The acid gas stream from the still vent condenser outlet is routed to a regenerative thermal oxidizer (Anguil, Model 100, SN: TBD) rated at 10,000 scf/min. Destruction efficiency for the RTO is a minimum of 96% for VOC and 99% for CH4. 048 One (1) triethylene glycol (TEG) dehydrator unit with a design capacity of 230 MMscf/day (make, model, serial number: TBD). This emissions unit is equipped with two (2) electric glycol pumps with a limited total combined capacity of 40 gallons per minute. This system includes a BTEX condenser, reboiler, still vent, and a flash tank. The flash gas is routed to a closed loop system that utilizes a vapor recovery unit (maximum 1% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The still vent emissions are routed to a condenser and then to an enclosed combustor with a minimum destruction efficiency of 95%. 050 Four (4) stabilized atmospheric condensate storage tanks. Each tank has a capacity of 1000 bbl. Emissions are routed to an enclosed combustor with a minimum destruction efficiency of 95%. 051 Condensate truck loading. Emissions from the loadout will be controlled by an enclosed combustor with a minimum destruction efficiency of 95%. 052 Fugitive emission component leaks from a natural gas processing plant associated with the expansion project. Is this location in a non -attainment area for any criteria pollutant? X Yes No If "yes", for what pollutant? PM10 CO X Ozone Is this location in an attainment maintenance area for any criteria pollutant? Yes X No If "yes", for what pollutant? (Note: These pollutants are subject to minor source RACT per Regulation 3, Part B, Section III.D.2) PR/lio CO Ozone Is this source located in the 8 -hour ozone non - attainment region? (Note: If "yes" the provisions of Regulation 7, Sections XII and XVII.C may apply) X Yes No Point 051: Is this source located at a facility that is considered a major source of hazardous air pollutant (HAP) emissions? Yes X No Section 5 — Emission Estimate Information AIRS Point Emission Factor Source 044 AP -42, Tables 3.1-2a and 3.1-3 for VOC, PM10, PM25, SO2 and HAPS Manufacturer Data for CO and NOx. See Section 14 for calculations. 045 AP -42, Tables 3.1-2a and 3.1-3 for VOC, PM10, PM2.5, SO2 and HAPS Manufacturer Data for CO and NOx. See Section 14 for calculations. 046 Manufacturer Data for NOx and PM2,5. See Section 14 for calculations. AP -42 for all other pollutants. 047 Amine unit: Site-specfic using Promax Simulation Model. See Section 14 for calculations. RTO: NOx and CO AP -42, Table 1.4 and SOx Promax and mass balance. 048 NOx and CO from AP -42, Table 1.4. VOC. GRI Gly-Calc v4.0. See Section 14 for calculations. 050 NOx and CO from AP -42, Table 1.4. VOC and HAPS from TANKS4.0.9d. See Section 14 for calculations. 051 NOx and CO from AP -42, Table 1.4. VOC: AP -42, Chapter 5.2, Equation 1 052 EPA Protocol for Equipment Leak Emission Estimates, EPA, November 1995, EPA - 453/R -95-017 Page 2 Did the applicant provide actual process data for the emission inventory? Yes X No Basis for Potential to Emit (PTEI AIRS Point Process Consumption/Throughput/Production 044 66.12 MMBtu/hr *1.1* 8760 hr/yr = 637,132 MMBtu/yr / 999 Btu/scf = 637.7 MMscf/yr 045 66.12 MMBtu/yr* 1.1* 8760 hr/yr = 637,132 MMBtu/yr 1999 Btu/scf = 637.7 MMscf/yr 046 470 MMscf/yr 047 83,950 MMscf/yr, natural gas throughput, 945 gallons per minute lean amine circulation rate. RTO throughput 2,869 MMscf/yr. 048 83,950 MMscf/yr, 40 gallons per minute glycol circulation rate 050 456,250 bbl/yr 051 456,250 bbl/yr 052 Equipment Type Gas Light Liquid Connectors 1914 6066 Flanges 1718 1146 Open -Ended Lines --- -- Pump Seals --- 38 Valves 2522 1982 Other 148 36 Basis for Permitted Emissions (Permit Limits) AIRS Point Process Consumptionlihroughput/Production 044 637.7 MMscf/yr 045 637.7 MMscf/yr 046 315 MMscf/yr (operator limiting capacity by 67%) 047 83,950 MMscf/yr. RTO throughput 2,869 MMscf/yr. 048 83,950 MMscf/yr, 40 gallons per minute glycol circulation rate 050 456,250 bbl/yr 051 456,250 bbl/yr 052 Equipment Type Gas Light Liquid Connectors 1914 6066 Flanges 1718 1146 Open -Ended Lines --- -- Pump Seals --- 38 Valves - 2522 1982 Other 148 36 Does this facility use control devices? X Yes No AIRS Point Process Control Device Description % Reduction Granted 047 of Regenerative thermal oxidizer 96% for 99% CH4H4 048 01 Flash tank: VRU (closed loop) and backup flare during VRU downtime 100% during VRU uptime 95% during VRU downtime (flare) 02 Still vent: condenser and enclosed combustor 95 050 oi Enclosed combustor 95 051 oi Enclosed combustor 95 052 01 LDAR per NSPS OOOO Connections 30 Flanges 30 Page 3 Open -Ends 75 Pumps 88 Valves 95 Other 75 Section 6 — Emission Summary (tons per year) Point NOx VOC CO SOx PM/PM 2.6 H2S CO2e Single HAP HAPI PTE: 044 15.0 0.7 17.6 1.1 2.1 -- 42,268 0.2 (formaldehyde)0.2 0.3 045 15.0 0.7 17.6 1.1 2.1 -- 42,268 (formaldehyde) 0.3 046 7.9 1.2 17.9 0.1 0.8 -- 20,250 --- -- 047 0.5 724.1 2.7 31.5 --- 17.5 154,337 69.9 (benzene) 115.6 048 0.9 705.6 0.8 --- --- -- 5,230 70.1 (benzene) 164.7 050 0.1 47.7 0.1 --- --- -- 275 3.5 (n -hexane) 7.4 051 0.1 46.2 0.1 -- -- -- --- 3.4 (n -hexane) 7.8 052 --- 104.2 --- --- --- -- 200 2.4 (n -hexane) 2.7 Requested Uncontrolled point source emission rate: 044 15.0 0.7 17.6 1.1 2.1 -- 42,268 0.2 (formaldehyde)0.2 0.3 045 15.0 0.7 17.6 1.1 2.1 -- 42,268 (formaldehyde) 0.3 046 5.8 0.9 13.2 0.1 0.8 -- 20,250 --- --- 047 0.5 724.1 2.7 31.5 --- 17.5 154,337 69.9 (benzene) 115.6 048 0.9 705.6 0.8 --- --- -- 5,230 70.1 (benzene) 164.7 050 0.1 47.7 0.1 --- --- -- 275 3.5 (n -hexane) 7.4 051 --- 46.2 --- -- -- -- --- 3.4 (n -hexane) 7.8 052 --- 104.2 --- -- -- -- 200 2.4 (n -hexane) 2.7 Permitted Controlled point source emission rate: 044 15.0 0.7 17.6 1.1 2.1 -- 42,268 0.2 (formaldehyde)0.2 0.3 045 15.0 0.7 17.6 1.1 2.1 -- 42,268 (formaldehyde) 0.3 046 5.8 0.9 13.2 0.1 0.8 -- 20,250 -- --- 047 0.5 7.0 2.7 31.5 --- 0.7 154,337 2.6 (benzene) 4.0 048 0.9 19.2 0.8 --- --- -- 5,230 3.4 (benzene) 7.4 050 0.1 2.4 0.1 --- --- -- 275 0.2 (n -hexane) 0.4 051 0.1 2.3 0.1 --- -- --- 0.2 (n -hexane) 0.4 052 --- 17.3^ --- --- --- -- 200 0.4 (n -hexane) 0.4 Total Permitted emissions: 37.4 33.1 (point) 52.1 33.8 5.0 0.7 264,828 3.5 (benzene) 12.8 17.3 (^fugitive) Section 7 — Non -Criteria / Hazardous Air Pollutants Pollutant CAS # BIN Uncontrolled Emission Rate (lb/yr) Are the emissions reportable? Controlled Emission Rate (Ib/yr) Point 044 (Reporting Scenario 2 in Appendix A of Reg 3, Part A) Formaldehyde 50000 A 452 Yes 452 Page 4 Acetaldehyde 75070 A 26 No 26 Acrolein 107028 A 4 No 4 Benzene 71432 A 10 No 10 Toluene 108883 C 83 No 83 Ethylbenzene 100414 C 20 No 20 Xylenes 1330207 C 41 No 41 Point 045 (Reporting Scenario 2 in Appendix A of Reg 3, Part A) Formaldehyde 50000 A 452 Yes 452 Acetaldehyde 75070 A 26 No 26 Acrolein 107028 A 4 No 4 Benzene 71432 A 10 No 10 Toluene 108883 C 83 No 83 Ethylbenzene 100414 C 20 No 20 Xylenes 1330207 C 41 No 41 Point 046 (Reporting Scenario 1 in Appendix A of Reg 3, Part A) Formaldehyde 50000 A 24 No 24 Benzene 71432 A 1 No 1 n -Hexane 110543 C 567 No 567 Toluene 108883 C 1 No 1 Point 047 (Reporting Scenario 2 in Appendix A of Reg 3, Part A) Benzene 71432 A 139,826 Yes 5,163 Toluene 108883 C 65,700 Yes 2,452 Ethylbenzene 100414 C 2,409 Yes 89 Xylenes 1330207 C 4,940 Yes 186 n -Hexane 110543 C 18,300 Yes 69 Point 048 (Reporting Scenario 1 in Appendix A of Reg 3, Part A) Benzene 71432 A 140,161 Yes 6,843 Toluene 108883 C 90,456 Yes 4,445 Ethylbenzene 100414 C 5,759 Yes 285 Xylenes 1330207 C 11,970 Yes 594 n -Hexane 110543 C 81,066 Yes 2,623 Point 050 (Reporting Scenario 1 in Appendix A of Reg 3, Part A) Benzene 71432 A 1,298 Yes 65 Toluene 108883 C 3,597 Yes 180 Ethylbenzene 100414 C 267 No 13 Xylenes 1330207 C 2,719 Yes 136 n -Hexane 110543 C 6,984 Yes 349 Page 5 Point 051 (Reporting Scenario 1 in Appendix A of Reg 3, Part A) Benzene 71432 A 1,257 Yes 63 Toluene 108883 C 3,483 Yes 174 Ethylbenzene 100414 C 259 No 13 Xylenes 1330207 C 2,632 Yes 132 n -Hexane 110543 C 6,762 Yes 338 Point 052 (Reporting Scenario 1 in Appendix A of Reg 3, Part A) Benzene 71432 A 237 Yes 34 Toluene 108883 C 175 No 25 Ethylbenzene 100414 C 14 No 2 Xylenes 1330207 C 24 No 3 n -Hexane 110543 C 4,843 Yes 694 Note: Regulation 3, Part A, Section Il.B.3.b APEN emission reporting requirements for non -criteria air pollutants are based on potential emissions without credit for reductions achieved by control devices used by the operator. Section 8 —Testing Requirements Will testing be required to show compliance with any emission rate or regulatory standard? X Yes No If "yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method 044 01 NOx, CO2 Regulation No. 3, Part B., Section III.G.3, 40 CFR Part 60 Subpart KKKK §60.4335 Stack Test 045 01 NOx, CO2 Regulation No. 3, Part B., Section III.G.3, 40 CFR Part 60 Subpart KKKK §60.4335 Stack Test 044 01 CO2' CO' State only requirement Portable Analyzer 045 01 CNO2 CO, . State only requirement Portable Analyzer 044 01 High heat value(HHV) Regulation No. 3, Part B, Section III.E. Fuel sampling 045 01 High heat value(HHV) Regulation No. 3, Part B, Section III.E. Fuel sampling 046 01 High heat value(HHV) Regulation No. 3, Part B, Section III.E. Fuel sampling 047 01 VOC, HAPS Regulation No. 3, Part B, Section III.E. Extended sour gas analysis 047 01 VOC, HAPS, CO2 Regulation No. 3, Part B, Section III.E. Extended waste gas analysis 047 01 SO2, CO, NOx, VOC, CH4, CO2 Regulation No. 3, Part B., Section III.G.3 Stack Test 048 01 VOC, HAPS Regulation No. 3, Part B., Section III.E Extended wet gas analysis 048 01 Opacity Regulation No. 1, Section II.A1 & 4 EPA Method 22 050 01 Opacity Regulation No. 1, Section II.A1 & 4 EPA Method 22 048, 050, 051 01 CO, NOx, VOC Regulation No. 3, Part B., Section III.G.3 Stack Test 052 01 VOC, HAPS State only requirement Extended gas analysis 052 01 VOC, HAPS State only requirement Component hard count Page 6 Section 9 — Source Classification Are all the points on permit 12WE2024 new previously un-permitted sources? X Yes No What is the existing facility classification? True Minor Synthetic Minor X Major Classification relates to what programs? X Title V X PSD X NA NSR MACT Is this a modification to an existing stationary source? X Yes No If "yes" what kind of modification? Minor X Synthetic Minor for NOx, VOC and CO X Major for GHG Section 10 — Public Comment Does this permit require public comment per CAQCC Regulation 3? X Yes No If "yes", for which pollutants? Why? NOx, VOC, CO and CO2e above thresholds For Reg. 3, Part B, III.C.1.a (emissions increase > 25/50 tpy)? X Yes No For Reg. 3, Part B, III.C.1.c.iii (subject to MACT)? X Yes No For Reg. 3, Part B, III.C.1.d (synthetic minor emission limits)? X Yes No For Reg. 3, Part D, IV (projects subject to PSD)? X Yes No AIRS Point Section 11 — Regulatory Review Regulation 1- Particulate, Smoke, Carbon Monoxide and Sulfur Dioxide 044-052 Section II.A.1 - Except as provided in paragraphs 2 through 6 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings taken at 15 -second intervals for six minutes. The approved reference test method for visible emissions measurement is EPA Method 9 (40 CFR, Part 60, Appendix A (July, 1992)) in all subsections of Section II. A and B of this regulation. Section II.A.5 - Smokeless Flare or Flares for the Combustion of Waste Gases No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. 044 and 045 Section III.A.1 - No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following: (i) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(Fli° 26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. Section VI.B.4.c - Emissions of sulfur dioxide shall not emit sulfur dioxide in excess of the following combustion turbine limitations.: Combustion Turbines with a heat input of less than 250 Million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input. Page 7 046 Section III.A.1 - No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following: (ii) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)-° 26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. Section VI.B.5.a - Any new source of sulfur dioxide not specifically regulated above shall limit emissions to not more than two (2) tons per day of sulfur dioxide. Regulation 2 — Odor 044-052 Section I.A - No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are measured in excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven (7) or more volumes of odor free air. Regulation 3 - APENs, Construction Permits, Operating Permits, PSD 044-052, Part A-APEN Requirements Criteria Pollutants: For criteria pollutants, Air Pollutant Emission Notices are required for: each individual emission point in a non -attainment area with uncontrolled actual emissions of one ton per year or more of any individual criteria pollutant (pollutants are not summed) for which the area is non -attainment. 044-052 Part B — Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled emissions from this facility are greater than the permitting thresholds (Reg. 3, Part B, Section II.D.2.a) Section III.D.2 — RACT Requirements Minor sources in designated nonattainment or attainment/maintenance areas that are otherwise not exempt pursuant to Section II.D. of this Part, shall apply Reasonably Available Control Technology for the pollutants for which the area is nonattainment or attainment/maintenance. 047 Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. This amine unit is controlled by a RTO to meet RACT requirements. 048 Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. This glycol unit is controlled by an enclosed combustor to meet RACT requirements. 050 Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. These tanks are controlled by an enclosed combustor to meet RACT requirements. 051 Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. The date of interest for determining whether the source is new or modified is therefore November 20, 2007 (the date of the 8 -hour ozone NA area designation). Since the tank battery from which loadout is occurring will be in service after the date above, this source is considered "new or modified." Operator is using submerged fill (0.6 saturation factor), therefore, RACT requirements are satisfied. This loadout is also being controlled by an enclosed combustor. Page 8 052 Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. These fugitives are subject to an LDAR program per NSPS OOOO. 044052 Part C — Operating Permit Requirements Applicant is required to obtain an operating permit since potential emissions from this facility exceed the major source 100 tons per year permitting threshold for NOx, CO, VOC, and CO2e. 044-052 Part D — PSD Permit Requirements Applicant is required to undergo PSD review for a major modification for CO2e emissions since the emissions increase exceeds 100,000 tons per year CO2e. Regulation 6 - New Source Performance Standards 044 and 045 NSPS KKKK: For combustion turbines with heat input at peak load equal to or greater than 10 MMBtu/hr and commenced construction, modification or reconstruction after February 18, 2005. This source subject to NSPS KKKK? Yes Why? These turbines will be constructed after the threshold date, so therefore, subject to NSPS KKKK. NSPS A - Source is subject to Regulation No. 6, Part A, Subpart A, General Provisions 044 and 045 Part B, Section II.C - Standard for Particulate Matter — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-oze Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. Part B, Section II.D.3.a - Standard for Sulfur Dioxide — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. 046 NSPS Dc: for steam generating units for which construction, modification or reconstruction is commenced after June 9, 1989 and that have a maximum design heat input capacity of greater than or equal to 10 MMBtu/hr and less than or equal to 100 MMBtu/hr. This source subject to NSPS Dc? Yes Why? According to the definition of a steam generating unit, this source meets this definition and has a design heat input capacity of 50 MMBtu/hr. NSPS A - Source is subject to Regulation No. 6, Part A, Subpart A, General Provisions 046 Part B, Section II.C - Standard for Particulate Matter — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=O'.5(FI).0.26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. • Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity Page 9 047 NSPS LLL: Each sweetening (amine) unit and each sweetening unit followed by a sulfur recovery unit; manufacturer date after January 24, 1984. This source is not subject to this subpart because it is subject to NSPS OOOO instead. 047 NSPS OOOO: Each sweetening (amine) unit and each sweetening unit followed by a sulfur recovery unit; manufacturer date after August 23, 2011. This source will have a design capacity less than 2 long tons/day H2S in the acid gas based on the information submitted in the application. This source will be required by 60.5423(c) to keep for the life of the equipment an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2S expressed as sulfur. No other requirements apply. 050 NSPS Kb: for storage vessels greater than 19,800 gallons after 7/23/84. Is this source greater than 19,800 gallons (471 bbl)? Yes Is this source subject to NSPS Kb? Yes NSPS OOOO - Each storage vessel which commenced construction, modification or reconstruction after August 23, 2011. These tanks will not be subject to NSPS OOOO since the unit will be controlled with an enclosed combustor, emissions will be less than the 6 tons VOC per year threshold. 051 No applicable subpart. This facility is not a bulk gasoline terminal. 052 NSPS OOOO - Equipment Leaks of VOC from onshore natural gas processing plants. Affected facilities at onshore natural gas facilities (any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids (NGLs) or both which commenced construction, modification or reconstruction after August 23, 2011. Is this source at a "natural gas processing plant?" Yes Is this source subject to NSPS OOOO? Yes This source is a natural gas processing plant that is extracting NGLs. The equipment covered by this point was constructed after the applicability date of the rule and are therefore subject to its provisions. NSPS OOOO — Reciprocating compressors which commenced construction, modification or reconstruction after August 23, 2011. This source has two compressors to be installed after the applicability date and is therefore subject to the provisions of the rule. NSPS A - Source is subject to Regulation No. 6, Part A, Subpart A, General Provisions Regulation 7 — Volatile Organic Compounds 044-052 Section II.C.2 - All new sources shall utilize controls representing RACT, pursuant to Regulation Number 7 and Regulation Number 3, Part B, Section III.D., upon commencement of operation. 048 Section XII.C.1.d - The combustion device used to control emissions of volatile organic compounds from these units to comply with Section XII. D shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from the outside of the enclosed combustion device, or by other means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XII. 048 Is this source subject to the control requirements of MACT HH? (Regulation 8 -Hazardous Air Pollutants review). No Is this source subject to the exemptions under MACT HH (i.e. throughput exemption less than 3 MMSCFD or benzene exemption of less than 1984 Ib/yr)? No This source is subject to review for the Regulation 7 control requirements. 048 Section XII.H: Is this source located in the non -attainment area? Yes This source is subject to Regulation 7, Section XII.H. Uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. Page 10 048 Section XVII.D (State only enforceable). Applicant is required to reduce VOC emissions from this dehydrator by at least 90% since uncontrolled VOC emissions are greater than the 15.0 TPY threshold. 050 Section XII and Section XVII.C - Emission reduction from condensate storage tanks at oil and gas exploration and production operations, natural gas compressor stations, natural gas drip stations and natural gas processing plants. These requirements will not apply to the condensate storage tanks even though uncontrolled actual emissions exceed 20 tons per year of VOC. The source is subject to Federal requirements under Subpart Kb. 051 No sections apply. Per Regulation 7, Section VI.C, a terminal is defined as a petroleum liquid storage and distribution facility that has a daily average throughput of more than 76,000 liters of gasoline (20,000 gallons), which is loaded directly into transport vehicles. This facility is neither a terminal, nor a bulk plant per definitions in Reg 7, Section VI.C. 052 Section XII.G - If facility is a natural gas processing plant located in non -attainment area, then subject to Section XII.G. This source is a natural gas processing plant in non -attainment. Therefore, it is subject to Section XII.G. The provisions require the facility to comply with NSPS Subpart KKK. However, the fugitive components are also subject NSPS Subpart OOOO, which is more stringent than Subpart KKK. Re ulation 8 — Hazardous Air Pollutants 044-047, 050, 052 None 048 MACT HH: If facility is MAJOR source for HAP (summation of HAPS of dehydrators and fugitives greater than 25 TPY total or 10 TPY single HAP), then all glycol dehydrators at this facility are subject to MACT HH. If facility is an area source of HAP, only TEG dehydrators are subject to MACT HH. 1.Is facility a production field facility per 63.761 (Refer to Section 14 for definition)? No 2.If facility is NOT a production field facility (i.e. natural gas processing plant), then is it a major source of HAPS when summing all HAP emissions from ALL HAP emitting units? No 3. Is this facility considered MAJOR for HAPS? No 4.ls this source subject to MACT HH? Yes 5. WHY? This facility is an area source of HAP and MACT HH area source requirements apply to this TEG dehydrator. This dehydrator is not located within an urban cluster or within two miles of an urban area, and is subject to the optimal circulation rate work practice standard in HH. 051 MACT EEEE: Not subject because minor source of HAPs Section 12—Aerometric Information Retrieval System Coding Information Point Process Process Description Throughput limit Emission Factor Pollutant / CAS # Fugitive (Y/N) Emission - Factor Source Control (%) 044 01 Combustion Turbine 637.7 MMscf/yr 0.0472 lb/MMBtu NOx No Manufacturer 0 0.0553 lb/MMBtu CO No Manufacturer 0 0.0021 lb/MMBtu VOC No AP -42, Table 3.1-2a 0 0.0034 lb/MMBtu - SO2 No AP -42, Table 3.1-2a 0 0.0066 lb/MMBtu PM/PM1o/PM 2.5 No AP -42, Table 3.1-2a 0 0.00071 Ib/MMBtu Formaldehy de / 50000 No AP -42, Table 3.1-3 0 SCC 20200201: Turbine (natural gas) 045 01 Combustion Turbine 637.7 MMscf/yr 0.0472 lb/MMBtu NOx No Manufacturer 0 0.0553 lb;/MMBtu CO No Manufacturer 0 Page 11 0.0021 lb/MMBtu VOC No AP -42, Table 3.1-2a 0 0.0034 lb/MMBtu SO2 No AP -42, Table 3.1-2a 0 0.0066 lb/MMBtu PM/PM1o/PM 2.5 No AP -42, Table 3.1-2a 0 0.00071 lb/MMBtu Formaldehyde / 50000 No AP -42, Table 3.1-3 0 SCC 20200201: Turbine (natural gas) 046 01 37 lb/MMscf NOx No Manufacturer 0 Hot oil 315 84 lb/MMscf CO No AP 42, Chapter 1.4-1 0 heater MMscf/yr 5.5 lb/MMscf VOC No AP -42, Chapter 1.4-1 0 5.0 lb/MMscf PM/PMio/PM 2.5 No Manufacturer 0 SCC 31000404 — Process heaters; Natural gas 047 01 21.82 lb/MMscf SO2 No ProMax, Mass Balance 0 2,869 MMscf/yr 100 lb/mmscf NOx No AP -42, Chapter 1.4 0 84 lb/mmscf CO No AP 42, Chapter 1.4 0 0.068 lb/MMBtu NOx No AP -42, Chapter 13.5 0 0.37 lb/MMBtu CO No AP -42, Chapter 13.5 0 Amine Unit 17.2514 ib/MMscf VOC No ProMax 99 83,950 1.6656 lb/MMscf Benzene / 71432 No ProMax 96.3 MMscf/yr 0.7826 lb/MMscf Toluene / 108883 No ProMax 96.3 0.0287 lbs/MMscf Ethylbenzen e / 100414 No Promax 96.7 0.0588 lbs/MMscf Xylenes / 1330207 No Promax 96.4 0.2179 lbs/MMscf n -Hexane / 110543 No Promax 99.7 SCC 31000305 — Gas Sweetening; Amine process 048 01 16.8101 lb/MMscf VOC No GlyCalc 4.0 97.3 100 Ib/rnmscf NOx No AP -42, Chapter 1.4 0 84 lb/mmscf CO No AP 42, Chapter 1.4 0 Glycol 83,950 1.6696 lb/MMscf Benzene / 71432 No GlyCalc 4.0 95.1 Dehydrator MMscf/yr 1.0775 lb/MMscf Toluene / 108883 No GlyCalc 4.0 95.1 0.0686 lb/MMscf Ethylbenzen e / 100414 No GlyCalc 4.0 95.1 0.1426 lb/MMscf Xylenes / 1330207 No GlyCalc 4.0 95 0.9656 lb/MMscf n Hexane / 110543 No GlyCalc 4.0 96.8 SCC 31000301 — Glycol dehydrators: reboiler still vent: Triethylene glycol 050 01 Condensate storage tanks 456,250 bbl/yr . 4.9764 lb/1000 gal VOC No TANKS4.0.9d 95 100 lb/mmscf NOx No AP -42' Chapter 1.4 0 Page 12 84 lb/mmscf CO No AP -42, Chapter 1.4 0 0.0677 lb/1000 gal Benzene / 71432 No Engineering Calculation 95 0.1876 Ibs/MMscf Toluene / 108883 No Engineering Calculation 95 0.1418 lb/1000 gal Xylenes / 1330207 No Engineering Calculation 95 0.3643 lb/1000 gal n -Hexane / 110543 No Engineering Calculation 95 SCC 40400311 — Fixed Roof Tank, Condensate, working+breathing+flashing losses 051 01 4.82 lb/1,000 gallon VOC No AP -42, Chapter 5.2 95 100 lb/mmscf NOx No AP -42, Chapter 1.4 0 Truck 84 lb/mmscf CO No AP -42, Chapter 1.4 0 Condensate Loadout 456?5 bbl yr0 0.0656 lb/1000 gal Benzene / 71432 No Engineering Calculation 95 0.1817 lb/1000 gal Toluene / 108883 No Engineering Calculation 95 0.1374 lb/1000 gal Xylenes / 1330207 No Engineering Calculation 95 0.3529 lb/1000 gal n -Hexane / 110543 No Engineering Calculation 95 SCC 40600132: Crude Oil: Submerged Loading (Normal Service) 052 01 Fugitive VOC Leak Emissions VOC Yes EPA -453/R-95-017, Table 2-4 83.4 SCC 31000220: All Equip. Leak Fugitives (Valves, flanges, connections, seals, drains) Page 13 Section 14 - Miscellaneous Application Notes AIRS Points Facility -wide Source Determination Industrial Grouping The first element in completing an analysis using the three-part test is to determine whether the air pollutant -emitting activities at issue share the same industrial grouping; i.e., the same two -digit SIC code. In the oil and gas industry, natural gas processing plants, compressor stations, and exploration and production wells and their associated equipment (such as storage tanks) share the same two -digit SIC code. Generally, SIC Code 1311 is used for natural gas production and gathering compressor stations upstream from a natural gas processing plants. SIC code 1321 is used for natural gas liquids and typically applies to natural gas processing plants. SIC code 4922 is reserved for natural gas transmission and is usually considered for facilities after treatment at,a natural gas processing plant. Under the Regulation No. 3 definition, facilities that belong to the same major group (i.e., have the same initial two - digit code, "13") as described in the 1987 SIC Manual, are considered to belong to the same industrial grouping. Therefore, the first requirement of the three-part test for the Lucerne Gas Plant is met for any upstream compressor station, gas processing plant, or well operation. Common Control The second part of the analysis is to determine whether the pollutant -emitting activities of concern are under common ownership or control. The most obvious form of control is throughcommon ownership. DCP Midstream, LP operates several natural gas compressor stations and processing plants within the DJ basin. DCP does not own or operate upstream or downstream facilities such as exploration and production wells or transmission and storage facilities. The Division considers that common control has been established for all DCP owned and operated facilities. Another mechanism of establishing common control is through contractual agreements. DCP indicated that they are contracted to move and process raw natural gas from approximately 85 different producers. Typically, DCP takes title of the gas upon passing through one of 6,180 producer gas delivery gas meters. After title transfer, the contracting entity retains no right to control the transport and treatment of the natural gas and is entirely uninvolved in the operations of DCP Midstream, LP. Likewise, DCP does not obtain the right to control operations of the wellheads. Accordingly, the Division acknowledges that the Lucerne natural gas compressor is not under "common control" with any of the well pads serviced by this station. Contiguous or Adiacent In addition to the industrial grouping and common control aspects of the analysis, pollutant -emitting activities must be contiguous or adjacent in order to qualify as a single stationary source. Thus far, the only facilities which satisfy the first two portions of the three-part test are DCP owned and operated compressor stations and natural gas processing plants. The final portion of the three-part test has two distinct criteria; contiguous and adjacent. The difference between contiguous and adjacent is that the former indicates the two facilities/pollutant-emitting activities are physically touching, while the latter implies the facilities/pollutant-emitting activities are not widely separated, though they may not actually touch. The determination whether two sources are considered to be contiguous or adjacent is made on a case -by -case basis. This has been stated in the preamble to the August 7, 1980 PSD regulations and reiterated in a number of EPA guidance. documents. The Lucerne gas plant is physically isolated from other pollutant -emitting activities. The facility's boundary is surrounded by property owned by a third party and therefore the Division does not consider the facility to be contiguous with any other emission units not included in this project review. Under the PSD rule, which provides for the aggregation of facilities located on "contiguous or adjacent properties," a pipeline which runs through property owned by a third party would not, by itself, be considered a contiguous connection between two facilities. This is supported by the preamble to the PSD rule which states that long -line sources, such as power lines and pipelines, are not considered a single source (45 FR 52695). Page 14 AIRS Points When considering adjacency, there is no fixed distance that defines two sources as being adjacent and the reviewing agency must make the determination on a case -by -case basis. Recent EPA decisions have also considered the operational dependence of pollutant -emitting activities as a factor in making this determination, though it is important to note that the consideration of operational dependence is based on interpretation and not a fixed part of the rule or the definition of a term under the rule'. Furthermore, there have been significant conflicting determinations made by the individual Regional Offices of the EPA. In the case of Summit Petroleum Corp. vs. United States EPA, et at, an EPA Region 5 decision relying heavily on operational dependence was rejected by the 6th Circuit Court of Appeals. In light of the inconsistencies, the Division must base its decision on the text of the PSD rule, the Division's own interpretations of regulations based on decades of experience with source determinations, and the direct guidance of our own EPA Region 8. The Division requested DCP to analyze compressor stations and gas plants to assist us to determine if any additional pollutant emitting activities should be considered adjacent to the Lucerne gas plant. Based on information supplied by DCP, the Division understands there are no additional facilities that are located within a 2 mile radius of the Lucerne gas plant. The closest DCP facility is the Libsack compressor station which is 3.25 miles away. The Libsack compressor station is not wholly or even primarily dedicated to the operation of the Lucerne gas plant. Should either the Libsack compressor station or the Lucerne gas plant cease operation, gathered gas would still continue to flow to lower pressure areas within the gathering system. Additionally, none of DCP's compressor stations or gas plants within the 2,300 square mile Denver-Julesburg (DJ) Basin has a dedicated relationship to the Lucerne gas plant. Therefore, no other DCP owned pollutant -emitting activities in the DJ basin are adjacent to the Lucerne gas plant. Facility -wide Aggregation (continued) Conclusions Based on the common sense notion of a plant and the three-part analysis as discussed above, the Division determined the source determination for this facility is accurate. There are no additional pollutant -emitting activities that fulfill all three criteria necessary for aggregation with the Lucerne Gas Plant. 1 The term adjacency, as written in the 1980 PSD rule and associated preamble, has no relation to interdependence or operational relationship. The EPA has introduced this factor as an aide in making these case -by -case adjacency determinations. The Division considers EPA's guidance and exemplar decisions when conducting single source determinations. As such, the Division has considered interdependence as a factor in determining adjacency, as warranted, on a case -by -case basis. Page 15 AIRS Points 044 & 045 Natural gas turbines A permit will be issued area. PM1o, PM25, VOC and VOC = because the uncontrolled HAPS were calculated 0.0021 lb emissions from AP -42, 1023 Btu are greater than permitting Table 3.1-2a: 566.2 MMscf threshold for I T a non -attainment = 0.61 TPY PM = MMBtu 0.0066 lb scf 1023 Btu yr 566.2 MMscf 2000 lb I T = 1.91 TPY Particulate matter emission assumed to be 2.5 AP -42, Table 3.1-3 Acetaldehyde = MMBtu calculations microns in diameter 0.00004 lb scf include both condensable or less. 1023 Btu yr and filterab 566.2 MMscf 2000 lb e particulate. All particulate = 24.5 lb/yr is in lb/MMBtu = 0.0519 Acrolein (0.0000064 Benzene (0.000015 Ethylbenzene (0.000032 Formaldehyde (0.00071 Toluene (0.00013 lb/MMBtu) Xylenes (0.000064 Manufacturer data so that they are consistent NOx = MMBtu lb/MMBtu) 4 3.7 lb/MMBtu) 4 6.9 lb/yr lb/MMBtu) 4 lb/MMBtu) 4 4 75.3 lb/yr lb/MMBtu) 4 37.1 emission factors were with the rest 15.02 T scf lb/yr 18.6 lb/yr 410.8 lb/yr lb/yr provided for NOx of the source's emission 2000 lb yr and CO in lb/hr. Emissions calculations. mmscf were calculated year CO = year 17.61 T 1 T 2000 lb 1023 mmBtu mmscf 566.2 MMscf year lb/MMBtu = 0.0608 Stephanie Chaousy 1. Looking at listed on the agree with need one 2. I generated factors at the facility. If The source responded include emissions factors August 28, 2013: mmbtu/hr. This change process throughput VOC = (0.0021 lb/mmbtu)*(72.73 PM = (0.0066 Ib/mmbtu)*(72.73 SO2 = (0.0034 Ib/mmbtu)*(72.73 NOX E.F. = (15.02 CO E.F. = (17.61 TPY)*2000/ HAP emissions changed Acetaldehyde (0.00004 Acrolein (0.0000064 Benzene (0.000015 Ethylbenzene (0.000032 Formaldehyde (0.00071 Toluene (0.00013 Ib/MMBtu) Xylenes (0.000064 year emailed the operator AP -42, Table 3.1-3, Form 102. When my calculations, I for each turbine. Once new emission factors facility and therefore, you agree with my calculations, in agreement and in Ib/MMBtu. The operator requested did effect CO2 also required some mmbtu/hr)*(8760 mmbtu/hr)*(8760 mmbtu/hr)*(8760 TPY)*2000/ (999*637.7 (999*637.7 a little due to Ib/MMBtu) 4 Ib/MMBtu) 4 4.1 lb/MMBtu) 4 9.6 Ib/MMBtu) 4 lb/MMBtu) 4 4 82.8 lb/yr lb/MMBtu) 4 40.8 1 T on 1/23/13 (for both there is an emission I calculated formaldehyde, will need DCP to fill you have filled in for NOx and CO easier for the I will just provided the appropriate to increase the emissions as well adjusting as well. hr/yr) / hr/yr) / 2000 hr/yr) / mmscf/yr) = 0.0472 mmscf/yr) = 0.0553 the increase in throughput: 25.5 lb/yr lb/yr lb/yr 20.4 lb/yr 452.3 lb/yr lb/yr 1023 mmBtu points 044 and factor for formaldehyde, I calculated out the non -criteria the form, you can so that they are consistent inspector to use when redline the APEN reporting forms. rated capacity by 1.1 as VOC, PM2.5/PM10 Revised emissions 2000 = 0.67 TPY = 2.10 TPY 2000 = 1.08 TPY lb/mmbtu lb/mmbtu 566.2 MMscf 045):• however, formaldehyde a reportable value reportable form for formaldehyde. just email them to with all the calculating emissions accordingly. The APENs were from 66.12 mmbtu/hr and SO2. Emission and emission factors lb/MMBtu is not of 402 lb/yr. If you I will me PDF. other emission from the red -line to to 72.73 factors and are: Page 16 AIRS Point 046 Hot Oil Heater A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non - attainment area. Note that DCP chose to limit the capacity of the heater to 67% of full utilization. This is requested by the fuel use restriction of 315 mmscf/yr. AP -42, Table 1.4-3 Benzene = I 0.0021 lb 315 MMscf = 0.7 Ib/yr MMscf Formaldehyde (0.075 lb/MMscf) 4 23.6 lb/yr n-hexanes (1.8 lb/MMscf) 4 567 lb/yr Toluene (0.0034 Ib/MMscf) 4 1.1 lb/yr The permit engineer contacted the source regarding the original NOx emission factor provided with the application of 25 lb/MMscf. The source was asked to provide documentation from the manufacturer guaranteeing the proposed emission factor. The manufacturer's response asserted the unit was capable of emissions "as low as" the proposed rate. The Division accepts manufacturer's certifications that guarantee "not to exceed" emission rates. The Division does not consider the provided documentation which states an "as low as" emission rate to be sufficient. Based on review of test data of other hot oil heaters operating at gas plants, the average tested emission rate is 0.037 lb/MMBtu (converting to lb/MMscf = 0.037*999=37 Ib/MMScf). The Division notified the source that we would be willing to accept this rate with performance testing verification. DCP proposed to permit the heater at 37 lb/MMscf, to which the Division agreed. DCP is accepting a fuel use limit on this emissions unit to restrict emissions below potential to emit. This limit is required to enable this permit modification to remain below the 40 TPY NOx major modification significance level for NANSR review. AIRS Point 047 Amine unit Page 17 A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non - attainment area. The table below summarizes the inputs to the process simulation used to calculate the PTE for this equipment. Parameter Value Inlet Gas Temperature 78.14°F Inlet Pressure 900.5 psia Throughput 83,950 mmscf/yr Lean amine circulate rate 945 gpm Lean amine concentration 50 %w Flash Tank Temperature 157.848°F Flash Tank Pressure 72.33 psia Composition Estimated from representative DCP source Uncontrolled emission factor calculations from ProMax model not including flash stream: VOC = (166.90 TPY*2000)/83950 MMscf/yr= 3.98 lb/MMscf Benzene=(64.47*2000)/ 83950 MMscf/yr = 1.54 b/MMscf Toluene=(30.62*2000)/ 83950 MMscf/yr =0.729 b/MMscf Ethylbenzene =(1.11 TPY * 2000)/83950 MMscf yr = 0.0264 lb/MMscf Xylenes = (2.32 TPY* 2000)/83950 MMscf/yr = 0.0553 lb/MMscf n -hexane = (0.76 TPY * 2000)/83950 MMscf/yr = 0.0181 lb/MMscf An extended gas analysis and flow monitoring will be performed on the waste gas stream vented to the control device to monitor compliance with the VOC emission limitations for the source. The heating value will be verified by way of the extended gas analysis required on the waste gas stream to determine BTU loading on the control device and monitor compliance with the NOx emission limitation. The permitted NOx emissions for this modification are very close to the PSD threshold, and a small change in the assumptions made have the potential to affect if the project should be considered significant for NOx above 40 tpy. The permit application initially identified the regenerative thermal oxidizer controlling the amine unit as a separate unit emission point. Since the unit controls only emissions from the amine unit, the Division recommended the control device be reported as part of the controlled emission unit. Therefore the RTO was permitted as a part of the amine unit point. NOx and CO were calculated using emission factors from AP -42, Table 13.5-1: NOx = (0.068 lb/MMBtu)*(5.12 Btu/scf)*(2869 MMscf/yr)/2000 = 0.5 TPY CO = (0.37 lb/MMBtu)* 5.12 Btu/scf)*(2869 MMscf/yr)/2000 = 2.7 TPY SOx was calculated from mass balance inlet as compressed by points 047 and 048 Unit Compound DRE Inlet to RTO (lb/hr) Controlled RTO emissions (Ib/hr) Amine Unit Hydrogen Sulfide 96 3.96 0.16 Emissions were calculated by: Controlled SO2 hourly emission rate (lb/hr) = ((amine unit inlet to RTO-controlled RTO emissions) * SO2 MW) / H2S MW = ((3.96-.16)*64.06)/34.08 = 7.15 lb/hr Controlled SO2 emissions = (7.15 lb/hr)* (8760 hr/yr) / 2000 = 31.3 TPY Converting emission factor to lb/MMBtu: SOx = 31.3 T 2000 lb Yr mmscf = 4.2616 lb yr 1 T 2869 MMscf 5.12 mmBtu MMBtu AIRS Point 047 Amine unit continued Page 18 While the manufacturer of this unit guarantees a 99% control efficiency, the permittee is claiming 96% control efficiency for the unit for VOC, H2S and HAP. A stack test will be required on the unit to confirm control efficiency. The unit is a smokeless combustion device and no particulate matter emissions are expected according to the unit's manufacturer. The Division emailed the source on 1/23/13: The Division has started a preliminary review of the BACT and have some concerns regarding the RTO combustion emissions. -The RTO combustion emissions shown in the application only account for the amine unit stream. The emissions must also include the dehydrator and supplemental fuel. It appears that DCP included the dehydrator for GHG, but not for NOx and CO. This may affect the netting analysis for this project application. Please review the RTO combustion emissions and provide any new and revised information to the Division. The source submitted additional information changing the configuration of the equipment such that the dehydrator would no longer be routed to the RTO. The pilot gas emissions from the RTO were included in the submitted material as insignificant activity. June 27, 2013: The Division had a meeting with DCP and Trinity to discuss the Lucerne project (mostly a "catchup" meeting since the project has been transferred between engineers at the Division as well as contacts at DCP). Trinity provided new calculation sheets during the meeting to represent a conservative 1% downtime for the flash stream to account for downtime activities (so no longer 100% control from the flash tank as per the original application). This was brought to their attention by Bailey when she mentioned that downtime is treated accordingly as downtime and not as upset conditions, so if DCP believes they will have downtime, it needs to be accounted for in the emissions. When briefly reviewing the calculation sheet after the meeting, it was noted that the VOC emissions were greater than 40 TPY, which is over the major modification for VOC at a major facility. 1 emailed the operator and consultant immediately to bring this to their attention. They did not believe that the threshold was 40 TPY VOC because a significant emissions increase for ozone is considered 100 TPY in non - attainment areas of VOC and NOx (Reg 3, Part D, VI.B.3.D). Chris clarified for them that because this is a major facility and all criteria pollutants are already over the 100 TPY threshold, if DCP requests a modification greater than 40 tons per year of VOC for this project it would be considered a "major modification" unless DCP completes a netting analysis to show there is not a significant net emissions increase of VOC. We received an email from Trinity thanking for the clarification and said they would provide new calculations the following week. We received new calculations for the amine unit and dehydrator via email on 7/3/13. DCP has agreed that during downtime, the 1% from the flash stream will be routed to a flare at 95% destruction efficiency. Therefore, this change keeps VOC emissions under the 40 TPY threshold for this project. Therefore, it is not considered a major modification for VOC. At this time, I modified the emissions, emission factors, etc. in the PA, APENs and permit. Promax-Uncontrolled Emission factors with acid stream and flash stream emissions: VOC = ((557.23+166,9)*2000)/(230*365) = 17.2514 lb/mmscf (matches APEN received via email on 7/3/13) Benzene = ((5.44+64.47)*2000)/(230*365) = 1.6655 lb/mmscf (rounding; close to APEN received via email on 7/3/13. APEN shows 1.6656 lb/mmscf; will use this in the permit). Toluene = ((2.23+30.62)*2000)/(230*365) = 0.7826 lb/mmscf (matches APEN received via email on 7/3/13) Ethyl benzene = ((0.09+1.11)*2000)/(230"365) = 0.0286 lb/mmscf (rounding; close to APEN received via email on 7/3/13. APEN shows 0.0287 lb/mmscf; will use this in the permit). Xylenes = ((0.15+2.32)*2000)/(230*365) = 0.0588 lb/mmscf (matches APEN received via email on 7/3/13) N -hexane = ((8.39+0.76)*2000)/(230*365) = 0.2180 lb/mmscf (rounding; close to APEN received via email on 7/3/13. APEN shows 0.2179 lb/mmscf; will use this in the permit). To calculate the controlled emissions, it would be 96% control of the acid stream plus 95% control of 1% of the flash stream emissions: VOC = (166.9*.04) + (557.23*.01*.05) = 6.95 TPY VOC controlled (matches new APEN) Benzene = (64.47*.04) + (5.44*.01 ".05) = 2.58 TPY (5163 Ib/yr) (matches new APEN) Toluene = (30.62*.04) + (2.23*.01*.05) = 1.23 TPY (2452 I/byr) (matches new APEN) Ethylbenzene = (1.11*.04) + (0.09*.01*.05) = 0.04 TPY (89 Ib/yr) (matches new APEN) Xylenes = (2.32".04) + (0.15 * .01*.05) = 0.09 TPY (186 Ib/yr) (matches new APEN) n -hexane = (0.76*.04) + (8.39*.01*.05) = 0.03 TPY (69 Ib/yr) (matches new APEN) Page 19 AIRS Point 048 Glycol Dehydrator A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non - attainment area. In order to determine emissions, the operator used GRI GlyCALC 4.0. The source assumed the inlet gas temperature of 110°F and pressure of 865 psig. The permitted glycol recirculation rate is 40 gallons per minute. The design capacity of the glycol recirculation rate is 50 gpm. Therefore, the source is limiting capacity to minimize emissions. The inlet wet gas stream in the GlyCalc model was based off of a Promax simulation model. The amine unit wet gas stream is connected to the dehydrator. The permit will require periodic extended gas analysis to support actual emission calculations because one was not included with this application and a simulation model was used to predict the emissions. Stephanie emailed the operator on 1/23/13 with this question: For the dehydrator: I believe the emissions listed on the APEN did not include the emission from the flash tank. I believe you will need to add the uncontrolled regenerator emissions plus the flash tank off gas to get the total uncontrolled emissions. The source responding explaining the flash gas stream is routed directly to inlet compression. During downtime, flash gas emissions would not be vented uncontrolled. The equipment configuration is inherent to the process and not considered a control device such that uncontrolled emissions need to be quantified. The uncontrolled emissions from the dehydrator includes only those from the regenerator stream. Gly-Calc-Uncontrolled Emission factors (Regenerator Stream) not including flash tank: VOC = (380.6382*2000)/(230*365) = 9.07 lb/mmscf Benzene = (68.4141*2000)/(230*365) = 1.63 lb/mmscf Toluene = (44.4359*2000)/(230*365) = 1.06 lb/mmscf Ethylbenzene = (2.8464*2000)/(230*365) = 0.068 lb/mmscf Xylenes = (5.9362*2000)/(230*365) = 0.14 lb/mmscf N -hexane = (26.0851*2000)/(230*365) = 0.62 lb/mmscf Operator used AP -42, Table 1.4 emission factors for NOx and CO. The emission factors are for natural gas with a heat input of 1000 Btu/scf. The emission calculation for flared gas used heat input and input flow rate as estimated from GlyCalc modeling output. NOx = Flow rate x Heat input x Emission factor = (17400 scf/hr) x (120 Btu/scf) x (8760 hr) x (100 Ib/MMscf / 106) / (1000 Btu/scf x 2000 lb/ton) = 0.916 ton/yr CO = (17400 scf/hr) x (120 Btu/scf) x (8760 hr) x (84 lb/MMscf / 106) / (1000 Btu/scf x 2000 lb/ton) = 0.770 ton/yr MACT HH includes requirements for both major and area sources of HAPs. The definition of major source for MACT HH (63.761) states: (3) For facilities that are production field facilities, only HAP emissions from glycol dehydration units and storage vessels with the potential for flash emissions shall be aggregated for a major source determination. For facilities that are not production field facilities, HAP emissions from all HAP emission units shall be aggregated for a major source determination. Based on the definitions above, this source qualifies as natural gas processing plant. HAP emissions from all HAP emission units aggregated do not exceed the major source threshold and the unit is subject to the area source requirements in MACT HH. The following definitions from 63.761 are also needed to determine major source applicability: Production field facilities means those facilities located prior to the point of custody transfer Custody transfer means the transfer of hydrocarbon liquids or natural gas: after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportation. For the purposes of this subpart, the point at which such liquids or natural gas enters a natural gas processing plant is a point of custody transfer. Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, or the fractionation of mixed NGL to natural gas products, or a combination of both. Page 20 AIRS Point 048 Glycol Dehydrator continued Does this dehydrator have a reboiler? Yes If Yes, what is the reboiler rated? Indirect mmbtu/hr (what is on the APEN) Will have to request this information after construction because this reboiler may or may not meet the APEN- exemption of Regulation No. 3, Part A, II.D.1.k. Gly-Calc-Uncontrolled Emission factors (Regenerator Stream) with flash tank emissions: VOC = ((380.6382+324.9637)*2000)/(230*365) = 16.8101 lb/mmscf (matches APEN received via email on 7/3/13) Benzene = ((68.4141+1.6637)*2000)/(230*365) = 1.6695 lb/mmscf (rounding; close to APEN received via email on 7/3/13. APEN shows 1.6696 lb/mmscf; will use this in the permit). Toluene = ((44.4359+0.7903)*2000)/(230*365) = 1.0775 lb/mmscf (matches APEN received via email on 7/3/13) Ethylbenzene = ((2.8464+0.033)*2000)/(230*365) = 0.0686 lb/mmscf (matches APEN received via email on 7/3/13) Xylenes = ((5.9362+0.049)*2000)/(230*365) = 0.1426 lb/mmscf (matches APEN received via email on 7/3/13) N -hexane = ((26.0851+14.4472)*2000)/(230*365) = 0.9656 lb/mmscf (matches APEN received via email on 7/3/13) This system includes a BTEX condenser, reboiler, still vent, and a flash tank. The flash gas is routed to a closed loop system that utilizes a vapor recovery unit (maximum 1% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The still vent emissions are routed to a condenser and then to an enclosed combustor with a minimum destruction efficiency of 95%. There is initial control from the condenser and then 95% control from the flare. This source is subject to Regulation 7, Section XII.H, Uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. The combustion device used to control emissions of volatile organic compounds from these units to comply with Regulation 7, Section XII.D shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from the outside of the enclosed combustion device, or by other means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XII. To calculate the controlled emissions, it would be 95% control of the regenerator emissions plus 95% control of 1% of the flash tank emissions: VOC = (380.6382*.05) + (324.9637*.01 *.05) = 19.19 TPY VOC controlled (the new APEN said 21.46 TPY. I emailed the operator on 7/8/13 to confirm which calculation is right. I believe the consultant's included ethane in the total VOC). She wrote back on 7/8/13 confirming 19.19 TPY is the correct VOC emission limit. Benzene = (68.4141*.05) + (1.6637*.01*.05) = 3.42 TPY (6843.1 Ib/yr) (matches new APEN) Toluene = (44.4359*.05) + (.7903*.01*.05) = 2.22 TPY (4444.4 1/byr) (matches new APEN) Ethylbenzene = (2.8464*.05) + (0.033*.01*.05) = 0.14 TPY (284 Ib/yr) (matches new APEN) Xylenes = (5.9362*.05) + (0.049 * .01 *.05) = 0.297 TPY (593.7 Ib/yr) (matches new APEN) n -hexane = (26.0851*.05) + (14.4472*.01*.05) = 1.31 TPY (2623 lb/yr) (matches new APEN) Page 21 AIRS Point 050 Condensate storage tanks A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non - attainment area. Operator used AP -42, Table 1.4 emission factors for NOx and CO. The emission factors are for natural gas with heat input of 1000 Btu/scf. The emission calculation for flared gas used heat input and input flow rate as estimated from engineering calculations. During operator draft review (comments received 8/2/13), DCP decided to change the equipment from eight -400 bbl tanks to 4-1000 bbl tanks. This change slightly increased the emissions as well as making this source subject to Kb and not Regulation 7. Changes were made to the permit and PA accordingly. NOx = Flow rate x Heat input x Emission factor = (49.71 scf/hr) x (3397 Btu/scf) x (8760 hr) x (100 Ib/MMscf / (1000 Btu/scf x 2000 lb/ton) = 0.074 ton/yr CO = (49.71 scf/hr) x (3397 Btu/scf) x (8760 hr) x (84 lb/MMscf / 106) / (1000 Btu/scf x 2000 lb/ton) = 0.062 ton/yr HAPS were calculated using a VOC speciation from a condensate analysis performed at a similar DCP site. a 106) / Component VOC wt% from condensate analysis Uncontrolled Emissions (Ib/yr) Controlled emissions at 95% (Ib/yr) Benzene 1.3287 1296.9 64.8 Toluene 3.6822 3595.1 179.8 Ethylbenzene 0.2743 267.0 13.4 Xylenes 2.7832 2717.8 135.9 n -hexane 7.1492 6980.4 349.0 Uncontrolled Emission Factors VOC = (47.68* 2000) / 456250 = 0.209 lb/bbl (matches APEN) * 1000/42 = 4.9764 lb/1000 gal Benzene = (1296.9) / 456250= 0.00284 lb/bbl (matches APEN) *1000/42 = 0.0677 lb/1000 gal Toluene = (3595.1) / 456250= 0.00788 lb/bbl (matches APEN) * 1000/42 = 0.1876 lb/1000 gal , Ethylbenzene = (267) / 456250= 0.00059 lb/bbl (matches APEN) * 1000/42 = 0.0139 lb/1000 gal Xylenes = (2717.8) / 456250= 0.00596 lb/bbl (matches APEN) * 1000/42 = 0.1418 lb/1000 gal n -hexane = (6980.4) / 456250= 0.0153 lb/bbl (matches APEN) * 1000/42 = 0.3643 lb/1000 gal This source is located in the 8 -hour ozone non -attainment area. Therefore, the provisions of Regulation 7, Section XII do apply to this source. Page 22 AIRS Point 051 Truck Condensate Loadout A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non - attainment area. Operator used AP -42, Table 1.4 emission factors for NOx and CO. The emission factors are for natural gas with a heat input of 1000 Btu/scf. The emission calculation for flared gas used heat input and input flow rate as estimated from engineering calculations. All loading operations shall occur in vapor balance service, such that all tanker truck vapors are routed to and controlled by the enclosed combustor. The vapor return hose shall be connected at all times during loading operations. NOx = Flow rate x Heat input x Emission factor = (60.57 scf/hr) x (3397 Btu/scf) x (8760 hr) x (100 lb/MMscf / 106) / (1000 Btu/scf x 2000 lb/ton) = 0.090 ton/yr CO = (60.57 scf/hr) x (3397 Btu/scf) x (8760 hr) x (84 lb/MMscf / 106) / (1000 Btu/scf x 2000 lb/ton) = 0.076 ton/yr Units Basis S 0.6 Submerged loading: dedicated normal service based on source's description P 5.0032 Psia Estimated based on representative extended natural gas sample at a DCP facility. M 66 lb/lb-mole Estimated based on representative extended natural gas sample at a DCP facility. T 512.45 Deg R Estimated based on representative extended natural gas sample at a DCP facility. L 4.82 lb/10^3 gal 0.20 lb/bbl This value is used to calculate annual emissions. A control efficiency of 95% for an enclosed combustor is applied. AP -42: Chapter 5.2 Equation 1 L = 12.46*S*P*M/T L = loading losses in lb per 1000 gallons loaded S = Saturation Factor P = true vapor pressure of liquid loaded [psia] M = molecular weight of vapors [lb/lb-mole] T = temperature of bulk liquid loaded [deg. R] L 4.82lb/10^3 gal 0.201 b/bbl Annual requested Throughput 456,250bb1/yr Annual requested VOC emissions 923201b/yr 46.16tpy Controlled requested VOC emissions 46201b/yr 2.31tpy Uncontrolled emission factors for non -criteria pollutants are: Benzene = (0.63 * 2000) / 456250= 0.0028 lb/bbl * 1000/42 = 0.0656 lb/1000 gal Toluene = (1.74 * 2000) / 456250= 0.0076 lb/bbl * 1000/42 = 0.1817 lb/1000 gal Ethylbenzene = (0.13 * 2000) / 456250= 0.0006 lb/bbl * 1000/42 = 0.0135 lb/1000 gal Xylenes = (1.32 * 2000) / 456250= 0.0058 lb/bbl * 1000/42 = 0.1374 lb/1000 gal n -hexane = (3.38 * 2000) / 456250= 0.0148 lb/bbl * 1000/42 = 0.3529 lb/1000 gal I wanted to clarify the control setup for the loadout because the tanks. I emailed DCP on 10/8/13 and this is what they said: The control device for the loadout is tied to the same enclosed combustor as the storage tank. The loadout does not have a vapor balance system, so "no, the vapor balance should not be included with the loadout." Page 23 AIRS Point 052 Fugitive VOC Leak Emissions A permit will be issued because the uncontrolled emissions are greater than permitting threshold for a non - attainment area. The fugitive emissions point includes only newly installed components. These components will be subject to NSPS Subpart OOOO. The source is required to have a LDAR program in accordance with state and federal regulations. The following emission reductions have been approved by component type for the LDAR program. Component Control Efficiency Connections 30 Flanges 30 Open -Ends 75 Pumps 88 Valves 95 Other 75 Emissions were calculated using emission factors from EPA Protocol for Equipment Leak Emission Estimates, EPA, November 1995, EPA -453/R-95-017. The control factors for pumps and valves were taken from EPA's "LDAR —A Best Practices Guide" for a representative LDAR program. The control factors for the remaining component types are identical to Division approved control factors for similar LDAR programs implemented by DCP at other Colorado facilities. The initial application included components counts inconsistent with other submittals for the facility. A corrected count was requested. A new APEN with correct counts and emission calculations was provided on 3/12/13. It was not signed, so I will use it as a guideline to redline the original APEN. During operator draft review (comments received 8/2/13), the operator increased the component count and removed the 20% safety factor. I made revisions to the PA, permit and APEN accordingly. Page 24 Summary of Preliminary Analysis & Prevention of Significant Deterioration Review Air Pollution Control Division Stationary Sources Program Colorado Department of Public Health and Environment October 2013 Permit Number: AIRS ID: Application Completeness Date: Applicant: Location: Permit Engineer: Reviewer: 12WE2024 Issuance 1 123/0107 Points 044 through 052 June 19, 2012 DCP Midstream, LP 31495 Weld County Road 43 Weld County. Carissa Money Chris Laplante DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 Table of Contents I. PROJECT DESCRIPTION 1 II. PROJECT LOCATION 2 III. APPLICABLE REGULATIONS 2 IV. BACT & RACT ANALYSIS 4 V. CONCLUSION AND PROPOSED ACTION 26 I. PROJECT DESCRIPTION DCP Midstream, LP has submitted a request to modify their Lucerne Gas Processing Plant to include a new processing train referred to as the Lucerne 2 expansion project. The application for modification was received June 19, 2012 and requested to add a 230 million cubic feet per day (MMSCFD) processing train. The application was considered administratively complete on June 19, 2012. The application is deemed complete as of the day of receipt since the Division did not notify the applicant that the application was incomplete within sixty calendar days of receipt (Regulation No. 3, Part B, Section lll.B.4). The existing facility is a natural gas processing plant operating under SIC code 1321 capable of processing 85 MMSCFD. The facility is an existing major stationary source for carbon monoxide (CO), volatile organic compounds (VOC) and oxides of nitrogen (NOx) in an ozone nonattainment area. The new 230 MMSCFD processing train will receive third party field produced natural gas, remove entrained carbon dioxide (CO2) and water, extract natural gas liquids (NGL) and then re - compress the residue gas stream for sales. The existing and proposed emissions at the facility are as follows: Pollutant NO x VOC PM PMm PM2s Fugitive VOC SO2 CO HAPs Existing Equipment 204.0 110.4 8.2 13.8 12.5 233.9 9.4 Proposed Facility Total 241.4 143.6 13.2 31.1 46.1 286.0 22.9 Project Emissions Increase* 37.4 33.2 5.0 17.3 33.6 52.1 13.0 Project emission increase does not include emissions from ins gnificant activity The CO2 will be removed from the inlet gas stream uti izing one (1) 230 MMSCFD amine sweetening unit, with a lean amine recirculation rate of 945 gallons per minute (gpm). The gas stream will then be dehydrated using one (1) 230 MMSCD triethelyene glycol dehydration unit with a lean glycol recirculation rate of 40 gpm. The still vent emissions from the amine unit will be routed to a thermal oxidizer. The still vent emissions from the glycol dehydrator will be routed to a condenser and then to an enclosed combustor for control of VOCs and methane (CH4). Flash emissions from the amine and glycol dehydrator units will be collected and recycled back to the plant inlet using a vapor recovery unit (VRU). During VRU downtime, flash tank emissions will be routed to an emergency flare. The dry gas will then run through the cryogenics plant to remove NGL. The residue gas from the cryogenics unit will be compressed utilizing two (2) 72.73 MMBtu/hr natural gas combustion turbines driving compressors to deliver the gas to the transportation pipeline. The turbines will be equipped with a Waste Heat Recovery Unit (WHRU) System. An additional heater, design rated at 50 MMbtu/hr will provide supplemental heat. Condensate removed from the inlet gas using a separator will be stored in four (4) 1,000 -bbl condensate tanks prior to removal via a condensate truck loadout. The Division views the requested permit changes to be a physical change and a change in the method of operation. As such, the project needs to be reviewed to determine if a major modification is triggered under the Prevention of Significant Deterioration (PSD) rules. This review includes determining the emission increases associated with this project to establish if a significant emission increase will occur for any regulated New Source Review (NSR) pollutant. 1 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 Since this project consists of an independent processing train, the construction and operation of equipment at the Lucerne 2 expansion site should not have any effect on operations at the existing Lucerne plant. The Division does not believe, based on information provided in the application that any debottlenecking or increased utilization will occur at existing emission units. The revised construction permit will include all applicable requirements, including BACT requirements, emission limitations, production limitations, monitoring/testing requirements, and other applicable state and federal requirements. II. PROJECT LOCATION The proposed modification at the Lucerne Gas Processing Plant is located in Weld County. The street address is 31495 WCR 43, Greeley, CO. The geographic coordinates for this facility are as follows: Latitude: 40° 27' 25.84" N Longitude: 104° 39' 51.72" W This facility is located in an area designated by the EPA as a non- attainment area for ozone. The area is designated as attainment for all other pollutants. III. APPLICABLE REGULATIONS Public Notice: This application is subject to public comment for the following reasons (Regulation No. 3, Part B, III.C): • Projected controlled increase in emissions exceed 25 tons per year. • The modification is subject to a BACT determination. In addition, any interested person may submit a written request for a public comment hearing to be held pursuant to section 1.7.0. of the commission's procedural rules to receive comments regarding the foregoing concerns, the sufficiency of the preliminary analysis, and whether the division should approve or deny the permit application. Best Available Control Technology (BACT): The proposed modification will not result in a significant increase in emissions for NOx, CO, VOC, SO2, PM, PM1o, or PM2,5 (Regulation No. 3, Part D, VI.A.1). Potential emissions from the proposed modification are above PSD significance thresholds for CO2e only. DCP's application is subject to PSD review for the pollutant greenhouse gases (GHGs), because the project would lead to an emissions increase of GHGs for a facility as described at Colorado Regulation No. 3, Part A, Section I.B.44. Under the project, increased GHG emissions will have a mass basis over zero tpy and carbon dioxide equivalent (CO2e) emissions are calculated to exceed the applicability threshold of 75,000 tpy (DCP calculates CO2e emissions from the proposed project of 264,828 tpy). The Division is the permitting authority for regulated NSR pollutants including GHGs. Thus, the permit will address GHGs as well as criteria pollutants. Since GHGs are emitted above the significance levels, a BACT review is required for GHGs. See Section IV below for the BACT Analysis. Source Impact Analysis: Regulation No. 3, Part D, VI.A.2 would require the owner or operator of the proposed source or modification to demonstrate to the Division that allowable emission increases from the proposed source or modification in conjunction with all other applicable 2 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 emissions increases or reductions (including secondary emissions) will not cause or contribute to concentrations of air pollutants in the ambient air in violation of: • Any state or national ambient air quality standard in any baseline area or air quality control region; • Any applicable maximum allowable increase over the baseline concentration in any area. However, consistent with EPA guidance, the Division has not required the applicant to model emission impacts or conduct ambient monitoring for GHGs, and we have not required any assessment of impacts of GHGs in the context of the additional impacts analysis or Class I area provisions. This approach is based on the fact that no National Ambient Air Quality Standards (NAAQS) or Increment standards exist for GHGs. Additionally, since requested emissions of other pollutants do not exceed the significance thresholds, a source impact analysis is not required per the provisions of Regulation 3, Part D, Section VI.B.1.b. MACT and NSPS: The proposed equipment will be subject to several federal regulations including: • NSPS Dc applies to steam generating units having a maximum design heat input capacity less than or equal to 100 MMBtu/hr but greater than or equal to 10 MMBtu/hr that are constructed, reconstructed or modified after June 9, 1989. This facility will have one (1) heater with a design input rating at 50 MMBtu/hr and a construction date after June 9, 1989. Therefore, this heater will be subject to this subpart. • NSPS Kb applies to each storage vessel with a capacity greater than or equal to 75 cubic meters (approximately 471 bbl) that is used to store volatile organic liquids for which construction, reconstruction or modification commenced after July 23, 1984. This facility will have four (4) stabilized condensate storage tanks each with a capacity of 1,000 bbl and each with a construction date after July 23, 1984. Therefore, these storage tanks will be subject to NSPS Kb. NSPS KKKK applies to stationary combustion turbines with a heat input at peak load equal to or greater than 10 MMBtu/hr, which commenced construction, reconstruction or modification after February 18, 2005. This facility will operate two (2) stationary combustion turbines each with a design heat input rate of 72.73 MMBtu/hr and a construction date after February 18, 2005. Therefore, these turbines will be subject to NSPS KKKK. • NSPS OOOO applies to each sweetening (amine) unit and each sweetening unit followed by a sulfur recovery unit manufactured after August 23, 2011. The one (1) amine unit at this facility will not be subject to NSPS OOOO because the amine unit will have a design capacity less than 2 long tons/day H2S in the acid gas based on the information submitted in the application. This source will be required to keep for the life of the equipment an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2S expressed as sulfur. No other requirements will apply to the amine unit. • NSPS OOOO applies to equipment Leaks of VOC from onshore natural gas processing plants. Affected facilities at onshore natural gas facilities (any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids (NGLs) or both) after August 23, 2011. This facility is considered a natural gas processing plant with a construction date after August 23, 2011. Therefore, it is subject to this subpart. • MACT HH includes requirements for both area and major sources of HAPs. The proposed facility will not be considered a major source of HAPs; thus, only the area source requirements are applicable. MACT HH area source requirements apply to triethylene (TEG) glycol dehydration units. The facility will operate one (1) TEG dehydratrion unit which will be subject to area source MACT HH requirements. 3 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 IV. BACT & RACT ANALYSIS Best Available Control Technology (BACT) has been defined in Colorado's Regulation No. 3, Part D, II.A.8 as "An emission limitation (including a visible emissions standard) based on the maximum degree of reduction of each regulated NSR pollutant that would be emitted from any proposed major stationary source or major modification that the Division or Commission, on a case -by -case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of the best available control technology result in emissions of any pollutant that would exceed emissions allowed by the applicable standards in the Code of Federal Regulations, Title 40, Parts 60 and 61 (Regulation No. 6, Part A, and Regulation No. 8, Part A) as in effect on the effective date of this clause, but not including later amendments, unless such amendments are specifically incorporated by reference in accordance with the provisions of Colorado Revised Statutes section 24-4-103 (12.5)." Since GHGs are emitted above the significance levels, a BACT review is required for GHGs. Note that the Division has applied the policies and practices reflected in the EPA document entitled "PSD and Title V Permitting Guidance for Greenhouse Gases" (March 2011). Consistent with that guidance, we have not required the applicant to model or conduct ambient monitoring for GHGs, and we have not required any assessment of impacts of GHGs in the context of the additional impacts analysis or Class I area provisions. Instead, the Division has determined that compliance with the BACT analysis is the best technique that can be employed at present to satisfy the additional impacts analysis and Class I area requirements of the rules related to GHGs. For the BACT analysis, control technologies were evaluated using EPA's "top -down" 5 -step analysis procedure to make the BACT determination. This procedure ensures that each determination considers the most stringent control technologies available, and presents a reasoned justification for the BACT determination, considering energy, environmental and economic impacts and other costs. EPA has published industry specific white papers that summarize information on control techniques and measures to mitigate greenhouse gas emissions for specific industrial sections. EPA has not yet published a white paper specific to oil and gas industry. The Division has reviewed certain white papers to help inform this evaluation where appropriate. The Division has also reviewed recent GHG BACT permits issued by EPA Region 6 for similar oil and gas facilities. Applicable Emission Units The majority of the GHG emissions associated with the project are from combustion sources (i.e., turbines, heater, flare, and thermal oxidizer), amine unit and glycol dehydration unit. The piping component leaks (i.e., fugitive emissions) and condensate storage tanks and loadout contribute a small amount of GHGs. Stationary combustion sources and dehydration unit primarily emit CO2, and small amounts of nitrous oxide (N2O) and methane (CH4). The amine unit emits primarily CO2 and a small amount of CH4. Within the permit application, DCP provided a 5 -step top -down BACT analysis for each GHG emission source. The BACT analyses and other technical information in DCP's application are incorporated into this analysis and technical review document. The following equipment is subject to this GHG PSD Permit: • One (1) Amine Unit • One (1) Triethylene Glycol Dehydration Unit • Two (2) Combustion Turbines • One (1) Heater 4 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 • Four (4) Condensate Storage Tanks • One (1) Condensate Truck Loadout • Fugitive Component Leaks • Insignificant Activity Amine Unit The proposed expansion will include one amine unit (AU -02) design rated to process 230 MMscf per day of natural gas. A primary purpose of the amine unit is to remove CO2 from the natural gas. The generation of CO2 is inherent to the process, and a reduction of CO2 emissions by process changes would only be achieved by a reduction in the process efficiency, which would result in natural gas that would not meet pipeline quality specifications and leave CO2 in the natural gas for emission to the atmosphere at downstream sources. DCP identified five potential control technologies for the BACT analysis. The initial application was supplemented with additional information to include a more comprehensive analysis of the feasibility and availability for carbon capture and sequestration technology. The Division's review of each of the options will be discussed in detail. 1. Carbon capture and sequestration 2. Tank off -gas recovery systems 3. Regenerative thermal oxidizer 4. Flare 5. Proper design and operation 1. The highest ranked control technology for the amine units was Carbon Capture and Storage (CCS). DCP estimated approximately 90% CO2 control of the amine acid gas stream using CCS technology. In their evaluation of the most effective controls, CCS was deemed not feasible due to technical, environmental, and economic reasons. The CCS process involves capturing CO2, transporting it as necessary, and then permanently storing it instead of releasing it into the atmosphere. The process requires: • Capturing CO2 at its source by separating it from other gases. • Transporting the captured CO2 to a suitable storage location (typically in compressed form) and • Storing the CO2 in underground geological formations or within certain mineral formations. There are two potential methodologies for geological carbon storage. The first is enhanced oil recovery (EOR), which utilizes injected CO2 gas to improve oil displacement efficiencies. The second form of geological carbon sequestration is direct CO2 injection for the purpose of long-term storage. In regards to considering CCS in a BACT analysis, EPA made the following statements in their guidance document : For the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add-on pollution control technology that is "available A for facilities emitting CO2 in large amounts, including fossil fuel -fired power plants, and for industrial facilities with high -purity CO2 streams... This does not necessarily mean CCS should be selected as BACT for such sources. Many other case - specific factors, such as the technical feasibility and cost of CCS technology for the specific application, size of the facility, proposed location of the source, and availability and access to transportation and storage opportunities, should be assessed at later steps of a top -down BACT 'Id. DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 analysis. However, for these types of facilities and particularly for new facilities, CCS is an option that merits initial consideration and, if the permitting authority eliminates this option at some later point in the top -down BACT process, the grounds for doing so should be reflected in the record with an appropriate level of detail. A As noted above, a control option is "available" if it has a potential for practical application to the emissions unit and the regulated pollutant under evaluation. Thus, even technologies that are in the initial stages of full development and deployment for an industry, such as CCS, can be considered "available" as that term is used for the specific purposes of a BACT analysis under the PSD program. In 2010, the Interagency Task Force on Carbon Capture and Storage was established to develop a comprehensive and coordinated federal strategy to speed the commercial development and deployment of this clean coal technology. As part of its work, the Task Force prepared a report that summarizes the state of CCS and identified technical and non -technical challenges to implementation. EPA, which participated in the Interagency Task Force, supports the Task Force's recommendations concerning ongoing investment in demonstrations of the CCS technologies based on the report's conclusion that: "Current technologies could be used to capture CO2 from new and existing fossil energy power plants; however, they are not ready for widespread implementation primarily because they have not been demonstrated at the scale necessary to establish confidence for power plant application. Since the CO2 capture capacities used in current industrial processes are generally much smaller than the capacity required for the purposes of GHG emissions mitigation at a typical power plant, there is considerable uncertainty associated with capacities at volumes necessary for commercial deployment." See Report of the Interagency Task Force on Carbon Capture and Storage, p.50 (http://www.epa.goviclimatechange/policy/ccs_task_force.html). In the same document, EPA asserts "specifically, EPA considers a technology to be "available" where it can be obtained through commercial channels or is otherwise available within the common meaning of the term." (In re Cardinal FG Company, 12 E.A.D. at 14; In re Steel Dynamics, Inc., 9 E.A.D. at 199). The practicability, technically feasibility and cost effectiveness of CCS were thoroughly reviewed to satisfy EPA's request for a detailed determination and to confirm DCP's analysis. The Division's intent was to examine the current status of the technology and consider its availability as a potential control technology for this project. Carbon Capture Given the nature of this emission unit, the feasibility of CO2 isolation is highly practical. The acid gas emissions from the amine unit consists of an almost pure CO2 stream. This conclusion is supported by EPA's PSD guidance document, as cited above, which states CCS technology is available for high -purity CO2 streams. The portion of the amine acid gas stream which is not CO2 is comprised mainly of H2S and small fraction of water and hydrocarbons. In order to isolate CO2 to the extent necessary for transportation via a dedicated CO2 pipeline, additional treatment is necessary. The equipment needed to remove additional constituents of the acid gas stream includes scrubbers and a dehydrator. This equipment will have ancillary environmental impacts in the way of sulfur compounds and hydrocarbon emissions. Considering the alternative proposal to a carbon capture system, which is routing the acid gas stream directly to a combustion device, converting all entrained H2S to SO2 and VOC to CO2, CO and NON, the ultimate difference in emissions would likely be insignificant. The Division considers carbon capture and isolation technologically feasible DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 and practical for implementation. The costs associated with the carbon capture component of the CCS technology was not specifically isolated, rather their associated costs were included in the overall cost assessment of the CCS technology. CO2 Injection for Long -Term Storage CO2 injection for the purpose of long-term storage has been implemented on a large-scale for over a decade. The first major large-scale operation was in the offshore Sleipner fields of Norway. The company Statoil began the project in 1996 in response to a Norwegian carbon tax. Sequestration is achieved by separating CO2 from the natural gas stream using amine units and injecting the pure CO2 into a deep water saline aquifer in the North Sea2. Chevron's Gorgon Project in Australia is the first project to be regulated under legislation dedicated to GHG storage and is the world's first large-scale storage project to have been subject to an exhaustive, publicly available environmental impact assessment3. Project construction has begun, and injection operations are anticipated to begin in 2014.4 Both of these examples of large-scale CO2 injections occur in saline formations. Saline formations are believed to have the highest potential for geological sequestration activities.° Since the initial deployment of long term CO2 storage several demonstration projects have occurred internationally, the DOE has sponsored several domestic large-scale efforts°. The intent of these studies is to confirm the reliability and repeatability of CO2 storage systems. The impact of CO2 injection on the fate and transport of subsurface constituents is an area of ongoing research.' National labs and research institutions nation-wide have been commissioned to future investigate the effectiveness, impact, and reliability of geological sequestration °. The next step in the deployment of this technology in the United States is conducting geological analyses to identify geologic formations amenable to long term CO2 injection. Depleted oil and gas fields, such as those present in Colorado, are a promising reservoir for future sequestration.9 The efforts of the Southeast Regional Carbon Sequestration Partnership have identified several potential reservoirs in the Southeastern United States and are conducting ongoing field testing to verify their findings.10 The DOE projects this process to occur nationwide in the immediate future and predicts that reservoirs will be identified as early as 2015. As cited by DCP, the DOE estimates that the technology will be available for commercial implementation by 2020. 2 Statoil. "Annual and Sustainability Report 2008: Sleipner CCS" <http://www. statoil. com/Ann ual Report2008/en/Sustainability/CI imate/Pages/5-3-2- 3 SleipnerCCS.aspx> (April 2, 2013) 3' Chevron. "Frequently Asked Questions About Climate Change" <http://www.chevron.com/globalissues/climatechande/faq/> (April 2, 2013) 4 Id. 5 Friedmann, S.J. (2007)"Carbon Capture and Sequestration Technologies: Status and Future Deployment." Lawrence Livermore National Laboratory, Livermore, California. ° National Energy Technology Laboratory, U.S. Department of Energy. "Carbon Storage: Large - Scale Field Tests" http://www.nett.doe.gov/technologies/carbon seci/infrastructure/largescale.html> (April 2, 2013) / Lawrence Livermore National Laboratory. "Carbon Capture and Storage: Modeling Reactive Transport of CO2 in Groundwater" https://energv.11nl.gov/ccs-docs.php?id=4 (April 2, 2013) 8 National Energy Technology Laboratory, U.S. Department of Energy. "Carbon Storage: Geologic Storage Focus Area" <http://www.netl.doe.gov/technologies/carbon sea/corerd/storage.html> (April 2, 2013) 9 Friedmann, S.J. (2007)"Carbon Capture and Sequestration Technologies: Status and Future Deployment." Lawrence Livermore National Laboratory, Livermore, California. t0 Southeast Regional Carbon Sequestration Partnership. "Projects". <http://www.secarbon.org/index.php?page id=8> (April 2, 2013) DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 At this point in time, no area suitable for geologic CO2 storage has been identified in the area surrounding the facility. An alternative option for implementing this technology is to transport gas to an area which is suitable for CO2 injection. DCP and the Division have not been able to identify any commercial permanent CO2 injection operations outside of externally funded research projects in the United States. Based on research of the available literature on the subject, the Division concludes that CO2 injection is a promising approach that has thus far proven as an effective long-term solution for CO2 emissions which has the potential for significant environmental benefit in the future. However, the scientific community and its domestic industrial partners are in agreement that at the present moment, within the practical timeline for this project, conducting CO2 injection at a commercial scale in Colorado is currently infeasible. While in general application, the technology is available, CO2 injection for long term storage is not currently feasible for application in this project. An analysis of the economic, social, and environmental impacts of compressing, transporting, and injecting CO2 is not possible given the technology is still a conceptual idea. Since, at this time, there is no existing infrastructure to tie into and there are no reservoirs identified as suitable for CO2 injection, the Division has determined CO2 injection for long-term storage is currently unavailable and technically infeasible. CO2 Injection for Enhanced Oil Recovery EOR has been implemented on a commercial scale for several decades as a tool to improve oil production". The oil industry has a proven record of safely injecting CO2 into geological formations.12 One of the reasons FOR is so widely discussed and examined in the CCS conversation is that the proven technologies and operating procedures used in the FOR practice may be directly applied to the CO2 injection for long term storage field. There is significant conflicting interest in FOR versus CO2 injection for the purpose of permanent storage. In the former case, because the intent is to further economic gain, the operator is encouraged to limit CO2 injection to what is the absolute minimum necessary to reach target production levels. Since EOR operators must pay for additional CO2 not available from immediate production area, the operator is economically incentivized to limit CO2 injection. The intent of sequestration is to inject and permanently store as much CO2 as possible. 13 If DCP were to transport CO2 to an FOR operator, the CO2 would only be utilized to the extent necessary to increase production. Another prominent concern regarding FOR practices is the extent to which CO2 is permanently stored or the equivalent of control efficiency for injected CO2. Historically the fate of injected CO2 in FOR operations has been largely unmonitored. The Weyburn-Midale project in Saskatchewan, which began in 200014 is a unique operation which has been extensively monitored over the last decade and shown successful permanent storage of 11 U.S. Department of Energy. "Enhanced Oil Recovery/CO2 Injection" <http://fossil.energy.qov/programs/oilgas/eor/> (April 2, 2013) 12 National Energy Technology Lab, U.S. Department of Energy. (2010) "Carbon Dioxide Enhanced Oil Recovery: Untapped Domestic Energy Supply and Long Term Carbon Storage Solution" <http://www.netl.doe.qov/technologies/oil-gas/publications/EP/CO2 EOR Primer.pdf> (April 2, 2013). a Id. 14 Carbon Capture and Sequestration Technologies, Massachusetts Institute of Technology. "Weyburn Fact Sheet: Carbon Dioxide Capture and Storage Project" <http://sequestration.mit.edu/tools/proiects/wevburn.html> (April 2, 2013) 8 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 injected gases.15 The results of that study were recently compiled into a document citing the best management practices for long-term CO2 storage facilities.16 In Texas, legislation has been passed to provide incentives for CO2-EOR operations that conduct monitoring and verification to reasonably demonstrate that 99% of the injected CO2 will be sequestered for 1,000 years.17 In accordance with 40 CFR Part 98 Subpart RR, an EOR operation can take credit for geological sequestration of CO2 provided a monitoring, reporting, and verification plan is submitted to the EPA which specifies strategies to detect and quantify potential surface leaks. The DOE asserts that flooded CO2 is constantly recycling during production and once production is finished the injected CO2 will remain underground indefinitely. The report does not address a potential increase in CO2 content of the oil for downstream release, the assumption is that entrained CO2 will be removed from the oil at the wellhead and directly re- injected into the ground.18 Studies of existing EOR sites have concluded leakage is unlikely to occur or have adverse impacts.19 Kinder Morgan reported that in 2008 0.3% of the total CO2 handled at EOR operations was ultimately emitted into the atmosphere.20 IPCC reports that the likelihood of an injection well leak is similar to that of a traditional hydrocarbon well21. Another study reported that the permanence of CO2 storage for an EOR site may likely be higher than that of CO2 injected solely for the environmental benefit.22 Reasons for this hypothesis are primarily due to the increased knowledge about the reservoir and resource properties due to a history of operations on that well. While a common control efficiency factor has yet to be identified, the information reviewed suggests 99% control of injected CO2 is possible for EOR operations. 23 This figure does not included losses in the carbon capture or transportation processes associated with implemented EOR as CCS. In the submitted BACT analysis, DCP assumed 90% control of the amine stream through the use of CCS. The control efficiency estimation is not well 15 National Energy Technology Lab, U.S. Department of Energy. (2010) "Carbon Dioxide Enhanced Oil Recovery: Untapped Domestic Energy Supply and Long Term Carbon Storage Solution" <http://www.netl.doe.qov/technologies/oil-qas/publications/EP/CO2 EOR Primer.pdf> (April 2, 2013). 6 Petroluem Technology Research Centre. "Weyburn-Midale" <http://ptrc.ca/proiects/wevburn- midale> (April 2, 2013) rte, J.R. and Phillips, S.J. (2010) "Enhanced Oil Recovery as Carbon Dioxide Sequestration". Technical Advisory Committee Report to the California Carbon Capture and Storage Review Panel. 18 National Energy Technology Lab, U.S. Department of Energy. (2010) "Carbon Dioxide Enhanced Oil Recovery: Untapped Domestic Energy Supply and Long Term Carbon Storage Solution" <http://www.netl.doe.gov/technologies/oil-qas/publications/EP/CO2 EOR Primer.pdf> (April 2, 2013). 9 Zhou, W., Stenhouse, M., and Arthur, R. (2005). "Assessment of Potential Well Leakage in the Weyburn Site Using a Stochastic Approach." Proc., 4th Annual Conference on Carbon Capture and Sequestration DOE/NETL, Hilton Alexandria Mark Center, Alexandria, Virginia. 20 Bradley, T. of Kinder Morgan. "The CO2 Enhanced Oil Recovery Story." <http://www.edf.oro/sites/defauit/files/10254 Bradlev.pdf> (April 2, 2013) 21 Intergovernmental Panel on Climate Change. Metz, B., Davidson, O., de Coninck, H., Loos, M., and Meyer, L. (Eds.) (2005). "Carbon Underground geological storage". Carbon Dioxide Capture and Storage. 22 Hovorka, S. (2010). "EOR as Sequestration — Geoscience Perspective: White Paper for Symposium on Role of EOR in Accelerating Deployment of CCS". 23 Fish, J.R. and Phillips, S.J. (2010) "Enhanced Oil Recovery as Carbon Dioxide Sequestration". Technical Advisory Committee Report to the California Carbon Capture and Storage Review Panel. 9 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 supported given the lack of available data. However, the Division feels the estimation is conservative enough for purposes of this hypothetical analysis. In a report cited in DCP's BACT analysis24, several formations in the vicinity of the Denver- Julesburg (DJ) Basin were screened as amenable for CO2 EOR. DCP does not conduct business in the exploration and production sectors and only operates midstream facilities. The company is not equipped to execute FOR and would therefore have to contract other entities to purchase CO2 for use in EOR operations. Due of the nature of CO2 supply and demand for EOR operations, a reliable contract would be difficult to procure. At the wellhead, entrained CO2 would be separated from the resource and re -injected into the reservoir. The priority for EOR operators would be to utilize the recycled CO2 rather than rely on externally provided OO2. DCP operations would produce a constant stream of OO2. After initial injection, once the amount of CO2 produced and recycled meets the level necessary for enhanced. recovery, the demand for an external CO2 source would be seldom and intermittent, at best. At this point the DCP CO2 stream would need to be released directly, effectively employing 0% control, or have backup wells in place with a demand for OO2. Since FOR systems impact, by way of improvement, the production rates in surrounding fields, it is impractical to assume a secondary FOR system would be available in a nearby location. The logistics of permitting and procuring contracts would be highly complex and extremely difficult. Due to geology of the DJ Basin and multiple owners/operators in the area, EOR is- not current feasible at any large scale level. Furthermore, since the infrastructure necessary for implementation of EOR in the DJ basin does not currently exist, the timeline for the development of such a system is not practical for application of this project. Outside the potential for immediate surrounding area, DCP estimated that the next nearest area actively utilizing FOR with CO2 would be approximately 150 miles from the proposed site. Under either circumstance, compression would be needed for transport. DCP noted it would require significant additional equipment to reduce exhaust temperature, compress the gas, and transport the gas via pipelines. These activities would result in significant criteria pollutant emissions and GHG emissions. Assuming the opportunity to transport CO2e within the DJ basin, DCP estimated 2000 HP of compression capacity would be needed. It is estimated that the addition of natural-gas fired engines powering the 2000 HP needed would result in the total project emissions exceeding the nonattainment NSR modification threshold for NOx. The implications of this increase are significant. Currently, the offsets needed to permit a nonattainment area NSR project are unavailable. If the compressors were powered by the electrical grid, there would be no net increase in NOx emissions within the boundary of the facility; however, there would be a resulting increase in demand from the electrical grid, which would in turn increase emission upstream. Due to the incomparable nature of GHG emission and criteria pollutants, in regards to both the existence of air quality standards as well as the global versus local health and environmental impact of the two different categories of pollutants, the Division cannot definitively say that additional equipment needed to implement CCS outweighs the environmental benefit from the implementation of the technology. Due to the absence of a demand for CO2 in the immediate area surrounding the facility as well as the logistical issues with developing OO2-EOR infrastructure and establishing reliable contracts, the Division considers FOR not technically feasible for the facility at this time. Cost Effectiveness 24 Advanced Resources International. (2006) "Basin Oriented Strategies of CO2 Enhanced Oil Recovery: Rocky Mountain Region of Colorado, Utah, and Wyoming" U.S. Department of Energy, Office of Fossil Energy — Office of Oil and Natural Gas. 10 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 In order to provide a comprehensive BACT analysis, DCP estimated the cost to transport the CO2 along both 15 (DJ Basin) and 150 miles of pipeline, assuming an FOR site is feasible. The cost analysis used DOE's guidelines for estimating carbon dioxide transport for the installation of an 8 -inch pipeline resulting in a total capital cost of $10.56 million and $99.78 million, respectively. These costs correspond to cost effectiveness of $12/ton and $71/ton CO2e, respectively, but does not include capital and operating and maintenance costs associated with the additional compression and processing equipment necessary for transport. The cost of this additional technology was calculated for the nearby basin only, estimated at $50 million. This brings the cost effectiveness to $30/ton. A dollar per ton cost effectiveness guideline has not been established for CO2e. The limited number of GHG BACT determinations25 presents a challenge in making an assessment regarding the cost effectiveness of GHG BACT technologies. The Division is unable to make a determination at this time regarding the cost effectiveness alone. The $30/ton figure is significantly lower than what has been reported for the very few similar determinations; it may imply that CCS would be an economically viable option if it were a feasible technology. Since at this time it is impractical for DCP to implement this technology as discussed above, the cost effectiveness is irrelevant. Furthermore, the overall costs necessary to implement this technology, if feasible, independent of the pollution benefits, is significant. DCP estimated the cost of implementing CCS to be approximately 34% of the total cost of the expansion project. EPA has indicated relative cost is a valid comparison26 and has used such a comparison for making BACT determinations.27 The Division considers this to be a prohibitive investment for the project and could lead to a determination that the absolute cost relative to the project would render the technology economically infeasible. Again, the Division is not obliged to determine economic feasibility for technologies that have been deemed unavailable or technically infeasible. The economic analysis discussion was included in this BACT analysis as a reference and to provide additional information for future determinations in this currently limited area. Division Determination In the GHG guidance document, EPA acknowledges that "while CCS is a promising technology, EPA does not believe that at this time CCS will be a technically feasible BACT option in certain cases. As noted above, to establish that an option is technically infeasible, the permitting record should show that an available control option has neither been demonstrated in practice nor is available and applicable to the source type under review."28 EPA specifies that "a permitting authority may conclude that CCS is not applicable to a particular source, and consequently not technically feasible, even if the type of equipment needed to accomplish the compression, capture, and storage of GHGs are determined to be generally available from commercial vendors."29 25 U.S. Environmental Protection Agency. "RACT/BACT/LAER Clearinghouse". <htto://cfpub.epa.ciov/rblc/index.cfm?action=Search.BasicSearch&lanq=eq> (April 2, 2013) 26 Donald Law, EPA, personal phone communication with Matt Burgett, ACPD, March 19, 2013. 27 Region VI of the Environmental Protection Agency. (2012). "Statement of Basis: Draft Greenhouse Gas PSD Permit for the Enterprise Products Operating LLC, Mont Belvieu Complex." < http://www.epamov/earth1r6/6pd/air/pd-r/oha/enterprise-sob.pdf > (March 18, 2013) 28 U.S. Environmental Protection Agency. (2011). "PSD and Title V Permitting Guidance for Greenhouse Gases" EPA -457/B-11-001, <http://www.epa.qov/nsr/ohodocs/ghgpermittinqquidance.pdf> (April 2, 2013). 29 Id. DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 While the CCS technology has been demonstrated in practice, specifically for EOR, and the technology has an application for high purity CO2 streams such as amine units, the Division believes implementation of this technology is not currently technically feasible for the DCP Lucerne expansion project. The BACT analysis as discussed in this document provides an adequate record for the Division's determination. 2. The amine unit emits methane at the point of amine regeneration, due to a small amount of natural gas becoming entrained in the rich amine. The amine unit is designed to include a flash tank, in which gases (i.e., including CO2 and methane) are removed from the rich amine stream prior to regeneration, thereby reducing the amount of waste gas created. A control technology considered in the analysis was installing a flash tank off -gas recovery system which DCP estimated as 99% control assuming that the flash tank off -gas is recycled back to the plant inlet and assuming 1% downtime for the vapor recovery unit. The proposed project includes electric -powered vapor recovery unit and no additional combustion is required on - site to power the unit, resulting in a minimum of 99% reduction of CH4 emissions from the flash tank off -gas. Additionally, DCP will route the flash tank off -gas to the emergency flare during periods of VRU downtime. 3. The next highest ranked control technology in the BACT analysis for the amine units was routing the still vent stream to a regenerative thermal oxidizer (RTO). The amine still vent stream includes a very small (<2%) CH4 content, which will be destructed in the regenerative thermal oxidizer and converted to OO2. In DCP's application, they stated that the RTO will achieve 96% reduction; however, as explained below, the Division increased this requirement to 99% for CH4. Since the global warming potential for CH4 used for GHG calculations is 21, this operation will result in overall reductions in OO2e emissions despite an increase in CO2 emissions. In this regard, combustion of the amine still vent stream is considered BACT with respect to the CH4 portion of the stream. Routing the amine still vent stream to the RTO requires additional assist gas to be fired to keep the RTO operational. The additional assist gas is a source of superfluous GHG emissions that are not essential or inherent in the process of an amine sweetening unit. However, the use of assist gas is necessary to maintain the combustion chamber temperature above 1,550°F to assure adequate combustion of the hydrocarbon stream routed to the unit. Utilization of assist gas represents a source of additional negative environmental impacts that are inherent to the implementation of this control technology. Note that the RTO serves a primary purpose for VOC control. 4. The flare has the same benefits of waste gas combustion in the RTO; however the flare is less efficient than the RTO. The additional negative environmental impacts due to the combustion of assist gas are at least comparable for an RTO or enclosed combustion device. Typically, additional assist gas is needed to operate a flare treating a waste stream with low heat -content, so the additional negative environmental impacts due to the combustion of assist gas in the flare would most likely be more significant than the RTO. Therefore, DCP proposed RTO as BACT for the still vent stream rather than the flare. 5. DCP "indentified proper design and operation as a feasible control technology. The BACT analysis also indicated the unit will be fired using pipeline quality natural gas. As the Division understands, combustion is not part of the equipment comprising this permitted emission unit and the use of natural gas is more appropriately associated with the thermal oxidizer. This control technology, as described in DCP's analysis, is simply a reassertion that the other control options, including condensers, combustion devices, flash tanks, and vapor recovery units will be properly designed. As part of the implementation of the other BACT options, the Division expects the equipment to be properly designed and therefore does not consider this specifically identified option as a unique control strategy. BACT outcome 12 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 DCP proposed to route the amine still vent (also referred to as the regenerator vent) emissions to an RTO, achieving 96% control of CH4, and route the flash tank emissions to a VRU, achieving a minimum of 99% control, to meet BACT. The Division reviewed GHG BACT limits and controls for similar amine units at other similar oil and gas facilities as summarized in the table below. Company/ Location Unit Description BACT Control BACT Emission Limit/ Requirement Year Issued Reference Copano Processing, LP, Houston Central Gas Plant Houston, TX 1 Amine unit (400 MMSCF per day) Regenerative Thermal Oxidizer (RTO) Good combustion practices for RTO Minimum CH4 destruction efficiency of 99% Minimum combustion temperature of 1,550 °F 2013 PSD-TX- 104949 - GHG DCP Midstream, LP, Jefferson County NGL Fractionation Plant Beaumont, TX 2 NGL Amine Unit (75,000 bpd each train) Thermal Oxidizer (TO) Good combustion practices for TO Minimum CH4 destruction efficiency of 99.9% Minimum combustion temperature of 1,500 °F 2013* PSD-TX- 110557 - GHG Energy Transfer Company (ETC), Jackson County Gas Plant Ganado, TX 4 NGL Amine units (200 MMSCF per day each) Flash tank recycled to plant inlet and still vent routed to TO Good combustion practices for TO Minimum CH4 destruction efficiency of 99.9% for TO Minimum combustion temperature of 1,400 °F 2012 PSD-TX- 1264-GHG Energy Transfer Partners, LP, Lone Star NGL Mont Belvieu, TX 2 NGL Amine Unit (100,000 bpd each train) Flash tank and still vent routed to TO Good combustion practices for TO Minimum CH4 destruction efficiency of 99% Minimum combustion temperature of 1,400 °F 2012 PSD-TX- 93813-GHG Kerr-McGee Gathering LLC Lancaster Plant Ft. Lupton, CO 4 Amine units (150 MMSCF per day each) Flash tank and still vent routed to Thermal Oxidizer Good combustion practices for TO Minimum CH4 destruction efficiency of 99% Minimum combustion temperature of 1,400 °F 2013 Colorado Construction Permit12WE1492 Issuance 1 ONEOK Hydrocarbon, LP, Mont Belvieu NGL Fractionation Plant Baytown, TX _ 1Amine Unit (75,000 bpd) Flash tank routed to flare gas recovery unit where it will be treated and then routed as fuel gas to Flue gas from heaters equipped with SCR and maximum flue gas exit temperature of 385°F, 365 -day rolling average 2013 PSD-TX- 106921 - GHG 13 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 E2024 Issuance 1 Company/ Location Unit Description BACT Control BACT Emission Limit/ Requirement Year Issued Reference heaters. Still vent routed directly to heaters and flue gas from heaters will be treated with SCR. Targa Gas Processing, LLC, Longhorn Gas Plant Decatur, TX 1 Amine Unit (200 MMSCF per day) Regenerative Thermal Oxidizer (RTO) Good combustion practices for RTO Minimum CH4 destruction efficiency of 99% Minimum combustion temperature of 1,500 °F 2013 PSD-TX- 106793- GHG Based on this review of similar units, the Division determined that routing f ash tank emissions to the plant inlet and still vent emissions to an RTO will satisfy BACT. The amine unit flash tank off - gases will be recycled via an electric powered vapor recovery unit resulting in a minimum of 99% control. During VRU downtime, the flash tank off -gases will be routed to an emergency flare achieving 95% control. The Division considers this control efficiency as BACT for the amine unit flash emissions. However, as summarized in the table above, the lowest CH4 destruction efficiency approved as BACT for a thermal oxidizer or RTO is 99%. The RTO manufacturer specifications provided with the application guaranteed 99% VOC destruction efficiency and the manufacturer clarified that VOC and CH4 destruction efficiency should be equivalent. Thus, the Division will require the RTO to achieve a minimum CH4 destruction efficiency of 99% to be consistent with other GHG BACT limits. As part of the BACT determination for the amine unit, the RTO will be maintained according to manufacturer's recommendations and periodic monitoring will be conducted to assure the combustion chamber temperature exceeds the minimum level identified in the application. The exhaust oxygen concentration in the RTO will be monitored to ensure adequate combustion is occurring. The Division is also including annual CO2e emission limits on a 12 -month rolling basis as per EPA's guidance for GHG BACT. The BACT emission limit included in the permit is 154,351 tons CO2e per year. An initial stack test demonstration will also be required to ensure compliance with the CO2 emissions and to ensure 99% reduction of CH4 is achieved. The Division will require on -going performance testing to demonstrate that the RTO achieves a minimum CH4 emissions reduction of 99%. Glycol Dehydration Unit The proposed expansion will include one triethylene glycol dehydration unit (D-1) design rated to process 230 MMscf per day of natural gas. The primary purpose of the dehydration unit is to remove water from the natural gas. The glycol dehydrator regenerator (still) vent and flash tank are both potential sources of methane emissions. 14 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 DCP identified six potential control technologies for the BACT analysis. each of the options will be discussed in detail. 1. Carbon capture and sequestration 2. Tank off -gas recovery systems 3. Regenerative thermal oxidizer 4. Flare 5. Condenser 6. Proper design and operation 1. The highest ranked control technology for the dehydrator was Carbon Capture and Storage (CCS). In their analysis, DCP claimed CCS is the most effective control option for the CO2 stream from the TEG unit. However, according to the material provided with the permit application, the still vent stream from the dehydrator contains no CO2. Therefore, employing CCS in the context of the glycol dehydration unit would have little to no benefit. 2. DCP estimated 99% control of flash tank off -gas by installing a vapor recovery system where the flash tank off -gas is recycled back to the plant inlet, assuming 1% downtime for the vapor recovery unit. The proposed project includes electric -powered vapor recovery unit and no additional combustion is required on -site to power the unit, resulting in a 99% reduction of CH4 emissions from the flash tank off -gas. Additionally, DCP will route the flash tank off -gas to the emergency flare during periods of VRU downtime. The Division's review of 3. The next highest ranked control technology in the BACT analysis for the glycol dehydration unit was routing the vent stream to a regenerative thermal oxidizer. The still vent stream includes a significant CH4 content, which will be destructed in the regenerative thermal oxidizer and converted to CO2. Since the global warming potential for CH4 used for GHG calculations is 21, this operation will result in overall reductions in CO2e emissions despite an increase in CO2 emissions. In this regard, combustion of the dehydration unit still vent stream is considered BACT. Since this BACT is for the destruction of hydrocarbon emissions only, for this instance, it would be appropriate to apply the same BACT as if the unit was being reviewed for VOC emissions as a precursor to ozone. There are very few entries in the RBLC3° for glycol dehydrators and in many cases no control technology is identified. Typically condensers, flares and thermal oxidizers (enclosed flares) are used to control emissions from dehydrators. The source stated in the application that the RTO could achieve 96% destruction efficiency. However, as discussed above for the amine unit, the RTO is manufacturer guaranteed to achieve 99% reduction for VOC and assumed to also achieve 99% reduction of CH4. 4. The flare has the same benefits of waste gas combustion in the RTO, however a flare is less efficient than the RTO. Therefore, an RTO would be considered BACT rather than the flare. However, in this scenario, DCP has identified that routing a dehydrator vent stream to an RTO has safety implications due to uncontrolled detonation concerns. DCP identified this as a reason for the infeasibility of the RTO as a control technology for the dehydration unit. DCP has encountered problems with uncontrolled detonation for the destruction of streams with a high heating value while operating other facilities which employ an RTO to control the still vent emission from a dehydration unit. The addition of the dehydrator still vapors increases the otherwise low heating value from the amine unit to an extent which would require additional safeguards to prevent uncontrolled detonation. Due to ongoing concerns, DCP has implemented a policy of avoiding this configuration. Therefore, for the glycol dehydrator, 3o U.S. Environmental Protection Agency. "RACT/BACT/LAER Clearinghouse". <http://cfpub.epa.gov/rblc/index.cfm?action=Search.BasicSearch&land=eq> (April 2, 2013) 15 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 DCP selected an enclosed combustor as BACT for the still vent stream since the use of an RTO is infeasible due to safety concerns. 5. A condenser serves to reduce the temperature of the still column vent vapors to form condensate, water, and VOCs, including methane. The condensed liquids are then collected for further treatment or disposal. DCP estimates the reduction efficiency from the use of a condenser to be between 50-98% removal of VOCs. By reducing the amount of VOCs to be routed to the enclosed flare, DCP is reducing the potential to generate additional CO2 as combustion by-product. Thus, DCP is proposing to utilize an air-cooled condenser on the dehydrator still vent prior to routing to the flare as part of BACT control. 6. DCP indentified proper design and operation as a feasible control technology. The BACT analysis indicated the unit will be fired using pipeline quality natural gas. As the Division understands, combustion is not part of the equipment comprising this permitted emission unit and the use of natural gas is more appropriately associated with the flare. This control technology, as described in DCP's analysis, is simply a reassertion that the other control options, including condensers, combustion devices, flash tanks, and vapor recovery units will be properly designed. As part of the implementation of the other BACT options, the Division expects the equipment to be properly designed and therefore does not consider this specifically identified option as a unique control strategy. BACT outcome While CCS and the RTO are not technically feasible, DCP proposed to implement all of the remaining control options as BACT for the dehydrator. The dehydration unit flash tank off -gases will be recycled via an electric powered VRU resulting in a minimum of 99% reduction. During VRU downtime, the flash tank off -gases will be routed to the emergency flare achieving 95% control of CH4. The Division considers this design as BACT. DCP proposed to route the dehydrator still vent emissions to an air-cooled condenser, achieving between 50-98% control of VOC, and then the non -condensible vapors from the still vent will be routed to an enclosed flare achieving 95% reduction of CH4. By first routing to a condenser, DCP is minimizing GHG emissions that would then be emitted as combustion by-product in the flare. The Division is not aware of GHG BACT limits for glycol dehydrators at other facilities (most facilities at this time proposed molecular sieve dehydrators). However, the Division is aware through minor source construction permitting (e.g., non-BACT permits) that thermal oxidizers have been utilized to control dehydrator streams at oil and gas facilities. While other sites may have utilized a thermal oxidizer to control a glycol dehydrator, the Division is approving DCP's proposed configuration based on site -specific concerns. The Division considers the condenser and enclosed flare to satisfy BACT. Since the dehydrator still vent will be equipped with an air-cooled condenser and relied upon for air pollution control, the condenser will be operated below the maximum condenser temperature of 145°F consistent with the Division's standard for monitoring proper operation of condensers. As part of BACT for the dehydrator, the efficacy of the enclosed combustor will be monitored by continuously monitoring the presence of a pilot light and conducting Method 22 visible observations daily. The Division is also including annual CO2e emission limits on a 12 -month rolling basis as per EPA's guidance for GHG BACT. The BACT emission limit included in the permit is 5,230 tons CO2e per year. The control device will combust pipeline quality natural gas for the pilot light which has a firing rate of 0.5 MMBtu/hr, generating a small amount of combustion -related GHGs. In the Division's review of recent EPA Region 6 PSD permits' requirements for BACT control devices, periodic 16 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 maintenance and operating the equipment in accordance with manufacturer's recommendations was standard practice. The enclosed combustor is considered a flare for reporting purposed in 40 CFR Part 98 and combustion emissions from the device must be monitored in accordance with §98.233(n). Regenerative Thermal Oxidizer DCP included an analysis of BACT for the regenerative thermal oxidizer. The thermal oxidizer is a BACT requirement for the operation of the amine unit. The regenerative thermal oxidizer generates NOX, CO, and SO2; however the project emissions increase is not significant for these pollutants. Therefore, BACT review is not required for the thermal oxidizer for these criteria pollutants. The RTO will generate GHG in the form of CO2 and has been included in the BACT analysis for this pollutant. Proper operation and maintenance are an essential component of the BACT determination for the amine unit. As part of the BACT determination for the amine unit, the thermal oxidizer is required to conduct periodic monitoring and operate the equipment according to manufacturer's recommendations to ensure efficient operation. Combustion Turbines As part of this project, DCP is proposing to install two 9,055 HP natural gas -fired residue gas compressors (TURB-1 and TURB-2). The combustion of natural gas results in emissions of CO2, CH4, and N2O. DCP identified four potential control technologies for the BACT analysis. The Division's review of each of the options will be discussed in detail. 1. Carbon capture and sequestration (CCS) 2. Efficient turbine design 3. Fuel selection 4. Good combustion, operating and maintenance practices 1. Since CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons, the analysis, as discussed in more detail under the amine unit discussion, focused primarily on the amine unit that would have the most pure and concentrated CO2 streams. Routing other GHG sources such as the turbines to a CCS system would require even more processing to separate and purify the CO2 since the streams would contain lower concentrations of CO2 than the amine stream. The turbine emission stream would also be at essentially atmospheric pressure and higher temperature which would require more steps to cool and then compress. The technology available for post -exhaust treatment, which would involve low pressure scrubbing, has not yet been implemented at an operating facility. The gas stream contains a low concentration of CO2e and the costs and energy required to install a post -combustion carbon capture and treatment technologies is significant relative to the emission reductions available. Since the Division considered CCS infeasible for the amine unit, it would also be infeasible for the turbines. This conclusion is supported by EPA's PSD guidance document31, which states CCS technology is most practical for pure CO2 streams. 2. The combustion turbines proposed by DCP are the most efficient model currently available from the manufacturer and employs waste heat recovery to increase efficiency. By utilizing the heat recovered from waste gas to heat hot oil, the source effectively reduces the need for increased fuel consumption from the hot oil heater (HT -02). 3. The proposed units will use only natural gas as a fuel source, thus creating emissions less than those from alternative fuel sources. DCP identified fuel selection as BACT for the 31 U.S. Environmental Protection Agency. (2011). "PSD and Title V Permitting Guidance for Greenhouse Gases" EPA -457/8-11-001, <http://www.eoa.eov/nsr/ohgdocs/ghgpermittinqquidance.pdf> (April 2, 2013). 17 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 turbines which represents a 28% reduction in GHG emissions when using natural gas in lieu of No. 2 fuel oil. This control percentage is derived from GHG emissions estimates based on the emission factors in 40 CFR Part 98 Subpart C, Table C-1 for various fuel types. 4. The proposed combustion turbines will operate in lean pre -mix mode to ensure an effective staging of air/fuel ratios in the turbines to maximize fuel efficiency and minimize incomplete combustion: BACT outcome Each of the BACT options listed above, with the exception of CCS, will be utilized for these units. Additionally, DCP proposed as BACT an input -based CO2e emission limitation for the combustion turbines. While no white paper exists specifically for oil and gas production operations, a white paper does exist for refineries 2, which discusses combustion turbines, and the Division reviewed this white paper to inform the BACT review. The technology discussed is aimed at combined heat and power units since refining operations create a large demand for process steam. The white paper implies that the best approach for CO2 reductions from combustion would be the use of natural gas as a fuel source and installing newer, more energy efficient units. In EPA's PSD GHG guidance document33, EPA emphasizes that source -wide energy efficiency strategies (over an entire production process) should be considered in the application of BACT for GHGs. EPA's guidance document also discusses that BACT limits should be output -based limits and that BACT emission limits should be converted to a net output basis for the permitted emission limit. Additionally, the Division reviewed GHG BACT limits and controls for similar combustion turbines at other similar oil and gas facilities. A review of the RBLC resulted in two facilities (Exxon Mobil Corporation, Point Thomson Production Facility and Municipality of Anchorage, Anchorage Municipal Light & Power) that established GHG BACT for combustion turbines utilized for energy generation. EPA Region 6 has issued several permits for combustion turbines, but most of the permitted combustion turbines are used for energy generation. These permits are helpful in understanding control options for combustion turbines but are not directly relevant for comparing output based limits for combustion turbines used for compression. At this time, only one EPA Region 6 permit establishes BACT limits for combustion turbines that are used for gas compression. The Division considers this permit to be most relevant when comparing BACT limits. EPA Region 6 permit34 PSD-TX-104949-GHG includes two natural gas combustion turbines used for residue gas compression at the Copano Processing, L.P (Copano) Houston Central Gas Plant. The permit requires the combustion turbines to burn pipeline quality natural gas, operate waste heat recovery unit, and comply with a minimum thermal efficiency limitation of 40%, as well as periodic maintenance and tune-ups. To be more consistent with EPA Guidance and Permit PSD-TX-104949-GHG, the Division requested that DCP provide a minimum thermal efficiency for the combustion turbine and WHRU system to ensure efficient turbine design. The thermal efficiency limit will be prescribed as the BACT limit in lieu of DCP's proposed input -based BACT limit. DCP estimated that the system will achieve a minimum thermal efficiency of 40% which is equivalent to the thermal efficiency limit in Permit PSD-TX-104949-GHG. Thus, a minimum thermal efficiency of 40% for the turbine and WHRU system will be required in the permit. 32 U.S. Environmental Protection Agency. (2010). "Available and Emerging Technologies for Reducing Greenhouse Gas Emissions From The Petroleum Refining Industry." 33 Id. 34 Region VI of the Environmental Protection Agency (2013). "PSD Permit for GHG emissions for Copano Processing L.P. Houston Central Gas Plant, Colorado County, Sheridan, TX." <http://vosemite.epa.qov/r6/Apermit.nsf/AirP> (March 18, 2013) 18 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 It is worth noting that the size of the turbines at the DCP facility are smaller (9,055 hp each) than the turbines in Permit PSD-TX-104949-GHG (15,000 hp each) and DCP has explained that the smaller turbines will not generate enough waste heat to support the heat demand for the entire plant. Thus, unlike the Copano facility which will operate supplemental heaters during events such as startups and shutdowns of the turbines, DCP will utilize the hot oil heater (HT02) on a routine basis. However, by utilizing the WHRU, DCP will only need to install one heater to meet the facility's heat demand and thus minimize GHG emissions from the process. DCP will also be able to minimize fuel throughput to the hot oil heater while utilizing the WHRU. Additionally, since the turbines are used for residue compression, the entire plant must be fully operational before the WHRUs can be utilized. To allow for the system to become fully operational, the thermal efficiency limit will be based on a 12 -month rolling average basis. To demonstrate compliance with the thermal 'efficiency limit, DCP will measure oil flow and inlet and outlet temperature of the hot oil system that uses the recovered heat from the combustion turbines. The amount of heat (MMbtu/hr) recovered by the WHRU can be calculated from these values and then added to the output of the turbines, converted to MMbtu/hr, to obtain total output of the overall system to then use in calculating the efficiency of the system. These equations for calculating thermal efficiency will be specified in the permit. The Division is including annual CO2e emission limits on a 12 -month rolling basis as per EPA's guidance and to maintain consistency in GHG permitting efforts. The BACT emission limit included in the permit is 42,268 tons CO2e per year for each turbine. DCP will demonstrate compliance with the CO2e limits for the turbines based on inlet metered fuel consumption and using the measured actual high heat value (HHV) determined according to the requirements at 40 CFR §98.34(a)(6), and the default emission factors for natural gas from 40 CFR Part 98 Subpart C, Table C-1. The gross calorific value (GCV, or higher heating value, HHV) of the natural gas will be determined semiannually in compliance with 40 CFR Part 98.34(a)(6). According to EPA's GHG Mandatory Reporting Rule, natural gas generally has a homogeneous nature and a low variability in the characteristics of the fuel. The HHV analysis will be used to determine compliance with the BACT limit on a 12 -month rolling basis. Records of the calculations are required to be kept to demonstrate compliance with the emission limits on a 12 - month rolling basis. DCP will be required to implement manufacturer's recommended comprehensive inspection and maintenance program for the turbines and perform tune-ups at least annually. DCP will maintain records of turbine tune-ups and maintenance. An initial stack test demonstration will be required for CO2 emissions from each emission unit. An initial stack test demonstration for CH4 and N2O emissions is not required because the CH4 and N2O emission are less than 0.01% of the total CO2e emissions from the turbines and are considered insignificant in comparison to the CO2 emissions, making initial stack testing impractical and unnecessary. CO2 is required to be measured quarterly by portable analyzer testing to monitor compliance with the emission limitations. Heater The proposed expansion will include one natural gas -fired hot oil heater (HT -02), design rated at an input of 50 million British thermal units per hour (MMBtu/hr). The combustion of natural gas results in emissions of CO2, CH4, and N2O. DCP identified five potential control technologies for the BACT analysis. The Division's review of each of the options will be discussed in detail. 1. Carbon capture and sequestration 19 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 2. Fuel selection 3. Good combustion, operating and maintenance practices 4. Heat recovery 5. Efficient heater design 1. Since CCS requires a highly concentrated, pure CO2 stream for practical and economic reasons, the analysis, as discussed in more detail under the amine unit discussion, focused primarily on the amine unit which would have the most pure and concentrated CO2 streams. Routing other GHG sources to a COS system, such as the heater, would require even more processing to separate and purify the CO2 since the stream would contain lower concentrations of CO2 than the amine stream. The heater emission stream would also be at essentially atmospheric pressure and higher temperature which would require more steps to cool and then compress. Thus, utilizing CCS for the heater would further increase the costs of CCS implementation, as discussed for the amine unit, as well as increase criteria pollutant and GHG emissions. Since the Division considered CCS infeasible for the amine unit, it would also be infeasible for the heater. 2. DCP identified fuel selection as BACT for the heater which represents a 28% reduction in GHG emissions when using natural gas in lieu of No. 2 fuel oil. This control percentage is derived from GHG emissions estimates based on the emission factors in 40 CFR Part 98 Subpart C, Table C-1 for various fuel types. 3. Good combustion and operating practices can increase fuel efficiency and in turn limit CO2 emissions, as identified in DCP's BACT analysis. Properly controlling the air/fuel ratio increases heat transfer efficiency, reducing CO2 emissions, and is considered a component of good combustion and operating practices for this unit. The heaters will be equipped with a burner management system with intelligent flame ignition, flame intensity controls, and flue gas recirculation as components of good combustion practices. 4. An additional component identified as BACT is heat integration through the use of process -to - process heat exchangers. The utilization of waste gas heat exchangers from the turbines will limit the demand from this heater. The Division considers this practice as part of the BACT determination for the turbines and not specific to the heaters. 5. The new heater will be equipped with next generation ultra-low-NOX burners (NGULNB) capable of meeting 0.037 lb-NOx/MMBtu, which is indicative of efficient operation. BACT outcome Each of the BACT options listed above, with the exception of CCS and heat recovery, will be utilized for this heater. Additionally, the applicant proposed an input -based CO2e limit as well as limitations on natural gas consumption, effectively limiting the unit to a 67% annual capacity factor. The Division reviewed GHG BACT limits and controls for similar heaters at other similar oil and gas facilities. EPA Region 6 has issued several GHG permits that include heaters utilized within oil and gas operations. The Division's review was focused on hot oil heaters since the similarity in heater purpose is important when comparing BACT outcomes. The following table summarizes GHG BACT requirements for hot oil heaters. Company/ Location Heater Description BACT Control BACT Emission Limit/ Requirement Year Issued Reference DCP Midstream, LP, Jefferson County NGL 2 Hot Oil Heaters (179 MMBtu/hr each) Energy efficiency and good design and combustion practices Minimum thermal efficiency of 85% on a 12 -month rolling basis 2013* PSD-TX- 110557 - GHG 20 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance I Company/ Location Heater Description BACT Control BACT Emission Limit/ Requirement Year Issued Reference Fractionation Plant Beaumont, TX Energy Transfer Company (ETC), Jackson County Gas Plant Ganado, TX 4 natural gas processing trains 4 Hot Oil Heaters (48.5 MMBtu/hr each) Energy efficiency and good design and combustion practices GHG BACT limit for all process heaters per train (each train includes a hot oil heater, trim heater, molecular sieve heater and regenerator heater) of 1,102.5 lbs CO2/MMSCF natural gas output from plant 2012 PSD-TX- 1264-GHG Energy Transfer Partners, LP, Lone Star NGL Mont Belvieu, TX 2 Hot Oil Heaters (270 MMBtu/hr each) Energy efficiency and good design and combustion practices 2,759 lb CO2/bbl of NGL processed per heater, 365 -day average, rolling daily 2012 PSD-TX- 93813-GHG Enterprise Products Operating LLC, Eagleford Fractionation Mont Belvieu, TX NGL Fractionation 2 Hot Oil Heaters (140 MMBtu/hr each) Energy efficiency and good design and combustion practices Minimum thermal efficiency of 85% on a 12 -month rolling basis 2012 PSD-TX- 1286-GHG Kerr-McGee Gathering LLC Lancaster Plant Ft. Lupton, CO Natural gas processing plant 4 heat medium heaters for amine units (76.9 MMbtu/hr each) Energy efficiency and good design and combustion practices GHG BACT limit for all heaters associated with the plant (the plant includes 4 hot oil heaters and 2 regenerator heaters) 1,716.9 lbs CO2/MMSCF natural gas output from plant 2013 Colorado Construction Permit 12WE1492 Issuance 1 KM Liquids Terminals LLC, Galena Park Terminal Galena Park, TX 2 Hot Oil Heaters (247 MMBtu/hr each) Energy efficiency and good design and combustion practices Minimum thermal efficiency of 85% on a 12 -month rolling basis 2013 PSD-TX- 101199- GHG ONEOK Hydrocarbon, LP, Mont Belvieu NGL Fractionation 3 Hot Oil Heaters (154 MMBtu/hr each) Energy efficiency and good design and combustion practices 14.25 lbs CO2/bbl y- grade feed for all heaters combined, 365 -day rolling average, equipped 2013 PSD-TX- 106921 - GHG 21 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 Company/ Location Heater Description BACT Control BACT Emission Limit/ Requirement Year Issued Reference Plant Baytown, TX Heaters will combust waste gas from amine units and flue gas from heaters will be treated with SCR. with SCR Targa Gas Processing LLC, Longhorn Gas Plant Decatur, TX 1 Hot Oil Heater (98 MMBtu/hr) Energy efficiency and good design and combustion practices 1,783.23 lb CO2/MMSCF for all heaters combined (plant includes one glycol reboiler, one mol sieve heater and one hot oil heater), 365 -day rolling average 2013 PSD-TX- 106793- GHG This permit is not issued as a final permit as of 10/2/2013 To date, BACT determinations for hot oil heaters at similar facilities are consistent with the energy efficiency, good design and combustion practices, and proper maintenance as proposed by DCP. Thus, the Division has determined that for this source, the use of natural gas, next generation ultra low-NOx burners (NGULB), and good combustion and operating practices (work practices to ensure good combustion and operating practices include annual tune-ups, routine maintenance, and controlling the air to fuel ratio) are BACT for the heater. While not discussed explicitly in DCP's application, the Division will also require utilization of insulation materials as part of good operating practices. As seen in the table above, the BACT limit has varied among hot oil heaters. While EPA's guidance suggests that BACT limits should be output -based, an output -based limit for the hot oil heater does not necessarily ensure energy efficiency or good design and combustion practices. The operation of the hot oil heater does not directly relate to the gas produced at the plant, so a BACT limit established in terms of gas produced does not ensure good combustion practices or correlate well to energy efficiency. In fact, this output -based limit could create unintended compliance issues if the plant does not operate at full capacity for a majority of the time. Since the output -based limit could create compliance issues that are not actual GHG compliance issues and does not correlate to ensuring energy efficiency, the limit does not seem appropriate. DCP will be required to achieve a minimum thermal efficiency for the turbines and WHRU system as discussed in the turbine section. This thermal efficiency requirement ensures DCP will limit the use of the hot oil heater while maximizing utilization of the WHRU. Therefore, a more appropriate BACT limit for the heater in conjunction with the overall process would be to limit heater use. Limiting the fuel throughput ensures energy efficiency across the process and minimization of GHG emissions. In lieu of an output -based limit, the use of the heater will be limited to 315 MMSCF per year of fuel throughput, which is 67% of design throughput, to ensure DCP maximizes utilization of the WHRU associated with the turbines. Additionally, EPA Region 6 established GHG limits for two combustion turbines and two supplemental heaters at the Copano Processing Houston Central Gas Plant (PSD-TX-104949- GHG). While the Copano Houston Central Gas Plant and DCP Lucerne facilities are not identical, the Copano facility is an appropriate comparison since both facilities are utilizing combustion turbines and WHRUs along with heaters to fulfill the heat demand for natural gas processing. EPA Region 6 established a thermal efficiency limit as GHG BACT for the turbine 22 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 and a process limit and use of good combustion practices for the two supplemental heaters at the Copano facility. Thus, the Division considers the proposed process limit and use of good combustion practices to be consistent with other GHG BACT determinations. The process limit will suffice as the BACT limit for this heater in conjunction with the thermal efficiency requirements for the turbine and WHRU. While some GHG permits include a thermal efficiency requirement as a BACT limit for a hot oil heater (e.g., DCP Jefferson County NGL Fractionation Plant, Enterprise Products Eagleford Fractionation Plant, and KM Liquids Galena Park Terminal), this process is designed differently such that it is not feasible to readily calculate thermal efficiency for the heater. This heater is supplying heat demand for multiple processes and there is not a direct correlation to calculate efficiency. In the other facilities, the heater is limited to supporting one process such as supplying hot oil to amine reboilers and separate regeneration heaters are used to provide heat for regeneration of the molecular sieves. When the heater is isolated to supporting one or two processes, thermal efficiency can be more readily assessed. Since this heater is utilized to supply heat throughout the plant including the amine unit, glycol reboiler, and regeneration of molecular sieve beds, heat demand and thermal efficiency significantly varies and is not readily tracked for compliance. As with the other units, the Division is including annual mass emission rates for CO2e on a 12 - month rolling basis. The BACT limit for the heaters is 20,250 tons CO2e per year. Typically, the Division also includes monthly limits for the first year of operation. However, the Division will establish process and emission limits for the first year on a quarterly basis for the heater. The quarterly basis is consistent with the Division's permitting policy (PS Memo 97-03) to allow flexibility for operations that fluctuate. As explained in the turbine section, the heater will be used on an on -going basis to fulfill the heat demand of the plant. However, utilization of the heater will be higher in certain scenarios such as periods prior to the plant being fully operational. Since the turbines are associated with residue compression, the turbines and WHRU will not operate until the plant is fully operational and generating residue gas. The immediate heat demand must then be provided by the hot oil heater until the WHRU is operating. Quarterly limits provide operational flexibility but ensure compliance with the limited use of the heater during the first twelve months of operation. DCP will demonstrate compliance with the CO2e limits for the heater based on metered fuel consumption and using the measured actual high heat value (HHV) determined according to the requirements at 40 CFR §98.34(a)(6), and the default emission factors for natural gas from 40 CFR Part 98 Subpart C, Table C-1. The GCV (or HHV) of the natural gas will be determined semiannually in compliance with 40 CFR Part 98.34(a)(6). According to EPA's GHG Mandatory Reporting Rule, natural gas generally has a homogeneous nature and a low variability in the characteristics of the fuel. The HHV analysis will be used to determine compliance with the BACT limit on a 12 -month rolling basis. DCP will be required to perform annual tune-ups and cleaning of the burner tips as monitoring for good combustion practices. While the heaters' air and fuel valves will be mechanically linked to maintain the proper air to fuel ratio, DCP will be required to monitor the air/fuel ratio to ensure good combustion. DCP will be required to maintain records of heater tune-ups, calibrations of the air/fuel control analyzer, and maintenance on the system. An initial stack test demonstration will be required for CO2 emissions from the emission unit. An initial stack fest demonstration for CH4 and N2O emissions is not required because the CH4 and N2O emission are less than 0.01% of the total CO2e emissions from the unit and are considered insignificant in comparison to the CO2 emissions, making initial stack testing unnecessary. 23 DCP, Midstream LP — Lucerne Gas Processing Plant 12WE2024 Issuance 1 Condensate Tank and Condensate Loadout The condensate storage and loadout operations at this facility are similar in nature and will be addressed concurrently. The condensate storage tanks at the facility house stabilized condensate. The stabilization process volatilize and remove a significant portion of lighter hydrocarbons, mainly methane. DCP reported that no methane is present in the condensate, citing a liquids analysis from a similar nearby DCP facility. A liquids analysis will be required by the permit to confirm the composition of the condensate at the Lucerne plant. There are no flash losses from the tank but working and breathing losses occur and present a source of VOC emissions. The unloading of condensate from the tanks into trucks for transportation will also result in VOC emissions. DCP asserted GHG emissions from these two units were negligible and conducting a BACT analysis was technically and economically infeasible. The Division agrees with this determination and determined BACT is not required on these emission sources since CO2e is not emitted. DCP has proposed, as a part of the designed expansion project, routing the emissions from the tanks and loadout to an enclosed combustor with 95% destruction and removal efficiency. The enclosed combustor proposed as control for the tanks and loadout is the same device which will control emissions from the glycol dehydrator. The emissions from the operation of the enclosed combustor were considered in the BACT review for the dehydrator. The mandatory greenhouse gas reporting rule for onshore natural gas processing facilities in 40 CFR Part 98 §98.232(d) does not require emissions from storage tanks and condensate loadout operations to be monitored and reported. Fugitives Emissions from leaking components associated with the proposed project include methane, a GHG. The additional methane emissions from process fugitives have been conservatively estimated to be 200 tpy as CO2e. Fugitive emissions of methane are negligible, and account for less than 0.1% of the project's total CO2e emissions. The only identified control technology for process fugitive emissions of CO2e is use of a leak detection and repair (LDAR) program. LDAR programs vary in stringency as needed for control of VOC emissions; however, due to the negligible amount of GHG emissions from fugitives, LDAR programs would not be considered for control of GHG emissions alone. As such, evaluating the relative effectiveness of different LDAR programs is not warranted. Although technically feasible, use of an LDAR program to control the negligible amount of GHG emissions that occur as process fugitives would most likely be cost prohibitive. However, if an LDAR program is being implemented for VOC control purposes, it will also result in effective control of the small amount of GHG emissions from the same equipment components. DCP stated in the BACT analysis that the plant would follow NSPS KKK. With the final issuance of NSPS OOOO, the plant will in fact be subject to NSPS OOOO instead of NSPS KKK. The LDAR requirements under NSPS OOOO are more stringent than NSPS KKK. Due to the negligible amount of GHG emissions from process fugitives, implementation of an LDAR program could potentially be economically infeasible. In this case, BACT would be determined to be no control. However, since the facility will be subject to the LDAR program as required under NSPS OOOO to control VOC emissions, the Division concurs with DCP's assessment that following NSPS OOOO requirements is an appropriate control of GHG emissions for fugitives. As noted above, LDAR programs would not normally be considered for control of GHG emissions alone due to the negligible amount of GHG emissions from fugitives, and while the existing LDAR program is being imposed in this instance, the imposition of a numerical limit for control of those negligible emissions is not feasible. 24 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance 1 Insignificant Activity The Division considers uncontrolled compressor blowdown activities a unique emission point, distinct from compressor components as regulated under NSPS Subpart OOOO. Compressor blowdowns are planned maintenance activities and uncontrolled emissions are released through a dedicated blowdown valve. The Division considers these point source emissions rather than fugitive, as with leaking compressor components. Additionally, in DCP's analysis, an emergency flare was considered. The emergency flare at the Lucerne plant will te used to destroy off -gas produced during emergency situations and during planned maintenance emissions from compressor blowdowns. Blowdown activities, emergency venting, and the emergency flare used to control the emissions from those activities are otherwise exempt from the construction permit requirements in Colorado Regulation No. 3, Part B and the APEN reporting requirements in Colorado Regulation No. 3, Part A. Historically, it has been the Division's practice to require BACT analyses for any uncontrolled emission unit with a net emission increase in the PSD subject pollutant that is otherwise subject to APEN reporting requirements. The mandatory reporting rules in 40 CFR Part 98 Subpart W requires monitoring and calculating emissions from the blowdown vent stacks in accordance with §98.2330). The combustion -related emissions from the control device are required to report in 40 CFR Part §98.233(n). RACT (Regulation No. 3, Part B, III.D.2.a) The proposed expansion at the Lucerne plant will be located in an area designated by the EPA as a non- attainment area for ozone and the proposed equipment will emit ozone pre -cursors, including NOx and VOC. Since the proposed equipment does not qualify as a major modification for NANSR, the proposed equipment is subject to minor source RACT requirements per Regulation 3, Part B, Section III.D.2.a. The proposed equipment that would emit NOx and VOC include: • One (1) Amine Unit • One (1) Glycol Dehydrator • Two (2) Combustion Turbines • One (1) Hot Oil Heater • Condensate Storage Tanks • Condensate Loadout • Fugitives The combustion turbines and heaters will utilize natural gas as fuel and implement low NOx burners along with good combustion practices. The selected control options will minimize NOx emissions and thus satisfy minor source RACT. The selected BACT option for the amine unit is to route still vent emissions to a thermal oxidizer achieving 99% reduction of methane. This control will also result in 96% reduction of VOC and thus satisfies minor source RACT. Flash emissions will be routed to a vapor recovery unit employing 99% control of the flash gas stream. Additionally, the source will implement good combustion practices for the thermal oxidizer to satisfy BACT; these requirements will also reduce NOx generated due to optimal combustion. As part of the BACT determination fix the glycol dehydration unit, still vent emissions from the unit will be routed to a condenser then to an enclosed combustor achieving 95% reduction in methane emissions. This control will also result in reduction of VOC through the condenser plus 95% reduction of VOC through combustion and thus satisfies minor source RACT. Flash emissions will be routed to a vapor recovery unit employing 99% control of the flash gas stream. Additionally, the source will implement good combustion practices for the enclosed combustor to satisfy BACT; these requirements will also reduce NOx generated due to optimal combustion. 25 DCP, Midstream LP — Lucerne Gas Processing Plant 12W E2024 Issuance I The VOC emissions from the condensate storage tanks and condensate loadout will be routed to an enclosed combustor with 95% destruction efficiency. The condensate loadout will also employ submerged fill. This configuration is considered RACT for these units. The proposed plant will be subject to leak detection and repair requirements specified in Regulation 7, Section XII.G, which specifies RACT. The facility will follow 40 CFR 60 Subpart OOOO in lieu of following 40 CFR 60 Subpart KKK. The permit will specify the requirements that the source must follow to comply with minor source RACT. V. CONCLUSION AND PROPOSED ACTION Based on the information supplied by DCP, our review of the analyses contained in the Permit Application, and our independent evaluation of information, it is our determination that the proposed facility will employ BACT for GHGs under the terms contained in the draft permit. Therefore, the Division is proposing to issue DCP Midstream, LP a PSD permit for GHGs for the facility, subject to the PSD permit conditions specified therein. This permit is subject to review and comments. A final decision on issuance of the permit will be made after considering comments received during the public comment period. 26 tea. C O 4▪ 7▪ . 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'0055, 066W 0055, 066W 0050, 084W0055, 063W 0055, 081W0055, 060W T 0050, mtw 0050, 067O/, 0056, 062W EFFERSON 0005 066W 0065, 075W0080, 074W0085, 073W 0065, 071W 0060 06 W006S 088W0085 087W 0065, 0650/0063, 064W 0065 062W006S, 061 W006s, 060W 0065, 072 0065,0700/ - 0085, 0630/ 00] , 069W7. 0070, 066W 0075, 075W007S, 074W007$ 073W - 0075, 071W0070, 070W 0075 060W000, 967W 0070, ' 065W 0075, 003W0070, 002W0075, 061W0075, 060W 0075, 072 Castle Rock, CO 0075, 0640/ - 0085, 075W0085, 074W0085, 073W 0005,072 0060, 075W0085, 074W0095, 073W PARK ! 0095,072 0105, 075W0105, 074W0105, 073W0105, 07 '0 0085, 068W 0063, O66W ELBERT 0080, 0710/096$ O70yr0065, 0690/ GOBS, O6IW • 006$ 0650/ 0080, 0630/0065, 062WOO6S, 081W0050, 060W DOUGLAS 0085, 064W 009$ 071W 0 0090, 006W 0095, 069W 0090, 087W0055, 065W0050, 065W 0095, 063W0085, 062W0096, 061W0095, 000W 070W - 0095, 064W ' 0]00, 068W 0105,06107 0100, 070W0105, 069W 0100, 007W0105, 066W0100, 065W 0105, 083W0100, 062W 010$ 060W 0100, 071W 0105, 064W 0115, 073W 0115, 069W - 0115, 075W• 0115, Wzw 0110,0610/ 060 0115, 074W 0115, 070W 015088W011506]W011s,06610115, 0652/0115, 064O/0115, 0630/0115, 0620/ 0115, 0115, D]1W• EL PASO TELLER Colorado-Sphngs, CO 0125,0 0120, 0752/0125, 0740/ 0120. 072W0125. 071W0125, 070W0125, 060wo, 2s 068W -. 0126 066W0120, 065W 0125, 073W WoodlandPark Co912s 0870/, 0135 072WKr PLSS Township; Boundaries Urban Area Buffer Urban Clusters> 10,000 -. r Urban Area for DCP Lucerne .__ Major Road ble at this zoom I Items in grey text are not O Queried Stationary Sources of Air Pollution December 14, 2012 cz z m 0. 55 / 2008 So you finally bought a Combustion Analyser! Crispin Pemberton -Pigott New Dawn Engineering, P.O. Box 3223 Manzini, M1200, Swaziland, Southern Africa Email: crispinpigott@gmail.com Developing an improved stove is the primary goal of many domestic energy projects. Most developers know it is not easy to produce a clean burning stove without using emissions measuring equipment like a combustion analyser. But along with having the -correct equipment you also need to know how to extract useful information from the raw numbers. A stove developer is looking for better combustion and better heat transfer. -A basic combustion analyser along with a few mathematical tools will produce useful information from a surprisingly small number of measurements. Analysing combustion Improving combustion has two aspects: burning the fuel completely and minimizing harmful emissions. Similarly, a better heat transfer also has two main factors: getting the heat into the pot or the room, and limiting the amount that is wasted either up the chimney or into the air. The combustion analyser will help with all of these. First you need to find the level of carbon monoxide (CO) in the emissions, the oxygen (Ot) level and the temperature. These three measurements are key. If you have a scale you can also determine the mass of fuel being burned at the time the measurements were taken and from this calculate the quantity of. CO produced when burning a kilogram of fuel. Carbon monoxide (CO) If CO or CO2 is -found in the gas flowing from a stove, there is combustion taking place. Detecting CO2 is more difficult than CO, so simple gas analysers will only measure the latter. It is normally reported in parts per million (ppm) or milligrams per cubic metre of gases (mg/ m3). To convert mg/m' to ppm, multiply mg/m' by 0.81075. To convert CO ppm to CO%, divide by 10,000. Exam 500 ppm CO - 0.05% CO 10,000 Oxygen (07) Oxygen is also easy to detect and is usually reported in percent (%). The air entering a stove can be thought of in two components, the amount required for combustion (the air demand) and the air not theoretically needed to burn the fuel (excess air) Excess air (EA) is calculated as follows: EA (%) _ [1:211/a — ICO%/211 x 100 20.95 - [O,% - (CO%/2(] Summing the combustion and excess air gives the total air supplied, also called the Air Factor, represented by the symbol lambda, X. Lambda is excess air plus one. EA% _ +1 100 If EA=160%,k = 160/100+.1.00=2.60 i.e. the total air entering the stove is 2.6 times greater than that required for combustion. Calculating CO, Because the composition of fuels like coal or wood is usually known, the amount of CO2 in the stack (chimney) sample can be calculated from the O2 and CO. If there is 20.95% oxygen in the air going into a stove, and 10% in the gases that come out, then approximately half of it has been used during combustion. Some. of it will have reacted with hydrogen in the fuel to make H2O (water). This happens easily so analysers usually assume that all the hydrogen has been burned. Another portion of the oxygen combines with carbon to make CO. So based on the fuel composition, the initial and post -combustion oxygen levels, and the CO level, the rest of the oxygen can be assumed to have been burned to CO2. Using this logic, a reasonable calculation of the CO2 level, expressed in %, can be made without measuring it directly, useful if you have that simple gas analyser. Figurel A TSI CA -6203 Combustion Analyser r20.95 -(O °/ CO% CO2% CO2 Max %x 2 l 20,95 Note: CO2 Max for Wood is 19.4% The CO/CO2 katio (C05) A measure of how completely the fuel is being burned can be determined by dividing the CO by the CO2. Fully combusted carbon emerges as CO2, partially burned carbon as CO. The better the combustion, the lower the proportion of CO. This calculation can be made with any level of dilution, provided. both are determined from readings taken at the same time: As the CO is usually given in ppm and the CO2 in °/o, a conversion factor is needed to determine their relative abundance. CO COR = CO 7 Suppose the levels are 500 ppm CO, and 10% CO2 First convert the CO ppm to CO0/0 500ppm CO 10,000 =0.05%CO Then divide the CO by the CO2 CO =0.05% CO _ 0.005 = 0.5% ° 10% CO2 The target of a stove developer is to achieve a COR of 2% or less.' Very low readings are possible in modern stoves. 19 Correcting the CO reading undiluted gas concentration The CO° is calculated using the readings taken directly from the analyser and can compare the combustion efficiency of different stoves. However it is not correct to makecomparisons between stoves using uncorrected CO readings alone. The presence of •excess air, as indicated by the oxygen level, means that the CO measurements will be incorrect, with valid comparisons for individual gases only being made using EA -corrected figures. :a. Compare these measurements from the stack and determine which version of the stove has lowest CO level: Test I CO = 2561 ppm, O2 = 8.00% Test 2 CO = 1981 ppm, O2 = 10.60% Test 3 CO = 2144 ppm, O2 = 11.25% Test I shows the EA is 60.19%, so A is 1.6019. The undiluted CO level is 1.6019 x 2561 = 4301 ppm. Test 2 shows the EA is 100.50%, so A is 2.0050. The undiluted CO level is 2.0050 x 1981 = 3972 ppm. Test 3 shows the EA is 113.62%, so A is 2.1362. The undiluted CO level is 2.1362 x 2144 = 4580 ppm. The stove in Test 2 is the cleanest burning, and Test 3 is the dirtiest, something not obvious from the COreading alone. It is very important to make this correction to obtain the undiluted gas concentration. It makes meaningful comparisons between different stoves and fuels possible. Particulates Suppose we want to know the PM 2.5 particulate emission level and how clean the burn is when a stove is used with two different fuels. Test I CO = 3566 ppm, O2 = 13.05%, PM 2.5 = 135 pg/m3 Test 2 CO = 2911 ppm, O2 = 11.40%, PM 2.5 = 161 pg/m3 The calculated EA, A, CO2 and COa levels for the tests are: Test I EA = 159.34%, A = 2.5934, CO2 7.15%, COa = 4.99% Test 2 EA = 116.08%q A = 2.1608, CO2 8.71%, CO°=3.34% The undiluted PM 2.5 concentrations are: Test 1135 x 2.5934 = 350 pg/m' Test 2 161 x 2.1608 = 348 pg/m3 The fuel in Test 2 has- a better combustion efficiency indicated by a lower COa but they have the same level of PM 2.5 emissions. Analysing heat transfer efficiency A combustion analyser can measure the chimney gas temperature and calculate the amount of heat lost up the 'chimney stack'. The air feeding a stove has to be drawn from outdoors. The initial temperature (T,) is the outdoor temperature and the final temperature (T2) is the temperature inside the chimney. TzTi= Delta T=AT Stack losses are a combination of gas volume and AT. Recording the temperature in the chimney will not, alone, tell you what the loss is. You need to know, as before, the amount of excess air that is diluting and expanding the volume of emissions from the fire. The combustion analyser will calculate the amount of heat contained in the gases and combine this with the quantity of excess air to produce a percentage heat loss, If the exit temperature was the same as the outdoor temperature, the loss would be 0%. To determine the loss in Watts, you have to weigh the fuel being burned and determine the heat generated, then multiply that times the percentage of heat being lost. This heat loss feature is helpful even if you are working on stoves without a chimney. Take a sample of gases from the point at which they exit past the pot and you get the percentage of heat being lost at that point. The inputs used are the room temperature, the exit temperature and the Excess Air level. Care must be taken to ensure no air from the room enters the sample being drawn or you will get an inflated Excess Air figure. Forsmall stoves with a short gas path, the exit temperature will give a general indication of losses: the higher the temperature, the greater the loss. Unfortunately, this is only true in certain cases. For example, if you increase the excess air supply significantly, you may see a drop in temperature but a large increase in heat loss because the extra air is cooling the fire and rushing the heat past the pot in a larger volume of cooler gas. The thermal efficiency of a small stove is usually lower than a space heating chimney stove. Exceptions to this are some institutional stoves with pots sunk completely into an all -enclosing, insulated body. In such a stove, decreasing the excess air can show a constant or even a decreasing exit temperature and a substantial increase in efficiency. Figure 2 A Testa 350 XL Combustion Analyser Figure 3 A Lufft temperature logger Using a combustion analyser to track the undiluted gas and particulate levels, the heat loss and the CO° a stove developer is well equippedto work wonders improving a stove's performance, Profile of the Author Crispin Pemberton -Pigott has worked with Appropriate Technologies for 30 years, largely in rural water and manual production equipment. A stove maker for 25 years, he won the Design Institute of South Africa Chairman's Award 2004 for the 'Vesto', e semi- gasifing stove now manufactured in Swaziland at New Dawn Engineering, a producer of labour -based manufacturing systems for rural employment. He is a co-founder of the Eastern Cape Appropriate Technology Unit (RSA), the Renewable Energy Association of Swaziland and the Industrial Designers Association of South Africa. • Presently the Regional Technical Advisor for GTZ/ProBEC he is also on the Board of the Sustainable Energy Society of Southern Africa (SESSA) and chairs its daughter organisation, the Association for Renewable Energy Cooking Appliances (AFRECA). He is a member of the South African Bureau of Standards technical committees writing national standards and test protocols for coal, paraffin and gel fuel stoves. www.hedon.info/KU.JA Full article online Author profile and latest contact details 20 3/26/13 State.co.us Executive Branch Mail - Minor Revision to DCP Lucerne 2 Ecansion Comment Response 3 b J i1 Ll�7l L State of Colorado- - Minor Revision to DCP Lucerne 2 Expansion Comment Response Roshini Shankaran<RShankaran@trinityconsultants.corn > To: bailey.smith@state.co.us Cc: "Stephens, Dana" <DStephens@dcpmidstream.com>, Kim Ayotte <KAyotte@trinityconsultants.com> I just got a mail delivery failure for this email. Re -forwarding! Please confirm receipt of the email. Thanks, Roshini Shankaran1 Consultant lrshankaran@trinityconsultants.com Trinity Consultants, Inc. 11400 16th Street, Suite 4001 Denver, CO 80202 Main: (720) 932-8063 Direct: (720) 932-8164 'Fax: (720) 932-8263 — Forwarded by Roshini Shankaran/Trinity Consultants on 03/25/2013 04:57 PM - Mon, Mar 25, 2013 at 4:59 PM From: Roshini Shankaran/Trinity Consultants To: "Smith -CDPHE, Bailey" <bailey.smith@state.co.us> Cc: "Stephens, Dana" <DStephens@dcpmidstream.com>, Kim Ayotte <KAyotte@trinityconsultants.com> Date: 03/25/2013 03:57 PM Subject: Re: Minor Revision to DCP Lucerne 2 Expansion Comment Response Bailey, Here are the responses to your questions. I am just copying your questions from the email below and noting DCP's responses below each question. How will CO2 emissions be monitored for the amine unit to comply with 40 CFR Part 98 Subpart W? Will the amine unit be equipped with a vent meter? Are you proposing to use ProMax? Will you install a continuous gas analyzer or take samples quarterly? A. CO2 emissions will be calculated -using the inlet or outlet gas flow rate of the amine unit, which corresponds with Calculation Methodology 3 under 40 CFR Part 98 Subpart W. Is the turbine waste gas heat used to pre -heat intake air or to heat other processes on site? A. The turbine waste gas heat is used to heat the hot oil in addition to heat from the hot oil heater. I don't understand the safety concerns associated with routing the dehy still vent emissions to an RTO. Could you explain this situation in more detail? This seems to be common practice. For example, I also permit the Roggen facility, which routes the dehy still vent stream to an RTO. I'm not sure what makes the proposed configuration at this facility different. A. A recent policy change has resulted in DCP routing the dehydrator still vent emissions to a combustor rather than an RTO. All DCP projects will have this configuration going forward. The policy has been put into effect due to -safety concerns at existing DCP sites that use an RTO for control of this stream. This can be most recently seen in the application submitted for DCP's Platteville 2 Expansion. Please feel free to give Dana Stephens (303-605-1745) or https://mail .g oog le.com/mai l/u/0/?ui=2&ik=98c42040dd&vtevpt&search-inbox&msg� 13da3c7835ab4f8a 1/2 3/26/13 State.co.us Executive Branch Mail - Minor Revision to DCP Lucerne 2 Ecansion Comment Response Brian Taylor (303-605-2185) a call to discuss. The proposed BACT limit for the turbines is simply the emission factor from the mandatory reporting rule. Since BACT should represent efficient operation of the unit, I feel an output -based limit would be more appropriate (ie lb/hp). Is manufacturer's information available on the CO2 emissions from the turbines? A. Manufacturer specifications are not included for CO2. However, DCP has converted the input based emission factors from the mandatory reporting rule into output based emission factors that is specific to the proposed turbine. Revised output -based turbine BACT limits are calculated as follows: lb 7.550 lb �Y lb BACT Limft = Turbine Emissions + Engine Horsepower (8.53 hp) _ 0.88 , 6, (iip— hr. _ hr tip — hr It is my opinion that the RTO should be included as part of the amine unit and not permitted as a separate emission unit. I have a suite of reasons for this, let me know if you want more detail on that decision. If you are okay with that I can red -line your amine unit APEN to include the RTO. A. DCP agrees. Please red -line the APEN for the amine unit. The supplemental submittal included revisedAPENs for the fugitives and the dehydration unit. These APEN were not signed. Should 1 expect to receive a signed hard copy version of these APENs? A. Yes, these will be signed and mailed to the CDPHE this week. Thanks, Roshini Shankaran 1 Consultant Irshankaran@trinityconsultants.com Trinity Consultants, Inc. 1 1400 16th Street, Suite 4001 Denver, CO 80202 Main: '(720) 932-8063 1 Direct: (720) 932-8164 'Fax: (720) 932-8263 From: "Smith -CDPHE, Bailey" <bailey.smith@state.co.us> To: Roshini Shankaran<RShankaran@trinityconsultants.com> Cc: "Stephens, Dana" <DStephens@dcpmidstream.com>, Kim Ayotte <KAyotte@trinityconsultants.com> Date:03/19/2013 02:39 PM Subject: Re: Minor Revision to DCP Lucerne 2 Expansion Comment Response [Quoted text hidden] https://mail.g oog ie.comrmail/u10/?ui=2&i k=98c42040dd&view=pt&search=inbox&msg=13da3c7835ab4f8a 2/2 18/13 _ State.co.us F'Acutive Branch Mail - Re: DCP Lucerne Re: DCP Lucerne STATE OF COLORADO Roshini Shankaran <RShankaran@trinityconsultants.com> To: "Chaousy - CDPHE, Stephanie" <stephanie.chaousy@state.co.us> Cc: "Stephens, Dana" <DStephens@dcpmidstream.com> Stephanie, Tue, Jun 18, 2013 at 12:10 PM I am responding on behalf of Dana as she is tied up today. I am listing the responses to your questions below. A general thought that came to my mind though is - do you have the responses that we sent Bailey back in March? I recall several of these questions being addressed a few months ago and just wanted to make sure we all have the same information. I am attaching twoindividual responses that were prepared and sent to Bailey on March 1st and March 11th. The response documents have the questions, DCP's responses, as well as several relevant attachments. Ifyou already had this, please ignore the attachments, just thought it would be worth sending your way! I could not tell with the ProMax model if any of the VOC, HAP or CH4 reductions were credited by the condenser operation? I thought typically condensers are water knockouts and not for full criteria control. Could you please provide some guidance on this? The condenser is only for water knockout and does not offer any pollutant control. Therefore, DCP did not take credit for any emission reductions due to the presence of a condenser. Please refer to the responses sent to Bailey on March 11th (attached, see response to question 4). Did you include flash tank emissions in the "uncontrolled" baseline forprocessunit? The flash tank emissions are routed to inlet compression even when the control device for the processunit is down. Therefore, there will not be a situation when the flash tank vent would be uncontrolled. Please refer to the responses sent to Bailey on March 1st (attached, see response to question 5), How were the CH4 emissions quantified? The methane emissions from the amine and dehydrator still vent are quantified on the respective control device calculations. For example, the RTO GHG calculations indicate "Controlled GHG Emissions" for methane, which is the portion of CH4 that is emitted directly from the control device. Please refer to the responses sent to Bailey on March 1st that touches on the same question (see response to question 6), and the detailed calculations prodded as part of the March 11th response, Attachment A. If you have any questions about the above or theattachedresponses; please feel free to give me a call! Thanks, Roshini Shankaran I Consultant I rshankaran@trinityconsultantscom Trinity. Consultants, Inc. 11400 16th Street, Suite 4001 Denver, CO 80202 Main: (720) 932-8063 I Direct: (720) 932-8164 I Fax: (720) 932-8263 From: "Chaousy -CDPHE, Stephanie" <stephanie.chaousy@state.co.us' To: "Stephens, Dana" <DStephens@dcpmidstream.com> Cc: 'RShankaren@trinityconsultantscom Date: 06/18/2013 10:01 AM Subject: Re: DCP Lucerne Hi Dana, We are definitely working on this permit, and we appreciate your patience as we catch up to this challenging and complex permit. I do have a quick question for you though...I could not tell with the ProMax model if any of the VOC, 1.4 A D nr f I-tA rat, intinnc r ,nra nrarli+nrl hr+ha nnnrlanear nnnrofinn9 I +hn, Vnht hmirolI, nnnrlancorc om nn,a+ar https://mall .g cog le.com/mail/u/0/?ui=2&i!=7faca29a3B&view=pt&search=i nbox&th= 13f587ae36223ea9 1/5 6/18/13 State.co.us ExecutKe Branch Mail - Re: DCP Lucerne I Irll VI vI IY IGUI.At LILt 10 VIIGE vl GUI L U Ly LI I0 vUI IUGI IbGI U}.lGI QLIUI It I LI IVUIvI II lypIVQIIy vUI IUGI lOGIO Calc YVa CGI knockouts and not for full criteria control. Could you please provide some guidance on this? Did you include flash tank emissions in the "uncontrolled" baseline for process unit? How were the CH4 emissions quantified? Like I said before, the Division does have some significant concerns on the BACT as well, but we are needing to do pieces at a time as we go through the application/permit. Thanks! Steph On Mon, Jun 17, 2013 at 11:32 AM, Stephens, Dana <DStephens aC�dcpmidstream.com> wrote: Hi Stephanie, Based on the attached emails received from Bailey Smith on May 23rd and May 24th, DCP is not currently reviewing the draft permit we received on May 13, 2013. However, DCP is concerned that the timing of this permit is going to slip. Are there parts of the draft permit (May 13, 2013 version) that we can/should be reviewing that are currently not being changed by the .Division? Please advise so we can keep this moving from our side. Thanks, Dana Dana M. Stephens, REM DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Office -1303) 605-1745 Mobile - (7201 355-4703 Email - dstephens@dcpmidstream.com From: Chaousy - CDPHE, Stephanie [mailto:stephanie.chaousv(lstate.co.us] Sent: Thursday, June 06, 2013 12:46 PM To: Stephens, Dana Cc: Mark,MCMillanastate.co.us; Christopher Laplante - CDPHE; carissa.monev(lstate.co.us Subject: -Re: DCP Lucerne Hi Dana, The Division has some significant comments on the BACT analysis that we are currently putting together that we will want to discuss before the next DRAFT permit. In the meantime, I was wondering if you could send me digital/electronic copies of the Promax model? The printouts in the application are really small and the headings are hard to read. Specifically the streams information would be beneficial. Thanks! Steph On Mon, Jun 3, 2013 at 11:29 AM, Stephens, Dana <DStephens@dcpmidstream.com> wrote: https://mail .g oog le.corrdmai l/u/0/?ui=2&Ik=7faca29a38&vien= pt&search= l nbox&th=13f587ae36223ea9 2/5 6/18/13 State.co.us Fxecutive Branch Mail - Re: DCP Lucerne , ➢ Stephanie, Please find attached a scanned document that contains.a signed copy of the APEN addendum for the Amine unit (P-047), a signed copy of the revised APEN for the amine unit (P-047), and a signed copy of the revised APEN for the loadout (P-051). Please let me know if you need anything else. Bailey had mentioned that we would be receiving a revised draft permit that looked quite a bit different than the one we have already received and have been reviewing. Do you know when you will be sending that version, out for review? Thanks, Dana Dana M. Stephens, REM DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Officer J3031 605-1745 Mobile -17201355-4703 Email - dstephens@dcnmidstream.com from: Chaousy - CDPHE, Stephanie[mailto:stephanie.chaousy@state.co.us] Sent: Thursday, May 30, 2013 8:19 AM To: Stephens, Dana Subject: DCP Lucerne Hi Dana, lam starting my review of DCP's Lucerne after Bailey's departure, trying to familiarize with the project. I am starting with the APENS (thought that would be a good place to start :-)) and have a few things: 1. For the Amine unit (Point O47): Even though the APEN addendum the Division has is for non -criteria pollutants, could you please fill one out for the SO2 and H2S emissions? Please sign it as well; you can email it to me. 2. For the Amine unit (Point 047): The emission factors are listed in lb/hr and should be in Ib/mmscf. I have made the calculations, and if you agree, I can just redline the APEN: VOC = (166.90 TPr2000)/83950 MMscf/yr= 3.98 Ib/MMscf Benzene=(64.47*2000)/ 83950 MMscf/yr =,1.54 lb/MMscf Toluene=(30.62"2000)/ 83950 MMscf/yr =0.729 lb/MMscf Ethylbenzene =(1.11 TPY* 2000)/8395O MMscf/yr = 0.0264 lb/MMscf Xylenes = (2.32 TPY* 2000)/83950 MMscf/yr = 0.0553 lb/MMscf https://mail.goog le.cordmail/u/0/?ui=2&i lc-7faca29a38&vevr_pt&search=i nboX&th=13f587ae36223ea9 3/5 6/18/13 State.co.us Executive Branch Mail - Re: DCP Lucerne n -hexane = (0.76 TPY* 2000)/83950 MMscf/yr = 0.0181 lb/MMscf d 3. For the loadout (Point 051): The emission factors listed are in wt% and should be in lb/1000 gal. I have made the calculations, and if you agree, I can just redline the APEN: Benzene = (0.63 *2000) /456250= 0.0028 lb/bbl * 1000/42 = 0.0658 lb/1000 gal Toluene = (1.74 *2000) / 456250= 0.0076 lb/bbl * 1000/42 = 0.1816 lb/1000 gal Ethylbenzene = (0.13 *2000) / 456250= 0.0006 lb/bbl * 1000/42 = 0.0136 lb/1000 gal Xylenes = (1.32 *2000)/456250= 0.0058 lb/bbl * 1.0.00/42 = 0.1378 lb/1000 gal n -hexane = (3.38 * 2000)/456250= 0.0148 lb/bbl* 1000/42 = 0.3528 lb/1000 gal I apologize if there will be several emails from me, but I am trying to familiarize myself with the project and might have some more questions along the way. But I thought I would start the ball rolling and get things taken care of while reviewing. Thank you, Steph Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment • 303-692-2297 • www.colorado.gov/cdphe Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297 www. colorado. gov/cdohe Stanhania C:hanusv P I https //mail.gcog le.com/mail/u/0/?ui=2&ik=7faca29a38&view=pt&search=inbox&th=13f587ae36223ea9 4/5 6/18/13 Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297 www. col orado. gov/c do he State.co.us Executive8ranch Mail - Re: DCP Lucerne The information transmitted is intended only for the'person or entity to which it is addressed and may contain confidential and/or privileged material. Any review, retransmission, dissemination -or other use of,, or taking of any action in reliance upon,' this information by persons or entities other than the intended recipient is prohibited. If you Received this in error, please contact- the sender and delete the material from. any computer. 2 attachments a,, 5 FINAL DCP Lucerne Platteville Response (2013_0301).pdf E 1 231K FINAL Lucerne GHG PSD Application Response (2013_0311).pdf 687K https://mai l.g cog l e.corn/mail/u/0/?ui=2&i k=7faca29a38&vi ev=pt&search=i nbox&th=13f587ae36223ea9 5/5 7)8113 State.co.us Executive Branch Mail - Re: APENS for DCP Lucerne STATE OF COLORADO Re: APENS for DCP Lucerne Roshint Shankaran <RShankaran@trinityconsultants.com> Wed, Jul 3, 2013 at 4:05 PM To: "Cheousy - CDPHE, Stephanie" <stephanie.chaousy@state.co.us> Cc: "carissa.money@state.co.us" <carissa.money@state.co.us>, Christopher Laplante - CDPI-JE <christopher.laplante@state.co.us>, "Stephens, Dana" <DStephens@dcpmidstream.com>, "Kimberly Ayotte (kayotte@trinityconsultants.com)" <kayotte@trinityconsultants.com> Hi Stephanie, We have revised the VOC emissions for the facility. During the 1% downtime of the VRU, the flash streams from the amine unit and dehydrator will be routed to the facility flare which offers 95% control. Please find attached the revised calculations, APENs, and O&M plans that reflect this change. We are working on the remainder of the items and will have them to you as soon as we can. Please let me -know if you have any questions about this revision. i will be out of the office till July 8th, but will be happy to respond then. Happy 4th of July everyone! Thanks, Roshini Shankaranl Senior Consultant Irshanl¢gran@tnnityconsultantscom Trinity Consultants, Inc. 1391 N Speer Blvd, Suite 3501 Denver, CO 80204 Main: (720) 638-7647 1 Cell: (404) 915-2569, WEVE MOVED! PLEASE NOTE OUR NEW CONTACT INFORMATION ABOVE. From: "Chaousy-CDPHE, Stephanie" <stephanie.chaousy@state.co.us> To: Roshini Shankaran <RShankaran@trinityconsultantscom>, "Kimberly Ayotte. (kayotte@trinityconsultants.comr <kayotte@trinityconsultants.com>, "Stephens. Dana" <DStephens@dcpmidstream.com> Cc: "canssa.money@state.co.us' <carissa.money@state.co.us>, Christopher Laplante - CDPHE <christopher.laplante@slate.co.us> Date: 07/01/2013 09:13 AM Subject: APENS for DCP Lucerne Hi Roshini, I wanted to send you a copy of the redlined APENS I have for Lucerne. We discussed having a clean copy for public comment, and Ijust wanted to make sure you agreed and aware of all the changes to the APENS. I know some of the APENS might change again due to the 40 TPYVOC limit, but I wanted to send you what I have now, and then the new APENS will reflect these changes plus incorporate the new changes that you are working on now. Thank you, Stephanie Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297 www.colorado.gov/cdphe https://mail.goog le.corn /rrtail/u/0/?ui=2&!k=7faca29a38&view= pt&search=i nboX&th=13fa6918ed86f067 1/2 7/8/13 - State.co.us Fracutive Branch Mail - Re: APENS for PCP Lucerne [attachment "DCP APENS 7-1-13.pdf' deleted by Roshini Shankaran/Trinity Consultants] The information transmitted is intended only for the person or entity to which it is addressed and may contain confidential and/or privileged material. Any review, retransmission, dissemination or other use of, or taking of any action in reliance upon, this information by persons or entities other than the intended recipient is prohibited. If you Received this in error, please contact the sender and delete the material from any computer. 3 attachments ti Amine and Dehy APENS (2013 07 03).pdf 175K Amine Unit and Dehy O&M Plans (2013 07 03).pdf 146K Revised Lucerne Mod Plant Calculations_v5.4.pdf 180K https://mail.goog le.coMmail/u/0/?ui=2&il=7faca29a38&view=pt&search=i nbox&th=13fa6918ed86f067 2/2 Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit 9 & AIRS ID] E C z [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] N 4�. a c W H j 0 v J L N a a ro s v r. 0 0 d Section 02 — Re Section 01— Administrative Information N Lucerne Natural Gas Processing Plant a 00 Change processor equipment 3 ❑ ❑ ❑ s 0 0 0 s N 0 00 0 U P.. N 370 17th St, Suite 2500 C ❑ 303-605-1745 Phone Numb Dana Stephens Fax Number: 303-605-1957 '¢ m1 c Section 03 —General Informa 0 0 0 0 v 5' G 0' z CC C D N o -p ▪ .5 a a- v o° ° N A 'o O P. P. 0 O .9 Q .0 v O 0 co' A 0. o 0 C O 0 CO' ens 0 a C L. g 'a • o 0 0 .0 ° a " 4 Ta �x °aG w8 Z O 3 0 00 0 a O ❑ ❑ ❑❑ ®® .0 ro ad -G .0 0 C o -- o 00ten In a _ a a m e n c n C N N N ° Co. Co 0.w O a G - 0 N Tho an nn 0 O O O C v v v > 90 00 CP E ro e0 a O O > U 2 O U 3, .5 .5 act O W q < CO sestate.co.us/ he.state.co:us/a -0 C 00 ° TM -0 m 5 y W m -10 0 000 arn 0 0 N w 0' 000 -00 A w C) C e' ment Information Ca CO CC Section 04 Amine Sweetenin C 0 A ao ❑ C C 6Gn 0p o cars' la75 N A C 0 0 U U In O 0 co 00 cd U 0 Calendar year actual: c 00 en O N w w 00 N co 0 to 00 00 N 07 W In CO 05 GO N ▪ Vi m x 0 0 Ca.0 m TOI P. aO. . p F F F F F a O 5 at ro 0. �P. - 0. O. v°. v 0 y In 4 m " 04 4 0. ' a an .5 N a 0 0 ca ¢ N 4 ix C 0 0 VD m a F ro m a a M N a a v z S ✓ 0 • a 5 .9 y .0 a O O O P. a 0 -o 'a 0 0 O O P. P. O 0 0' 0' 9 L O O 0 • 0 .0 a 0 • .0 G O 0 5 2 0 2 t.2 0 • 'Er, o a S N N v w -O aU z� colx U 5 `3 v mx G 6 o� 0 0 >G • ° F o • to CO 5. • g00 0• 7 • U -5 a • 13 .`0 5 w m o 0 0 0 5 3 o G O ° G 0 o N 7 .C C v o 0 EL OP. 0 " y 0 N ar.' U F ,L -2 -2 O • L 0 0 El OE is 0 E L 0\ 9 a 0 4 PZ N 0 6 N iI FORM APCD-206 0 0) 0) 0 Q 0 Q 0 R.� as O 0 W . .a O S. Emission Source AIRS ID: Permit Number. Z` a N N N N 7 v� 528681.36 m E qo N n tt o ❑o 0 0 .0 0 V A rs. .. 0 0 Cl, 0i L 0) 07 .L. 8 U .O ttltica w C O ar E U 0) A 0 U N 0 m. Information & Emission Control Information O a Cl: d 0 .O n s 0 0 b Cl U CO e C E U 0 5. U W 0 y E z Estimation Method or Emission Factor Source v e 1 aaaac2 Please use the APCI) Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Requested permitted -. Emissions Uncontrolled "Controlled (TobiArear) , (Tons/Year) O O N 01 sO 2.72 2.58 1.23 v O O a, O q f'9 O O C/, O 724.13 172 69.91 V) . M N " 2.47 9.15 Actual Calendar Year Emissions' Uncontrolled C.ontrolied (Tons/Year) (Tbns%I'ear) ( � ssion Factor Und'1lfrolled Basis Units F. .0 V .0 4-. to. 0 tad 4 00 C c, _ \` 17.2514 0.37 1.6656 'D N 00 I...; O N 00 N O O 00 00 I(7 O O O, N N O Control Efficiency (% Reduction) V r, {Sr N�-i1�iy1 �` Z } identify !h Sectiori-07 _ t> if' y.r 4x�s Control Device Description n '7 0 C./) w NOK VOC CO Benzene . a 0yp - .7.1‘m. 0p) e ro 00 L. u 0 d 00 C 0 o s 0 0r w O V 00 O CO u 0. 0. 00 O 00 0 • 00 Oi ° v) 'fl 00 O 0 ar 'ar 0 A 0? .L'. 0 .00 C 0 00 0i u is a0i 0 1.4 00 U Q 00 a Section 09—A w .0 N 0 -. z W CI U I z z • E U LIJ .E Z E • O O M U .°I b ® { m a. II U Z AIRS ID Number: Permit Number \ O 0_ J E a) Co 70 0_ U Company Name: 31495 Weld County Road 43 Plant Location: Phone Number: Dana Stephens Person to Contact: Fax Number: dstephens@dcpmidstream.com E-mail Address: Controlled Actual Emissions (lbs/year) O N O Cr5- CO CO a0 O N- _. Uncontrolled Actual Emissions (lbs/year) 63,020 34,914 rr�Iss ofV Fa tol• Sbu rce ©BMass alance Mass Balance Emission Factor (Include Units) N. O O N LO O Q \O 44- O N N O c O � C U ..-^-- Control Equipment / Reduction (%) Still Vent - RTO / 96% Flash — Flare / 95% ,,, ! 214 Reporting BIN r Chemical Name Sulfur dioxide Hydrogen Sulfide \ Cx- JV, Chemical Abstract Service (CAS) Number th O C V 7783-06-4 Calendar Year for which Actual Data Applies: Reporting Scenari a) O Sr. Environmental Specialist Title of Person Legally Authorized to Supply Data on Legally Authorized to Supply D Form Revision Date: December 4, 2006 a m a Z w ❑ ❑ 4 w U Z O O O (35 co w Z H J J O d C w J m C I- O d w e w 9 Z O Z e4 O LL w O Z Q ❑ 7 C9 a O N r O O) N O Y 2 co a) U Q = ii c o a a 2 (a 0 moo O a) O E U N N .N-. -0 a 0 N 0) -Op oo a1 N. YO tC _C LL N 0 a D J co C Q. N N a) 6 v w F2 t O N N O g p. 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Z N awc o m c c c. c Egli o 0 Q N .w .S U cu.es � U J Ow QY mm �.N a) N >t C(6 m f/OJ (J .�� lLL !L C d Q 9 Q j N Z N.. O) x C Na L co N w W 2 on c o N fn 'E, o Z O U C •c a c z N O N O C 4 O c O (B L C _ c. U c _ 7) N Y c •C. c N L O m O c •y u •N m C :N O N. c N € U N J N 0 o N a L .(6 N Ct 0. O. _ C U N_ N to o C .N N C N a E 'O E 'E OL CO N a (n N U U T a) >- x axi (_ a 6 p a) a O c a Z o d Q Q a U a re < Z°° -o U a W c W �. D g oC) Form Revision Date: December 4, 2006 r r 0 O C- a 0)41 U E a w O U a O a O 1 d d z U E' z z O rip C4 Emission Source AIRS ID: t# & AIRS ID] [Leave blank unless APCD has already assigned a pe Permit Number: us equipment is referenced within your organization.] O C O Q a w Facility Equipment ID: a R a O U ^ 0 H N C y O C T Ca G 6 C 0 Len L c S. N > \r U 6 G ,o y 0 O E `° C G s U C 0 p, O•• o C - a N' !; d pq y y p o , t S' ' m � C. 4 '7r w y V5 .15 .. v E � c �\n a Cl Ca E e M o-� OL 0. bU ❑ ❑ y C O W- L C 4 i. u T m G 9 V T 3 d C t V 0 E w S b YC yZ o' s- >,. 0 Qz t. 0 °, Q Q 0 0 U u L E. `o .°.' i' g ¢ N¢ a CO U N N 'O 0. .Vi u 6 m C. w w g g> W 0 a• Z o m '° e z p'c++ 00 5 E aw. .� Cat w '- L .C ¢ LOj d Nu U U o u Section 02 — Re O 0 0 C a O' P P a a ❑ ❑ a a ❑ ❑ az ® ❑ ❑ ❑ a N ti Company Name: 31495 Weld County. Road 43 Source Locati N W 0 a N 370 17th St, Suite 2500 303-605-1745 Phone Number: dstephens@dcpmidstream.com E-mail Address: Section 03 — General Information 3 0 0 0 0 5 Q Q Q ❑ ❑ ❑ Z' z z ❑ O > >' ® ❑ ❑ fr N ^c .E 5 ct > 'a O ..E, C O C C - y o o Al c - E CC E Ca o 2 O 3 0 0. 0 9 w E C O % C G W „, :w a ._ a 0 ¢ Y 0 0 T by U 7 o v O o p p a p p f. U N •• g - C O C C 0. O 2 ti '0 a oCi o .0. v 0 0 Ern ❑ a 0. C, 0 0 0 W Q '0 L O a O Ca a C CO O 1 p E as 'C C p, ti w 1.y C O ,5 .14 k W '0 I ro 3 d 14 14ZOA! `A C N a 'O u 0 14 a o -0 0 5 .n WPy m Q N ti U a ->'4 N ~ NW b9 ? .N g a m on a ti m 3 EN O P. X00v 3 wG C b > o > W C .4 O 0 U 0, o v O LL. y C C F .4 Q 00 0 E ON t N rU in in C N N On On W '0 L0 0 b m O0 M O O o re.state.co.us/ 'O APEN forms: h he.state.co.us/a Application status: h 0 E" '00 0 \ L co V7 W C.) 0 a \ C N 0 0 zzS C7 o U Temperature: NO n by b0 o-> '\ a -° a a go s U g z 3 O U m .d j ❑- 2 E E C \ y 5 p H P.vn 4.,a\c a ® '1 e. . osn 2 U O N Z - U ❑ E U E LA p, .E N J7N\ 0 U U E 0 15 • 8 C U Cca U. 14 .o 0. O O O 0' 2 2 pro, ro m 'C O Lt O 0 O O. P, O 0 cv a a' C. C. 0 0 0 0 0 .0 L t U U N® 0 0 a C O C d H T C7 1 0 0 a2 C 1•o a 5C C 7 Ca 8- a 5 51'y s5 '0X a0 °' c to' F ¢ 00 .0'O 0 to O U x0 'v a y 0. H O a v 0 a ro a UC7o O a . d 0. a a a GlycolDehydratorAPEN_TEG (D-1) v2. N O N FORM APCD-202 O se 1r1 6 A O O • 04 z LL� 0 0 L W 11-t a Emission Source Permit Number: L. 0 00 C {. d q 0 a 0 0 u ai O ci O Section 05 - Stack Information (Combustion star C:' :1. reF� 447832739 m N W s 00 VJ • 0 O • N c0 0 N a A Direction of stack outlet (check one): Section 08 —Emissions Inventory Information & Emission Control Information Estimation Method or Emission Factor Source AP -42 Section 1.4 j GlyCaic AP -42 Section 1.4 G1vCalc U 0 GlyCalc GlyCalc GlyCalc 'Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. 2 Ar,m,dt ..,;n o.'--'- ---- - ... a.,:;2 '0) 0el°,-4 '." �yI ?7 =..N at O."O U '-H -.••••:e' : Y -. N N t'7 N N C 0 O -enen 4 .-1 .-. Uncontrolled (Tons/Year)'. 0.913 b InO© b 0 O N 'et a0 N I. M tri R Actual CalehdarYear Em issions= Uncontrolled Controlled (Tons/Year) -.' .(TonstYear) b ::z O 5.--- 4.--... u u u u u u u u -!";"" Uncontrolledasis /1 100 a 00 %O ON ,moo, T V) P a 1.S 00 00 o O eO N et Q IO VI a Q Control Device Description ' Control Efficiency' Primary • Secoidaiyc" , Reduction)_ r Identify in Spctio _ti07 fx Pollutant NOx VOC Benzene Toluene • 0) w .E w C G V 4) a 0) 0 m u 0 .74 O .n .61 1.4 O Q C u O O CO • CI 4.1 d F�1 44, R u Section 09 A R CC C. as • 1}{' we .O' ta C es it�f Az 6 Lucerne Responses DCP is providing this information in response to questions received from the CDPHE on January 23, 2013 for the Lucerne Gas Plant PSD Application.1 The Lucerne Gas Plant is currently identified as AIRS ID 123/0107, authorized under CDPHE Construction Permit Number 12WE2024, and located in Weld County, Colorado. The CDPHE questions on the Lucerne permit application are listed below in italics and followed by a corresponding DCP response. Q; 1. The turbines: Looking at AP -42, Table 3.1-3, there is an emission factor for formaldehyde, however, formaldehyde is not listed on the Form 102. When I calculated formaldehyde, I calculated a reportable value of 402 lb/yr. If you agree with my calculations, I will need DCP to fill out the non -criteria reportable form for formaldehyde. I will need one for each turbine. Once you have filled in the form, you can just email them to me PDF. A: DCP agrees with this comment. An NCRP form for formaldehyde has been filled out for each turbine and is included in Attachment A. Q: 2. The turbines: I generated new emission factors for NOx and CO so that they are consistent with all the other emission factors at the facility and therefore, easier for the inspector to use when calculating emissions from the facility. Ifyou agree with my calculations, I will just redline the APEN accordingly. A: DCP noted some minor discrepancies in rounding. The emissions of NOx are estimated to be 16.95 tpy instead of 16.94 tpy, and CO is 17.17 tpy instead of 17.19 tpy. A revised attachment is provided in Attachment B that indicates the revised emission factors in lb/MMBtu units - NOx = 0.0598 lb/MMBtu, CO = 0.0606 lb/MMBtu. Please redline the APEN with these factors. Q: 3. For the hot oil heater: since formaldehyde is over 50 lb/yr, I will need the same form listed above #1 for the hot oil heater (formaldehyde at 567 Ib/yr). Update from Daily Smith on January 31, 2013: Also I think Steph may have mixed up the emissions for the hot oil heater -- from my calculations,you shouldn't need to report HCHO. I think she may have accidentally used the hexane emission factor. A: Formaldehyde emissions from the hot oil heater are less than 50 lb/yr. Please refer to the emissions previously submitted that demonstrates formaldehyde emissions to be at 24 lb/yr. Q: 4. For the amine unit: emission factors on the APEN were listed as lb/hr. Typically for amine units and dehydrators the Division likes to see emission factors in lb/mmscffor inventory purposes. I calculated the emission factors, and if you agree, I can just redline the APEN accordingly: VOC = (166.9 TPY * 2000)/83950 mmscf/yr = 3.9762 lb/mmscf Benzene =(64.47 TPY * 2000)783950 mmscf/yr = 1.5359 lb/mmscf Toluene = (30.62 TPY *2000)/83950 mmscf/yr = 0.7295 lb/mmscf Ethylbenzene =(1.11 TPY * 2000)/83950 mmscf/yr = 0.0264 lb/mmscf Xylenes = (2.32 TPY * 2000)/83950 mmscf/yr = 0.0553 Ib/mmscf n -hexane = (0.76 TPY * 2000)/83950 mmscf/yr = 0.0181 lb/mmscf A: DCP agrees with this assessment. Q: 5. For the dehydrator i believe the uncontrolled emissions listed on the APEN did not include the emission from the flash tank. I know that the GlyCALC model says that flash gas emissions are zero with the recycle/recompression control option but for the uncontrolled, but I think that's for the purpose of calculating the controlled emissions. I believe it ' Questions on DCP Lucerne application were received from Ms. Stephanie Chaousy on January 23, 2013. This response also includes questions and responses for the DCP Platteville Permit Application received from Ms. Bailey Smith on January16, 2013. Since the Lucerne and the Platteville projects are essentially identical, questions are applicable for both applications and projects. Any separate questions on Platteville are addressed separately. would be included because those are the emissions from the flash tank prior to control. Please let me know your thoughts. believe you will need to add the uncontrolled regenerator emissions plus the flash tank off gas to get the total uncontrolled emissions. If so, then the emissions (and emission factors) 1 calculated are: Uncontrolled VOC = 380.6547+324.9637 = 705.6 TPY; controlled will be what is on the APEN since it is just controlling the regenerator (flash tank closed loop). Uncontrolled Benzene = 68.4169+1.6637 = 70.1 TPY controlled will be what is on the APEN since it is just controlling the regenerator (flash tank closed loop). Uncontrolled toluene = 44.4377+.7903 = 45.2 TPY; controlled will be what is on the APEN since it is just controlling the regenerator (flash tank closed loop). Uncontrolled ethyl benzene = 2.8465+0.033 = 2.9 TPY; controlled will be what is on the APEN since it is just controlling the regenerator (flash tank closed loop). Uncontrolled xylenes = 59364+0.049 = 6.0 TPY; controlled will be what is on the APEN since it is just controlling the regenerator (flash tank closed loop). Uncontrolled n -hexane = 26.0863+14.4472 = 40.5 TPY; controlled will be what is on the APEN since it is just controlling the regenerator (flash tank closed loop). VOC = (705.6 TPY * 2000)/83950 mmscf/yr = 16.81 lb/mmscf Benzene =(70.1 TPY *2000)/83950 mmscf/yr = 1.67 lb/mmscf Toluene = (45.2 TPY * 2000)/83950 mmscf/yr = 1.0768 lb/mmscf Ethyl benzene =(2.9 TPY * 2000)/83950 mmscf/yr = 0.0691 lb/mmscf Xylenes = (60 TPY * 2000)/83950 mmscf/yr = 0.1429 lb/mmscf n -hexane = (40.5 TPY * 2000)/83950 mmscf/yr = 0.9649 lb/mmscf Ifyou agree, I can redline the APEN accordingly. The APEN will show more than 96% control, but that is because of the closed loop system. A: DCP disagrees with this assessment. As presented in the Process Flow Diagram, the flash gas stream is routed to inlet compression. During downtime associated with the control device, the flash gas emissions would still not be vented uncontrolled. Therefore, the regenerator stream presented previously in the APEN would be the only uncontrolled emissions associated with the dehydrator. Q: 6 For the thermal oxidizer: I converted the SOx emission factor to lb/mmbtu so that the source is consistent with their emission factors (easier for the inspector). Ifyou agree with my calculations, I can just redline the APEN. S0x = 31.3 T 2000 lb Yr scf = 4.26161b/mmbtu yr 1T 2869 mmscf 5.12 btu A: DCP agrees with this assessment. Q: 7. Sorry to keep adding questions on as you are working to get answers to the first round, but there is one potentially major aspect I wanted to cover before getting too far along in the review process. Particulate emissions from the RTO (and combustor) are not accounted for in the permit application. For an RTO, I feel the closest applicable AP -42 emission factor would be external combustion of natural gas (Chapter 1.4), and we have used this for calculating PM emissions from other RTOs. Using this value and a £12 Btu/scf heat value, PM2.5 emissions comes out to 109 lb/yr, or a little over 0.05 tons per year. This would put total modification emissions over our modeling threshold for PM. A: The RTO is a smokeless combustion device as described on the manufacturer specifications provided in Appendix A of the permit application. Therefore, no particulate matter is expected to be generated from combustion in this device. Platteville Responses Q: 6) There are a couple sources of GHG emissions that! can't account for in the GHG calculations for the facility. a. The methane emissions from the 4% of the amine acid gas stream that is not destroyed by the RTO. b. The methane emissions from the 5% of the dehy still vent that is not combusted. c. Methane emissions from the uncontrolled portion of working and breathing losses from the tanks. d. Methane emissions from the uncontrolled portion of emission from the loadout. Since there is no de minimis level for GHG emissions, all potential sources of GHG emission, however insignificant they may be, must be accounted for. A: These emissions are all accounted for and are explained below: a. These methane emissions are indicated as "Controlled GHG Emissions" on the RTO Combustion Emissions - GHG page included in Section 5 (Attachment C) of the permit application. b. These methane emissions are indicated as "Controlled GHG Emissions" on the Enclosed Combustor - GHG page included in Section S (Attachment C) of the permit application. c. Since the methane content of the condensate is 0%, there are no methane emissions from working and breathing losses from the tanks. d. Since the methane content of the condensate is 0%, there are no methane emissions from loadout. Q: 8) The component counts for the existing portion of the fugitive emissions point does not agree with the Title V permit or application. I believe that the component category titles were simply mismatched with the counts. Also, the existing component count included in the application I know to include a 20% buffer to account for changes. It is not clear in the application whether the projected component count for the new equipment includes such a buffer. Please revise the emission calculations based on the correct component counts for existing equipment (or let me know if the count included in the Title V renewal application was the incorrect version). A: The component counts do include a 20% buffer. DCP believes that the modification application submitted uses the same component counts as that submitted with the renewal application for the existing facility. Please correct the discrepancy. Q: 9) The application requests that the new fugitive equipment leaks point be combined with the existing equipment leaks point. This is not a problem to combine all equipment on one point, however, you should be aware that parts of the point will be subject to NSPS Subpart KKK and the new equipment permitted under the point will be subject to NSPS Subpart 0000. It is not significant to us whether the points are separate or combined, but I want to offer the option to keep the equipment on separate points if it easier for you. Alternatively, you could chose to have all equipment comply with the newer, more stringent standard, if that is best for you. A; DCP would like to keep these points separate so as to not make the existing equipment subject to NSPS Subpart KKK. ATTACHMENT A. NON -CRITERIA REPORTABLE FORMS NON -CRITERIA REPORTABLE AIR POLLUTANT EMISSION NOTICE ADDENDUM (See reverse side for guidance on completing this form) Permit Number: Company Name: Plant Location: Person to Contact: E-mail Address: TBD (TURB-1) DCP Midstream, LP 31495 Weld County Road 43 Brian Taylor bstavlortdcpmidstream.com AIRS ID Number: 123/0107 County: Weld Phone Number: 303-605-2185 Zip Code: Fax Number: 303-605-1957 Chemical Abstract Service (CAS) Number Chemical Name Reporting BIN Control Equipment / Reduction (%) Emission Factor (Include Units) Emission Factor Source Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions (lbs/year) _ 50-00-0 Formaldehyde A N/A 7.10E 4 lb/MMBtu AP 42 Section 3.1 402 402 Reporting Scenario (1, 2 or 3): 1 Calendar Year for which Actual Data Applies: Signature of Person Legally Authorized to Supply Data Brian Taylor Name of Person Legally Authorized to Supply Data (Please print) Title of Person Legally Authorized to Supply Data Form Revision Date; December 4, 2006 Date Rockies Air Permitting Manager NON -CRITERIA REPORTABLE AIR POLLUTANT EMISSION NOTICE ADDENDUM (See reverse side for guidance on completing this form) Permit Number: Company Name: Plant Location: Person to Contact: E-mail Address: TBD (TURB-2) DCP Midstream, LP 31495 Weld County Road 43 Brian Taylor bstaylor(c idcpmidstream.com AIRS ID Number: 123/0107 County: Weld Phone Number: 303-605-2185 Zip Code: Fax Number: 303-605-1957 Chemical Abstract Service (CAS) Number Chemical Name Reporting BIN Control Equipment / Reduction (%) Emission Factor (Include Units) Emission Factor Source Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions (lbs/year) 50-00-0 Formaldehyde A N/A 7.10E-4 lb/MMBtu AP -42 Section 3.1 402 402 Reporting Scenario (1, 2 or 3): 1 Calendar Year for which Actual Data Applies: Signature of Person Legally Authorized to Supply Data Brian Taylor Date Rockies Air Permitting Manager Name of Person Legally Authorized to Supply Data (Please print) Title of Person Legally Authorized to Supply Data Form Revision Date: December 4.2006 ATTACHMENT B. EMISSION FACTORS FOR TURBINES Section 14 — Miscellaneous Application Notes AIRS Point 044 Natural gas turbine A permit will be issued in non -attainment. PM10, PM2.5, VOC AP -42, Table 3.1-2a VOC = because the and HAPS were 0.0021 lb uncontrolled CO calculated from I 1023 btu emissions are greater than 5 TPY (permit threshold) AP -42: 554 MMscf I T 0.60 TPY PM = MMBtu 0.0066 lb scf 1023 btu I yr 554 MMscf 12000 lb I T = 1.87 TPY AP -42, Table 3.1-3 Acetaldehyde = MMBtu 10.00004 lb scf 11023 btu yr MMscf 2000 lb = 22.7 lb/yr emissions in = 0.0598 Acrolein (0.00064 Benzene (0.000015 Ethylbenzene (0.000032 Formaldehyde (0.00071 Toluene (0.00013 Xylenes (0.000064 Manufacturer data lb/mmbtu so that NOX = MMBtu lb/mmbtu) 4 3.6 Ib/mmbtu) 4 lb/mmbtu) lb/mmbtu) Ib/mmbtu) 4 73.7 lb/mmbtu) 4 36.3 emission factors they are consistent 16.94 T 1554 scf lb/yr 6.8 lb/yr 4 18.1 lb/yr 4 402.4 lb/yr lb/yr lb/yr was provided for with the rest of the 2000 lb yr NOX and CO in lb/hr. source's emission scf I I calculated calculations. year CO = I year 17.19 T 11 1 T 2000 lb 1023 btu scf 554 MMscf year Lb/mmbtu 0.0607 year T 11023 btu 1554 MMscf I Lb/mmbtu Page 11 AIRS Point 045 Natural gas turbine A permit will be issued in non -attainment. PM10, PM2.5, VOC AP -42, Table 3.1-2a VOC = because the uncontrolled CO and HAPS were calculated from 0.0021 lb 1023 btu emissions are greater AP -42: 554 MMscf than 5 TPY (permit I T threshold) = 0.60 TPY PM = MMBtu 0.0066 lb scf 1023 btu yr 554 MMscf I 2000 lb I T I = 1.87 TPY AP -42, Table 3.1-3 Acetaldehyde = MMBtu 0.00004 lb scf 1023 btu yr 554 MMscf 2000 lb = 22.7 lb/yr emissions in = 0.0598 Acrolein (0.00064 Benzene (0.000015 Ethylbenzene (0.000032 Formaldehyde (0.00071 Toluene (0.00013 Xylenes (0.000064 Manufacturer data lb/mmbtu so that NOX = MMBtu lb/mmbtu) 4 3.6 lb/mmbtu) - lb/mmbtu) lb/mmbtu) lb/mmbtu) 4 73.7 lb/mmbtu) 4 36.3 emission factors they are consistent 16.94 T scf lb/yr 6.8 lb/yr 4 18.1 lb/yr 4 402.4 lb/yr lb/yr lb/yr was provided for with the rest of the 2000 lb yr NOX and CO in lb/hr. source's emission scf I calculated calculations. year CO = year 17.19 T 1 T 2000 lb 1023 btu scf 554 MMscf year Lb/mmbtu = 0.0607 year 1 T 1023 btu 554 MMscf Lb/mmbtu AIRS Point 046 Hot Oil Heater A permit will be issued in non -attainment. AP -42, Table 1.4-3 Benzene = because the uncontrolled CO 0.0021 lb 315 MMscf emissions are greater than 5 TPY = 0.7 lb/yr (permit threshold) Formaldehyde (0.075 n-hexanes (1.8 lb/mmscf) Toluene (0.0034 MMscf yr lb/mmscf) 4 23.6 lb/yr 4 567 lb/yr lb/mmscf) 4 1.1 lb/yr Page 12 VIA EMAIL August 2, 2013 Ms. Stephanie Chaousy Colorado Department of Public Health and Environment Air Pollution Control Division - Oil & Gas Division 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 RE: Draft Permit Comments - Permit Number 12WE2024 Issuance 1 DCP Midstream, LP - Lucerne Natural Gas Processing Plant Lucerne 2 Expansion Project Weld County, Colorado Dear Ms. Chaousy: DCP Midstream LP (DCP) has reviewed the draft construction permit, 12WE2024, issued on July 18, 2013 for the Lucerne 2 Expansion Project at the existing Lucerne Natural Gas Processing Plant in Weld County. Comments were requested to be provided by August 2, 2013. This letter and attachments address DCP's comments on the draft permit. Please note that any requested revisions are indicated in red-strikethrough font, and any additions are indicated in blue -bolded font. Any revisions requiring explanation are indicated below the respective permit condition in italics and are highlighted. The red -lined permit is provided in Attachment A. The following attachments are provided with this submittal: > Attachment A - Draft permit review and DCP comments > Attachment B - Revised emission calculations, specifically including o Revised APCD Form 102 • Revised tank configuration - from 8 x 400 bbl tanks to 4 x 1,000 bbl tanks, condensate throughput remains the same Revised enclosed combustor emissions - due to increase in volume of gas vented from the revised tank configuration Revised fugitive component count - the initial fugitive component count provided in the June 2012 application has been updated per a more recent DCP application for a similar site to provide for additional conservatism in the permit limit > Attachment C - Revised APENs, specifically including: • Form APCD 204 - Tanks o Form APCD 203 - Fugitives • Attachment D - Revised TANKS4.09d output > Attachment E - Revised regulatory applicability for the condensate storage tanks to account for NSPS Subpart Kb t Ms. Stephanie Chaousy - Page 2 August 2, 2013 Please feel free to contact me at dstephensPdcpmidstream,com or (303) 605-1745 if you should have any questions. Sincerely, DCP MIDSTREAM, LP Dana Stephens Rockies Air Permitting Manager cc: Roshini Shankaran, Trinity Consultants Kim Ayotte, Trinity Consultants Enclosure Attachment A Red -Lined Draft Permit c .9 I ra v , F. ppt�rJ �.a CSr STATE OF COLORADO COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION TELEPHONE: (303) 692-3150 C•NSTUCTIO\! PER IT PERMIT NO: 12E2®24 Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Lucerne 2 Expansion Project at the Lucerne Gas Processing Plant, located in 31495 WCR 43, Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility Equipment ID AIRS Point Description TURB-1 044 One (1) natural gas fired combustion turbine (Solar Model Taurus 70 serial number: TBD), equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is design rated for a heat input of 66.12 MMBtu/hr. This combustion turbine is used to power a compressor. Emissions from this turbine are not controlled. TURB-2 045 One (1) natural gas fired combustion turbine (Solar Model Taurus 70, serial number: TBD), equipped with low NOx burners, site rated at 9,055 horsepower at 11,513 RPM. The turbine is design rated for a heat input of 66.12 MMBtu/hr. This combustion turbine is used to power a compressor. Emissions from this turbine are not controlled. HT -02 046 Hot oil heater (make, model, serial number: TBD), equipped with low NOx burners. The heater is design rated at a heat input of 50 MMBtu/hr. This heater is fueled by natural gas to supplement the waste heat recovery cystem and used unit (WHRU) provided from Points 044 and 045. Emissions from this heater are not controlled. AIRS ID: 123/0107 Page 1 of 41 NGEngine Version 2009-1 golora %.Depaft : ent of Peiblic Health and Environment Air Pollution Control Division Facility Equipment ID AIRS Point Description AU -02 047 One (1) methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf per day (make, model, serial number: This emissions is with two (2) or three TBD). unit equipped with total design {3) electric amine recirculation pumps a limited capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, • condenser, a flash tank, still vent and a natural gas fired amine regeneration reboiler (point 046). The amine flash stream is routed to a closed loop vapor recovery unit with a backup unit (1% annual downtime). equipped Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The acid gas stream from the amine still vent is routed to a regenerative thermal oxidizer Model 100, SN: submitted TBD) rated at 10,000 (Anguil, not scf/min. Destruction efficiency is a minimum of 96%. Please remove equipped with a backup unit' for the vapor recovery. unit (VRU) because although the facility will have two VRUs, it is expected that both VRUs can be operational at the same time during certain seasons, therefore the second VRU is not truly considered a backup unit. D-01 048 One (1) triethylene glycol (TEG) dehydrator unit with a design capacity of 230 MMscf/day (make, model, serial number: TBD). This emissions unit is equipped with two (2) electric glycol pumps with a limited total combined capacity of 40 gallons per minute. This system includes a condenser, reboiler, still vent, and a flash tank. The flash gas is routed loop with a backup to a closed vapor recovery unit equipped (1% annual downtime). Emissions during the downtime will be routed to a flare with 95% destruction efficiency. The still vent is routed to a condenser and then to an enclosed combustor with a minimum destruction efficiency of 95%. TANKS 050 Eight (8) Four (4) stabilized atmospheric condensate storage tanks. Each tank has a capacity of 408 1000 bbl. Emissions are routed to an enclosed combustor with a minimum destruction efficiency of 95% . DCP requests a` change in tank configuration from 8x400 bbl tanks to 4x1000 bbl tanks. Please note that there will be no increase in condensate throughput LOAD 051 Condensate truck loading. Emissions from the loadout will be controlled by an enclosed combustor with a minimum destruction efficiency of 95%. FUG 052 Fugitive emission leaks from a natural gas processing plant associated with the expansion project. Points 044 and 045 may be replaced with another turbine in accordance with the temporary turbine replacement provision or with another Solar Model Taurus 70 turbine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. AIRS ID: 123/0107 Page 2of4.1 lr zt�yC�Olorado Deptrtnoent of Public Health and Environment rirg Air Pollution Control Division THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S.. (25-7-101 et sect), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: YOU MUST notify the APCD no later than fifteen days after commencement of the permitted operation or activity bar sytina a Notice of Startup INOS) form to the AJ CD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the APCD of startup of the permitted source is a violation of AQCC Regulation No. 3, Part B, Section IIi.G.1 and can result in the revocation of the permit. 2 Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, III.G.2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B, III.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self -certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, Ill.E.) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self -certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section ll.A.4) Monthly' Limits: AIRS I Facility Equipment ID AIRS Point Pounds per Month Tons per Month Emission Type NOX SO2 VOC CO PM2.5 H2S CO2e2. TURB-1 044 2,552 167 104 2,991 3245 -- 2,872 Point TURB-2 045 2,552 167 104 2,991 3245 -- 2,872 Fage 13,109 Point 3 of 41 Point D. 123/0107 AU -02 047 85 5,317 1,189 462 -- 118 A7" rt F'1rde '" `a9 'olor dlq;Departr ent Public Health and Environment Air Pollution Control Division :r, t.%!;reltiN ,. ar E ,� D-01 048 155 — 3,262 131 -- -- 444 Point TANKS 050 126 -- 322 14 -- -- Point 405 3 29 LOAD 051 15 -- 392 14 -- 3 Point FUG 052 -- -- 2,232 -- -- — 13 Fugitive 2,935 17 1: Monthly limits are based on a 31 -day month. Facility -wide emissions of each individual hazardous air pollutant shall be less than 1,359 lb/month. Facility wide emissions of total hazardous air pollutants shall be less than 3,398768 lb/month. Quarterly2 Limits: Facility Equipment !D AIRS Point Pounds per Quarter' Tons per Month Emission Type NOx SO2 VOC CO PM2.5 H2S CO2e3 HT -02 046 2970 51 459 6,741 612 -- 4,806 Point 2: Quarterly Emits will be established beginning with the calendar month of permit ssuance. ror the first twelve (12) months of operation, monthly emissions from the three calendar months of a quarter shall be summed to demonstrate compliance with the quarterly emission for AIRS Point 046 as well as the annual limitations. After the first twelve (12) months of operation, the operator shall calculate monthly emissions to demonstrate compliance with the annual limits and to maintain the 12 -month rolling total. 3: CO2e is carbon dioxide equivalent in tons per year. CO2e is the total sum of the mass of each greenhouse gas emission multiplied by global warming potential for each greenhouse gas. The greenhouse gas emissions in this inventory include CO2, CH4 and N2O. Annual Limits: Facility Equipment AIRS Point Tons per Year Emission Type NOX SO2 VOC CO PM2s H2S CO2e TURB-1 044 15.0 1.0 0.6 17.6 1.9 -- 33,814 Point TURB-2 045 15.0 1.0 0.6 17.6 1.9 -- 33,814 Point HT -02 046 5.8 0.1 0.9 13.2 1.2 -- 18,853 Point AU -02 047 0.5 31.3 7.0 2.7 - 0.7 154,34951 Point D-01 048 0.9 -- 19.2 0.8 -- -- 5,228 Point TANKS 050 0.1 -- 4--9- 2.4 0.1 -- -- 211 275 Point AIRS ID: 123/0107 Page 4of41 Q7,. 1 S?iAh�i s atsi� Goloradb4Depart . eht of Public Health and Environment Air Pollution Control Division LOAD 051 0.1 -- 2.3 0.1 -- -- -- Point FUG 052 -- -- a-3-1- 17.3 - -- -- 1-52 200 Fugitive ee "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. Facility -wide emissions of each individual hazardous air pollutant shall be less than 8.0 tpy. Facility -wide emissions of total hazardous air pollutants shall be less than 20.0 22.1 tpy. During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the emission limits in this permit shall be determined by recording the facility's annual criteria pollutant emissions, (including all HAPs above the de-minimis reporting level) from each emission unit, on a rolling (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. Please revise the emission limits in the tables above dueto rounding convention discrepancies. Please also update the tank emissions due to the change in configuration. Additionally, please update the fugitive emissions to' include additional components and associated emissions. 8. Points 044, 045, 046 and 047: The owner or operator shall calculate, on a monthly basis, the amount of CO2emitted from fuel and gas waste combustion using equation C - 2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in Table C-1, measured actual heat input (HHV), and measured actual monthly natural gas fuel flow volume. 9. Points 044, 045, 046 and 047: The owner or operator shall calculate CH4 and N2O emissions from fuel and waste gas acid gas stream from amine still vent combustion on a monthly basis using equation C -9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly natural gas fuel flow volume. A complete record of the methods used, the measurements made, and the calculations performed to quantify monthly natural ga. fuel flow volume shall be kept. 10. Points 044, 045, 046 and 047: The owner or operator shall calculate the CO2e emissions based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 11. Point 047: The owner or operator shall calculate CO2 emissions from acid gas sweetening, on a monthly basis, using equation W-3 consistent with 40 CFR Part 98, Subpart W [98.233(d)(2)] along with the most recent measured waste gas acid gas stream from amine still vent sampling composition and monthly measured waste gas acid gas stream from amine still vent flow volume. AIRS ID: 123/0107 Page 5 of 41 Q a ra Golora QkDepa�rt ent or Public Health and Environment 4F-14, �� Air Pollution Control Division a,S4t 12. Point 047: Total CO2e emissions from the RTO shall be based on the sum of GHG emissions from waste gay acid gas stream from amine still vent combustion, calculated as per Conditions 8, 9 and 10 plus CO2 emissions from the amine unit acid gas sweetening as calculated per Condition 11. The sum total of CO2e emissions generated from waste gas acid gas stream' from amine still vent combustion generated from the amine unit acid gas sweetening shall be compared to the CO2e limits listed in this section above to demonstrate compliance. 13. Point 047: The owner or operator shall calculate uncontrolled VOC and H2S emissions on a monthly basis using the most recent measured waste gas acid gas stream from amine still vent sample composition and monthly measured waste gas acid gas stream from amine still vent flow volume. A control efficiency of 99 96% for CH4, based on maintaining the minimum temperature requirements specified in Condition 25.x), shall be applied to the uncontrolled emissions. DCP requests the destruction rate efficiency (DRE) for methane to be revised to 96% per the original application. There are several reasons for this: 1. The purpose of the regenerative thermal oxidizer (RTO) is to destroy VOC in the acid gas stream. The oxidationof methane is supplementary. Most of the CO2 that passes through the RTO will be released unchanged regardless of the DRE of the RTO. There is no test data available by the manufacturer that can guarantee methane DRE since all performance tests have been targeted at VOC DRE. Therefore, a guarantee of 99% isnot available. Due to lack of test data and the known fact that the manufacturer guarantee of 99% for VOCs is also not practically achieved, DCP requests that the DRE for VOC and CH4 be set equal at 96%. 3. DCP provided a revised Best Available Control Technology. (BACT) analysis to CDPHE on March 15, 2013' This analysis proposed a BACT limit of 3,677 lb CO2e/MMscffor the RTO controlling the amine unit, based on a DRE. of 96% for methane. DCP performed a calculation to determine what the BACT limit would be if the DRE for methane was increased from 96% to 99%. The BACT limit fora DRE, of 99% for methane would be 3,676 lb/MMscf- This is a difference of only 1 lb.CO2e/MMscf Additionally, the increase in the DRE from 96% to 99% decreases CO2e emissions by 0.02% on an annual basis DCP believes this, minor decrease in CO2e emissions does not warrant the 3% increase in the DRE. 2. As the RTO is not a primary control device for CH4 and there is no guarantee that the RTOs control methane •specifically with a' DRE of 99%, DCP would like to maintain the DRE of 96% for both VOCs and methane. 14. Point 047: Emissions from the amine flash tank are routed to a closed loop vapor recovery system back to the plant inlet equipped with a primary and backup vapor recovery unit (VRU) (1% downtime). During the VRU downtime, emissions generated will be routed to a flare. Emissions from the natural gas/amine contactor a 4 still vent shall be collected and controlled by a regenerative thermal oxidizer in order to reduce the emissions of volatile organic compounds, H2S and hazardous air pollutants to the level listed in this section, above. During the VRU downtime, emiseions.generated will be routed to a flare. Operating parameters of the regenerative thermal oxidizer are identified in the operation and maintenance plan for this unit. (Reference: Regulation No.3, Part B, Section III.E.) 15. Point 048: The owner or operator shall calculate CO2 and CH4 emissions, on a monthly basis, using GRI-GLYCaIc consistent with 40 CFR Part 98, Subpart W [98.233(e)(1)] along with the most recent results from the extended wet gas analysis as required by this permit. 40 CFR Part 98, Subpart W [98.233(e)(1)]. 16. Points 048, 050 and 051: The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly AIRS ID: 123/0107 Page 6 of 41 T 0 Department of Public Health and Environment 01 Air Pollution Control Division basis, using equations and_procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The minimum combustion efficiency of this unit is assumed as 95%. 17. Point 048: Compliance with the VOC emission limits in this permit shall be demonstrated by running the GRI GiyCaic model version 4.0 or higher on a monthly basis using the most recent wet gas analysis and recorded operational values (including gas throughput, lean glycol recirculation rate, and other operational values specified in the O&M Plan). Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into GRI GlyCalc and be provided to the Division upon request. 18. Points 050 and 051: Emissions from the condensate tanks and loadout shall be collected and controlled by an enclosed combustor in order to reduce the emissions of volatile organic compounds to the level listed in thissection, above. Operating parameters of the enclosed combustor are identified in the BACT requirements in Condition 25. 19. Point 051: All loading operations shall occur in vapor balance service, such that all tanker truck vapors are routed to and controlled by the combustor. The vapor return hose shall be connected at all times during loading operations. (Reference: Regulation No. 3, Part B, Section III.E.) 20. Point 052: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. FR•CES LIQITATJONS AND RECORDS 21. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Equipment ID AIRS Point Process Parameter Annual Limit Quarteriy4 Limits HT -02 046 Natural Gas Combusted 315 MMscf/yr 80.25 MMscf/quarter 4: Quarterly limits will be established beginning with the calendar month of permit issuance. Facility Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limits (31 days) TURB-1 044 Natural Gas Combusted 566 MMscf/yr 48.10 scf /month MMcf m AIRS ID: 123/0107 Page 7 of 41 14 •-olora Depqrtment Public Health and Environment 4 4-twa4 ,r `r�';"'s Air Pollution Control Division `a -ate^ TURB-2 045. Natural Gas Combusted 566 MMscf/yr 48.10 MMscf/month AU -02 047 Natural Gas Throughput 83,950 MMscf/yr 7,130 MMscf/month D-01 048 Natural Gas Throughput 83,950 MMscf/ r y 7,130 MMscf/month TANKS 050 Condensate Throughput 456,250 bbl/yr 38,750 bbVmonth LOAD 051 Condensate Loading 456,250 bbl/yr 38,750 bbl/month During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) quarterly months of operation, compliance with only the yearly limitation shall be required. Compliance with the yearly process limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate, monitor, and record monthly natural gas combusted, processed, and condensate throughput and keep a compliance record on site or at a local field office with site responsibility, for Division review. 22. Point 047: This unit shall be limited to a maximum lean amine recirculation pump rate of 945 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, 23. Point 048: This source shall be limited to a maximum lean glycol recirculation pump rate as calculated per 40 CFR, Part 63, Subpart HH, §63.764 (d)(2)(i). If the owner or operator requests an alternate circulation rate per §63.764(d)(2)(ii) or an exemption per §63.764(e), then the maximum recirculation rateshall not exceed 40 gallons per minute. The owner or operator shall maintain monthly records of the actual lean glycol recirculation rate and make them available to the Division for inspection upon request. 24. Points 047 and 048: The owner or operator shall monitor and record VRU downtime for each emission point. VRU downtime shall be defined as times when the flash gas from the amine and the dehydrator are routed to the flare rather than the VRU. The total hours of downtime and volume of gas processed during VRU downtime shall be recorded on a monthly basis. The operator shall demonstrate VRU downtime for each emission point does not exceed 1% of total operational hours and total volume of gas processed on a rolling 12 month total basis. BEST AVAILABLE CONTROL TECHNOLOGY (BACT1 REQUIREMENTS 25. The equipment and activities at this facility are subject to the requirements of the Prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Greenhouse Gases (GHG). BACT has been determined to be as follows: a. For purposes of BACT, total CO2e emissions from the emission units covered under this permit shall not exceed the annual emission limits contained in condition 7, based on a rolling twelve month total. Turbines AIRS ID: 123/0107 Page 8 of 41 �s t bolorado Department of�Public Health and Environment 4 ,< ttil j Fz F.. V r, Air Pollution Control Division b. Points 044 and 045: The turbines shall be equipped with waste heat recovery units (WHRU) to increase the efficient use of waste heat for process heating. c. Points 044 and 045: Fuel for the turbines shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the turbines shall be sampled initially and at least once per every six months as required in Conditions 53 and 66 to determine the fuel dross calorific value (GCV) [high heat value (HHV)]. d. Points 044 and 045: The owner or operator shall install and maintain an operational non resettable elapsed continuous fuel flow 44:1-et-er monitor for each turbine at the inlet. The fuel flow meters shall be calibrated at a minimum frequency of at least once every twelve months and. The volume of the fuel combusted in each natural gas fired combustion emission unit shall be used to measured and recorded ucing an operational non resettable elapsed flow meter at the inlet the volume of fuel. Please make the "continuous fuel flow monitor" wording consistent throughout the permit per condition 26. b: e. Points 014 and 045: The combustion turbines shall be equipped with a control package that monitors the air/fuel ratio in the primary combustion 7 one. Please delete condition 25.e since air/fuel ratio controllers are not available for Solar turbines. f. Points 044 and 045: The owner or operator shall install temperature monitoring equipment to measure temperature in the exhaust gas and shall maintain records of the stack exhaust tempera₹ure. Points 044 and 045: The owner or operator shall maintain records of the fuel temperature, ambient temperature and stack exhaust temperature on a daily basis. Please delete Condition 25.g. sincethe fuel temperature and ambient temperature do not affect the operation of the turbine. h. Points 044 and 045: Tune-ups and maintenance shall be required annually for the life of the turbines. The owner or operator shall maintain records of the tune-ups and maintenance activities and implement the manufacturer's recommended comprehensive inspection and maintenance program to comply with this condition. Points 044 and 045: The combustion turbines and WHRU shall meet a BACT limit of 40% minimum thermal efficiency, which equates to 0.9046 1.0657 lbs of CO2e/hp-hr, on a 12 -month rolling average basis. DCP requests that the BACT limit for CO2e from the turbines be increased to 1.0657 lb/hp-hr. Since the limit is a short-term hourly limit based on the maximum hp capacity of the turbine, any decrease in capacity of the turbine (equating to lower hp) will result in the hourly actual calculation to exceed the permit limit Although: this limit is an average limit over a 12 - month period, the work output of the turbine can :never exceed the maximum rated hp of 9,055 hp, but the work output can be lower than the maximum rated hp at certain periods of time. An average limit can only be achieved if the limit is based on the average work output of the turbine, but for emissions' purposes the turbine is permitted at the maximum output Therefore, DCP is requesting a 20% safety factor to be included in the short-term average limit to account for variability in operation of the turbine Note: that even with an increase in the average limit, DCP. will maintain compliance with Condition 7. AIRS ID: 123/0107 Page 9 of 41 rg rnent of Public Health and Environment Air Pollution Control Division Points 004 and 045: Compliance with the BACT limit will be based on a monitoring computer system installed that will automatically calculate efficiency for each hour of operation using monitoring firing rate, turbine output in hp -hr, and the hp output equivalent from the WHRU. Heater k. Point 046: On or after the date of initial startup, the owner or operator shall not discharge or cause the discharge of emissions in excess of'M9.16 561.45 lb CO2e/MMscf natural gas input to the facility on a 365 -day rolling average. To show compliance with the BACT limit, the owner or operator shall calculate actual emissions based on the measured input mass rate of CO2 from the natural gas HHV analysis required in Conditions 8 and 66 (note that mass emission rate must be converted from metric tons to pounds) and divide by the measured daily natural gas output from input to the Lucerne 2 facility from the Lucerne 2 expansion plant (MMscfd). DCP requests that the BACT limit for. CO2e from the hot, oil heater be increased to 561.45 lb/MMscf. Since the limit is based on the maximum gas capacity of the plant, any decrease in gas throughput will result in the actual per MMscf emission calculation to exceed the permit limit. Although this limit isan average limit over a 12 -month period, the gas throughput through the facility can never exceed the maximum permit limit of 230 MMscfd, but the gas processed can be lower than the maximum permit limit since DCP has built in a buffer to allow for a worst -case maximum gas throughput rate. An average limit can only be achieved if the limit is based on the average capacity of the facility, but emissions are permitted at the maximum throughput to be conservative. Therefore, DCP is requesting a 20% safety factor to be included in the average limit to account for variability in operation of the facility and the heater. . Note that even withan increase in the average limit, DCP will maintain compliance with Condition 7. Additionally, please replace the output -based limit to input -based limit since DCP has requested a limit of 230 MMscfd based on gas input to the facility rather than gas output from the facility. Point 046: Fuel for the heater shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100, dscf). The fuel used in the heater shall be sampled initially and at least once per every six months as required in Conditions 53 and 66 to determine the fuel gross calorific value (GCV) [high heat value (HHV)]. m. Point 046: The owner or operator shall install and maintain an operational non resettable elapsed continuous fuel flow meter monitor for the heater. The flow meter shall be calibrated at a minimum frequency of at least once per every twelve months and shall measure and record the volume of the fuel combusted in this natural gas -fired combustion emission unit. n. Point 046: The volume of the fuel combusted in this natural gas fired combustion emission unit shall be measured and recorded using an operational non resettable elapsed flow meter at the inlet. Please delete Condiaion25n. since this.has been merged with; Condition o. Point 046: The heater shall be equipped with low-NOx staged/quenching (flue gas recirculating) burners with burner management systems that include intelligent flame ignition and flame intensity controls or of like -kind approved AIRS ID: 123/0107 Page 10 of 41 q. 1 I9 3 by the Division . lorad'o+Department o1 -Public Health and Environment amaa Et Air Pollution Control Division Point 046: The heater shall be tuned for thermal efficiency at a minimum frequency of at least once per every twelve months. Point 046: The owner or operator shall perform cleaning of the burner tips, at a minimum of, once per every twelve months. r. Point 046: The owner or operator shall install, operate, and maintain an automated air/fuel control system which is part of the burner management system. s. Point 046: The owner or operator shall calibrate and perform preventative maintenance on the air/fuel control analyzer at least once per every three months, at a minimum. per manufacturer recommendations. t. Point 046: Tune-ups and maintenance shall be required annually for the life of the heater. The owner or operator shall maintain records of the tune-ups and maintenance activities to comply with this condition. Amine unit and regenerative thermal oxidizer u. Point 047: The amine flash tank stream shall be routed to a closed loop vapor recovery unit and back to the plant inlet at all times, during amine unit operation. A maximum 1% downtime (based on total gas treated on a rolling 12 month total) is allowable. During VRU downtime flash tank emissions shall be routed to the flare. A minimum 99% control of the flash tank emissions is required. v. Point 047: The still vent from the amine unit shall be collected and routed to a regenerative thermal oxidizer for combustion. The regenerative thermal oxidizer shall have a minimum destruction and removal efficiency of methane (CH4) of 9.9 96%. w. Point 047: The thermal oxidizer shall have an initial stack test and on -going compliance testing to verify destruction and removal efficiency of at least 99% for CH'l. Please delete Condition 25.w. for compliance purposes since this has thesame requirement as Condition 6Z X. Point 047: The combustion temperature of the regenerative thermal oxidizer used to control emissions from the amine unit still vent shall be greater than 1550 'F, or the temperature established during the most recent stack test of the equipment that was approved by the Division. The approved minimum operating temperature shall be maintained at all times that any amine unit emissions are routed to the regenerative thermal oxidizer in order to meet the emission limits in this permit. y. Point 047: The regenerative thermal oxidizers' combustion temperature shall be continuously monitored and recorded when amine unit waste gac still vent is directed to the oxidizer. The temperature measurement devices shall reduce the temperature readings to an averaging period of 6 minutes 1 hour or less and record it at that frequency. z. Point 047: The owner or operator shall install and maintain a temperature AIRS ID: 123/0107 Page 11 of 41 ColoradZIDepartrnent (if Public Health and Environment e �- �� Air Pollution Control Division y� G +3F]- Stk. C -1i7 recording device with an accuracy of the greater of ±0.75 percent of the temperature being measured expressed in degrees Celsius or ±2.5°C (+/- 36.5°F). aa. Point 047: Waste gas from the still vent and flash gas streams of the amine unit will be sampled and analyzed initially and at least once every three months for composition as specified in Conditions 56 and 68. The sample data will be used to calculate GHG omissions as specified in Condition 11. Please delete Condition 25.aa. for compliance purposes since this has the same requirement as Conditions 56 and 68. bb. Point 047: The volumetric flow rate of the waste gas acid gas stream from amine still vent combusted shall be measured and recorded using an operational non resettable elapsed continuous fuel flow meter monitor at the inlet to the regenerative thermal oxidizer. The owner or operator shall operate and calibrate the flow meter in accordance with §98.3(i). cc. Point 047: For burner combustion fuel, the volume of natural gas fuel usage (scf) shall be measured and recorded using an operational non resettabic elapsed continuous fuel flow m ter monitor at the regenerative thermal oxidizer. dd. Point 047: The flash tank stream to the cncloced flare during downtime operations shall be measured and recorded using an operational non resettable elapsed continuous fuel flow meter monitor at the thermal oxidizer flare. DCP would like to note that, the flash tank stream from the amine unit is directed to the emergency flare during downtime operations ee. Point 047: Periodic maintenance shall be completed to maintain the efficiency of the regenerative thermal oxidizer and shall be performed at a minimum of once per every twelve months or more often as recommended by the manufacturer specifications. ff. Point 047: An oxygen analyzer shall continuously monitor and record oxygen concentration when waste gas acid gas stream from amine still vent is directed to the regenerative thermal oxidizer. It shall reduce the oxygen readings to an averaging period of 6 minutes or less and record it at that frequency, except during periods of downtime as defined in 40 CFR §60.7(d)(1). gg. Point 047: The oxygen analyzer shall be maintained per the manufacturer's recommendations. quality assured at least encc ocry six months using cylinder gas audits (CGAs) in accordance with 1@ CFR-Part 60, Appendix F, Procedure 1, § 5.1.2, with the following exception: a relative accuracy test audit is not required once every four quarters (i.e., two successive semiannual CGAs may be conducted). The CGAs must be performed at least thirty (30) days apart. Per discussion with the manufacturer, DCP has determined that by maintaining the oxygen, analyzer according to manufacturer's recommendations, the quality assurance aspect of the, oxygen analyzer will be taken care of Dehydrator and enclosed combustor hh. Point 048: The dehydrator flash stream shall be routed to a closed loop vapor AIRS ID: 123/0107 Page 12 of 41 .1 :olorad5;,,Departrmtent of Public Health and Environment Air Pollution Control Division Lxtv, recovery unit at all times, during dehydrator operation. A maximum 1% downtime (based on total gas treated on a rolling 12 month total) is allowable. During VRU downtime flash tank emissions shall be routed to the flare. A minimum 99% control of the flash tank emissions is required. ii. Point 048: The still vent from the dehydration unit shall be collected and routed through a condenser then controlled by an enclosed combustor. The enclosed combustor shall have a minimum removal and destruction efficiency of methane (CH4) of 95%. Point 048: The condenser outlet temperature shall be recorded as per the frequency required in the approved O&M Plan. This information shall be maintained in a log on site and made available to the Division for inspection upon request. The condenser outlet temperature, shall not exceed 145 °F on a monthly average basis. kk. Point 048: The enclosed combustor shall be operated with a pilot flame present at all times. The presence of a flame in the enclosed combustor shall. be continuously monitored with thermocouple. The ignition system shall send a remote alarm during pilot light outages and be capable of automatically relighting the pilot. Manual ignition of the pilot shall also be possible. If. Point 048: The enclosed combustor shall be operated with zero visible emissions. An EPA Method 22 shall be conducted monthly to monitor compliance with this condition. Please revise the Method 22 opacity test requirement frequency to monthly rather than daily to be consistent with 40 CFR 60.5415(e)(2)(vii)(c). mm. Point 048: The enclosed combustor shall be designed and operated in accordance with 10 CFR 60.18 including specifications of mieimum heating value of the waste gas, maximum tip velocity, and pilot flame monitoring. An infrared monitor is considered equivalent to a thermocouple for flame monitoring, purposes. Please delete condition25.mm. since the enclosed combustor at the facility does not meet the definition of open flare per 40 CFR 60.18. This is consistent with the EPA determination, specifically per Applicability Determination Index, Control Number 0000068 07/07/2000 EPA', says "In a determination that is posted as Control Numbers 0000019 and M000002 on EPA's' Applicability Determination Index (ADI); EPA Region 6 determined that an enclosed: flare is not the type of flare that is regulated by the, open -flame flare specifications at 40. CFR 60.18." Accordingly, DCP asks that this condition be deleted: Fugitives nn. Point 052: The owner or operator shall implement the leak detection and repair (LDAR) requirements in New Source Performance Standards of Regulation No. 6, Part A, Subpart OOOO for fugitive emissions of methane. 26. The owner or operator shall maintain the following records for a period of 5 years: a. Operating hours for all emission sources. b. The volume natural gas fuel usage for all combustion sources. This shall include data obtained from continuous fuel flow monitors as well as a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage from unit not equipped with continuous fuel flow monitors. AIRS ID: 123/0107 Page 13 of 41 A Colorado Dep ttrt;ent (Public Health and Environment 3 k AL -4k Air Pollution Control Division n'44.101)- '44. 1 ost ac `c3'i'�z b. $fu3 S#.C'.'-•-y isg& c. Annual fuel gas sampling results, quarterly waste go,'; acid gas stream from amine still vent sampling. d. Daily natural gas processing output input rate (MMscfd) for the Lucerne 2 expansion plant. e Leak detection and repair (LDAR) program monitoring results, as well as the repair and maintenance records. f. Records, data, measurements, reports, and documents related to the operation of the facility, including, but not limited to, the following: all records or reports pertaining to significant maintenance performed on any system or device at the facility; the occurrence and duration of any startup, shutdown, or malfunction, annual tuning of heaters; all records relating to performance tests and monitoring of combustion equipment; calibrations, checks, duration of any periods during which a monitoring device is inoperative, and corresponding emission measurements; and all other information required by this permit recorded in a permanent form suitable for inspection. g. All records required by this Permit shall be retained for not less than 5 years following the date of such measurements, maintenance, and reports. STATE AND,EDERAL REGULATORY REQUIREMENTS 27. The requirements of Colorado Regulation No. 3, Part D shall apply at such time that any modification becomes a major modification solely by virtue of a relaxation in any enforceable limitation that was established after August 7, 1980, on the capacity of the source or modification to otherwise emit a pollutant such as a restriction on hours of operation (Colorado Regulation No. 3, Part D, Section V.A.7.B). With respect to this Condition, Part D requirements may apply to future modifications if emission limits for the following emission units are modified to equal or exceed the following threshold levels. Increases in permit limits for any of these emissions units will require evaluation of the original project net emissions increase to ensure the significant modification thresholds are not exceeded: Facility Equipment ID AIRS Point Equipment Description p Pollutant Emissions — tons per year Threshold Current Limit TURB-1 044 Combustion Turbine NOx VOC H2S PM2.5 40 40 10 10 37.4-7 32.4 9 0.7 5.0 TURB-2 045 HT -02 046 Hot Oil Heater AU -02 047 Amine Unit D-01 048 TEG Dehy TANKS 050 Condensate tanks LOAD 051 Condensate load out FUG 052 Fugitives AIRS ID: 123/0107 Page 14 of 41 Ai �Y ply �`�~ :.� Colorado-.Dep rtment a ; Public Health and Environment Hc / Air Pollution Control Division c:��,- ' Es k- E 28. The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable). 29. Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. (Reference: Regulation No. 1, Section Il.A.1. & 4.) 30. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 31. Points 044 and 045: The combustion turbines are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart KKKK, Standards of Performance for Stationary Combustion Turbines including, but not limited to, the following: §60.4320 — Nitrogen Oxide Emissions Limits o (a) NOX emissions shall not exceed 15 ppm at 15% O2011.2 lb/MW-hr; ® §60.4330 — Sulfur Dioxide Emissions Limits o (a)(1) SO2 emissions shall not exceed 0.9 Ib/MW-hr gross output; or o (a)(2) Operator shall not burn any fuel that contains total potential sulfur emissions in excess of 0.060 lb SO2/MMBtu heat input. • §60.4333 -- General Requirements o (a) Operator must operate and maintain your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown and malfunction. 9 §60.4340 — NO„ Monitoring o (a) Operator shall perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance with NOX emissions limits. §60.4365 (or §§60.4360 and 60.4370) - SO2 Monitoring o The operator shall comply with §60.4365 or with both §§60.4360 and 60.4370 to demonstrate compliance with SO2 emissions limits. ® §60.4375 -- Reporting o (b) For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test. • §§60.4400 and 60.4415 — Performance Tests o Annual tests must be conducted in accordance with §60.4400(a) and (b). o . Unless operator chooses to comply with §60.4365 for exemption of monitoring the total sulfur content of the fuel, then initial and subsequent performance tests for sulfur shall be conducted according to §60.4415. 32. Points 044, 045 and 046: These units are subject to the Particulate Matter and Sulfur AIRS ID: 123/0107 Page 15 of 41 a !`£ ''-'+ ? "-='� irr- 1 t; ficloraarb Department f Public Health and Environment ef. -�� rh' Air Pollution Control Division %s , 5.2z cakes Dioxide Emission Regulations of Regulation 1 including, but not limited to, the following: a. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section III.A.1): (i) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)"a.26 Where: PE = Particulate Emission'in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. b. Emissions of sulfur dioxide shall not emit sulfur dioxide in excess of the following combustion turbine limitations. (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates). (Regulation 1, Section VI.B) (i) Points 044 and 045: Combustion Turbines with a heat input of less than 250 Million BTU per hour: 0.8 pounds of sulfur dioxide per million BTU of heat input (Regulation 1, Section VI.B.4.c): (ii) Point 046: Limit emissions to not more than two (2) tons per day of sulfur dioxide (Regulation 1, Section VI.B.5.a) 33. Points 044, 045 and 046: These units are subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation 6, Part B, Section II): a. Standard for Particulate Matter — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-026 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. (ii) Greater than 20 percent opacity. b. Standard for Sulfur Dioxide — On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of: (i) Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. SO2/million Btu. Please combine Conditions 32 and 33 since. they_ both relate to PM and 502 emissions. ,This will make compliance tracking' easier for DCP AIRS ID: 123/0107 Page 16 of 41 c rj Colorado Department oflPu.iblic Health and Environment tt tF ,t 4 tA E -M` Air Pollution Control Division 34. Points 044, 045, 046 and 052: The source is subject to the requirements of Regulation No. 6, Part A, Subpart A, General Provisions, including, but not limited to, the following: a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11) b. No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) c. Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. e. Performance tests shall be conducted as required under §60.8. 35. Point 046: These sources are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small industrial -Commercial -Institutional Steam Generating Units including, but not • limited to, the following: a. The owner or operator of the facility shall record and maintain records of the amount of fuel combusted during each month (40 CFR Part 60.48c(g)). b. Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record (40 CFR Part 60.48c(i)). 36. Point 047: The amine unit addressed by AIRS ID 047 is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: o §60.5365 — Applicability and Designation of Affected Facilities o §60.5365(g)(3) Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). o §60.5423 — Record keeping and reporting Requirements o §60.5423(c) - To certify that a facility is exempt from the control requirements AIRS ID: 123/0107 Page 17 of 41 ent o Public Health and Environment 14'Air Pollution Control Division fr iirm of these standards, for each facility with a design capacity less that 2 LT/D of H2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2 S expressed as sulfur. 37. Point 048: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XII 38. Point 048: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 39. Point 048: This source is subject to the TEG dehydrator area source requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: • §63:760 -Applicability and designation of affected source o (f) The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (0(3) through (f)(6) of this section. (4) The owner or operator of an affected area source, located in an Urban -1 county, as defined in §63.761, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the provisions of this subpart immediately upon initial startup or January'3, 2007, whichever date is later. • §63.764 - General Standards o (d)(2) Each owner or operator of an area source not located in a UA plus offset and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2(i) through (iii) of this section. ® (i) Determine the optimum glycol circulation rate using the following equation: Lour=1.15*3.0 gal TEG *�F*(I IbH 0 24hr/day AIRS ID: 123/0107 Page 18 of 41 , s «blorgd`t =Departr E k 444 L: nt cf Public Health and Environment Air Pollution Control Division Where: LoPT = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) = Inlet water content (lb/MMSCF) O = Outlet water content (lb/MMSCF) 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/IbH2O) 1.15 = Adjustment factor included for a margin of safety. • (ii) Operate the TEG dehydration unit such that the actual glycol circulation rate does not exceed the optimum glycol circulation rate determined in accordance with paragraph (d)(2)(i) of this section. If the TEG dehydration unit is unable to meet the sales gas specification for moisture content using the glycol circulation rate determined in accordance with paragraph (d)(2)(i), the owner or operator must calculate an alternate circulation rate using GRI—GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). • (iii) Maintain a record of the determination specified in paragraph (d)(2)(ii) in accordance with the requirements in §63.774(f) and submit the Initial Notification in accordance with the requirements in §63.775(c)(7). If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph (d)(2)(i) or (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v). O §63.774 - Recordkeeping Requirements o (b) Except as specified in paragraphs (c), (d), and (f) of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1) through (11) of this section: • (1) The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports, and notifications) required by this subpart. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. AIRS ID: 123/0107 • (1) All applicable records shall be maintained in such a manner that they can be readily accessed. • (ii) The most recent 12 months of records shall be retained on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. • (iii) The remaining 4 years of records may be retained offsite. • (iv) Records may be maintained in hard copy or computer - readable form including, but not limited to, on paper, microfilm, Page 19 of 41 N'13 G; rfri olora? Department of Public Health and Environment is -rem , A. r' Air Pollution Control Division is `�tab, Katz computer, floppy disk, magnetic tape, or microfiche. o (f) The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. o §63.775 — Reporting Requirements o (c) Except as provided in paragraph (c)(8), each owner or operator of an area source subject to this subpart shall submit the information listed in paragraph (c)(1) of this section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). ■ (1) The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.9(a), you must also submit a copy of the initial notification to EPA's Office of Air Quality Planning and Standards. Send your notification via e-mail to CCG— ONG@EPA.GOV or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Coatings and Chemicals Group (E143-01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. ■ (7) The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. o (i) Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the names of the nearest urban cluster with 10,000 people or more and nearest urbanized area. o (ii) Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i). • (iii) If applicable, documentation of the alternate glycol. circulation rate calculated using GRI-GLYCaIcTM, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. • (iv) The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. • (v) Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. AIRS ID: 123/0107 Page 20 of 41 color do Department of Public Health and Environment Air Pollution Control Division p5 # 4A - o (f) Notification. of process change., Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance. Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: • (1) A brief description of the process change; ▪ (2) A description of any modification to standard procedures or quality assurance procedures • (3) Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and • (4) Information required by the Notification of Compliance Status Report under paragraph (d) of this section for changes involving the addition of processes or equipment. 40. Point 048: This unit is subject to the requirements in 40 CFR part 63 Subpart A "General Provisions", as adopted by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart HH § 63.764. These requirements include, but are not limited to the following: a. Prohibited activities and circumvention in § 63.4. b. Operation and maintenance requirements in § 63.6(e)(1). c. Notification requirements in § 63.9(j). d. Recordkeeping and reporting requirements in § 63.10(b), except as provided in § 63.774(b)(1). 41. Points 048 and 050: The combustion device used to control emissions of volatile organic compounds from these units to comply with Section XII.D shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from the outside of the enclosed combustion device, or by other means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XII. (Reference: Regulation No. 7, Section XII.C.1.d.) 42. Point 050: This source is subject to the recordkeeping, monitoring, reporting and emission control requirements of Regulation 7, Section XII. The operator shall comply with all applicable requirements of Section XII. 43. Points 048 and 050: The combustor covered by this permit is subject to Regulation No. 7, Section XVII.B General Provisions (State only enforceable). If a flare or other combustion device is -used to control emissions of volatile organic compounds to comply with Section XVII, it shall be enclosed, have no visible emissions during normal operations, and be designed so that an observer can, by means of visual observation from the outside of the enclosed flare or combustion device, or by other convenient means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of Section XVII. AIRS ID: 123/0107 Page 21 of 41 %Department o ?Public Health and Environment ft Air Pollution Control Division ] t E3 e 44. Point 050: The condensate storage tanks covered by this permit are subject to ' Regulation 7, Section XVII emission control requirements (State only enforceable). These requirements include, but are not limited to: Section XVII.C. - Emission reduction from condensate storage tanks at oil and gas exploration and production operations, natural gas compressor stations, natural gas drip stations and natural gas processing plants. XVII.C.1. Beginning May 1, 2008, owners or operators of all atmospheric condensate storage tanks with uncontrolled actual emissions of volatile organic compounds equal to or greater than 20 tons per year based on a rolling twelve-month total shall operate air pollution control equipment that has an average control efficiency of at least 95% for VOCs on such tanks. XVII.C.3. Monitoring: The owner or operator of any condensate storage tank that is required to control volatile organic compound emissions pursuant to this section XVII.C. shall visually inspect or monitor the Air Pollution Control Equipment to ensure that it is operating at least as often as condensate is loaded out from the tank, unless a more frequent inspection or monitoring schedule is followed. In addition, if a flare or other combustion device is used, the owner or operator shall visually inspect the device for visible emissions at least as often as condensate is loaded out from the tank. XVII.C.4. Recordkeeping: The owner or operator of each condensate storage tank shall maintain the following records for a period of five years: XVII.C.4.a. Monthly condensate production from the tank. XVII.C.4.b For any condensate storage tank required to be controlled pursuant to this section XVII.C., the date, time and duration of any period where the air pollution control equipment is not operating. The duration of a period of non -operation shall be from the time that the air pollution control equipment was last observed to be operating until the time the equipment recommences operation. XVII.C.4.c. For tanks where a flare or other combustion device is being used, the date and time of any instances where visible emissions are observed from the device. 45. Point 052: The compressors at this point facility that commenced construction, modification or reconstruction after August 23, 2011, are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: ® §60.5385(a) — Owner or operator must replace the reciprocating compressor rod packing according to either paragraph §60.5385(a)(1) or (2). o §60.5385(a)(1) - Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or October 15, 2012, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. o §60.5385(a)(2) - Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been AIRS ID: 123/0107 Page 22 of 41 ti]; az./ . G:olorad Department O Public Health and Environment Air Pollution Control Division _ irgy replaced. o . §60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(c). • §60.5415 -- Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(c). §60.5420 - Owner or operator must comply with the notification, reporting, and recordkeeping requirements as specified in §60.5420(a), §60.5420(b)(1), §60.5420(b)(4), and §60.5420(c)(3). Please delete reference to Point 052 from Condition 45 since that point specifically relates to fugitive: emissions 46. Point 052: The fugitive component emissions from this point that commenced construction, modification or reconstruction after August 23, 2011, are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: o §60.5365 Applicability: The group of all equipment, except' compressors, within a process unit which commenced construction, modification or reconstruction after August 23, 2011 is an affected facility per §60.5365(f). O §60.5400 Standards: The group of all equipment, except compressors, within a process unit must comply with the requirements of §60.5400 and §60.5401. ® §60.5410: Owner or operator must demonstrate initial compliance with the standards using the requirements in §60.5410(f). o § 60.5415: Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). • § 60.5421: Owner or operator must comply with the recordkeeping requirements of §60.5421(b). o § 60.5422: Owner or operator must comply with the reporting requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). 47. Point 052: This source is subject to Regulation No. 7, Section XI1.G.1 (State only enforceable). To comply with Regulation No. 7, Section XII.G.1, the source shall follow the leak detection and repair (LDAR) program as provided at 40 C.F.R. Part 60, Subpart OOOO in lieu of following 40 C,F.R. Part 60, Subpart KKK. 48. This source is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2.b. The following requirements were determined to be RACT for this source. Facility Equipment ID AIRS Point Pollutant RACT TURB-1. 044 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices TURB-2 045 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices AIRS ID: 123/0107 Page 23 of 41 oior dq Dep Public Health and Environment Air Pollution Control Division HT -02 046 NOx, VOC Natural gas as fuel, low NOx burners, good combustion practices. AU -02 047 VOC Flash Tank: VRU to inlet and downtime to flare Still Vent: Regenerative Thermal Oxidizer D-01 048 VOC Flash Tank: VRU to inlet and downtime to flare Still Vent: Condenser and enclosed combustor TANKS 050 VOC Enclosed combustor LOAD 051 VOC Submerged fill, enclosed combustor FUG O52 VOC LDAR 49. Points 047, 048, 050 and 051: Upon startup of the points covered by this permit, the applicant shall follow the operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.) 50. Point 047: The inlet gas temperature and inlet gas pressure to the amine contactor shall be measured and recorded weekly. COMPLIANCE TESTING AND SAMPLING Jnitial Testing Requirements 51. Points 044 and 045: The combustion turbines are subject to the initial testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 52. Point 044 and 045: A source initial compliance test shall be conducted on each of the combustion turbines to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Carbon Dioxide using EPA approved methods. This test may be conducted concurrently with the testing required by Condition 51. 53. Points 044, 045, and 046: The owner or operator shall complete the initial fuel sampling for gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the turbines and heaters as required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section !II.E.) 54. Point 046E A source initial compliance test shall be conducted on the heater to measure AIRS ID: 123/0107 Page 24 of 41 F5 i 9 . "3 f 3i, € I �' u� if'' w cp G:olo�Depairtment oflPublic Health and Environment � ,, ₹2y r iti il Air Pollution Control Division ..),_ clzw5,1 tL t.� v�9�8 P ...,t1,1114. 7.L the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section IIl.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Carbon Dioxide using EPA approved methods. Particulate matter (filterable and condensable) less than 2.5 microns in-. diameter using EPA approved methods. DCP requests to remove the PM25stack test since emissions of PM25 are minimal from the hot oil heater especially since: it purely: combusts natural gas. 55. Point 047: The operator shall complete the initial annual analysis of the inlet gas to the plant to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that this amine unit qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution : SO2 Emissions (§60.5365(g)(3)). 56. Point 047: The owner or operator shall complete the initial amino unit waste ga& acid gas stream from amine still vent extended gas analysis required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 57. Point 047: A source initial compliance test shall be conducted on emissions point 047 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specified in Condition 7 in this permit. The operator shall also demonstrate the regenerative thermal oxidizer achieves a minimum destruction and removal efficiency of 96% for VOC and 99% for CH4. The operator shall measure and record, using EPA approved methods, VOC and CH4 mass emission rates at the regenerative thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the regenerative thermal oxidizer (process models shall not be used to determine the flow rate or composition of the wasto goo acid gas stream from amine still vent sent to the regenerative thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, and sulfur content of sour gas entering the amine unit shall be monitored and recorded during this test. The operator shall also measure and record combustion zone temperature during the initial compliance test to c...tablich confirm the minimum combustion temperature in the O&M plan. This proposed language is consistent with a similar DCP facility (LaSalle) Permit:11WE1481 upon discussed with the CDPHE APCD.".Please reword accordingly. Additionally please remove the underline from the second sentence above. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to AIRS ID: 123/0107 Page 25 of 41 ooloradoor,Depa ent cltPuublic Health and Environment Air Pollution Control Division 04'4�t s i ... ar :a show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods Methane using EPA approved methods Carbon Dioxide using EPA approved methods. DCP requests removal of CO and NOx from the stack test requirement for the amine unit since emissions of NOx and CO are minimal from this source, and the emissions are purely generated as a result of the control device operation. 58. Point 048: The owner or operator shall complete the initial annual extended wet gas analysis testing required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 59. Points 048 and 050: The owner or operator shall demonstrate compliance with Condition 29 using EPA Method 22 to measure opacity from the enclosed combustor daily monthly. Per NSPS OOOO, the frequency shall be a total of 5 minutes during any 2 consecutive hours. Please revise the Method 22 opacity test requirement frequency to monthly rather than daily to be consistent with 40 CFR 60.5415(e)(2)(vii)(c) 60. Points 048, ,050 and 051: A source initial compliance test shall be conducted on emissions points 048, 050 and 051 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emission limits in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section IIl.G.3) Oxides of Nitrogen using EPA approved methods. Volatile Organic Compounds using EPA approved methods. Carbon Monoxide using EPA approved methods. Carbon Dioxide using EPA approved methods. DCP requests removal of CO. NOx, and CO2fromthe stack test:requirement for the enclosed. combustor since emissions of NOx, .CO, and CO2 are minimal from this source, and the emissions are purely generated as a result of the control device operation. 61. Point 052: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of liquids that are representative of methane (CH4), carbon dioxide (CO2), volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and AIRS ID: 123/0107 Page 26 of 41 �-Mippu i.--ay1 za FC tf `k ` C`olorado, Department o 'Public Health and Environment 1,"4. g Air Pollution Control Division liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas and liquids analyses and emission calculations to the Division as part of the self -certification process to ensure compliance with emissions limits. 62. . Point 052: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "light liquid service" and "gas service". The operator shall submit the results to the Division as part of the self - certification process to ensure compliance with emissions limits. Periodic Testing Requirements 63. Points 044 and 045: Replacements of these units completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 64. Points 044 and 045: The combustion turbines are subject to the periodic testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 65. Points 044 and 045: The operator shall conduct, at a minimum, quarterly portable analyzer monitoring of each turbine exhaust outlet emissions of nitrogen oxides (NOx) and carbon monoxide (CO) to monitor compliance with the emissions limits. Emissions of carbon dioxide (0O2) shall be measure from an infrared detector or calculated from the oxygen (O2) reading to monitor compliance with the emissions limit. Results of all tests conducted shall be kept on site and made available to the Division upon request. 66. Points 044, 045, and 046: The fuel gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the turbines and heaters shall be determined, at a minimum, once per every six months with consecutive samples taken at least 4 months apart by the procedures contained in 40 CFR Subpart C, Part 98.34(a)(6) and records shall be maintained of the semiannual fuel GCV for a period of five years. Upon request, the owner or operator shall provide a sample and/or analysis of the fuel that is fired in the units. If sampling is performed more often, the results of all valid fuel analyses shall be used in the GHG emission calculations. 67. Point 047: The operator shall measure the emission rate(s) for the pollutants listed below at least once every 12 months in order to demonstrate compliance with the emissions limits contained in this permit. Periodic testing shall be conducted at a minimum of at least one hundred and eighty (180) days apart. The operator shall also demonstrate the regenerative thermal oxidizer achieves a minimum destruction and removal efficiency of 96% for VOC and 99% for CH4. The operator shall measure and record, using EPA approved methods, VOC and CH4 mass emission rates at the regenerative thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the regenerative thermal oxidizer (process models shall not be used to determine the flow rate or composition of the waste gar.: acid gas stream from amine still vent sent to the regenerative thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine circulation rate, MDEA concentration, sulfur content of sour gas entering the amine unit and combustion zone temperature shall be monitored and recorded during this test. Please remove the underline from the third sentence above, The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for AIRS ID: 123/0107 Page 27 of 41 Depatrneti nt ojPublic Health and Environment Air Pollution Control Division review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section III.G.3) Sulfur Dioxide using EPA approved methods Oxides of Nitrogen using EPA approved methods Volatile Organic Compounds using EPA approved methods Carbon Monoxide using EPA approved methods PM (filterable and condensable) using EPA approved methods. Methane using EPA approved methods Carbon Dioxide using EPA approved methods. Please remove PMzs stack test requirement for this source especially since the source does not generate any PM2,s emissions. 68. Point 047: Amino -unit waste gas Acid gas stream from amine still vent will be sampled and analyzed from the amine unit including an extended gas analysis at least once every three rnontho annually for composition in accordance with 40 CFR 98.233(d)(6) and 98.234(b). The sample shall be analyzed for CO2, CH4, VOC, Benzene, Toluene, Ethylbenzene, Xylene n Hexane, and H2S content. The sampled data will be used to calculate GHG, VOC and H2S emissions to show compliance with the emission limits specified in Condition 7. Please update Condition 68 for an annual gas analysis since the composition of the gas processed is not expected to be highly variable over the course of a year Additionally please remove the HAP constituents from this required analysis since the individual HAP emissions are much lower than the major source threshold for individual HAPs 69. Point 047: The operator shall sample the inlet gas to the plant on an annual basis to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that each amine unit qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (§60.5365(g)(3)). 70. Point 048: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the TEG dehydrator on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 71. Points 048, 050 and 051: The owner or operator shall conduct EPA Method 22 visible emission observations to monitor opacity from the enclosed combustor daily monthly. Per NSPS OOOO, the frequency shall be a total of 5 minutes during any 2 consecutive hours. 72. Point 052: On an annual basis, the permiftee shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of liquids that are representative of methane (CH4), carbon dioxide (CO2), volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. 73. Point 052: The fugitive emissions at this point that commenced construction, AIRS ID: 123/0107 Page 28 of 41 • a., .,tee ---s, . ..!1, -NS -11-2,,. R CSIF :‘ F.L V' d'2 kt' 'F41� 1 Al A y r' �1 5olorado,A,Dep`artdent of Public Health and Environment rte. ;5 �1 r p z1 1: fi Air Pollution Control Division s h ,. �A Imo; Jig OI ; modification or reconstruction after August 23, 2011, are subject to the leak detection and repair (LDAR) requirements of 40 C.F.R Part 60, Subpart OOOO. ADRITIONAL REQUIREMENTS 74. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually whenever a significant increase in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5) tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NO,) in ozone nonattainment areas emitting less than 100 tons of VOC or NOX per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NO ozone nonattainment areas emitting less than 100 tons of VOC or NOper year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; OF Please delete since this is repetitive. For any non -criteria reportable pollutant: If the emissions increase by 50% or five (5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. b. Whenever there is a change in the owner or operator of any facility, process, or activity; or c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. f. Points 044 and 045: Within 14 calendar days of commencing operation of a permanent replacement turbine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative -operating scenario and is installing a permanent replacement turbine. 75. This source is subject to the provisions of Regulation Number 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The provisions of this construction permit must be incorporated into the operating permit. The application for the modification to the Operating Permit is due within one year of commencement of operation of the equipment or modification covered by this permit. 76. Points 044 and 045: MACT Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) solely by virtue of a 'relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated AIRS ID: 123/0107 Page 29 of 41 ? tA"t a; fir#' Yolorall4pepart .ent of Public Health and Environment 1' " l' Air Pollution Control Division .. in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) 77. Points 048 and 052: MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities major stationary source requirements shall apply to this stationary source at any such time that this stationary source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) Please delete reference to AIRS Point 052 since this condition applies only to the glycol dehydrator (Point 048). GENERAL TERMS AND CONDITIONS: 78. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 79. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with the provisions of 25-7-114.5(12)(a) C.R.S. and AQCC Regulation. No. 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self -certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final authorization. Details for obtaining final authorization to operate are located in the Requirements to Self - Certify for Final Authorization section of this permit. 80. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 81. Unless specifically stated otherwise, the general and specific conditions contained in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 25-7-114.5(7)(a), C.R.S. 82, Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self -certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 83. Section 25-7-114.7(2)(a), C.R.S. requires that all sources required to file an Air Pollution Emission Notice (APEN) must pay an annual fee to cover the costs of inspections and administration. If a source or activity is to be discontinued, the owner must notify the Division in writing requesting a cancellation of the permit. Upon notification, annual fee AIRS ID: 123/0107 Page 30 of 41 A\ 'l ,r7-1 abloratiVepart ent f Public Health and Environment �Fl Air Pollution Control Division I Y.i:Acn.."tea'`-w4 billing will terminate. 84. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. By: Stephanie Chaousy, PE Permit Engineer Permit History Issuance Date Description Issuance 1 This Issuance Issued to DCP Midstream. Addition of eight (8) permitted sources at a natural gas processing plant. Sources located at a major facility. AIRS ID: 123/0107 Page 31 of 41 olor"q�Depa ent ;Public Health and Environment '`r Air Pollution Control Division 1.6 Notes to Permit Holder at the time of this permit issuance: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure 'to pay the invoice will result in revocation of this permit (Reference: Regulation No. 3, Part A, Section Vl.B.) 2) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdphe.state.co.us/requlationslairregs/100102agcccommonprovisionsreq.pdf. 4) The following emissions of non -criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. AIRS Point Pollutant CAS # BIN Uncontrolled Emission Rate (lb/yr) Are the emissions reportable? Controlled Emission Rate (Ib/yr) 044 Formaldehyde 50000 A 411 Yes 411 045 Formaldehyde 50000 A 411 Yes 411 047 Benzene 71432 A 139,8206 Yes 5,163 Toluene 108883 C 65,700 Yes 2,452 Ethylbenzene 100414. C 2,4089 Yes 89 Xylenes 1330207 C 4,940 Yes 186 ' n -Hexane 110543 C 18,300 Yes 69 048 Benzene 71432 A 140,18661 Yes 6,843 Toluene 108883 C 90,4526 Yes 4,444 Ethylbenzene 100414 C 5,759 Yes 2845 Xylenes 1330207 C 11,970 Yes 594 n -Hexane 110543 C 81,0656 Yes 2,623 050 Benzene 71432 A 1,021-298 Yes 5265 Toluene 108883 C 2 8583,597 Yes 14280 Xylenes 100414 C 2,160719 Yes 10836 n -Hexane 110543 C 575496,984 Yes 277349 051 Benzene 71432 A 1,257 Yes 63 AIRS ID: 123/0107 Page 30 of 41 Pleas Golorad%Departrt)erit of Public Health and Environment 59 ii n:.. Pollution Control Division G. �l��lyA x_if 1S :r:•lu.`.nw�l Sl �a'�7 r'?4`.f..'A�N {:': r... i'4 Toluene 108883 C 3,483 Yes 174 Xylenes 1330207 C 2,632 Yes 132 n -Hexane 110543 C 6,762 Yes 338 Benzene 71432 A 22536 Yes 26 052 n -Hexane 110543 C 4,€-'15843 Yes X694 5) The emission levels contained in this permit are based on the following emission factors: Points 044 and 045: CAS Pollutant Emission Factors lb/MMBtu - Uncontrolled Source NOX 0.0519 Manufacturer CO 0.0608 Manufacturer VOC 0.0021 AP -42, Chapter 3.1-2a PM2.5 . 0.0066 AP -42, Chapter 3.1-2a 50000 Formaldehyde 0.00071 AP -42, Chapter 3.1 Greenhouse Gas Emission Factors Pollutant kg/MMBtu GIMP Source CO2 53.02 1 40 CFR 98 Subpart C CH4 0.001 21 40 CFR 98 Subpart C N2O 0.0001 310 40 CFR 98 Subpart C Em'ssion factors are based on a rated heat input of 66.12 MMBtu/hr, a HHV value of 1.023e-03 MMBtu/scf and 8760 hours of operation a year. Point 046: CAS Pollutant Emission Factors lb/MMscf - Uncontrolled Source NOx 37 Manufacturer CO 84 AP -42, Chapter 1.4 VOC 5.5 AP -42, Chapter 1.4 PM2.5 7.6 AP -42, Chapter 1.4 Greenhouse Gas Emission Factors Pollutant kgIMMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart C CH4 0.001 21 40 CFR 98 Subpart C N2O 0.0001 310 40 CFR 98 Subpart C Emission factors are based on a rated heat input of 50 MMBtu/hr, a higher heating value of 1,023 Btu/scf, and a limited use scenario of 315 MMscf/yr or the equivalent of 67% of operating capacity. Point 047: Emissions from the amine unit result from venting of acid gas (still vent overhead to the regenerative thermal oxidizer) and flash tank emissions to the flare during VRU downtime. Additionally, emissions result from combustion of supplemental fuel from the burner. Actual VOC, HAP and H2S emissions from venting of still vent acid gas and flash tank emissions shall be calculated based on most recent waste gas acid gas stream from amine still vent sampling and most recent monthly waste gas acid gas stream from amine still vent flow volume. Controlled emissions are as follows: Point Source VOC CH4 AIRS ID: 123/0107 Page31 of 41 ,Dep rtm ent o Public Health and Environment Air Pollution Control Division Controlled Still Vent 96% 9-9 96% Controlled Flash Tank during VRU uptime 100% 100% Controlled Flash Tank during VRU downtim e 95% 95% SO2 emissions resulting from the control/combustion of H2S emissions in the waste gas acid gas stream from amine still vent are based on mass balance and assuming 96% of the H2S is converted to SO2. Additional combustion emissions (from waste gas acid gas stream from amine still vent) are calculated using the following emission factors and volume of total gas combusted. Total gas combusted is the sum of most recent waste gas acid gas stream from amine still vent flow volume plus most recent burner volume. Total actual emissions are based on sum of emissions calculated for controlled waste gas (flash tank during VRU downtime and still vent) plus combustion (including burner and waste gas acid gas stream from amine still vent volumes). CAS Pollutant Emission Factors for flash tank volume sent to flare - Uncontrolled Uncontrolled EF Source NOx 0.068 lb/MMbtu AP -42, Table 13.5-1 CO 0.37 lb/MMbtu AP -42, Table 13.5-1 For RTO combustion: CAS Pollutant Emission Factors - Uncontrolled . Lb/mmscf total gas corn busted* Uncontrolled EF Source NOx 100 AP -42, Table 1.4-1 - CO 84 AP -42, Table 1.4-1 VOC 5.5 AP -42, Table 1.4-2 SO2 0.6 AP -42, Table 1.4-2 PM10 7.6 lb/MMsc-f AP -42, Table 1.4-2 PM2.5 7.6 lb/MMscf AP -42, Table 1.4-2 *Total gas combusted equals waste gas acid gas stream from amine still vent volume plus supplemental fuel volume plus fuel volume to burner. Greenhouse Gas Emission Calculations for Amine Units The owner or operator shall calculate CO2 emissions from each amine unit, on a monthly basis, using equation W-3 consistent with 40 CFR Part 98, Subpart W [98.233(d)(2)] along with the most recent waste gas acid gas stream from amine still vent sampling composition and most recent monthly waste. gas acid gas stream from amine still vent flow volume. The owner or operator shall calculate GHG emissions from combustion at each regenerative thermal oxidizer based on procedures in 40 CFR 98 Subparts A and C along with the most recent monthly fuel gas and waste gas acid gas stream from amine still vent flow volumes. Total CO2 emissions shall be based on the sum of CO2 emissions from the amine unit plus GHG emissions from combustion at each the regenerative thermal oxidizer. AIRS ID: 123/0107 Page 32 of 41 - C;oloradbt_Depa4rtngent of Public Health and Environment J. ti -Q'-'14 M6 1' Air Pollution Control Division Greenhouse Gas Emission Factors for Regenerative Thermal Oxidizer Combustion Pollutant kg/MMBtu GWP I Source CO2 53.02 1 I 40 CFR 98 Subpart A and C CH4 0.001 21 40 CFR 98 Subpart A and C N2O 0.0001 310 40 CFR 98 Subpart A and C GHG emissions from combustion are based on a heat content of 5.12 Btu/scf and a total heat input for eas4 the regenerative thermal oxidizer of 4.0 MMBtu/hr. Point 048: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. For Lopt, the gas flowrate (F) is 230 MMSCF/D, the inlet water content (I) is 7.0 Ib/MMSCF and the outlet water content (O) is 7.0 5.0 Ib/MMSCF. CAS Pollutant Emission Factors - Uncontrolled Uncontrolled EF Source NOx 100 lb/MMscf AP -42, Table 1.4-1 CO 84 lb/MMscf AP -42, Table 1.4-1 Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 -- 1 40 CRFR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W* The emission factors are for natural gas with a heat input of 1000 Btu/scf. The emissions for NOx and CO were calculated based on a fuel heat content of 120 1,797 Btu/scf and a flow rate of 17,400 1,160 scf/h r. Note that the condenser vent stream is stream that is combusted in the enclosed combustor. The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95% for VOC and CH4. Point 050: CAS Pollutant Emission Factors Uncontrolled Emission Factors Controlled Source ( NOx 100 lb/MMScf --- AP -42, Chapter 1.4 CO 84 lb/MMScf --- AP -42, Chapter 1.4 VOC 0.-209 lb/bbl 0.008310 lb/bbl EPA Tanks 4.09d PM10 7.6 lb/MMscf --- AP -42, Table 1.4-2 PM2.5 7.6 lb/MMscf --- AP -42, Table 1.4-2 71432 Benzene 0.0022885 lb/bbl 0.0001434 lb/bbl EPA Tanks 4.09d 108883 Toluene 0.0062-77881b/bb 0.00034 lb/bbl Engineering Calculation 1330207 Xylenes 0.004735961b/bb 0.00023 lb/bbl Engineering Calculation 110543 n -Hexane 0.0125 lb/bbl 0.00088 lb/bbl Engineering Calculation Note: The controlled emissions factors for point 050 are based on the enclosed combustor control efficiency of 95%. Emission factors are based on the condensate tank battery as a combined unit, not per tank. AIRS ID: 123/0107 Page 33 of 41 ff A fe ,olorat7Depart ent ai Public Health and Environment Air Pollution Control Division n Greenhouse Gas Emission Factors Pollutant kg/MM Btu GWP Source C02 -- 1 40 CRFR Subpart W N20 0.0001 310 40 CFR 98 Subpart W* The owner or operator shall calculate C02, CH4, and N20 emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Point 051: CAS Pollutant Emission Factors Uncontrolled Emission Factors Controlled Source NOx 100 lb/MMScf --- AP -42, Chapter 1.4 CO 84 lb/MMScf --- AP -42, Chapter 1.4 VOC 0.202 lb/bbl 0.0101 lb/bbl AP -42, Chapter 5.2 PM10 7.6 lb/MMscf --- AP -42, Table 1,4-2 _ PM2.5 7.6 lb/MMscf --- AP -42, Table 1.4-2 71432 Benzene 0.0656 lb/1000 gal 0.0033 lb/1000 gal Engineering Calculation 108883 Toluene 0.1817 lb/1000 gal 0.0091 lb/1000 gal Engineering Calculation 1330207 Xylenes 0.1374 lb/1000 gal 0.0069 lb/1000 gal Engineering Calculation 110543 n -Hexane 0.3529 lb/1000 gal 0.0176 lb/1000 gal Engineering Calculation The uncontrolled VOC emission factor was calculated using AP -42, Chapter 5.2, Equation 1 (version 1/95) using the following values: L = 12.46*S*P*M/T S = 0.6 (Submerged loading: dedicated normal service) P (true vapor pressure) = 5.0032 psia M (vapor molecular weight) = 66 Ib/lb-mol T (temperature of liquid loaded) = 512.45 °R The uncontrolled non -criteria reportable air pollutant (NCRP) emission factors were calculated by multiplying the mass fraction of each NCRP in the vapors by the VOC emission factor. Controlled emission factors are based on an enclosed combustor efficiency of 95%. Greenhouse Gas Emission Factors Pollutant kg/MM Btu GWP Source CO2 -- 1 40 CRFR Subpart W N20 0.0001 310 40 CFR 98 Subpart W* The owner or operator shall calculate OO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. AIRS ID: 123/0107 Page 34 of 41 63? �.:oloradb,Depaftment of Public Health and Environment r Et Air Pollution Control Division 147,4-4-O tea'" !py r iii Point 052: Equipment Type Gas Light Liquid Connectors 1,274914 4,0'l16,066 Flanges 1,1'15718 76111,146 Open -Ended Lines --- -- Pump Seals 25 38 Valves 2,611522 X8461,982 Other 74148 366 VOC Content (wt%) 26.92% 100% Benzene (wt%) 0.06% 0.06% Toluene (wt%) 0.04% 0.04% Ethylbenzene (wt%) 0.003% 0.003% Xylenes (wt%) 0.01% 0.01% n -hexane (wt%) 1.21% 1.21% CO2 Content (wt%) 6.65% --- CH4 Content (wt%) 54.67% --- *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Light Oil Connectors 2.0E-04 2.1E-04 Flanges 3.9E-04 1.1E-04 Open-ended Lines 2.0E-03 1.4E-03 Pump Seals 2.4E-03 1.3E-02 Valves 4.5E-03 2.5E-03 Other 8.8E-03 7.5E-03 Source: EPA -453/R95-017 Note that the emission limits included in this permit are derived by multiplying the equipment counts in the table above by a factor of 1.2 to accommodate other minor changes to the facility and to provide a conservative -estimate of facility widc emissions. The emission limits in the permit did not include the 1.2 factor. Additionally, since DCP is revising the fugitive component count to be higher and hence more conservative, this 1.2 factor is no longer required. Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas and liquids analyses. For CO2e emissions, the TOC emission factors listed in the table above with representative component count will be multiplied by the CH4 and CO2 content from the most recent gas analysis. CO2e emissions are then calculated based on procedures in 40 CFR 98 Subpart A 6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-3150_ 7) This facility is classified as follows: AIRS ID: 123/0107 Page 35 of 41 olorati Dep r1 -tent of Public Health and Environment :t Air Pollution Control Division Applicable Requirement Status Operating Permit Major Source of NOR, VOC, and CO PSD Subject to Regulation of CO2e NANSR Major Source of NOR and VOC 8) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below. http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A — Subpart OOOO NSPS Part 60, Appendixes Appendix A — Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A — Subpart Z MACT 63.600-63.1199 Subpart AA — Subpart ODD MACT 63.1200-63.1439 Subpart EEE— Subpart PPP MACT 63.1440-63.6175 Subpart QQQ - Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ — Subpart MMMMM MACT 63.8980 -End Subpart NNNNN — Subpart XXXXXX 9) An Oil and Gas Industry Construction Permit Self -Certification Form is included vrith this permit packet. Please use this form to complete the self -certification requirements as specified in the permit conditions. Further guidance on self -certification can be found on our website at: http://wvvw.cdphe.state.co.us/ap/oilqasperrn itti n q. h tm I AIRS ID: 123/0107 Page 36 of 41 F l � .65 DCP Midstream, LP Vi g Colorado Dk partmenit of Public Health and Environment Permit No. 12WE2024 ' tst r 7-4-1‘.‘ Air Pollution Control Division Issuance 1 d,;• ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING August 16, 2011 1. Routine Turbine Component Replacements The following physical or operational changes to the turbines in this permit are not considered a modification for purposes of NSPS GG, major stationary source NSR/PSD, or Regulation No. 3, Part B. Note that the component replacement provisions apply ONLY to those turbines subject to NSPS GG. Neither pre-GG turbines nor post GG turbines (i.e. KKKK turbines) can use those provisions. 1) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seals, and shaft packings, provided that they are of the same design as the original. 2) Changes in the type or grade of fuel used, if the original gas turbine installation, fuel nozzles, etc. were designed for its use. 3) An increase in the hours of operation (unless limited by a permit condition) 4) Variations in operating loads within the engine design specification. 5) Any physical change constituting routine maintenance, repair, or replacement. Turbines undergoing any of the above changes are subject to all federally applicable and state only requirements set forth in this permit (including monitoring and record keeping). If replacement of any of the components listed in (1) or (5) above results in a change in serial number for the turbine, a letter explaining the action as well as a revised APEN and appropriate filing fee shall be submitted to the Division within 30 days of the replacement. Note that the repair or replacement of components must be of genuinely the same design. Except in accordance with the Alternate Operating Scenario set forth .below, the Division does not consider that this allows for the entire replacement (or reconstruction) of an existing turbine with an identical new one or one similar in design or function. Rather, the Division considers the repair or replacements to encompass the repair or replacement of components at a turbine with the same (or functionally similar) components. 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of combustion turbines and turbine components has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility- Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any turbine or turbine component replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such turbine or turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. AIRS ID: 123/0107/044, 045 Page 37 of 41 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 - c•. -e, R, . oll ltpdo Departure t o'f'Public Health and Environment Air Pollution Control Division AL 2.1 Turbine Replacement The following AOS is incorporated into this permit in order to deal with a turbine breakdown or periodic routine maintenance and repair of an existing onsite turbine that requires the use of a temporary replacement turbine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the total number of days that the turbine is in operation. If the turbine operates only part of a day, that day shall count as a single day towards the 90 -day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. Any permanent turbine replacement under this AOS shall result in the replacement turbine being considered a new affected facility for purposes of NSPS and shall be subject to all applicable requirements of that Subpart including, but not limited to, any required Performance Testing. All replacement turbines are subject to all federally applicable and state -only requirements set forth in this permit (including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with the NSPS requirements. Results of all tests shall be kept on site for five (5) years and made available to the Division upon request. The owner or operator shall maintain a log on -site and contemporaneously record the start and stop date of any turbine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the turbine (s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement turbine. 2.1.1 The owner or operator may temporarily replace an existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit, so long as the temporary replacement turbine complies with the emission limitations for the existing permitted turbine and other requirements applicable to the original turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1:2 The owner or operator may permanently replace the existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit so long as the permanent replacement turbine complies with the emission limitations and other requirements applicable to the original turbine as well as any new applicable requirements for the replacement turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.3 An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar days of commencing operation of the replacement turbine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement turbine. This AOS cannot be used for permanent turbine replacement of a grandfathered or permit exempt turbine or a turbine that is not subject to emission limits. The owneroroperator shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent turbine replacement. AIRS ID: 123/0107/044, 045 Page 38 of 41 r r� ion e t zi DCP Midstream, LP C f Colorado Drepartme ut of Public Health and Environment Permit No. 12WE2024 ,.� . ''r r Air Pollution Control Division• Issuance 1 Wyk 6.., The AOS cannot be used for the permanent replacement of an entire turbine at any source that is currently a major stationary source for purposes of Prevention of Significant Deterioration or Non -Attainment Area New Source Review ("PSD/NANSR") unless the existing turbine has emission limits that are below the significance levels in Reg 3, Part D, I I.A.42. Nothing in this AOS shall preclude the Division from taking an action, based on any permanent turbine replacement(s), for circumvention of any state or federal PSD/NANSR requirement Additionally, in the event that any permanent turbine replacement(s) constitute(s) a circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse the owner or operator from complying with PSD/NANSR and applicable permitting requirements. 2.2 Portable Analyzer Testing Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss streamlining the testing requirements. Note that the testing required by this Condition may be used to satisfy the periodic testing requirements specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer testing, this test conducted under the AOS will serve as the quarterly test and an additional portable analyzer test is not required for another three months). The owner or operator may conduct a reference method test, in lieu of the portable analyzer test required by this Condition, if approved in advance by the Division. The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement turbine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement turbine. All portable analyzer testing required by this permit shall be conducted using the most current version of the Division's Portable Analyzer Monitoring Protocol as found on the Division's website. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. For comparison with a short-term limit that is either input based (Ib/mm Btu), output based (g/hp-hr) or concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to -or the replacement turbine will be subject to, the results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the turbine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO AIRS ID: 123/0107/044, 045 Page 39 of 41 erg,, DCP Midstream, LP Permit No. 12WE2024 Issuance 1 Color do DApartmet of Public Health and Environment _a Air Pollution Control Division emission limitations, the turbine will be considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the turbine is taken offline. 2.3 'Applicable Regulations for Permanent Turbine Replacements 2.3.1 NSPS for Stationary Gas Turbines: 40 CFR 60, Subpart GG §60.330 Applicability and designation of affected facility. (a) The provisions of this subpart are applicable to the following affected facilities: All stationary gas turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired. (b) Any facility under paragraph (a) of this section which commences construction, modification, or reconstruction after October 3, 1977, is subject to the requirements of this part except as provided in paragraphs (e) and (j) of §60.332. A Subpart GG applicability determination as well as an analysis of applicable Subpart GG monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS GG requirements). 2.3.2 NSPS for Stationary Combustion Turbines: 40 CFR 60, Subpart KKKK §60.4305 Does this subpart apply to my stationary combustion turbine? (a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part. A Subpart KKKK applicability determination as well as an analysis of applicable Subpart KKKK monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is AIRS ID: 123/0107/044, 045. Page 40 of 41 DCP Midstream, LP IP Permit No. 12WE2024 �A Issuance 1 Colorpni - do Departrfent of Public Health and Environment 47, k2. E Air Pollution Control Division first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS KKKK requirements). 2.4 Additional Sources The replacement of an existing turbine with a new turbine is viewed by the Division as the installation of a new emissions unit, not "routine replacement" of an existing unit, The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new' emission points for any site; a turbine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite turbine has to go through the appropriate Construction/Operating permitting process prior to installation AIRS ID: 123/0107/044, 045 Page 41 of 41 Responses to DCP comments received August 2, 2013 via email. Please see the Division's responses to DCP comments below in italics. I. Equipment Description box, Point 046: Change "system" to "unit." Condition has been revised to reflect this change. 2. Equipment Description box, Point 047: remove "two (2) or three (3)" and change "design" to "limited." Please remove "equipped with a backup unit" for the vapor recovery unit (VRU) because although the facility will have two VRUs, it is expected that both YRUs can be operational at the same time during certain seasons, therefore the second VRU is not truly considered a backup unit. Also the serial number is TBD. The "two (2) or three (3)" has been removed, "design" has been changed to "limited" and the sentence has been changed to "The amine flash stream is routed to a closed loop system that utilizes two vapor recovery units (1% annual downtime)." The serial number description has been changed to TBD. 3. Equipment Description box, Point 048: Please remove "equipped with a backup unit" for the vapor recovery unit (VRU) because although the facility will have two VRUs, it is expected that both VRUs can be operational at the same time during certain seasons, therefore the second VRU is not truly considered a backup unit. The sentence has been changed to "The flash gas is routed to a closed loop system that utilizes two vapor recovery units (I% annual downtime)." 4. Equipment Description box, Point 050: DCP requests a change in tank configuration from 8x400 bbl tanks to 4x1000 bbl tanks. Please note that there will be no increase in condensate throughput. This change was made throughout the permit and was noted that the throughput did not change. However, this change in increase the emission limit slightly. 5. Condition 7: Please revise the emission limits in the tables above due to rounding convention discrepancies. Please also update the tank emissions due to the change in configuration. Additionally, please update the fugitive emissions to include additional components and associated emissions. The tables have been modified to include rounding discrepancies, configuration change of the condensate tanks, and the additional components for the fugitives. 6. Condition 7: The HAP statements (monthly and annually) need to be modified to account for the actual HAPS at the facility (22.1 TPY). After review, it appears that the HAPS are actually 22.8 TPY. I emailed DCP regarding this and it was confirmed by Trinity. I will make that change as well as add the insignificant activities tracking condition since the HAPS are greater than 20 TPY (so will need to track to not exceed 25 TPY). 7. Condition 7: The subscript in the quarterly table is not correct. It has been corrected. 8. Condition 8: Change "natural gas" to "fuel flow". Change has been made to permit. 9. Condition 9: Change "waste gas" to "acid gas stream from amine still vent" and "natural gas" to "fuel flow." Per our meeting on 8/8/13, the Division did not clearly state what waste gas was and what was needed to show compliance. In this case, waste gas is including flash tank stream during VRU downtime and acid gas stream from the still vent. The condition has been modified to say "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." "Natural gas" has been changed to "fuel flow." 10. Condition 11: Change "waste gas" to "acid gas stream from amine still vent." Per the statement above, "waste gas" has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." 11. Condition 12: Change "waste gas" to "acid gas stream from amine still vent." Per the statement above, "waste gas" has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." 12. Condition 13: Change "waste gas" to "acid gas stream from amine still vent." Per the statement above, "waste gas" has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." 13. Condition 13: DCP requests the destruction rate efficiency (DRE) for methane to be revised to 96% per the original application. There are several reasons for this...As the RTO is not a primary control device for CH4 and there is no guarantee that the RTOs control methane specifically with a DRE of 99%, DCP would like to maintain the DRE of 96% for both VOCs and methane. Per our discussion at the 8/8/13 meeting, the 99% control for methane has been set not only by the Divisions' other PSD application (Lancaster) but EPA as well. In fact, EPA just issued a draft PSD permit for a DCP facility in Texas with 99.9% control efficiency of methane. We believe that 99% is acceptable and will leave the permit condition as -is. 14. Condition 14: Remove "primary and backup" from the condition, move the sentence "During the VRU downtime, emissions generated will be routed to flare" after the first sentence of the condition and remove "natural gas/amine contactor and" from the condition. "Primary and backup" was removed and replaced with "two vapor recovery units, " the sentence was re -located and "natural gas/amine contactor and" was removed. 15. Condition 24: Add sentence "VRU downtime shall be defined as times when the flash gas from the amine unit and the dehydrator are routed to the flare rather than the VRU" after the first sentence of this condition. Sentence has been added to condition. 16. Condition 25.d: Change "non-resettable elapsed flow meter" to "continuous fuel flow monitor" and streamline the last sentence. Both comments have been incorporated in modifying this condition. 17. Condition 25.e: Please delete condition 25.e since air/fuel ratio controllers are not available for Solar turbines. This has been erased. 18. Condition 25.f: add "and shall maintain records of the stack exhaust temperature." This language has been revised per our meetings and emails (it is now 28.e) 19. Condition 25.g: Please delete Condition 25.g since the fuel temperature and ambient temperature do not affect the operation of the turbine. Condition has been erased. 20. Condition 25.i: DCP requests that the BACT limit for CO2e from the turbines be increased to 1.0657 lb/hp-hr. Since the limit is a short-term hourly limit based on the maximum hp capacity of the turbine, any decrease in capacity of the turbine (equating to lower hp) will result in the hourly actual calculation to exceed the permit limit. Although this limit is an average limit over a 12 -month period, the work output of the turbine can never exceed the maximum rated hp of 9055 hp, but the work output can be lower than the maximum rated hp at certain periods of time. An average limit can only be achieved if the limit is based on the average work output of the turbine, but for emissions purposes the turbine is permitted at the maximum output. Therefore, DCP is requesting a 20% safety factor to be included in the short-term average limit to account for variability in operation of the turbine. Note that even with an increase in the average limit, DCP will maintain compliance with Condition 7. Please see Condition 28.g for new language. 21. Condition 25.j: Remove "efficiency for each hour of operation using monitoring firing rate." Please see Condition 28.g for new language. 22. Condition 25.k: DCP requests that the BACT limit for CO2e from the hot oil heater be increased to 561.45 lb/mmscf. Since the limit is based on the maximum gas capacity of the plant, any decrease in gas throughput will result in the actual per mmscf calculation to exceed the permit limit. Although this limit is an average limit over a 12 -month period, the gas throughput through the facility can never exceed the maximum rated hp of 230 mmscfd, but the gas processed can be lower than the maximum permit limit since DCP has built in a buffer to allow for a worst -case maximum gas throughput rate. An average limit can only be achieved if the limit is based on the average capacity of the facility, but emissions are permitted at the maximum throughput to be conservative. Therefore, DCP is requesting a 20% safety factor to be included in the avearge limit to account for variability in operation of the facility and heater. Note that even with an increase in the average limit, DCP will maintain compliance with Condition 7. Additionally, please replace the output -based limit to input -based limit since DCP has requested a limit of 230 mmscfd based on gas input to the facility rather than gas output from the facility. Please see the new language under Condition 28.j. 23. Condition 25.m: Change "non-resettable elapsed flow meter" to "continuous fuel flow monitor" and streamline the last sentence by combining Conditions 25.n and 25.m together. Both comments have been incorporated in modifying this condition. 24. Condition 25.n: Please delete condition 25.n since this has been merged with Condition 25.m. Condition has been removed since it is now part of Condition 25.m. 25. Condition 25.s: Remove "at least once per every three months, at a minimum" and replace it with "per manufacturer recommendations." Per our meeting on 8/8/13, the BACT requires a specific measuring tactic, and every 3 months has been consistent among other Region 6 PSD permits. Therefore, this will stay as - is. 26. Amine unit and thei„ial oxidizer title in the BACT section: Add "regenerative." Regenerative has been added to the title. 27. Condition 25.v: add "regenerative" and change 99% control of methane to 96%. "Regenerative" has been added to the thermal oxidizer description and as previously mentioned, the 99% control of methane will stay as -is. 28. Condition 25.w: Please delete Condition 25.w for compliance purposes since this has the same requirement as Condition 67: Per our meeting on 8/8/13, it was discussed that this condition has to be determined as a BACT condition, while Condition 67 includes the other criteria pollutants. While BACT cannot be changed during a modification without a BACT review, Condition 67 can be modified based on criteria pollutants. Therefore, this condition will stay as -is. 29. Condition 25.x: add "still vent" after amine unit in first sentence and add "regenerative" to thermal oxidizer in last sentence. Both additions have been added to the condition. 30. Condition 25.y: change "waste gas" to "still vent" and change "6 minutes" to "1 hour." "Still vent" has been added to the condition, however, 6 minutes will stay as -is because it is a BACT requirement to show compliance. 31. Condition 25.aa: Please delete Condition 25.aa for compliance purposes since this has the same requirement as Conditions 56 and 68. Again, this condition has to be determined as a BACT condition while the other conditions are also for criteria pollutants. The condition will stay as -is. 32. Condition 25.bb: change "waste gas" to "acid gas stream from amine still vent", "non resettable elapsed flow meter" with "continuous fuel flow monitor." Both modifications have been incorporated into the permit condition. 33. Condition 25.cc: change "non-resettable elapsed flow meter" to "continuous fuel flow monitor" and add "regenerative" to thermal oxidizer description. Both changes have been incorporated into this permit condition. 34. Condition 25.dd: DCP would like to note that the flash tank stream from the amine unit is directed to the emergency flare during downtime operations. Change "non-resettable elapsed flow meter" to "continuous fuel flow monitor." Both changes have been incorporated into this permit condition. 35. Condition 25.ee: Add "regenerative" to the thermal oxidizer description. It has been added to the permit condition. 36. Condition 25.ff: change waste gas to "acid gas stream from amine unit." Add "regenerative" to the thermal oxidizer description. Add "except during periods of downtime as defined in 40 CFR §60.7(d)(1)." The recommendations have been incorporated into this permit limit. 37. Condition 25.gg: Per discussion with the manufacturer, DCP has determined that by maintaining the oxygen analyzer according to manufacturer's recommendations, the quality assurance aspect of the oxygen analyzer will be taken care of Please see new condition language for Condition 28ff 38. Condition 25.11: Please revise the Method 22 opacity test requirement frequency to monthly rather than daily to be consistent with 40 CFR 60.515(e)(2)(vii)(c). Daily is consistent with the O&M plan for facilities with permitted VOC emissions greater than 80 TPY. This condition will stay as is. 39. Condition 25.mm: Please delete condition 25.mm since the enclosed combustor at the facility does not meet the definition of open flare 40 CFR 60.18. This is consistent with the EPA determination, specifically per Applicability Determination Index, Control Number 0000068, 07/07/2000, EPA says "In a determination that is posted as Control Numbers 0000019 and M000002 on EPA's Applicability Determination Index (ADI), EPA Region 6 determined that an enclosed flare is not the type of flare that is regulated by the open -flame flare specifications at 40 CFR 60.18." Accordingly, DCP asks that this condition be deleted. It has been removed. 40. Condition 26.c: Change "waste gas" to "acid gas stream from amine still vent." The sentence has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." 41. Condition 26.d: Change output to input and add (MMscfd) after rate. Both recommendations have been incorporated in the condition modification. 42. Condition 27: Revise the current limit based on the new modifications (tanks and fugitives): Limits have been revised. 43. Condition 32 and 33: Please combine conditions 32 and 33 since they both relate to PM and SO2 emissions. This will make compliance tracking easier for DCP. At this point, the Division would like to keep these separate since the conditions are asking for different things. 44. Condition 45: Please delete reference to Point 052 from Condition 45 since that point specifically relates to fugitive emissions. Condition has been modified. 45. Condition 54: DCP requests to remove PM2.5 stack test since emissions from PM2.5 are minimal from the hot oil heater especially since it purely combusts natural gas. Testing for PM2.5 has been removed from this condition. 46. Condition 56: Change "waste gas" to "acid gas stream from amine still vent." The sentence has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." 47. Condtion 57: Change the control efficiency of methane from 99% to 96%. Change "waste gas" to "acid gas stream from amine still vent." This proposed language is consistent with a similar DCP facility (LaSalle) Permit 11 WE1481 upon discussed with the CDPHE APCD. Please reword accordingly. Per earlier discussion, methane will maintain the 99% control efficiency. The sentence has been changed to "waste gas (acid gas stream from the still vent)." Regarding LaSalle, that decision was made on a case -by -case basis that was specific to LaSalle. That does not mean that Lucerne will be reviewed the same way. This is standard, and therefore, the condition will stay as -is. 48. Condition 57: DCP requests removal of CO and NOx from the stack test requirements for the amine unit since emissions of NOX and CO are minimal from this source, and the emissions are purely generated as a result of the control device operation. These testing requirements will not be removed because DCP needs to show compliance with NOx and CO showing that this facility did not exceed the significant thresholds for a major modification. 49. Condition 59: Please revise the Method 22 opacity test requirement frequency to monthly rather than daily to be consistent with 40 CFR 60.515(e)(2)(vii)(c). Daily is consistent with the O&M plan for facilities with permitted VOC emissions greater than 80 TPY. This condition will stay as is. 50. Condition 60: DCP requests removal of CO, NOx and CO2 from the stack test requirement for the enclosed combustor since emissions of NOx, CO and CO2 are minimal from this source, and the emissions are purely generated as a result of the control device operation. These testing requirements will not be removed because DCP needs to show compliance with NOx and CO showing that this facility did not exceed the significant thresholds for a major modification. 51. Condition 67: Change control of methane from 99% to 96%. Change "waste gas" to "acid gas stream from amine still vent." Per earlier discussion, methane will maintain the 99% control efficiency. The sentence has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." 52. Condition 67: Please remove PM2.5 stack test requirement for this source especially since the source does not generate any PM2.5 emissions. Testing for PM2.5 has been removed from the condition. 53. Condition 68: Change "amine unit waste gas" to "acid gas stream from amine still vent." Please update Condition 68 for an annual gas analysis since the composition of the gas processed is not expected to be highly variable over the course of a year. Additionally, please remove the HAP constituents from this required analysis since the individual HAP emissions are much lower than the major source threshold for individual HAPS. The sentence has been changed to "waste gas (including flash tank stream during VR U downtime and acid gas stream from the still vent)." The frequency will not change nor will the HAP constituents be removed per our meeting on 8/8/13. This is a PSD facility with all HAPS at reportable levels. 54. Condition 71: Change Method 22 readings from daily to monthly. The last sentence was removed from this condition which was referencing NSPS OOOO. The daily requirement is based off of the O&M plan for facilities with permitted VOC emissions greater than 80 TPY. 55. Condition 74: Please delete since it is repetitive. This has been removed, but the correct one has been added: For sources emitting 100 tons per year or more, a change in actual emissions offive percent or 50 tons per year or more, whichever is less, above the level reported on the last APEN submitted; or 56. Condition 77: Please delete reference to AIRS point 052 since this condition applies only to the glycol dehydrator (Point 048). Actually, fugitives and condensate tanks are subject to MACT HH if the facility is major for HAPS. So the fugitives could be subject to MACT HH if the limits relax and become major. This condition will stay as -is. 57. Notes to Permit Holder, Note 4: Please revise the HAP emission rates per the revised tank configuration and fugitive component increases. The table has been revised accordingly. 58. Notes to Permit Holder, Note 5, Point 047: add regenerative and change "waste gas" to "acid gas stream from amine still vent." Change 99% methane conrol to 96% control. Regenerative has been added to the thermal oxidizer description where all appropriate and where it says "waste gas" has been changed to "waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent)." Per previous discussion, methane will stay at 99% control. 59. Notes to Permit Holder, Note 5, Point 047: The RTO combustion table needs some modification: VOC emission factor is 5.5 (not 1.1) and lb/mmscf is not needed for PM10 and PM2.5. All recommendations have been incorporated into the condition. 60. Note to Permit Holder, Note 5, Point 048: Note that the condenser vent stream is stream that is combusted in the enclosed combustor. The fuel heat content and flow rate has been revised as well as CRR to CFR. 61. Notes to Permit Holder, Note 5, Point 048: change the outlet water content to 5.0 lb/mmscf. Condition has been revised. 62. Notes to Permit Holder, Note 5, Point 050: Revise the emission factors based on the modified APEN received with these comments. The emission factors have been modified to reflect the recent changes to the condensate tanks as well as CRR to CFR. 63. Notes to Permit Holder, Note 5, Point 051: Change CRR to CFR. Label has been changed 64. Notes to Permit Holder, Note 5, Point 052: Revise the component counts based on the modified APEN received with these comments. The emission limits in the permit did not include the 1.2 factor. Additionally, since DCP is revising the fugitive component count to be higher and hence more conservative, this 1.2 factor is not longer required. The component counts have been modified to reflect the recent changes to the fugitive emissions as well as removing the safety factor paragraph since the increase in components removed the need for the safety factor. DCP Lucerne CDPHE Comment Response DCP Midstream, LP (DCP) is providing the following responses to the questions received from CDPHE on January 16, 2013 for the DCP Platteville Permit Application. The nature of the Lucerne expansion and Platteville expansion are similar, and DCP is providing two sets of the same responses for the two facilities. Pleasenote that this document contains the following five attachments: > Attachment A: Emission calculations including routing of the dehydrator vent to the tank combustor instead of the RTO and a nitrogen oxides (N0x) emission factor change; > Attachment B: Revised APCD Form 102; > Attachment C: NOx emission factor guarantee for the hot oil heater; > Attachment D: Revised Best Available Control Technology (BACT) write up; and > Attachment E: Revised APENs. The specific questions are listed here but please note that the responses are found in the specified Attachments, except as indicated below. Questions from the CDPHE are noted in italicized font, while any responses are noted in regular font. 1) The BACT analysis does not adequately consider CCS technology. The application refers to a DOE study as when claiming the closest site for CCS is 150 miles away. A review of this study reveals that the authors assert enhanced oil recovery is a viable technology for several fields in Weld County. The study lists the Sussex and Shannon sandstone of the nearby Spindle field (SW Wattenberg) as amenable to enhanced oil recovery operations. The BACT analysis in paragraph 12.6,1.1 describes the operations as technically feasible, but does not go on to discuss why EOR couldn't be practical nearby. There aren't currently any active CO2 injection wells in the area, but one would presume that is because well operators would also need to construct a 150 mile pipeline. A quick calculation for a pipeline to the proximate wells sites (assuming 15 miles) yields about $20/ton of CO2e. The analysis also does not account for the sale price of the CO2 recovered, which according to the study provided, $0.80/MMscf (or $13/ton) would be a conservative estimate of low priced CO2. Before CCS can be eliminated as infeasible, a comprehensive analysis is needed discussing why the amine unit acid gas stream, or a portion of it, couldn't be used for EOR at local wells. Please submit additional information to supplement the BACT analysis. A. Please see Attachment D for a revised BACT writeup that addresses these concerns 2) The cost of the pipeline is based on an assumed 10 year pipeline lifetime, based on engineering judgment. DCP (obviously) has significantly more experience inthis field than I do, but from layman's judgment, this seems like an inappropriately short (ifetime. The most prominent thought coming to mind being the Trans Alaska Pipeline which I think was installed in the mid 70s and -is expected to remain for at least another couple decades. Clearly you aren't building the Trans Alaska Pipeline here, but I'm wondering if the assumption was a typographical error of100 years? Or perhaps just a very conservative estimate. If this was in tentional,just ignore this comment. A. CO2 is a corrosive gas and a 10 year lifetime for the pipeline is intentional due to its corrosivity.1 3) The BACT analysis describes the benefits of using a regenerative thermal oxidizer over a flare or combustor and uses this as justification for RTO control for the amine acid gas stream. This same discussion is referred to as grounds for using an enclosed combustor to control dehydrator emissions. Please supplement the application with justification for the dehydrator still vent being routed to an enclosed combustor rather than the RTO. 1 http://www.ccsassociation.org/docs/2010/lEA%20Pipeline%20final%20report%20270410.pdf DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants A. Please see Attachment D for a revised BACT writeup that addresses these concerns. 4) The BACT analysis in 12.6.1.5 discusses that the amine unit will be routed to a condenser prior to the RTO. However, the presence of this condenser is not reflected elsewhere in the application (namely, on the APENs or processflowdiagram). Do you intend to include a condenser? - A. A condenser is present, however the condenser's main purpose is to recapture and recover water to reduce makeup water. Therefore, the condenser is not a control device. 5) The NOx emission factor for the hot oil heater was eye -popping! The source of the emission factor is sited as manufacturer specification data, but no such data was provided with the application. It appears from the APEN info that a manufacturer hasyet tobe chosen. Because this emission factor is so low (significantly lower than the lowest emission factor ever permitted for a heater in the state of Colorado) I would like to see some sort of manufacturer's guarantee that this emission rate can be achieved. A. Please see vendor guarantee provided in Attachment C along with revised NOx emissions for the facility provided in Attachment A. 7) The NOx and CO emissions from the combustion of the dehy still vent stream sent to the enclosed combustor does not appear to be accounted for in the criteria pollutant calculations. Please supplement the application with this calculation. A. This stream is now accounted for, as shown in the emission calculations in Attachment A. However; please note that DCP is now proposing to route the dehydration still vent stream to the tank combustor as opposed to the RTO. This is due to safety concerns from routing a rich stream such as the dehydration still vent stream to the RTO. DCP has witnessed several uncontrolled detonation events at RTOs that control the dehydrator and is concerned about safety of the employees at each of these facilities. In DCP's experience, the tank combustor is more capable of handling a rich stream. Therefore, DCP is proposing to vent the dehydrator stream to the tank combustor instead of the RTO. Revised emission calculations reflecting this change are provided in Attachment A. The BACT writeup provided in Attachment D also accounts for this change. A revised APCD Form 102 is provided in Attachment B. Revised APEN associated with the dehydrator is provided in Attachment E. 9) The application requests that the new fugitive equipment leaks point be combined with the existing equipment leaks point This is nota problem to combine all equipment on one point, however, you should be aware that parts of the point will be subject to NSPS Subpart KKK and the new equipment permitted under the point will be subject to NSPS Subpart 0000. It is not significant to us whether the points are separate or combined, but I want to offer the option to keep the equipment on separate points if it easier for you. Alternatively, you could chose to have all equipment comply with the newer, more stringent standard, if that is best for you. A. DCP is submitting an APEN with this response that separates the existing fugitive equipment leak emissions from the proposed equipment leak emissions. The APEN for the proposed fugitives is provided in Attachment E. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response • Trinity Consultants ATTACHMENT A EMISSION CALCULATIONS AND SUPPORTING DOCUMENTATION This section summarizes any changes to emission calculations previously submitted in June 2012. Detailed emission calculation spreadsheets, including example calculations, are included at the end of this section. Specifically, this includes: Y One TEG dehydrator (ID D-1); > One RTO (ID RT0); Y Site -wide Fugitive emissions (ID FUG2). The operation of these sources will result in emissions of nitrogen oxides (NOx), carbon monoxide(CO), sulfur dioxide (SO2), particulate matter (PM), particulate matter with aerodynamic diameter less than 10 microns (PM10), particulate matter with aerodynamic diameter less than 2.5 microns (PMzs),.volatile organic compounds (VOC), hazardous air pollutants (HAP), carbon dioxide (CO2), methane (CH4), and nitrous oxide (N20). According to Title 40 of the Code of Federal Regulations (40 CFR) Section (§)52.21(b)(49)(ii), PSD applicability for GHG emissions are determined based on GHG emissions on a carbon dioxide equivalent basis (CO2e), as calculated by multiplying the mass of each of the six GHGs by the gas's associated global warming potential (GWP).2 The GWP for each GHG proposed to be emitted at the Lucerne 2 Expansion is listed in the following table. Table 0-1 Greenhouse Gas Global Warming Potentials C.O2 CH4 N20 1 21 310 The following is an example calculation for hourly and annual CO2e emissions: lb C 02. Hourly Emission Rate ( hr lb\ lb = CO2 Hourly Emission Rate (hr) x CO2 GWP + CH4 Hourly Em ission Rate (hr \ I x CH4 GWP lb + N20 Hourly Emission Rate (—hr) x N20 GWP CO2 e Annual Emission Rate ( tpy ) = CO2 Annual Emission Rate (tpy) x CO2 GWP + CH4 Annual Emission Rate (tpy) x CH4 GWP + N20 Annual Emission Rate (tpy) x N20 GWP GLYCOL DEHYDRATOR The proposed Lucerne 2 Expansion will include one TEG dehydrator (ID D-01) as part of the modification, which will be controlled by the tank combustor instead of the RTO. DCP has several safety concerns with directing a rich stream such as the glycol dehydrator vent stream, to the RTO since it has resulted in uncontrolled detonation at other similar facilities. The tank combustor is expected to have a destruction efficiency of 95%. 2 40 CFR Part98, Subpart A, Table A-1. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants A-1 Emissions from the glycol dehydrator are estimated from the GRI-GLYCalc Version 4.0 Aggregate Calculations Report dated June 5, 2012. The GRI-GLYCalc aggregate file for the dehydrator is provided in this section for reference. -1=125. VOC, and HAP Hourly Emissions Uncontrolled inlet hourly rates of H2S, VOC and HAP from the glycol dehydrator are obtained using the GRI GLYCalc aggregate emissions report. The following equation is used to estimate hourly H2S, VOC and HAP inlet rates to the combustor: lb lb Uncontrolled Inlet Hourly Emission Rate ( hr ) = Uncontrolled Regenerator Emissions (hr) Controlled hourly emission rates of HZS,. VOC and HAP, as controlled by the combustor, are estimated using the inlet to combustor as calculated above and a conservative DRE. The following equation is used to estimate hourly H2S, VOC and HAP emission rates from the controlled streams: lb lb Controlled Hourly Emission Rate ( hr) = Inlet to Combustor (hr) x [1 — Destruction Rate Efficiency (%)J SO, Hourly Emissions SO2 emissions are based on the conversion of sulfur during the destruction of inlet H2S using a mass balance equation for the amount of H2S that goes into and out of the combustor and the ratio of the molecular weights of SO2 and H2S. The equation is used to estimate hourly 502 emission rates from the controlled streams: Controlled Hourly SO2 Emission Rate ( hrIb ) hr lb lb = Inlet H2S to combustor (hr) — Outlet H2S to combustor (hr) Annual Emissions 64.06 lb lb-mol 34.08 lb lb-mol Annual emission rates of H2S, VOC, 502, and HAPs are based on hourly emission rates and maximum operation equivalent to 8,760 hrs/yr, as shown in the following equation: lb hrs ton Annual Emissions (tpy) = Hourly Emissions (hr) x Hours of Operation ( —r ) x (2,000 lb) Y Combustion Emissions The volume of vapor vented is obtained from the GRI-GLYCalc output, Regeneration Overhead stream is assumed to be the amount of vapor that the enclosed combustor can combust. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants - A-2 The heat value HHV (Btu/scf) of this vapor was calculated by using the component mass fractions and individual component heat values. This information is then used with the AP -42 Section 1.4 External Natural Gas Combustion emission factors for NOx and CO to estimate emissions of those pollutants.3 A sample calculation is provided below: lb Hourly. Emission Rate hr lb (scf)Btu = Emission Factor ( MMscf ) x Volume Vented x Vented Gas Heat Value ( scf hr Btu\(1 MMscfl Natural Gas Heat Value (Btu scf I x 106 scf ) Annual emissions are estimated assuming 8,760 hours of operation annually: COY CH4,and N2Q Hourly Combusted Emissions Controlled hourly emission rates for CO2 and CH4 from the combustor are estimated using the inlet to combustor data using the GRI-GLYCaIc output for the Regenerator Overheads stream and a conservative destruction efficiency of 95%. The following equation is used to estimate hourly CO2 and CH4 emission rates from the controlled streams: lb (lb Controlled Hourly. Emission Rate ( hr) = Inlet to combustor (hr I x [1 — Destruction Rate Efficiency(%)] Hourly N2O emission rates are estimated using Equation W-40 in 40 CFR Subpart W for combustion units that combust process vent gas, as shown in the following equation:4 lb N20 Hourly Emission Rate MMscf 1 day 106 scf MMBtu = Vent Gas Flowrate ( day ) x 24 hr x 1 MMscf x Process Gas HHV ( scf ) kg 2.20461b x N2O Emission Factor ( MMBtu ) x 1 kg The process gas higher heating value (HHV) and N20 emission factor are taken from 40 CFR §98.233(z)(2)(vi). Hourly Emissions from Conversion to CO2 In addition to emissions from combusted CO2, CH4, and N2O, additional GHG emissions will result from the conversion of carbon atoms in the fuel to CO2. For sources that combust process vent gas, the converted emissions are estimated based on Equations W -39A and W -39B obtained from 40 CFR 98 Subpart W.5 The following equation is used to determine the COz emissions resulting from the oxidation of methane (compounds with one carbon atom), ethane (compounds with two carbon atoms), propane (compounds with three carbon ' TNRCC Flares and Vapor Oxidizers, Table 4 Flare Factors 4 40 CFR §98.233(z)(2)(vi). 5 40 CFR §98.233(z)(2)(iii).. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response - - Trinity Consultants A-3 atoms), butanes (compounds with four carbon atoms), and pentanes+ (compounds with five or more carbon atoms): Converted CO2 Hourly Emission Rate lb =Inlet to combustor (—hr) x Carbon Count x Destruction Rate Efficiency (%) Annual Emissions All annual emission rates are based on maximum operation equivalent to 8,760 hrs/yr, using the following equation: Controlled Annual Emission Rate (tpy) lb hr ton = Controlled Hourly Emission Rate ( hr ) x Hours of Operation (r) x (2,000 lb) Y REGENERATIVE THERMAL OXIDIZER The proposed Lucerne 2 Expansion will be equipped with one RTO (ID RTO) to control emissions from the amine unit. The flowrates and characteristics for the amine still vent are obtained from the ProMax® output. NOx and CO emissions are estimated using U.S. EPA AP -42 Section 13.5, Table 13.5-1 emission factors. GHG emissions of C02, CH4, and N20 from the RTO will result from the combustion of the amine still vent (ID AU - 02) waste stream. NOx and CO Hourly Emissions Emissions factors for NOx and CO are estimated using U.S. EPA AP -42 Section 13.5 emission factors.6 Hourly emission rates are based on the heat value and maximum amine acid gas flowrate, as shown in the following equation: lb Hourly Emission Rate hr lb Btu MMscf = Emission Factor ( MMBtu x Heat Value ( scf) x Amine Acid Gas Flowrate da ) Y 1 day 24 hr CO2. CH4, and Nz4 Hourly Combusted Emissions Controlled hourly emission rates for C02 and CH4 from the RTO are estimated using the inlet to RTO data using the ProMax® output for the waste stream and a conservative destruction efficiency. The following equation is used to estimate hourly C02 and CH4 emission rates from the controlled streams: 6 U.S. EPA AP -42 Section 13.5, Industrial Flares (September 1991). DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants A-4 lb Ib Controlled Hourly Emission Rate I hr) = Inlet to RTO (hr) x [1 - Destruction Rate Efficiency(%)] Hourly N20 emission rates are estimated using Equation W-40 in 40 CFR Subpart W for combustion units that combust process vent gas, as shown in the following equation:7 lb N20 Hourly Emission Rate (hr) MMscf 1 day 106 scf MMBtu = Waste Gas Flowrate x x x Process Gas HHV ( ) day ) 24 hr 1 MMscf ( scf kg 2.2046 lb x N20 Emission Factor ( MMBtu ) x 1 kg The process gas higher heating value (HHV) and N20 emission factor are taken from 40 CFR §98.233(z)(2)(vi). Hourly Emissions from Conversion to CQz In addition to emissions from combusted CO2, CHz, and N20, additional GHG emissions will result from the conversion of carbon atoms in the fuel to CO2. For sources that combust process vent gas, the converted emissions are estimated based on Equations W -39A and W -39B obtained from 40 CFR 98 Subpart W.B The following equation is used to determine the CO2 emissions resulting from the oxidation of methane (compounds with one carbon atom), ethane (compounds with two carbon atoms), propane (compounds with three carbon atoms), butanes (compounds with four carbon atoms), and pentanes+ (compounds with five or more carbon atoms): lb Converted CO2 Hourly Emission Rate = Inlet to RTO (hr) x Carbon Count x Desruction Rate Efficiency (%) Annual Emissions All annual emission rates are based on maximum operation equivalent to 8,760 hrs/yr, using the following equation: Controlled Annual Emission Rate (tpy) lb hr ton = Controlled Hourly Emission Rate ( hr ) x Hours of Operation ( r) x (2,000 lb ) Y TANK AND TRUCK LOADING COMBUSTOR The emissions from the tanks and truck loading remain unchanged. However, the combustor emissions were modified slightly to use NOx and CO emission factors from AP -42 Section 1.4, External Natural Gas Combustion instead of the TNRCC (TCEQ) flare emission factors. Emissions provided below are updated with this information. 40 CFR §98.233(z)(2)(vi). s 40 CFR §98.233(z)(2)(iii). DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants A-5 EQUIPMENT LEAK FUGITIVES Process fugitive emissions of VOC result from leaking components such as valves and flanges (ED FUG2). Emissions from fugitive equipment leaks are calculated using the fugitive component counts for the proposed Lucerne 2 Expansion, the VOC content of each stream for which component counts are placed in service, and emission factors for each component type taken from the U.S. EPA Protocol for Equipment Leak Emission Estimates.9 The existing fugitive equipment leaks are not being modified and will retain their own APEN. The proposed modification will likely be subject to NSPS Subpart 0000 and will be therefore be subject to more stringent fugitive control requirements under the LDAR program. Accordingly, DCP has selected control efficiencies as applicable and applied those to the equipment leak fugitive calculations. The representative analyses used in the fugitive calculations are obtained from the ProMax® output and can be found below in this section. Hourly Emissions Hourly emissions of VOC from traditional fugitive components (i.e., valves, pumps, flanges, compressors, relief valves, and connectors) are estimated using EPA emission factors, component counts, and the VOC content of each stream. The following equation is used to estimate hourly VOC emissions: Hourly Emission Rate (lb/hr) kg l 2.2 lb = EPA Emission Factor ( hr com 1 x ( x Number of Components (# comp) p kg x VOC Weight Percent (% wt) x (1 — Control Factor(%)) Speciated VOC and HAP emissions from traditional fugitive components are estimated based on the total VOC emissions as estimated above and the speciated gas analysis for each stream. The following equation is used to estimate speciated VOC and HAP emissions for each compound in the stream: Speciated Hourly Emission Rate (lb/hr) kg 2.2 lb = EPA Emission Factor ( hr -comp 1 x ( ) x Number of Components (# comp) P kg x Compound Weight Percent (% wt) x (1 — Control Factor(%)) Annual Emissions Annual emissions are estimated based on hourly emissions rates and maximum operation equivalent to 8,760 hrs/yr, as shown in the following equation: (—hr) hton l Annual Emission Rate (tpy) Hourly Emission Rate I hr I x Hours of Operation (--r) xyr 2,000 lb/ GHG Emissions 9 U.S. EPA, Protocol for Leak Emission Estimates, Table 2-4 Oil and Gas Production Operations Average Emission Factors (November 1995). DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants A-6 Greenhouse gas emissions are calculated using the following equation: rlbl Hourly Emission Rate (1b/hr) _ = VOC Uncontrolled Emissions lhr/ x CO2or CH4 Weight Percent (% wt) DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants A-7 SITE -WIDE SUMMARY • Id O7 • V • W feE FC�F fn• W cu 4 V1 13.4 Controlled Hourly Emissions (lb/hr) 1 ., , a L!) a+ ,-i I Lucerne 2 Expansion .. t. N. c N a [� CO l� ooOc,.0 , OOO o000.-1 000 N , I I 1 o := 0 b ai N O t- 00 N N M In N N O I i - I i : O O 9 I I M I . 7.62 V1 N 0 0 0 N: 0 o N N M r-1 N 07 dt d, M ''I, 1 1 et* in in 9 9"I r.4 u1 1 w . N .41 ri N . M M O O 9 A. W 4 .4. d M o 0 0 w N • N ,n to m N• ri .1 ,-1 N d' M •M 1.23 9O 0 X A. 00 ,..1OOO d; M 1 I , 1 i t tp N' N' koII Cq d r-i N VOC 28.22 rat r -I -I N lA M I el N O 00oe4Ci* OO1+1 cl' M M M 9 p0 O W R1 W W N N O1 00 Mp00 0 CC r CI r-1 ON N 52.76 M 0 V rnrn --I -+ -b 00 M Mi d' 6 0 0 0 O 410 1 ..1. : , Q o 0 `z V7 NON I, O LfiM CO CO N I N N O O 1 M r-i 000 0 O Li.1 O 1 O I I 2, 0 O M 43 Description Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2)' Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D -D1) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Site -wide Fugitive Emissions IA Enclosed Combustor Pilot RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions 07 'a a a+ El SITE -WIDE SUMMARY - CRITERIA POLLUTANTS Controlled Annual Emissions (tpy) I cri get N Ib o R a. N d E Q, or, o N O, O %D+ O N N M IT M , Pn M ry 0 0 0 en n O o O m I 1 I , O 1 , O N tr';= O In n N• H O O, Cr:R, I M , i O O O M a. n .4. O O O W W W , N' n • ,-1 ,-i O r -I M M „ 0. 42 r N N 0 co, W cy 1 1 rS ,—IOO M ...oN 42,qW .O ix: O Ni ,-t 0,O, c Ow No rn N N.Ncz. coIDN I 1 I , : ati ti ri M ,O 9 O 1-i LON , O . 10, O � O N c-i in d' PM SO N N. co. OR N, , ,i . ,-1 r-i M \O W W 1 O I lc, 9o+ • O U7 a N c-1 d' V > co in t`,1 N Q, Q, N co O Cr, c -I .1' V1 It co W M I co M . O O O ,O N H NT. M ,D in O O O .d' I :D COO W W O Da OffO O 1f3 • O 0 c -t ,-1 CO I 49.25 CO 1 231.10 N N , -t r1 N n n O COd 1 n n M O N a a e -t N rl L O w , ,�-t a ' O, ,O • co in H y NOx 201.34 Ln Ln O:O; T, NON. O O `maM 0000 .1--4 Li.) O W I ,^1 0 O e , N N O M G O ti, Q Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D -01) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Site -wide Fu tive Emissions Insignificant Activities Endosed Combustor Pilot RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions SITE -WIDE SUMMARY - HAPS Hourly Emissions (16/hr) Total Existing Emissions I 0.12 I 0.06 I 0.00 I 0.03 I 0.42 0.12 0.12 7 -0.03 -� 1.05 I 0.00 1,95 Lucerne 2 Expansion COO ooee..000P0 eee m e sN I 1 1 1 1 a E7 a N N L ., I :Ili I,I 1/1 „ E O 0 t o ro o d 6E, o 000 m 2. min 0 tn 6 < G < a L 0 0 Q Acetaldehyde Ni ry ui D S 0 ,42., 1 1 1„ l l m o "o N.'.': 0 e N a 0 m 0 0 w 0 N 0 0 N a N N ...... , m in in o 0 t o t'. L. o o m0„ rj I .. e e E m�t•-:.. o 0 omm �n o 0 qo :r - N O M IA .+ Combustion Turbine 1(TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) RTO (ID RTO) Storage Tanks LID TANKS) - Truck Leading (ID LOAD) Site -wide Fugitive Emissions Insignificant Activities Enclosed Combustor Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Modification Emissions Post Modification Total Emissions Description a' 1 C OEC- R O n a 6 a a a 0. n O a 0 a • 0 iTt O a N a aa a O II La x • q tY `G a a' x '1 X C V -Cf O. O T �1 O b m 0 a 9 P • F. a 0 O O O' II v a' ti Example Controlled Ethane Hourly Emission Rate (Ib/hr) _ 11 L1 N C VOC HAP anoK [n O coma }' a o a o al `? � ' a r, 'o i g n c r Ry a d R 7 m 1 0,ga g srg n a Lee 7 C aa. co Compound .D .D N in .D .D .O .O .D ‘o .D .D .O .D .O .O .D .D Ui In N UI VI V1 V1 In Ln Ul U7 Ln en V1 r• k O 86.91 33.73 F.' I--` O o N to to .A ,p :. ,.Cr o O i,-.1 W T i..,O b 'a :4..D N LJ P1 co O. 01,,,,,,,,10,C00,01,,,6, N V O. m O Ln m N , p • • "�' y Inlet to Combustor Z'4 380.65 147.72 F. ? O. N N N O. NCO ,p W Ln U1 N co . P D. en so W. N Ln N co b.:o co ,4 4. O c :I k) L• to oo h7 m W 'P Ln N'11 .D LT V O F-• N o p •". 'a v I-' .P .O VI 441 O O o 0 0 0 o 0 0 0 0 0 0 0 Cr, V W N CD 0 0 .D N N L�n co N 6 o c v./ • Controlled Combustor Emissions 3'4 I V N LJ W .D c O O O N Ui 0 Ir I••• O W F•' :A N p.l LS I-• N :P .P W N LD 14 O W N m Lb O N N N 4 .D LT V .a o D. O Vi K "O ▪ v IIIJ Oa O c- c a. 1n II ^ ro T h • CJ • O N to cr IA a a n a a a EMISSION CALCULATIONS FOR GLYCOL DEHYDRATOR S 0 = ro a fA ` 'C'J m' • D — z�" z ❑' o y N a � w ro YJ � ❑. _ .❑ m a o a w g o ❑ O N °f x ❑ ❑ N Na 2 ❑ R C a w O R N 0 O O • V N w O 7 ro v D N o I- - ti w 0 • 9 w w o < H # rD N N � 7 £ � o `1 1 o n a n S Dj b �^ o • rD R. w n N CO o • 't n • �• T • m Er R • m a N O 0 0 7-1 z o' o O N a � a cr 'O :71n• N 0 w o' N 0 • 7 N � DJ ❑ 0 N N a P 0 P u n N H .ao o Fs ry n o s a oa. yn n ❑ 0 3 N W rt a MC O `GT w _ n 'O a D a a n N vow a° C a N 'n G n ❑ 't K. m 3 xo a w w 5 0 ' S a w -oi y ;go c m as m o z Tom. of EO X C C 0 N O al , O m y M < a fD w co t1 m 7 n O O ▪ •_— R N o Q C ❑ O A V m w R N F- ro [ Q -1 �n ^T N N ry `❑I O d`< N '0 • O m m •a n E. C Q O o C • g a o 0 a o z ~ D x r 0 < 0 n N O N ^Off m w • CD g Z w N a 70 N 't O C N C N !� If w 0 C CD Is the project above NNSR SERs? NNSR SER 4's Is the project above PSD SERs? EPSD Significant Emission Rates (SER) 3,4 Is the site above NNSR limits? Nonattainment New Source Review (NNSR) Limits Is the Project above PSD major source threshold? J Prevention of Significant Deterioration (PSD) Ma -or Source Threshold D O O y 0 NO NO -- NO NO NO NO YES I co O Zr Y N r r i tit Or O 0 Z O "' 0 O r r ".E m y 0 4 i r Z 0 N ul r I N N 0 r 2 0 Y 1n 0 N 0 r Z 0 I-, O r N 1n 0 r Z r i N N 0 0 0 r i r V N O O a . i Y 0 0 O o O 5 .or w C C O y a z 01 N ITotal Modification Emissions Enclosed Combustor Pilot RTO Pilot Emergency Flare I Insignificant Activities (Non -fugitive) Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID 0-01) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading,(ID LOAD) ILucerne 2 Expansion i O N. x N C OD 3 N 0 C N Description I 39.62 • Annual Emissions (tpy) 0 0 0 V CO 0 0 0 0 w .O OV ON ! '!' N 0 Y W Z 0 to cliff P N cri N O Cr, 0 0 0 N O W V V N W n Lc O 1••. [r1 O m O N 10 , , O O V V N V. I-, Y CO 0, N V IY V V • Y N O 0 CO I-• Y VOC PM . P " to O N [r1 tq K1 N N N 1 ` 0' O O P W W i w CD CO U1 in O `o 'P O O O w O+ w p-. ND O CO V .O sO CO O ? 2.00E-03 1.52E-06 1.24E-02 r• F-• F+ V \D I I I r N CO CO 0 1n O V V O• Y Y NJ . 1O 4, N 0 0 RIM m Y Y Y r , , r 'NOM V ;-0 'O M in O O O a V V 0. c N O. W Y Y N PM25 :P LI •P N O m c?s to C ,- NJ r r 1 I r N o bo V 0 0 0 O V V C' N C' W IDD W to I-, 1.58E-04 1.20E-07 9.76E-04 FW+ 0 0 0 , r G, , r o 50 10 O O 01 O. N in V y 0 N N ,P K W • . Y Y W W N to O W W co P 82876.52 O V O M 11;• co N N .p r P r W m, Ln O. 0s Co CO W V V 0 Ito N •+ ~ in m W N N A W Cr. •p a SITE -WIDE SUMMARY FOR PSD APPLICABILITY 0 co 0 DC a 0 EMISSION CALCULATIONS FOR RTO COMBUSTION RTO (ID RTO) RTO Combustion Emissions a 2 r m X o N 0O 'C CO n H r C6 a co II 5 L 0 p C a a^ Q o o � E 0 C x 0L_,`" Co RTO Combustion Emissions CC a E V RTO Emissions 2E N N • N PC: 'r '0 O o to o L O O a 'D 'CO v a a a 0 O or 0 Z U m N \ m O O Li U a N N C 2 a • O N a a a a 'b0' o > > ▪ Co a o m xv x h m 0 4 Lr, C a E Q \ m02 072, ` E C N W m an' c °0• `R a o y 1.5` . 5 b y G L O O 0 c "' v P - II 0.' T ✓ x m E N Fri O Example NO, Hourly Emission Rate (Ib/hr) L 0 O 0 Example NO, Annual Emission Rate (tpy) __ T L. .0 2 Emissions from Conversion of H5S in Amine Unit y ao 0 M m Ln N m ti Cr; b H U CC Hydrogen Sulfide Amine Unit .0 n C. yz" O No � E u � a= 2 E o a • L • E 00 'O 6 O C o 'C m � S Ed - O F II a \ .0 4-0 C G a E iyino a IIFA 0 i E. • ➢ O v o C 0 O o E E w ✓ O C O 0 p 0 V o a U O a a RO t C ^ ry 64.06 Ib/lb-mol 34.08 lb/lb-mol .0 0 Na? V J E W �^ u° E u c u r- GI-IG CALCULATIONS FOR RTO COMBUSTION E tr 5 p E ,r a e a 3 E,m M e Controlled CHC Emissla ns a,s llb/brl 1tPV). II SS II e m e ol' m m m m m gem e�m ee ea Number of Carbon Moms u o Carbon Dioxide Methane Echoes Propane Butanes Pentanes+ C0r° CH4g N00 ro EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR es s ° L A Input for Enclosed Combustor Emis Loadout Input Value Loadout Input Units 92,312.8 lb/yr 66 lb/Ibmat 1,398.7 Ibmol/yr 519.67 "R 14.7 psla 10.731 530,601 sd/yr 530,601 scf/yr 8,760 hr/yr 60.57 scf/hr Tanks Input Value Tanks Input Units 9,470 lb/yr/tank 66 Ib/Ibmol 143.49 Ibmol/yr/tank 519.67 it 14.7 psla 10.731 54,434 scf/yr/tank 8 tanks 435,475 sd/yr 8,760 hr/yr 49.71 scf/hr i. it E al Total Emissions' Vapor MW 2 Molar Emissions; Ts Ps • R Volume Vented • No. of Tanks Total Vented Volume Hours of Operation Total Hourly Vented Volume 6 A. O. .9 C O w L 3.b n E. 190 0 m °, O1M m o ,- u�i ,p n d ^ d G OL 0, m 0, to C •z EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR 0 0 0 Z 4 fi 0. 0 0. a L E � A v U 9 Ei C u x 9 E a w . Q Component Fraction Heat Value (Htu/sci) d'yMmti ml.^y.o d O 9 N 0 N Pure : Component Heat Value. (Btu/scf) O ry m 0. d. 10 m on N ; NO d co co M Y d [' M v) M VN Component Mass Fraction 000071.₹0000Mrymm d' P W Y:W d' on on m Component Fraction Mol Weight (1b/lb-ma I) o creme < H e mm .O N N Component Molecular Weight (lb/lb-mol) NmM°° mP-a ,.N Mol Fraction N d r ti;;mm0 e m o m o N.ti N 00N. C C °o. G � t ➢915 c G G v v ➢ m d a 2 i. ry m a 0 • 0 U rC U - 0 9 C J EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR 0 .O O O A N 3't cgs ea 4 B Z C 0>, O U N❑ g NI o O or o r O O , 6 E I0 To Q Z 1r o O O 4 O O p ,..)1' 0 .e. it v .-,`-I O o O o O N O w 0 .y ML 0 z'" i` r O 0 OOO N 0 N O O O N N O Hours of Operation (hr/yr) O r 4 4. O O W N r N. W CO Heat Input (Etu/scf) M. M 3,397 120 Input Flowrate (scf/hr) 1 49.71 1 r o o r t=i I TANKS o A Description Tanks Loadout Dehydrator Gas Total 0 O. C v z c7 13. z x N .0 0 IL C O E x C G e .0 0 II .O 0 x P ` m 3 m ti Ja h r a O a p E 0 .4 0 0 .O • a t 0. m O O Example NO, Hourly Emission Rate (Ib/hr) _ C O 11 0 c O y 0 a o O C 1.69E-02 lb Example NO, Annual Emission Rate (tpy) _ .O O N .0 SO2 Emissions from Conversion of H2S in Dehydrator O N 0 OR N O N O • C 6 U O' Hydrogen Sulfide O 1-4 5 C 0 O C N C 0 0 8 0 ti 0 S c U 0 0 m C .O t 111 N 11 64.06 Ib/Ib-mol [1.00E-04 -5.00E-06] lb Controlled SO2 Hourly Emission Rate (lb/hr) .O Tanks, Loadaut and Dehydrator Combustor (ID TANXS, LOAD, D-Oi) 8 a 3 O 4 2 t m. RRu.e. 1a`N'�`a ..i M M n n R g m 74, o e N C V ^ e M e a i" w e ce G a M n R } m v, ro P 3 2 . pp\r O O C Number of Carbon Atoms „m M S v t e O a tai F s + Ci .'4'2E 22&Bs o uwaE m'e.0 u z v S E e • C A 5 s 9• N R q a s 5 2 , 8 2 2. tl M • 3 m a a d• e oM A n O z • x E x soot g.a o it g u' : °xa % • a o p R M u 2 N 9 d _ g o n Y1' ; z 9 K e A >i + s S W u � p N U N m K O t I= c C .11.2..' • C oD O .- wQ k e- a x• g i• ,i o.t^o %o e N n g A. A l e C m .a• N .C �eU F- L b cF ,.9.1", y^v T a ^v Zo .%n 2 o a t,i= M B G .' N 4 « w R Um C X 3 E a E " o' 3= o° P u s GHG EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR U Converted to CO2 °.e ,- 9. M1 O m D IN NPui .. .... w t n m °•O N m n % O_ p N 1,193.63 5,220.08 (lb/hr) 4.04 19.65 55.90 75.75 224.95 Controlled 6113 Emissions (lb/hr) (tpy) 0.00 0.00 0.21 0.93 Inlet to Combustor (lb/hr) 0.00 4.26 10.34 19.62 19.93 47.36 o " • Number of Carbon Atoms n N M * in 3 4 Carbon Dioxide Methane Ethane Propane Butanes Pentanes + ."..`'...0 G V V Z y V E b 8 3 a JJ N O n 3 — my \ p arc ▪ w 3 c O • Q3 9 � w X ,+1 L• w lit".4 °m — .h f .4 V 5 '67 w u N p rJ j e • a' 'A...'A...V y A o a o •� X T a v c E O D x C v � 'R m r• 7 ry M o n \ o E _ "3 u e % 9 C c $ o ° l l E 5 Z 0 o I.Ei N E U 8 w -v C n a� T n o 1 •E ° Y 3 'o u u 2 n O y 7 L ▪ V ▪ U V b ' h " a • C y O P ' a o E C U E .9 E p Y V a T u u 'o 0 o u` S ° Z 13 13 t;2. T still valid trrarhe men recmiTtlev rmnrW aYnflcallon } d; l .i 11 3 / aRw G§§955 ! c �.la.7 §!!§!! n !! 84/5535555 f- _ ) 5 ;.geg 1 a&\q§§ 4 s 5525 ! }i !!!B!§ |. !) it )A!, ' / 5559!| I..;§� 3! I» Nk§§! . 'ik §§ !||!!! I }/\$/ � . 4 i\ /-, - - ,E,� ■E 4§::,,._ . ew/!E\5§| fi e e535 E : ; §. !© ;zi !,Q ®® !e 5 glb;/[ :; §\ §■ wRgawg§ q \ ! j!1 '. Q / g } !J / z,.=: .. ;.«.� |f - ! | ! ! EMISSION CALCULATIONS FOR FUGITIVES 1 !>e5GReee§e!!E!! ) > !a :,EE1;;Z!! ,!■!! ,;;�,.,,,,,.., !§ ;§ ! . § !Ili . ® li7k' A i 2 j. i i/e /it /s';8lh! L> ! }}Sge/5©oo©!§§§e! B§!,R§l;E11!!! ,! |! /2c .•.,;, /!k §|§§■!!•;,: �' !k }; ! , D !! 5 ! /;I I ;iifl/ lls.kl,.=...��26 � tg \A SEW Hk f ) - |§ !! \� || | I §§ ATTACHMENT B - FORM APCD-102 Facility Wide Emission Inventory DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants B-1 lii Form APCIP-102 iII1111111==1111111! 1111111 11111x= 11111111 IlDaeevae°a1s 111 I la aloui °1=====I `111111111 111111 111111 0 1111@ 111 1111111 II 111111 111111 ..=.1 ;` H1I 11111! -111111. 111111Fl _ �i ■II € ri�000000000� o+ =11=11-111' iuuu'e ool"Ilc wq�'m_.m 1$'191116 ��` 11111 _ 119999 99� e '991= 1191 111111 1111111 a e !P= ! !!!! !!!!!! 111 f t Il ll 1111=l =11 c 1111111® X111 II I°ooells 1111111/ 9 1leeeee°aee-e = 1111111= 1111114 clle epee° p1111 l 11 111111® Ileeeee e ea 1I II I 111111 pee Ba cep ;i 1 11 t c111111 _ 11 aoo Iola 1111111 111111° _ mmmmmm mm 4 0 o mm m mmm a mmmmmm mF. 1 acle I c=1 l III _ nl 1111111 II11111-11� 11111 I II 111111 _111..IM.,:,n.a _.1111111111 111111 §113$13 F 1= = IIII 11= 1111111 s Ills=a 11 =III.1$11� 111111 mmmmmmmmmmm -=mm mm mm mmmmmm = Illl lHI In l -=1 111111 I III c c a _ t t 11====a====1 'VIII II II 111111® = = s9. 11 1 1111= 1111111® ll e= 111111® 111111 P ll =11111= 111111 = 11 =-1 111= 1111114 = 11 -111I�1111 illllll ; _ .i cl nri w xe rl _6 n.i _i 36'ty .. �"6GCC6CGCn' a ` ATTACHMENT C - NOx EMISSION FACTOR GUARANTEE DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants C'1 OPTIMIZED PROCESS FURNACES, INC. 3995 S. Santa Fe P. O. BOX 706 I CHANUTE, KS 66720-0706 PHONE (620) 431-1260 FAX (620) 431-6631 March 11, 2013 Jeff Ross Director, Project Development Engineering/Chief Corporate Office DCP Midstream Gentlemen: OPF routinely utilizes the latest burner emissions technology in our direct fired heater products. Our typical installation uses Ultra Low NOx natural draft burner technology to reach 'NOx emission levels of as low as 0.025 #/MM Btu. These burners used staged fuel gas combustion and internal flue gas recirculation within the firebox of the heater. Regards, Rob Phillips President OPTIMIZED PROCESS FURNACES, INC. Telephone: (620) 431-1260 Fax: (620) 431-6631 E-mail: phillipsr@optimizedpf.com ATTACHMENT D - GHG BACT ANALYSIS This section addresses CDPHE's concerns on certain aspects of the BACT analysis. Specifically, the Carbon Capture and Sequestration section is rewritten. Additionally, the dehydrator still vent is routed to the tank combustor instead of the RTO and this is discussed in the relevant section. GHG BACT REQUIREMENT The GHG BACT requirement applies to each new emission unit from which there are emissions increases of GHG pollutants subject to PSD review. The estimated emissions increase of GHGs from the proposed project will be greater than 100,000 tpy on a CO2e basis primarily due to the removal of CO2 in the amine unit which is emitted when the process gas streams are combusted and released by the RTO. The units discussed in this writeup do not include unchanged units. The following emission units are discussed: Amine Unit; > TEG Dehydration Unit; and > Regenerative Thermal Oxidizer (RT0); The following guidance documents were utilized as resources in completing the GHG BACT evaluation for the proposed project: > PSD and Title V Permitting Guidance for Greenhouse Gases (hereafter referred to as General GHG Permitting Guidance)=° > Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and Industrial Boilers (hereafter referred to as GHG BACT Guidance for Boilers)" > Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from the Petroleum Refining Industry (hereafter referred to as GHG BACT Guidance for Refineries)12 GHG BACT EVALUATION FOR PROPOSED EMISSION SOURCES The following is an analysis of BACT for the control of GHG emissions from the project following the EPA's five - step "top -down" BACT process. The table at the end of this section summarizes each step of the BACT analysis for the emission units included in this review. Table 1 provides a summary of the proposed BACT limits discussed in the following sections. ID U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, (Research Triangle Park, NC: March 2011). http://www.epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf 11 U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, (Research Triangle Park, NC: October 2010). http://www.epa.gov/nsr/ghgdocs/iciboilers.pdf • 12 U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, (Research Triangle Park, NC: October 2010). http://www.epa.gov/nsr/ghgdocs/refineries.pdf DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-1 Table 1. Potential GHG BACT Limits for Lucerne 2 Expansion Source Proposed' BACT Limit Amine Unit 3,702 lb CO2e/MMscf (wet) TEG Dehydration Unit 9 lb CO2e/MMscf (wet) Regenerative Thermal Oxidizer (RTO) 3,677 lb CO2e/MMscf (wet) Combustor 125 lb CO2e/MMscf (wet) The detailed BACT analysis conducted for all other CO2e contributors is not being resubmitted with this response since they are still valid from the June 2012 submittal. AMINE UNIT The amine unit at the Lucerne 2 Expansion will be used to remove CO2 in order to meet pipeline quality natural gas specifications. Because the amine unit is designed to remove CO2 from the natural gas, the generation of CO2 is inherent to the process, and a reduction of the CO2 emissions by process changes would only be achieved by a reduction in the process efficiency and would result in more CO2 in the gas which would be released downstream. The available control technologies for the amine unit are discussed below. Step 1 — Identify All Available Control Technologies The available GHG emission control options for the process emissions: > Carbon Capture and Sequestration > Flare/Combustor > Thermal Oxidizer > Condenser > Proper Design and Operation > Use of Tank Off -gas Recovery Systems Carbon Capture and Sequestration As CO2 separation is one of the primary objectives of the amine unit, the amine regeneration unit produces a gas stream with a high CO2 content compared to a typical exhaust stream from a combustion unit. Accordingly, CCS is one possible option for control of GHG emissions from the amine regeneration unit. It is assumed CCS would sequester at least 90% of the CO2 from the source in question. An effective CCS system would require three elements: > Separation technology for the CO2 exhaust stream (i.e,"carbon capture" technology), 9 Transportation of CO2 to a storage site, and • A viable location for long-term storage of CO2. These three elements work in series. To execute a CCS program as BACT, all three elements must be 'available' for this project. Geologic sequestration of CO2 can be achieved by one of two methods: (1) CO2 can be used in DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-2 Enhanced Oil Recovery (FOR) projects, or (2) a well dedicated to CCS (i.e., a Class VI well) can be drilled and permitted. FOR technology enhances oil recovery rates by reinjecting CO2 and hydrocarbon gases recovered from the well (and CO2 from external sources, as needed) into the geologic formation to maintain well pressure. This technology is designed to maintain pressure in an active well, rather than for the long term sequestration of CO2. Consequently, EOR projects are not designed with the same considerations for permanent CO2 sequestration when compared to Class VI wells intended specifically for CCS. While EOR has been commercially demonstrated EOR cannot be considered an available technology in this BACT assessment for the following reason: The DCP Lucerne facility is not designed to perform FOR. If DCP sold CO2 as a commodity to EOR injection fields, the lifetime of the contract(s) must equal the lifetime of the facility; else FOR would not be a sustainable control option for the DCP Lucerne facility. This would pose significant logistical challenges, such as matching the relatively constant output of CO2 at the facility to, the varying CO2 demand of an FOR system. As EOR operation continues and the CO2 content of a formation increases, more CO2 would be recovered from the well(s) for reinjection, resulting in a declining demand for supplemental CO2 from external sources over the lifetime of a given EOR project.13 Therefore, FOR cannot be considered as an available BACT technology. For th reas OR is not considered an available technology for the permanent sequestration of CO2 from the DCP Lucerne acility. However, to ensure that the option to use CCS technology to capture CO2 emissions from the Lucerne facility is thoroughly evaluated in this application, discussions of the technical and economic feasibility of CCS are presented in Steps 2 and 4 of this BACT analysis, respectively. DCP conducted research and analysis to determine the technical feasibility of CO2 capture and transfer. Since most of the CO2 emissions from the proposed project are generated from the amine unit, DCP evaluated potential options to capture and transfer the CO2,from the amine unit still vent, to an off -site facility for injection. Based on the results of these studies, capture and transfer of CO2 from the amine treatment unit is technically feasible. A study was performed to evaluate the potential options for capture and transfer of CO2 from the Lucerne Plant (located near Greeley in Weld County, CO) to nearby CO2 injection wells. The transfer of the CO2 stream would require further treatment to remove contaminants and compression for transfer via a new pipeline. Since capture and transfer of CO2 for off -site transfer is technically feasible for the proposed project, this option is further evaluated for energy, environmental, and economic impacts. Flares/ Combustor One option to reduce the GHGs emitted from the Lucerne 2 Expansion is to send stripped amine acid gases to a flare or a combustor. The flare is an example of a control device in which the control of certain pollutants causes the formation of collateral GHG emissions. The control of CH4 in the process gas at the flare results in the creation of additional CO2 emissions via the combustion reaction mechanism. However, given the relative GWPs of CO2 and CH4 and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional CO2 emissions. In general, flares have a destruction efficiency rate (DRE) of 98%, resulting in minor CH4 emissions from the process flare due to incomplete combustion of CH4. 1, MIT Laboratory for Energy and the Environment, The Economics of CO2 Storage," August 2003, P. 37. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-3 Additionally, the flare requires the use of a continuous pilot ignition system or equivalent that results in additional GHG emissions. Thermal Oxidizers Another option to reduce the GHGs emitted from the Lucerne 2 Expansion is to send stripped amine acid gases to a thermal oxidizer (TO). The TO is an example of a control device in which the control of certain pollutants causes the formation of collateral GHG emissions, the control of CH4 in the process gas at the TO results in the creation of additional CO2 emissions via the combustion reaction mechanism. However, given the relative GWPs of CO2 and CH4 and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional CO2 emissions. A regenerative thermal oxidizer (RTO) has a high efficiency heat recovery. This allows the facility to recover heat from the exhaust stream, reducing the overall heat input of the plant. In general, TOs have a destruction efficiency rate (DRE) greater than of 99%, resulting in minor CH4 emissions from the process flare due to incomplete combustion of CH4. In contrast with a flare, which requires the use of additional fuel to maintain a constant pilot, a RTO only uses additional natural gas to get up to the optimum temperature for combustion resulting in lower use of assist gas and lower GHG emissions due to pilot burning when compared to a flare. Condenser Condensers are supplemental emissions control that reduces the temperature of the still column vent vapors on amine units to condensate water and VOCs, including CH4. The condensed liquids are then collected for further treatment or disposal. The reduction efficiency of the condensers is variable and depends on the type of condenser and the composition of the waste gas, ranging from 50-98% of the CH4 emissions in the waste gas stream. Proper Design and Operation The amine unit will be new equipment installed on site. New equipment has better energy efficiency, hence reducing the GHGs emitted during combustion. The new equipment will operate at a minimum circulation rate with consistent amine concentrations. By minimizing the circulation rate, the equipment avoids pulling out additional VOCs and GHGs in the amine streams, which would increase VOC and GHG emissions into the atmosphere. The amine unit still overhead stream will be controlled with a condenser and an RTO with a 96% DRE.14 The unit is equipped with a flash tank for recycling off -gas back to the plant inlet, including CH4, from the rich amine stream prior to regeneration, resulting in a reduction of waste gases created. Use of Tank Off -gas Recovery Systems The amine unit will be equipped with a flash tank. The flash tank will be used to recycle the off -gases back into the plant for reprocessing, instead of venting to the atmosphere or combustion device. The use of flash tanks increases the effectiveness of other downstream control devices. EDiC kW -2, Puo( (CS Step 2. Eliminate technically infeasible options The technical infeasibility of CCS is discussed below. CCS has been classified as an unavailable. contro- 1 > technology in Step 1, but voluntary analysis of the technology through Steps 2 and 4 of this BACT analysis is also provided to demonstrate its technical infeasibility and extreme costs. All other control technologies listed in Step 1 are considered technically feasible for implementation at the Lucerne facility. 14 The actual DREof the RTO is 99% per the manufacturer. For conservatism, DCP is applying a tower DRE of 96%. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-4 Carbon Capture and Sequestration As explained in EPA's 1990 Draft New Source Review Manual: "[I]f the control technology has been installed and operated successfully on the type of source under review, it is demonstrated and it is technically feasible. For control technologies that are not demonstrated in the sense indicated above the analysis is somewhat more involved." "Two key concepts are important in determining whether an undemonstrated technology is feasible: 'availability' and 'applicability.'.... a technology is considered `available' if it can be obtained by the applicant through commercial channels or is otherwise available within the common sense meaning of the term. An available technology is 'applicable' if it can reasonably be installed and operated on the source type under construction. A technology that is available and applicable is technically feasible". 15 Geologic CO2 storage is not a feasible technology becaus 02 storage sys are still in the testing-phase_.ef development by the US Department of Energy (DOE). Until this testing is compete, geologic carbon storage is not considered to have been operated successfully or, therefore, available. Carbon sequestration poses a number of issues before the technology can be safely and effectively deployed on the commercial scale. For example, the following items still need to be proven and documented on a large-scale (greater than 1 million metric tons CO2 injected). > Permanent storage must be proven by validating that CO2 will be contained in the target formations. > Jechnologies and;_protocols must be d-e_v_elopec .tcZquantifkpotential releases and to confirm that_the' projects do not adversely impact underground sources of drinking water (USDWs) or_cause_CO2-to be releasedI t e sphere` > Long term monitoring of the migration of CO2 during and after project completion must be completed. Methodologies to determine the presence/absence of release pathways must be developed. > Effective regulatory and legal framework must be developed for the safe, long term injection and storage of CO2 into geological formations. Large-scale sequestration projects using carbon sequestration are at the ey r eaErl sytages.of.testing and development It is still unclear, at this time, what the long term outcome of these projects will be. The National Energy Technology Laboratory (NETL), which is part of the DOE's national laboratory system, is currently working on (and in some instances economically supporting) a number of large-scale field tests in different geologic storage formations to confirm that CO2 capture, transportation, injection, and storage can be achieved safely, permanently, and economically over extended periods of time. However, according to the NETL, carbon sequestration technologies will not be ready for commercial deployment until 2020.16 Hence, such technologies are not considered available or technically feasible.17 Although the Lucerne 2 Expansion is not expected to have 1 million metric tons of CO2 emissions, the concept of storage in geologic formations will be the same. 15 U.S. EPA, Draft New Source Review Manual, p. B.17, 1990. r16'NETL, "Carbon Sequestration Program: Technology Program Plan," DOE/NEIL-2011/1464, February 2011, p. 10. "The overall t ,objective of the Carbon Sequestration Program is to develop and advance CCS technologies that will be ready for widespread commercial deployment by 2020. To accomplish widespread deployment, four program goals have been established... Only by accomplishing these goals will CCS technologies be ready for safe, effective commercial deployment both domestically and abroad beginning in 2020 and through the next several decades." _ 77 See "In re: Cardinal FG Company," 12 E.A.D. 153 (E.A.B, 2005) ("[T]echnologies in the -pilot scale testing stages of development would not be considered available for BACT review"), quoting from EPA, Draft New Source Review Workshop Manual (Oct. 1990) -at B-18). DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-5 Step 3. Rank the technically feasible control technologies by control effectiveness CCS (i.e., sequestration or transfer of CO2) is the most effective control option for the control of the CO2 streams from the amine unit, since it provides approximately 90% CO2 control of the amine acid gas stream, based on literature review. Other control technologies do not destroy or reduce the amount of CO2 produced by the amine unit Therefore, given the relative GWPs of CO2 and CH4, 1 and 21 respectively, and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional CO2 emissions. A RTO has higher potential destruction efficiencies compared to flares, 99% and 98% respectively, and uses less pilot gas fuel, resulting in overall lower GHG emissions. The implementation of good combustion, operating, and maintenance practices; and the use of condensers and flash tanks for off -gas recycle are technically feasible control options for minimizing GHG emissions from fuel combustion and waste gas streams, respectively. Step 4. Evaluate most effective controls The only technically feasible technology listed in Step 3 that may have additional energy, environmental, and economic impacts is CO2 capture and transfer. While the process exhaust stream is relatively high in CO2 content, additional processing of the exhaust gas will be required to implement CCS: These include separation (removal of other pollutants from the waste gases), capture, and compression of CO2, transfer of the CO2 stream and sequestration of the CO2 stream. These processes require additional equipment to reduce the exhaust temperature, compress the gas, and transport the gas via pipelines. These units would require additional electricity and generate additional air emissions, of both criteria pollutants and GHG pollutants. This would result in negative environmental and energy impacts. As_part of the CO2 transfer feasibility analysis, DCP reviewed currently active CO2 injection wells.18 This document provides the details of registered wells and permitted fluids for injection. Based on the aerial distance from the proposed Lucerne 2 Expansion, the nearest CO2 injection well is located at approximately 1, 0 mil . A map of the location of the proposed Lucerne 2 Expansion and the nearest well was submitted with the June 2012 application. Review of the map will demonstrate that a CO2 transfer pipeline laid straight from the Lucerne Plant to this well would need to pass through Denver and Colorado Springs, which is not technically, economically, or environmentally feasible. Therefore, the actual length of a transfer pipeline would be much greater tha miles. For cost estimation purposes, a pipeline length of 150 miles is used to be conservative. The cost of pipeline installation and operation are obtained from the National Energy Technology Laboratory (NETL)'s Document Quality Guidelines for Energy System Studies Estimating Carbon Dioxide Transport and .Storage Costs DOE/NETL-2010/1447. Per this document, the pipeline costs include pipeline installation costs, other related capital costs, and operation and maintenance (O&M) costs. A copy of this document was previously included to provide additional details and assumptions in this study. Using the cost estimation methods from the NETL document, the cost of capture, compression, and transfer of CO2 via a 150 mile pipeline was estimated to be approximately $71 per ton of CO2, and $42 per ton of CO2 for a 18 Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Rocky Mountain Region http: / /www.fe.doe. gov/programs/oilgas/ publications/eor_co2/Rocky_Mountain_Basin_Document.pdf DCP Midstream LP Lucerne 2 Expansion CDPHE Response Trinity Consultants D-6 In addition to bei economically infeasible, installation of CCS will also increase energy demand by approximatrly'15-i30 In addition to increased emissions from the additional equipment, the addition of pressor rll-dr ve the emissions of other pollutants, such as NOx and CO, up and will also contribute to )1T.1); j making the project PSD Major for NOx due to emissions increasing above the PSD major source threshold. 19 Al-Juaied, Mohammed A and Whitmore, Adam, "Realistic Costs of Carbon Capture" Discussion Paper 2009-08, Cambridge, Mass.: Belfer Center for Science and International Affairs, July 2009, Abstract, p ii, http: / / belfe rcen ter. ksg.harvard.edu / files/ 2009_AlJuaied_Whitmore_Realistic_Costs_of_Carbon_Capture_web. pdf 20 $50 million based on best engineering estimate for the units required. 21 Prospects for Carbon Capture and Storage Technologies http: / /www. rff.org/documents/ RFF-DP-02-68. pdf 'i IXri' e_`:PS 1. ' 15 mil e le peftne with equipment costs included. A detailed cost analysis is included at the end of this ."----Attac-hthent. The cost estimation does not include additional capital costs incurred to compression equipment and other process equipment such as cryogenic units. Q (S C: S° t \ n^trI r. Therefore, based on the pipeline transfer cost, although technically feasible, off -site transfer is not regard -e able-e-r-eso_norni,call easib0 control option. Additionally, CO2 capture and transfer would havnegative environmental and enegy impacts, as discussed above. The CO2 can also be transferred to FOR pipelines closer to the area that the facility is located in. Carbon capture costs have been estimated using published articles and government resources in the absence of cost data or specific technology details for the capture of C02. As stated earlier, due to the uncertainty in technology, it is anticipated that a first of a kind installation (FOAK) as in the current case, would lead to substantial increase in cost when compared to a Nth of kind (NOAK) installation.19 Estimated additional equipment that would be needed to be installed at the plant to compress the amine stream into a pipeline would include: > Approximately>2000 hp motor • A fan cooling unit > MCC building for electric switchgear > Suction scrubbers on each compressor stage and a final scrubber • Sampling equipment • Controls/Instrumentation > Glycol Unit, contactors and regeneration units with VRU to dehydrate the CO2 stream since the amine unit is upstream of the dehydrator > Additional power and building costs. A conservative estimate on the cost of equipment for the above purposes is assumed to be $50,000,000.20 The cost of transportation to the closest pipeline (assuming 15 miles away) was calculated using the NETL method. The net cost of transfer (including materials, labor, miscellaneous, right of way, interest rates) was estimated to be roughly $ 1.5 million/yr as shown at the end of this section. DCP estimates the net capital cost for the project is equal to about $200,000,000. The capital cost for DCP's Lucerne 2 Expansion and the expected CCS capital cost were both annualized. A ratio of the CCS capital cost to DCP's project cost was taken to determine the additional amount that DCP woul to invest in order to successfully implement CCS. The project specific ratio is determined to be rough 34%. Therefore, the employment of CCS in the current system is conclusixely proved to be an economica y i •-asible option. 'SD s� DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-7 In conclusion, while CCS is an attractive option for an amine vent stream that contains fairly concentrated CO2, there are other reasons for technical, economical, and environmental infeasibility. Additionally, as discussed above, vent gases resulting from the processing of natural gas through amine units are o-eoffi5U t ti sing a flare or a RTO before they are released into the atmosphere to reduce the amount of released VOCs and HA -Ps. These control options have varying destruction efficiency rates which ultimately esult.s-fn-hig lower GHG emissions. However, flares do not allow for heat recovery an ceased energy efficiency that enclosed combustion systems like a RTO can offer. Consequently, DCP has elected to use a RTO as the primary control technology for the amine unit. Step 5. Select BACT DCP proposes the following design elements and work practices as BACT for the amine unit: > Regenerative thermal oxidizer a Proper Design and Operation of amine u > Use of Tank Off -gas Recovery Sys ems; and > Use of a Condenser. In addition, DCP proposes a numerical BACT limit for the amine unit vent stream of 3,702 lb CO2e/MMscf (wet) 2 based on 230 MMscfd gas flow through the facility. This includes CO2 and CH4 emisss ith Co ime scions being more than 99% of the total emissions. Compliance with these emission limits and throughput limits will be demonstrated by monitoring amine throughput rate and performing calculations consistent with those in Attachment A of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average ratio of short tons of CO2e per year emission rates per throughput do not exceed these limits. TEG DEHYDRATOR The TEG dehydration unit will be located downstream of the amine unit and will be used to remove water from the gases. Since the TEG dehydration unit is located downstream of the amine unit most of the CO2 entrained in the natural gas will already be removed. The available control technologies for the TEG dehydrator are discussed below. Step 1 — Identify All Available Control Technologies The available GHG emission control options for the process emissions: > Carbon Capture and Sequestration > Flare/Combustor > Thermal Oxidizer Condenser > Proper Design and Operation > Use of Tank Off -gas Recovery Systems Carbon Capture and Sequestration A detailed discussion of CCS technology is provided above. DCP Midstream LP 1 Lucerne 2 Expansion CDPHE Response Trinity Consultants D-8 Flare/ Combustor A detailed discussion on the flare is provided above. Thermal Oxidizer A detailed discussion on the thermal oxidizer is provided above. Condenser A detailed discussion on the condenser is provided above. Proper Design and Operation The TEG dehydrator will be new equipment installed on site. New equipment has better energy efficiency, hence reducing the GHGs emitted during combustion. The new equipment will operate at a minimum circulation rate. By minimizing the circulation rate, the equipment avoids pulling out additional VOCs and GHGs in the glycol stream, which would increase VOC and GHG emissions into the atmosphere. The TEG dehydrator regeneration overhead stream will be controlled with a condenser and a flare with a 95% DRE.22 The unit is equipped with a flash tank for recycling off -gas back to the plant inlet, including CO2 and CH4, from the rich dehydrator stream prior to regeneration, resulting in a reduction of waste gases created. Use of Tank Off -gas Recovery Systems The TEG dehydrator will be equipped with a flash tank. The flash tank will be used to recycle the off -gases back into the plant for reprocessing, instead of venting to the atmosphere or combustion device. The use of flash tanks increases the effectiveness of other downstream control devices. Step 2. Eliminate technically infeasible options As discussed above under the amine unit BACT section, all the above options are technically feasible. CCS does have its challenges, however DCP is continuing this assessment with the assumption that CCS is technically feasible. Step 3. Rank the technically feasible control technologies by control effectiveness CCS (i.e., sequestration or transfer of CO2) is the most effective control option for the control of the CO2 streams from the TEG dehydrator, since it provides approximately 90% C02 control of the dehydrator vent stream, based on literature review. Other control technologies do not destroy or reduce the amount of CO2 produced by the TEG dehydrator. Therefore, given the relative GWPs of CO2 and CH4, 1 and 21 respectively, and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional CO2 emissions. RTO have higher destruction efficiencies compared to flares, 99% and 98% respectively, and uses less pilot gas fuel, resulting in overall lower GHG emissions. The implementation of good combustion, operating, and maintenance practices; and the use of condensers and flash tanks for off -gas recycle are technically feasible control options for minimizing GHG emissions from fuel combustion and waste gas streams, respectively. 22 An enclosed combustor can demonstrate DRE as high as 98%. For conservatism, DCP is applying a lower ORE of 95%. DCP Midstream LP Lucerne 2 Expansion CDPHE Response Trinity Consultants D-9 Step 4. Evaluate most effective controls The TEG dehydrator vent stream does not contain a pure CO2 stream since most of the CO2 is stripped out in the upstream amine unit. Therefore, in addition to compression and transmission of CO2, a process to isolate and purify the CO2 is also required. This adds more reasons for technical, economical, and environmental infeasibility. Additionally, as discussed above, vent gases resulting from the processing of natural gas through TEG dehydrators are often combusted by using a flare or a RTO before they are released into the atmosphere to reduce the amount of released VOCs and HAPs. These control options have varying destruction efficiency rates which ultimately results in higher or lower GHG emissions. DCP has elected to use a flare or an enclosed combustor as the rip mart control technology for the TEG dehydrator because of unsafe operations that result from routing the vent to a RTO . In DCP's experiences routing the dehydrator xe-nt,stream to a RTO resultsoc in uncontrolledddetonation that raises safety concerns. g„ .,... lc? vd Step 5. Select BACT DCP proposes the following design elements and work practices as BACT for the TEG dehydrator: > Flare (enclosed combustor); > Proper Design and Operation of TEG dehydrators; • Use of Tank Off -gas Recovery Systems; and > Use of a Condenser. In addition, DCP proposes a numerical BACT limit for the TEG dehydrator vent stream combustion of 125 lb CO2e/MMscf (wet). This includes CO2 and CH4 emissions, with CO2 emissions being more than 99% of the total emissions. Additionally, DCP also proposes a numerical BACT limit for the uncontrolled portion of the TEG dehydrator vent stream of 9 lb CO2e/MMscf (wet) based on 230 MMscfd gas flow through the facility. Compliance with these emission limits and throughput limits will be demonstrated by monitoring inlet gas throughput rate and performing calculations consistent with those in Attachment A of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average ratio of short tons of CO2e per year emission rates per throughput do not exceed these limits. REGENERATIVE THERMAL OXIDIZER GHG BACT Step 1 — Identify All Available Control Technologies The available GHG emission control strategies for the RTO combustion emissions include: > Carbon Capture and Sequestration; > Proper RTO Design; > Fuel Selection; and > Good Combustion Practices. Carbon Capture and Sequestration A detailed discussion of CCS technology is provided above. DCP Midstream LP Lucerne 2 Expansion CDPHE Response Trinity Consultants - D-10 Proper RTO Design Good RTO design can be employed to destroy any VOCs and CH4 entrained in the waste gas from the amine unit. Good RTO design includes flow measurement and monitoring/control of waste gas heating value. In addition, periodic tune-up and maintenance will be performed per the manufacturer recommendation. Fuel Selection The fuel for firing the proposed RTO will be limited to natural gas fuel. Natural gas has the lowest carbon intensity of any available fuel for the RTO. In addition, the RTO will utilize the gas -fired burner system to bring the RTO up to combustion temperature during startup only. After the system has reached temperature, the burners will be shut off and the system will function using the energy content of the amine waste streams alone to support combustion. Good Combustion, Operating, and Maintenance Practices Good combustion and operating practices are a potential control option.. Good combustion practices are achieved by improving the fuel efficiency of the RTO and also include proper maintenance and tune-up of the RTO at least annually per the manufacturer's specifications. Step 2 — Eliminate Technically Infeasible Options All control options identified in Step 1 are technically feasible. Step 3 — Rank Remaining Control Technologies by Control Effectiveness CCS (i.e., sequestration or transfer of CO2) is the most effective control option for the control of the CO2 streams from the amine unit to the RTO, since it provides approximately 90% CO2 control of the gas stream, based on literature review. Good RTO design and operation result in approximately 1-15% and 1-10% reduction in GHG emissions, respectively. 23 Low carbon fuel selection and the implementation of good combustion, operating, and maintenance practices are technically feasible control options for minimizing GHG emissions from fuel combustion. Step 4 --Evaluate Most Effective Control Options The only technically feasible technology listed in Step 3 that may have additional energy, environmental, and economic impacts is CO2 capture and transfer. While the process exhaust stream is relatively high in CO2 content, additional processing of the exhaust gas will be required to implement CCS. These include separation (removal of other pollutants from the combustion gases), capture, and compression of CO2, transfer of the CO2 stream and sequestration of the CO2 stream. These processes require additional equipment to reduce the exhaust temperature, compress the gas, and transport the gas via pipelines. These units would require additional electricity and generate additional air emissions, of both criteria pollutants and GHG pollutants. This would result in negative environmental and energy impacts. 23 Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Petroleum Refining Industry, U.S. EPA, October 2010, Section 3. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-11 Therefore, based on the pipeline transfer cost, although technically feasible, off -site transfer is not regarded as a viable or economically feasible CO2 control option. Additionally, CO2 capture and transfer would have negative environmental and energy impacts, as discussed above. Step 5 — Select BACT for the RTO DCP proposes the following design elements and work practices as BACT for the RTO: > Proper RTO design, > Proper operation and maintenance procedures; and > Use of natural gas as fuel. In addition, DCP proposes a numerical BACT limit for total GHG emissions emitted from the RTO during normal operation of 3,677 lb CO2e/MMscf (wet) based on 230 MMscfd gas flow through the facility. These emissions include process related emissions from the amine unit This includes CO2, CH4, and N20 emissions, with CO2 emissions being more than 99% of the total emissions. Compliance with these emission limits and throughput limits will be demonstrated by monitoring inlet gas throughput rate and performing calculations consistent with those in Attachment A of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average ratio of short tons of CO2e per year emission rates per throughput do not exceed these limits. DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants D-12 Cost Estimation for Transfer of CO2 via Pipeline CO2 Pipeline and Emissions Data Parameter Value Units Minimum Length of Pipeline 150 miles Average Diameter of Pipeline 8 inches CO2 emissions from RTO 241,392.00 Short tons/yr CO; Capture Efficiency 90% Captured CO2 217,253 Short tons/yr CO2 Transfer Cost Estimation Cost Type Units Cost Equation Cost (1) Pipeline Costs Materials $ Diameter (inches), Lengthmiles) $64,632 + $1.85 x L x (330.5 x D2+686.7 x D + 26,960) $14,940,186.00 Labor Diameter (inches), Length (miles) $341,627 + $1.85 x L x (343.2 x D2 + 2,074 x D + 170,013) $58,219,746.50 Miscellaneous Diameter (inches), Lengthmiles) $150,166 + $1.58 x L x (8,417 x D + 7,234) $17,823,256.00 Right of Way Diameter (inches), Length (miles) $48,037 + $1.20 x L x (577 x 0 +29,788) $6,240,757.00 .. Other Capital ' .. , CO2 Surge Tank $ $1,150,636 $1,150,636.00 Pipeline Control System $ $110,632 $110,632.00 Operation & Maintenance (O&M) Fixed O&M $/mile/yr I $8,632 $1,294,800.00 Total Pipeline Cost $99,780,013.50 Amortized Cost Calculation Equipment Life 2 10 years Interest rate 3 7% Capital Recovery Factor (CRF) " 0.14 Total Pipeline Installation Cost (TCl) $98,485,214 $ (Pipeline + Other Capital) Amortized Installation Cost (TCI *CRF) $14,022,079 $/yr Amortized Installation + 0&M Cost $15,316,879 $/yr CO2 Transferred 217,253 Short tons/yr Annuitized control cost per tons 71 $/ton-yr Cost estimation guidelines obtained from "Quality Guidelines for Energy System Studies Estimating Carbon Dioxide Transport and Storage Costs", DOE/NETL-2010/1447, dated March 2010. z Pipeline life is assumed based on engineering judgment. 'Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition. 4 Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) ^ Pipeline Life) / ((1 + Interest Rate (%)) ^ Pipeline Life - 1) 5 This cost estimation does not include capital and O&M costs associated with the compression equipment or processing equipment. DCP Midstream, LP Lucerne 2 Expansion Trinity Consultants Amortized Cost Calculation - For FOR Pipeline Equipment Life'. 30. years ' Interest rate' 7% Capital Recovery Factor (CRF) 2 PUB Total Capital Cost for Equipment(TCI)4 $50,000,000 $ (Pipeline + Other Capital) Amortized Installation Cost (TCI *CRF) $4,029,320 $/yr Amortized Installation +O&M Cost $4,158,800 $/yr CO2 Transferred 138,914 Short tons/yr Annuitized control cost per tons 30 $/ton-yr Plant life is assumed based on engineering judgment - Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition. Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) " Pipeline Life) / ((1 + Interest Rate (%)) ^ Pipeline Life - 1) ° Total equipment capital cost assumed conservatively to be $50 million. s This cost estimation includes the compression equipment and processing equipment. DCP Midstream, LP Lucerne 2 Expansion Trinity Consultants CO2 Pipeline and Emissions Data - For FOR Pipeline Parameter Value Units Minimum Length of Pipeline 15 miles Average Diameter of Pipeline 6 inches CO2 emissions from RTO 154,348.53 Short tons/yr CO2 Capture Efficiency 90% Captured CO2 138,914 Short tons/yr CO2 Transfer Cost Estimation I Cost Type Units Cost Equation Cost ($) Pipeline Costs Materials $ Diameter (inches), Length (miles) $64,632 + $1:85 x L x (330.5 x D2 + 686.7 x D + 26,960) $1,257,277.05. Labor $ Diameter (inches), Length (miles) $341,627 + $1.85 x L 343,2 x D2 + 2,074 x 0 + 170,013) $5,747,665.55 Miscellaneous Diameter (inches), Length (miles) $150,166 + $1.58 x L x (8,417 x D + 7,234) $1,518,509.20 Right of Way Diameter (inches), Length (miles) $48,037 + $1.20 x L x (577 x D +29,788) $646,537.00 Other Capital CO2 Surge Tank $ $1,150,636 $1,150,636.00 Pipeline Control System $ $110,632 $110,632.00 Operation & Maintenance (0&M) Fixed 0&M I ' $/mile/yr I $8,632 $129,480.00 Total Pipeline Cost $10,560,736.80 Amortized Cost Calculation Equipment. Life 2 10 years Interest rate 3 7% Capital Recovery Factor (CRF) ° 0.14 Total Pipeline Installation Cost (TCI) $10,431,257 $ (Pipeline + Other Capital) Amortized Installation Cost (TCI *CRF) $1,485,176 $/yr Amortized Installation + O&M Cost $1,614,656 $/yr CO2 Transferred 138,914 Short tons/yr Annuitized control cost per tons 12 $/ton-yr I Cost estimation guidelines obtained from "Quality Guidelines for Energy System Studies Estimating Carbon Dioxide Transport and Storage Costs", DOE/NETL-2010/1447, dated March 2010. 2 Pipeline life is assumed based on engineering judgment. 3 Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition. ° Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) " Pipeline Life) / ((1 +Interest Rate (%)) " Pipeline Life - 1) 'This cost estimation does not include capital and 0&M costs associated with the compression equipment or processing equipment DCP Midstream, LP Trinity Consultants Lucerne 2 Expansion Amortized Cost Calculation- DCP Lucerne 2 Expansion Equipment Life 1 - 30 years Interest rare 2 7% Capital Recovery Factor (CRF)' 0.08 Total Capital Cost (TCI) ' $200,000,000 $ (Pipeline + Other Capital) Amortized Installation Cost (TCI *CRF) $16,117,261 $/yr CO2 Transferred 138,914 Short tons/yr Plant life is assumed based on engineering judgment 2 Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition. v Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) A Pipeline Life) / ((1 + Interest Rate (%)) A Pipeline Life -1) ° Total equipment capital cost assumed conservatively to be $200 million per internal DCP resources. Ratio of Capital Costfor CCS and Capital Cost for Project CCS Total' $ 5,514,496 - DCPTotal' $ 16,117,281 Ratio:' . 34.21% t Taken as sum of Pipeline transfer amortized costs and CCS capital amortized costs. 2 DCP Lucerne 2 Expansion capital amortized cost. DCP. Midstream, LP Trinity Consultants Lucerne 2 Expansion ATTACHMENT E. REVISED APENS DCP Midstream LP I Lucerne 2 Expansion CDPHE Response Trinity Consultants E-1 Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization. ] Facility Equipment ID: D-1 Section 02 — Requested Action (Check applicable request boxes) Section 01 — Administrative Information Request for NEW permit or newly reported emission source Vl r 0. 0 0 0 .a 0 0 .0 .0 v 9 d a a 4) CAI A-. 0 Change company name Transfer of ownership ❑ ❑ Change process or equipment Change permit limit ❑ ❑ Request to limit HAPs with a Federally enforceable limit on PTE El El El N ti Lucerne Natural Gas Processing Plant •0 3 31495 Weld County Road 43 .9 0 N n 00 .0 0 U 303-605-1957 4) z z a. Section 03 —General Information N r ro I 0. 0 b U U 2 2 0 3- C 0 a p C 0 a 0 8 a 0 .5 z z z ❑ ❑® E Ei O ZN k v R ai Z 0o0� C �Y° re •n ro 0 Al .0 0 '0 .y o 9 c° U o. N O U A � bJ1 5 a C G m 8 .9 E °i a. d 0 a � ' • N a g a C Normal Hours of Source Operation: /attainmaintain.htm I) he.state.co.us/ us Air Pollutant (HAP) emissions? O b J O O -� y OOD h j a ^ d —r Vi .0 9 z y M M f7 Q C N y N r t1 O U 0 .0b� vNAi F7 j� U W . Y C 000'v N co F en cn en co ?a :F 00.1, to w0 o o .•b �W z y °� W a °�≥ 0 e0� .4 'w Py A Cn G U i.. Q, U «r w a0°i 4 en a. p,a 0L a �'= g'v w o >+o a. r; a 5 P s 0 y c v a 0 c0 E .S a 'O Ei U o w°d'u I.o Co 0 >8 t r o o. G to A$ A 5 ca w >' o 0 f 0 4 0 p°.' 0� ..a P.. a�U000 est EN G U rn .0 W •4 o e o 1 �'O 0 0 y p ''° .2 9 -f U R: 'O c0 g d.' U<etA w Qrn he.state.co.0 Application status: htt o ,o Y W E 0 o'. '0 .4. i72 al 0 U 0 I z oa c ea .5 2 W N 0 0 r.11 0 ,i 0 Fn C 0 O o .0 1, I .a it 0 C cli ♦ ♦ cA Serial No.: TBD .y 0 Manufacturer: U s. 'O e bbn .9 a - 8 8 a. 4 C Pump Make & Model: in C 0 C O 8 0 00 . 'g 0 bA 0 Cua VO) M N Design Capacity: W 0 O ti C. 00 04 0 4 r N 3 Water Content: zz` N N ry2 A z rIA O O tw O. 00 O Qa z❑ 2 a 0 0 0. a 0 � v U • U O .4 0. ss 0. 0. Qom' w w 0 0 88 Cr Cr o .E A .0.0 0U IZIEI 2 0 a� 00 .S o E a , 2 It g ax y a3 � ca 4 4 76 .Q 2 eh C 0.0 O c(d .p H 3 10 ., y a G fA n' O ca �00 C., U U Q Q Q ®® ❑ GlycolDehydratorAPEN TEG (D -1 ) v2.1 FORM APCD-202 r CC O rr 5 C., O 44.4 ti O 0 O. z a �I z C W E-4 a a Emission Source AIRS ID: Permit Number: 0 C w .44 os 04 O A c O r. C7 V V V v> • E -. 0 con O d O Cu 2'.. O W z 5" 4478327.79 m N 52868136 m E C') co r A I1 H U V f U g Y 80 en rd .0 V O 'U > A a f0.) "ElU >❑ 0 ;A u d u�. u � O.d J 0 0 o � 0.0 •$ v, 0 0 o O o V C) 0) s W Section 07 — Contro b0 CC 0 O U d aa a) H a 9 0 U Enclosed Combustor a 3k o .V •o 0. O Ocr ix 8❑ V.. Cl) • ❑ mac• U E o Y ' 9 a Cc g• 0. OU •H 0 U Flash Tank Ve O 8 O •0 0 Describe An 0 C VOC and I3APs Sti Condenser used for control of I® Make/Model: BTEX Condenser 0. 4 o Temperature (°F): ii CO 0 0 bypassed (emissions vente Section 08 —Emissions Inventory Information & Emission Control Information u .0 CC CC 0 CC ggs L 0 W TEstimation Method. ^' or Emission Factor Source G1yCalc ,al 00000 71 Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollu tan is not listed above. C :Controlled `'(Tons/Year) 3.42 2.22 0.14 0.30 C rF.: :' M PI M ,..• II :Uncontrolled (Tons/Yeai 68.42 44.44 00 f+1 t',1 .1) ry Actual Calendar Year Emissions' - Uncontrolled > .. Controlled (Tons[)(ein) (Tons/Year) Emission Factor Uncontrolled Basis Units w.. t eu 4••, 4. w \C `WO N1 & NI n 00 tr) P. ,, "r n.n TT V) M NI C. ., ,-* o 0 O h :.Identify in Section 07 ... to ::,,,g4.'.',,•,;,...;:,-,*., ::::-.,,...., . ...r.,:r.,--,1,t44.4:. i„:., - ..-;.::,....,:•r,:.; Pollutant • NOx VOC CO Ir Benzene V 0 0 0 X F° ..=a 5, W.1 CC 0) z R C A Person (Please print) Signature of Person Legally Authorized to Supply Data GlycolDehydratorAPEN_TEG (D-1) v2.1 0 O CI P. onent Leak Emissions AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit — Fu Emission Source AIRS ID: [Leave blank unless APCD has already assigned a permit # & AIRS m] Permit Number: [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Facility Equipment ID: uested Action (Check applicable request boxes) Section 02 —Re Section 01 — Administrative Information Request for NEW permit or newly reported emission source t 0.4.4 F o a O L .O C.) N L W s E ❑ ❑ OA L ['q a Change company name Change process or equipment Transfer of ownership Change permit limit Request to limit HAPs with a Federally enforceable limit on PTE O O m .5 C d O a F .0 et e 29 3 .2 '5 c m O t o `4 a E O a) e. 5 u g, O 5 t -o ..Vi c T ^ O 0 o ro W U •o m ;' O z g W Col .E ea O cr z ❑ ® ❑ ❑ ❑ N en 0 0 'n U U z 4 County: Weld Elevation: 4,701 O W 370 17th St, Suite 2500 Mailing Address TA o a o -2 Section 03 — General Information O 0 tJ 3 ro cen O 0 u U O O •O II N -o E O wzca o 9 o O O y L v�� C O ,= C E eel W65 - W ea .O a d a E O VI sx a E y u 1 O o a 0 0 0 ac. 4 E .4a u O > O O > U Sat O O` an gU n0 e o ho e O k la i N 0 o d E c,.., U 0.2o V " i s T 0 0 0 a .fl 6 Z s: b 7 C = O V 0 G 0. 9 U dre; q w0 d4 O In v cn .n <n P N N N C & is w a a rn fn en O vs 'O re.state.co.us/ he.st'ate.co.us/a Co O z z z ❑ ❑ El ttainment area? en oa 8 Z T 5 .5 E m O174 � O O C33 O H 5 ei P O. n.'d O cr Information 2 CO CO Section 04 — Re r ® ❑ Is this equipment subject to NSPS 40 CFR Part 60, Subpart KKK? P 40 CFR Part 63, Subpart Is this equipment subject to NE NSPS OOOO P Subpart that applies to this equipment: List any other NSPS or NE Section 05 -Stream Constituents ®® 0 R Q a)' ' u O' L X `'3 , o 0 0 0 Ce N O O O 4O .3 T 3 o c O c W Toluene (wt. %) Tr O a O 0 0 Benzene (wt. %) 0 V o o a a U e p e," 68 N o o 4-4 E O I Heavy Oil (or Heavy Liquid) Light Oil (or Light Liquid) Water/Oil L en F.. 3 °D C g .9 O .o o O O 00 E N 0 a a O O E. a o •O (0 W O O 0 0 a, cn Cr Cr 2 2 5 O O O d oa) O -O .O U 0 3,3 O O en 4 a O X m eq 5 V O V 5 T 0 0 0 0 or Por pC OD O 0 v 2 N 5 en FugitiveComponentLeaksAPEN v2.0 N 0 an FORM APCD-203 onent Leak Emissions Emission Source AIRS ID: Permit Number: & Control Information 9 L Section 07 -Leak Detection & Re conducted at this site: appropriate boxes to identify LDAR pros LDAR per NSPS KKK ❑ Other. NSPS 0000 c p' a'. 4478327.79 m N 528681.36 m E M rf z Section 08 - Emission Factor Information O 3 0 v O L L 6 C o 0 fH L M L s 4 4 0 N M C M N 0 U V L O L Y L s R N 0 al Q col N .61 N N 0: N H et 6 113 N 01 s 0 U C 0 C.) Open -Ended Lines ro 0) U) 0. Vi O Actual Count conducted on the folio Estimated Count 131 Section 09 — Emissions Inventory Information & Emission Control Information Estimation Method r Emission Factor "Source. EPA Protocol EPA Protocol EPA Protocol EPA Protocol EPA Protocol EPA Protocol pollutants not listed above. Requested Permitted Emissions3 Uncontrolled Controlled (Tons/Year) (Tons/Year) e N 4 W NVJ r -f M W 4:4N QC rwi ., ,G M co - N C of O .— O O O O 11 O ...I . N Actual Calendar Year Emissions2 ..Uncontrolled Controlled (Tons/Year):!..--:: (Tons/Year) Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report Emission Factor Uncontrolled Basis Units. Identify in Section 08" Control Efficiency..' (% Reduction) it r_.:.•. J} 5 Control. Device Description Pollutant VOC Benzene t°.. Ethylbenzene Xylene c 0 Section 10 —A U) • Owe 0• 5. Fu gitiveCo mponentLeaksAPEN O N A, Format RBLC Report a Page 1 of 7 Previous, Page,,,.. COMPREHENSIVE REPORT Report Date:09/10/2013 Facility lnformatian RBLC ID: Corporate/Company Name: Facility Name: Facility Contact: Facility Description: Permit Type: Permit URL: EPA Region: Facility County: Facility State: Facility ZIP Code: Permit Issued By:, Other Agency Contact Info: Permit Notes: Facility -wide Emissions: AK -0081 (draft) EXXONMOBIL CORPORATION POINT THOMSON PRODUCTION FACILITY MATT REILE 907-929-4108 MATTHEW.R.REILE@EXXONMOBIL.COM Oil/Gas Exploration and Production Facility. The facility contains electric power generating stations, power distribution facilities, water treatment facilities, wastewater treatment facilities, waste management facilities, oil spill response equipment, and others D: Both B (Add new process to existing facility) &C (Modify process at existing facility) 10 NORTH SLOPE BOROUGH AK 99524-1449 ALASKA DEPT OF ENVIRONMENTAL CONS (Agency Name) MR. JOHN KUTERBACH(Agency Contact) (907) 465-5103 JOHN.KUTERBACH@ALASKA.GOV Kwame Agyei Kwame.Agyei@alaska.gov 907 465 5124 Revising existing permit AQ1201CPT01 that authorized the installation of several emission units. The facility contains electric power generating stations, power distribution facilities, water treatment facilities, wastewater treatment facilities, waste management facilities, oil spill response equipment, and othersnd operation of several emission units. See facility description. Pollutant Name: Facility -wide Emissions Increase: 'Carbon Monoxide 105.0000 (Tons/Year) Nitrogen Oxides (NOx) 160.0000 (Tons/Year) Particulate Matter (PM) 20.0000 (Tons/Year). Sulfur Oxides (SOx) 31.0000 (Tons/Year) Volatile Organic Compounds (VOC) 36.0000 (Tons/Year) Date Determination Last Updated: Permit Number: Permit Date: FRS Number: SIC Code: 08/30/2013 AQ120ICPT02 06/12/2013 (actual) 1311 NAICS Code: 211111 COUNTRY: USA Process/Pollutant Information PROCESS NAME: Process Type: Primary Fuel: Throughput: Process Notes: Combustion 16.110 (Natural Gas (includes propane & liquified petroleum gas)) Natural Gas 7520.00 kW Solar Turbine with SoLoNOx POLLUTANT NAME: Particulate matter, total <2.5 p (TPM2.5) CAS Number: PM Test Method: Unspecified Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit l: 0.0066 LB/MMBTU Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: (P) Good combustion and operating practices. Control Method: Est. % Efficiency: Cost Effectiveness: Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown Pollutant/Compliance Notes: Emission limit based on AP -42, Table 3.1-2a 0 $/ton POLLUTANT NAME: CAS Number: Carbon Dioxide Equivalent (CO2e) CO2e U http: //cfpub. epa. gov/rbl c/index. cfm?action=Reports.ReportComprehens,iveReport&Report... 9/10/2013 Format RBLC Report vs Page 2 of 7 Test Method: Unspecified. Pollutant Group(s): ( Greenhouse Gasses (GHG) ) Emission Limit 1: Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: Control Method: (P) Good Combustio and Operating Practices Est. "G, Efficiency: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown Pollutant/Compliance Notes: Process/Pollutant Information PROCESS NAME: Process Type: 16.290 (Liquid Fuel & Liquid fuel Mixtures) Primary Fuel: Fuel Gas / ULSD Throughput: 7520.00 kW . Process Notes: Dual fuel burning fuel gas or ULSD and installed with Waste Heat Recovery Units Combustion POLLUTANT NAME: Particulate matter, total <2.5 p (TPM2.5) CAS Number: PM Test Method: Unspecified Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0120 LB/MMBTU Emission Limit 2: Standard Emission:, Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: Control Method: (P) Good Combustion and Operating Practices Est. % Efficiency: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown Pollutant/Compliance Notes: BACT limit is from AP -042, Table 3.1-2a POLLUTANT NAME: Carbon Dioxide Equivalent (CO2e) CAS Number: CO2e Test Method: Unspecified Pollutant Group(s): ( Greenhouse Gasses (GHG) ) Emission Limit 1: Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: Control Method: (P) Good Combustion and Operation Practices Est. '7 Efficiency: Cost Effectiveness: - 0 $/ton Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown Pollutant/Compliance Notes: Process/Pollutant Information PROCESS NAME: Combustion http://cfpub.epa. gov/rb1e/index.cfm?action=Reports.ReportComprehensiveReport&Report... 9/10/2013 Format RBLC Report Page 5 of 7 Process Notes: Well Testing, HP, and LP Flares POLLUTANT NAME: Particulate matter, total <2.5 p (TPM2.5) CAS Number: PM. Test Method: Unspecified Pollutant Group(s): ( Particulate Matter (PM)) Emission Limit 1: 0.0264 LB/MMBTU Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: Control Method: (P) Good operation and combustion practices Est. % Efficiency: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown - Pollutant/Compliance Notes: PreviousPage Facility Information RBLC ID: AK -0080 (draft) Corporate/Company Name: MUNICIPALITY OF ANCHORAGE Facility Name: ANCHORAGE MUNICIPAL LIGHT & POWER Facility Contact: )(ELENA SAVILLE 907-263-5273 SAVILLEYV@CI.ANCHORAGE Facility Description: Electric Utility Permit Type: D: Both B (Add new process to existing facility) &C (Modify process at existing facility) Permit URL: EPA Region; Facility -County: Facility State: Facility ZIP Code: Permit Issued By: Other Agency Contact Info: Permit Notes: Facility -wide Emissions: 10 MATANUSKA AK 99504 Date Determination Last Updated: Permit Number: Permit Date: FRS Number: SIC Code: NAICS Code: COUNTRY: 08/30/2013 AQ0203CPT02 06/06/2013 (actual) 4911 221112 USA ALASKA DEPT OF ENVIRONMENTAL CONS (Agency Name) MR. 1O1 -IN KUTERBACH(Agency Contact) (907) 465-5103 JOHN.KUTERBACH@ALASKA.GOV Kwame Agyei _ Kwame. Agyei@alaska goy 907 465 5124 Authorized two natural gas turbines each rated at 408 MMBtu/hr, one ULSD Caterpillar generator rated at 2,000 ekW, and one cooling towerrated at 30,400 gallons per minute Pollutant Name: Carbon Monoxide Nitrogen Oxides (NOx) Particulate Matter (PM) Sulfur Oxides (SOx) Volatile Organic Compounds (VOC) Facility -wide Emissions Increase: 22.0000 (Tons/Year) 38.0000 (Tons/Year) 24.0000 (Tons/Year) 12.0000 (Tons/Year) 8.0000. (Tons/Year) Process/Pollutant Information PROCESS NAME: Process Type: 16.110 (Natural Gas (includes propane Re liquified petroleum gas)). Primary Fuel: Natural Gas Throughput: 408.00 MMBtu/hr Process Notes: Natural Gas -fired combustion turbine rated at 408.2.MMBtu/hr Combustion POLLUTANT NAME: CAS Number: Particulate matter, total .<2.5 p (TPM2.5) PM http://cfpub. epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&Report:.. 9/10/2013 Format RBLC Report Page 6 of 7 Test Method: Unspecified Pollutant Group(s):' ( Particulate Matter (PM) ) Emission Limit 1: 0.0066 LB/MMBTU Emission Limit 2: Standard Emissio*; Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: OTHER Control Method: (P) Good operation and combustion practices Est. % Efficiency: Cost Effectiveness: . 0 $/ton Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown Pollutant/Compliance Notes: BACT is good operation and combustion practices and emitting no more than 0,0066 Ib/IvlMBtu, which is based on the emission factor in AP -42 POLLUTANT NAME: Carbon Dioxide Equivalent (CO2e) CAS Number: CO2e Test Method: Unspecified Pollutant Group(s): ( Greenhouse Gasses (GHG)) Emission Limit I: Emission Limit 2:' Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: Control Method: (P) Good operating and combustion practices Est. G, Efficiency: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 $/ton Compliance Verified: Unknown Pollutant/Compliance Notes: GHG BACT for the turbines is good combustion and operation practices Process/Pollutant Information PROCESS NAME: Process Type: 17.130 (Natural Gas (includes propane & liquified petroleum gas)) Primary Fuel: Ultra Low Sulfur Diesel Throughput: 2000.00 ekW Process Notes: Blackstart engine rated. at 2,000 ekW and burning ULSD POLLUTANT NAME: - Particulate matter, total a 2.5 µ (TPM2.5) CAS Number: PM Test Method: Unspecified - Pollutant Group(s): _ ( Particulate Matter (PM)) Emission Limit 1: 0.2000 G/KWH Emission Limit 2: Standard Emission:. Did factors, other then air pollution technology considerations influence the BACT decisions: U Case -by -Case Basis: OTHER CASE -BY -CASE Other Applicable Requirements: NSPS Control Method: (P) Good Combustion and Operating Practices Est. % Efficiency: Cost Effectiveness: 0 $/ton Incremental Cost Effectiveness: 0 Shun Compliance Verified: Unknown Pollutant/Compliance Notes: Emission limit based on 40 CFR 60, Subpart 11I1 and 40 CFR 89.112 Combustion POLLUTANT NAME: Carbon Dioxide Equivalent (CO2e) CAS Number: Test Method: CO2e Unspecified http://cfpub. epa.gov/rblc/index. cfm?action=Reports.ReportComprehensiveReport&Report... 9/10/2013 10/17/13 State.co.us Executive Branch Mall - Fwd: Lucerne HHV/GHG updates and proposed BACT requirement language STATE OF COLORADO Fwd: Lucerne HHV/GHG updates and proposed BACT requirement language Chaousy - CDPHE, Stephanie <stephanie.chaousy@state.co.us> Wed, Aug 28, 2013 at 4:12 PM To: Christopher Laplante - CDPHE<christopher.laplante@state.co.us>, "carissa.money@state.co.us" <carissa.money@state.co.us> Forwarded message ----- From: Stephens, Dana <DStephens@dcpmidstream.com> Date: Wed, Aug 28, 2013 at 4:11 PM Subject: Lucerne HHV/GHG updates and proposed BACT requirement language To: "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us> Cc: "Stevenson, Peter F" <PFStevenson@dcpmidstream.com>, "Roshini Shankaran (rshankaran@ trinityconsultants.com)" <rshankaran@trinityconsultants.com>, "Stephens, Dana" <DStephens@dcpmidstream.com> Stephanie, Per a recent discussion with Solar Turbines, the manufacturer, of the turbines proposed to be installed at Lucerne 2, it was discovered that the specification sheet provided the heat input to the turbine of 66.12 MMBtu/hr on a lower heating value (LHV) basis. In order to convert the LHV to a higher heating value (HHV) basis, DCP increased the LHV by about 10% to 66.12 x 1.1 = 72.73 MMBtu/hr. DCP requests that this heat input be reflected throughout the permit. Additionally, Solar was also able to provide emission information on CO2 and CH4 based on an engine exhaust analysis. DCP has updated the emissions of CO2 from the engine exhaust analysis and has set unburned hydrocarbon (UHC) on the specification sheet provided previously equal to methane to be conservative. N2O is still calculated using 40 CFR 98 Subpart C emission factors. The emission calculations reflecting these updates are attached. Accordingly, the permit condition revision requested relates to the revised emission estimate for CO2e from the turbines. DCP is also requesting a 10% safety factor on the hot oil heater CO2e Ib/MMBtu proposed BACT limit. The attached calculations reflect this safety factor in the annual emissions as well. DCP has also reviewed recently issued GHG PSD permits from Region VI and have drafted language for your consideration for the BACT requirements for the turbines, the hot oil heater, and the amine unit/RTO. Please find attached the following items: * Revised CO2e emission calculations for the turbines and the hot oil heater; CO2 engine exhaust analysis for turbines; Solar Turbines specification sheet for turbines; and Proposed BACT requirement language for the turbines, the hot oil heater and the amine/RTO. https:/Imail.google.comlmail/u/01?ui=2&ilyda5742cbb2&view=pt&cat=DCP Lucerne&search=cat&th=140cefc64dbfdfce 1/2 10/17/13 State.co.us Executive Branch Mail - Fwd: Lucerne HHV/GHG updates and proposed BACT requirement language I'm going on vacation but wanted to get this to you before. I left. I will be back in the office on September 4th but if you need anything before then, please feel free to contact my boss, Pete Stevenson at 303-605-2035. I've also cc'd him on this email. Have a great Labor Day weekend, Dana Dana M. Stephens, REM Rockies Air Permitting Manager DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Office - (303) 605-1745 Mobile - (720) 355-4703 Email - dstephens@dcpmidstream.com Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297 www.colorado.gou/cdphe 4 attachments GFS 20967 DCP Midstream Formai 10802S at 13 ppm NOx.pdf 16K gfs 20967 other temps DCP Midstream Text 10802S at 13 ppm NOx.pdf 23K Revised Lucerne Mod Plant Calculations v7.9.pdf 278K Turbines Heaters and RTO conditions.docx 62K https://mail.google.com/mail/u/0/?ui=2&ik=da5742cbb2&viex=pt&cat=DCP Lucerne&search=cat&th=140c6fc64dbfdfce 2/2 0 P SION CALCULATIONS FOR HEATERS 9 c 0 x d EN O .x, O O & O" Pz aV c .71 C co 0 61 3 04 FED GHG CALCULATIONS FOR COMBUSTION TURBINES .44 lo 2{{ 42, EA V. The firing rate is converted to HHV as LHV x 1.1. O \ \ \. 04 0 CD CC Li 40, 110 part C, Table C-2 for Natural Gas and coverted to Ib/MMBtu. GHG Potential Emi 0Li 2 0 \E Solar Turbines A Caterpillar Company PREDICTED EMISSION PERFORMANCE Customer DCP Midstream Prairie Gas Pla Job ID DN12-001 Inquiry Number Run By Leslie Witherspoon Date Run 8 -May -13 NOx EMISSIONS Engine Model TAURUS 70-10802S ESC CS/MD STANDARD DAY Fuel Type Water Injection CHOICE GAS NO Engine Emissions Data REV. 0.1 CO EMISSIONS UHC EMISSIONS 9022 HP 100.0% Load Elev. 4800 ft Rel. Humidity ;'30.0% Temperature 60.0 Deg. F PPMvd at 15% O2 ton/yr Ibm/MMBtu (Fuel LHV) Ibm/(MW-hr) (gas turbine shaft pwr) Ibm/hr 13.00 14.99 0.052 0.51 3.42 25.00 17.55 0.061 0.60 4.01 25.00 10.05 0.035 0.34 2.29 Notes 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid -fuel (except for the Centaur 40). An emission warranty for non-SoLoNOx equipment is available for greater than 0 deg Fund between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non -warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut -down, malfunction, or transient event. Solar Turbines A Caterpillar_,-.n...mr,.. Company Customer DCP Midstream Prairie Gas Pla Job ID DN12-001 Run By Leslie Witherspoon Date Run 8 -May -13 Engine Performance Code REV. 4.6.1.8.3 - Engine Performance Data REV. 2.0 Elevation Inlet Loss Exhaust Loss feet in H2O in H2O Engine Inlet Temperature deg F Relative Humidity Driven Equipment Speed RPM Specified Load Net Output Power Heat Rate Therm Eff Fuel Flow HP HP Btu/HP-hr mmBtu/hr Nom Net Output Power HP Nom Heat Rate Btu/HP-hr Nom Therm Eff Nom Fuel Flow mmBtu/hr Engine Exhaust Flow Ibm/hr PT Exit Temperature deg F Exhaust Temperature deg F Fuel Gas Composition (Volume Percent) Fuel Gas Properties 4800 4.0 4.0 60.0 30.0 114961 FULL 8752 7537 33.759 65.96 9022 7311 34.803 65.96 178262 942 942 Methane (CH4) 86.17 Ethane (C2H6) 12.35 Propane (C3H8) 0.40 1 -Butane (C4H10) 0.01 Nitrogen (N2) 1.07 Sulfur Dioxide (SO2) 0.0001 PREDICTED ENGINE PERFORMANCE Model TAURUS 70-10802S ESC Package Type CS/MD Match STANDARD DAY Fuel System GAS Fuel Type CHOICE GAS LHV (Btu/Scf) 993.0 Specific Gravity 0.6221 Wobbe Index at 60F 1259.0 This performance was calculated with a basic inlet and exhaust system. Special equipment such as low noise silencers, special filters, heat recovery systems or cooling devices will affect engine performance. Performance shown is 'Expected" performance at the pressure drops stated, not guaranteed. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE. REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 1 HP= 9883, %Full Load=100.0, Elev= 4800ft, %RH= 30.0, Temperature= 0.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: CHOICE GAS 25.09 in Hg .30.0 percent 0.0003 --- AMBIENT PRESSURE RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = 993.0 SG = 0.6221 W.I. @60F (Btu/Scf) 1259.0 Gas Fuel Suitability (GFS)# 20967 Methane (CH4) Ethane (C2H6) Propane (C3H8) I -Butane (C4H1O) Nitrogen (N2) Sulfur Dioxide (S02) = 86.1699 = 12.3500 0.4000 0.0100 = 1:0700 = 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of fuel blends, however Engineering review is required when methane drops below 80% or other constituents exceed standard boundaries. Performance as modeled here should be accurate, but note that alterations to the combustion and package systems may be necessary. GENERAL OUTPUT DATA 3483.lbm/hr FUEL FLOW 1222.40 Scfm FUEL FLOW 20914. Btu/lbm LOWER HEATING VALUE 993. Btu/Scf .LOWER HEATING VALUE 43954.. Scfm EXHAUST FLOW @ 14.7 PSIA & 60F 135976. Acfm ACTUAL EXHAUST FLOW CFm 198732. 1bm/hr EXHAUST GAS FLOW 4627.0 deg R ADIA STOICH FLAME TEMP, CHOICE GAS. 4612.8 deg R ADIA STOICH FLAME TEMP, SDNG 28.60 --- MOLECULAR WEIGHT OF EXHAUST GAS 56.23 --- AIR/FUEL RATIO EXHAUST GAS ANALYSIS ARGON CO2 H2O N2 02 0.91 3.14 5.90 75.76 14.28 VOLUME PERCENT WET 0.96 3.34 0.00 80.52 15.18 VOLUME PERCENT DRY 2514. 9597. 7390. 147468. 31758. lbm/hr 0.72 2.76 2.12 42.34 9.12 g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 1 Fuel:. CHOICE GAS Customer: DCP Midstream Prairie Gas Pla Water Injection: NO Inquiry Number: Model: TAURUS 70-10802S ESC CS/MD STANDARD DAY GAS Emissions Data: REV. 0.1 The following predicted emissions performance is based on the following specific single point: HP= 9883, %Full Load=100.0, Elev= 4800ft, %RH= 30.0, Temperature= •O.OF NOX 13.00 16.60 0.052 0.51 CO 25.00 19.44 0.061 0.60 3.79 4.44 UHC 25.00 - PPMvd at 15% 02 11.13 ton/yr 0.035 lbm/MMBtu (Fuel LHV) 0.34 lbm/(MW-hr) (gas,turbine shaft pwr) 2.54 lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific Wo the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-SOLoNOx equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non - warranted emissions of S02, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions'. and does not apply during start-up, shut -down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 2 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon HP= 9765, oFul1 Load=100.0, Elev= 4800ft, oRH= 60.0, Temperature= 32.OF GENERAL INPUT SPECIFICATIONS ENGINE FUEL: CHOICE GAS - 25.09 in Hg -60.0 percent 0.0027 --- AMBIENT PRESSURE RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR). FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = 993.0 SG = 0.6221 W.I. @60F (Btu/Scf) = 1259.0 Gas Fuel Suitability (GFS)# 20967 Methane (CH4) Ethane (C2H6) Propane (C3H8) I -Butane (C4H10) Nitrogen (N2) Sulfur Dioxide (SO2) 86.1699 = 12.3500 0.4000 = 0.0100 1.0700 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of fuel blends, however Engineering review is required when methane drops below 80% or other constituents exceed standard boundaries. Performance as modeled here should be accurate, but note that alterations to the combustion and package systems may be necessary. GENERAL OUTPUT DATA 3340. lbm/hr FUEL FLOW 1172.41 Scfm FUEL FLOW 20914. Btu/lbm LOWER HEATING VALUE 993. Btu/Scf LOWER HEATING VALUE 42007. Scfm EXHAUST FLOW @14.7 PSIA & 60F 131481. Acfm ACTUAL EXHAUST FLOW CFm 189656. lbm/hr EXHAUST GAS FLOW 4663.9 deg R ADIA STOICH FLAME TEMP, CHOICE GAS 4649.7 deg R ADIA STOICH FLAME TEMP, SDNG 28.56 --- MOLECULAR WEIGHT OF EXHAUST GAS 55.95 --- AIR/FUEL RATIO EXHAUST GAS ANALYSIS ARGON CO2 H2O N2 02 0.90 3.14 6.28 75.47 14.20 VOLUME PERCENT WET 0.96 .3.35 0.00 80.53 15.15 VOLUME PERCENT DRY 2394. 918.3: 7515. 140391. 30169. 1bm/hr 0.72 2.75 2.25 42.03 9.03 g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 - - DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 2 Fuel: CHOICE GAS - Customer: DCP Midstream Prairie Gas Pla Water Injection: NO Inquiry Number: Model: TAURUS 70-10802S. ESC CS/MD STANDARD DAY GAS Emissions Data: REV. 0.1 The following predicted emissions performance is based on the following specific single point: HP= 9765, %Full Load -100.0, Elev= 4800ft, %RH= 60.0, -Temperature= 32.OF NOX 13.00 15.89 0.052 0.50 CO 25.00 18.60 0.061 0.58 3.63 4.25 UHC 25.00 PPMvd at 15% 02 10.65 ton/yr 0.035lbm/MMBtu (Fuel LHV) .0.33 lbm/(MW-hr) (gas turbine shaft pwr) 2.43 lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-SoLONOx equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non - warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory'testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut -down, malfunction, or transient event. SOLAR TURBINES INCORPORATED - DATE RUN: 8 -May -13 ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 RUN BY: Leslie Witherspoon CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001- --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 3 HP= 9085, %Full Load=100.0, Elev= 4800ft, %RH= 60.0, Temperature= 59.OF GENERAL INPUT SPECIFICATIONS ENGINE FUEL: CHOICE GAS 25.09 in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY 0.0077 --- SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = 993.0 SG = 0.6221 W.I. @60F (Btu/Scf) 1259.0 Gas Fuel Suitability (GFS)# 20967. Methane (CH4) Ethane (C2H6) Propane (C3H8) I -Butane (C4H10) Nitrogen (N2) Sulfur Dioxide (SO2) = 86.1699 12.3500 = 0:4000 = 0.0100 = 1.0700 = 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of fuel blends, however Engineering review is required when methane drops below 80% or other constituents exceed standard boundaries. Performance as modeled here should be accurate, but note that alterations to the combustion and package systems may be necessary. GENERAL OUTPUT. DATA 3173. lbm/hr FUEL FLOW 1113.86 Scfm FUEL FLOW 20914. Btu/1bm LOWER HEATING VALUE 993. Btu/Sc£ LOWER HEATING VALUE 39695. Scfm EXHAUST FLOW @ 14.7 PSIA & 60F 127624. Acfm ACTUAL EXHAUST FLOW CFm 178695. lbm/hr EXHAUST GAS FLOW 4684.1 deg R ADIA STOICH FLAME TEMP, CHOICE GAS 4669.9 deg R ADIA STOICH FLAME TEMP, SDNG 28.48 --- MOLECULAR WEIGHT OF EXHAUST GAS 55.48 --- AIR/FUEL,RATIO EXHAUST GAS ANALYSIS • ARGON CO2 H2O - N2 02 0.90 3.14 7.04 74.88 14.04 VOLUME PERCENT WET 0.96 3.38 0.00 80.55 15.10 VOLUME PERCENT DRY 2244. 8682. 7962. 131622. 28182. 115m/hr 0.71 2.74 2.51 41.48 8.88 g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 3 Fuel: CHOICE GAS Customer: DCP Midstream Prairie Gas Pla Water Injection: NO Inquiry Number: Model: TAURUS 70-10802S ESC CS/MD STANDARD DAY GAS Emissions Data: REV. 0.1 The following predicted. emissions performance is based on the following specific single point: HP= 9085, %Fu11 Load=100.0, Elev= 4800ft, %RH= 60.0, Temperature 59.OF. NOX 13.00 15.02 0.052 0.51 CO 25.00 17.59 0.06,1 0.59 3.43 4.02 UHC 25.00 PPMvd at 15% 02 10.07 ton/yr 0.035 lbm/MMBtu (Fuel LHV) 0.34 1bm/(MW-hr) (gas turbine shaft pwr) 2.30 1bm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SOLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-SoLoNOx equipment is available for greater than 0 deg F and between 80 and 100% load. 3. Fuel must meet Solar standard fuel specification ES 9-96. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide. Product Information Letters to address turbine operation outside typical warranty ranges, as well as non - warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut -down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN ,.BY: Leslie Witherspoon --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 4 HP= 8212, %Full Load=100.0, Elev=-4800ft, %RH= 60.0, Temperature= 80.OF GENERAL INPUT SPECIFICATIONS ENGINE FUEL: CHOICE GAS 25.09 in Hq 60.0 percent 0.0159 AMBIENT PRESSURE RELATIVE HUMIDITY SP. HUMIDITY (LBM H20/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME -PERCENT) LHV (Btu/Scf) = -993.0 SG = 0.6221 W.I. @60F (Btu/Scf) = 1259.0 Gas Fuel Suitability (GFS)# 20967 Methane (CH4) Ethane (C2H6) Propane (C3H8) I -Butane (C4H10) Nitrogen (N2) Sulfur Dioxide (S02) = 86.1699 = 12.3500 = 0.4000 = 0.0100 = 1.0700 = 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32. deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of fuel blends, however Engineering review is required when methane drops below 80% or other constituents exceed standard boundaries. Performance as modeled here should be accurate, but note that alterations to the combustion and package systems may be necessary. GENERAL OUTPUT DATA 2961. lbm/hr FUEL FLOW 1039.49 Scfm - FUEL FLOW 20914. Btu/lbm LOWER HEATING VALUE 993. Btu/Scf LOWER. HEATING VALUE 37310. Scfm EXHAUST FLOW @ 14.7 PSIA & 60F 122121. Acfm ACTUAL EXHAUST FLOW CFm 167190. lbm/hr EXHAUST GAS FLOW 4693.0 deg R ADIA STOICH FLAME TEMP, CHOICE. GAS 4678.7 deg, R. ADIA STOICH FLAME TEMP, SDNG 28.35 --- MOLECULAR WEIGHT OF EXHAUST GAS 55.62 --- - AIR/FUEL RATIO EXHAUST GAS ANALYSIS ARGON 002, H2O. N2 02 0.88 3.10 8.19 /3.94 13.88 VOLUME PERCENT WET 0.96 3.37 0.00 80.55. 15.11 VOLUME PERCENT DRY 2083. 8037. 8707. 122171. 26188. lbm/hr 0.70 2.71 2.94 41.25 8.84 g/(g FUEL) SOLAR TURBINES INCORPORATED DATE RUN: 8 -May -13 ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 - -RUN BY: Leslie Witherspoon CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 4 Fuel: CHOICE GAS Customer: DCP Midstream Prairie Gas Pla Water Injection: NO Inquiry Number: Model: TAURUS 70-10802S ESC CS/MD STANDARD DAY GAS Emissions Data: REV. 0.1 The following predicted emissions performance is based on the following specific single point: HP= 8212, %Full Load=100.0, Elev= 4800ft, %RH= 60.0, Temperature= 80.OF NOX 13.00 13.91 0.051 0.52 CO 25.0O 16.28 0.060 0.61 3.18 3.72 UHC 25.00 PPMvd at 15% O2 9.33 ton/yr 0.034 lbm/MMBtu (Fuel LHV) 0.35 lbm/(MW-hr) (gas turbine shaft pwr) 2.13 lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SOLONOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-SoL0NOx equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non - warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut -down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon --- SUMMARY OF ENGINE EXHAUST ANALYSIS ---- POINT NUMBER 5 HP= 7252, %Full Load=100.0, Elev= 4800ft, %RH= 60.0, Temperature=l00.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: CHOICE GAS 25.09 in Hg 60.0 percent 0.0305 --- AMBIENT PRESSURE RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = 993.0 SG = 0.6221 W.I. @6OF (Btu/Scf) = 1259.0 Gas Fuel Suitability (GFS)# 20967 Methane (CH4) Ethane (C2H6) Propane (C3H8) I -Butane (C4H10) Nitrogen (N2) Sulfur Dioxide (SO2) 86.1699 = 12.3500 0.4000 = 0.0100 1.0700 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg. NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of Engineering review is required when methane drops below 80% or exceed standard boundaries. Performance as modeled here should note that alterations to the combustion and package systems may GENERAL OUTPUT DATA 2738. 960.89 20914. 993. 34590. 115760. 153770. 4698.9 4684.6 28.12 55.34 EXHAUST GAS ANALYSIS lbm/hr Scfm Btu/lbm Btu/Scf Scfm Acfm lbm/hr deg R deg R fuel blends, however other constituents be accurate, but be necessary. FUEL FLOW FUEL FLOW LOWER HEATING VALUE LOWER HEATING VALUE EXHAUST FLOW @ 14.7 PSIA. & 60F ACTUAL EXHAUST FLOW CFm EXHAUST GAS FLOW ADIA STOICH FLAME TEMP, CHOICE GAS ADIA STOICH FLAME TEMP, SDNG MOLECULAR. WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 02 0.86 0.96 1889. 0.69 3.04 3.39 7326. 2.68 10.21 72.33 13.54 0.00 80.56 15.08 10058. 110796. 23697. 3.67 40.47 8.66 VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 5 Fuel: CHOICE GAS Customer:. DCP Midstream Prairie Gas Pla Water Injection: NO Inquiry Number: Model: TAURUS 70-10802S ESC CS/MD STANDARD DAY GAS Emissions Data: REV. 0.1 The following predicted emissions performance is based on the following specific single point: HP= 7252, %Full Load=100.0, Elev= 4800ft, %RH= 60.0, Temperature=100.0F NOX 13.00 12.68 0.051 0.54 CO 25.00 14.84 0.059 0.63 2.89 3.39 UHC 25.00 PPMvd at 15% O2 8.50 ton/yr 0.034 lbm/MMBtu (Fuel. LHV) 0.36 lbm/(MW-hr) (gas turbine shaft pwr) 1.94 lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SOLONOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-SOLoNOx equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification. ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non - warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut -down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID:DN12-001 TAURUS 70-10802S ESC CS/MD STANDARD DAY GAS TBC-2 REV. 2.0 ES-ES2235 ES-ES2235 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon *** GAS GENERATOR SPEED REFLECTS ELEVATED SPEED CONTROL METHODOLOGY. ALL OTHER PERFORMANCE PARAMETERS IDENTICAL TO NON ELEVATED SPEED CONTROL T70 MODELS. *** Fuel Type CHOICE GAS. Elevation feet Inlet Loss in. H2O Exhaust Loss in H2O Engine Inlet Temp. deg F Relative Humidity Elevation Loss - HP .Inlet Loss HP. Exhaust Loss HP 4800 4.0 4.0 0 32.0 59.0 80.0 100.0 30.0 60.0 60.0 60.0-, 60.0 1895 1873 1744 1577 1394 182 181 171 158. 143 68 69 67 63 59 Driven Equipment Speed RPM 11919 11772 11530 11212 10818 Optimum Equipment Speed RPM 11919 11772 11530 11212 10818 Gas Generator Speed RPM 15199 15200 15200 152O0 15200 -Specified Load HP FULL FULL FULL FULL FULL Net Output Power Heat Rate Therm Eff Fuel Flow Nom Nom Nom Nom Net Output Heat Rate Therm Eff Fuel Flow HP Btu/HP-hr mmBtu/hr 9586 9472 8813 7965 7035 7598 7375 7531 7776 8139 33.489 34.502 33.788 32.723 31.264 72.83 69.86 66.37 61.94 57.25 Power HP 9883 9765 9085 8212 7252 Btu/HP-hr 7370 7153 7305 7543 7894 % 34.525 35.570 34.833 33.735 32.231 mmEtu/hr 72.83 69.86 66.37 61.94 57.25 Inlet Air Flow lbm/hr Engine Exhaust Flow lbm/hr PCD. psiG Compensated. PTIT deg F PT Exit Temperature deg F Exhaust Temperature deg F 195837 186877 176050 .1647.23 151487 198732 189656 178695 167190 153770 210.5 208.5 197.4 184.4 169.4 1372 1377 1400 1399 1398 894 904. 941 966 998 888 904 941 966 998 FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = 993.0 SG. = 0.6221 W.I. @60F (Btu/Scf) = 1259.0 Gas Fuel Suitability (GFS)# 20967. Methane (CH4) Ethane (C2H6) Propane (C3H8) = 86.1699 = 12.3500 .= 0.4000 I -Butane (C4H10) Nitrogen (N2) Sulfur Dioxide (S02) = 0.0100 1.0700 = 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of fuel blends, however Engineering review is required when methane drops below BO% or other constituents exceed standard boundaries. Performance as modeled here should be accurate, but note that alterations to the combustion and package systems may be necessary. This performance was calculated with a basic inlet and exhaust system. Special equipment such as low noise silencers, special filters, heat recovery systems or cooling devices will affect engine performance. Performance shown is "Expected" performance at the pressure drops stated, not guaranteed. 10/17/13 State.co.us Eecutive Branch Mail - RE: TurbinesMMRUs BACT Lang uage for Lucerne 2 STATE OF COLORADO RE: Turbines/WHRUs BACT Language for Lucerne 2 Stephens, Dana <DStephens@dcpmidstream.com> Thu, Sep 19, 2013 at 2:22 PM To: Roshini Shankaran <RShankaran@trinityconsultants.com>, "Money - CDPHE, Carissa" <carissa.money@state.co.us> Cc: "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us> Carissa, Here's the explanation from our engineer. The quantity known as lower heating value (LHV) is determined by subtracting the heat of vaporization of the water vapor from the higher heating value. This treats any H2O formed as a vapor. The energy required to vaporize the water therefore is not released as heat. LHV calculations assume that the water component of a combustion process is in vapor state at the end of combustion, as opposed to the higher heating value (HHV) which assumes that all of the water in a combustion process is in a liquid state after a combustion process. The LHV assumes that the latent heat of vaporization of water in the fuel and the reaction products is not recovered. It is useful in comparing fuels where condensation of the combustion products is impractical, or heat at a temperature below 150 degrees C cannot be put to use. In the turbine/WHRU unit, water in the exhaust will remain in the vapor form. The energy required to vaporize water cannot be recovered. Therefore, in a thermal efficiency calculation, LHV should be used. Using HHV would mean that the energy to vaporize water could be recovered. Both HHV and LHV should be specified in the fuel analysis. HHV is typically the basis for emission factors that are in the form of Ib/mmbtu and LHV is the correct basis for thermal efficiency calculations. Let me know if you need additional information on this. Dana From: Roshini Shankaran [mailto:RShankaran@trinityconsultants.com] Sent: Thursday, September 19, 2013 12:55 PM To: Money- CDPHE, Carissa; Stephens, Dana Cc: stephanie.chaousy@state.co.us Subject: RE: Turbines/WHRUs BACT Language for Lucerne 2 Carissa, I do have the answer for the first question since I asked the sanie question hack when DCP first put the proposed conditions together. 2,544 Btu/hr =1 hp — this is just simple unit conversion! Thanks, Roshini https://mail.goog le.com/mail/u/0/?ui=2&ik=,da5742cbb2&viev pt&cat=DCP Lucerne&search=cat&th=14137e3d745101e4 1/4 10/17/13 State_co.us Executive Branch Maif - RE: Turbines/WHRUS BACT Language for Lucerne 2 Roshini Shankaran Senior Consultant Trinity Consultants 1391 N Speer Blvd, Suite 350 I Denver, CO 80204 Office: 720-638-7647 Email: rshankaran@trinityconsultants.corn_ From: Money - CDPHE, Carissa[mailto:carissa.money@state.co.usj Sent: Thursday, September 19, 2013 12:47 PM To: Stephens, Dana Cc: stephanie.chaousy@state.co.us; Roshini Shankaran Subject: Re: Turbines/WHRUs BACT Language for Lucerne 2 Dana, am working through the proposed conditions and have a few questions on the equations for calculating thermal efficiency. Can you explain what the value of 2,544 btu/hp-hr in Equation 2 represents and is based on? It appears to be a heat rate but it is much lower than the heat rate provided on the Solar spec sheet. The heat rate on the spec sheet is 7,537 btu/hp-hr. Also, can you clarify why Equation 4 uses the Fuel LHV instead of HHV? The fuel sampling that is required by the permit specifies HHV. Thanks, Carissa Money Oil and Gas Permit Engineer Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3229 email: carissa.money@state.co.us On Tue, Sep 17, 2013 at 3:20 PM, Stephens, Dana <DStephens@dcpmidstream.com> wrote: Stephanie and Carissa, Please find attached a) the proposed draft language for the turbines/WHRUs BACT condition for the permit, b) the Solar Turbines Predicted Engine Performance sheet, and c) the Xceltherm 600 Engineering Properties sheet. The information below is to support the technical review document you are working on. Please let me know if you have any questions or comments on the proposed language. Thanks again for the opportunity to meet last week to discuss the permit conditions. Thanks, https://mail.google.conYmail/u/0/?ui=2&ik=da5742cbb2& iewppt&cat=DCP Lucerne&search=cat&th=14137e3d745101e4 2/4 ` 10/17/13 uana State.co.us Executive Branch Mail - RE: Turbines/WHRUs BACT Language for Lucerne 2 Dana M. Stephens, REM Rockies Air Permitting Manager DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 . Office - (303) 605-1745 . Mobile - (720) 355-4703 Email - dstephens@dcpmidstream.com<mailto:dstephens@dcpmidstream,com> DCP expects to operate the turbines between 50% to 100% load. DCP feels that an average turbine load of 70% is appropriate given the expected gas processing rate variations and ambient conditions which affect actualturbine load. Solar rates the Solar Taurus 70 thermal efficiency as 27% at a 70% load as -indicated in the attached manufacturer performance. sheet. The waste heat recovery unit (WHRU) manufacturer estimates that the WHRUs are capable of an additional 20% thermal efficiency with exhaust conditions at 70% turbine load. The theoretical average combined turbines/WHRUs thermal efficiency could be as high as 47%. However, there are many factors that will reduce the actual thermal efficiency achieved by the turbines/WHRUs system: The demand for thermal energy from the plant processes will not be constant. Varying inlet gas flow rates change thermal energy demand and thermal energy demand will vary with ambient temperature and seasonally. The WHR units themselves will require periodic maintenance, DCP is, however, incentivized to maximize the thermal efficiency of the WHRUs since the alternative is burning fuel (at a cost to DCP) in the Hot Oil Heater. For these reasons, DCP is proposing a BACT thermal efficiency limit for the turbines/WHRUs of 40%, on a 12 - month rolling average basis. DCP will measure the following parameters to demonstrate compliance with this condition: Fuel flowrate to the turbines (MMscf/hr) as required per Condition 25 d. Fuel LHV (Btu/scf) as determined per Condition 25 c. - Horsepower for each of the turbines (hp) Hot oil flowrate to each WHRU (lb/hr) as determined per Condition 25 i. Hot oil temperature into each WHRU (°F) and hot oil temperature out of each WHRU (°F) as determined per Condition 25 i. Each of these parameters (except fuel LHV), will be monitored and recorded by the plant control system. Thermal efficiency of the turbines/WHRUs system will be calculated as proposed in the attached turbine draft permit conditions. The information transmitted is intended only for the person or entity to which it is addressed and may contain confidential and/or privileged material. Any review, retransmission, dissemination or other use of, or taking of any action in reliance upon, this information by persons or entities other than the intended recipient is prohibited. If you Received this in error, please contact the sender and delete the material from any computer. https://rnail.g oog le.corrdmail/u/0/?ui=2&ilFda5742cbb2&viev,Fpt&cat=DCP Lucerne&search=cat&th= 14137e3d745101e4- 3/4 10/17/13 State.co.us ErecutKe Branch Mail - RE: TurbinesN HRUs BACT Language for Lucerne 2 https://maiLgoogle.cons/mail/u/0/?ul=2&ik=da5742cbb28odievrpt&c4i=DCP Lucerne&search=cat&th=14137e3d745101e4 4/4 XCELTHERM® 600 Engineering Properties* Temperature j` Industries Viscosity Density Heat Capacity Thermal Conductivity Vapor Pressure °F °C cP lb/ft3 kg/m3 BTU/lb-°F J/g-K BTU/ft-hr-°F W/m-K psia kg/cm2 50 10 75.697 53.6 857.8 0.467 1.96 0.0791 0.1369 - - 60 15.6 50.182 53.3 854.4 0.472 1.98 0.0788 0.1364 - - 65 18.3 41.886 53.2 852.7 0.474 1.99 0.0787 0.1362 - - 70 21.1 35.431 53.1 851.1 0.477 1.99 0.0785 0.1359 - - 80 26.7 26.191 52.9 847.7 0.481 2.01 0.0783 0.1355 - - 90 32.2 20.055 52.7 844.4 0.486 2.03 0.078 0.135 - - 100 37.8 15.489 52.5 841 0.49 2.05 0.0778 0.1347 - - 110 43.3 12.087 52.3 837.6 0.497 2.08 0.0775 0.1342 - - 120 48.9 9.734 52.1 834.3 0.501 2.1 0.0773 0.1338 - - 130 54.4 7.973 51.9 830.9 0.506 2.12 0.077 0.1333 - - 140 60 6.625 51.7 827.5 0.51 2.13 0.0768 0.1329 - - 150 65.6 5.574 51.4 824.1 0.515 2.15 0.0765 0.1324 - - 160 71.1 4.742 51.2 820.8 0.519 2.17 0.0762 0.132 - - 170 76.7 4.072 51 817.4 0.524 2.19 0.076 0.1315 - - 180 82.2 3.526 50.8 814.1 0.528 2.21 0.0757 0.1311 - - 190 87.8 3.077 50.6 810.7 0.533 2.23 0.0755 0.1306 - - 200 93.3 2.703 50.4 807.3 0.537 2.25 0.0752 0,1302 0 0.0001 210 98.9 2.432 50.2 804 0.542 2.27 0.0749 0.1297 0 0.0001 220 104.4 2.191 50 800.6 0.546 2.29 0.0747 0.1293 0 0.0001 230 110 1.983 49.8 797.2 0.551 2.3 0.0744 0.1288 0 0.0002 • 240 115.6 1.801 49.6 793.8 0.555 2.32 0.0742 0.1284 0 0.0003 250 121.1 1.642 49.3 790.5 0.56 2.34 0.0739 0.1279 0.01 0.0004 260 126.7 1.503 49.1 787.1 0.564 2.36 0.0736 0.1275 0.01 0.0005 270. 132.2 1.382 49 785.4 0.569 2.38 0.0734 0.127 0.01 0.0007 280 137.8 1.27 48.7 780.3 0.573 2.4 0.0731 0.1266 0.01 0.0009 290 143.3 1.172 48.5 776.9 0.578 2.42 0.0729 0.1261 0.02 0.0011 300 148.9 1.085 48.3 773.6 0.582 2.44 0.0726 0.1257 0.02 0.0015 310 154.4 1.01 48.1 770.2 0.587 2.46 0.0723 0.1252 0.03 0.0019 320 160 0.945 47.9 766.8 0.591 2.47 0.0721 0.1248 0.03 0.0024 330 165.6 0.885 47.7 763.4 0.596 2.49 0.0718 0.1243 0.04 0.003 340 171.1 0.832 47.5 760.1 0.6 2.51 0.0716 0.1239 0.05 0.0037 350 176.7 0.783 47.2 756.7 0.605 2.53 0.0713 0.1234 0.07 0.0046 360 182.2 0.737 47 753.3 0.609 2.55 0.071 0.123 0.08 0.0057 370 187..8 0.696 46.8 749.9 0.614 2.57 0.0708 0.1225 0.1 0.007 380 193.3 0.658 46.6 746.6 0.618 2.59 0.0705 0.1221 0.12 0.0085 390 198.9 0.623 46.4 743.2 0.623 2.61 0.0703 0.1216 0.15 0.0103 400 204.4 0.59 46.2 739.8 0.627 2.62 0.07 0.1212 0.18 0.0124 410 210 0.559 46 736.4 0.632 2.64 0.0697 0.1207 0.21 0.0149 420 215.6 0.532 45.8 733 0.636 2.66 0.0695 0.1203 0.25 0.0178 430 221.1 0.507 45.6 729.7 0.641 2.68 0.0692 0.1198 0.3 0.0212 440 226.7 0.483 45.3 726.3 0.645 2.7 0.069 0.1194 0.36 0.0251 450 232.2 0.46 - 45.1 722.9 0.65 2.72 0.0687 0.1189 0.42 0.0297 XCELTHERM® 600 Engineering Properties* " Temperature Industries Viscosity Density ' Heat Capacity Thermal Conductivity Vapor Pressure °F °C cP Ib/ft3 kg/m3 BTU/Ib-°F J/g-K BTU/ft-hr-°F W/m-K psia kg/cm2 460 237.8 0.439 44.9 719.5 0.654 2.74 0.0684 0.1185 0.5 0.0349 470 243.3 0.42 44.7 716.2 0.659 2.76 0.0682 0.118 - 0.58 0.0409 480 248.9 0.402 44.5 712.8 0.663 2.78 0.0679 0.1176 0.68 0.0479 490 254.4 0,385 44.3 709.4 0.668 2.79 0.0677 0.1171 0.79 0.0557 500 260 0.368 44.1 706 0.672 2.81 0.0674 0.1167 0.92 0.0647 505 262.8 0.358 44 704.3 0.674 2.82 0.0673 0.1164 0.99 0.0697 510 265.6 0.351 43.9 702.6 0.677 2.83 0.0671 0.1162 1.07 0.075 520 271.1 0.337 43.7 699.3 0.681 2.85 0.0669 0.1158 1.23 0.0866 530 276.7 0.325 43.4 695.9 0.686 2.87 0.0666 0.1153 1.42 0.0997 540 282.2 0.313 43.2 692.5 0.69 2.89 0.0664 0.1149 1.63 0.1145 550 287.8 0.301 43 689.2 0.695 2.91 0.0661 0.1144 1.87 0.1312 560 293.3 0.29 42.8 685.9 0.699 2.93 0.0658 0.114 2.13 0.1499 570 298.9 0.281 42.6 682.5 0.704 2.94 0.0656 0.1135 2.43 0.1709 580 304.4 0.27 42.4 679.1 0.708 2.96 0.0653 0.1131 2.76 0.1944 590 310 0.261 42.2 675.7 0.713 2.98 0.0651 0.1126 3.14 0.2206 600 315.6 0.252 42 672.4 0.717 3 0.0648 0.1122 3.55 0.2499 * Data Represents typical laboratory samples and are not guaranteed for all samples. Turbine BACT Limit d. Points 044 and 045: The owner or operator shall install and maintain an operational continuous fuel flow monitor for each turbine at the inlet. The fuel flow monitors shall be calibrated at a minimum frequency of at least once every twelve months and shall be used to measure and record the volume of fuel on a daily basis. Points 044 and 045: The oil flow rate and inlet and outlet temperature on the hot oil system that uses the recovered heat from the WHRUs system shall be recorded on a daily basis. Points 044 and 045: The combustion turbines and the WHRUs system shall meet a BACT limit of 40% minimum thermal efficiency on a 12 -month rolling average basis. k. Points 044 and 045: Compliance with the BACT limit will be based on the following equations, calculated each day of operation using data collected for Conditions 25 c, d, and i (Eqn 1.): Where: Eqn 2. Eqn 3. Note: Oil heat capacity is from Xceltherm 600 Data Sheet. Eqn 4. Points 044 and 045: All monitors identified in Conditions 25 b through k shall achieve 95% operational time or greater on a daily average basis. Solar'Turbines A Caterpillar Company Customer DCP Midstream Job ID Lucerne Run By Michael E Clay Date Run 11 -Sep -13 Engine Performance Code REV. 4.8.1.10.4 Engine Performance Data REV. 2.0 PREDICTED ENGINE PERFORMANCE Model TAURUS 70-10802S ESC Package Type CS/MD Match STANDARD DAY Fuel System GAS Fuel Type SD NATURAL GAS DATA FOR MINIMUM PERFORMANCE Elevation feet Inlet Loss in H2O Exhaust Loss in H2O Accessory on GP Shaft HP Engine Inlet Temperature deg F Relative Humidity Driven Equipment Speed RPM Specified Load HP Net Output Power HP Fuel Flow mmBtu/hr Heat Rate Btu/HP-hr Therm Eff Engine Exhaust Flow Ibm/hr PT Exit Temperature deg F Exhaust Temperature deg F Fuel Gas Composition (Volume Percent) Fuel Gas Properties 4800 4.0 10.0 26.0 60.0 60.0 9141 50.0% 4323 50.07 11581 21.970 142103 1053 998 60.0 60.0 9751 60.0% 5188 53.85 10380 24.512 150930 1022 985 60.0 60.0 10259 70.0% 6053 57.17 9445 26.939 158504 994 972 Methane (CH4) 92.79 Ethane (C2H6) 4.16 Propane (C3H8) 0.84 N -Butane (C4H10) 0.18 N -Pentane (C5H12) 0.04 Hexane (C6H14) 0.04 Carbon Dioxide (CO2) 0.44 Hydrogen Sulfide (H2S) 0.0001 Nitrogen (N2) 1.51 60.0 60.0 10682 80.0% 6917 60.21 8704 29.233 165718 969 958 60.0 60.0 11046 90.0% 7782 62.91 8084 31.477 172093 947 943 60.0 60.0 11438 FULL 8646 66.11 7646 33.280 177726 948 948 LHV (Btu/Scf) 939.2 I Specific Gravity 0.5970 Wobbe Index at 60F 1215.6 This performance was calculated with a basic inlet and exhaust system. Special equipment such as low noise silencers, special filters, heat recovery systems or cooling devices will affect engine performance. Performance shown is "Expected" performance at the pressure drops stated, not guaranteed. 10/17/16 State.co.us E,acutite Branch Mail - FW: Lucerne HHV/GHG updates and proposed BACT requirement language STATE OF COLORADO FW: Lucerne HHV/GHG updates and proposed BACT requirement language Stephens, Dana <DStephens@dcpmidstream.com> To: "carissa.money@state.co.us" <carissa.money@state.co.us> Cc: "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us>, "Roshini Shankaran (rshankaran@trinityconsultants.com)" <rshankaran@trinityconsultants.com> Carissa, Please see DCP's answers below in blue. Wed, Sep 18, 2013 at 2:05 PM I am reviewing the revised turbine emissions and I'm struggling to follow the revisions. First, the turbine calculations indicate that to achieve HHV, the LHV was multiplied by 1.1. Looking at the Solar spec sheet, the LHV is 993 so I don't calculate the same adjusted HHV. I calculate 1.0923 x 10-3 MMbtu/scf instead of 9.988 x 10-4. Can you please explain your heat value calculations? The revised turbine emissions refer to the revised heat input of the turbine (now based on HHV basis), which was increased from 66.12 MMBtu/hr x 1.1 = to 72.73 MMBtu/hr. Note that the HHV does not affect the emission calculations since the emissions are not dependent on the volume of fuel combusted or the heat content of the fuel, but the heat input of the turbine. A revised APEN will be submitted reflecting the change in heat input and consumption of fuel. Additionally, the Solar engine exhaust analysis that was used as the revised basis for the CO2 emission factor also includes higher emission factors for CO, NOx and UHC. However, it appears that you are still using the lower emission values for CO, NOx and UHC as presented on the original spec sheet. It seems that all emissions should be based on the engine exhaust analysis instead of the lower values from the spec sheet. For example, UHC emission factor should be 2.54 lb/hr instead of 2.29 lb/hr. Please explain why you are only using the CO2 emission factor from the engine exhaust analysis. The most recent engine exhaust analysis is the only Solar guarantee obtained for CO2 emissions since these emissions were not included in the standard conditions spec sheet provided earlier. Additionally, since CO2 is a PSD-triggering pollutant, DCP would like to request a buffer in the compliance margin and feels comfortable with the highest emission rates provided by Solar (which are far higher than 40 CFR 98 Subpart C). As for UHC, a very conservative estimate is made to assume that all UHC equals CH4. Since there is already a great deal of conservatism built into that assumption (it's probably more like 80 - 90% of UHC rather than a 100% of UHC), DCP did not feel it necessary to add in an additional buffer by taking the worst -case emissions from the varying scenarios. NOx and CO are also retained from the average condition spec sheet because the regulatory limit for NOx is 25 ppm provided by NSPS Subpart KKKK. The turbine is guaranteed to achieve 13 ppm in any condition, and therefore DCP believes that a buffer is not required. DCP will ensure compliance with the NOx and CO lb/month limits while retaining the average emission factors from the spec sheet. Hope this answers your questions. Thanks Dana Dana M. Stephens, REM DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Office - (303) 605-1745 Mobile - (720) 355-4703 Email - dstephens@dcpmidstream.com https://mail.g cog le.cormrnail/u/0/?ui=2&ilyda5742cbb2&NeaFpt&cat=DCP Lucerne&search=cat&th= 14132ade6fe2b0a7 1/4 10/17/13 State.co.us Eecutike Branch Mail - FW: Lucerne HHV/GHG updates and proposed BACT requirement language From: Money - CDPHE, Carissa [mailto:carissa.money@state.co.us] Sent: Tuesday, September 17, 2013 4:52 PM To: Stephens, Dana; Roshini Shankaran Cc: stephanie.chaousy@state.co.us<mailto:stephanie.chaousy@state.co.us> Subject: Fwd: Lucerne HHV/GHG updates and proposed BACT requirement language Dana, I am reviewing the revised turbine emissions and I'm struggling to follow the revisions. First, the turbine calculations indicate that to achieve HHV, the LHV was multiplied by 1.1. Looking at the Solar spec sheet, the LHV is 993 so I don't calculate the same adjusted HHV. I calculate 1.0923 x 10-3 MMbtu/scf instead of 9.988 x 10-4. Can you please explain your heat value calculations? Additionally, the Solar engine exhaust analysis that was used as the revised basis for the CO2 emission factor also includes higher emission factors for CO, NOx and UHC. However, it appears that you are still using the lower emission values for CO, NOx and UHC as presented on the original spec sheet. It seems that all emissions should be based on the engine exhaust analysis instead of the lower values from the spec sheet. For example, UHC emission factor should be 2.54 lb/hr instead of 2.29 lb/hr. Please explain why you are only using the CO2 emission factor from the engine exhaust analysis. I'm continuing to review but wanted to send some of questions as they come up. Thank you, Carissa Money Oil and Gas Permit Engineer Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3229 email: carissa.money@state.co.us<mailto:carissa.money@state.co.us> --- Forwarded message From: Chaousy - CDPHE, Stephanie <stephanie.chaousy@state.co.us<mailto:stephanie.chaousy@ state.co.us>> Date: Wed, Aug 28, 2013 at 4:12 PM Subject: Fwd: Lucerne HHV/GHG updates and proposed BACT requirement language To: Christopher Laplante - CDPHE <christopher.Iaplante@state.co.us<mailto:christopher. Iaplante@state.co.us>>, "carissa.money@state.co.us<mailto:carissa.money@state.co.us>" <carissa.money@state.co.us<mailto:carissa.money@state.co.us>> ---- Forwarded message From: Stephens, Dana <DStephens@dcpmidstream.com<mailto:DStephens@dcprnidstream.com>> Date: Wed, Aug 28, 2013 at 4:11 PM Subject: Lucerne HHV/GHG updates and proposed BACT requirement language To: "stephanie. chaousy@state.co.us<mailto:stephanie.chaousy@state.co.us>" <stephanie.chaousy@state.co. us<mailto: stephanie.chaousy@state. co.us>> Cc: "Stevenson, Peter F" <PFStevenson@dcpmidstream.com<mailto:PFStevenson@dcpmidstream.com», "Roshini Shankaran. (rshankaran@trinityconsultants.com<mailto:rshankaran@trinityconsultants.com>)" <rshankaran@trinityconsultants.com<mailto:rshankaran@trinityconsultants.com>>, "Stephens, Dana" <DStephens@d cpm idstream. com<mailto: DStephens @dc pm idstream. com>> Stephanie, Per a recent discussion with Solar Turbines, the manufacturer of the turbines proposed to be installed at Lucerne 2, it was discovered that the specification sheet provided the heat input to the turbine of 66.12 MMBtu/hr on a https ://mail .google.cor Vmail/u/0/?ui=2&ilyda5742cbb2&tievi=pt&cat=DCP Lucerne&search=cat&th=14132ade6fe2b0a7 2/4 10/1,113 State.co.us Executive Branch Mail - FW: Lucerne HHV/GHG updates and proposed BACT requirement tang uage lower heating value (LHV). basis. In order to convert the LHV to a higher heating value (HHV) basis, DCP increased the LHV by about 10% to 66.12 x 1.1 = 72.73 MMBtu/hr. DCP requests that this heat input be reflected throughout the permit. Additionally, Solar was also able to provide emission information on CO2 and CH4 based on an engine exhaust analysis. DCP has updated the emissions of CO2 from the engine exhaust analysis and has set unbumed hydrocarbon (UHC) on the specification sheet provided previously equal to methane to be conservative. N2O is still calculated using 40 CFR 98 Subpart C emission factors. The emission calculations reflecting these updates are attached. Accordingly, the permit condition revision requested relates to the revised emission estimate for CO2e from the turbines. DCP is also requesting a 10% safety factor on the hot oil heater CO2e Ib/MMBtu proposed BACT limit. The attached calculations reflect this safety factor in the annual emissions as well. DCP has also reviewed recently issued GHG PSD permits from Region VI and have drafted language for your consideration for the BACT requirements for the turbines, the hot oil heater, and the amine unit/RTO. Please find attached the following items: Revised CO2e emission calculations for the turbines and the hot oil heater; CO2 engine exhaust analysis for turbines; Solar Turbines specification sheet for turbines; and Proposed BACT requirement language for the turbines, the hot oil heater and the amine/RTO. I'm going on vacation but wanted to get this to you before I left. I will be back in the office on September 4th but if you need anything before then, please feel free to contact my boss, Pete Stevenson at 303-605-2035<te1:303- 605-2035>. I've also cc'd him on this email. Have a great Labor Day weekend, Dana Dana M. Stephens, REM Rockies Air Permitting Manager DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Office - (303) 605-1745<tel:%28303%29%20605-1745> Mobile - (720) 355-4703<tel:%28720%29%20355-4703> Email - dstephens@dcpmidstream.com<mailto:dstephens@dcpmidstream.com> Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297<tel:303-692-2297> www.colorado.gov/cdphe<http://www.colorado.gov/cdphe> https://mail.g cog le.con/mail/u/0/?ui=2&ik=da5742cbb2&aevipt&cat—DCP Lucerne&search=cat&th=14132ade6fe2b0a7 3/4 10/17/13 State.co.us Executive Branch Mail - FW: Lucerne HHV/GHG updates and proposed BACT requirement language The information transmitted is intended only for the person or entity to which it is addressed and may contain confidential and/or privileged material. Any review, retransmission, dissemination or other use of, or taking of any action in reliance upon, this information by persons or entities other than the intended recipient is prohibited. If you Received this in error, please contact the sender and delete the material from any computer. winrnail.dat 23K https://mail.g nogle;com/mail/u/0/?ui=2&ilyda5742cbb2&viev,=pt&cat=DCP Lucerne&search=cat&th=14132ade6fe2b0a7 4/4 10/17/13 State.co.us ER:cutive Branch Mail - RE: FW: Question for Lucerne STATE 6F COLO RADO RE: FW: Question for Lucerne Stephens, Dana <DStephens@dcpmidstream.corn> To: "Money - CDPHE, Carissa" <calissa.money@state.co.us> Wed, Sep 11, 2013 at 3:21 PM Thanks, Carissa. We will take a look at this and we look forward to meeting with the three of you tomorrow. From: Money - CDPHE, Carissa [mailto:carissa.money@state.co.us] Sent: Wednesday, September 11, 2013 1:23 PM To: Stephens, Dana Subject: Re: FW: Question for Lucerne Dana, I reserved a conference room for Thursday at 1:30 and I have invited Chris and Stephanie to join us. Also, I wanted to follow up from our call yesterday regarding whether WHRU should be considered as part of BACT for the turbine since the WHRU is not an emitting unit by itself. In EPA's PSD and Title V Permitting Guidance for Greenhouse Gases, EPA discusses in some detail that for GHG in particular BACT should be evaluated across the process and not just from a single emitting unit. "The application of BACT to GHGs has the potential to place greater importance on determining the scope of the entity or equipment to which BACT applies. Under existing rules, a permitting authority evaluating applications to construct new sources has the flexibility to consider source -wide energy efficiency strategies (over an entire production process or across multiple production process) to reduce GHG emissions from the proposed new source. EPA interprets the language of the BACT definition in CAA §169, which requires consideration of "production processes and available methods, systems, and techniques ... for control of [each] pollutant," to include control methods that can be used facility -wide." (page 23) EPA also emphasizes throughout the guidance document that energy efficiency is an important part of BACT for GHG sinceadd-on control options for GHG are limited. https://nail.google.corn/mail/u/0/?ui=2&iirda5742cbb2&Nev pt&cat=DCPLucerne&search=cat&th=1410ee6bOf39ccc5 1/6 10/17/13 State.co.us Eecuthe Branch Mail - RE: FW: Question for Lucerne "The application of methods, systems, or techniques to increase energy efficiency is a key GHG-reducing opportunity that falls under the category of "lower -polluting processes/practices." Use of inherently lower -emitting technologies, including energy efficiency measures, represents an opportunity for GHG reductions in these BACT reviews. In some cases, a more energy efficient process or project design may be used effectively alone; whereas in other cases, an energy efficient measure may be used effectively in tandem with end -of -stack controls to achieve additional control of criteria pollutants." (page 29) While the WHRU is not an emitting unit by itself, it is an energy efficient measure that can be applied as BACT for the process. It makes sense to associate it with the turbine since parametric monitoring of the turbine will be needed to understand the energy efficiency gained. Hopefully this information can give some background for why it was appropriate to identify WHRU as BACT for the turbine. Thank you, CarissaMoney Oil and Gas Permit Engineer Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3229 email: carissa.money@state.co.us On Tue, Sep 10, 2013 at 5:04 PM, Stephens, Dana <DStephens@dcpmidstream.com> wrote: Let's tentatively schedule it for 1:30 pm on Thursday. Should we plan on coming to your office? Might be easier to have a face to face meeting. It will be me, Roshini Shankaran (Trinity), Jeff Ross and possibly another turbine engineer. I will confirm with my side and send you an email tomorrow. httpsJ/mail.googIe.com/mail/u/0/?ui 2&ik=da5742cbb2&Hern"pt&cat=DCP Lucerne&search=cat&th=1410ee6b0139ccc5 2/6 10/17/13 - State.co.us Eecutire Branch Mail - RE: FW: Question for Lucerne From: Money - CDPHE, Carissa [mailto:carissa.money@state.co.us] Sent: Tuesday, September 10, 2013 4:11 PM To: Stephens, Dana Subject: Re: FW: Question for Lucerne OK. The call I already have scheduled on Thursday should be over by 4:30 if that helps. Carissa Money Oil and Gas Permit Engineer Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3229 email: carissa.money@state.co.us On Tue, Sep 10, 2013 at 3:35 PM, Stephens, Dana <DStephens@dcpmidstream.com> wrote: Carissa, I'll shoot you an email tomorrow with a time fora meeting on Thursday. Our engineer has a dr's appt. on Thursday that he was going to try and reschedule. Thanks Dana From: Money - CDPHE, Carissa [mailto:carissa.money@state.co.us] Sent: Tuesday, September 10, 2013 10:55 AM To: Stephens, Dana Cc: stephanie.chaousy@state.co.us; Roshini Shankaran(rshankaran@trinityconsultants.com); Kimberly Ayotte (kayotte@trinityconsultants.com); Christopher Laplante - CDPHE(christopher.laplante@state.co.us) Subject: Re: FW: Question for Lucerne Dana, Thank you for the additional WHRU information. As we discussed on the phone this morning, DCP stated in the BACT analysis for turbines that overall energy efficiency would be increased by utilizing waste gas heat from the turbines. In this latest email, you have clarified that waste gas heat from the turbine will be used to heat hot oil for the amine units. It seems then that DCP should be able to measure and calculate how much energy is recovered from the turbines and then used to heat the hot oil. Can you clarify why DCP cannot measure this energy recovery? httns:!mail.aooaIe.comlmail/uf0/?ui=2&ilyda5742cbb2&vieu.Fpt&cat=DCP Lucerne&search.=cat&th=1410ee6b0f39ccc5 3/6 10/17/13 - State.co.us Exxcuthe Branch Mail - RE: FW: Question for Lucerne I'm available anytime before 3:30 on Thursday if you are able to schedule some time to discuss in more detail. Thank you, Carissa Money Oil and Gas Permit Engineer Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3229 email: carissa.money@state.co.us On Fri, Aug 23, 2013 at 11:30 AM, Stephens, Dana <DStephens@dcpmidstream.com> wrote: Hi Stephanie, Our WHRU expert put together this information on waste heat recovery units and I wanted to pass it on for your review. By definition a waste heat recovery unit (WHRU) is a piece of passive equipment that is typically placed on the exhaust of a host system to utilize heat, that under ordinary circumstances, would not be used for any other purpose. In other words the heat source is "wasted heat" The WHRU has no effect on the emissions in the exhaust of the host system, but converts the waste heat from the host system into useable energy by either generating steam that can be used in a plant, or by absorbing this heat into a heating oil that can then be used in various reboilers located throughout the plant. In order for a WHRU to be effective, it must have a significant heat source. Gas fired turbines are typically utilized at gas processing plants to either generate electricity or to compress the natural gas that is discharged from the plant to the various pipeline transmission companies. Because the turbines are designed to efficiently compress very large volumes of gas or to generate large amounts of electrical power, they consume large volumes of fuel gas and have typical exhaust temperatures that average over 900 degrees F. Due to the high temperatures and the volume of the combusted fuel gases, it is possible to recover millions of BTU/hr heating value. All gas plants must generate heat to supply the various reboilers located throughout the plant. Given the amine reboiler as an example, the heat could be generated by the following methods: 1. It can be direct fired which would use fuel gas 2. It can be supplied by hot oil from a direct fired heat medium oil heater https://mail.g nog le.com/mail(u/0/?ui=2&ilrida5742cbb2&uevi9tt&cat=DCP Lucerne&search=cat&th=1410ee6b0f39ccc5 - 4/6 10/17/13 a. 4 • State.co.us Executive Branch Mail - RE: FW: Question for Lucerne 3. It can use hot oil that is heated by a WHRU DCP has chosen to use Option 3 at Lucerne 2. , DCP indicated the WHRU in the permit application in the combustion turbine BACT section simply because the WHRU will be physically located on the gas fired turbine. The turbine emissions are unchanged with the WHRU. Therefore, _.,DCP requests the WHRU and efficiency limitation be removed from the BACT conditions for the turbine under Condition )25. i. As for the selection of the Solar turbines, it's just a good fit for the horsepower requirements. Solar has catered to the needs of our industry and we have an excellent working relationship with them across the U.S. They are a strong leader `in the industry. As always, DCP appreciates the opportunity to provide comments. Have a nice weekend, 'Dana Dana M. Stephens, REM DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Office -1303) 605-1745 Mobile - (720) 355-4703 Email — dstephens@dcpmidstream.com From: Chaousy - CDPHE, Stephanie [mailto:stephanie.chaousy@state.co.us] Sent: Thursday, August 15, 2013 3:59 PM ,To: Stephens, Dana; Roshini Shankaran; Kimberly Ayotte(kayotte@trinityconsultants.com); carissa.money@state.co.us; Christopher Laplante - CDPHE Subject: Question for Lucerne Hello Dana, We have been working on the Lucerne permit and have a few questions for you. httos:l/mail.a000le.corrdmail/u/0/?ui=2&ik=da5742cbbaotien= ot&cat=DCP Lucerne&search=cat&th=1410ee6b0t39ccc5 5/6 10/17/13 State.co.us E ecutire Branch Mail - RE: i=W: Question for Lucerne DCP selected waste recovery as an option for the turbine BACT. However, there is not much discussion in the BACT about how DCP will utilize the waste gas heat and what the thermal efficiency DCP is achieving with the waste gas heat. Could you please provide a better discussion of the turbine selection and how DCP decided on Solar versus other types of turbines. Also then if DCP can provide some more information on how the waste gas heat will be utilized and what is the thermal efficiency being achieved from the waste gas heat. Also, per our meeting last week, DCP was going to provide some information on the condition with 60.18, but we have not heard anything from you yet. If you can provide this as well at this time, that would be great. Thank you, Stephanie Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297 www. colorado. gov/cdphe https://mail.goog I e.com/rnail/u/0/?ui= 2&i k= da5742cbb2&vi evPt&cat=DCP Lucerne&search=cat&th=1410ee6bOf39ccc5 6/6 10/21/13 State.co.us Executive Branch Mail - Draft permit for Lucerne STATE OF COLORADO Draft permit for Lucerne Stephens, Dana <DStephens@dcpmidstream.com> Thu, Oct 3, 2013 at 2:52 PM To: "stephanie.chaousy@state.co.us" <stephanie.chaousy@state.co.us> Cc: "Christopher Laplante - CDPHE (christopher.laplante@state.co.us)" <christopher.laplante@state.co.us>, "carissa.money@state.co.us" <carissa.money@state.co.us>, "Roshini Shankaran (rshankaran@trinityconsultants.com)" <rshankaran@trinityconsultants.com>, "Kimberly Ayotte (kayotte@trinityconsultants.com)" <kayotte@trinityconsultants.com>, "Stevenson, Peter F" <PFStevenson@dcpmidstream.com>, "Ondak, Stephen R" <SROndak@dcpmidstream.com> Hi Stephanie, Please find a "tracked changes" Word version of the draft permit for Lucerne, 12WE2024, attached. I have also attached a vendor guarantee received by Optimized Process Furnaces on Tuesday, October 1, 2013. To assist you in your review, I have summarized the comments/changes that are included in the draft permit below: On Page 1, in the Specific Equipment or Activity table for the turbines, additional language on the design rate has been added to specify the ambient temperature. • On Page 2, in the Specific Equipment or Activity table for the amine unit and the dehydrator, additional language has been added for a more accurate description of each piece of equipment. • In Condition 7, the emission limitations tables have been modified to include the correct emissions on a monthly, quarterly, and annual basis. In Condition 8, 59 and 69, sentences are underlined for no apparent reason. • In Condition 10, the "natural gas" has been removed and replaced with "fuel flow" in two places. These changes were made in subsequent conditions by the Division and it appears this condition was simply overlooked. • In Conditions 11, 12, 14, 15, 16, and 70, the term waste gas has been removed and the two streams have simply been separated. These two streams are not combined and will need to be measured and sampled separately. In Condition 16, DCP believes that the Division intended that the H2S be CH4 based on the last sentence of the condition. Please clarify. * In Condition 17, at this time, the design of the facility only includes one VRU. This VRU will be operational 99% of the time as required by the condition. In Conditions 22 and 45, the word "enclosed" was added. In Condition 24, the Process/Consumption Limits tables were updated to show the correct throughputs. In Condition 28 j, the correct lbs CO2/MMscf natural gas input to the heater was included. https://mail.g oog le.com/mail/u/0/?ui=2&ik=7faca29a38&view=pt&search=trash&th= 14180183922e35df 1/3 10/21/13 State.co.us Executive Branch Mail - Draft permit for Lucerne • In Condition 28 ff, DCP has added language regarding the recordkeeping requirement. • In Condition 29 e, DCP modified the language slightly to make it less ambiguous for compliance purposes. In Condition 30, the correct VOC site -wide emission limit was included. • In Condition 59, language that was drafted and approved by Carissa Money for the DCP LaSalle permit was included. In Condition 62, a clarifying sentence was added to the condition. In Condition 67, another option on calculating CO2 emissions was included. In the Notes section, a couple of errors were identified and corrected. I As you are aware, DCP is eager to get this permit to public comment and ultimately issued. If you have any questions or concerns with any of the requested changes, please give me a call to discuss at your earliest convenience. I will be out of town tomorrow (10/4/13) and Monday (10/7/13) and will have little or no access to the outside world! However, I don't want to be the hold up on anything regarding this permit. I have cc'd Pete Stevenson and Stephen Ondak. They are both familiar with this project and can help respond to any questions you might have. Their phone numbers are below. Pete Stevenson, Director of Air Programs - 303-726-8937 Stephen Ondak, Environmental Manager - North Region - 303-718-7821 Trinity is also working on the revised application for the public comment. We should be able to provide that when I return on Tuesday. Thanks again for your diligent effort on this permit. DCP really appreciates it. Dana Dana M. Stephens, REM Rockies Air Permitting Manager DCP Midstream, LP 370 17th Street, Suite 2500 Denver, CO 80202 Office - (303) 605-1745 Mobile - (720) 355-4703 Email - dstephens@dcpmidstream.com<mailto:dstephens@dcpmidstream.com> From: Chaousy - CDPHE, Stephanie [mailto:stephanie.chaousy@state.co.us] Sent: Friday, September 20, 2013 11:18 AM To: Stephens, Dana; Roshini Shankaran; Kimberly Ayotte (kayotte@trinityconsultants.com<mailto:kayotte@ trinityconsultants.com>); carissa.money@state.co.us<mailto:carissa.money@state.co.us>; Christopher Laplante - CDPHE; Mark.McMillan@state.co.us<mailto:Mark.McMillan@state.co.us> Subject: Draft permit for Lucerne Hello Dana, Per our meeting last week, here is the draft permit for Lucerne, 12WE2024. A few things to note: 1. Items highlighted in green: Because of the requested throughput change for the turbines (1.1 increase from https://maiI.google.con mail/u10/?ui=2&ik=7faca29a38&vievFpt&search=trash&th=14180183922e35df 2/3 10/21/13 \a State.co.us FKocutive Branch Mail - Draft permit for Lucerne 66.12 mmbtu/hr to 72.73 mmbtu/hr), several other parameters had to be adjusted to accommodate for this increase, including emissions for VOC, SO2, PM, process throughput, formaldehyde and emission factors for NOx and CO. The following calculations show that they were: VOC = (0.0021 Ib/mmbtu)*(72.73 mmbtu/hr)*(8760 hr/yr) / 2000 = 0.67 TPY PM = (0.0066 Ib/mmbtu)*(72.73 mmbtu/hr)*(8760 hr/yr) / 2000 = 2.10 TPY SO2 = (0.0034 Ib/mmbtu)*(72.73 mmbtu/hr)*(8760 hr/yr) / 2000 = 1.08 TPY NOX E.F. = (15.02 TPY)*2000/ (1023*622.8 mmscf/yr) = 0.0471 lb/mmbtu CO E.F. = (17.61 TPY)*2000/ (1023*622.8 mmscf/yr) = 0.0553 lb/mmbtu Formaldehyde (0.00071 Ib/MMBtu)*(72.73 mmbtu/hr)*(8760 hr/yr) = 452.4 lb/yr These have been highlighted in green for your review. Please make these revisions to the updated application that will be submitted to the Division prior to public comment. 2. I have attached a response letter to all of DCP's previous comments (8/2/13). I think everything has been addressed in the comment letter. 3. Because of the complexity of this permit, I will give you 2 weeks to review and respond to this permit. Please provide comments by Friday, October 4, 2013. Thank you, and have a great weekend. Stephanie Stephanie Chaousy, P.E. Oil and Gas Permitting Engineer Department of Public Health and Environment 303-692-2297 www.colorado.gov/cdphe<http://www.colorado.gov/cdphe> 2 attachments 12WE2024 PERMIT DRAFT 4.docx 946K 10-01-2013 OPF Guarantee.pdf 22K https://mail.goog Ie.comlmai I/u/0/?ui=2&i k=7faca29a38&tiew=pt&search=trash&th= 14180183922e35df 3/3 Lucerne II STATE OF COLORADO Laplante - CDPHE, Christopher <christopher.laplante@state.co.us> Thug Oct 3, 2013 at 12:44 PM. To: "Stephens, Dana" <DStephens@dcpmidstream.com>, Stephanie Chaousy - CDPHE <stephanie.chaousy@state.co.us>, Carissa Money - CDPHE <carissa.money@state.co.us> Dana, Please provide responses to these questions. 1. Please provide a list of all DCP compressor stations and gas plants within the Wattenburg Field and the distance (in miles) of each operation from DCP Lucerne gas plant. 2. For each compressor station and gas plant identified in #1 above, please indicate if any of the gas stream on the outlet of the identified plant flows to the inlet of the DCP Lucerne gas plant. If gas does flow from the outlet of the plant to the inlet of the DCP Lucerne gas plant then please also indicate what other flow paths, if any, the gas could travel if the inlet to the DCP Lucerne gas plant were shut in. Please let me know if you have any questions with this request. Thank you, Chris Christopher Laplante Oil and Gas Permitting Supervisor Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3216 email: christopher.laplante@state.co.us Stephens, Dana <DStephens@dcpmidstream.com> Mon, Oct 14, 2013 at 2:00 PM To: "Laplante - CDPHE, Christopher" <christopher.laplante@state.co.us>, Stephanie Chaousy - CDPHE <stephanie.chaousy@state.co.us>, Carissa Money - CDPHE <carissa.inoney@state.co.us> Cc: "Stephens, Dana" <DStephens@dcpmidstream.com> Hi Chris, Please find attached DCP's response letter addressing your questions from the October 3, 2013 email below. Let me know if you need any additional information. Thank you, Dana Dana M. Stephens, REM Rockies Air Permitting Manager DCP Midstream., LP 370 1 7th Street, Suite 2500 Denver, CO 80202 Office - {303) 605-1745 Mobile — (720) 355-4703 Email--dstephens@dcpmidstream.com From: Laplante - CDPHE, Christopher[mailto:christopher.laplante@state.co.us] Sent: Thursday, October 03, 2013 12:45 PM To: Stephens, Dana; Stephanie Chaousy - CDPHE; Carissa Money - CDPHE Subject: Lucerne II Dana, Please provide responses to these questions. 1. Please provide a list of all DCP compressor stations and gas plants within the Wattenburg Field and the distance (in miles) of each operation from DCP Lucerne gas plant. 2. For each compressor station and gas plant identified in #1 above, please indicate if any of the gas stream on the outlet of the identified plant flows to the inlet of the DCP Lucerne gas plant. If gas does flow from the outlet of the plant to the inlet of the DCP Lucerne gas plant then please also indicate what other flow paths, if any, the gas could travel if the inlet to the DCP Lucerne gas plant were shut in. Please let me know, if you have any questions with this request. Thank you, Chris Christopher Laplante Oil and Gas Permitting Supervisor Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South I Denver, CO 80246-1530 office: 303.692.3216 • Midstream.. October 14, 2013 VIA ELECTRONIC MAIL ONLY Mr. Christopher LaPlante Oil and Gas. Permitting Supervisor Air Pollution Control Division Colorado Department of Public Health and Environment 4300 Cherry Creek Drive. South Denver, Colorado 8.0246-153.0 DCP Midstream ' 370 17th Street, Suite 2500 Denver, Co 80202 303-545-3331 VIA, ELECTRONIC MAIL ONI.,Y Ms. Stephanie Chaousy Oil and Gas Permitting Engineer Air Pollution Control Division Colorado Department of Public Health and Environment 4300. Cherry Creek Drive South Denver, Colorado 80246-1530 Re: Lucerne II Gas Processing Plant— Draft Construction Permit No. 12WE2024 Dear Mr. LaPlante and Ms. Chaousy: This letter supplies information the Division requestedto assist with the source determination for the Lucerne II Gas Processing Plant to be located at 31495 Weld County Road 43, Weld County, Colorado ("Lucerne"), as the same relates to the issuance of the above referenced draft construction permit for the project. We have discussed with you the appropriate' scope of the information DCP should provide for the determination and we present below information that is consistent with the framework the Division established in its July 2010 Response to EPA Order on Petition No. VIII -2008-02 concerning In re Anadarko Petroleum Corp.; Frederick Compressor Station. In the July 2010 response, the Division clarified that it had gone to extraordinary lengths to obtain, compile andanalyze the Frederick Compressor Station permitting action. The Division further indicated thatwhile the effort was unique to the specifics of the EPA order then at issue, it would, in the future, continue to be informed by and use the general record developed in the case to assist it in making future oil and gas sector source determinations that account for the complexities, changed and evolving conditions and operating variables that characterize the infrastructure and commercial framework of the sector. The Division's July 2010 ar,slysis explains, in:particular, that the - application of the "contiguous or adjacent" element of the three-part stationary source definition. can be highly challenging in theoil and gas sector. The analysis recognized that EPAhas, over time, grafted a concept of "interdependency" onto its interpretation of the term "adjacent" (i.e., property that proximally close, but is not actually touching) in cases when property was not otherwise "contiguous" (Le., actually touching); but that the unique engineering and. commercial complexities posed by oil and gas production and midstream operations effectively negated the consideration of interdependency as a determining factor at Frederick and in other similar cases. The. Division. also noted that since EPA. had not promulgated a definition of`proxi.mate" in the PSD or Title V Christopher LaPlante Stephanie Chaousy October 14, 2013 Page 2 regulations, the weight to be given any particular individual EPA office determination regarding what constitutes "proximate," similar to "interdependency," is not binding on the Division.' The Division further determined that the nature and extent of connectedness by pipeline in the oil and gas industry generally, and in the Denver-Julesburg Basin specifically, is unique and that it should be viewed differently than pipeline connectedness in other industries and given less weight in source aggregation analyses. The Division did not adopt a bright'line distance test for assessing proximity of connected facilities, but it did recognize the states of Texas, Oklahoma and Louisiana as having established a'/ mile distance for concluding that pipeline connected facilities within that distance may be, in fact, adjacent (if not otherwise contiguous).2 -As you know, DCP will own and operate Lucerne and it also owns and operates other compressor stations and natural gas processing plants within the 2,300 square mile area that comprises the Denver-Julesburg Basin, which facilities are connected, in various ways and at various points, to 2,800 miles of pipeline.3 That stated, there is no DCP facility located within a mile of Lucerne, nor is there any DCP facility or any other commonly owned source within a two (2) mile radius of Lucerne (i. e., 8 times further than the % mile threshold; in past DCP The difference between contiguous and adjacent is that the former indicates the two facilities/pollutant-emitting activities are physically touching, while the latter implies the facilities/pollutant-emitting activities are not widely separated, though they may not actually touch, According to EPA, determining whether two sources are considered to be contiguous or adjacent requires a case -by -case assessment. See e.g., 45 Fed. Reg. August 7, 1980 42676, 52693-94. The term "adjacent," as written in the 1980 PSD rules and related rule -making preamble makes no reference to interdependence or operational relationship. The EPA introduced this factor as an aide in making case - by -case adjacency determinations. The Division's July 2010 approach to the contiguous and adjacent factor was fashioned two years before the recent holding in Summit Petroleum Corporation v. EPA, 690 P.3d 733 (6th Cir. 2012), in which the court rejected EPA's historic interpretation of the term "adjacent." (EPA petition for re hearing en bane rejected by the 6th Circuit on October 29, 2012 (Case No. 09-4348/10-4572)). 2 The definition of "stationary source" and the component elements of that definition, "building", "structure," "facility" and "installation" as discussed by EPA in its August 7, 1980 PSD rule -making preamble, is confined to what constitutes a "common sense notion of plant", in light of court -ordered directives to EPA to "avoid aggregating pollutant emitting activities that as a group would not fit within the ordinary meaning of `building,' `facility' or `installation."' See 45 Fed, Reg. 42676, 52693-95. As such, the three-part definition of "major stationary source" (i.e., same SIC code, common control, and contiguous/adjacent), merely exists to effectively bound what reasonably comprises a single plant location. As a general matter, DCP's facilities, including but not limited to Lucerne, are standalone separate installations constructed at different times. Common usage of the term "plant" would not apply to various, dispersed individual facilities. By way of example, the Division itself has indicated that it would be inappropriate to refer to a network of commonly owned gas service stations in any given Colorado county as a single "facility" merely because they belong to the same industrial grouping, are under common control, and are geographically located within_the same county receiving the same shipment of the same product. Aggregation in this example, as with Lucerne relative to DCP's other Weld County facilities that are located across a 2,300 square mile area, defies the common sense notion of what constitutes a single facility. 3 DCP's natural gas processing plants and compressor stations are subject to separate two -digit SIC Major Group Codes; 49 for compressor stations and 13 for gas processing plants. As such, DCP's compressor stations and natural gas processing plants lack a common two -digit SIC Major Group Code for purposes of source aggregation. Christopher LaPlante Stephanie Chaousy October 14, 2013 Page 3 source determination. communications with the Division, DCP has voluntarily applied a 2 -mile radius, to provide information, rather than rely on the 'A mile "ruleof thumb" noted by the Division in the July 2010 Frederick determination). In fact, the closest DCP facility to Lucerne is the Libsack Compressor Station, which is located 3.25 miles away (i.e., 13 times further than the 'A quarter mile threshold). Finally, operation of the Libsack Compressor Station is not solely dependent on, nor is it wholly or even primarily dedicated to, Lucerne. In the event either Lucerne or Libsack were to be shut-in or not operate, gathered gas would flow to low pressure areas in DCP's gathering system.4 The above then confirins that: (a) there are no DCP compressor stations or gas plants otherwise. located within % mile of Lucerne; (b) there are no DCP compressor stations or gas plants otherwise located within a. 2 mile radius of Lucerne; (c) that the closest DCP facility to Lucerne is 3.25 miles away; and (d) there is no dedicated relationship between Lucerne and any other compressor station or gas plant that DCP owns or. operates in the Denver-Julesburg Basin. In regard to (d), the Division has asked whether any of DCP's natural gas processing plants are connected to one another. The simple answer to this question is no. Natural gas processing plants receive gathered gas for processing, and then discharge the processed or "residue gas" to residue gas pipelines, while any resulting natural gas liquids ("NGL's") are likewise transported by pipeline or, alternatively, by pressurized trucks to end users natural gas processing plants are not connected to each other. We trust that in light of the oil and gas sector source determination framework the Division established in July 2010, the information supplied herein is responsive to the Division's source determination request and adequate to allow the Division to conclude that the Lucerne project poses no stationary source aggregation issues. Should you have any questions regarding anything set forth in this letter, please contact me at 303-505-1745 or dstephens@dcpmidstream.com.. Sincerely, DCP Midstream, LP \nst,e(TAc31-e.ip Dana Stephens Rockies Air Permitting Manager 4 A fundamental physical principle of gas dynamics is that natural gas flows from high pressure to low pressure. As a result, the capacity, operation, spacing and location of compressor stations and gas plants relative to production reservoirs is engineered to•flexibly optirni7e the transmission of the gathered gas considering: (a) the addition of new or re=stimulated wells; (b) declining production (and pressures) from existing reservoirs; and (c) the impacts of all oil and production activities on reservoir pressures. DCP Lucerne II CDPHE Comment Responses DCP Midstream, LP (DCP) is providing the following responses to the questions received from CDPHE on May 24, 2013 from Bailey Smith. The questions are provided below and the corresponding responses are bolded and italicized. Bailey Smith Questions - May 24, 2013 > The Division does not consider low NOx burners a control device. • DCP agrees with this comment > Can you explain the reasoning for wanting monthly limits for the heater to be at full utilization rather than the limited capacity requested for the unit? • The purpose of the annual limit is not to restrict the short-term firing capacity of the heater. DCP would like to maintain flexibility in using the heater at maximum firing capacity (50 MMBtu/hr) on a short-term basis i.e. monthly while limiting operation (to 315 MMscf/yr) over a longer term basis i.e. annual. Therefore, DCP requests the emissions and natural gas usage in Conditions 7 and 18 to be representative of the maximum firing capacity on a monthly basis and to only be limited on an annual basis. This is consistent with how the emissions are represented in the application. > The "normal operation" qualifier for the no VRU downtime condition will not be added. If there are true malfunctions they shall be treated as such. If there are foreseeable scenarios, such as maintenance activities, which DCP may consider as "non -normal" operations, VRU downtime should be incorporated into the permit. • DCP acknowledges this assessment In order to be conservative, DCP would like to take into account a 1% annual downtime on the VRU to allow for maintenance activities. DCP will submit revised APEN forms to reflect this change. The emission estimates have been revised accordingly to account for a 1% uncontrolled flash stream emissions from the amine and dehydrator flash tanks (Le. revision from 100% to 99% control in order to permit emissions from VRU downtime during maintenance activities). Please find attached the emissions in Attachment A. > The BACT requirements cannot reference an external 0&M plan and all maintenance and monitoring requirements associated with the BACT determination must be included in the permit document. • DCP acknowledges this assessment Accordingly, DCP requests that Permit Condition 21.t. be reworded to: Point 047: n a' l ' fi The regenerative thermal oxidizer shall be performed operated and maintained per the manufacturer's recommendations at a minimum of once per every twelve months or more often if recommended by the manufacturer. > The EPA Method 22 is required per our standard 0&M practices. • The regulatory requirement for a Method 22 test stems from NSPS Subpart 0000. Conditions 21(aa), 54 and 65 all require a Method 22 test DCP requests that each subsequent condition refer back to the first condition, Condition 21(aa,) for the Method 22 requirement Additionally, per NSPS Subpart 0000, the frequency is required to be monthly for a total of 5 minutes during any 2 consecutive hours. Please reword this condition accordingly. 9 The VOC significance threshold is 40 tpy rather than 100 tpy. • Per Reg 3, Part D, L B. 17, VOCs are only defined as criteria pollutants as a precursor to ozone. Additionally, per Reg 3, Part D, VI. B. 3. D, a significant emissions increase for ozone is considered 100 tpy in non -attainment areas of VOCs or NOx. In addition, Trinity had a conversation with Chip Hancock in Apri12012 to discuss significant emission rates for VOCs in Weld County. Chip agreed that the VOC SER for a NNSR project would be at 100 tpy, and not 40 tpy, and referenced the New Source Review Workshop Manual, page F-9 as an example.1 > The NOx limit requested to be listed in the PSD threshold's condition includes insignificant activity rather than the permittedlevel. • Per Reg 3, Part B, IL D, any permit exempt emission units need to be included in a permit application to determine applicability of Title V, PSD, or NNSR. Therefore, although the insignificant activity sources do not need a permit or an APEN, they are included in the emission inventory. Accordingly, DCP requests that these emissions be included in the table included in Condition 23. • The heater's "intelligent flame" description was identified as BACT in your application and has been determined as BACT for other GHG PSD permits. Please explain your reason for the proposed deletion. ® In the BACT assessment, efficient heater design options included intelligent flame ignition as one of many options for the hot oil heater: Since the final design on the heater has not been determined, DCP requests deletion of the intelligent flame ignition and flame intensity controls in Condition 21 > The extended waste gas analysis will not be relaxed to annually without further explanation. DCP doesn't expect the composition to be highly variable and requested the frequency to be relaxed since this is viewed as an administrative burden. However, DCP will comply with this condition and will perform extended waste gas analysis every three months as listed in Condition 61. Is it possible for this condition to be relaxed to having the analysis performed every three months for the first year of operation and then annually if the waste gas analysis shows that the composition is not highly variable? > Proper operation of the condenser is a parameter associated with proper operation of the amine unit (and hence temperature should be monitored for BACT). Also, the condenser was identified as control in the BACT analysis. The design of the amine unit system is slightly different than what was presented in the original BACT analysis, The condenser associated with the amine unit is only for water condensation, The condenser associated with the amine unit will not target GHGs since GHGs are gas at near -ambient temperatures, Therefore, DCP requests that the condenser not be viewed as a control device on the amine unit Accordingly, please remove Condition 21. r. New Source Review Workshop Manual, October 1990. http://www.epa.gov/NSR/ttnnsr0l/gen/wkshpman.pdf ATTACHMENT A Revised Emissions with 1% VRU Downtime Total Modification Emissions Enclosed Combustor Pilot . RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water • Pressurized Condensate Load I Insignificant Activities Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02)• Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Site -wide Fugitive Emissions I Lucerne 2 Expansion ` Total Existing Emissions Description k..7 Fi © Os O O c' i , A N CD W O O O O 1" W (.1 N N N N i 0J W W N •-.1 V xON Controlled Hourly Emissions (Ib/hr) 1 W o U'' O O O,oh .A N D W 0 0 0 0 ,? ;P. 1ob�N Noo N Y N CO F+ N N 52.76 n O NDO.OP '00.O N IV ‘.D H W COoo N C7 [s'] [zJ CT7 O o o O W W W .p Wao InNOO o O W O in W: V O Obo V .A 4N p N VOC N trt N N 4. W.CO IIIN Q` O o 0 W W 4. O co P !'a ,.0 I" N N N .A OD in Ln ' . f+7 , t+7 Ui O O O W W 4. O O O • . , , W .P. 4. V .P .A 1k Co N � rl e •N N CA N f-+ .P co N 0, , . [i7 , Mt.] O o 0 W43 .p O O P , , , , w .. :p . V .P 4, F'i m N r V UJ N i-_ W W O O O O O .A .A U7 - V O O O U7 .t..,.) CO N 2.87 y W P N , , O O P Y 0 0 0 0 V CO V W ..p O O i", Gill H o 7 K � n o c C77 3 7 N N 7 f0 N m D ro 0 •O ua m N 0 Total Modification Emissions Enclosed Combustor Pilot • RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load• I_ Insignificant Activities Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Site -wide Fugitive Emissions ILucerne 2 Expansion Total Existing Emissions Description 1 37.65 N a D O 1--. . rTi O V •0 w VI 0 0 0 0 (R u, Ln i O O in .0 . 00 N0 V 0 H W ON ON N O 1� W z O Controlled Annual Emissions (tpy) in N. criO1 I-. O c O 1 i--. . [z7 O N O to a O N O j V V O O CON VN O . . O., O. N V W H r,, N N H o n O CO pa H co H Y 0 0• 0 o in CO O. CI .A trl 171 a O O W O. W W N H+ N 0 0 0 H 1•+ `O [n N W H F-` A 123.58 C O. p. 1--I N in oU7 O N O O o ol rn Cl H 1-, F, • .O NO . 0 H 1• :- 'O Cr, "0N N 0 co I --I N O in D . . O i ' rnl C+1 F-, O O O. W I--` Y 1--I , . . . + s N NO ND O H N 7.96 `P .' i c .n W fa N O 0 in CI ' 1 F-, 0 0 o. w H H 1-' i i oIV -- ...1i o N W W W. N .0 Y N OVi Ico . 0. ti7 CA o 0 Co H 0 t0 'D 1 1 . O• . co m N V O N CA N O '0 00 0' v;A o 0 0 tNO 9+ 0 O0i w 0 0 0 CO ON H Post Modification Total Emissions Enclosed Combustor Pilot Compressor Maintenance Slowdown ' Emergency Flare Produced Water Pressurized Condensate Load Modification Emissions Combustion Turbine 1 (TURK -1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -O2) Amine Still Vent (ID AU -02) TEC Dehydrator Vent (ID D-01) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Site -wide Fugitive Emissions 1insitinificant Activities ITatal Exdsting0missions I 0.12 I 0.06 I 0.00 I 0.03 I 0.42 I 0.12 ' I 0.12 I 0.03 - 1.05 I 0.00 I 1.95 1 Lucerne 2 Expansion r e i b 6 a 9 3. 0 A N n n f - - Hourly Emissions (ib/hr) H in p W .•s {Wif O Y I. pl co 4. 1 N 7.7 i" i•' V V .P V ..0 p p W o W tom DJ '1 0 0 rococo 0 m 0 0 0 o La ww • ## f •••i E. C fCC 00 Io I.2 Nx'00 ib I I J S° I U p. N r 0 CO po°`a. e N N 1 I... CO al t�0 R7 .. W W 71 b 0 A bbl ICI co l l m I. rn o a. ......... N N ta La PI co I c o 10 t, ..opow ~ tta 0 X Kist.... p co M' 0 O to GM O # b i m N N ? IP °00 op t2t3 6N... SIN i oo # m la 0 IC N 0 ;a I I I I I 0 w a ! 1 1 1 i l h o 0 6Ell y W Di eR DI `< 0. m D. ° N p r w co N 1 1 i 1 1 o tv •N N 0 0` I I I I I 1 1 PI MI w' W ' 4 N P 2 I• 11 # # 4. ., 11 I W P Rf N -Hexane Methanol O W V o o .0 O i N I tilt 0 La 000 P.0 - m .Op N( La w: 10 I la o NI I t I„ t I N N. +� I 0 M to Ss O m W p 0 t... I I; I N I t/l la o H1 0 0 0 N 0 0 0 0 O o b I �7 to b b b V m V W .P 0 V V SdVH - A JVWwns AUIM-3.LIS 'Post Modification Total Ernissionsf Enclosed Combustor Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water ' Pressurized Condensate Load Modification Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent OD AU -02) TEC Dehydrator Vent (ID 0-01) RTO (ID RTO) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) • Site -wide Fugitive Emissions insignificant Activities Total Existing Emissions I 0.52 f 0.28 f 0.02 I 0.13 I 1.85 0.54 I 0.50' I 0.13 f 4.59 0 0 I 8.56 Lucerne 2 Expansion - y 0 C R 'o 0 0 e 0 o r.. 0 0 I kb:: W w u1 10 0 0 O .pa�p N Yin 0� 14 41. m O� W W I ,P 1132 , e SQ 0. W W Benzene I Toluene I ' • ..Annual Emissions (ivy) 1P.' O O N W V I I L t N O A • SL p TOP, N I'i�++ W O O m O 0 N N w°99 . ,D V W V1 o A .P' W . A 0 ivies �+N W 0 m II i I o V Ff. N 10 10 6 W o o N N t,n$m 11-10 I ma aw16 A' 13W DI 0 0 �+ © 0 2 N m to v " o P O O O 0 0 O m o o o I is f 'O o V N N 1n 0 10 W HCHO I Acetaldehyde I N V .• i N O N I. N - H 0 in 01 0 G I I,, N 0 0 I O o Y N 0,-1 K i-'6 W•k W 0 7.0 I I I I I I I o�'•1 m b b W W 0 N a N 0 O W W W -. 0 0 O rO 0 a V 4 • t in r 0 t I 0 0 0 ,p III : i 1 • 1 1 .1 1 1 1 1 t . f l l t t J I I•., ., A ,j X .12 - 1N,,, N• r:� , 0 0 • I - I 01 A • ' 0 0 o V 1p o 0 o N W WI t!1 W W W loan 01.00 00 SdVH - A IVWWf1S 3GIM- J.IS 0 0 9 0 9 CD • n, C 'to R.- 0 a' a O. 0 b CCy 0 O O m .0 N V Y 45. .p Y Gn b to m m 0 0 UI L O 0 0 0 0 m m to y .3 VI O O c -I O. m . y P," Af `' 'D2 M' aq 0 O n. r' E. m .T tD y n .21 .a N C < ^ • In n b CI .-ti 9 0 z o ti H ,.-g•O a'0 H a4 a x w 0 C S In PO m o O O O �y OtSC E M C < a 0 - C G F <, C D C 3 d o n CD uNW ti C N 0 ) Cal r. m c co • CO C n CD ro N t65 0 0 a UI OI V UI Lo FIDW . O 1D V CO N [n U1 V V W17-. W . m N V N. W o`'- Y Y �p A N N O V. N in U1 U7 P 0 •r P P o .. UI r Y Ln W W b o N O O P m o oI I o 0 Y UI W r U7 V ,V W UI r+ OD V V Ill N Al2 ' P b O co O Cr' N D W N V V I-. L.3 W I-. N I.-. O W O DI `'P O' W V V O P O C. W Ui ' W O o N Ch N O V V P rON 0 r 0101 V .O V 01 O o P O r 1 1 UI 0 WON a co Ul W Ul .P W tP N �+ �•'� r• LO ID W o NC O 0 0 ~mmrra t' an'i w • 1 oco 1O o O O O W a m co co VI .P N Y LA OY. ‘/., P N1,1 .A W N .i tt V O m. ' 02 CD [n O a1 V Y W W fA Y.' CO CO m LT Y N W W W [af W LD 01 0 1D 02 as I • O O CD 0 x 0 UI W V •n O O w ;.000 ag Fe r In D 0 • 0 na a na A?JVWWf1S ¶ND 301M-31IS w O 8 aDICa'4 414 p a a n 8 Si o g n [ a N N o oc O 0 z0-5 ro d a N°� m 8 3 — m 7. a o a p'.< 0 0. ct - • z a Z m m O x O a 8 o o o nn B .1 D: O n w ..•1 ^ 0 0 a. Ba 1V 0 ,-,.P m . m o 3. z 0 Hsu o • zo me Pm. 17 o .�~ y'.0, .p_. ° c m �' '(D n • 8 .- m m •O ar n y W CO 3 ,4' ma • umi ff 0 Q y 3 w 'O1 D �v.`-f a o .m .. 5 m w ro a ' at= pO O. o O PR- "2W N 0 b a O N m - O O w N . y 7 tl l. 8 m a� • N n y .O F w . ,a Fj a C O 0 x I z = n n =�' O • N a 0 • 04 0 "1 a • p R 0-I oo a % o . u • x C N• G m O• aTG D f N - Ci O+ W z o o 2 2 ,F~+ e m .� y S F�1 a N y 'O ry. 0 c Ij a • R 7 g w .N„ o h3 o N . . m 2o z N -D. y w -O 3 X 0 '-0' C 0 .1 z N y a m • n m O -Op 0 L'1 w I c y�i 3 • y • ` 7 S m n � w to C � O ry m Cc R . Is the project above NNSR SERB? z j Is the project above PSD SERB? PSD Significant Emission Rates (SER) s'4 Is the site above NNSR Ihults? Nonattainment New Source Review (NNSR) Limits Is the Project above PSD major source threshold? Prevention of Significant Deterioration (PSD) Major Source Threshold 1 mi y R1 73 in Z D O Z.s. O O tge y oZvi. o D o t o o k 1 o O O o 11 y o 1 Z p t� cn ' I Z O • N O I' O n I I O o I O a k l ZDI o r.00 ....I 1 1 0 0 o '. 10 0 O 1 1 c 0 C ITotal Modification Emissions Enclosed Combustor Pilot RTO Pilot Emergency Flare I Insignificant Activities (Non- fugitive) Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) T£G Dehydrator Vent (ID D-01) RTO (ID RTO) . • Storage Tanks (ID TANKS) Truck Loading (ID LOAD) I. Lucerne 2 Expansion I Total Existing Emissions 1 i q b a. 0 O N N NO„ V NV O co O i-+too 'O W O Q O O V1 �' m 0oUiiD I mbO o V o H I 1V N F•' w .VI • N •N N 0 0 i-, o O O N 0' yl V V O O +I V W 01 t, W " I••' f'! D K Q. O N fll. m M N V W N o m h' F.. ZO F+ W I -a m000 o 01 trn ry -' m m 0 0 N. F+ ha N O O O Y'0 I • 4(n N V °•' H m m 0 • o G' n W T W •,-.1-,N3 L11 W .P N O 6Oklinb o N O' W • N N N I I I I Or�-1N • V m 'fl "�'' y F us ..., m q a En.' 0tnnaallCV W !-LL-." 2 G O .O. 0 1 I 1 I I [4.O'.~D o F+ I �VD•3.p Ch ro "' N Ol W _ ti lV in O 'O 0 Ma ra 1 I I 1 N .o ;21.o 3 W O • N Oh W a h+ F+ D, ' C•' -,01-3P4 W V NLI W O00 N y W00.0 0. OD O - t In N W VWLpF' N W w N N W W W o I �m t cmilNr I 82876.52 n D co m F•' N In 1D m m .�i bo t'b ,4)Ol m,0,0 R SITE -WIDE SUMMARY FOR PSD APPLICABILITY O 0 w n• ' W. P. R. N 0 y 10 y N N ▪ R. o a 0 • N '. 3 3 Le - 0 m o. `. .... 0 m • N 7 -I X N o o F a N o •z o m 3 C C C R w N II _ P C P 0 CO 01 N O O • � O • f 'O -01 a C' Y O rn II ro o 0 •0 H • .D CD• D N ON r - C x'C Dn ='D nx X rn.3aa0 7 r o "'•ro D W N x a m w y a s y co N 0 co O N C O m CD a N o. o 4 0. 0. ' C C w V I- U1 N H. W N N CO N N Cr, .P V N N (+1 V W N .P .P V V H w 01 Y 01 O 01 'I' V • . In V C-+ 01 W 0] .P O In .p 0 0 '�D .A 230 0' CJ O m 01 .p 'Egg 01 W W ',0`. m m t?7 Cid I=1 to In I?7 cz F tf 1 m m °,2_ ts1 O N Y O O O O O O O O O C2 O N .p w O` 01 .p .p.' w N .p .p .4s w w N w0 r' G 0 tt O g a? E ' 0 ' SS • M W W W W W 1D. 10 0 10 W 0 0 W W •W 01 01 01 01 01 01 01 01 01 01. 01 01 01 Cr. 0. DRE2 N d1 V O • .P W I- V L17 W W W w 0 0 01 O O O W Y 1D W �j m C+'7 In N O h'4. N b O 1D Q1 r r 0 0 w U1 W I`j V Y 01 W O N r P W w Cr k. r. � Inlet to RTO 3'4'5 .W OYi .o .01 W W O Y Y in 4' Y P w 'P O N Y w en. Y r 'P V co W Y O (.J Y o 'P _'=' m Y Iv' .• 'A F+ op' W N 1." N V 01 P W m W o 10 w �} 'D 'ZS P Y Y N ' . Y Y ..P. N 01 N :P' O N Yi‘a W P P O O V O w 0 it 0 01 Lt Lt m m N Y CO .O N lI y O Y Y 0 0 • O O .'C ' N r U1.4, . U.1 .. N N Q' •T I Controlled RTO Emissions 4' 5 U.1 . Fr, :.o 01 V P • V U7 N Y P N Iw-1 Q1 t2O 0 Y N 0 0 0 O P i--1 OS C� trl tq to O O N En O O 'o .o.‘ N .. V W r r 0 • W .P. N Co co V al V CO .P N I-, .4s .w ' °0 L'5,, O CD • x p4p?? F rwr L° O W Er D •CD N 11 R. o • C II D. 0 m uopsngmoj se0 ppv aunud- sums (Z0 -flit GO mad ZIPS aMutt( EMISSION CALCULATIONS FOR AMINE UNIT x a 0 Y 1 O a m 0 0 Fr n Di 0 a17) 0 w En - 0 a oo O P O O 7 Example Controlled Propane Hourly Emiss II D C n m L o o rt C 6 Dr G a ai ro o ft o L Dr O 3 1c O o n 0 Methane VOC6 HAP' x b o ,� `G T g ra b b Co m p m `G a 0 C ^a v y w o m k a p u d w a m o 2 m m m a m m 0 m 0 CoC = a Co ca.. p '3C C a to O 0 m m 0 0 0 0 0 0 0 0 0 m 0 0 m m 0 m 0 0 0 0 0 0 0 0 0 0 0 0 0 0'0.0 O O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Control Efficiency' (%) a. -4 N 127.22 3.72 I-+ W , O P e 0 0 0 0 0 S S 4. W N 0 V •O m m m '+ O bin N 0 W In N 'p W VI W N S sta.S S P, 4, co— a- \ '1 T 0 C W 0I-, W .V 557.23 I 16.29 V W O I' pp O O 0 N (n W W 4,rt m F+ O c F+ O N? W -com VI N F+ co. W N VI 0 W..p. 0 m #.N pJ W V O v C\ p1 W r V 0 Y O N 4P V • N F+ W F+ F+ W N V1 Y W 0 in O• Ol N in W F+ O O 0 O in O b O V N N N N ? N co F+ co .P m"m m m m m m m O m 0 m N m m\ 0 0 0 0 0 0 0 0 0 O O O A co A? W. 4,W IJ N N S V VRU Downtime Emissions 4.7 N 0 V V W 0V0 0 Lrt ‘0‘ Ul S V S OD O` F+ 0 1-.' in O O O O OF+ O W m m m m m m m O inc O F+ F+ F+ .P C O 0 0 0 0 0 N OJ 0 01 W N O W 01 W .P W W a " y suoisslut3 ysElg Amine Still Vent (ID AU -02) EMISSION CALCULATIONS FOR AMINE UNIT C! n a o CD R a a r C 3 fD 0 O 0 CPCP •o 0 .y CD a' a C ' a D. CD 0 •S 0 My 6 3 0 0 1.1 .r1. O 1. a ti3 c n I:1 x N 2 44gl a k m p ON O M .S Oi m a N OIa' K O• H ✓ 0 0 o c f '▪ 4 a - w q 8 • a O acr5 140 T1 O m • sa 0 o R a.a D p x m a 0 2 cP C OM CD ▪ O. O • ; e g Do a Nis 5.5 a O m N N (] O • o w . M3 ❑. GC m o E e 8 6 d N CD n 3 C▪ 0 w • n p• a II! • [8A O • 0 0 o. d m a D 0 O N VOC HAP m`G m o r 344 X 12 D 0: 7 m? .a "-D .5:1G 7 G R N R. SD,O UI Uf ND U5 va .4,,D,OU5 VD VDOD,550,5NO�,ti UI N In UI UI UI 01 us 01 VI us Ul Ul U1 v 74 P•'f UW.1 a V 4p w r N r6 C al N Fl Fl :P 6.•g C C N 4J C, I-` P0 O sO CA .4. ID ,0 01 ii,v CO Ch vl , N V ON CO o , CO N ,p 0 4. • Q v Inlet to Combustor ]14 380.65 147.72 ' UI tm o O+ UNl�O in r I sU1 N 0 o N C^ 'D m ..I{i, O b +1 N in 0 in iJ tp w 4'Li' ,A N'' .4) Os V 05D0'- ,? -. O. w' UO N 4'-.- 6 0 0 0 0 0 0 0 0 0 0 0 0 W 0 b O O (A V I••04.1 N LI 0 1 0 UI m? 01 V W N ID o o 0 N Ut OD IV O Os' EP ` n Controlled Combustor Emissions 9'4 21.30 7.39 • 0 0 o N W C) I-•' I-. Cl w r .P. N. is1 0 r W W �N .P .P I ;D b h1 to CO o .p N N N o ..00 OI V ID 0 Ch . Ul .- 'O L CD • •0 H EL O o o ▪ a o o o. m g � 't a ° ^ 51. .L7 H C • 0 0 o as `C U {:. rn 0 O EMISSION CALCULATIONS FOR GLYCOL DEHYDRATOR Example Controlled Ethane Annual Emission Rate (tpy) fr O C- 8 0 O 7 0 S <x C -F a 10 ,< 5 Er o 0 E c 0 � 7 ▪ 2- ▪ g v s w o C • g o T C m j F W O • Pa O • k 3 0 w _ 7 9 Q O � S Cn d -e J ry n w T A O 67 C a C • y o- oe w 7 w r .p ▪ k W E• m n n g O O a a O A 3 a ED CD `SG Q . C N . O Example Controlled Ethane Hourly Emission Rate (11)/hr) _ w d P n. O q Methane VOC HAP nm x m ^3 m Y> > a 0 y t m 2 +.G N 9 0 ro L'O m a.0 izo7 0. ET- a g W ri 7 rt .r ,, m PO w N �° " m 7 G m m m zLn a 0 n 'O K' G m O e 0m 0 d e e m m 0 0 0 O N b O O AO O d 0 0 O 0 0 0 0 d 0 0 O O d e e e e e e e CO' e e e e e e• Control Efficiency° (%) V W Y co WO V I' O O N O O O W. •.P P• T co O, N F+ m COO a O T AN N m N m m V O W a r, S v Inlet to VRU t'4 N P q 324.95 16.98 a • N N V W N N V W O O O O F+ N .P N O W 07,1'; -0 m O b m N 0 NJ CD O m .p ut N V P V.0 O A • o ;.O o O 4P v 0.74 0.04 N 1+ V F` W P F+ ~ w O O aO O O O O O O O m,, m m m w W m m V V P d m 10 ' o o o W" m� .p vi w P _ VRU Downtime Emissions t'° WN 0, P O W V L° 10 .P W V aP m, w p 0 0 0 0 0 0 0 F+ 1+ m O O m m O"? I, O N o in o mV wa aww m V O S EMISSION CALCULATIONS FOR GLYCOL DEHYDRATOR STATE OF COLORADO COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION TELEPHONE: (303) 692-3150 CONSTRUCTION PERMIT PERMIT NO: 12WE2024 Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Natural gas processing facility, known as the Lucerne 2 Expansion Project at the Lucerne Gas Processing Plant, located in 31495 WCR 432, Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility Equipment ID AIRS Point Description TURB-1 044 One (1) natural gas fired combustion turbine (Solar Model Taurus 70 serial number: TBD), equipped with low NOx burners, site rated at 9 0558 534 horsepower at 11,51375 RPM. The turbine is design rated for a heat input of 66.12486 MMBtu/hr. This combustion turbine is used to power a compressor. IEmi^cions from this turbinq arc not TURB-2 045 One (1) natural gas fired combustion turbine (Solar Model Taurus 70, serial number: TBD), equipped with low NOx burners, site rated at 9 0558 534 horsepower at 11,51375 RPM. The turbine is design rated for a heat input of 66.124-56 MMBtu/hr. This combustion turbine is used to a compressor. Emi'cions from this turbine power arc not controlled. HT -02 046 Hot oil heater (make, model, serial number: TBD) determined. The heater is design rated at a heat input of 50 MMBtu/hr. This heater is fueled by natural gas and used to supplement the waste heat recovery system provided from Points 044 and 045. Emissions from this heater are not controlled. AIRS ID: 123/0107 Page 1 of 37 NGEuugine-Version 2000-1 Comment [DM51]: These turbines are not controlled with add-on devices, however, they are equipped with. low NOx burners .y 2 k�� (blora`Jc .Dep Sent Public Health and Environment Air Pollution Control Division Facility Equipment ID AIRS Point Description AU 02 047 One (1) methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf per day (make, model, serial number: TBD). This emissions unit is equipped with two (2) or three )_electric amine recirculation pumps with a total design capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, a flash tank, still vent and a natural gas fired amine regeneration reboiler. The amine flash stream is routed to a closed loop vapor recovery unit equipped with a redundantbackup unit (0% annual downtime). The acid gas stream is routed to a regenerative thermal oxidizer (Anguil, Model 100, SN: not submitted) rated at 10,000 scfm. Destruction rate efficiency is a minimum of 96%. D-01 — 048 One (1) triethylene glycol (TEG) dehydrator unit with a design capacity of 230 MMscf/day (make, model, serial number: TBD). This emissions unit is equipped with two (2) electric glycol pumps with a limited capacity of 40 gallons per minute. This system includes a condenser, reboiler, still vent, and a flash tank. The flash gas is routed to a closed loop vapor recovery unit equipped with a backup unit (0% annual downtime). The still vent is routed to a condenser and an enclosed combustor with a minimum destruction efficiency of 95%. TANKS 050 Eight (8) stabilized atmospheric condensate storage tanks. Each tank has a capacity of 400 bbl. Emissions are routed to an enclosed combustor with a minimum destruction efficiency of 95%. LOAD 051 Condensate truck loading. Emissions from the loadout will be controlled by an enclosed combustor. FUG 052 Fugitive emission leaks from a natural gas processing plant associated with the expansion project. Points 044 and 045 may be replaced with another turbine in accordance with the temporary turbine replacement provision or with another Solar Model Taurus 70 turbine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S. (25-7-101 et seg), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION 1. YOU MUST notify the APCD no later than fifteen days after commencement of the permitted operation or activity by submitting a Notice of Startup (NOS) form to the APCD. The Notice of Startup (NOS) form may be downloaded online at www.cdphe.state.co.us/ap/downloadforms.html. Failure to notify the APCD of startup of AIRS ID: 123/0107 Page 2 of 37 •N, en t Public Health and Environment Air Pollution Control Division the permitted source is a violation of AQCC Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Reference: Regulation No. 3, Part B, FlI.G.2). 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part 8, III.F.4.) 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self -certification process. (Reference: Regulation No. 3, Part B, Section III.E.) 5. The manufacturer, model number and serial number of the subject equipment shall be provided to the Division within fifteen days (15) after commencement of operation. This information shall be included on the Notice of Startup (NOS) submitted for the equipment. (Reference: Regulation No. 3, Part B, III.E.) 6. The operator shall retain the permit final authorization letter issued by the Division after completion of self -certification, with the most current construction permit. This construction permit alone does not provide final authority for the operation of this source. EMISSION LIMITATIONS AND RECORDS 7. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4) Monthly' Limits: Facility Equipment ID AIRS Point Pounds per Month Tons per Month Emission Type NOx SO2 VOC CO CO2e2 TURB-1 044 2,5524- 167— 104— 2,991 2,872 Point TURB-2 045 2,5524 167— 104— 2,991 2,872 Point HT -02 046 1,3458 — — 3,0582 21764T69 Point 21790 4 , AU -02 047 85— 5, 872 1,1354 4624 13,109 Point D-01 048 155- -- 3' 6182131— 444 Point AIRS ID: 123/0107 Page 3 of 37 D� lorar �: t ep Public Health and Environment r Air Pollution Control Division TANKS 050 12— -- 322 11— 20 Point LOAD 051 15— -- 3924 14— Point FUG 052 — -- 2 2323 -- 131-8 Fugitive 476 1: Monthly limits are based on a 31 -day month. 2: CO2e is carbon dioxide equivalent in tons per year. CO2e is the total sum of the mass of each greenhouse gas emission multiplied by global warming potential for each greenhouse gas. The greenhouse gas emissions of concern include CO2, CH4 and N2O. Facility -wide emissions of each individual hazardous air pollutant shall be less than 1,359 lb/month. Facility -wide emissions of total hazardous air pollutants shall be less than 3,398 lb/month. Annual Limits: Facility Equipment ID AIRS Point Tons per Year Emission Type N0x SO2 V0C CO CO2e TURB-1 044 15.0 1_0— 0_6— 17.6 33,814 Point TURB-2 045 15.0 1.0— 0.6— 17.6 33,814 Point M -IT -02 046 5.8 0.1— 0.9— 13.2 18,853 Point) AU -02 047 0.5— 31.3 6.7 2.7 154,349 Point D-1 048 0_9— — 21.3 0.8— 5,228 Point TANKS 050 0_1- -- 1.9 0.1- 2410 Point LOAD 051 0.1- - 2.3 0.1— Point FUG 052 — -- 18.7 -- 216 Fugitive See "Notes to Permit Holder #4 for information on emission factors and methods used to calculate limits. Facility -wide emissions of each individual hazardous air pollutant shall be less than 8.0 tpy. Facility -wide emissions of total hazardous air pollutants shall be less than 20.0 tpy. During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the emission limits in this permit shall be determined by recording the facility's annual criteria pollutant emissions, (including all HAPs above the de-minimis AIRS ID: 123/0107 Page 4 of 37 Comment [DM52]: Monthly limit on HT -02 should be full utilization not annual divided by 365 days times 31. olora$ittDep: Public Health and Environment Air Pollution Control Division reporting level) from each emission unit, on a rolling (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly emissions and keep a compliance record on site or at a local field office with site responsibility, for Division review. This rolling twelve-month total shall apply to all emission units, requiring an APEN, at this facility. 8. Points 044, 045, and 046: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from combustion using equation C -2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in Table C-1, measured actual heat input (HHV), and measured actualmonthly natural gas flow volume. The owner or operator shall calculate CH4 and N2O emissions from combustion on a monthly basis using equation C -9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and measured actual monthly natural gas flow volume. The owner or operator shall calculate the CO2e emissions based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1. 9. Point 047: The owner or operator shall calculate, on a monthly basis, the amount of CO2 emitted from combustion in the regenerative thermal oxidizer using equation C -2a in 40 CFR Part 98 Subpart C, default natural gas CO2 emission factor in Table C-1, measured actual heat input (HHV), and monthly fuel usage. A complete record of the methods used, the m acurements made, and the calculations performed to quantify fuc usage .,hall be kept. The owner or operator shall calculate CH4 and N2O emissions from combustion on a monthly basis using equation C -9a of 40 CFR Part 98 Subpart C, default CH4 and N2O emission factors for natural gas contained in Table C-2, measured actual heat input (HHV) and monthly fuel usage. P complete record of the /methods used, the measurementsmade, and":the calculations performed to quantify fuel usage shall be kept;[ The owner or operator shall calculate the CO2e emissions based on the { comment[ores3]: ouphcateaegmremeni procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 10. Point 047: The owner or operator shall calculate CO2 emissions from the amine unit, on a monthly basis, using equation W -4A consistent with 40 CFR Part 98, Subpart W [98.233(d)(3)] along with the most recent measured amine waste gas sampling composition. 11. Point 047: Total CO2e emissions from the RTO ach point shall be based on the sum of GHG emissions from waste gas combustion, calculated as per Condition 9 plus CO2 emissions from the amine unit acid gas sweetening as calculated per Condition 10. —The sum of GHG emissions generated from waste gas combustion and CO2 emissions generated from the amine unit acid gas sweetening shall be compared to the CO2e limits listed in this section above to demonstrate compliance. 12. Point 048: The owner or operator shall calculate CO2 and CH4 emissions, on a monthly basis, using GRI-GLYCaIc consistent with 40 CFR Part 98, Subpart W [98.233(e)(1)] along with the most recent results from the extended wet gas analysis as required by this permit. 40 CFR Part 98, Subpart W [98.233(0)(1)] 13. Points 048, 050 and 051: The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly AIRS ID: 123/0107 Page 5 of 37 DepOment p/Public Health and Environment Air Pollution Control Division basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Flare, for the purposes of subpart W, means a combustion devicewhether at ground level or elevated, that uses an open or closed flame to combust waste gases without energyrecoverl 14. Points 047: Compliance with the emission limits in this permit shall be demonstrated by running the ProMax software on a monthly basis using the most recent amine unit inlet extended gas analysis. 15. Point 048: Compliance with the emission limits in this permit shall be demonstrated by running the GRI GlyCalc model version 4.0 or higher on a monthly basis using the most recent wet gas analysis and recorded operational values (including gas throughput, lean glycol recirculation rate, and other operational values specified in the O&M Plan). Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into GRI GlyCalc and be provided to the Division upon request. 16. Points 050 and 051: Emissions from the condensate tanks shall be collected and controlled by an enclosed combustor in order to reduce the emissions of volatile organic compounds to the level listed in this section, above. Operating parameters of the enclosed combustor are identified in the BACT requirements in Condition 21. 17. Point 052: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. PROCESS LIMITATIONS AND RECORDS 18. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limits (31 days) TURB-1 044 Natural Gas Combusted 566 MMscf/yr 48.10 MMscf/month TURB-2 045 Natural Gas Combusted 566 MMscf/yr 48.10 MMscf/month HT -02 046 Natural Gas Combusted 315 MMscf/yr 36.362848 MMscf/month AU -02 047 Natural Gas Throughput 83,950 MMscf/yr 7,130 MMscf/month AIRS ID: 123/0107 Page 6 of 37 l Comment [DMS41: Unclear whylthis is here? Comment [DHSS]: This needs to be full utilization 50 mmbtu/hr *8760 hr/year" sof/1023 BTU `31days/month/365 days/yr = 3636 mmsof/month , for Lvp p ent cc Public Health and Environment Air Pollution Control Division D-1 048 Natural Gas Throughput 83,950 MMscf/yr y 7,130 MMscf/month TANKS 050 Condensate Throughput 456,250 bbl/yr 38,750 bbl/month LOAD 051 Condensate Throughput 456,250 bbl/yr 38,750 bbl/month During the first twelve (12) months of operation, compliance with both the monthly and yearly emission limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly limitation shall be required. Compliance with the yearly consumption limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate monthly consumption of natural gas and keep a compliance record on site or at a local field office with site responsibility, for Division review. 19. Point 047: This unit shall be limited to a maximum lean amine recirculation pump rate of 945 gallons per minute. The lean amine recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4). 20. Point 048: This unit shall be limited to a maximum lean glycol recirculation pump rate of 40 gallons per minute. The lean glycol recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation No. 3, Part B, II.A.4) BEST AVAILABLE CONTROL TECHNOLOGY (BACT) REQUIREMENTS 21. The equipment and activities at this facility are subject to the requirements of the Prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Greenhouse Gases (GHG). BACT has been determined to be as follows: a. For purposes of BACT, total CO2e emissions from the emission units covered under this permit shall not exceed the annual emission limits contained in condition 7, based on a rolling twelve month total. Turbines b. Points 044 and 045: The turbines shall be equipped with waste heat recovery units to increase the efficient use of waste heat for process heating. c. Points 044 and 045: Fuel for the turbines shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the turbines shall be sampled initially and at least once per every six months as required in Conditions 47-46 and 5960 to determine ... { Formatted: Font: (Default) vial, 11 pt the fuel gross calorific value (GCV) [high heat value (HHV)]. d. Points 044 and 045: The owner or operator shall install and maintain an operational non-resettable elapsed flow meter for the turbines. The flow meters shall be calibrated at a minimum frequency of at least once per -every twelve months. The flow rate of the fuel combusted in this natural gas -fired combustion AIRS ID: 123/0107 Page 7 of 37 blora JP%:Dep ent c,`'; Public Health and Environment Air Pollution Control Division emission unit shall be measured and recorded using an operational non- resettable elapsed flow meter at the inlet. e. Points 044 and 045: The combustion turbines shall be equipped with a control package that monitors the air/fuel ratio in the combustion primary zone. Heater g Points 044 and 045: The owner or operator shall install temperature monitoring equipment to measure temperature in the exhaust gas and turbineengine. Point 046: On or after the date of initial startup, the owner or operator shall not discharge or cause the discharge of emissions in excess of 449.16 lb CO2/MMscf natural gas inlet output from plant on a 365 -day rolling average. To determine this BACT emission limit, the owner or operator shall calculate the limit based on the measured input mass rate of CO2 from the natural gas HHV analysis required in Conditions a and 5968 (note that mass emission rate must be converted from metric tons to pounds) and divide by the measured daily natural gas output from the expansion plant (MMscfd). h. Point 046: Fuel for the heater shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The fuel used in the heater shall be sampled initially and at least once per every six months as required in Conditions 4647 and 5960 to determine the fuel gross _- Formatted: Font: (Default) Arial, a pt calorific value (GCV) [high heat value (HHV)]. Point 046: The owner or operator shall install and maintain an operational non- resettable elapsed flow meter for the heater. The flow meter shall be calibrated at a minimum frequency of at least once per every twelve months. The flow rate of the fuel combusted in this natural gas -fired combustion emission unit shall be measured and recorded using an operational non-resettable elapsed flow meter at the inlet. { Formatted: Font: (Default) Arial, 11 pt j. Point 046: The heater shall be equipped with low-NOx ctaged/qucnching (flue gas recirculating) burners with burner management systems that include intelligent flame ignition and flame intensity control^. k. Point 046: The heater shall be tuned for thermal efficiency at a minimum frequency of et least once per every twelve months. Point 046: The owner or operator shall perform cleaning of the burner tips, at a minimum of, once per every twelve months. Point 046: The owner or operator shall install, operate, and maintain an automated air/fuel control system which is part of the burner management system. The owner or operator shall calibrate and perform preventative maintenance on the air/fuel control analyzer at least once per every three months, at a minimum. Amine Unit AIRS ID: 123/0107 Page 8 of 37 Deptitrr,ieeit 04 Public Health and Environment ti L__llr: J !,.Air Pollution Control Division n. Point 047: The amine flash stream shall be routed to a closed loop vapor recovery unit during normal operationsat all times, with no downtime, resulting in 100% control. o. Point 047: The still vent from the amine unit shall be collected and and controlled by a condenser then, 'routed to a regenerative thermal oxidizer for combustion. The regenerative thermal oxidizer shall have a minimum removal and destruction efficiency of methane (CI -14) -of 96%. p. Point 047: The operating temperature of the regenerative thermal oxidizer used to control emissions from the amine unit shall be greater than 1550 'F at all times that amine unit emissions are routed to the regenerative thermal oxidizer. The regenerative thermal oxidizers' exhaust temperature shall be continuously monitored and recorded when amine unit waste gas is directed to the oxidizers. The temperature measurement devices shall reduce the temperature readings to an averaging period of 6 minutes or less and record it at that frequency. The owner or operator shall install and maintain a temperature recording device with an accuracy of the greater of ±0.75 percent of the temperature being measured expressed in degrees Celsius or ±2.5°C q. Point 047: Waste gas from the ach amine unit will be sampled and analyzed initially and at least once every three months for composition as specified in Conditions 5064 and 6064. The sample data will be used to calculate GHG - Formatted: Font: (Default) Arlal, 11 pt ) emissions as specified in Condition 94A. Formatted: Font: (Default) Arial, 11 pt Comment [DMS6]: The condenser is not a control device, it is integral to the process. There Is no to effectively regenerate amine without it. There should not be control requirements for it. r. Point 048: The average''diatly condenser outlet tQixiperattarc shall be maintalr thermpcotple. - Comment [DMS7] The condenser is not e control device s r. Point 047: Record the gas flow rate of the inlet natural gas stream of the amine unit using a flow meter. The owner or operator shall operate and calibrate the flow meter in accordance with §98.3(i). t s. Point 047: The regenerative thermal oxidizer shall be operated and maintained per the O&M plan. Periodic maintenance will help maintain the efficiency of the thermal oxidizer and shall be performed at a minimum of once per every twelve months or more often as recommended by the manufacturer specifications. +-t -__Point 047: An oxygen analyzer shall continuously monitor and record oxygen concentration when waste gas is directed to the regenerative thermal oxidizer. It shall reduce the oxygen readings to an averaging period of 6 minutes or less and record it at that frequency. Point 047: The oxygen analyzer shall be quality -assured at least once every six months using cylinder gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 5.1.2, with the following exception: a relative accuracy test audit is not required once every four quarters (i.e., two successive semiannual CGAs may be conducted). The CGAs must be performed at least thirty (30) days apart. Dehydrator w:v. Point 048: The dehydrator flash stream shall be routed to a closed loop vapor recovery unit during normal operationsat all times, with no downtime, resulting in 100% control. AIRS ID: 123/0107 Page 9 of 37 rent c{ Public Health and Environment pi Air Pollution Control Division ran Point 048: The still vent from the dehydration unit shall be collected and controlled by a condenser then routed to an enclosed combustor. The enclosed combustor shall have a minimum removal and destruction efficiency of methane (CH4) of 95%. y-x,Point 048: The average daily condenser outlet temperature shall be maintained at a maximum minimum of 16045°F. Condenser outlet temperature be monitored using a thermocouple. -y. Point 048: The enclosed combustor shall be operated with a pilot flame present at all times. The presence of a flame in the enclosed combustor shall be continuously monitored with thermocouple. aa-z. Point 048: The enclosed combustor shall be operated with zero visible emissions. A daily visual observation n EPA Method 22 shall be conducted deify to monitor compliance with this condition. If the visual observation detects something other than zero visible emissions, an EPA Method 22 will be conducted. 22. The owner or operator shall maintain the following records for a period of 5 years: a. Operating hours for all emission sources. b. The volume natural gas fuel usage for all combustion sources. This shall include data obtained from continuous fuel flow monitors as well as a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage from unit not equipped with continuous fuel flow monitors. c. Annual fuel gas sampling results, quarterly waste gas sampling. d. Daily natural gas processing output rate for the plant. e. Records, data, measurements, reports, and documents related to the operation of the facility, including, but not limited to, the following: all records or reports pertaining to significant maintenance performed on any system or device at the facility; the occurrence and duration of any startup, shutdown, or malfunction, annual tuning of heaters; all records relating to performance tests and monitoring of combustion equipment; calibrations, checks, duration of any periods during which a monitoring device is inoperative, and corresponding emission measurements; and all other information required by this permit recorded in a permanent form suitable for inspection. f. All records required by this Permit shall be retained for not less than 5 years following the date of such measurements, maintenance, and reports. STATE AND FEDERAL REGULATORY REQUIREMENTS 23. The requirements of Colorado Regulation No. 3, Part D shall apply at such time that any modification becomes a major modification solely by virtue of a relaxation in any enforceable limitation that was established after August 7, 1980, on the capacity of the source or modification to otherwise emit a pollutant such as a restriction on hours of operation (Colorado Regulation No. 3, Part D, Section V.A.7.6). With respect to this Condition, Part D requirements may apply to future modifications if emission limits for the following emission units are modified to equal or exceed the following threshold levels: AIRS ID: 123/0107 Page 10 of 37 in 'Public Health and Environment Air Pollution Control Division Facility Equipment ID AIRS Point Equipment Description Pollutant Emissions - tons per year Threshold Current Limit TURB-1 044 Combustion TURB-2 045 Turbine HT -02 046 Hot Oil Heater NOx 40 37.75 AU -02 047 Amine Unit VOC 10040 49.34 10 H2S 0.0 D-01 048 TEG Dehy PM2.s 10 5.0 TANKS 050 Condensate tanks LOAD 051 Condensate loadout 24. The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable). 25. Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. (Reference: Regulation No. 1, Section II.A.1. & 4.) 26. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 27. Points 044, 045,: and 046: These units are subject to the Particulate Matterrand Sulfur Dioxide Emission Regulations of. Regulation1 including, but not limited to) `,theyfollowing: rze-•r-. �_•_. a. No owner or operator shall cause or permit to be emittedpinta,,the. atmosphere from any fuel -burning equipment, particulate matter in the.'fluegases iwhich exceeds the following (Regulation 1, Section IIl.A.1):: (i) For fuel burning equipment with designed heat inputs greater than 1x106 BTU, per hour, but less than or equal to 500x106 BTU per, hour, the following ;equation,wiil be used to determine the allowable' articulate emission limitation:; PE=0.5(FI)'o.26 Where: • PE = Particulate., Emission in Pounds per million BTU heat°.input,! Fl =,Fuel' Input in Million_ BTU per hour. b. Emissions of sulfur dioxide shall not emit sulfur dioxide inexcessfofthe following combustion turbine limitations. (Heat inPut rates shall ; be the.` manufacturer's guaranteed maximum,heatinput rates), (Regulation 1 `Section Vl B) (i) Points 044,and045: Combustion Turbines withwa heat input of lessthan 250 Million'BTU per hour: AIRS ID: 123/0107 Page 11 of 37 lg 0.8 pounds of sulfur dioxide per million BTU of heat input (Regulation 1, Section Vl..R.4c): (ii) Point 046: Limit emissions to not more than two (2) tons per day of sulfur dioxide (Regulation 1, Section VI.B.5.a) Dept¢•Itr ent 4APublic Health and Environment Air Pollution Control Division r .. 28. Points 044, 045, and 046: These units are subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation6,`_Part B, Section II): a. Standard for Particulate Matter —.On rand after the date ..on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but les than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)'° 26 rr Where: PE is the.allowable.:particulate emission in pounds per million Btu_ heat input. Fl is the fuel inputin million Btu per hour: (ii) Greater than 20 percent opacity:. b. Points 044 and 045 only: Standard for Sulfur Dioxide — On and after the date on which the required performance test is :completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere sulfur dioxide in excess of, (i) Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. S02/million Btu: . 29. Points 044 and 045: The combustion turbines are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart KKKK, Standards of Performance for Stationary Combustion Turbines including, but not limited to, the following: • §60.4320 — Nitrogen Oxide Emissions Limits o (a) NOx emissions shall not exceed 15 ppm at 15% O2 or 1.2 lb/MW-hr; • §60.4330 - Sulfur Dioxide Emissions Limits o (a)(1) SO2 emissions shall not exceed 0.9 lb/MW-hr gross output; or o (a)(2) Operator shall not bum any fuel that contains total potential sulfur emissions in excess of 0.060 lb SO2/MMBtu heat input. • §60.4333 — General Requirements o (a) Operator must operate and maintain your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner AIRS ID: 123/0107 Page 12 of 37 Comment [DMSSj: Can Condition 27 and 28 be combined as they are essentially the same requirements? Public Health and Environment Air Pollution Control Division consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown and malfunction. §60.4340 - NOx Monitoring o (a) Operator shall perform annual performance test's in accordance with §60.4400 to demonstrate continuous compliance with NOx emissions limits. §60.4365 (or §§60.4360 and 60.4370) - SO2 Monitoring o The operator shall comply with §60.4365 or with both §§60.4360 and 60.4370 to demonstrate compliance with SO2 emissions limits. §60.4375 - Reporting o (b) For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test. §§60.4400 and 60.4415 — Performance Tests o Annual tests must be conducted in accordance with §60.4400(a) and (b). o Unless operator chooses to comply with §60.4365 for exemption of monitoring the total sulfur content of the fuel, then initial and subsequent performance tests for sulfur shall be conducted according to §60.4415. 30. Point 046: This source is subject to the New Source Performance Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units including, but not limited to, the following: • §60.48c — Reporting and Recordkeeping Requirements o (g) The owner or operator of the facility shall record and maintain records of the amountof fuel combusted during each month. o (I) Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record 31. Point 047: The amine units are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: §60.5365 — Applicability and Designation of Affected Facilities o (g)(3) Facilities that have 'a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in §60.5423(c) but are not required to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g). §60.647 — Record keeping and reporting Requirements o (c) To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less that 2 LT/D of H2 S in AIRS ID: 123/0107 Page 13 of 37 ent cLi Public Health and Environment 1 Air Pollution Control Division the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2S expressed as sulfur. 32. Point 048: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XII 33. Point 048: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). Beginning May 1, 2008, uncontrolled actual emissions of volatile organic compounds from the still vent and vent from any gas -condensate -glycol (GCG) separator (flash separator or flash tank), if present, shall be reduced by an average of at least 90 percent through the use of air pollution control equipment. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 34. Point 048: This source is subject to the TEG dehydrator area source requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities including, but not limited to, the following: §63.760 — Applicability and designation of affected source o (f) The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. (4) The owner or operator of an affected area source, located in an Urban -1 county, as defined in §63.761, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the provisions of this subpart immediately upon initial startup or January 3, 2007, whichever date is later. §63.764 -General Standards o (d)(2) Each owner or operator of an area source not located in a UA plus offset and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2(i) through (iii) of this section. • (i) Determine the optimum glycol circulation rate using the following equation: AIRS ID: 123/0107 Page 14 of 37 t ,„xllorail6Dep f €;t Lo„=115*3.0 gal TEG * F*(I—O) IbH2O 24hr/day Public Health and Environment Air Pollution Control Division Where: Loan = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D). I = Inlet water content (Ib/MMSCF). O = Outlet water content (lb/MMSCF) 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/IbH2O) 1.15 = Adjustment factor included for a margin of safety. (ii) Operate the TEG dehydration unit such that the actual glycol circulation rate does not exceed the optimum glycol circulation rate determined in accordance with paragraph (d)(2)0) of this section. If the TEG dehydration unit is unable to meet the sales gas specification for moisture content using the glycol circulation rate determined in accordance with paragraph (d)(2)(i), the owner or operator must calculate an alternate circulation rate using GRI—GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). (iii) Maintain a record of the determination specified in paragraph (d)(2)(ii) in accordance with the requirements in §63.774(f) and submit the Initial Notification in accordance with the requirements in §63.775(c)(7). If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph (d)(2)(i) or (H) of this section and submit the information specified under §63.775(c)(7)0i) through (v). §63.774 - Recordkeeping Requirements o (b) Except as specified in paragraphs (c), (d), and (0 of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1) through (11) of this section: (1) The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports and notifications) required by this subpart. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. • (i) All applicable records shall be maintained in such a manner that they can be readily accessed. (ii) The most recent 12 months of records shall be retained on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. AIRS ID: 123/0107 Page 15 of 37 )olorai 1Dept Public Health and Environment Air Pollution Control Division • (iii) The remaining 4 years of records may be retained offsite. • (iv) Records may be maintained in hard copy or computer - readable form including, but not limited to, on paper, microfilm, computer, floppy disk, magnetic tape, or microfiche. o (f) The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or §63.764(d)(2)0i), as applicable. §63.775 — Reporting Requirements o (c) Except as provided in paragraph (c)(8), each owner or operator of an area source subject to this subpart shall submit the information listed in paragraph (c)(1) of this section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). (1) The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under §63.0(a), you must also submit a copy of. the initial notification to EPA's Office of Air Quality Planning and Standards. Send your notification via e-mail to CCG— ONG@EPA.GOV or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Coatings and Chemicals Group (E143—01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. (7) The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification. (I) Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shall include the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the names of the nearest urban cluster with 10,000 people or more and nearest urbanized area. (ii) Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i). (iii) If applicable, documentation of the alternate glycol circulation rate calculated using GRI-GLYCaIcTM, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. (iv) The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. AIRS ID: 123/0107 Page 16 of 37 plorDepent Public Health and Environment w; Air Pollution Control Division (v) Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. o (f) Notification of process change. Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: (1) A brief description of the process change; (2) A description of any modification to standard procedures or quality assurance procedures (3) Revisions to any of the information reported in the original Notification of Compliance Status Report under paragraph (d) of this section; and (4) Information required by the Notification of Compliance Status Report under paragraph (d) of this section for changes involving the addition of processes or equipment. 35. Point 048: This unit is subject to the requirements in 40 CFR part 63 Subpart A "General Provisions", as adopted by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart HH § 63.764. These requirements include, but are not limited to the following: a. Prohibited activities and circumvention in § 63.4. b. Operation and maintenance requirements in § 63.6(e)(1). c. Notification requirements in § 63.9(j). d. Recordkeeping and reporting requirements in § 63.10(b), except as provided in § 63.774(b)(1). 36. Points 048 and 050: The combustion device used to control emissions of volatile organic compounds from these units to comply with Section XII.D shall be enclosed, have no visible emissions, and be designed so that an observer can, by means of visual observation from the outside of the enclosed combustion device, or by other means approved by the Division, determine whether it is operating properly. The operator shall comply with all applicable requirements of SectionXII. (Reference: Regulation No. 7, Section XII.C.1.d.) AIRS ID: 123/0107 Page 17 of 37 Deprl trpent c',11 Public Health and Environment j," !? ri Air Pollution Control Division opulpmentr, shall have 'a' control efficiency of. at I act 95% and shall control volatile organic compounds during the first 90 calendar days after the date of first production after the tank was newly installed, or after the well was newly drilled, re completed, re fractured or otherwise stimulated.' The air pollution control equipment and associated monitoring equipment required pursuant to Xlj C 1 may removed after`the..first 90 calendar days as long —as --the source can demonstrate compliance with the applicable system wide standard' 3-R 37 Point 050: The condensate storage tanks covered by this permit are subject to Regulation 7, Section XVII emission control requirements (State only enforceable). These requirements include, but are not limited to: Section XVII.C. - Emission reduction from condensate storage tanks at oil and gas exploration and production operations, natural gas compressor stations, natural gas drip stations and natural gas processing plants. XVII.C.1. Beginning May 1, 2008, owners or operators of all atmospheric condensate storage tanks with uncontrolled actual emissions of volatile organic compounds equal to or greater than 20 tons per year based on a rolling twelve-month total shall operate air pollution control equipment that has an average control efficiency of at least 95% for VOCs on such tanks. XVII.C.3. Monitoring: The owner or operator of any condensate storage tank that is required to control volatile organic compound emissions pursuant to this section XVII.C. shall visually inspect or monitor the Air Pollution Control Equipment to ensure that it is operating at least as often as condensate is loaded out from the tank, unless a more frequent inspection or monitoring schedule is followed. In addition, if a flare or other combustion device is used, the owner or operator shall visually inspect the device for visible emissions at least as often as condensate is loaded out from the tank. XVII.C.4. Recordkeeping: The owner or operator of each condensate storage tank shall maintain the following records for a period of five years: XVII.C.4.a. Monthly condensate production from the tank. XVII.C.4.b For any condensate storage tank required to be controlled pursuant to this section XVII.C., the date, time and duration of any period where the air pollution control equipment is not operating. The duration of a period of non -operation shall be from the time that the air pollution control equipment was last observed to be operating until the time the equipment recommences operation. XVII.C.4.c. For tanks where a flare or other combustion device is being used, the date and time of any instances where visible emissions are observed from the device. I 39 38. Point 052: The compressorsat this point that commenced construction, modification or reconstruction after August 23, 2011, are subject to the New Source Performance AIRS ID: 123/0107 Page 18 of 37 Comment [DM59]: This should be removed Lucerne is not en Exploration and production site. Public Health and Environment Air Pollution Control Division Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: §60.5385(a) — Owner or operator must replace the reciprocating compressor rod packing according to either paragraph §60.5385(a)(1) or (2). o §60.5385(a)(1) - Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or October 15, 2012, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. o §60.5385(a)(2) - Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced. §60.5410 — Owner or operator must demonstrate initial compliance with the standards as detailed in §60.5410(c). §60.5415 — Owner or operator must demonstrate continuous compliance with the standards as detailed in §60.5415(c). §60.5420 - Owner or operator must comply with the notification, reporting, and recordkeeping requirements as specified in §60.5420(a), §60.5420(b)(1), §60.5420(b)(4), and §60.5420(c)(3). 48-39. Point 052: The fugitive emissions at this point that commenced construction, modification or reconstruction after August 23, 2011, are subject to the New Source Performance Standards requirements of Regulation No. 6, Part A, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution including, but not limited to, the following: §60.5365 Applicability: The group of all equipment, except compressors, within a process unit which commenced construction, modification or reconstruction after August 23, 2011 is an affected facility per §60.5365(f). • §60.5400 Standards: The group of all equipment, except compressors, within a process unit must comply with the requirements of §60.5400 and §60.5401. • §60.5410: Owner or operator must demonstrate initial compliance with the standards using the requirements in §60.5410(f). • § 60.5415: Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). • § 60.5421: Owner or operator must comply with the recordkeeping requirements of §60.5421(b). § 60.5422: Owner or operator must comply with the reporting requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). 41-:40. Point 052: This source is subject to Regulation No. 7, Section XII.G.1 (State only enforceable). To comply with Regulation No. 7, Section XII.G.1, the source shall follow the leak detection and repair (LDAR) program as provided at 40 C.F.R. Part 60, Subpart OOOO in lieu of following 40 C.F.R. Part 60, Subpart KKK. AIRS ID: 123/0107 Page 19 of 37 ora'Ji5Depsitrent c Public Health and Environment Air Pollution Control Division e*a3,r •, a::.31:a ece.,gla 42:41, Points 044, 045, 046, and 052: The source is subject to the requirements of Regulation No. 6, Part A, Subpart A, General Provisions, including, but not limited to, the following: a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division, which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11) b. No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§ 60.12) c. Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under § 60.7. e. Performance tests shall be conducted as required under §60.8. 43 42 This source is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D2.b. The following requirements were determined to be RACT for this source. Facility Equipment AIRS Pollutant RACT ID Point TURB-1 044 NOR, VOC Natural gas as fuel, low NOx burners, good combustion practices TURB-2 045 NOR, VOC Natural gas as fuel, low NOx burners, good combustion practices HT -02 046 NOR, VOC Natural gas as fuel, low NOx burners, good combustion practices. AU -02 047 VOC Flash: VRU, Still Vent: Regenerative Thermal Oxidizer D-1 048 VOC Flash: VRU, Still Vent: Enclosed combustor TANKS 050 VOC Enclosed combustor LOAD 051 VOC Submerged fill, enclosed combustor AIRS ID: 123/0107 Page 20 of 37 41_ 'olora� 4 ent Public Health and Environment JDepkri Air Pollution Control Division OPERATING & MAINTENANCE REQUIREMENTS ermit the applicant shall follow the operating dA,43. Upon maintenance n of the plan and overed brecordy this pkeeping format approved by the Division, in and (O&M) order is permito demonsrae Revisiotnstto y�lraO&Mnce onpanan�are subjectngoinasis toltDivson approeatsprior f hto implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.) COMPLIANCE TESTING AND SAMPLING Initial Testina Requirements a5-aa ,Points 044 ial testing requirements off045: The combustion turbines are subject 40 C.F.R. Part 60, Subpart KKKK, as referenced inthispermit. test be ucted on each of e ns.a5._combution tu045: A source rbines to measurelfial the emssionerate(s) for t the pollutants listed belowin order to demonstrate compliance with the emissions limits contained in this permit. The test must be in accordance with the requirements of the D visiontCompliance Test Manual and shall be submitted to the Di is on for ollut review and nd approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show copll have he s upmtoltheemonthly orannual limitation with a averaging tmebymultiplying the ttest eestultsprojected by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Part B., Section IILG.3) Carbon. Dioxide using EPA approved methods. This test may be conducted concurrently with the testing required by Condition 45. ator hall sampling 044, 045, and for g gross caloriffiiicvalue (GCV) [high heat The owner or rvalue s(HHV)I of complete hfuel used in the turbines required is p n as of the selfcertifcatonprocesso ensure compliance t and submit the fewith emissionsults to the s limits. partmits. (Reference: Regulation No. 3, Part B, Section III.E.) be conducted on the heatto measure a&47 initial the emission rate(s) for the pollutants shall listed below in order to demonstrate compliance with the limitcontained in acco dancemwith the requirements of this test the AirPollu on Control Division Compliance Test Manual andshall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from thDivision. emission compliance conducted to with a monly or limitation shall have theresultsproj projected upcompliance the monthly or annual annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3, Section III.G.3) Oxides of Nitrogen using EPA approved methods. methods. Carbon Monoxide using EPA approved methometho Carbon Dioxide using EPA approved Page 21 of 37 AIRS ID: 123/0107 Public Health and Environment 1. Air Pollution Control Division I 49448. Point 047: The operator shall complete the initial annual analysis of the inlet gas to the plant to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that this amine unit qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Production Transmission and Distribution Emissions (§60.53651g113>64g(b)) essiag: —SO2 50.49. Point 047: The owner or operator shall complete the initial annual extended sour gas analysis testing required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 54.50_ Point 047: The owner or operator shall complete the initial amine unit waste gas extended gas analysis required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) 52.51 Point 048: The owner or operator shall complete the initial annual extended wet gas analysis testing required by this permit and submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. (Reference: Regulation No. 3, Part B, Section III.E.) I 5252. Point 047: A source initial compliance test shall be conducted on emissions point 047 to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits specified in Condition 7 in this permit. The amine units must be operating at its natural gas throughput and lean amine circulation rate capacity as stated _in this permit plus or minus 10% for the duration of the test. The natural gas throughput, lean amine circulation rate, and sulfur content of sour gas entering the amine units shall be monitored and recorded during this test. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Common Provisions Section II.C and Regulation No. 3, Part B., Section III.G.3) Volatile Organic Compounds using EPA approved methods Carbon Dioxide using EPA approved methods. I 54.53. Points 048 and 050: The owner or operator shall demonstrate compliance with Condition 36 using EPA Method 22 to measure opacity from the enclosed combustor. The observation period shall be a minimum of fifteen consecutive minutes. 35,54. _Point 052: Within one hundred and eighty days (180) after commencement of operation, the permittee shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of liquids that are representative of methane (CH4), carbon dioxide (CO2), volatile organic compound (VOC) and hazardous air AIRS ID: 123/0107 Page 22 of 37 NI jiblor rim it r, ep . ent . Public Health and Environment q"1 Air Pollution Control Division VA 9 pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas and liquids analyses and emission calculations to the Division as part of the self -certification process to ensure compliance with emissions limits. 56,55. Point 052: Within one hundred and eighty days (180) after commencement of operation, the operator shall complete a hard count of components at the source and establish the number of components that are operated in "light liquid service" and "gas service". The operator shall submit the results to the Division as part of the self - certification process to ensure compliance with emissions limits. Periodic Testing Requirements 57:56. Points 044 and 045: Replacements of these units completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 58-57. Points 044 and 045: The combustion turbines are subject to the periodic testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 5-9-58. Points 044 and 045: The operator shall conduct, at a minimum, quarterly portable analyzer monitoring of the turbine exhaust outlet emissions of nitrogen oxides (NOx) and carbon monoxide (CO) to monitor compliance with the emissions limits. Emissions of carbon dioxide (CO2) shall be measured from an infrared detector or calculated from the oxygen (O2) reading to monitor compliance with the emissions limit. Results of all tests conducted shall be kept on site and made available to the Division upon request. 60.59. Points 044, 045, and 046: The fuel gross calorific value (GCV) [high heat value (HHV)] of the fuel used in the turbines and heaters shall be determined, at a minimum, once per every six months by the procedures contained in 40 CFR Part 98.34(a)(6) and records shall be maintained of the semiannual fuel GCV for a period of five years. Upon request, the owner or operator shall provide a sample and/or analysis of the fuel that is fired in the units. 61-:60. Point 047: The operator shall complete an extended gas analysis on the amine unit waste gas annuallyat least once every throe months. The sample data shall be used to determine GHG composition in accordance with 40 CFR 98.233(d)(6) and 98.234(b). The analysis shall also include be used to determine the heat value of the waste gas stream. 62.-61. PaintOW The eratoiShalt samp)e' efmlet gas to the plant on anQa'nnual basis;tq deters�pine the conce.ntratton;of hydrogen sulfjde,(HZS).in;the:,bas stream. The sample results�`shall'-be`monitored to -demonstrate that thisram`ine' unit qualifies for the.•exemption from the Standards of,Performance for, Onshore ;Natural,;, Gas Processing: S02 Emissions (§60,'2640(b))._ 63.62.__Point.047: The owner or operator shall complete'anrextended sour gas analysis prior to the inlet of the amine unit on an annual basis. Results of the sour'gas analysis shall be used . to calculate emissions of criteria- pollutants and :hazardous ;pair pollutants per Condition 7. AIRS ID: 123/0107 Page 23 of 37 :Comment [DMS10]: Can these two • conditions be. combined? They seem to be the. same. • in ent e'? Public Health and Environment Air Pollution Control Division 64:63_Point 048: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the TEG dehydrator on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 165.64 Points 048: The owner or operator shall conduct EPA Method 22 visible emission observations to monitor opacity from the enclosed combustor daily. The observation period shall be a minimum of six consecutive minutes. 66.65. Point 052: On an annual basis, the permittee shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of liquids that are representative of methane (CH4), carbon dioxide (CO2), volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. 167:66. Point 052: The fugitive emissions at this point that commenced construction, modification or reconstruction after August 23, 2011, are subject to the leak detection and repair (LDAR) requirements of 40 C.F.R Part 60, Subpart OOOO. 16€467. Point 052: The fugitive emissions at this point that commenced construction, modification or reconstruction prior to August 23, 2011 are subject to the leak detection and repair (LDAR) requirements of 40 C.F.R Part 60, Subpart KKK. ADDITIONAL REQUIREMENTS 16&f8.__A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually whenever a significant increase in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five (5) tons per year or more, above the level reported on the last APEN; or For volatile organic compounds (VOC) and nitrogen oxides sources (NO) in ozone nonattainment areas emitting less than 100 tons of VOC or NOx per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last APEN; or For any non -criteria reportable pollutant: If the emissions increase by 50% or five (5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. b. Whenever there is a change in the owner or operator of any facility, process, or activity; or c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. AIRS ID: 123/0107 Page 24 of 37 Public Health and Environment Air Pollution Control Division f. Points 044 and 045: Within 14 calendar days of commencing operation of a permanent replacement turbine under the alternative operating scenario outlined in this permit as Attachment A. The APEN shall include the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative -operating scenario and is installing a permanent replacement turbine. 79-69. This source is subject to the provisions of Regulation Number 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The provisions of this construction permit must be incorporated into the operating permit. The application for the modification to the Operating Permit is due within one year of commencement of operation of the equipment or modification covered by this permit. 71-:70. Points 044 and 045: MACT Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) 72.,71. Point 048: MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities major stationary source requirements shall apply to this stationary source at any such time that this stationary source becomes major solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) GENERAL TERMS AND CONDITIONS: 73-72. This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 74.73_If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with the provisions of 25-7-114.5(12)(a) C.R.S. and AQCC Regulation No. 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self -certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final authorization. Details for obtaining final authorization to operate are located in the Requirements to Self - Certify for Final Authorization section of this permit. 75.74. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. AIRS ID: 123/0107 Page 25 of 37 ioloradO,DeptiArpento Public Health and Environment zi tu{ Air Pollution Control Division 76/5. Unless specifically stated otherwise, the general and specific conditions contained in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 25-7-114.5(7)(a), C.R.S. 27:76. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self -certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 78:77. Section 25-7-114.7(2)(a), C.R.S. requires that all sources required to file an Air Pollution Emission Notice (APEN) must pay an annual fee to cover the costs of inspections and administration. If a source or activity is to be discontinued, the owner must notify the Division in writing requesting a cancellation of the permit. Upon notification, annual fee billing will terminate. 79.78. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention and Control Act or the regulations of the AQCC may result in administrative, civil or criminal enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil penalties), -122.1 (criminal penalties), C.R.S. By: Bailey Kai Smith Permit Engineer Permit Histo Issuance Date Description Issuance 1 This Issuance Addition of nine (9) permitted sources for a natural gas processing plant. Sources located at a major facility. AIRS ID: 123/0107 Page 26 of 37 Public Health and Environment Air Pollution Control Division Notes to Permit Holder: 1) The production or raw material processing limits and emission limits contained in this permit are based on the consumption rates requested in the permit application. These limits may be revised upon request of the permittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request fora permit revision. 2) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See: http://www.cdohe.state.co.us/regulations/airregs/100102agcccommonprovisionsreq.odf. 3) The following emissions of non -criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. AIRS Point Pollutant CAS # BIN Uncontrolled Emission Rate (Ib/yr) Are the emissions reportable? Controlled Emission Rate (Ib/yr) 044 Formaldehyde 50000 A 411 Yes 411 045 Formaldehyde 50000 A 411. Yes 411 047 Benzene 71432 A 128,947 Yes 5,158 Toluene 108883 C .61,24732 Yes 2,45049 Ethylbenzene 100414 C 2,2211.99 Yes 898 Xylenes 1330207 C 4,6473 Yes 186 n -Hexane 110543 C 1,526488 Yes 618 048 Benzene 71432 A 136,834 Yes 6,842 Toluene 108883 C 88,875 Yes 4,444 Ethylbenzene 100414 C 5,693 Yes 285 Xylenes 1330207 C 11,872 Yes 594 n -Hexane 110543 C 52,173 Yes 2,609 050 Benzene 71432 A 1,03140 Yes 52 Toluene 108883 C 2,8586 Yes 1432- Xylenes 1330207 C 21601-2 Yes 44108 n -Hexane 110543 C 5,5496 Yes 277 051 Benzene 71432 A 1,25726 Yes 63 Toluene 108883 C 3,483604 Yes 1746 Xylenes 1330207 C 2,63228 Yes 1324- n -Hexane 110543 C 6,76245 Yes 3387 AIRS ID: 123/0107 Page 27 of 37 ente Public Health and Environment Air Pollution Control Division 052 Benzene 71432 A 225 Yes 26 n -Hexane 110543 C 4,615 Yes 528 4) The emission levels contained in this permit are based on the following emission factors: Points 044 and 045: CAS Pollutant Emission Factors Ib/MMBtu - Uncontrolled Source NOx 0.0519 Manufacturer CO 0.0608 Manufacturer Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart C CH4 0.001 21 40 CFR 98 Subpart C N2O 0.0001 310 40 CFR 98 Subpart C Emission factors are based on a rated heat input of 66.12466 MMBtulhr and 8760 hours of operation a year. Point 046: CAS Pollutant Emission Factors lblMMscf - Uncontrolled Source NOx 37 Manufacturer CO 84 AP -42, Chapter 1.4 Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart C CH4 0.001 21 40 CFR 98 Subpart C N2O 0.0001 310 40 CFR 98 Subpart C Emission factors are based on a rated heat input of 50 MMBtu/hr, a higher heating value of 1,02362 Btu/scf, and a limited use scenario of 315 MMscf/yr or the equivalent of 67% of operating capacity. Point 047: The VOC emission levels contained in this permit are based on the ProMax model using the extended sour gas analysis representative of the natural gas processed by this unit submitted with the permit application. Sampling is required and the results of which shall be used on an ongoing basis to calculate emissions. The following emission factors are used for the combustion of waste gas in the regenerative thermal oxidizer: CAS Pollutant Emission Factors — Uncontrolled lb/MMBtu Uncontrolled EF Source CO 0.37 AP -42, Chapter 13.5 AIRS ID: 123/0107 Page 28 of 37 i ' Ior Dep, trient c Public Health and Environment 1 Air Pollution Control Division The SO2 emission levels contained in this permit are based on information provided in the application and using a mass balance approach from the H2S content of the gas stream as determined using the ProMax model. The owner or operator shall calculate CO2 emissions from each amine unit, on a monthly basis, using equation W -4A consistent with 40 CFR Part 98, Subpart W [98.233(d)(2)] along with the most recent waste gas sampling composition. The owner or operator shall calculate GHG emissions from combustion at the regenerative thermal oxidizer based on procedures in 40 CFR 98 Subparts A and C. Total CO2 emissions shall be based on the sum of CO2 emissions from the amine unit plus GHG emissions from combustion at the regenerative thermal oxidizer. (Greenhouse Gas -Emission -`Factors for Regenerative Thermal Oxidizer Combustion Pollutant kg/MMBtu GWP Source CO2 53.02 1 40 CFR 98 Subpart A and C CH4 0.001 21 40 CFR 98 Subpart A and C N2O 0.0001 310 40 CFR 98 Subpart A and C GHG emissions from combustion are based on a heat content of 5.12 Btulscf and a total heat input for the regenerative thermal oxidizer of 4.0 MMBtuihr. Point 048: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 -- 1 40 CRR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W* The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Point 050: CAS Pollutant Emission Factors Uncontrolled lb/BBL Condensate Throughput Emission Factors Controlled lb/BBL Condensate Throughput Source VOC 0.166 0.0083 EPA Tanks 4.09d 71432 Benzene 0.0022851-8 0.00011332 EPA Tanks 4.09d Note: The controlled emissions factors for point 050 are based on the enclosed combustor control efficiency of 95%. Emission factors are based on the condensate tank battery as a combined unit, not per tank. Greenhouse Gas Emission Factors Pollutant kg/MMBtu GWP Source CO2 — 1 40 CRR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W" The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 AIRS ID: 123/0107 Page 29 of 37 Comment [DMS11]: Are these factors for t2TOs or TOs7 . `7 Vlr 11 DeptIrrlent a„ Public Health and Environment rt Air Pollution Control Division CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Point 051: CAS Pollutant Emission Factors Uncontrolled lb/BBL loaded Emission Factors Controlled Ib/BBL loaded Source VOC 0.202 0.0101 AP -42, Chapter 5.2 71432 Benzene 0.00276667 0.000138 AP -42, Chapter 5.2 The uncontrolled VOC emission factor was calculated using AP -42, Chapter 5.2, Equation 1 (version 1/95) using the following values: L = 12.46*S*P*M/T S = 0.6 (Submerged loading: dedicated normal service) P (true vapor pressure) = 5.0032 psia M (vapor molecular weight) = 66 lb/lb-mol T (temperature of liquid loaded) = 512.45 `R The uncontrolled non -criteria reportable air pollutant (NCRP) emission factors were calculated by multiplying the mass fraction of each NCRP in the vapors by the VOC emission factor. Controlled emission factors are based on an enclosed combustor efficiency of 95%. Greenhouse Gas Emission Factors Pollutant kg/MIVIBtu GWP Source CO2 -- 1 40 CRR Subpart W N2O 0.0001 310 40 CFR 98 Subpart W" The owner or operator shall calculate CO2, CH4, and N2O emissions from the combustion of waste gas in the enclosed combustor, on a monthly basis, using equations and procedures outlined in 40 CFR Part 98, Subpart W 98.233(n) along with the use of engineering calculations based on process knowledge, company records, and best available data. The combustion efficiency of this unit is assumed as 95%. Point 052: Equipment Type Gas Light Liquid Connectors 1,276 4,044 Flanges 1,145 764 Open -Ended Lines -- -- Pump Seals 25 38 Valves 2;611 2,006 Other 71 35 VOC Content (wf%) 26.92% 100% Benzene (wt%) 0.06% 0.06% Toluene (wt%) 0.04% 0.04% Ethylbenzene (wt%) 0.003% 0.03% Xylenes (wt%) 0.01% 0.01% n -hexane (wt%) 1.21% 1.21% CO2 Content (wt%) 6.65% -- CH4 Content (wt%) 54.67% — AIRS ID: 123/0107 Page 30 of 37 jolora Public Health and Environment Air Pollution Control Division 'Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Light Oil Connectors 2.0E-04 2.1E-04 Flanges 3.9E-04 1.1E-04 Open-ended Lines 2.0E-03 1.4E-03 Pump Seals 2.4E-03 1.3E-02 Valves 4.5E-03 2.5E-03 Other 8.8E-03 7.5E-03 Source: EPA -453/R95-017 Note that the emission limits included in this permit are derived by multiplying the equipment counts in the table above by a factor of 1.2 to accommodate other minor changes to the facility and to provide a conservative estimate of facility -wide emissions. Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas and liquids analyses. For CO2e emissions, the TOC emission factors listed in the table above with representative component count will be multiplied by the CH4 and CO2 content from the most recent gas analysis. CO2e emissions are then calculated based on procedures in 40 CFR 98 Subpart A. 5) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it was received by the Division. A revised APEN shalt be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-3150. 6) This facility is classified as follows: Applicable Requirement Status Operating Permit Major Source of NOx, VOC, and CO PSD Subject to Regulation of CO2e NANSR Major Source of NOx and VOC 7) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A - Subpart OOOOKKKK AIRS ID: 123/0107 Page 31 of 37 'qre 1,{-:.. k.olora,J;Dep4 atrnent c, Public Health and Environment Air Pollution Control Division 4,1 NSPS I Part 60, Appendixes Appendix A — Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories MACT 63.1-63.599 Subpart A — Subpart Z MACT 63.600-63.1199 Subpart AA — Subpart DDD MACT 63.1200-63.1439 Subpart EEE — Subpart PPP MACT 63.1440-63.6175 Subpart QQQ — Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ— Subpart MMMMM MACT 63.8980 -End Subpart NNNNN — Subpart XXXXXX 8) An Oil and Gas Industry Construction Permit Self -Certification Form is included with this permit packet. Please use this form to complete the self -certification requirements as specified in the permit conditions. Further guidance on self -certification can be found on our website at: http://wivw.cdphe.state.co.us/ap/oiloaspermittinq.html AIRS ID: 123/0107 Page 32 of 37 DCP Midstream, LP Permit No. 12WE2024 f3 Issuance 1 of Public Health and Environment Air Pollution Control Division ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING August 16, 2011 1. Routine Turbine Component Replacements The following physical or operational changes to the turbines in this permit are not considered a modification for purposes of NSPS GG, major stationary source NSR/PSD, or Regulation No. 3, Part B. Note that the component replacement provisions apply ONLY to those turbines subject to NSPS GG. Neither pre-GG turbines nor post GG turbines (i.e. KKKK turbines) can use those provisions. 1) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seals, and shaft packings, provided that they are of the same design as the original. 2) Changes in the type or grade of fuel used, if the original gas turbine installation, fuel nozzles, etc. were designed for its use. 3) An increase in the hours of operation (unless limited by a permit condition) 4) Variations in operating loads within the engine design specification. 5) Any physical change constituting routine maintenance, repair, or replacement. Turbines undergoing any of the above changes are subject to all federally applicable and state only requirements set forth in this permit (including monitoring and record keeping). If replacement of any of the components listed in (1) or (5) above results in a change in serial number for the turbine, a letter explaining the action as well as a revised APEN and appropriate filing fee shall be submitted to the Division within 30 days of the replacement. Note that the repair or replacement of components must be of genuinely the same design. Except in accordance with the Alternate Operating Scenario set forth below, the Division does not consider that this allows for the entire replacement (or reconstruction) of an existing turbine with an identical new one or one similar in design or function. Rather, the Division considers the repair or replacements to encompass the repair or replacement of components at a turbine with the same (or functionally similar) components. 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of combustion turbines and turbine components has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility- Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any turbine or turbine component replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such turbineor turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. AIRS ID: 123/0107/044, 045 Page 2 of 37 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 Co Ado , 1 or Public Health and Environment Air Pollution Control Division 2.1 Turbine Replacement The following AOS is incorporated into this permit in order to deal with a turbine breakdown or periodic routine maintenance and repair of an existing onsite turbine that requires the use of a temporary replacement turbine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. "Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The. 90 days is the total number of days that the turbine is in operation. If the turbine operates only part of a day, that day shall count as a single day towards the 90 -day total. The compliance demonstrations and any periodic monitoring required by this AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit. Any permanent turbine replacement under this AOS shall result in the replacement turbine being considered a new affected facility for purposes of NSPS and shall be subject to all applicable requirements of that Subpart including, but not limited to, any required Performance Testing. All replacement turbines are subject to all federally applicable and state -only requirements set forth in this permit (including monitoring and record keeping). The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30 calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with the NSPS requirements. Results of all tests shall be kept on site for five (5) years and made available to the Division upon request. The owner or operator shall maintain a log on -site and contemporaneously record the start and stop date of any turbine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the turbine (s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, andserialnumber of the replacement turbine. 2.1.1 The owner or operator may temporarily replace an existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit, so long as the temporary replacement turbine complies with the emission limitations for the existing permitted turbine and other requirements applicable to the original turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.2 The owner or operator may permanently replace the existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit so long as the permanent replacement turbine complies with the emission limitations and other requirements applicable to the original turbine as well as any new applicable requirements for the replacement turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.3 An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar days of commencing operation of the replacement turbine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement turbine. This AOS cannot be used for permanent turbine replacement of a grandfathered or permit exempt turbine or a turbine that is not subject to emission limits. The owner or operator shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent turbine replacement. AIRS ID: 123/0107/044, 045 Page 3 of 37 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 CoItinado Public Health and Environment Air Pollution Control Division The AOS cannot be used for the permanent replacement of an entire turbine at any source that is currently a major stationary source for purposes of Prevention of Significant Deterioration or Non -Attainment Area New Source Review ("PSD/NANSR") unless the existing turbine has emission limits that are below the significance levels in Reg 3, Part D, II.A.42. Nothing in this AOS shall preclude the Division from taking an action, based on any permanent turbine replacement(s), for circumvention of any state or federal PSD/NANSR requirement. Additionally, in the event that any permanent turbine replacement(s) constitute(s) a circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse the owner or operator from complying with PSD/NANSR and applicable permitting requirements. 2.2 Portable Analyzer Testing Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss streamlining the testing requirements. Note that the testing required by this Condition may be used to satisfy the periodic testing requirements specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer testing, this test conducted under the AOS will serve as the quarterly test and an additional portable analyzer test is not required for another three months). The owner or operator may conduct a reference method test, in lieu of the portable analyzer test required by this Condition, if approved in advance by the Division. The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement turbine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement turbine. All portable analyzer testing required by this permit shall be conducted using the most current version of the Division's Portable Analyzer Monitoring Protocol as found on the Division's website. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. For comparison with a short-term limit that is either input based (Ib/mmBtu), output based (g/hp-hr) or concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement turbine will be subject to, the results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the turbine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO emission limitations, the turbine will be considered to be out of compliance from the date of the AIRS ID: 123/0107/044, 045 Page 4 of 37 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 oP Public Health and Environment Air Pollution Control Division portable analyzer test until a portable analyzer test indicates compliance with both the NOX and CO emission limitations or until the turbine is taken offline. 2.3 Applicable Regulations for Permanent Turbine Replacements 2.3.1 NSPS for Stationary Gas Turbines: 40 CFR 60, Subpart GG §60.330 Applicability and designation of affected facility. (a) The provisions of this subpart are applicable to the following affected facilities: All stationary gas turbines with a heat input at peak load equal to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the lower heating value of the fuel fired. (b) Any facility under paragraph (a) of this section which commences construction, modification, or reconstruction after October 3, 1977, is subject to the requirements of this part except as provided in paragraphs (e) and (I) of §60.332. A Subpart GG applicability determination as well as an analysis of applicable Subpart GG monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the. State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS GG requirements). 2.3.2 NSPS for Stationary Combustion Turbines: 40 CFR 60, Subpart KKKK §60.4305 Does this subpart apply to my stationary combustion turbine? (a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part. A Subpart KKKK applicability determination as well as an analysis of applicable Subpart KKKK monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS KKKK requirements). AIRS ID: 123/0107/044, 045 Page 5 of 37 DCP Midstream, LP Permit No. 12WE2024 Issuance 1 2.4 Additional Sources Public Health and Environment Air Pollution Control Division The replacement of an existing turbine with a new turbine is viewed by the Division as the installation of a new emissions unit, not "routine replacement" of an existing unit. The AOS is therefore essentially an advanced construction permit review. The AOS cannot be used for additional new emission points for any site; a turbine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite turbine has to go through the appropriate Construction/Operating permitting process prior to installation AIRS ID: 123/0107/044, 045 Page 6 of 37 NE SOURCE REVIEW PERMIT APPLICATION DCP Midstream LP > Lucerne 2 Plant dcp Midstream. Prepared By: Dana Stephens - Rockies Air Permitting Manager DCP MIDSTREAM LP 370 17th Street, Suite 2500 Denver, CO 80202 (303) 605-1716 Fax: (303) 605-1957 Kim Ayotte - Senior Consultant Roshini Shankaran - Senior Consultant Hari Krishna Bharadwaj - Consultant TRINITY CONSULTANTS 1391 N Speer Blvd, Suite 350 Denver, CO 80204 (720) 638-7647 October 2013 Project 120601.0002 Tri ° Consultants Environmental solutions delivered uncommonly well TABLE OF CONTENTS 1. EXECUTIVE SUMMARY 1-1 1.1. Proposed Project 1-1 1.2. Permitting Considerations 1-2 1.2.1. Nonattainment New Source Review 1-2 1.2.2. Prevention of Significant Deterioration 1-2 1.3. Permit Application 1-3 2. FORM APCD-100 2-1 3. ATTACHMENT A - APEN FILING FEES 3-1 4. ATTACHMENT B - APCD FORM SERIES 200 4-1 5. ATTACHMENT C - EMISSION CALCULATIONS AND SUPPORTING DOCUMENTATION 5-1 5.1. Combustion Turbines 5-2 5.2. Heater 5-2 5.3. Amine Treater 5-3 5.4. Glycol Dehydrator 5-6 5.5. Atmospheric Storage Tanks 5-9 5.6. Truck Loading Losses 5-10 5.7. Equipment Leak Fugitives 5-11 6. ATTACHMENT D - FORM APCD-101 6-1 7. ATTACHMENT E - AMBIENT AIR IMPACT ANLAYSIS 7-1 8. ATTACHMENT F - FORM APCD-102 8-1 9. ATTACHMENT G - PROCESS AND FACILITY INFORMATION 9-1 9.1. Process Description 9-2 9.1.1. Current Process Description 9-2 9.1.2. Proposed Process Description 9-2 9.2. Process Flow Diagram 9-3 9.3. Area Map 9-4 10. ATTACHMENT H - APCD FORM SERIES 300 10-1 11. ATTACHMENT I - REGULATORY ANALYSIS 11-1 11.1. Colorado State Regulations 11-1 11.1.1. CDPHEAPCD Regulation 3, Part A, Section II11-1 11.1.2. Concerning Construction Permits (Regulation 3, Part B) 11-1 11.1.3. Concerning Operating Permits (Regulation 3, Part C) 11-1 11.1.4. Concerning Major Stationary Source New Source Review and Prevention ofSignificant Deterioration (Regulation 3, Part D) 11-1 11.1.5. Volatile Organic Compound Emissions from Oil and Gas Operations (Regulation 7, Section XII)11-1 11.1.6. Control of Emissions from Stationary and Portable Engines in the 8 -Hour Ozone Control Area (Regulation 7, Section XVI) 11-2 11.1.7. Statewide Controls for Oil and Gas Operations and Natural Gas -Fired Reciprocating Internal Combustion Engines (Regulation 7, Section XVII) 11-2 DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11.2. New Source Performance Standards 11-2 11.2.1. SubpartA - General Provisions 11-3 11.2.2. Subpart Dc - Small Industrial -Commercial -Institutional Steam Generating Units 11-3 11.2.3. Subpart Kb - Volatile Organic Liquid Storage Vessels 11-3 11.2.4. Subpart KKK - Equipment Leaks of VOC From Onshore Natural Gas Processing Plants 11-4 11.2.5. Subpart LLL - Onshore Natural Gas Processing: SO2 11-4 11.2.6. Subpart KKKK- Stationary Combustion Turbines 11-4 11.2.7. Subpart 0000 - Crude Oil and Natural Gas Production, Transmission, and Distribution 11-5 11.3. National Emission Standards for Hazardous Air Pollutants 11-5 11.3.1. SubpartA - General Provisions 11-6 11.3.2. Subpart HH - Oil and Natural Gas Production Facilities 11-6 11.3.3. Subpart HHH - Hazardous Air Pollutants From Natural Gas Transmission and Storage Facilitiesll-7 11.3.4. Subpart YYYY - Hazardous Air Pollutants From Stationary Combustion Turbines 11-7 11.3.5. Subpart DDDDD - Industrial, Commercial, and Institutional Boilers and Process Heaters 11-7 11.3.6. Subpart JJJJJJ - Industrial, Commercial, and Institutional Boilers Area Sources 11-7 11.4. NNSR Applicability Review 11-7 11.5. PSD Applicability Review 11-8 12. ATTACHMENT J - GHG BACT ANALYSIS 12-1 12.1. BACT Definition 12-1 12.1.1. Emission Limitation 12-1 12.1.2. Each Pollutant 12-2 12.1.3. BACT Applies to the Proposed Source 12-2 12.1.4. Case -By -Case Basis 12-2 12.1.5. Achievable 12-3 12.1.6. Production Process 12-4 12.1.7. Available 12-4 12.1.8. Floor 12-4 12.2. GHG BACT Assessment Methodology 12-4 12.2.1. Step 1 - Identify All Available Control Technologies 12-5 12.2.2. Step 2 - Eliminate Technically Infeasible Options 12-6 12.2.3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness 12-6 12.2.4. Step 4- Evaluate Most Effective Controls and Document Results 12-6 12.2.5. Step 5 - Select BACT 12-7 12.3. GHG BACT Requirement 12-7 12.4. GHG BACT Evaluation for Proposed Emission Sources 12-8 12.5. Overall Project Energy Efficiency Considerations 12-9 12.6. Amine Unit (Direct Emissions) 12-9 12.6.1. Step 1 -Identify All Available Control Technologies 12-9 12.6.1.1. Carbon Capture and Sequestration 12-10 12.6.1.2. Flare/Combustor 12-11 12.6.1.3. Thermal Oxidizers 12-11 12.6.1.4. Condenser 12-11 12.6.1.5. Proper Design and Operation 12-11 12.6.1.6. Use of Tank Off -gas Recovery Systems 12-12 12.6.2. Step 2. Eliminate technically infeasible options 12-12 12.6.3. Step 3. Rank the technically feasible control technologies by control effectiveness 12-13 12.6.4. Step 4. Evaluate most effective controls 12-13 12.6.5. Step 5. Select BACT 12-15 12.7. TEG Dehydrator 12-16 DCP Midstream LP Lucerne 2 Expansion Trinity Consultants ii 12.7.1. Step I —Identify All Available Control Technologies 12-16 12.7.1.1. Carbon Capture and Sequestration 12-16 12.7.1.2. Flare/Combustor 12-16 12.7.1.3. Thermal Oxidizer 12-16 12.7.1.4. Condenser 12-16 12.7.1.5. Proper Design and Operation 12-16 12.7.1.6. Use of Tank Off -gas Recovery Systems 12-16 12.72. Step 2 —Eliminate Technically Infeasible Options 12-17 12.7.3. Step 3 —Rank Remaining Control Technologies by Control Effectiveness 12-17 12.7.4. Step 4 —Evaluate Most Effective Control Options 12-17 12.7.5. Step 5 —Select BACT for the RTO 12-17 12.8. Amine Unit (Indirect Emissions - RTO) 12-18 12.8.1. Step 1 —Identify All Available Control Technologies 12-18 12.8.1.1. Carbon Capture and Sequestration 12-18 12.8.1.2. Proper RTO Design, Operation, and Maintenance 12-18 12.8.1.3. Fuel Selection 12-18 12.8.1.4. Good Combustion, Operating, and Maintenance Practices 12-18 12.8.2. Step 2 —Eliminate Technically Infeasible Options 12-18 12.8.3. Step 3 —Rank Remaining Control Technologies by Control Effectiveness 12-18 12.8.4. Step 4 —Evaluate Most Effective Control Options 12-19 12.8.5. Step 5 —Select BACT for the RTO 12-19 12.9. Combustion Turbine 12-20 12.9.1. Step 1 —Identify All Available Control Technologies 12-20 12.9.1.1. Carbon Capture and Sequestration 12-20 12.9.1.2. Selection of Efficient Combustion Turbine 12-21 12.9.1.3. Fuel Selection 12-21 12.9.1.4. Good Combustion, Operating, and Maintenance Practices 12-21 12.9.2. Step 2 —Eliminate Technically Infeasible Options 12-21 12.9.3. Step 3 — Rank Remaining Control Technologies by Control Effectiveness 12-21 12.9.4. Step 4 —Evaluate Most Effective Control Options 12-21 12.9.5. Step 5 —Select BACT for the Combustion Turbines 12-21 12.10. Hot Oil Heater 12-22 12.10.1. Step I —Identify All Available Control Technologies 12-22 12.10.1.1. Carbon Capture and Sequestration 12-22 12.10.1.2. Fuel Selection 12-23 12.10.1.3. Good Combustion, Operating, and Maintenance Practices 12-23 12.10.1.4. Heat Integration 12-23 12.10.1.5. Efficient Heater Design 12-23 12.10.2. Step 2 —Eliminate Technically Infeasible Options 12-23 12.10.2.1. Carbon Capture and Sequestration 12-24 12.10.3. Step 3 —Rank Remaining Control Technologies by Control Effectiveness 12-24 12.10.4. Step 4 —Evaluate Most Effective of Control Options 12-24 12.10.5. Step 5 —Select BACT for the Process Heater 12-24 12.11. Emergency Flare 12-25 12.11.1. Step 1 —Identify All Available Control Technologies 12-25 12.11.1.1. Carbon Capture and Sequestration 12-25 12.11.1.2. Fuel Selection 12-25 12.11.1.3. Flare Gas Recovery 12-26 12.11.1.4. Good Combustion, Operating, and Maintenance Practices 12-26 DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants iii 12.11.1.5. Good Flare Design 12-26 12.11.1.6. Limited Vent Gas Releases to Flare 12-26 12.11.2. Step 2 -Eliminate Technically Infeasible Options 12-26 12.11.2.1. Carbon Capture and Sequestration 12-26 12.11.2.2. Flare Gas Recovery 12-26 12.11.3. Step 3 -Rank Remaining Control Technologies by Control Effectiveness 12-27 12.11.4. Step 4 -Evaluate Most Effective Control Options 12-27 12.11.5. Step 5 -Select BACT for the Flare 12-27 12.12. Fugitive Components 12-27 12.12.1. Step 1 - Identify All Available Control Technologies 12-27 12.12.1.1. Leakless Technology Components 12-28 12.12.1.2. LDAR Programs 12-28 12.12.1.3. Alternative Monitoring Program 12-28 12.12.1.4. AVO Monitoring Program 12-28 12.12.1.5. High Quality Components 12-28 12.12.2. Step 2 - Eliminate Technically Infeasible Options 12-28 12.12.3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness 12-29 12.12.3.1. LDAR Programs 12-29 12.12.3.2. Alternative Monitoring Program 12-29 12.12.3.3. AVO Monitoring Program 12-29 12.12.3.4. High Quality Components 12-29 12.12.4. Step 4 - Evaluate Most Effective Control Options 12-29 12.12.5. Step 5 - Select BACT for Fugitive Emissions 12-29 12.13. Condensate Storage Tanks 12-30 12.14. Truck Loading 12-30 APPENDIX A. MANUFACTURER SPECIFICATIONS APPENDIX B. GREENHOUSE GAS BACT SUPPORTING INFORMATION DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants iv LIST OF TABLES Table 1-1. Criteria Pollutant Emission Summary Table 1-2. Hazardous Air Pollutant Emission Summary Table 1-3. Greenhouse Gas Emission Summary Table 1-4. Site -Wide Emission Summary for PSD Applicability Table 5-1 Greenhouse Gas Global Warming Potentials Table 5-2. Turbine GHG Emission Factors Table 11-1. Potentially Applicable NSPS Subparts Table 11-2. Heaters Potentially Subject to NSPS Subpart Dc Table 11-3 Potentially Applicable MACT Subparts Table 11-4. TEG Dehydrators Potentially Subject to MACT Subpart HH Table 12-1. Potential GHG BACT Limits for Lucerne 2 Expansion DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants v 1-4 1-5 1-6 1-7 5-1 5-2 11-2 11-3 11-6 11-6 12-9 1. EXECUTIVE SUMMARY DCP Midstream LP (DCP) owns and operates the Lucerne Natural Gas Processing Plant, located at 31495 Weld County Road 43, Weld County, Colorado. DCP is proposing to expand the Lucerne Plant (Lucerne). The Lucerne Plant operates under Operating Permit 950PWE100 issued by the Colorado Department of Public Health and Environment (CDPHE), Air Pollutant Control Division (APCD), on November 1, 1998, which was most recently reissued on April 1, 2008 and revised on April 1, 2010. A renewal of the Title V permit was submitted on March 30, 2012. The primary Standard Industrial Classification code of the current Lucerne Plant is 1321 (Natural Gas Liquids). A portion of Weld County is designated as nonattainment for the 8 -hr ozone standard and attainment or unclassifiable for all other criteria pollutants. The Lucerne Plant is an existing major source with respect to Nonattainment New Source Review (NNSR) for emissions of nitrogen oxides (N0x) and volatile organic compounds (VOC) as precursors to ozone. The existing Lucerne Plant is an existing minor source for NOR, sulfur dioxide (SO2), carbon monoxide (CO), particulate matter (PM), particulate matter with an aerodynamic diameter of 10 microns or less (PM10), and particulate matter with an aerodynamic diameter of 2.5 microns or less (PM2.$) with respect to the Prevention of Significant Deterioration (PSD) rules.1 The facility is also an existing minor source for greenhouse gas (GHG) emissions under the Tailoring Rule. 1.1. PROPOSED PROJECT The Lucerne 2 Expansion will be designed to process up to 230 million MMscfd of sweet natural gas. The Lucerne 2 Expansion will consist of inlet separation facilities, two turbines, an amine treating unit, a glycol dehydration unit, condensate tanks, and supporting equipment. The main processes at the Lucerne 2 Expansion will include the following: > Inlet separation facilities; > Removal of carbon dioxide (CO2) and hydrogen sulfide (H2S) from natural gas through amine treating; > Removal of water from natural gas through glycol dehydration; > Compression of natural gas by electric -driven compressors; • Pipeline loading of high-pressure condensate liquids ; and • Truck loading of low-pressure condensate and produced water liquids. The proposed Lucerne 2 Expansion will include the following emissions sources: > Two gas -fired combustion turbines (IDs TURB-1, TURB-2); > One natural gas heater (ID HT -02); > One amine treating unit (ID AU -02); > One TEG dehydrator (ID D-01); > Four condensate tanks (ID TANKS); • Truck loading from tanks (ID LOAD); > Fugitive emissions for Lucerne 2 (ID FUG2)2; and > One emergency flare for maintenance and emergency activities. The Lucerne Plant is located in Weld County, which is nonattainment for ozone and attainment/unclassifiable for all other criteria pollutants including NOx. As such, as precursors to ozone formation, VOC and NOx emissions from the proposed project are subject to nonattainment new source review evaluation and NOx emissions from the project are subject to PSD evaluation. 2 Note that the Site -wide Fugitive emissions provided in this application includes only the proposed project. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 1-1 A detailed process description is included in Section 9 of this permit application. 1.2. PERMITTING CONSIDERATIONS DCP is proposing to expand the current Lucerne Plant in order to increase the natural gas processing capacity. The proposed expansion herein referred to as the Lucerne 2 Expansion, will add 230 million standard cubic feet per day (MMscfd) of additional processing capacity to process the rapidly growing gas volumes that are being developed in this area. The proposed Lucerne 2 Expansion will be a separate operation from the existing Lucerne Plant operations. Lucerne is currently a 40 MMscfd capacity natural gas processing plant. In February 2010, DCP installed a 40 MMscfd amine treater to remove carbon dioxide (CO2) from the natural gas liquids (NGL) in order to obtain a higher recovery of NGL product and meet required pipeline CO2 specifications. The capacity of the existing amine treater exactly matches the existing Lucerne plant capacity and is capable of supporting the existing plant only. The proposed Lucerne 2 Expansion will have a separate amine treater with 230 MMscfd processing capacity. The existing 40 MMscfd amine treater will not support the Lucerne 2 Expansion in any way. In addition, the purpose of the proposed project is unrelated to the goal of the 2010 amine treater project. Therefore, the two projects are separate for applicability under NNSR and PSD and this application addresses NNSR and PSD applicability for the Lucerne 2 Expansion Project only. 1.2.1. Nonattainment New Source Review The Lucerne 2 Expansion will be located near Greeley in Weld County, Colorado. Weld County is currently classified as nonattainment for the 8 -hr ozone standard and attainment/unclassified for all criteria pollutants.3 Since the existing Lucerne facility is considered a major source under the NNSR program with emissions of NOx and VOC exceeding the 100 tpy major source threshold, the emissions from the Lucerne 2 Expansion were compared to the Significant Emission Rates (SERs; i.e., 100 tpy for NOx and VOC) to determine if NNSR is required. As shown in Table 1-4 at the end of this section, the proposed modification will not result in emissions above the respective SERs and therefore, the project will not trigger NNSR for NOx or VOC. As shown in Table 1-4, the combined existing and proposed Lucerne 2 Expansion emissions will exceed the carbon monoxide (CO) and GHG PSD major source thresholds of 250 tpy and 100,000 tpy, respectively. Therefore, once the proposed Lucerne 2 Expansion project is in operation, the site will be considered a major source under the PSD program. DCP is submitting this PSD permit application to authorize GHG emissions from the proposed modification at Lucerne. 1.2.2. Prevention of Significant Deterioration PSD regulations define a stationary source as a major source if it emits or has the potential to emit (PTE) either of the following: ® 250 tons per year (tpy) or more of any PSD pollutant; or ® 100 tpy or more of any PSD pollutant and the facility belongs to one of the 28 listed PSD major facility categories. The Lucerne Plant is a Natural Gas Liquids facility and is not one of the 28 Listed PSD major facility categories; therefore, the major source threshold for non-GHG regulated pollutants is 250 tpy. As shown in Table 1-3, the 3 Per 40 CFR §81.306. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 1-2 proposed Lucerne 2 Expansion project emissions will exceed the carbon dioxide equivalent (CO2e) GHG PSD major source threshold of 100,000 tpy CO2e. According to EPA guidance, the "major for one, major for all" PSD policy applies to GHGs for any project occurring on or after July 1, 2011. Therefore, if a site is major for GHGs only, then the criteria pollutant emissions need to be compared to the Significant Emission Rates (SERs; i.e., 40 tpy for NOx, 5O2 and VOC, 100 tpy for CO, 25 tpy for PM, 15 tpy for PM10, and 10 tpy for PM2.$) when determining PSD applicability for these pollutants. Based on emissions estimates documented in Table 1-4, the Lucerne 2 Expansion will not result in emissions of non-GHG emissions above the respective SERs. Therefore, the project will require a PSD review for GHGs only and the project is not subject to PSD review for NOx, 5O2, VOC, CO, PM, PM10, and PM2.s• 13. PERMIT APPLICATION This permit application was prepared in accordance with CDPHE APCD Regulation 3, Part D and Oil and Gas Division guidance. This application includes the following: 9 Construction Permit Application Completeness Checklist (Form APCD-100), • Attachment A - APEN Filing Fees, > Attachment B - Equipment Specific Air Pollutant Emissions Notice (APEN) forms (Form Series 200), > Attachment C - Emission Calculations and Supporting Documentation, • Attachment D - Company Contact Information form (APCD-101), > Attachment E - Ambient Air Impact Analysis, > Attachment F - Facility Wide Emissions Inventory form (APCD-102), 9 Attachment G - Process description, process flow diagram and plot plan, > Attachment H - Operating & Maintenance plan form (Form Series 300), Attachment I - Regulatory Analysis, and > Attachment J - Best Available Control Technology (BACT) evaluation DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 1-3 Table 1-1 Criteria Pollutant Emission Summary Controlled Annual Emissions (tpy) VI O u pp I Lucerne 2 Expansion M M 0 CO as N MD CO Cr) M M T M M CO M O O O M r-:0 0 0 O O , M En !M7 O SH 12.57 ,..r co CO Oh 0 0 0 ii, .-I O M O O O W W, W' ' LA �' It -- ,4 r-1 O' I 33.76 1/1 N a 7.96 O Q CO i i i CV Ni C M d' O O W W 1 O i { o s C tV .4 O to i ry CI IN: 0 0 CO I 1 i I , tV N O M d' O C7 r-4 O� W i r:::1 • i I O s o N H N O vi PM % O a r-1 `'I CO i i i i i Ni N C M d' C . i 0 CO i O ' i O N O tV e-1 N d tf VOC OJ II? N s o co ,c, co Q, N M M N C C G N N M d' M Cr W 9 th O W D CO N O cr, O 0• 52.22 Co H Cr) N r1 kr-t$D M N CI CO C N N N O O •• e,-1 ,_r N O C O on N O • i O O .--1 N LN XON Tr M o N O O co to Oai O O , 7, Li, C •C o •C M C en fi3 �s� C M C CV CA M Description I Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2)__ Is Insignificant Activities Enclosed Combustor Pilot RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions Table 1-2. Hazardous Air Pollutant Emission Summary Annual Emissions (tpy) Total O M Q, 'Lucerne2 Expansion I CO CO O CO Q. N. l.7 CO M M M T M M M M O O O M2, 0 0 0 .. .-$ :0 .-+ r a a O 1 M H O W N N 1224-TMP O O r 1 r I r 1 „ , i, r 1 O Methanol ON In r 1 , , , 1 , 1 r 1 r r 1 , 4.59 d 2.43 I = co n m co r+ t\ t` in M CO O k O z co O J N O COc-1 .-I M a a a a a r , [ O : O : 0 a CO (+j Acetaldehyde Acrolein co co co O O O O in LU CO I in O et' Ui a 0 0 LV N r p el' • 0 '-I e-1 O O r r., i. O O 0.03 so to O 0 in co CO .-1 N N O 1 I r I r 0.46 ,-I CO Um .y, .--i O O O ei v G 61 M .-1 co N N O. O L. h. •O O O r O M co co Q ' II) O . r rr2J 1 r • L` in ON �O k O a a co 0 co O ti co LJ] C C E -Benzene 0.02 co M co to 0.24 .--i .-r 0 0 co O N 0 0 : O .--1 O S O 0 0 O 0 N .d. O I.t . r I p0 N O Toluene d' d' 3.72 4.00 CO N O O d' cl. < M N O, O. .-.--I O O t N N O 0 0 O O cr., .-I N O O O ul O r . I 1 '..$1 n Benzene 0.52 M M d M Lit Liz L:] 1JN7 V' O O O m O0 Ly N co 0 0 co ; hl r co ; c O N LO .D C) M M .-i Description 'Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fu 'fives ID FUG2 Insignificant Activities Enclosed Combustor Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions I Post Modification Total Emissions' Table 1-3. Greenhouse Gas Emission Summary Annual Emissions (tpy) CU N O N. O Lucerne 2 Expansion riri�o�N CO 0O CO on O N N N on M N N O N uj e N c.l 00 n N a N NON e co • N M „,r4 N CC in N N z 0 0 d, a+ CO 0 0 M �' 6 0a `2, N e 0 N n d rl ' N VD CO 0 0 0 W W W N co <i' P N rl tf] v] ce5 H O N ry CH4 C Ci O M ti rn 0 0 ri o 1 dN' a ‘,1' 1.0 O O W W .1-I e U] U CO N M CO N O V iV CO C M 0 N e 0O hCD 0 m ON • N M N 0 N C Na- a d' N ti N n N el r 'tri O `n [V e M N N e•1 `~ ey N Description Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) Inisignificant Activities Enclosed Combustor Pilot RTO Pilot Emergency Flare Total Modification Emissions Table 1-4. Site -Wide Emission Summary for PSD Applicability Annual Emissions (tpy) -_ I o v N. O N m Lucerne 2 Expansion mi a' O N CA co o6 \OVIM '• N NI, N N d. �' N N N N 31.45 2.81 235.51 W M M N N O I 12.57 CO W Os .-I O O O !n , 1 m 1.58E-04 1.41E-05 9.76E-04 33.8 nj 0 O O 2.00E-03 1.78E-04 1.24E-02 5.0 at-: NN O • 1 1 1 • .., sr)O O .-I 2.00E-03 1.78E-04 1.24E-02 xa.m 1 , . C CU G7 N N O co PM M d' N O co O O ti N H co 1, 1 0 O a W W W O IN i N N O 0 0 a. o n N t0 N r1 .-1 VOC CD CO N N` U CN O H 1.45E-03 1.29E-04 8.95E-03 33.1 O O ,..0 CO T M CO O o 0 \O N N N CO on 0 ,y 1/40 MD N N 0s m QO N N O O O N,% V O .-' M G.,j N ,�., N ,, N o 0 0 0 Us o .1 try "ON M 37.7 N N O O W tOC) Off+ 0 0 O O W .�-. .M-4 �o ,"-Uiooao ocr)o N Description Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) I Insignificant Activities (Non -fugitive) Enclosed Combustor Pilot RTO Pilot Emergency Flare I Total Modification Emissions Comparison to PSD/NNSR Limits 1'2 0 O O O NO NO NO NO NO NO YES 0 0 O 143 N O O O Ni ..d. z. I, N. co , O r., to O z z . . O N ' • In N Q z • • O o N w O 't a O Z O o N 0 Z N. . Oml Z 0 CD CA C0 Prevention of Significant Deterioration (PSD Major Source Threshold Is the Project above PSD major source threshold? Nonattainment New Source Review (NNSR) Limits Is the site above NNSR limits? 1 PSD Significant Emission Rates (SER) a,a I Is the project above PSD SERs? INNSR SER ~ 's Is the project above NNSR SERB? Lam) L., O V d a .xl a) co a a) C O O O O 0 7 L • y) • m E a o p., N a) E ra C C• iv > • a) OV)) • y. W ' O X z • EO E • F T OX • z C • 1" o c� y b 7,8 U V Gy 1� • E u F 2 C -a C) N 3 N U N N a w U 0 a) U C vi co op O a cc ciJ z z b co 0 G O A u d CC O z 0 C O Z7) E 63 0 a) X 0 z d R A c9 crr .) a) C CID a) 0 0 w E 0 c0 c). o.) u a) O a 0 a c0 a a) 0 0 O a ra lb 0 0 O N N .I- a C 0 C O O E C la a W a C] U O 0 cc V N O N C O ru E d Co) C 0 0 co▪ l 0. 2. FORM APCD-100 Oil and Gas Industry Construction Permit Application Completeness Checklist DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 2-1 Form APCD-100 Colorado Department of Public Health and Environment Air Pollution Control Division Oil & Gas Industry Construction Permit Application Completeness Checklist Company Name: Source Name: Date: Ver. September 28, 2009 DCP Midstream, L.P. Colorado Department of Public i Health andEsmieonirient Lucerne Natural Gas Processing Plant - Lucerne 2 Expansion October 03, 2013 Are you requesting a facility wide permit for multiple emissions points? Yes No ❑ In order to have a complete application, the following attachments must be provided, unless stated otherwise. If application is incomplete, it will be returned to sender and filing fees will not be refunded. Attachment Application Element Applicant APCD A APEN Filing Fees 11 ❑ B Air Pollutant Emission Notice(s) (APENs) & Application(s) for Construction Permit(s) — APCD Form Series 200 ❑ C Emissions Calculations and Supporting Documentation 0/ ❑ D Company Contact Information - Form APCD-101 ►1 ❑ E Ambient Air Impact Analysis l ❑ il Check here if source emits only VOC (Attachment E not required) F Facility Emissions Inventory — Form APCD-102 ❑ Check here if single emissions point source (Attachment F not required) a ❑ G Process description, flow diagram and plot plan of emissions unit and/or facility ❑ Check here if single emissions point source (Attachment G not required) ❑ H Operating & Maintenance (O&M) Plan — APCD Form Series 300 ❑ Check here if true minor emissions source or application is for a general permit (Attachment H not required) V ❑ I Regulatory Analysis ❑ Check here to request APCD to complete regulatory analysis (Attachment I not required) A ❑ J Colorado Oil and Gas Conservation Commission (COGCC) 805 Series Rule Requirements— Form APCD-105 here if is COGCC 805 Series ❑ ❑ ri Check source not subject to requirements (Attachment J not required) Send Complete Application to: Colorado Department of Public Health & Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Check box if facility is an existing Title V source: ® Send an additional application copy Check box if refined modeling analysis included: n Send an additional application copy Page 1 of 1FonnAPCD-100-AppCompleteChecklist-Ver.9-28-2009 v1.3 (Oct 2013) 3. ATTACHMENT A - APEN FILING FEES DCP Midstream LP i Lucerne 2 Expansion Trinity Consultants 3-1 4e ATTACHMENT B — APCD FORM SERIES 200 Air Pollution Emission Notice (APEN) Forms This section contains APEN Forms for the following units: 9 Two gas -fired combustion turbines (IDs TURB-1, TURB-2); • One natural gas heater (ID HT -02); > One amine treating unit (ID AU -02); 9 One TEG dehydrator (ID D-01); • Four condensate tanks (ID TANKS); 9 Truck loading from tanks (ID LOAD); and > Fugitive emissions for Lucerne 2 (ID FUG2). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 4-1 C �4 Oea [Leait blank unkess.APCD:has ul Permit Number: .. 0-16 a o �. m 3+ `fir Fs f -:g L.C p c a :g t '�. .., .., 5 " .. 4 ' a a a 0 0 Section pi — Administrative Information C)CP Midstream, LP M a 9~' LL 3 Q 0 -r. PTA CS. 8 0 a CA E 0 0 a. N bone Number: 303-605-1745 Dana Stephens I 303-605-1957 z M O' the projectedstartup date is: v le c 0.0 L C. C a w q .1 a C P%. R .. 4 o n L C o C Q < •0 g' 2 UC C •r CpE lo IJ ✓+ c u v C SY 45.4) 4.1 ti: 0. 0 Tt , Q 0 0' .,,..0'0 w <r,M <Q C 0 M j z 0 ion & Mate C 04 — Processi 0 i Manufacturer: 4) .115 nQ h . . 8 L C• 0 ,0. H g Q 4 o R. u ® El N 0 FORM APCD-200 n C 0 0 1.4 0 A M 0 a 0 N1 to 0 0 O 40 z U 2 W A U itt O z z Qto 4c; W.5. H <8 I— o 7 cvi III 0_ cc W QE2 0 N O 123/0107/044 0 .12 z a Permit Number: DCP Midstream, LP Company Name: s - m CO CO d) O U O, N County: Weld 31495 Weld County Road 43 Plant Location: midstream.co a) E-mail Address: Controlled Actual Emissions (lbs/year) N to Tr Uncontrolled Actual Emissions (lbs/year) b' Factor Source AP -42 Section 3.1 Emission Factor (Include Units) 7.10E-4 lb/MM Btu Control Equipment/ Reduction (%) z rn c Qm v a Chemical Name Formaldehyde Chemical Abstract Service (CAS) Number Q 0 0 0 M O N Reporting Scenario Dana Stephens ca m Q. z O 4) 0 0 a. 0) C� 0- 4••••• a) I - LO O ti O 0 0 has already assigned"apermii # & AIRS. 1O1 [Leave blank unless a. a • 0 ►.1 DCP Midstream.U' Company Name: U G 0 Ci O a o r ❑ ❑ ❑ ❑ ion Lucerne. Natural Gas z a U .31495 Weld'County.it Source Location: b s ak U 7 PersonTQ Contact: Fax Number: :303-605-1957 .sources, the projected startupdate is 0 U E k4O, w4O c9 a O 0 z U a W V L C) U • 8• a' 8 .4 5. O. fa ~ O •�'y 4 044 8. O O 0r O 0 ae x • .S o • o ® ED N C) 2 FORM APCD-200 O .01 0 0 O 0 a M 'fi O n U a p N 0 m N 4 cJ N Permit Number: DCP Midstream, LP Company Name: cr) CO 0 co ai 0 U 0_ N County: Weld M Cti 0 c C O 0 Plant Location: Dana Stephens Person to Contact: midstream.com C) U) C a) L U) "O E-mail Address: Controlled Actual Emissions (lbs/year) CNI L Uncontrolled Actual Emissions (lbs/year) N LI) Emission Factor Source AP -42 Section 3.1 Emission Factor (Include Units) w°0 ci r: .0 Control Equipment / Reduction (%) Q z Reporting BIN Chemical Name Formaldehyde Chemical Abstract Service (CAS) Number o O 9 O LI) Calendar Year for which Actual Data Applies T"" Reporting Scenario (1, 2 or 3): is as a. a. O 0 N '"C -C 4- 0) v c i v a. 0 4- a) C 0) Co Dana Stephens ca O a. a. 0 v N .C 0 Q lU 0) 0 L a) 0 0 v c a) N tQ a) ca a a. 0 N O • N -C < : ?+ E • U a)O G N U) a) c a. .O 11 Q (≥, a) ix E E z lL� rTa SOO Q 0 O C/} a N- O O 12WE2024 Permit Number: Facility Equipment ID: HT -02 Section 02 — Requested Action (check applicable request boxes) Section 01 - Administrative Information Request PORTABLE source permit Transfer of ownership Change permit limit Request to limit HAPs with a Federally enforceable limit on PTE m a 0 as a 0. a ❑ ❑ ❑ ❑ Lucerne Natural Gas Processing Plant as z m 0 N 31495 Weld County Road 43 0 O C) CO r o O 00 V N ❑ ❑ Phone Number: dstephens@dcpmidstream.com Section 03 — General Information M N u d e 'C O oo rn E a O is M c"r M IZ At ' M N N N .a i. t 4) O O O b ,� w o 000 . u w co v C) TO 0. L.... = N rb a v O U v .. '; t> . O G. O C. d. > y' i > c '5 c; C M O A a aG. :2 )N6 of Yy3 c > U L4 E L N L C Q yoEo�U gun mo�o a 8 a e4Uu of a y— .- 0 L) 4 a 04 a, W t'� 2UQvcz 4 w drn APEN forms: U o O O 5 ment Information & Material Use /Manufacturin Section 04 — Processin • ° cn O z 7 pA A :U - z 0 f '4 z C,, 0 a" U 0 II tt U5 for to public notice. FINAL GeneralAPET1 Hot Oil Heater (11T -02) _v'2 N ao O aJ as FORM APCD-200 0 O R V A N- U o O co) N � r O C) cat O U V C Q W 4 H O z O W E.* N L1A a O CID Emission Source Permit Number: Lion information went & Fuel Consum Section 06 — Combustion E r. tn E 0 C C C O Fci L 0 0 W 0 5 0 C G C, 8 r O 0 Ct ci a' D 9 eCi N N 0. N 0 0 0 0 0 x 0 O ci O c P 9 c. W w Q C ci o n 0 .Yea. u Cc w 0 a 0 0 ) C O V c .R N o.' y a a N 0 n W a Ol 0 O y, Q 0 O N C. C. N 0 0 a a 0 a 0 0 CO U G w44.0 C V 0 a cia ciAi y L C) CJ u S. Cat 0 C c c 0. a K G d G a 0 n E: 07, 73 L. 0 a;4. _ yea O '0 p N' E a z'. L u .G b `laC. u 4 z m F4 .ration for Construction Permit — Amine Y 0 1inission Source. AIRS ID: a:permit# .AIRS ID] Permit Number: jP'rovideFoOlity. quipmeut.IDtioidentifyhow.thisequip:pentis.rckettcedwithinyourorgaaixatio.n Facility Equipment 1D: AU -02 (Check applicable request boxes) 0 u Ci Section 01— Administrative information permit or newly reported emission source 0 r* . t a a 2 flU U o 0 w .a 1DO >,. n .0 0 z . '5 a . O 3 0 g o . i v �. O rz 00 w 41 ti 2 Q :j a a.+ e gw000 ® ❑ DO DCl' ,Midstream,.) p c g. Lucerne Natural Gas Processing Pla a g' 0 t� Ea N 370 17th St, Suite 2500 Phone Number: Dana Stephens Person To Co c8 A C A a E-mail Address: Section 03 — Coneral_Information 011 N the .proje r 5 0 ❑ ❑ :J J r C C v I 12 4 a� a _ 01 C oU a 0 1O42 8a Q ,3. 0 e Q m' h 2 w 0 . a7 • • r -, o E. a o C '. a ,, N. 0 01 c 8 1 On to 2 44 'a In 4 ws QQL A'1 Y .k y 4 C 4.a a m t E0„ ga ..c) 8 c. � o ri6Vv iaA c471.:c1 Y C a a:� ,4a ii E yyA 0 0 V.. 8. C J 2.2 .1:4 v A 5 ®0 ent informati Manufacturer: N v L) A .8 .8 E 2 L4 .3i tot 8 0 a 00 a N C' a� Q rs Mole .loading CO2: 0 .,C eq O fl :as NM A .9 o. R In C' 3 / 8. .CT. 4. 0 tr. c . w :4 U - z tir • C) 00x g -OA 9 1,7 dO 4n CS Y. } On • a:e �W :ti 1 3 s x,0.0 add. EMI ❑ ❑ Kr r- u )e listed h r tlT Y 'd y CC. Vt C n v N G 4 4 a c J C ‘i' N N �- C O. b r ^' 2.47 I M it C 0 cd. u.. G 0 v G sr .0 G I a 9 = 0 . m a a w tr. ` '_' 2 q; I.. r u .Q SI ' �:.. V' O 24O 4� F O n• n Ott O O C O N. O b o O 'X fl a: 3 iii }'ti't ei,'ii p t"` �_____ _ Please use the APCU .p€tkfrF Qg� SY-"xr2 q Ski .: �`� yjith N' Rai h F: c v y J N X H N O bit 0 2 W 0 O W Z o � GO"; W ZE Q U r Q .1 43 o � a� W u J Q ,3 H LLB O CL LLI cc tL tY. 12WE2024 (AU -02) DCP Midstream, LP C, O co a) 73 O C-) C. N County: Weld 31495 Weld County Road 43 Plant Location: Dana Stephens Person to Contact: dstephens@dcpmidstream.com E-mail Address: Uncontrolled Actual Controlled Actual Emissions (lbs/year) Emissions (lbs/year) 63,020 63,020 00 co cl v v M 7 -Emission Factor Source 0 0 LOCCCU m CD vi 0 al� 15 m Emission Factor (Include Units) rib.75 007 /MMscf 0.4159 lb/MMscf (uncontrolled) Control Equipment / Reduction (%) Still Vent - RTO 1 96% Flash — Flare 95% o C o.. e .0 ce Chemical Name Sulfur dioxide Hydrogen Sulfide Chemical Abstract Service (CAS) Number c[s c� 9 4 r- et co o C ti Calendar Year for which Actual Data Applies: Reporting Scenario (1, 2 or 3): a) C) c6 c as C) a) a. Q U) a) al O • cr co c) Q 0. O. 0 73 0 L • .c (n N c c c m (00 co co O Q. O. O C/) 0 N O s U) a a)) J C 0 U) a) _a) a 0. U) co t_ as i 0 a. a VJ O N a 5 a (s C) C O CO a) 0 0 E co z Form Revision Date: December 4. 2006 CO A 1'••• O a i.D fo U E. o o qt n: III az r� y 52 a N a w N P Emission Source AIRS ID: 123 2 ad g cs Z cal .0d AN AN Ls. (Check applicable request boxes) C, Y> 1IEi1F e. gi4 .� 1 • as u 42 _ a a . 13 ' -a a ., ''1''` Sa. .d. vi y I~. ya I: _a g .0 0�:'".• S0 E dI: I'C' D L a C is U 6, 40 4 7 a. ❑ ❑ .�w' U NC0 . 4 a E w a « o. lC .rG 3 o 0' " t3 p] E C '6 is 'v. .m 0'1., a L G. O. . V. ..O V .3 3 w3a. Ems' ?; v °' > .� a II! 40 e .❑Oa a0 D zl 24z d ion 01 —. Admini sos r L O) UU c z. OCP Midstream, LP Qd U z a, O 3•149S Weld:County Road 43 0 37017th St, Suite 2500 a a I. au c E-mail Address: M_ A 3 a CUJ) tta a U W Z Z 7 r ® ❑ z� a --a(( >, ts i. D ^I 0 d lg v .c p. O' c 0 . a fl IA Er a s o ry 2 z r', y ,.. a y 0„ .z a g t g U C g O . �o � + U C ' ,,j Q U aka '.0 c o E a . f s�� w c. o ,o O 2 I a 0 x: Is this unit lot,E 6 A •:• a a a sa a •y F 7R U b L 1 a04.0 • R. �. U p 0 QE a P*g E'• U v w r-4 ( V N a y 10 b VJ M[ten c•'7 4 x9MM C g O zz y U U 4) O O ❑ '8 :y. 6• . U 8 8 2 5'Ei W ga o a. U 8 U, coo o N a, 3 D4' 4 0 0 0 m E- 0 It g � � CI El woo a o. 0 O C 0. a 'E. 'E. ►�1 0) Op Q*. .R 4 A <g [r'9 L y yE a O a _ N O Ct Chi C4 z s ® M❑ r C r 'it 24 4ew.ed .5 APEN TEG 0D -O gp 0.; Pr CD T' 0 N of - Emission Source AIRS ID: Permit Number: v P. E C3 2 ® v a O V o, rti �i .» Th 44, o Co Make/Model/Serial #: Manuta Requested: :95 U Liz 0 .99 cot cft E L it 47. 1G a .4O Let rC O c C .14 E t Ct Q w 15 5 g Li ca Section 08 . Emissions. Inventory information & Emission Control Information }• I. stitati;tn Method or Eintsion Factor otuce AP -42 Section 1.4 GlyCalc AP -42 Section 1,4 fir, Please use the APCD•.Non-Criteria Reportable Air Pollutant Addendum form to r�rt pollutants not listed above. e € J ., * v J t°Jncontn�lied 4-.. 74 J. 7 C.) ! n M t � 1 4. . 4 7 I N x 7..' V N {. 2 2!Z2F *i,rc y 2 OR . U 2 �� Vi 2 • v ... © 0 Q arol [)ctike Description Control fccncy Prima } Sc nndz rti (° , itt:ctuciiert) = Identify in Section 07 LC u WC Q Et g b .G • • go 4:+ E FINAL (3lycotDehydratorA,PENJEG (D-01) c1 )r Construction Permit O (L) (.Leave blank unless APCDhas already assigned a permit k: & AIRS ID] [provide Facility Equipment ID to identify bow this equipment is referenced within your 03 (Check applicable request boxes) Section 02 — E A C) C. C. CO o Cp A O' o C) i 13.1 44 atti 1 ;ff K v 00. a d k. .G o air G) v sto s C 00 I U go go {r? V ❑ ❑ S•, e ii t C ;1 i• 0 a - �; 1 C A o o'tin' D . V t. 4.0 ek 0Z, . :? V VI 3 s 0 'a .a I.. al g ;g . 0 wA .o 4.2: v. Q o yA .y R 40 Cle ®0 CO :RCP Midstream, LP z :Lucerne Natural Gas Processing Plant 31495 Weld County Road 43 i g a a rA Mailing Address: *Stabilized condensate therefore the gas to oil ratio will be very D ❑ v Phone Number: CO C ed Person To Contact: dstephens@dcpmi 2 w Section 03 General information �o a a C.. Normal Hours. 0 0 0 0 O ZZZZ E101:210 C) c) >4>4›*�C > D 0 plete this. APEN form: as ' i+' eni, � '. M' Men C rn O een n S s x il ti E 0 ^. a1 r- '6. s. A in• C• in t.• ?..: 0 a . - ; x S0 t..I 8. • �.o S 0 E Ai n 2 A3) ir,.g. b . CI O n ci .. c .o X X C' O' u c g co g •4 d g S. . .2 . �'.uC.3 y,.oa a.a a Cy a E v C>7 ':9 a'. O ' 8. a. a - o ; 0 C 8 N w e P. •Os e g 0,0 v • V. 0 '� .0 _ w t ,„ J AAA A I C 8 q a .zrAH FH C' . .0 AAA d•E� g. C 2 "03 'g 3 VC O . E c U C Q G b E5 C E C es O. G FINAL Condensate Tanks APEN_v2 Estimation methad Emission £agtar Snurpe__._l AP -f2 Tanks 4.09d AP -42 ling. Est. uVl _. � ..., n a I (Y5 Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to reportpollutants not listed above. �� ^� N p 5£ C O C M fa O O C C p. O C M 4 W C G C .ryyr G+ V yh. O. . 63 4 CJ i"i u .0 u - ,0 '0 .C .c .0 a ^^.�. it. o ® •cas; OD c ® • tS� 4J S 5 c �{ Y ij v L> t ca C 1 t 0 O 52DS a O ' •. 2 jam„cg 0 .V� Ufl 0, 0 O a o .0 0 z W � U', 0 0 CY to Q O O iV a I19 W 40 8 Vs aV • (24 W14 c,41 k ►- el C7� Z z g 2 F.* tjj j Permit Number: is.icfrieucai within your organ izati [Provide Facility. Equipment ID to identity how this equ a fl Facility Equipment ID: ion (Checkappficabte.request boxes) Request for NEW permit or newly reported emission source ❑ ❑ Change processor equipment Change permit limit O Request to limit HAPs with a Federally enforceable llimit on PTE ❑ ❑❑ 4.1 8 CJ z Lucerne Natural 31495 Weld Cou 37017"' Street, Suite 2500 Phone Number 303-605-1745 Dana Stephens o ... Z z a o dy Ia (. N e a 8 u? Fax Ntirnber: 303-605-1957 E-mail Address: V J i i DDOOO ®O®DE OI to 1,4 V V 12 4.a ❑CONO U to e a m � c a 2.s oD. AU P. 4 •'o" Q tR 14 14".9 A 41 > , 4 4) a ° 4 B 44 .V Q v O R III 4) V V C 48 C: CZ' tea r 4.1 E t7 • 1 C 0 .O 0 53. w X A z a E u a N 9 Po t3 tooQ 0! 01,0 L w �u+ 4 u r o, w, ♦ r; 0 • z' G 0 FORM APCD-208 / O 40 O1 e O 4 n. i; E ti E al n. Q. 0 4. CI All d` c , an a. U a, M g ' ,UH y w aT o C M N P 4 C O C 4zS `O C 0 gtG . ark O 4O .O M.ry04 O C OA G'� Fes. t W ca c R m®a90 o:.:s .O d QWgDO 3 a oDo cc ii 8 d an o *r C a C V�:' S' hi�iEa'3kit Sk YIE a O 4 OO. C c w E p G FF v F u a .a E 3 0 U 41 'J cn O Source AIRS ID: it - ested Action (Check applicable recpicstboxes) ar C ministrative In w 0 0 a 0 -I a Fa .CQ °n V.*?l).o4C.g aljrC3� 0, 0 0' .Af a w. 0 -tai'....!w �. . 0 I: H e . C ac `- .K 0 C 4 I E❑❑ � y T 7 "0 Cal 0 s 02._ L. :Le p ra r. U 5 O ,.m 8.F=0� `h. 0: v a i0 La.S .y 4» Z. - �g. a a U U `i 11. 0 a ❑..0 flo `•C•l 74 w 0 ❑Ca._z U. O WI 5 z :DCP Midstream, LP Lucerne I!IaturalRas'Processing Pia Q. a• col Source -Locution: 2 0 0 w Phone Number: :303-6054745: Person To Contact 0 a I V ion .03 — Gene O a Brief description of 0 ai o a. a U . 4 Q •m: -g• co 8 4 at IA A U v H I ?.0 r• �n a SZ ais r+. :c U 0 0 y o m2. a c..to Do �� r. C A a et • G� pp q Q a U N • p y_y 1 a o.c4. a• < :n C? to In v� n rI fI. M 0 0.0. t„ ‘0 '0 '0: n T M Q O O 2 cfl vim` co 0 a. ❑ ❑ o z z z `4? 1 4)i cQ et E. a co a a•: z a a" b(4 §�4 O 8 .iv. El a Is this equipmentsubject. to NSPS 40 CFR Part.60, Subpart laK? Is this equipaient subject to NESIIAP 40 CFRPart 63; NSPS 0000 FORM APCD-203 Emission 12WE2024 0. e Datum and either Lat/Lono o n 06 —Location 5. ATTACHMENT C - EMISSION CALCULATIONS AND SUPPORTING DOCUMENTATION This section summarizes the criteria pollutant, hazardous air pollutant (HAP), and GHG emission calculation methodologies and provides emission calculations for the emission sources included in the proposed modification at the Lucerne Plant. Detailed emission calculation spreadsheets, including example calculations, are included at the end of this section. These emission estimates reflect the emission limits chosen as BACT in Section 12. The following emission units are included in the emission calculations provided at the end of this section: > Two gas -fired combustion turbines (IDs TURB-1, TURB-2); > One natural gas heater (ID HT -02); • One amine treating For unit (ID AU -02); • One TEG dehydrator (ID D-1); > Four condensate tanks (ID TANKS); • Truck loading from tanks (ID LOAD); and > Fugitive emissions for Lucerne 2 (ID FUG2). The operation of these sources will result in emissions of NOx, CO, SO2, PM, PM10, PM2s, VOC, HAP, carbon dioxide (CO2), methane (CH4), and nitrous oxide (NM). According to Title 40 of the Code of Federal Regulations (40 CFR) Section (§)52.21(b)(49)(ii), PSD applicability for GHG emissions are determined based on GHG emissions on a carbon dioxide equivalent basis (CO2e), as calculated by multiplying the mass of each of the six GHGs by the gas's associated global warming potential (GWP).4 The GWP for each GHG proposed to be emitted at the Lucerne 2 Expansion is listed in the following table. Table 5-1 Greenhouse Gas Global Warming Potentials CO2 CH4 ! N20 1 21 310 The following is an example calculation for hourly and annua CO2e emissions: CO2e Hourly Emission Rate lhr) = CO2 Hourly Emission Rate (lbhrlb) x CO2 GWP + CH4 Hourly Emission Rate (—hr ) x CH4 GWP lb + N20 Hourly Emission Rate (h1) x N20 GWP CO2e Annual Emission Rate ( tpy ) = CO2 Annual Emission Rate (tpy) x CO2 GWP + CH4 Annual Emission Rate (tpy) x CH4 GWP + N20 Annual Emission Rate (tpy) x N20 GWP 4 40 CFR Part 98, Subpart A, Table A-1. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-1 5.1. COMBUSTION TURBINES The proposed Lucerne 2 Expansion will include two Solar Taurus 70 turbines (ID: TURB-1 & TURB-2), each rated at 9,055 hp. The firing rate was converted from LHV (Lower Heating Value) into HHV (Higher Heating Value) HHV as HHV= LHV x 1.1. Combustion in the turbines will result in emissions of CO, NOx, PM (and variants), 502, VOC, HAP, and GHG. NOx and CO emissions in lb/hr are based on vendor guarantees.s VOC, PM, Mho, PM2.5, SO2, and HAPs emission factors are based on U.S. EPA AP -42 Section 3.1, Tables 3.1-2a and Table 3.1-3.6 CO2 emissions are calculated using worst case emissions from the engine exhaust analysis supplied by the vendor.? CH4 emissions in lb/hr are estimated based on vendor guarantees and on the conservative assumption that 100% of the unburned hydrocarbon (UHC) value consists of methane.s N20 emissions were estimated using emission factors from 40 CFR Part 98, Subpart C, Table C-1 and Table C-2 for natural gas as indicated in Table 5-2.8 Table 5-2. Turbine GHG Emission Factors Units CO2 CH4 N2O lb/hr 9,597 2.30 - kg/MMBtu - - 1.0E-04 lb/MMBtu * 2.2E-04 *Emission factors are converted from kilograms to pounds using the conversion factor 2.2046 lb/kg. Criteria pollutant, HAP and GHG emissions were calculated as follows: lb (MMBtu) Ib Hourly Emission Rate ( hr ) = Heat Input Rating 1 hr I x Emission Factor (MM Btu) lb Annual Emission Rate ( tpy) = Hourly Emission Rate (hr) x Hours of Operation (yr) x (2,0001bton ) 5.2. HEATER The Lucerne 2 Expansion will include installation of one new natural gas -fired heater: Hot Oil Heater (ID HT -02). Combustion of natural gas will result in NOx, CO, VOC, PM/PM4o/PM2.5, and 502, HAP emissions, and GHG emissions of CO2, CH4, and N20. The emission factor for NOx is based on a manufacturer guarantee; CO, VOC, PM/PMto/PM2.s, SO2 and individual HAP emission factors are obtained from U.S. EPA AP -42 Section 1.4, Tables 1.4-1, 1.4-2, 1.4-3, and 1.4-4.9 5 All vendor guarantee values are estimated at 100% load, relative humidity of 30% and temperature of 60 °F. 6 U.S. EPA AP -42 Section 3.1, Stationary Gas Turbines (April 2000). 7 C0z emissions were taken from engine exhaust analysis performed by Solar Turbines on May 8, 2013. Worst case emissions from ten runs was chosen. 9 40 CFR Subpart C, Tables C-1 and C-2. U.S. EPA AP -42 Section 1.4, Natural Gas Combustion from External Combustion Sources (July 1998). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-2 All emission factors obtained from AP -42 Section 1.4 are converted from lb/MMscf of natural gas fired to lb/MMBtu heat input by dividing the emission factor by the average natural gas heating value of 1,023 Btu/scf. The PM emission factor obtained from AP -42 Table 1.4-2 represents total PM (i.e., filterable plus condensable). Additionally, all PM is assumed to be less than 1.0 micrometer in diameter, according to AP -42 Table 1.4-2, footnote c. Therefore, the total PM emission factor is used to estimate total PM40 and total PM2.s. Hourly emission rates are based on the maximum heat input rating (MMBtu/hr) for the heater. DCP will limit the annual fuel consumption in the hot oil heater to 315 MMscf of natural gas. The following are example calculations for hourly and annual NOx, CO, VOC, PM/PM4o/PM2.s, and SO2 emission rates from the heaters: lb Hourly Emission Rate ( hr) = Heat Input Rating , hr r ) x lb Btu Emission Factor (MMscf) /Natural Gas Heating Value ( scf MMscf lb l ton \ Annual Emission Rate (tpy) = Annual Fuel Consumption ( ) x Emission Factor (MMscf/ x (2,000 lb) Yr GHG emissions are estimated based on proposed equipment specifications as provided by the manufacturer and the default emission factors in the EPA's Mandatory Greenhouse Reporting Rule and as shown in Table 5-2. Turbine GHG Emission Factors. Hourly emission rates for CO2, CH4, and N20 are based on the heat input rating (MMBtu/hr) for the heater. Annual emission rates are based on the annual fuel consumption of 315 MMscf natural gas. The following equations are used to estimate hourly and annual CO2, CH4, and N20 emission rates from the heater: lb hr lb Hourly Emission Rate ( hr ) = Heat Input Rating ( hr ) x Emission Factor (MMBtu) Annual Emission Rate ( tpy) MMscf lb = Annual Fuel Consumption ( ) (x Emission Factor yr (MMBtu) x Natural Gas Heating Value (Bcf) x \2,000 lb) 5.3. AMINE TREATER The proposed Lucerne 2 Expansion will include one amine treater (ID AU -02) as part of this modification. Emissions from the amine still vent will be routed to the Regenerative Thermal Oxidizer (RTO), which is conservatively expected to have a destruction rate efficiency (DRE) of 96% for VOCs and 99% for methane. Flash emissions from the amine still vent will be routed to a Vapor Recovery Unit (VRU) which has a control efficiency of 100%. During periods of VRU downtime, which is conservatively estimated to be 1% annually, the flash emissions are routed to the facility emergency flare with a DRE of 95%. Uncontrolled VOC, HAP, and H2S emissions from the amine still vent are estimated using the ProMax® output. The ProMax® simulation output file for the amine treater is provided in this section for reference. DCP Midstream LP 1 Lucerne 2 Expansion Trinity Consultants 5-3 NOx and CO emissions are estimated using U.S. EPA AP -42 Section 13.5, Table 13.5-1 emission factors. GHG emissions of CO2, CH4, and N20 from the RTO will result from the combustion of the amine still vent (ID AU -02) waste stream. H2S, VOC, and HAP Hourly Emissions (Still Vent). Uncontrolled inlet hourly rates of H2S, VOC and HAP from the amine still vent are obtained using the ProMax® output. The following equation is used to estimate hourly H2S, VOC and HAP inlet rates to the RTO: lb Uncontrolled Inlet Hourly Emission Rate I —hr) I = ProMax Output Stream Data (hr) Controlled hourly emission rates of H25, VOC and HAP, as controlled by the RTO, are estimated using the inlet to RTO as calculated above and a conservative DRE. The following equation is used to estimate hourly HzS, VOC and HAP emission rates from the controlled streams: lb lb Controlled Hourly Emission Rate ( h) = Inlet to RTO (hr) x [1 — Destruction Rate Efficiency (%)] H2S. VOC. and HAP Hourly Emissions (Flash). Uncontrolled inlet hourly rates of H2S, VOC and HAP from the amine unit flash stream are obtained using the ProMax® output. The following equation is used to estimate hourly H2S, VOC and HAP inlet rates to the VRU: lb lb Uncontrolled Inlet Hourly Emission Rate ( hr ) = ProMax Output Stream Data (hr) Controlled hourly emission rates of H2S, VOC and HAP, during the 1% annual downtime of the VRU, are estimated using the inlet to VRU as calculated above, a control efficiency of 99% and a 95% destruction efficiency for the facility emergency flare. The following equation is used to estimate hourly H2S, VOC and HAP emission rates from the controlled streams: lb Controlled Hourly Emission Rate ( ) hr = Inlet to VRU (h) x [1 — Control Efficiency (%)] x [1 — Destruction Rate Efficiency (%)] SO2 Hourly Emissions (Still Vent). SO2 emissions are based on the conversion of sulfur during the destruction of inlet H2S using a mass balance equation for the amount of H25 that goes into and out of the RTO and the ratio of the molecular weights of 502 and H2S. The equation is used to estimate hourly SO2 emission rates from the controlled streams: 64.06 lb 16 Controlled Hourly 502 Emission Rate lb = Inlet H2S to RTO — Outlet H2S to RTO lb x lb -mob ( hr ) (hr) (hr) 34.08 lb Ib-mol DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-4 S02 Hourly Emissions fFlashj 502 emissions from the amine unit flash stream emissions are based on the conversion of sulfur during the destruction of inlet H2S using a mass balance equation for the amount of H2S that goes into and out of the VRU and flare, the ratio of the molecular weights of S02 and H2S, and the destruction efficiency of the flare. The equation is used to estimate hourly 502 emission rates from the controlled streams: 64.06 lb lb lb Controlled Hourly S02 Emission Rate ( hr ) = Inlet H2S to Flarehr () — Outlet H2S to Flare (lbhr) x lb-mol 1\ 34.08 lb lb-mol NOx and CO Hourly Emissions Emissions factors for NO2 and CO are estimated using U.S. EPA AP -42 Section 13.5 emission factors.10 Hourly emission rates are based on the heat value and maximum amine acid gas flow rate, as shown in the following equation: lb Hourly Emission Rate ( hr ) lb = Emission Factor ( MMBtu ) x Heat Value (B�f) x Amine Acid Gas Flowrate (MdMscf) Y 1 day x 24 hr CO2. CH4. and N20 Hourly Combusted Emissions (Still Vent). Controlled hourly emission rates for C02 and O14 from the RTO are estimated using the inlet to RTO data from the amine still vent using the ProMax© output for the waste stream and a conservative destruction efficiency. The following equation is used to estimate hourly C02 and CH4 emission rates from the controlled streams: lb lb Controlled Hourly Emission Rate ( h) = Inlet to RTO (hr) x [1 — Destruction Rate Efficiency(%)] Hourly N20 emission rates are estimated using Equation W-40 in 40 CFR Subpart W for combustion units that combust process vent gas, as shown in the following equation:" lb N20 Hourly Emission Rate ( hr ) MMscf 1 day 106 scf MMBtu = Waste Gas Flowrate (MMscf) ) x 24 hr x 1 MMscf x Process Gas HHV ( scf ) kg 2.2046 lb x N20 Emission Factor ( MMBtu ) x 1 kg 10 U.S. EPA AP -42 Section 13.5, Industrial Flares (September 1991). 11 40 CFR §98.233(z)(2)(vi). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-5 Hourly Emissions from Conversion to CO2 (Still Vent), In addition to emissions from combusted CO2, CH4, and N20, additional GHG emissions will result from the conversion of carbon atoms in the fuel (amine still vent) to CO2. For sources that combust process vent gas, the converted emissions are estimated based on Equations W -39A and W -39B obtained from 40 CFR 98 Subpart W.12 The following equation is used to determine the CO2 emissions resulting from the oxidation of methane (compounds with one carbon atom), ethane (compounds with two carbon atoms), propane (compounds with three carbon atoms), butanes (compounds with four carbon atoms), and pentanes+ (compounds with five or more carbon atoms): hrConverted CO2 Hourly Emission Rate = Inlet to RTO () x Carbon Count x Desruction Rate Efficiency (%) CO2 and CH4 Hourly Combusted Emissions (Flash) Controlled hourly emission rates for CO2 and CH4 from the VRU during annual downtime are estimated using the inlet to VRU data using the ProMax® output for the flash stream, a control efficiency of 99% and a conservative destruction efficiency for the facility emergency flare (95%). The following equation is used to estimate hourly CO2 and CH4 emission rates from the controlled streams: lb Controlled Hourly Emission Rate ( hr ) lb = Inlet to VRU (hr) x [1 — Control Efficiency (%)] x [1 — Destruction Rate Efficiency(%)] Annual Emissions All annual emission rates are based on maximum operation equivalent to 8,760 hrs/yr, using the following equation: Controlled Annual Emission Rate (tpy) = Controlled Hourly Emission Rate ( h ) x Hours of Operation (hr) x (2,0001b) 5.4. GLYCOL DEHYDRATOR The proposed Lucerne 2 Expansion will include one TEG dehydrator (ID D-01) as part of the modification, controlled by an enclosed combustor that with a conservative DRE of 95%. Emissions from the glycol dehydrator are estimated from the GRI-GLYCalc Version 4.0 Aggregate Calculations Report dated October 2, 2012. The GRI-GLYCalc aggregate file for the dehydrator is provided in this section for reference. Flash emissions from the dehydrator still vent is routed to a Vapor Recovery Unit (VRU) which has a control efficiency of 100%. During periods of annual VRU downtime, which is conservatively estimated to be 1%, the flash emissions are routed to the facility emergency flare with a DRE of 95%. 12 40 CFR §98.233(z)(2)(iii). DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 5-6 H2S VOC. and HAP Hourly Emissions (Still Ventl Uncontrolled inlet hourly rates of H2S, VOC and HAP from the glycol dehydrator still vent are obtained using the GRI GLYCaIc aggregate emissions report. The following equation is used to estimate hourly H2S, VOC and HAP inlet rates to the enclosed combustor: lb Uncontrolled Inlet Hourly Emission Rate ( hr ) = Uncontrolled Combustor Emissions (hr) Controlled hourly emission rates of H2S, VOC and HAP, as controlled by the enclosed combustor, are estimated using the inlet to enclosed combustor as calculated above and a conservative DRE. The following equation is used to estimate hourly H2S, VOC and HAP emission rates from the controlled streams: lb lb Controlled Hourly Emission Rate ( hr) = Inlet to Combustor (hr) x [1 — Destruction Rate Efficiency (%)] H2S. VOC. and HAP Hourly Emissions (Flash). Uncontrolled inlet hourly rates of H25, VOC and HAP from the glycol dehydrator flash stream are obtained using the GRI GLYCaIc aggregate emissions report. The following equation is used to estimate hourly H2S, VOC and HAP inlet rates to the VRU: lb lbUncontrolled Inlet Hourly Emission Rate ( hr ) = Uncontrolled VRU Emissions (—hr ) Controlled hourly emission rates of H2S, VOC and HAP, during the 1% annual downtime of the VRU, are estimated using the inlet to VRU as calculated above, a control efficiency of 99% and a 95% destruction efficiency for the facility emergency flare. The following equation is used to estimate hourly H2S, VOC and HAP emission rates from the controlled streams: lb Controlled Hourly Emission Rate ( hr ) = Inlet to V(n RU) x [1 — Control Efficiency (%)] x [1 — Destruction Rate Efficiency (%)] SOS Hourly Emissions 502 emissions are based on the conversion of sulfur during the destruction of inlet H2S using a mass balance equation for the amount of H2S that goes into and out of the combustor and the ratio of the molecular weights of S02 and H2S. The equation is used to estimate hourly SO2 emission rates from the controlled streams: lb Controlled Hourly 502 Emission Rate ( hr ) 64.06 lb = Inlet H2S to Combustor lb — Outlet HZS to Combustor lb x lb-mol (hr) (hr) 34.081b lb-mol DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-7 Criteria Pollutant Combustion Emissions The volume of vapor vented is obtained from the GRI-GLYCaic output, Regeneration Overhead stream is assumed to be the amount of vapor that the enclosed combustors can combust. The heat value HHV (Btu/scf) of this vapor was calculated by using the component mass fractions and individual component heat values. This information is then used with the AP -42 Section 1.4 External Natural Gas Combustion emission factors for NOx and CO to estimate emissions of those pollutants.13 A sample calculation is provided below: lb Hourly Emission Rate ( hr ) lb scf Btu = Emission Factor ( MMscf ) x Volume Vented (hr) x Vented Gas Heat Value ( scf/ Btu 1 MMscf Natural Gas Heat Value ( scf ) x ( 106 scf ) Annual emissions are estimated assuming 8,760 hours of operation annually: CO2. CH4, and N20 Hourly Combusted Emissions Controlled hourly emission rates for C02 and CH4 from the enclosed combustor are estimated using the inlet data using the GRI-GLYCaIc output for the waste stream and a conservative destruction efficiency of 95%. The following equation is used to estimate hourly C02 and CH4 emission rates from the controlled stream: lb Controlled Hourly Emission Rate ( h) = Inlet to Enclosed Combustor (h) x [1 — DRE(%)] Hourly N20 emission rates are estimated using Equation W-40 in 40 CFR Subpart W for combustion units that combust process vent gas, as shown in the following equation:14 lb N20 Hourly Emission Rate ( hr ) (MMscf)1 day 106 scf MMBtu = Waste Gas Flowrate day x 24 hr x 1 MMscf x Process Gas HHV ( scf ) kg 2.2046 lb x N20 Emission Factor ( MMBtu ) x 1 kg The process gas higher heating value (HHV) and N20 emission factor are taken from 40 CFR §98.233(z)(2)(vi). Hourly Emissions from Conversion to CO2 (Still Ventl In addition to emissions from combusted CO2, CH4, and NM, additional GHG emissions will result from the conversion of carbon atoms in the fuel to C02. For sources that combust process vent gas, the converted 13 AP -42 Section 1.4, Natural Gas Combustion (July 1998). 14 40 CFR §98.233(z)(2)(vi). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-8 emissions are estimated based on Equations W -39A and W -39B obtained from 40 CFR 98 Subpart W.15 The following equation is used to determine the CO2 emissions resulting from the oxidation of methane (compounds with one carbon atom), ethane (compounds with two carbon atoms), propane (compounds with three carbon atoms), butanes (compounds with four carbon atoms), and pentanes+ (compounds with five or more carbon atoms): lb Converted CO2 Hourly Emission Rate = Inlet to Enclosed Combustor (hr) x Carbon Count x DRE (%) CH4 Hourly Combusted Emissions (Flash Emissions). Controlled hourly emission rates for CH4 from the VRU during annual downtime are estimated using the GLYCaIc output for the flash stream (inlet to VRU), a control efficiency of 99% and a conservative destruction efficiency for the facility emergency flare (95%). The following equation is used to estimate hourly CH4 emission rates from the controlled streams: lb Controlled Hourly Emission Rate hr lb = Inlet to VRU (hr) x [1 — Control Efficiency (%)] x [1 — Destruction Rate Efficiency(%)] Annual Emissions Annual emission rates of H2S, VOC, SO2, and HAPs are based on hourly emission rates and maximum operation equivalent to 8,760 hrs/yr, as shown in the following equation: lb hrs ton Annual Emissions (tpy) = Hourly Emissions (hr) x Hours of Operation (—) x (2,000 lb) yr 5.5. ATMOSPHERIC STORAGE TANKS The proposed Lucerne 2 Expansion will include four (4) 1,000 barrel condensate tanks. Working and breathing losses from these tanks (ID TANKS) are estimated using the U.S. EPA TANKS 4.09d software, tank characteristics, and expected throughput. The condensate characteristics are obtained from a similar DCP site. Hourly uncontrolled tank emissions are estimated based on the maximum monthly emissions from the TANKS output. Annual uncontrolled tank emissions are taken directly from the TANKS output. A TANKS output report is included at the end of this section. The storage tanks will be equipped with an enclosed combustor with a control efficiency of 95%. Therefore, controlled hourly and annual emissions are estimated based on a 95% control over the uncontrolled emissions as follows: Controlled Emissions (tpy) = Uncontrolled Emissions (tpy) x (100 — Control Efficiency)% Additionally, according to the condensate analysis included in this section, there are no GHG weight fractions in the detectable range of the condensate sample. Therefore, GHG emissions from the tanks are assumed negligible. 15 40 CFR 598.233(z)(2)(iii). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-9 5.6. TRUCK LOADING LOSSES Low pressure condensate will be loaded into tanker trucks and removed offsite (ID LOAD). VOC and HAP emissions will result from vapors in the tanker truck that will be displaced by the loaded liquids. The tank loadout will be controlled by an enclosed combustor with 95% control efficiency. U.S. EPA AP -42 emission factors are used to estimate uncontrolled emissions from truck loading.16 The loading method is submerged loading, dedicated normal service. The loading loss emission factor is calculated using the following equation: 12.46x SPM T where L� = loading loss (lb/1,000 gal loaded) S = saturation factor (from AP -42, Section 5.2, Table 5.2-1) P = true vapor pressure of loaded liquid (psia) M = molecular weight of vapor (lb/lb-mol) T = temperature of bulk liquid (°R = °F + 460) The condensate characteristics are obtained from a similar DCP site. The following equations are used to estimate uncontrolled hourly and annual emission rates from the tank loading operations: lb lb Hourly Emission Rate ( gall hr ) = loading loss (1,000 gal) x Maximum Hourly Throughput (hr) ton \ Annual Emission Rate (tpy) = loading loss (1,000 gallb ) x Maximum Annual Throughput (gal) x (2,000 lb) As stated previously, the condensate tank loadout will be controlled by an enclosed combustor with 95% control efficiency. The controlled emissions are estimated with this control efficiency applied to the uncontrolled emissions as follows: Controlled Emissions (tpy) = Uncontrolled Emissions (tpy) x (100 — Control Efficiency)% Additionally, according to the condensate analysis included in this section, there are no GHG weight fractions in the detectable range of the sample. Therefore, GHG emissions from truck loading are assumed negligible. Emissions from the tanks and truck loading are controlled by an enclosed combustor with a 95% control efficiency. The combustor is equipped with a natural gas pilot and will combust the vapor captured from the tanks and truck loadout. 16 U.S. EPA AP -42, Section 5.2, Transportation and Marketing of Petroleum Liquids (July 2008). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-10 Tanks and Loadout Combustion Emissions The volume of vapor vented from each of the tanks and truck loading operations is assumed to be the amount of vapor that the enclosed combustor can combust. The volume of vapor vented is calculated based on the molecular weight of the vapor as follows: scf Volume Vented (-) yr lb lb scf. psia = Total Emissions (yr) x Vapor MW (Ibmol) x Gas Constant (°R.Ibmol) x Temperature(°R) y Pressure (psia) The heat value HHV (Btu/scf) of this vapor was calculated by interpolating between butane and pentane HHV based on molecular weight. This information is then used with the TNRCC Flares and Oxidizers emission factors for NOx and CO to estimate emissions of those pollutants)? A sample calculation is provided below: lb Hourly Emission Rate (hr) lb Btu scf = Emission Factor (MMscf) x Vent Gas Heat Value ( scf) x Input Flowrate (hr) MMscf scf x (100,000 scf) x (1,000 Btu) Annual emissions are estimated assuming 8,760 hours of operation annually: t ]b hr ton Annual Emission Rate (tpy) = Hourly Emission Rate (hr) x Hours of Operation (yr) x (2,000 lb ) Additionally, GHG emissions will result from the conversion of carbon atoms in the fuel to CO2. For sources that combust process vent gas, the converted emissions are estimated based on Equations W -39A and W -39B obtained from 40 CFR 98 Subpart W.18 The following equation is used to determine the C02 emissions resulting from the oxidation of methane (compounds with one carbon atom), ethane (compounds with two carbon atoms), propane (compounds with three carbon atoms), butanes (compounds with four carbon atoms), and pentanes+ (compounds with five or more carbon atoms): Converted CO2 Hourly Emission Rate = Inlet to Combustor (hr) x Carbon Count x Desruction Rate Efficiency (%) 5.7. EQUIPMENT LEAK FUGITIVES Process fugitive emissions of VOC result from leaking components such as valves and flanges (ID FUG2). Emissions from fugitive equipment leaks are calculated using the fugitive component counts for the proposed Lucerne 2 Expansion, the VOC content of each stream for which component counts are placed in service, and emission factors for each component type taken from the U.S. EPA Protocol for Equipment Leak Emission " TNRCC Flares and Vapor Oxidizers, Table 4 Flare Factors 18 40 CFR §98.233(z)(2)(iii). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-11 Estimates.19 The proposed modification is subject to NSPS Subpart 0000 and will therefore be subject to more stringent fugitive control requirements under the LDAR program. Accordingly, DCP has selected control efficiencies as applicable and applied those to the equipment leak fugitive calculations. The representative analyses used in the fugitive calculations are obtained from the ProMax® output and can be found below in this section. Hourly Emissions Hourly emissions of VOC from traditional fugitive components (i.e., valves, pumps, flanges, compressors, relief valves, and connectors) are estimated using EPA emission factors, component counts, and the VOC content of each stream. The following equation is used to estimate hourly VOC emissions: Hourly Emission Rate (lb/hr) kg = EPA Emission Factor ( hr-comP ) x (2.k g lb) lb\ x Number of Components (# comp) x VOC Weight Percent (% wt) x (1 — Control Factor(%)) Speciated VOC and HAP emissions from traditional fugitive components are estimated based on the total VOC emissions as estimated above and the speciated gas analysis for each stream. The following equation is used to estimate speciated V0C and HAP emissions for each compound in the stream: Speciated Hourly Emission Rate (lb/hr) kg l 2.2lb\ = EPA Emission Factor ( hr-cmn ) x ( kg I x Number of Components (# comp) P x Compound Weight Percent (% wt) x (1 — Control Factor(%)) C02 and CH4 fractions are calculated using the following equation: Ib Hourly Emission Rate (lb/hr) = Uncontrolled Emissions (hr) x C02or CH4 Weight Percent (% wt) Annual Emissions Annual emissions are estimated based on hourly emissions rates and maximum operation equivalent to 8,760 hrs/yr, as shown in the following equation: lb hr ton Annual Emission Rate (tpy) = Hourly Emission Rate (hr) x Hours of Operation (—) x 2,000 1b) yr 19 U.S. EPA, Protocol for Leak Emission Estimates, Table 2-4 Oil and Gas Production Operations Average Emission Factors (November 1995). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 5-12 SITE -WIDE SUMMARY - CRITERIA POLLUTANTS Controlled Hourly Emissions (lb/hr) a I N Ci p{ ILucerne 2 Expansion t� N O ti O 00 CO O 00000 O O O O c-1 O O O N i I O: O N rl (vj nq O Ct N 0] NO U] In M Ln N N O r1 .. O O R N M d' O O O W W • W.. O U] co ' 0 co N M Ni Ni 7.67 I 0. x cc? r1 d' d' N O O O • CO O O W O. W N O m v N 124 2 0. N N Ly 0] W in d' d' N O O O cF M O M O 10 co• ' N i y O co a{' N 1.24 aOJ �.{ d' •t.'N: 1 O O O a co O O W O' W y O W 4 N N '1 U Q N N V] U] t. 00 CO a' M LO ti r1 N i M 1n 1n O, O O O r1 4 O O M a' M M O O • N • N O W O W W N N ca O! o 0 0 co T N 12.02 O U N Ni O O r1 10 CO O O • " . a' CO O O O M O 41 M. O ' a O O N M co O Z N 0: coM c-1 r1 r1 N N .. CO I-, N O O ' M M T4 O O O O M O O c' 41 M. O O O OJ d' 0� Description Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) Insignificant Activities Enclosed Combustor Pilot RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions C C 6 X W NC C J 4 — m E E9 0 C C O 'C O F SITE -WIDE SUMMARY - CRITERIA POLLUTANTS Controlled Hourly Emissions (lb/hr) I 42 Q. If) O, .� Lucerne 2 Expansion N N. CT H Os OD CO ON 0000,,(3000o o000 �000 N o N e- t'i N y 2.87 L11 M N,-1� N tN O . O• ' ' 1 ' O O O N: tf) on 0 O O O L] W W C ' ' ' O U) ' M \O M N M N N 7.72 N X+ p, N CL ,-i W co U) d' d' N . . ' ' 00o d' on O M 9 O N No w d' N d' N • .. o� g", N CC 4p co CO In d' d' N , , , , , 0 O O d' co O M O W o • , N , , N O W d' Ni d' N .--, PM N c:'::? H CO O to d' d' N , O O O d co ' M a W O , V , • ter) O W d' ca vt N .-I VOC 28.22 to U) co O" CO d' co U) '-1 .--I N V) CO U) U) ON 0 0 0 d' O O M d' co co N O N 0 U O W W N N M • coO 4 o 0 0 M O Ni 12.03 G V 52.76 NJ Ni o NJ 00 N� O O• cr d' d' 0 0 0 0 co o V M; O ' 0 O ' to to d: M x O Z N O` co M V) rf .--4 N N d' d' CO , -t N O O , M M '-1 a O 0 0' on O ON d' W M , O D O ' O N U) pi C 0 , 0. .I- u 61 G { Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D -01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) I Insignificant Activities Enclosed Combustor Pilot RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions n m O O N N ro a SITE -WIDE SUMMARY - CRITERIA POLLUTANTS co L v co E E H 0J or O y E k7 N '0c 3y . 3 in Controlled Annual Emissions (tpy) I IsdtiH 1 ZOS VD U9 Lucerne 2 Expansion I M M O CO C' N. VD N M M M O� M KJ e M O O O M N O O O O, . , : i O' O M t!1• M r1 d' In a' O O O Cl] W • W • .4 .-1 D: I 33.76 " a k0 pl t` O O .--, - CO N N O on d' W W • p a co . . O N; O N .--I 5.02 G 2 4. •D c" r O O H N 0O . i . . . N N O M d' O O .--1 co . O• . O l\ co N .--I 5.02 22' N O co CO . . •• • .. .• ('INC M •,:t• W :Lop O CO . • •• , O N .^I p If) t..) © 'J O U]t•-•S. r.,.i N l 1, in O co .ti CO ' O OD a N M M N O O O N N .�-I O• O O co W W O W c, a) a. N co Cr, O O N N N CO 231.10 tD �D N N Cr, CO OD l� l", O O ' �-I .--1 .--1 N O O O M N• ' O O ' C) ' , -I Cr, N O Z 201.34 O C coMtOf) as aO: .�-1 e -I i! 1 0 0 0 0 M O O W ' .--i . C M O N as • M 0 O D O. V V) elJ L Total Existing Emissions I Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) LInsignificant Activities Enclosed Combustor Pilot RTO Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions SITE -WIDE SUMMARY - HAPS Emissions Summary Hourly Emissions (16/hr) _ I N m Total Existing Emissions I 0.12 I 0.06 I 0.00 I 0.03 I 0.42 I 0.12 I 0.12 I_ 0.20 I 1.05 I 0.00 I 2.12 I Lucerne 2 Expansion S N O ... 41, 0 0 0 0000 0 0 0 M O ' N i co p 4 0 M N M IA a. 'i 4 N N C C c.• X i ,0 .4 G R X y Z T•O d. C' co I p r-0 M P q= o P o 0 0 0 N co C N . 10pI . N I o n Oi CO V1 1. o c ; y C 99 1n M m 9 .i' 4 N 41 9 = !:: H::: C n M 41 K mm d' O O O W 41 i O O O O W ,P b o 0 0 0 6 .4 4, en an O :0: I e N .,-I ,66 E -Benzene 99 ,..,m999 9 mm 9 00:00000 M M --.1•4.,i N N .-1 .-I N 9 . 0, ' m' I' co 0.05 0.05 C O 000 W .+ N N O L•] 41 4] N In O O a, V' d4' 0 0 0 0 8 C0'.- N O , L11 1 I s ..+ N .� CC:M T O O Benzene .4.,4-.4- M M M O O' 02 0 0 0 W W W 1A N th Ii1 = ht. -1g O O m 00 . N n M O' M G O . 41 , 41 , y m M 1A q N d' m .. C O C. c Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) Insignificant Activities Enclosed Combustor Pilot Compressor Maintenance Slowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions Post Modification Total Emissions a to n Summary for Hazardous E 0 m Annual Emissions (toy) Total Existing Emissions 0.52 0.28 0.02 0.13 1.85 T 0.54 0.50dJ 0.87 I 4.59 I 0.00 I 9.30 Lucerne 2 Expansion 'aCO O O O m 6 O O O o O O CO W o N L S F 01 01 an 4 q0 d g 6 m oo.+OoO : 0 o ? m tam L C U .j Z w o o , 0 c e C u ¢` E a a 1 1 — io o o . .. an O O d 6 o 0 o . . a m d o S = m o 0 0 0 o ti un m op N H1.0 e o co G K O F W o p O O O O m N N O oO v G cU W d' mcr.p O O O p o O ui < ua n 3.72 4.00 d _ Q E-: rn an p en 6 4l 41 in m o d o o coa mm m o ' M an o of N V b 6 cu C eu Combustion Turbine 1 (TURK -1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D -01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) Insignificant Activities Enclosed Combustor Pilot Compressor Maintenance Blowdown Emergency Flare Produced Water Pressurized Condensate Load Total Modification Emissions Post Modification Total Emissions Description E 3 E fD 'C O F SITE -WIDE GHG SUMMARY Annual Emissions (tpy) C U 711-3-,047 Lucerne 2 Expansion CO tD t0 Cr) C.) C.i (NI N l� d' N N f] O d' d' N .41 14 a: N a. O, •-+ 31.45 2.81 235.51 r 265,586 I p N z t`t\d"�� O O qt -1 66667: d' o Liz ti , 5.91E-05 5.28E-06 3.14E-03 L T0'ZI c U c)c'm.-i-rn d o G • •rn . . L 5.91E-04 5.28E-05 1.14 33.23 U`1" U CO kri,In O O l� d d' d' Nif) `-i N 0 M N N N O N Hourly Emissions (lb/hr) I COze t0 t0 d' ,t, M N N N O O O tj CO CO in LO t0 O dM' N .--+ •;r N kNO �p L) d' N 1� CO O I .-1 co • t\ LO Cflti Q, C• co T p H N N .a O .-I O O O O s.O C C O O N in O Liz ,�� CO 1.35E-05 8.80E-04 7.16E-04 Cl., N N CH4 M m .-1 N N N N6 O6 ' , N d• CO O O LC C.1.17 N in CO O rl O %6 l' p U O O in co O O O O' [�[�°°,-c L1 LL) d' `� 07 O; O% v M M N CV N 0 7.17 467.56 48.08 61,787.23 Description Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Lucerne 2 Fugitives (ID FUG2) Inisignificant Activities Enclosed Combustor Pilot RTO Pilot Emergency Flare LTotal Modification Emissions W C W H n —.0 y z = o a o 4 F z C alu a tsi y E N 9 d E Annual Emissions (tpy) 1 O V 82,877 I ILucerne 2 Expansion CO co mO N 0 ,0 IC co co rn M— r d' N N IN N N V d' ON IL' N N N `-I N �' 0 N M N M N O N N Q y H CO CO O y 0 0 0 O co 1.58E-04 1.41E-05 9.76E-04 9 M on co G' N Irk LN VD O O rl N O r r 0 0 0 Ill 00 V] Q coN N O N Ni •-1 •-1 M W N g a O 0 S O O N '+ .r. 0 ; . N N O 0 Cr Cr al al of co 0 N N Ni r '-I 0` P 1: O O m N N O r r r 2.00E-03 1.78E-04 1.24E-02 O y CO N° M O O m O `c•ncuc,NO•O O O O al M > O a O O ‘ D P N N d. N C r rI CO co M 52.3 O ,r CONI 0 Q CO CO ° 'O N N N O O , O L0 V N H H M N O d OO O r a m O NM CO N N CO 0 'd' O, O, O O 0 NO` O O CO O N O I Z O H to N O O 6O O M a M N N Description Total Existing Emissions Combustion Turbine 1 (TURB-1) Combustion Turbine 2 (TURB-2) Hot Oil Heater (ID HT -02) Amine Still Vent (ID AU -02) TEG Dehydrator Vent (ID D-01) Storage Tanks (ID TANKS) Truck Loading (ID LOAD) Insignificant Activities (Non -fugitive) rEnclosed Combustor Pilot RTO Pilot Emergency Flare Total Modification Emissions Comparison to PSD/NNSR L 0 0 O 0 O NO NO -- NO NO NO NO YES O O O N N. O Ln CO O Q Z O Ln O .-1 O N O Ln o 401 N . in un N Z O O Z a Y Z Z 0 Ln • O 0 O . . N Z o N N 00 tlf O d' O z oO O Z Prevention of Significant Deterioration (PSD) Major Source Threshold Is the Project above PSD major source threshold? Nonattainment New Source Review (NNSR) Limits Is the site above NNSR limits? PSD Significant Emission Rates (SER)'''' Is the project above PSD SERs? NNSR SER °'s Is the project above NNSR SERs? s. Weld County is e is a major source of GHGs, then r July 1, 2011. Theref area for NOx, therefore emissions of NOx are subject to both PSD and NNSR programs. Since ck (CDPHE APCD) and Kim Ayotte (Trinity) on April 23, 2012. CO C tC y0+ N ` 6 o ;E a Ls. C W O E v H n m n e c E o ro m n E m E O O 0. a a o z _c CO z N p O i O 0 T m c O C O V > O c > o E 8 c o Z O O y o N v w 0 o c m o 0 T y C z Ip ry 0 v 419 CO m d a a 0 ° o E ¢ c ec = o ac Z O d N y y •p 0 CO C N C 00 v a E 0 00 o O a w O V V O. H 01 d NCr .. O uF OF in VI In 14 IDs: TURD -1, TURK -2 ] 12. Parameters 22 o 0 \ \ la \\\ \\0 co it 3 o 0. Turbine Emission Factors / E 0 to N N 14 0 in { ) \ \ ro LI \� \ \ \ \\\eji ri ori 0 ca \\ }))}) Proposed Maximum Hourly Emissions for the Combustion Turbines o CO 00 CO 00 0-1 CO 01 N N 0 0 co Source Name Ca CO C4 CC N O 0 \ \ N Oh CO Total Maximum Hourly \ja▪ e o 0 OD EMISSION CALCULATIONS FOR COMBUSTION TURBINES IDs: TURB-1, TURB-2 U O O. a z O U ' a0 m O O W O O ,-I O O N N O O ati N N N1 O O N N C. IV N N O O in an7 N N 03 0 N• N` •-I O N O C O O M N N U7 M Source Name i N 0 0 cC F F Total Annual Emissions II C O O O x C JD A N O L d' O a QCC� II N O C � 2 P.1 m � O I- C O II O p V C O E R O C a O 0 N 0 O a .8g * 0 0 0 0 d' O W 0 0 0 N Ci O O Ci oN 0 O 0 N Od N N O O N O O 44 O E N O O O O N �. a..l O O O M O O O O O. ..do .4 sF N: lf1 M 'd' d' M N U7 'd' M M O O O O O Q O 9 O O O CC W C] 2 W [C GC W 2 W 7d .I Cr: n m C; aO0, ai M N d' C0 N U1 C' a••I N C% N U1 aD U1 CO * ,O ,b U7 d' U1 0 0 0 0 0 0 0 0 0 0 0 al 00000000000 0 M O N N .� C 4 4 vi ati 1,•f n N N N ati aG 0 ai IV •O R u > C O 'fl = N N O CC ,o C C y b @ ?. u 3 ,0 fl c CO Ti R .,0 cx c H Q¢ O W U. z a. E. F. C v Uf C0 0 Total HAPs 3,13E-05 lb/hr II 72.73 MMBtu M W w � O tit F O. g II •a x r E t5 i C Z 0. H P+ PO 1: O •s PO N L • N m w G G co 2 cc Q Co N O_y C, E IA E O T y t. -x m o C >, C '•— O C O. E O C W O o w y x 4.4 0 O so .E O 0 O � x 3. O. C 0. O C C e O #L C O W II C yN w 7 t 2 0 to O Eh M '-I Annual HAP Emission Rate for 1,3 -Butadiene per Unit (tpy) = a O N N C a C- F C O E O 0 a z C c A. C N W C C C 5 F+ L C F L. C O w C C « ion Turbines GHG Emi 5 co led to HHV as LHV x 1.1. u • x • u. MI ) 64 UUZ are of 60 °F and relative o zz cgi \-oFc GHG Potential Emission Calculations Annual Emissions' (tons/yr) CO2 CH4 N2O CO2e4 4.2,035 10.07 0.07 42,268 42,035 10.07 0.07 42,268 84,069.72 20.15 0.14 84,536 - - 84,536 Hourly Emissions (lb/hr) COc1 CH45 N2O' COie4 9,597 2.30 0.02 9,650 9,597 2.30 0.02 9,650 CO Vi 0 ID Description Fuel Type TURB-1 Combustion Turbine 1 Natural Gas TURB-2 Combustion Turbine 2 Natural Gas Total Total CO2e Emissions' )o tfl o o aa am co co 3 co r O E A 22 0 CC EMISSION CALCULATIONS FOR H x z x x 5 5 > c 0 c L x a S 0 8 d O 5°v x°a z rq iatn C ID F d z E .n E 5 A a " ° x o ! E c vo 3 F E o E z v c ' E i x° E °N E o C E IC s E _ F � y s E E o E E o E C' 21 o= E '0 <U LATIONS FOR HEA EMISSION CAL c2i 0 f E V N 0 T 0 O 122,1 2,2 0 a° e N 3 T EMISSION CALCULATIONS FOR HEATERS Natural Gas External Combustion HAP Emission Rates Annual Emissions 3 (fiY) m n.o n NE\r.g E\ .. 6.g � n m m,,b !•mmN m*m mmmmmmmwmr mr Ea51$a`ichmwryiWiammaimmiummwimwm co.tr...m....s. a ama P P p. m m �yy' mm mTm mT m n m m m Nnmtm-O{mmm-mn d_ 0 m m. m M m1-lNmm• [3 N M N N N NMNM..N.+NN�+tiara.. N O N.11101. 44N.i IAN * M M M O Hourly Emissions (lb/hr) m m 1+ m. m m m m m m m I\ N M m m I\ n m E\ m m �p m m ma R R 2 2 R 9 R 9 4 9 9 R 9 4 R R 4 4 R R 2 R R p m 2 R Y Q P P P 0.-..,]m W , wwwwww0wwwwawwwwwwwwww 0 0�..-4.-4040,,,0,4,,,,4000e4,4..00001,10 m-OMI. NN 0 0 O O O O N O 0 0 0 0 0 0 0 0 Vl Q 0O o N ,, O O to O N I13 : !+l O w. .I P m PP.4P.+bP.Pab..0.IM P Mm N.+...omnaN Emission Factor (lb/MMsct) Source' 1 M M M M M M M M M M M M M M M M M M M M M M M I V T T I N I wA.°,I 01t4'XAX244444444444444444 Y S' Y4 a m m n m w a m m"a m a' a a m a a a a a a a a a a a a s 4 E-I-E+k E-I-r-FFf t-I-rrF-F F F F[ t2 4 Ff Ff FFFE F F F F .D.o N m M.o.o.o.o.o.o M.Dv N O.o m M m m Mm a Mm 999999999999e9Q Q Q Q Q 4 R R O 0 P O o p 0 0 0 9 9 9 Q 9 99999 4 wwwwwwwwwwwwwmwdzchImmmmmmwwwww mm amNmmvoNNMNMMNN 0M mmin� •C I`PmON.-l.- N M m N a I 1 S m NN E X C 45c yCy G 'S . S: L T C IN C C y l! c i ! � ^ S '+ 4 • "Igo c 8 4 .8 e c a. 6_ = c_ p� m Ti -y E. O a. 4 .% .-i Y G i R g a m a A t 0 I d . O C' !�` S .C 3 A m m Y d Mnaa acammmmmucca a.xmza.�'E-tmciuu °�fSz,.% r Maximum Potential Hourly Emission Rate (lb/hr) - Heat Input Rating (MMBtu/hr) x Emission Factor (Ib/MMsef) / Heating Value (Etu/scf). po 3 S C N Example 2-Methylnapbthalene Hourly Emission Rate (lb/hr). 8 N a O n EMISSION CALCULATIONS FOR AMINE UNIT Amine Still Vent (ID AU -02) .O N O CO e- .O n U7 0 O a .O aO III U N R A V 3 ;d o d w eu a C c.7 1 ID 11 a • o N _ C c3 O E iI t 4 ¢ -N o W 0 E Y 5 a 2 S Controlled RTO Emissions 4'5 v M d' N N d' CON I.n n M O N d' T O O e, e, O. e -I .O 0 OO U) N O O G>,] alW W .O e -I O O O O O N eti 0 0 N M N C .- N Uj lZ CO n .O O 0 rn �,.� I� V NN M "t La .N N d; W el W O W Lei r4 O o CO W GC W el 080 p oc, 0 O O O 0 N n O ,0. N .O N d' N N .n 0 r. O a VP 0 Cg O N N Pa > B. , on T O d. M n eti con d' `C ei M O W W Lsi M en co T' r, rl ei O m, M ri N O dt M OJ a-1 L e-1 .-I O N .o M7 T Imo'.. .0 M on O e -I N ON 1r) O 9V e-1 so O co N d: ey n C, NI N C3-1 W W Was C. e+ MO O o Z4 0 O O M N O N M n ti M e7• O n .D O M N Gv cm cm N a' T Oa, Ca. aa, ate, T CI, CO, Ca. Oa, C i .. O O nyOo a e3` .. O O p,� O U N Ca DI 1r *eh ch00000 N on a0 ar O.D N d' N O OOOOO O 00.--� e -t O W W W W Gil W W W W iz) W W W Wci, W r. N , m O 0 UI N H M 0 .O eK T 0 O N •.0 O m .O W' O, N T n .O OO'1 Gnovq"1C..O.-+n4na: n N N n V' .O N N CO N N 0 N N U) N n M O O 0 •C? _ _ a, O N N a y N .3) N N N N G C F N N �+ N a N a C 4 .5 +� f° a 0., N g N b� Q2 O a s O N N °agaga° x a) o ,S2. lo. ° and a1,— C— a IC,agFW x 2UX 6 T . J 5 x 'C''' rti Pr.. N R ,-aC L. N w N § 4 850 o 'a a °` o a ca C', 'a “ 'a Y H • N a w 1-,', • G. o II n -a G, id , p O .. X _ D O+ O. '. G o 4 E aai a a. F A ll a a g c a •E o N H N . 4• 7▪ 3' a eE. N a o W > a 50=' 0 7 N O aOO C i, o v o te a -. o, 1.13 a ° n121,3 2.0 W a a a O .a O L 110 E, a g o N ° z LI a a va >+ O W N C C 5 Inlet to RTO and Controlled RT0 Maximum Potential Annual Rate (tpy) = Hourly Rate (lb/hr) x Hours of Operation (hr/yr) x (1 ton / 2,0001b) a A a Example Controlled Propane Annual Emission Rate (tpy) = N .C a N a a 0 CJ ^O z W N z x Z c� O O a y a t ,a c6 N a F F DCP Midstream I Lucerne 2 Expansion Trinity Consultants on T EMISSION CALCULATIONS FOR AMINE UNIT Amine Still Vent (ID AU -02) VRU Downtime Emissions 4'5 Lvl y v M M CO M M N Ll] j' LO Li IO In N ‘.0 0 0 0 0 0 0 0 0 0 0 0 0 N O O ¢]WU] C'] V] GO Rl [L] W DJ [x] Lit O d(1i N N ` N N N r1 N N M Ci O O W cY rl h h co N 0 IO I.: 0 4 N rl 4 n: M 4 1` M V] O e'I N a .0 0 0 • O O rl In rl In N on co M d' d' d' o V] In VD N I- In t O ri 0 0 0 O 0 0 O O O 0 0 0 a W O in G] h] V G] in V] [L] V] V] in [x] N q v1 l� < q n qO 0 O q 0 r: rl V] N VI O IO VI IO '70' N y' rl N P lri N c -I c -I L` P rl q d 0 O O O O r1 d' O N 5.74 Destruction Efficiency 3 ^ O '•-•.."m o O 0 O O 0 o net e o 0 0 o N In in in in V) in VI 1f1 In in In N VI in m m m 0 m 0 m 0 0 m 0 0 0 0 e e VI N 0 0 0 LO 0 Inlet to VRU 2,5 >+ M CO N .. N q Cr, V'0, 0 In '0 0 '0 O 7-1 CO *. N 0 r1 'C 0 r1 VA rl m" N'n W N N O O O O O 2 O N NN in H y 1,389.37 1,056.07 IC 9 v N N M 0 0 0 q CO C In CO 0 N in 0 0 N. in Lx1 [x] 0 0, N M CI' r1 rl O O O O 0., M O .1 C,I 'y' 127.22 3.72 317.21 241.11 Control Efficiency 1 (%) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 0 0, 0 0, 0 0 0 rn rn 0 N 0 00, 0, SS 0. 0 0 0 0 0 .0 ooW E 0 V a 0O C ca',.“ wog O N UO m m a0+ u q% a, 0 di a0i ?.0 E <, 0 PM ❑ 4 P"' E o N J, u' ro O 6 T a.: _._ _ ccF L1 X w S voce HAP Methane CO2 O U 0 0 0 0' Example Controlled Propane Hourly Emission Rate (lb/hr) = L al Annual Rate (tpy) = Hourly Rate (lb/hr) x Hours of Operation (hr/yr) x (1 ton / 2,000 lb) 5 Inlet to VRU and VRU Downtime Maximum P O in ion Rate (tpy) = Example Controlled Propane Annual 0 w 00 0- EMISSION CALCULATIONS FOR AMINE UNIT Amine Still Vent (ID AU -02) SOi Emissions from Conversion of H2S in Amine Unit Flash Stream During VRU Downtime K ' en en en N N O N 0 0 M O oi m d 0 O. E 0 Hydrogen Sulfide 0 Q 0 A .0 UI 0 E .0 ri ry N O N K N L E =' 0 v m m = d O 0. S Eo m E2, E v) E N II .Lc m an A K N 0 E E _H E E O N N N L N C N c v 0 w t c o H a 0 64.06 Ib/Ib-mol Controlled SOi Hourly Emission Rate (lb/hr) = [0.03 - 1.29E-05] lb 34.08 Ib/16-mol L EMISSION CALCULATIONS FOR RTO COMBUSTION _ RTO (ID AU -02) RTO Combustion Emissions \ 05-3 Li 000 ))\ RTO Combustion Emissions RTO Emissions 3,4 0 01 U1 tu • ej tn co en • 0 o co uo N 01. dated June 1, 2012. tu/scf) x Amine Acid Gas Flowrate (MMscf/day) / (24 hr/day)] + -01 • • /co 00 co gIO 22 DJ \}) ) j11 ,:7a z ;:a>c \71. \n; 2-2 \ Maximum Potential Annual Emission Rate (tpy) = Hourly Emission Rate (lb/hr) x Hours of Operation (hr/yr) x (1 ton / 2,000 lb) 1.0 Example NO, Annual Emission Rate (tpy) = SO2 Emissions from Conversion of H2S in Amine Unit o \ 4O o 0 en rei \ Hydrogen Sulfide Amine Unit )to CO • cq 0 \6 8 o cn )/ )) U g \• \ 1-0 • 64.06 lb/lb-mol 34.08 Ib/Ib-mol on ra G-IG CALCULATIONS FOR RTO COMBUSTION o" Converted to CO, s''` Mir) (tPY) 41 Controlled GEM Emissions o S (lb/110 I (IpY) Inlet to RTO° (lb/hr) Tee**** " oPgoP :P E m o0 oc Number of Carbon Atoms o g 1 ° g Carbon Dioxide Methane Ethane Propane Butane Pentanes a EMISSION CALCULATIONS FOR GLYCOL DEHYDRATOR / T1 TEG Dehydrator Vent (ID D-01) Enclosed Combustor Emissions -Dehydrator Waste Gas Combustion Controlled Combustor Emissions 3'4 ' '-'°,000,I, at .w In Eh M O N T N M t t N N M N N 4 el M O rl el O M (V O O O N 19.03 7.39 �' C F.', N co N N N ca a CO ei co U7 O O O Q O CI O CI C d CI OO OO C O 0 0 uj M .0 d' .4 Inlet to Combustor 2'4 >p., .e v C a+ N ei O N .0T N IL N CI W V] N N. O C d: . m as h CO V1 L , l to O. I!7 .D W M d' W N .0 H N N O' .0 N u1 u7 d' 380.65 147.72 tea' .0 C M N CO 0; V. m es 0 .O .ti m M N O N e-', 4` 4 V1 6 N tri c' o a-1 e•1 Q. . W M ^U)U)U)U)U)U)U)U)U)U)U'U)U)IU)U) 0 O t0 t0 as Compound CU IC U J O N O0,N y o g a'y m v 0 V N 0 >, d >.fi Q o m o a x m m o Y -5; 00 x W 0. 4 C 4 G C X W F W X u cJ 0. 0 ›. 2 N H O N N .O 0 .Q 0 v O a v x N M 0. u '1" Q m P N 2 9 - 8 Es ryo v li N O O U A O E r C 0 O A 8 tn O E C N 0 y x O 7 2 o a 'O � y 7 C L Ul � T.; $ 2 • a E o a O O 0 d 8 b e v U �, o d J E x U ▪ N N .0 N 0 11 U) 0' CI e0 a Example Controlled Ethane Hourly Emission Rate (1b/hr) = X C $ so N I c 0 o s c J vo O co L ..0 Example Controlled Ethane Annual Emission Rate (tpy) = L .O O O T C O a. t N C 9 E a N EMISSION CALCULATIONS FOR GLYCOL DEHYDRATOR TEG Dehydrator Vent (ID D-0 VRU Downtime Emissions 4'5 ';' n mcn1- -manes- 0 0 0 0 0 0 0 0 al 0 0 0 0 0 0 4] 4l N I3 4l W ti 0 0 0 0 0 0 N* M pO yN. N N to: rl Ni M iii N. Z m 0 N 0 O t. c6 0 O N N L \ 6 v co M M M M o o N .0 .p d' 0 0 0 0 0 0 0 0 0 0 0 0 0 4l xL V] V] 41 L•] V] al hl Q 0 O m C N CO LO 0 O N Vl W 0 0 0 j• N CO 3x xO N P a n xD O ui m =I N N m 3i P M VI 31 co 0 O 0 eN O P etl ON O P d' a Destruction Efficiency' VN 0 0 0 0 0 0 0 0 0 0 0 0 0 0 V] N in v] in N in N N u] V] in P T P T P P T P T P P P P 0 0 In to P P P in 0 In 0 cg T {y v O O OJ bO N N .00 R .y 6 N m an d' W O' 0' ci W .. h o O T rexM ny con N N •-I IV O O O O a 'N 324.95 16.98 d' a0' 0 01 71 1' a CO Iy m N O] H xO m m M co W O N om m� `Na vi r600o IC I� y U n re; - n, Control Efficiency' (%) 0000000000000000 P P P T P CO P P P P T O. O P P P 0 P Compound ai V PC v3 G y C E N t C u Y G r, 0 8 v pL G R �E fGl = '< +� N v '6 R 0.2 m o a= G -5 t S Ill a. o C 4 C 0 S m F v] X U VOC HAP C R Y 0U P_ N 0 0 P co; G1 O L W co Example Controlled Ethane Hourly Emission Rate [lb/hr) = Y O P 0 T T F EMISSION CALCULATIONS FOR CONDENSATE TANKS Storage Tanks (ID TANKS) Storage Tank Emissions - Condensate Tanks Storage Tank Physical Characteristics O C C 7.4 FMI N O N t =CO 0 .C CO O N is 0 tot C U v m N C U VOC Speciation C C O E U 00044 00 U, O N N U, N O O r -I r-1 i0 N 0 V] 00000c-4 N O 0 M 0+ '000 0 0 0 CO N N W O O O O c -I 0 00 U, O N O d' N n O O r-1 CO O N 0 0 0 0 0 0 0 0 0 0 r4 O cy CO O co co O co co, O O O O co; O O co; O O O O O O O O O O O O O O N N N C' co d' CO N N .d: �0 CO N N M N O O O OJ N on LO N U, C' l0 d' U 0 N d' CO O O O co '0 fN rn O in r O NO ri O N 0J 0 00 0000 N .-I CO ri tit O O CO '0 N N O O O O ,21 O 0 0O h� d' �� 0 0 ri M O N 0 0 m C ro ° a a4.1m a cc 'O co N F P. y'T v 0 O O N N C y !N.'. N y u N'S E N F, N G y y N G X N N C° W N "n m o C m u C C 0 o% t.o >, N =� F C O A C " N .y P. 03 R d a V= !1 ,x0 a+ Q 0 C S.', w U .. W 0. C N C y O C O n CO N N CO F" W X O O N N 1/40 N 0' Cvi 01 01 r oc CC CS C F F F M 0 N N M O 0. OR CONDENSATE TANKS EMISSION CALCULATIONS Storage Tanks (ID TANKS) C- CC Ci O CC c Ct cza cu CC va CJ coa O Controlled s Total VOC Total HAP Emissions Emissions (tVY) (tPY) 1.62 0.25 0.76 0.12 2.38 0.37 Control Efficiency 4 0 0 c Lel Vl CS, CI, N Uncontrolled Total VOC Total HAP Emissions 2 Emissions' (tpY) RPY) 32.41 5.06 15.26 2.38 47.68 7.44 Tank Number d' Z. Uncontrolled Tanks 4.0.9 Emissions 1 (Ib/yr) 16,206.10 7,631.92 0 CO Vi Losses Working Losses Breathing Losses Totals C co A � r w O co O N \ Q. ° v a' as Z C x' R 9 * CC � u v O Q C ao P * o o O o >, o - .y a m E o 3 C G y C. d•E a 'al Ao. U B E > B = Uncontrolled Emissions (tpy) * (100 - Control Efficiency)%. o 0 ° m ya x L cc . 0 II II C h CCC 024 0i . Y > N > 0 o T En 'OC O O -o N a. 0 0 < E v a) 5 au a > ¢ N p N > 0 .y U Ta"O ^ E .6 'e a O o . o C C m O 1-; E. O O > CC > .7 Z O; U N M a 0 C. h Q M CC CC CC CC C co V Uncontrolled' Controlled 2 QPY) RPY) 3.49 0.17 2.59E-03 1.29E-04 0.65 0.03 1.80 0.09 0.13 6.70E-03 1.36 0.07 en O W N- HAP Summary n -hexane 2,2,4 Trimethylpentane Benzene Toluene Ethylbenzene Xylene Total HAP C CC C 6 CC 0 a C C O t P. X CC C 0 �O O C. a 0 O 0 y0 E W 0 v 0 0 0 U a II a >+ o -. E II 0 a ° coti CC C v o 6 S ED a a 0 N a O 'a) N C 0 4, u U Control Efficiency)%. 6 10 b 0 y 0 C 0 C 0 C CC X C N J b W 0 4g o -o a C O L o E On C. s EMISSION CALCULATIONS FOR TRUCK LOADING Truck Loading (ID LOAD) Truck Loading Emissions - VOC Emission Factor Development T EV n x Etc F O J O .0 .0 00 K " mgA iCC 00 0 Material Loaded 0 O a. U Truck Loading Emis On 0 gE 1/40 00 1 Uncontrolled Hourly Em N s S rJ C. 2 m 0 O J. N a .., N b W II ✓ z 0 C . O ' G [o U E 0 E O z x ✓ � 0 0 0 6 0 c E 0 0 a 00 .0 O T L O 0 U • 0 Page 23 of 37 EMISSION CALCULATIONS FOR TRUCK LOADING Controlled Emission Rate 4 I d' Nm Nd m 9 0 9 O m O fs. m N O O 1.7 O. O N 1O 00 1O N rl m H N H CO T O3 1O OO IQ O O N OO OONCCCCC NCCO N d' d' N m N .D .K 1O M m N O lb/hr m m 4 m m m m m O Q i in m o dI .O N N M O 9 O N O N L'1¢1OO W OoOOc.�C] W Rigp.1O 0m to o o 0 0 0 0 C. m is.,.., o o d' O. T M N N N .-1 m co1a7 NO p p Uncontrolled Emission Rate 0, E. 1O m O T so M M O. o O. O t�] W CO n .m -I m 0 0 M N O M Ill N V1 N 0.--1 O .� O ry .. N (f. e. ..0 O Cr. N O rl N N IA P 1l7 ."1 O O V' O m O w.+orn..00N..PCO.�wda.-IthQm G C o O O c; o .-1 4 N L.."'O G O G o. .-1 vi i d' -.O N .1 p o t\ O. T d' CO N Er. N.4 .O m P N m N 1-1 din d' co N m A T .O m I.D a d' m o m d' m O .O ' .O O N CO00 N or. .O O In d. m N . o o m O N N E-.- O ti 0 Cd .l3 O I� 2 d; ti M O C .-I N1 C r N .O N N N O. •'I C O 0 0 L a ge', >. y , _O. m v a M ° A Qy= C1 0 C y L u y 'S , = c1tHIfl < Ca _ C..0 .C 2=e, NNm Fco>< Total VOC Total HAP a W /r P 2 d• 11 O. CO Ca cu Tanks, Loadout and Dehydrator Combustor (ID TANKS, LOAD, D-01) Loadout Input Value Loadout Input Units 92,312.8 lb/yr 66 Ib/Ibmol 1,398.7 Ibmol/yr 519.67 °R 14.7 psia 10.731 530,601 scf/yr 530,601 scf/yr 8,760 hr/yr 60.57 scf/hr Tanks Input Value Tanks Input Units 23,838 Ib/yr/tank 66 Ib/Ibmol 361.18 Ibmol/yr/tank 519.67 °R 14.7 psia 10.731 137,018 scf/yr/tank 4 tanks 548,071 scf/yr 8,760 hr/yr 62.57 scf/hr ! A' Ai \�\\\ ^ I ` 7 \\ 2 0a5 erg \ E EEPL Ea> 7 70 E 143 \ \ tin IL' \\ 0 - rg BTU Calculation for Input into Enclosed Combustor Emissions c4 on a cc 04 en o o 444. 7. igicj a 49 o LI0 cp acr N 41 on EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR Combustion Criteria Pollutant Emission Factors m 0 0. Dehydrator Btu Content Calculation Component Fraction Heat Value (Btu/scf) m Q` 1/40 m N N P to:..O h N '^ .0. N .vi 1797 Pure Component Heat Value (Btu/scf) m a: m N ci P 66 .. . r: In m M T:C m 10 o m: : o' in o v 1. i W o N m:'.ro a' N N m v.0. ise Component Mass Fraction H0lx P d': P O: P C000 O d' 6 060 ?. N :a X. V in O O. Ex 0 0 N'0 in N: V P: ono O P CO 0 a Component Fraction Mol Weight (Ib/Ib-mol) P M 0/ M �c 6 'i .4. 0O.: t O 4 N xi O 'C xi a O N •' N vi xi 6 ix a CO co co Component Molecular Weight (lb/lb-mop X' nO a a d' W N H_ W.. Nnr O .i <:tiO H : N.: a,:o b in N m: S Mol Fraction co 01 N o,. H !ti. m a o CO m m 0 c e e m a a in CP b a.oggo e m in c v coeo m N vii: c y -c. m 4 a. y: co c O Qa U N i C F 41 m m �. m 2 N. c'.v O W CP i C. . Z .:. c is R C 6. S O' C C= m C 7>, i,. F W '',3 it T'-' X O ' Volume % obtained from GRI-GLYCaIc Aggregate Calculations Report, Condenser Vent Stream, dated June 5, 2012. on EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR Annual Emissions NO2 CO N v N O o b O O N O N m O o .- O O N r Hourly Emissions NO, CO L ? 6 .� O o 0 Ft CV O .. m CV 0 O O in N O Hours of Operation (hr/yr) O m O 0 m on, Heat Input (Btu/scf) a no riC a c,1 a, H Input Flowrate (scf/hr) 62,57 in co t ti zo.. G z < 2 O E-• Description Tanks Loadout Dehydrator Gas 5 F emissions, Maximum Potential Hourly Emission Rate (lb/hr) = Input Flowrate (scf/hr) x Vent Gas Heat Input (Btu/scf) x Emission Factor (Ib/MMscf) / (106 scf/MMsct) / Natural Gas Heat A It 0 m N kt S a G 0 A N s SO2 Emissions from Conversion of Hz3 in Dehydrator ICJ W N 0 tri 0 a N 0 T W 0 a In Hydrogen Sulfide O N O O a 0 N L 34.0816/16-mol W V 9 0 c O F GHG EMISSION CALCULATIONS FOR ENCLOSED COMBUSTOR r (ID TANKS, LOAD, D-01) Converted to CO2 0,3 (lb/br) (4➢) Inlet to Combustor' (1b/hr) o.. Number of Carbon Atoms E Carbon Dioxide Ethane Butanes Pentanes + 8" O N_ m O W N O -J U Z O z O O N O Converted to CO,''` o x o Eociu 2 oii. 0 Sz E. eo��A'eg Number of Carbon Atoms z" F E Carbon Dioxide Methane Ethane Propane Butanes Pentanes+ a EMISSION CALCULATIONS FOR FUGITIVES Lucerne 2 Fugitive Emissions (ID FUG2) 2 a Component Type' §§°N§« k(°m}! oo co k Controlled Annual Emission Rate' Light Liquid Gas (tPY) (My) G9§§S ( Controlled Hourly Emission Rate' Light Liquid Gas (lb/hr) (lb/lit) !§]§] 2 Control Fader g22P Totals 8%!\ k! |!§§\§ % i 1k )§§E§§ ) 3 Uncontrolled Hourly Emission Rate Light Liquid Gas (lb/hr) (lb/br) §S5§|§ N0d4 Emission Factor' Light Liquid Gas (kg/hr/source) (kg/hr/source) 4;§°§ §R8a 8?" m�2 a k «.,... §§S5§0 Component Type Connections Flanges Open -Ends Pumps Valves "Others" 2 s EMISSION CALCULATIONS FOR FUGITIVES Corrected Wt ova ��eooeeagf ee Ilnoe UU 3 . �8 ti atition00000 Weight (lb/Ibmole Gas) Mdo666666666 ad Mole Ws (Vol %) 72.456 13.014 05.470 ti Fa p cm Nm 44.0 28.0 Gas Constituent Methane Ethane Tot. Meth/Eth agGsN-- c.__._�ocxmFwxmF Carbon Dioxide Nitrogen Total Total Hydrocarbon LU w Gas Service Speciatlon Uncontrolled Emission Rate lb/hr° tpy' 0000$5ooS0 00^000 000o0,^od0ddddcddddd 0 0 c o c o o dddddodd000ddooddo 0.21 0.90 0.04 0.17 $a i ,N„ MI 3 ° ��e c . OO6O Total HAPs Controlled HAP' u� u a° Ey a u° e 0 oa u i a .1 o x E gg ° o N cum A 9 c e a s R.., t"e s c a s 2 0. 0 0 a, Z S V 41 S L m t l O 0 e g WX V Uncontrolled Emission Rate IY/hr� tpy' V" N'i oopp ro�4 n ohm 0 0 0 0 0 60dm d, ,6 ,3 of d ddddddd o$ O 'n 0 n N S o 0 0 0 0 0 n' o 'N rvnd d.'^. e d'2ddddd a ryry .'mod d 'n e5 N 'y m P a Cl t 3�3'f ggA d o Ogg ro 4g a n d .gym. d Z a g 4 o d d o 0 o Total HAPs Controlled HAP' V 8 9 E a tg Component + j 2-4N 4 Q E^ m% e g m i u C O m v m� aa o�m di � ae � a,�m+ ii C3g 2 ' q�' n0 QS iF W X V 4 a r .0 d a d 2 oc 3n E gW m. a a 2e A� a �n 0 B ^ iJ ■ U^ gg gG . 3a u c ,g 2n E o c.5 g g2 S2 m me me y? A F< ''..O e ti o a u• 8 . po SE qq Q m V 0 u m x > au V $ u 7 8 EMISSION CALCULATIONS FOR FUGITIVES \ VOC7 a',d the VOC rr 0 E a x o do `su°�°xHna�N3:em PROMAX SIMULATION OUTPUT 93 Propane , Mm9. 112 Carbon Ronde Propane n Butane TPenlano P enlane Deplane Toluene Waller PieerazIne NZ Methane P entane HOYMIO 0.1.3117 Benzene Toluene Krione O -%NemHydrogen ulrine Water 1.1029. N2 Carbon Dioxide Methane Elbene Propane Pentane Hapano O utane Bercone Toluono Ethyl' 9.271921 Hyemaen 9ni98n 9,105.9 Pipinanne Carbon Croxide Methane PrOpana T▪ Penbne Peniane Hepten Orions Toluene Hydrogen Sulfide Water METOP 227 Mi]strea94 l Lucerne 2 Elpaniien Trinl[y 0on1ultants 1395535-01 2342915-04 2796220.04 2494135-04 9945935-02 7552190900 2.070.01 1.005+96 2 59.01 4.11201 6.8830, 2.540.1 2265-01 35.830 29.11 7.950902 1 52E+00 6.59202 0599-03 7015-05 7695-02 229.03 2.5-93 1.195.1 2192279. 1.39734503 1.97947504 6.00420004 326545915 5.105360.05 1 71630E. 1.93201926 ..- 2217420-14 48404 1s 9918'0.292823 2329.92. 9.002359 72459009. 57007024. 75.564950 6.928850 1786633 0.405239 0297579. 0.094273. 0.199320 50.019 0010226 O 004275 0000.3' 0000120 17798. 293540 42. 23298. 2 05929. 01358864 ainoncto 0000045 0002194. 0003000 31721. 0000000 1770.99 24.72 291577.10 7340039 12111.66 24970.95 7570.95 7.3.51 4741.79 82.93 192.16 403 3.07 000 306.24 0.09 0.29 4013. 32212527 1 9115' 19595696 0.445T. 427 .17 004.3' 1049269 101.10.1 480620 00015. 24601 0243532. 0.061520. 0000014. 0000145. 0000.0. 0.000022. 0.000031. 0.003030. 003037. 0017219. 0000033. 00455 00909 29 4995 00324 0.575746 O .005117 155.534205 29237973 15.176.495 1.997303 3013996 0955635 0.925776 0.437731 0..5024 O .0.693 0.022405 0.009695 0.030414 0.030369 0.0031 0195263 0.020009 09000022 0.00134. 106745 965499E+00 259994. 009049 1 929148-07 1959965W 2.11572' 1943.84721 0.91302. 542.47327 3910585-02 30229399r 0.31465. 289.65593 9.03423. 43018. 0.00995' 9546342 0.21199. 2420995 1 30199E-03 0.01366. 2324475 329098 000044. 1.0775.9 OM.. 013495 0.00259. 0.43427 1.603175-02 009117. 0 21724 020005. 0.21125 00930. 0.00727 9.00009. 0.2772.1 200.9. 0.03292 9909499. 020.64 026001 2.346240.00 0.05608. 0.77212 5211210.13 2.09.7. 0.00002 202007 incise Page 54 N37 PROMAX SIMULATION OUTPUT be;my^ C'°i"• 3 yid YnMakYGM ky .# R4 4;kH? .. I h H Tot000tont„ 120.0al 76.141 57.8479121 8774763 767 22.700 900.51 72231 B79.5032 Morecula Weight ienernol as.. 22.741022511 25032029911 218750 Motor Flow lianoUh 6,2.643 25253.55585' 34553223031 242152601i U., Flow lioth 3325.722 57453.225 B662051555 521339.6922 Moro Fraction Vapor to0 000 90.40360cm. ICO. 10a0003 DJrz.F,a=tbniore.ry Liquid . 09130 0.1 21.0023 Sal Liquid Volumetric Flow 09pin 88,5,4,, nt„,0„3„2 527505, IS1L"� 40 �t�»mb �`2^Yk➢4"TYSY: SLW%AYZ'. 1 N 1 i ryti N 4 i d. l } N2 4.053160425 0254309 0.05.5015 a232323 Cere. Dioxide 9.2103-101 3.21974B 15050724 0022336 Methane 1.76582021 73 59501 57227024 75.554950 Ethane 7.95725E-02 12.970695 13.955644 1252534 Propane 2228220.2 6 710428 52.102 6.928250 latano 2.0959.02 0835051 0.479717 a8.85377 0Bulone 724252515 4730255 1.57505 058553 i-Pentane 24555.54 0.4222. 3942754 71-517275 Pontine 637737°36 44517°" 071°747 31677°7 lienene 732777044 "77477 3°54777 317757° Heptane 767577°277 71473775 7-372537 0373373 Octane 1.2525.03 005924 550487 0953019 317657035 3340717 3327564 7347775 Toluene 0105 8.5650003 000456 0015959 0(04275 ...one 2.41413.04 550125 0,030323 003012D >x01 tae 2.46545E-04 0.000128 0.000303 0.3 00123 o-xNene 9.12430.05 2.0313047 000543 D.C20015 Hoag., 8.55 124202E-02 2.03471 0.002104 0000000 armor 7.55255-00 a017255 5.468833 0089138 MIDEA 2.949513093 aCICO000 0.000575 0.802002 Pipette 277913E-14 0020200 0O00254 0002500 Nz 922.03 1771.43 054 17705 Carbon Dioxide 25.54 3523422 241.11 24.72 Methane 2.440.oi 221916.86 31721 2815771D Ell.no 2 07E+01 9702434 14504 95559.95 Poop. 9.92E+00 73577.10 705,, 1-Pontono 50200,1 257480 2, 7,, tam 124.0( 4.A.24 100 414578 lieNene 7.3303 71535 am 710.„ (3c5„ I 230_03 8301 002 62.93 Benzene 1. 470000 202 09 1.24 lezie 55797 592.50 102.32 0.51 2174 535330 Eth. 2.54.5 5.11 4.83 017635 221.22 3.31 001 307 0-Xylane 223034 034 3A3 7376737 520.02 1.25 Cial 1.16 752"5344 57'7 2.93E+02 3.99 an 000 777' 1170+03 7213 34 05 32524 1.10041/4 3ME-10 a00 004 0.01 NO 04 ea.252 D.0704 —63-iss Canon 13oride 725.52 a00O285 59703 05218 44745"7 1.52550 1019.5147 1077343 181752360 Elhone Propane 687E-01 2226.7257 4852 3221.2528 2.250.01 1658.5807 1.515 1666.5028 eBulene 1.75.52 2755575 97355 35.3.1 0Buhono 6597.02 420.2455 04457 4293317 i.Pentanc 3590.03 104.4544 a0433 104.2269 373333 5.5505 1043241 57557 15°4. Rua. 232.07 43577 30777 537670 xepene 7340275 72251 03°45 77755 0dene 4356275 17777° 07767 07767 357°47 47405 33755 13757 413367417 2.08E-03 00312 a025I 00283 "71337 2.13E-03 00318 O 0031 00295 o.Xylene 0750n5ul0tle 727E-04 00118 00230 00103 1,51 01170 00008 00001 Wotor 6.51.51 4.3925 12923 21.4395 pip, no, 0.08 00280 0➢`3<4 712 3.19227.06 05:5923 0.0CCI76 0.575726 Methane 1 „7„E.2 185752222 0 4.095 16522,205 Etrya„, 222275.25 52225213 0043232 .0237923 pa, 2349220.33 10.5813 00.439 455.53 lat.. 1.57147.04 1.85556 a001510 1.897923 95.57 5.0045.04 3.95518 0.004059 3.313B3G 7.66737 3.26545095 0956152 a0a31.49 0055635 Pentono 51055E-05 0942428 0020544 0.925776 674707 1.841440425 0039065 a000202 a.7731 Peptone 625161027 0063075 0000014 0055024 '773°7 17530003 0024275 0000145 05258 7376" 6.91105.61 0.01054 0.200250 0.05235 5227 ni-5/510 2.17489E -D5 0025428 a000002 al:50414 1.87537.05 0.0001M +000001 2.7054 05.75 1.53721.75 0.0.200 a200.7 2.755 O-Xylene 7.153093-06 00.57 0000232 0.0n100 Hydrogen Wide 1058290ES 0.00100d 0D 00707 0020201 alater 522347E-01 005025 0017212 0195283 NIDE+ 0.51742542 73.700 47..65 17.77.7 30717207 35545545 0.00,10,0 0050507 337752 DC? 00125.51wam Ine2 &pannpn Trinity Consultants Pap 35 of PROMAX SIMULATION OUTPUT "2 Cath93 0173M7 2222"Ee rthr Empene 1.9thas n-lthane thenthe Pentane throw He 41004 Othne thio,,,E ithiene Bethene, Ethyl- 4704340 p..80,„ na(Mene 150700Suthe 000 1.001 procrozino 2.43256005 B554502.01 1.62914001 1.15966E-01 3.91059E-02 3051000 12019002 027203004 1201OE-03 024515E-04 W2533O03 3.49274036 322657E-02 1.60317002 601409E-0 5.08714E-04 5014780.04 1.3O37E-04 98094SE-CO 2.3462000 112-11-13 1.1810013 00280 0.00134 430745 456.185.26 058984 0.060.19 19401109 21102 194324735 544.39653 0.61382 543.47327 2010473 03105 23065503 43.0595 0M423 4311100 0.5700 0.088s5 83.46042 24.22im 0OI133 2420e06 23.0135 001335 2324475 12.47753 0.00576 12.46323 107960 0.00044 W7782 02305 03005 023465 0.47030 0000 043427 0.23462 omit] 021724 0.01172 0.00305 001100 0.00762 000203 0.00707 0.03730 000003 0.00724 0.0320 0.0001 000222 0.3293.3 0.00006 000001 0.15519 00680 077212 0.000 000007 000002 000DB0 002:00 020.05,3 is i "h ,`"� 'a Fain �� ti C• '� x -' 2313013.13 120030 78.14 15707912 00763 Phew.° polo an 20720 800.5 72.33 079.530D in thiethth itheth 9454 00343 4.45103.092I 712700212 0002 24805.56277 3452392309 14020011 Math Flow ibm 00070 55$917.7131 265.2001065 5213306322 22222F2"222 V22E2 % ID.. 100 IOD 10011000 Mess Emotion ithoy Liquid N. 0000 0 00000 IdealItho3 414,77090791047140 now 3131$3911 Nal Gas H741203480 B 91iAfl�6.•+�W'gpn 7.357 20403032 0.31470384 2190622 1149.73509 937.9575326 .1ZS��,IAieC FR. .i - 0.0408997 Carbon 001.0 2.12B4736 Methane 200039113 30,500 152955204 3439700 105206B N308700 4.3304763 3700000 11.7710 fhPentano 52220371 Pathan 6.0633519 Pexan n. 8971503 Octane 04532576 Bowe. 0354405 Www 035050 0097037. 0145 00327841 04,71757 00240162 0"7.1233 0.023305 "22529 .maa 00002291 "kb" 0.010705 MEW Plperazina W00000 0.0000300 4.44539 Carbon Diorlda 283.44500 Methane 1623.5570 Ethane 170.1302 Propano 31912701B thatene 961.07566 nalano 200041B thantano 146202005 Pontano 107.4805 Hexane 230.0039 rvagann oc;th 790.03422 20309221 ththene 107.40916 thth„ 130.0100 Betheno Ethyl- 13.50440 m.40834 9.89342 p.Xyl¢ne 9.5M53 0Xylene 4.03173 NWhnoan Sulfide 0011319 181310r 07527a MIDEA 0.00000 PipS1,01E1 000000 58858.53381;1144553.5811851 .Y!Lmt5zx 30 354,040,2.0 0 0.2393305 Molhano 101.20377W Ethane 59.705739 Propane 72 7.947 H291007 16.8795547 050.3119 45092i009 2238171° 20200602 "Pt". 235273259 Hexane rvegam 27.0501046 7.6047186 00.00 1.7720079 Bormene 1.37009 Toluene 1.4143386 i3.48409.01571. 0.1272023 othylene 0.0931091 Ethylene 0.0825287 0thlene uyareom Sulfide 0.0370701 Water 00417577 NIDEA 0.0020000 310,4375,5 0.0000200 DCP midstream Ewen, 2 Exnansion Trinity consultants 7210 36 07 37 PROMAX SIMULATION OUTPUT K rmI Carbon Donde Methane Ethane Propane larene nnenbne Perlone Hexane Octane Bonnane Toluene t yi nm▪ rne gens.nm. Plater MOOS Pepernerne Carbon 046150 Methane Plhane Propane 000.00 Heplane Octane TellIene • thy axN e• s • Ylene Hydrogen aide ODES Pernino PrC9911 pale Meleculen md Ikahmel • nsiry abler Flop Mass nlow Mole Radian Paper Mass Fracfien Henry Liquid 815 Yap, Velurnel1e Flew MMSC.FD Het Ide Gas H044970158 Ell4117 0001945271 0.005113005 0.021720130 0514031188 0.153732711 0416201317 0.141556323 0.214278140 0.248360013 0.013193435 0.011512617 0012505925 0.001190100 000032732 0000343238 0000345871 040002.30 0.000300114 0.040000100 • 0.83910987 1482301642 1007794249 1117545139 3.98955641 908579389 7 01737405 1.10487041 0 57963235 024273537 020091359 0.03097026 002270413 0.00911163 0.00151355 3160044255 3004930336 17375.58569 67.5247296 1-291 946717 VfMN 0CP 41stream I Luacmo 2 0869044 Trinity Consultants Page 37 Of 37 Page: 1 GRI-GLYCalc VERSION 4.0 - AGGREGATE CALCULATIONS REPORT Case Name: Lucerne 230 MMSCFD TEG Dehydration Unit (40 GPM) File Name: U:\CLIENTS\DCP Midstream\120601.0002 Prairie Plant PSD\Project\Received\2012 0927 Revised Fugitives and Dehy Data\TEG Dehy for Lucerne Plant 230 MMSCFD (overheads to tank combustor 9-26-12).ddf Date: October 02, 2012 DESCRIPTION: Description: 230 MMSCFG TEG Dehydration Unit (40 GPM) w/ recycled flash tank Still vent condenser 95 °a control on still vent through combustion using an enclosed combustor Annual Hours of Operation: 8760.0 hours/yr EMISSIONS REPORTS: CONTROLLED REGENERATOR EMISSIONS Component lbs/hr lbs/day tons/yr Hydrogen Sulfide <0.0001 <0.001 <0.0001 Methane 0.2128 5.106 0.9319 Ethane 0.5169 12.405 2.2638 Propane 0.9805 23.531 4.2945 Isobutane 0.2489 5.974 1.0903 n -Butane 0.7475 17.941 3.2743 Isopentane 0.2199 5.278 0.9633 n -Pentane 0.2941 7.058 1.2880 n -Hexane 0.2977 7.146 1.3041 Heptanes 0.1033 2.478 0.4523 Benzene 0.7725 18.541 3.3837 Toluene 0.5030 12.072 2.2032 Ethylbenzene 0.0323 0.775 0.1415 Xylenes 0.0672 1.613 0.2945 C8+ Heavies 0.0642 1.541 0.2813 Total Emissions 5.0609 Total Hydrocarbon Emissions Total VOC Emissions Total HAP Emissions Total BTEX Emissions UNCONTROLLED REGENERATOR EMISSIONS 5.0609 4.3312 1.6728 1.3751 121.461 22.1666 121.461 103.950 40.148 33.002 22.1666 18.9708 7.3270 6.0228 Component lbs/hr lbs/day tons/yr Hydrogen Sulfide <0.0001 0.001 0.0001 Methane 4.2562 102.148 18.6420 Ethane 10.3394 248.145 45.2864 Propane 19.6145 470.748 85.9116 Isobutane 4.9791 119.500 21.8087 n -Butane 14.9536 358.886 65.4966 Isopentane 4.3991 105.578 19.2680 n -Pentane 5.8820 141.168 25.7631 n -Hexane Heptanes Benzene Toluene Ethylbenzene Xylenes C8+ Heavies 5.9555 2.0653 15.6197 10.1452 0.6499 1.3553 1.2845 142.932 49.568 374.872 243.485 15.597 32.527 30.829 Page: 2 26.0851 9.0461 68.4141 44.4359 2.8464 5.9362 5.6263 Total Emissions Total Hydrocarbon Emissions Total VOC Emissions Total HAP Emissions Total BTEX Emissions FLASH GAS EMISSIONS 101.4992 101.4992 86.9037 33.7255 27.7700 2435.982 444.5667 2435.981 2085.689 809.412 666.480 444.5666 380.6382 147.7177 121.6326 Note: Flash Gas Emissions are zero with the Recycle/recompression control option. FLASH TANK OFF GAS Component lbs/hr lbs/day tons/yr Hydrogen Sulfide Methane Ethane Propane Isobutane n -Butane Isopentane n -Pentane n -Hexane Heptanes Benzene Toluene Ethylbenzene Xylenes C8+ Heavies <0.0001 47.1371 38.8351 36.2708 6.8639 16.5222 4.6398 5.1594 3.2983 0.6405 0.3798 0.1804 0.0075 0.0112 0.2155 <0.001 1131.290 932.042 870.498 164.733 396.534 111.354 123.826 79.159 15.372 9.116 4.330 0.181 0.269 5.172 <0.0001 206.4605 170.0977 158.8660 30.0638 72.3674 20.3221 22.5983 14.4466 2.8054 1.6636 0.7903 0.0330 0.0490 0.9438 Total Emissions Total Hydrocarbon Emissions Total VOC Emissions Total HAP Emissions Total BTEX Emissions 160.1615 160.1615 74.1893 3.8773 0.5790 COMBINED REGENERATOR VENT/FLASH GAS EMISSIONS 3843.877 701.5075 3843.876 1780.544 93.055 13.896 701.5074 324.9493 16.9825 2.5359 Component lbs/hr lbs/day tons/yr Hydrogen Sulfide Methane Ethane Propane Isobutane n -Butane Isopentane n -Pentane <0.0001 0.2128 0.5169 0.9805 0.2489 0.7475 0.2199 0.2941 <0.001 5.106 12.405 23.531 5.974 17.941 5.278 7.058 <0.0001 0.9319 2.2638 4.2945 1.0903 3.2743 0.9633 1.2880 Page: 3 n -Hexane 0.2977 7.146 1.3041 Heptanes 0.1033 2.478 0.4523 Benzene 0.7725 18.541 3.3837 Toluene 0.5030 12.072 2.2032 Ethylbenzene 0.0323 0.775 0.1415 Xylenes 0.0672 1.613 0.2945 C8+ Heavies 0.0642 1.541 0.2813 Total Emissions 5.0609 Total Hydrocarbon Emissions Total VOC Emissions Total HAP Emissions Total BTEX Emissions 5.0609 4.3312 1.6728 1.3751 121.461 22.1666 121.461 103.950 40.148 33.002 COMBINED REGENERATOR VENT/FLASH GAS EMISSION CONTROL REPORT: 22.1666 18.9708 7.3270 6.0228 Component Uncontrolled Controlled s Reduction tons/yr tons/yr Hydrogen Sulfide <0.0001 <0.0001 96.02 Methane 225.1025 0.9319 99.59 Ethane 215.3841 2.2638 98.95 Propane 244.7775 4.2945 98.25 Isobutane 51.8725 1.0903 97.90 n -Butane 137.8641 3.2743 97.63 Isopentane 39.5902 0.9633 97.57 n -Pentane 48.3614 1.2880 97.34 n -Hexane 40.5316 1.3041 96.78 Heptanes 11.8515 0.4523 96.18 Benzene 70.0777 3.3837 95.17 Toluene 45.2262 2.2032 95.13 Ethylbenzene 2.8794 0.1415 95.09 Xylenes 5.9852 0.2945 95.08 O8+ Heavies 6.5701 0.2813 95.72 Total Emissions 1146.0742 Total Hydrocarbon Emissions Total VOC Emissions Total HAP Emissions Total BTEX Emissions EQUIPMENT REPORTS: 1146.0740 705.5875 164.7002 124.1685 22.1666 98.07 22.1666 98.07 18.9708 97.31 7.3270 95.55 6.0228 95.15 CONDENSER AND COMBUSTION DEVICE Condenser Outlet Temperature: 160.00 deg. F Condenser Pressure: 13.30 psia Condenser Duty: 4.19e-001 MM BTU/hr Produced Water: 52.84 bbls/day Ambient Temperature: 0.00 deg. F Excess Oxygen: 0.00 % Combustion Efficiency: 95.00 % Supplemental Fuel Requirement: 4.19e-001 MM BTU/hr Page: 4 Component Emitted Destroyed Hydrogen Sulfide 4.95% 95.05% Methane 5.00% 95.00% Ethane 5.00% 95.00% Propane 5.00% 95.00% Isobutane 5.00% 95.00% n -Butane 5.00% 95.00% Isopentane 5.00% 95.00% n -Pentane 5.00% 95.00% n -Hexane 5.00% 95.00% Heptanes 5.00% 95.00% Benzene 4.95% 95.05% Toluene 4.96% 95.04% Ethylbenzene 4.97% 95.03% Xylenes 4.96% 95.04% C8+ Heavies 5.00% 95.00% ABSORBER Calculated Absorber Stages: 1.31 Specified Dry Gas Dew Point: 5.00 lbs. H2O/MMSCF Temperature: 110.0 deg. F Pressure: 850.0 psig Dry Gas Flow Rate: 230.0000 MMSCF/day Glycol Losses with Dry Gas: 6.9260 lb/hr Wet Gas Water Content: Saturated Calculated Wet Gas Water Content: 87.38 lbs. H2O/MMSCF Calculated Lean Glycol Recirc. Ratio: 3.04 gal/lb H2O Remaining Absorbed Component in Dry Gas in Glycol Water 5.71% 94.29% Carbon Dioxide 99.80% 0.20% Hydrogen Sulfide 98.81% 1.19% Nitrogen 99.98% 0.02% Methane 99.98% 0.02% Ethane 99.95% 0.05% Propane 99.93% 0.07% Isobutane 99.91% 0.09% n -Butane 99.88% 0.12% Isopentane 99.89% 0.11% n -Pentane 99.86% 0.14% n -Hexane 99.79% 0.21% Heptanes 99.64% 0.36% Benzene 92.08% 7.92% Toluene 89.63% 10.37% Ethylbenzene 87.05% 12.95% Xylenes 82.32% 17.68% C8+ Heavies 98.85% 1.15% FLASH TANK Flash Control: Recycle/recompression Flash Temperature: 175.0 deg. F Flash Pressure: 87.3 psig Left in Removed in Page: 5 Component Glycol Flash Gas Water 99.92% 0.08% Carbon Dioxide 43.87% 56.13% Hydrogen Sulfide 80.43% 19.57% Nitrogen 8.04% 91.96% Methane 8.28% 91.72% Ethane 21.03% 78.97% Propane 35.10% 64.90% Isobutane 42.04% 57.96% n -Butane 47.51% 52.49% Isopentane 48.92% 51.08% n -Pentane 53.50% 46.50% n -Hexane 64.53% 35.47% Heptanes 76.45% 23.55% Benzene 97.74% 2.26% Toluene 98.39% 1.61% Ethylbenzene 98.97% 1.03% Xylenes 99.29% 0.71% C8+ Heavies 87.37% 12.63% REGENERATOR No Stripping Gas used in regenerator. Component Remaining Distilled in Glycol Overhead Water 22.18% 77.82% Carbon Dioxide 0.00% 100.00% Hydrogen Sulfide 0.00% 100.00% Nitrogen 0.00% 100.00% Methane 0.00% 100.00% Ethane 0.00% 100.00% Propane 0.00% 100.00% Isobutane 0.00% 100.00% n -Butane 0.00% 100.00% Isopentane 1.02% 98.98% n -Pentane 0.93% 99.07% n -Hexane 0.77% 99.23% Heptanes 0.65% 99.35% Benzene 5.12% 94.88% Toluene 8.03% 91.97% Ethylbenzene 10.52% 89.48% Xylenes 13.03% 86.97% C8+ Heavies 13.79% 86.21% STREAM REPORTS: WET GAS STREAM Temperature: 110.00 deg. F Pressure: 864.70 psia Flow Rate: 9.60e+006 scfh Page: 6 Component Conc. Loading (volo) (lb/hr) Water 1.84e-001 8.39e+002 Carbon Dioxide 2.33e-003 2.60e+001 Hydrogen Sulfide 2.53e-007 2.18e-003 Nitrogen 2.63e-001 1.86e+003 Methane 7.55e+001 3.06e+005 Ethane 1.34e+001 1.02e+005 Propane 6.92e+000 7.73e+004 Isobutane 8.66e-001 1.27e+004 n -Butane 1.78e+000 2.63e+004 Isopentane 4.36e-001 7.96e+003 n -Pentane 4.22e-001 7.71e+003 n -Hexane 2.00e-001 4.35e+003 Heptanes 2.97e-002 7.52e+002 Benzene 1.02e-002 2.02e+002 Toluene 4.27e-003 9.96e+001 Ethylbenzene 1.89e-004 5.08e+000 Xylenes 2.88e-004 7.73e+000 C8+ Heavies 3.02e-003 1.30e+002 Total Components 100.00 5.49e+005 DRY GAS STREAM Temperature: Pressure: Flow Rate: 110.00 deg. F 864.70 psia 9.58e+006 scfh Component Conc. Loading (volts) (lb/hr) Water 1.05e-002 4.79e+001 Carbon Dioxide 2.33e-003 2.59e+001 Hydrogen Sulfide 2.50e-007 2.15e-003 Nitrogen 2.63e-001 1.86e+003 Methane 7.56e+001 3.06e+005 Ethane 1.34e+001 1.02e+005 Propane 6.93e+000 7.72e+004 Isobutane 8.67e-001 1.27e+004 n -Butane 1.79e+000 2.62e+004 Isopentane 4.36e-001 7.95e+003 n -Pentane 4.22e-001 7.70e+003 n -Hexane 2.00e-001 4.35e+003 Heptanes 2.96e-002 7.49e+002 Benzene 9.43e-003 1.86e+002 Toluene 3.84e-003 8.93e+001 Ethylbenzene 1.65e-004 4.42e+000 Xylenes 2.37e-004 6.36e+000 C8+ Heavies 2.99e-003 1.29e+002 Total Components 100.00 5.47e+005 LEAN GLYCOL STREAM Temperature: 110.00 deg. F Flow Rate: 4.00e+001 gpm Component Conc. Loading Page: 7 (wt%) (lb/hr) TEG 9.90e+0o1 2.23e+004 Water 1.00e+000 2.25e+002 Carbon Dioxide 2.34e-014 5.26e-012 Hydrogen Sulfide 1.15e-017 2.59e-015 Nitrogen 1.59e-013 3.57e-011 Methane 7.66e-018 1.73e-015 Ethane 1.03e-007 2.32e-005 Propane 1.O1e-008 2.27e-006 Isobutane 1.58e-009 3.55e-007 n -Butane 3.47e-009 7.81e-007 Isopentane 2.02e-004 4.54e-002 n -Pentane 2.46e-004 5.55e-002 n -Hexane 2.06e-004 4.65e-002 Heptanes 6.04e-005 1.36e-002 Benzene 3.74e-003 8.42e-001 Toluene 3.93e-003 8.86e-001 Ethylbenzene 3.39e-004 7.64e-002 Xylenes 9.O1e-004 2.03e-001 C8+ Heavies 9.12e-004 2.05e-001 Total Components 100.00 2.25e+004 RICH GLYCOL STREAM Temperature: 110.00 deg. F Pressure: 864.70 psia Flow Rate: 4.21e+001 gpm NOTE: Stream has more than one phase. Component Conc. Loading (wt%) (lb/hr) TEG 9.46e+001 2.23e+004 Water 4.31e+000 1.02e+003 Carbon Dioxide 2.23e-004 5.26e-002 Hydrogen Sulfide 1.10e-007 2.59e-005 Nitrogen 1.51e-003 3.57e-001 Methane 2.18e-001 5.14e+001 Ethane 2.09e-001 4.92e+001 Propane 2.37e-001 5.59e+001 Isobutane 5.02e-002 1.18e+001 n -Butane 1.34e-001 3.15e+001 Isopentane 3.85e-002 9.08e+000 n -Pentane 4.71e-002 1.11e+001 n -Hexane 3.94e-002 9.30e+000 Heptanes 1.15e-002 2.72e+000 Benzene 7.14e-002 1.68e+001 Toluene 4.76e-002 1.12e+001 Ethylbenzene 3.11e-003 7.34e-001 Xylenes 6.66e-003 1.57e+000 C8+ Heavies 7.23e-003 1.71e+000 Total Components 100.00 2.36e+004 FLASH TANK OFF GAS STREAM Temperature: 175.00 deg. F Pressure: 102.00 psia Page: 8 Flow Rate: 2.16e+003 scfh Component Conc. Loading (vol%) (lb/hr) Water 7.44e-001 7.63e-001 Carbon Dioxide 1.18e-002 2.95e-002 Hydrogen Sulfide 2.61e-006 5.07e-006 Nitrogen 2.05e-001 3.28e-001 Methane 5.16e+001 4.71e+001 Ethane 2.27e+001 3.88e+001 Propane 1.44e+001 3.63e+001 Isobutane 2.07e+000 6.86e+000 n -Butane 4.99e+000 1.65e+001 Isopentane 1.13e+000 4.64e+000 n -Pentane 1.25e+000 5.16e+000 n -Hexane 6.72e-001 3.30e+000 Heptanes 1.12e-001 6.40e-001 Benzene 8.53e-002 3.80e-001 Toluene 3.44e-002 1.80e-001 Ethylbenzene 1.24e-003 7.53e-003 Xylenes 1.85e-003 1.12e-002 C8+ Heavies 2.22e-002 2.15e-001 Total Components 100.00 1.61e+002 FLASH TANK GLYCOL STREAM Temperature: 175.00 deg. F Flow Rate: 4.18e+001 gpm Component Conc. Loading (wt%) (lb/hr) TEG 9.52e+001 2.23e+004 Water 4.34e+000 1.02e+003 Carbon Dioxide 9.86e-005 2.31e-002 Hydrogen Sulfide 8.90e-008 2.08e-005 Nitrogen 1.22e-004 2.87e-002 Methane 1.82e-002 4.26e+000 Ethane 4.42e-002 1.03e+001 Propane 8.38e-002 1.96e+001 Isobutane 2.13e-002 4.98e+000 n -Butane 6.39e-002 1.50e+001 Isopentane 1.90e-002 4.44e+000 n -Pentane 2.54e-002 5.94e+000 n -Hexane 2.56e-002 6.00e+000 Heptanes 8.88e-003 2.08e+000 Benzene 7.03e-002 1.65e+001 Toluene 4.71e-002 1.10e+001 Ethylbenzene 3.10e-003 7.26e-001 Xylenes 6.66e-003 1.56e+000 C8+ Heavies 6.36e-003 1.49e+000 Total Components 100.00 2.34e+004 FLASH GAS EMISSIONS Control Method: Recycle/recompression Control Efficiency: 100.00 Page: 9 Note: Flash Gas Emissions are zero with the Recycle/recompression control option. REGENERATOR OVERHEADS STREAM Temperature: 212.00 deg. F Pressure: 14.70 psia Flow Rate: 1.74e+004 scfh Component Conc. Loading (vol%) (lb/hr) Water 9.57e+001 7.90e+002 Carbon Dioxide 1.14e-003 2.31e-002 Hydrogen Sulfide 1.33e-006 2.08e-005 Nitrogen 2.23e-003 2.87e-002 Methane 5.79e-001 4.26e+000 Ethane 7.50e-001 1.03e+001 Propane 9.70e-001 1.96e+001 Isobutane 1.87e-001 4.98e+000 n -Butane 5.61e-001 1.50e+001 Isopentane 1.33e-001 4.40e+000 n -Pentane 1.78e-001 5.88e+000 n -Hexane 1.51e-001 5.96e+000 Heptanes 4.49e-002 2.07e+000 Benzene 4.36e-001 1.56e+001 Toluene 2.40e-001 1.01e+001 Ethylbenzene 1.33e-002 6.50e-001 Xylenes 2.78e-002 1.36e+000 C8+ Heavies 1.64e-002 1.28e+000 Total Components 100.00 8.92e+002 CONDENSER PRODUCED WATER STREAM Temperature: 160.00 deg. F Flow Rate: 1.54e+000 gpm Component Conc. Loading (wt%) (lb/hr) (ppm) Water 1.00e+002 7.71e+002 999634. Carbon Dioxide 9.75e-006 7.52e-005 0. Hydrogen Sulfide 2.94e-008 2.27e-007 0. Nitrogen 4.13e-007 3.18e-006 0. Methane 1.08e-004 8.30e-004 1. Ethane 2.79e-004 2.15e-003 3. Propane 6.67e-004 5.15e-003 7. Isobutane 8.85e-005 6.83e-004 1. n -Butane 3.38e-004 2.61e-003 3. Isopentane 6.64e-005 5.12e-004 1. n -Pentane 9.32e-005 7.18e-004 1. n -Hexane 7.27e-005 5.61e-004 1. Heptanes 1.33e-005 1.03e-004 0. Benzene 2.19e-002 1.69e-001 219. Toluene 1.10e-002 8.48e-002 110. Ethylbenzene 5.03e-004 3.88e-003 5. Xylenes 1.39e-003 1.07e-002 14. C8+ Heavies 2.28e-006 1.76e-005 0. Page: 10 Total Components 100.00 7.71e+002 1000000. CONDENSER RECOVERED OIL STREAM Temperature: 160.00 deg. F The calculated flow rate is less than 0.000001 #mol/hr. The stream flow rate and composition are not reported. CONDENSER VENT STREAM Temperature: 160.00 deg. F Pressure: 13.30 psia Flow Rate: 1.16e+003 scfh Component Conc. Loading (vol%) (lb/hr) Water 3.57e+001 1.97e+001 Carbon Dioxide 1.71e-002 2.30e-002 Hydrogen Sulfide 1.98e-005 2.06e-005 Nitrogen 3.35e-002 2.87e-002 Methane 8.68e+000 4.26e+000 Ethane 1.12e+001 1.03e+001 Propane 1.45e+001 1.96e+001 Isobutane 2.80e+000 4.98e+000 n -Butane 8.42e+000 1.50e+001 Isopentane 1.99e+000 4.40e+000 n -Pentane 2.67e+000 5.88e+000 n -Hexane 2.26e+000 5.95e+000 Heptanes 6.74e-001 2.07e+000 Benzene 6.47e+000 1.55e+001 Toluene 3.57e+000 l.0le+001 Ethylbenzene 1.99e-001 6.46e-001 Xylenes 4.14e-001 1.34e+000 C8+ Heavies 2.47e-001 1.28e+000 Total Components 100.00 1.21e+002 COMBUSTION DEVICE OFF GAS STREAM Temperature: 1000.00 deg. F Pressure: 14.70 psia Flow Rate: 3.72e+001 scfh Component Conc. Loading (vol%) (lb/hr) Hydrogen Sulfide 3.08e-005 1.03e-006 Methane 1.35e+001 2.13e-001 Ethane 1.75e+001 5.17e-001 Propane 2.27e+001 9.80e-001 Isobutane 4.37e+000 2.49e-001 n -Butane 1.31e+001 7.48e-001 Isopentane 3.11e+000 2.20e-001 n -Pentane 4.15e+000 2.94e-001 n -Hexane 3.52e+000 2.98e-001 Heptanes 1.05e+000 1.03e-001 Page: 11 Benzene l.ole+001 7.73e-001 Toluene 5.56e+000 5.03e-001 Ethylbenzene 3.10e-001 3.23e-002 Xylenes 6.45e-001 6.72e-002 C8+ Heavies 3.84e-001 6.42e-002 Total Components 100.00 5.06e+000 to a OJ in4 0 bilized Condensate C CO CO 01 0 0 U, N CD O rn F- t x m 0 N 0 C to F- to 0 a C 0 a N 0 0 0 0 r 0 0 00.-0qLO CO '-Na-� O)a-N CO Ov 04 0 - O Fa v n o v 00 00 Ear mam O�LLa a 0 2 U E -0» 00 s .0 01 0) J J O j O Z O'O'O' 0 0 co co co co O O CO CO O O O O Orn C13 \ K 00,a O L^ mT fN}"6 "O co C ON 07 F2 5a CO 0mE - 000 CO :, me y0-. C c.�::sSo L� ��o�o m 0 CO m Ott O Oc C TF O N o i ?= U 0 O C co N O a O o d O N _6 O) O Y @ U U 0 0 rts 0 U E ra UU ...En N EOE�]CN (6 LNNOO L.d 010- GIUN 4= en `-' OT UJ OL67„3JO0d~ ULLOO UTNO .c@i1 G N U co (.J F O Y (n U J Q i F Z y L CI) CO Cr CC 0 H S CO ca i a 0 to 0 PO F- d re m Meterological Data used in Emissions Calculations: Denver, Colorado (Avg Atmospheric Pressure = 12.12 psia) file://C:\Program Files \Tanks409d\summarydisplay.htm TANKS 4.0.9d t 0 H C C H 0 0 'S 0 x Cu e) t 7 N co Co C d B C O U V N O - R .6 O R _ y O - - > o > o m 0 Option 4: RVP=10, ASTM Slope=3 N m2 o 6 O 0"PPE- m v Mixture/Component file://C:AProgram Files \Tanks409d\summarydisplay.htm ct TANKS 4.0.9d § ) co \\ �o §g to % § u \ ) / G s- oo \ o —o tions (AP -42) Annual Emission Calcaulatio 0000 000000 MOON MO ONm IOVM OQO MNOMM ON 000 =Laws 2 Egff\ ono_ on _R. ccaane LL881220-0',” '082 file://C:\Program Files \Tanks409d\summarydisplay.htm CIO NOCOCIL0000 Co COI ei al cr CV Total Losses (lb): file ://C*Program Files \Tanks409d\summarydisplay.htm TANKS 4.0.9d t O O cf f0 N u_ F - C l6 O d N O ._ E it IL C. c CL) co CC I -- N C � O N N ! c c c H W — o ce a d IL U_ a. Gl C) N C N 0 O U L N O II O Emissions Report for: Annual Total Emissions 0 01 L w m` J m 0 o N O CO CO M 0, M r Gasoline (RVP 10) M_ O file://C:\Program Files\Tanks409d\summarydisplay.htm 6. ATTACHMENT D - FORM APCD-101 Company Contact Information DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 6-1 Form APCD-101 Colorado Department of Public Health and Environment Air Pollution Control Division Company Contact Information Form Ver. September 10, 2008 Company Name: DCP Midstream, LP Source Name: Coloratto Dtparunent of Public Fieakh aid. giwirolinent Lucerne Natural Gas Processing Plant - Lucerne 2 Expansion Permit t Contact : Dana Stephens Address: 370 17th Street, Suite 2500 Street Denver CO 80202 City State Zip Phone Number: (303) 605-1745 Fax Number: (303) 605-1957 E-mail: DStephens@dcpmidstream.com Billing Contact: (Permit Fees Dana Stephens Address: See Permit Contact Street City State Lip Phone Number: Fax Number: E-mail: Compliance Contact': Jill Thornberry Address: 3026 4TH Avenue Street Greeley CO 80631 City State Zip Phone Number: (970) 378-6385 Fax Number: (303) 572-3516 E-mail: JMThornberry@dcpmidstream.com Billing Contact (Annual Fees) 4 Dana Stephens Address: See Permit Contact Street Ci State Zi Phone Number: Fax Number: E-mail: Check how would you like to receive your permit fee invoice? Mail: Ei E-mail: Fax: ❑ Footnotes: The permit contact should be the point of contact for technical information contained in the permit application. This may be a company representative or a consultant. 2 The compliance contact should be the point of contact for discussing inspection and compliance at the permitted facility. 3 The billing contact (Permit fees) should be the point of contact that should receive the invoice for fees associated with processing the permit application & issuing the permit. (Reg. 3, Part A, Section VI.B) 4 The billing contact (Annual fees) should be the point of contact that should receive the invoices issued on an annual basis for fees associated with actual emissions reported on APENs for the facility. (Reg. 3, Part A, Section VI.C) Page 1 of 1 FormAPCD-101-CompanyContactInfo-Ver.9-10-2008v1.2 7. ATTACHMENT E - AMBIENT AIR IMPACT ANLAYSIS The Colorado Department of Public Health and Environment Colorado Modeling Guideline for Air Quality Permits, dated August 20, 2010, states that the preliminary air impact analysis for construction permit applications can be done using quantitative (modeling) or qualitative (non -modeling) methods.2° Table 1 of the guidance, Modeling Thresholds, describes that modeling is usually warranted for sources that meet any of the following criteria: > CO emissions equal to or greater than 100 tons per year (tpy); • NOx emissions equal to or greater than 40 tpy; > SO2 emissions equal to or greater than 40 tpy; PMi° emissions equal to or greater than 15 tpy; PM2.s emissions equal to or greater than 5 tpy; • Lead emissions equal to or greater than 25 pounds per 3 -month; > Sources where a substantial portion of the new or modified emissions have poor dispersion characteristics (e.g., rain caps, horizontal stacks, fugitive releases, or building downwash) in close proximity to ambient air at the site boundary; > Sources located in complex terrain (e.g., terrain above stack height in close proximity to the source); > Sources located in areas with poor existing air quality; and, > Modifications at existing major sources, including grandfathered sources that have never been modeled before. As shown in Table 1-4 located in Section 1 of this application, all emission increases associated with this project will be below the modeling thresholds outlined in Table 1 of CDPHE's Modeling Guideline and none of the other criteria are applicable to this modification. Therefore, no further analysis is needed at this time. 20 http://www.colorado.gov/airquality/permits/guide.pdf DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 7-1 8. ATTACHMENT F - FORM APCD-102 Facility Wide Emission Inventory DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 8"1 1 Form APCD-102 Company Source Source AI Colorado Department oPublic Health . andFnvitar(mmt AIRS 10 Egdpuent Description P037 Fugitive Uri/minim 123/01(7/014 123/0107/015 123/0107/017 123/0107/01B 12310107/019 123/0107/024 123/0107/025 123/0107/D29 123/0107/932 123/0107/033 121/0107/0.12 123/0107/013 C-106 Wait 17012 GSI 1,212 HP C-110 Munk L7042 GSI 1.232 HP C -I07 Wank 17042 09I 1232 HP C-109 Wank L7042 GSI 1,23213? C-112 Wool L7042 GSI 1332 HP C-113 Wmuk1.7042GSP 1.232 HP C -log Wank L7042 GS1 1,232 HP C-103 Wank L7042 GM 1,478 HP HAP., 116s/vr) HCHO Amid Acre o-Haa Meth 224-TMP 1,480 395 I15 1(43 0 995 115 109 0 393 I15 108 0 375 115 108 0 395 115 108 0 395 115 107 0 395 115 108 0 474 138 130 0 444 129 122 0 126 D 126 0 126 D 126 D 126 0 126 D 126 D 151 D 141 9.009 C -I 15 (C-178) Wauk 1.5794 091 13801-P Allot Arane Unil 40 MMSCFD 175 gpal HT01 Amin Reboikr 16 MMB U/hr 0 0 0 0 15 10 0 0 243 0 0 Proposed Proposed Proposed Proposed Proposed Petro. d Propo. d Propowl Combustion Turbine I (URB-i) Combustion Turbine 2 (TURB 2) VtgP :'::, 452 452 24 2$ 25 4 11o1 081koater (ID ITT -02) Amine Still Vent (II) ALU'02) TEO Dehydrator Vern (ID D-01) Storage Tnn s (ID TANKS) Truck Lending (ID LOAD) 567 59 2,623 349 338 694 Lucerne 2 Fugitives (ID F1102) APEN OuI - Permit Exempt Sources Permitted Sources Su 123/0107/030 II -101 Repo Rebo,k, 6 0 N8vmTUA v 1,623 1,122 1618 6,378 9,182 0 91 APR4 Exempt i In,ieniRv.,ut sources APEi4 0nk Su 6 91 u F.i Hn6 Prairie PLml Insign,rOLnets Lucerne 2 Expansion Iasiomifirants n 227 In.ionific.tnt Su 2:1 Total, All So 4.6_7 1,122 1,016 6,696 0.172 I 2.3 I 0.6 l 0.0 -I_ 3.3 I 1.0 ( o,n Footnotes: 1. This form should be completed to include both existing some, 2. If the emissions source is new then enter 'proposed" under fist 3. HAP abbreviations include: BZ = Benzene Tel = Toluene EB = Ethylbenzene Xyl = Xylene HCHO — Formaldehyde 4. APEN Exempt/Insignificant Sources should be included when DCP Midstream, LP Page 1 of 1 9. ATTACHMENT G - PROCESS AND FACILITY INFORMATION Process Description Process Flow Diagram Plot Plan DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 9-1 9.1. PROCESS DESCRIPTION K 9.1.1. Current Process Description The current Lucerne Gas Processing Plant is a natural gas processing plant designed to extract natural gas liquids from field -produced natural gas, and recompress the processed gas prior to transmission to the sales pipeline. After liquid condensate is removed from the gas by the inlet slug catcher, CO2 and H2S are removed through a 40 MMscfd amine sweetening system. The amine flash gas emissions are recycled back to the inlet via a vapor recovery unit (VRU) and the amine still vent overhead emissions are controlled through a regenerative thermal oxidizer. Water is then removed from the gas stream by adsorption through the molecular sieve beds. Natural gas liquids formed during this process are stored in pressurized tanks and transported offsite by truck. The process uses natural gas compressors powered by nine (9) reciprocating internal combustion (IC) engines. Four (4] 1,232 HP IC engines and one (1) 1,380 IC engine are used for inlet gas compression. One (1) 1,478 HP IC engine is used for refrigeration. Three (3) 1,232 HP IC engines are used for compressing the residual gas to the discharge pipeline pressure. 9.1.2. Proposed Process Description The proposed project will add a 230 MMscfd processing train to the existing 40 MMscfd plant. Two natural gas - fired Solar Taurus 70 turbines will be used for residue gas compression. Electric motors will be used for the refrigeration and VRUs. The CO2 will be removed from the gas stream through a 230 MMscfd amine sweetening system. A 50 MMBtu/hr hot oil heater will be used to supplement the waste heat recovery system provided from the turbines. A 230 MMscfd TEG dehydrator unit will be used to remove moisture from the gas stream. The flash gas streams for both the amine and dehydrator units will be recycled via a VRU back to the plant inlet with a 1% annual VRU downtime at which time the flash gas streams will be routed to the emergency flare. The still vent emissions from the amine unit will be controlled by an RTO with a DRE of 96% for VOCs and 99% for methane. The still vent emissions from the dehydrator will be controlled by a benzene, toluene, ethylbenzene, xylene (BTEX) condenser followed by an enclosed combustor with a DRE of 95%. There will be four 1,000 -bbl atmospheric condensate tanks used to store stabilized condensate and an atmospheric condensate truck loadout. The condensate tanks and truck loadout emissions will be controlled by an enclosed combustor with a DRE of 95%. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 9-2 • N O co w 0 O 0 a) O c .0 . J U Z d A CRYO Plant (1) a) �37:5 cO .. QJ• O c 0 CD O. LA 0 N L z" o. E O L 0+.. N N u':: w u: 4-, N L. v uJ w m rci U_ . • C CU on :. L a, E C N (0 . C l% 1- J CCS CD CD U N ce _cv (0 C LL U r .ALL H J L C N aLl F 1 C O N N a) L 0_ E O U 4 ce > on C• i.'. .5 u: ce Condensate Flash Condensate to U) N C :26 :. f6 0 • U H N N C a, "Cl C O U N 5 N ateLib Condensate Feed Tank DCP Midstream C E O tv C CD a.o ex N O a) w C N L H Q) • O - L 9.3. AREA MAP The Lucerne Plant is located in Weld County, Colorado. An area map is included in this section to graphically depict the location of the facility with respect to the surrounding topography. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 9-4 / Proposed Lucerne 2 Expansion Location A 0 1,000 2,000 Feet 1 inch = 2,000 feet ton si 4709 4 1 21 4748 -Weil ej II\ 1 a Well 47f4 UNION Current Plant ;. suss 666 10. ATTACHMENT H - APCD FORM SERIES 300 Operating and Maintenance (O&M) Plans This section includes O&M Plans for the following: • Amine Sweetening Systems > Glycol Dehydration Systems > Condensate Storage Tanks > Truck Loading 1 DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 10-1 Form APCD-306 Colorado Department of Public Health and Environment Air Pollution Control Division Operating and Maintenance Plan Template for Amine Sweetening Systems Ver. September 19, 2013 The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (O&M Plan) for amine sweetening systems that are permitted at a synthetic minor facility in the State of Colorado. An O&M Plan for each type of amine sweetening system configuration, as described in Section 1, shall be submitted with the permit application. One O&M Plan may be used for multiple amine sweetening systems at one facility if each are controlled and monitored in the same manner. If the O&M Plan template is completed correctly, the Division will approve the O&M Plan and a construction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly, the Division will work with the facility to make corrections. Once a construction permit is issued, the facility operator must comply with the requirements of the O&M Plan upon commencement of operation. Operators are not required to use this template. Independent case specific O&M Plans may be developed and submitted for approval with the permit application. However, the Division encourages the use of this template to expedite the permit application approval process. Colorado Depparuneht of Public Health and Environment Submittal Date: 10/03/2013 Section 1 - Source Identification For new permits some of this information (i.e. Facility AIRS ID, Facility Equipment ID, Permit Number, and AIRS Point ID) may not be known at the time of application. Please only fill out those fields that are known and leave the others blank. Company Name: Facility Name: DCP Midstream, LP Lucerne Natural Gas Processing Plant Facility Location: 31495 Weld County Road 43, Greeley, CO Facility AIRS ID (for existing facilities) 047 Units Covered by this O&M form Facility Equipment ID Permit Number AIRS Point ID Amine Type Used AU -02 MDEA a Amine types include MEA, DEA, TEA, MDEA, and DGA Emission Points and Control Status: Check the appropriate boxes indicating whether the dehydration system(s) are equipped with aflash tank and whether or not the flash tank (if present) and still vent emissions are controlled or recycled or vented to atmosphere. ® Flash Tank ® Controlled/Recycled ❑ Vented to atmosphere Section 2 - Maintenance Schedules Check one of the following: ® Still Vent Controlled/Recycled ❑ Vented to atmosphere Facility shall follow manufacturer recommendations for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Page 1 of 4 AmineUnitO&M_v2.5 Colorado Department of Public Health and Environment Air Pollution Control Division Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the division upon request and should be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. Section 3 - Monthly Emission Modeling or Calculations The following box must be checked for O&M plan to be considered complete. The source will calculate emissions based on the methods and emission factors provided in the pennit application and approved by the division, as reflected in the construction permit. Please see the operation and maintenance plan guidance document for further details and examples of emission calculations. Section 4 — General Monitoring Requirements Table 1 below details the schedule on which the source must monitor each of the listed operating parameters depending on the requested permitted emissions at the facility. Check the appropriate box based on the facility -wide permitted VOC emissions. Table 1 Parameter Monitoring Frequency N Permitted Facility ❑ Permitted Facility Emissions < 80 tpy VOC Emissions ≥ 80 tpy VOC Lean Amine Circulation Rate Daily Weekly Gas Inlet Temperature Weekly Monthly Gas Inlet Pressure Weekly Monthly Volume of Gas or NGL Processed Monthly Monthly Tables 2 and 3 outline the methods by which the source may monitor the lean amine recirculation rate and the gas or NGL processed, respectively. In Tables 2 and 3 the source must chose one primary monitoring method and, optionally, up to two backup monitoring methods. Table 2 Primary Back-up Lean Amine Recirculation Rate Monitoring Method 112 Amine flow meter(s)— including flow from all pumps ❑ ❑ Record strokes per minute and convert to circulation rate — pump make/model and stokes per minute/ circulation rate relationship must be made available to the division upon request ❑ ❑ Assume maximum design pump rate ° — pump make/model and circulation rate specifications must be made available to the division upon request Note: if you are reque ting to permit at a rate lower than the maximum design pump rate then this option should not be used as it will create de facto non-compliance. Table 3 Primary Back-up Volume of Gas or NGL Processed Monitoring Method Metered �/ Inlet Iii Outlet ❑ Compressor Suction ❑ Compressor Discharge ❑Other: •❑ Metered ❑ Inlet ❑ Outlet ❑ Compressor Suction ❑ Compressor Discharge N Other: ❑N Assume maximum design rate specifications shall be made available to the division upon request ❑ Other (to be approved by the division): attach method explanation and sample calculations ` Note: if you are reques ing to permit at a rate lower than the maximum contactor design rate then this option should not be used as it will create de facto non-compliance. Page 2 of 4 AlnineUnitO&M d2.5 Colorado Department of Public Health and Environment Air Pollution Control Division Section 5 - Emission Control or Recycling Equipment Monitoring Requirements Table 4 below details the monitoring frequency for control equipment depending on the type of control equipment used and the requested permitted emissions at the facility. Check the appropriate box for "Monitoring Frequency" based on the facility - wide permitted VOC emissions. In addition, indicate still vent and flash tank emissions controls by checking the appropriate boxes. Table 4 Emissions Control or Recycling Method Still Vent Flash Tank Parameter Monitoring Frequency i1 Permitted Facility ❑ Permitted Facility Emissions < 80 tpy VOC Emissions ≥ 80 tpy VOC Thermal Oxidizer Combustion Chamber Temperature Daily Weekly A❑ Combustor or Flare ❑ Pilot Light Monitoring e Daily Weekly o Method 22 Readings Daily Weekly Recycled or Closed Loop System (Including Vapor Recovery Units) be determined by the source and approved by the division r il 1T Re-routed to Reboiler Burner ❑ ❑ To be determined by the source and approved by the division g d Minimum Thermal Oxidizer Combustion Chamber Temperature If the facility uses a thermal oxidizer to control emissions then the minimum combustion chamber temperature shall be: Select one of the following options from Table 5: Table 5 ❑ 1400 °F ® 1550 ° F Based on manufacturer specifications. Specifications must be submitted with the permit application and made available to the Division upon request ❑ Based on testing performed. The test data shall be submitted and attached to the O&M Plan e Pilot Light Monitoring Options If the facility uses a Combustor or Flare then the source must indicate the method by which the presence of a pilot light will be monitored in Table 6. One primary method for Pilot Light Monitoring must be checked and, optionally, up to two backup methods can be checked. Table 6 Primary Back-up Monitoring Method ❑ ❑ Visual Inspection ❑ ❑ Optical Sensor El Auto -Igniter Signal O ❑ Thermocouple Recycled or Closed Loop System Monitoring Plan In the space provided below please provide a brief description of the emission control or recycling system, including an explanation of how the system design ensures that emissions are being routed to the appropriate system at all times, or during all permitted runtime. The flash tank emissions are being routed to the VRU. To be conservative, 99% control efficiency is being taken for the Page 3 of 4 AmineUnitO&N,`_v2.5 Colorado Department of Public Health and Environment Air Pollution Control Division VRU to account for a 1% annual downtime. Emissions during this downtime will be routed to a flare with 95% destruction efficiency. Method 22 readings should only be required during VRU downtime. s Reboiler Burner Control Monitoring Plan In the space provided below please provide a brief description of the emission control system, including an explanation of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Section 6 — Recordkeeping Requirements The following box must be checked for O&M plan to be considered complete. Synthetic minor sources are required to maintain maintenance and monitoring records for the requirements listed in sections 2, 3, 4 and 5 for a period of 5 years. If an applicable Federal NSPS, NESHAP or MACT requires a longer record retention period the operator must comply with the longest record retention requirement. Section 7 - Additional Notes and O&M Activities Please use this section to describe any additional notes or operation and maintenance activities. Note: These templates are intended to address operation and maintenance requirements of the State of Colorado for equipment operated at synthetic minor facilities. If the facility or equipment is subject to other state or federal regulations with duplicative requirements, the source shad follow the most stringent regulatory requirement. Page 4 of 4 AmineUnitO&M_v2.5 Form APCD-302 Colorado Department of Public Health and Environment Air Pollution Control Division ColoradoDepuunent of Public Health and Environment Operating and Maintenance Plan Template for Glycol Dehydration Systems Ver. September 19, 2013 The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (O&M Plan) for glycol dehydration systems that are permitted at synthetic minor facilities in the State of Colorado. An O&M Plan for each type of glycol dehydration system configuration, as described in Section 1, shall be submitted with the permit application. One O&M Plan may be used for multiple glycol dehydration systems at one facility if each are controlled and monitored in the same manner. If the O&M Plan template is completed correctly, the Division will approve the O&M Plan and a construction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly, the Division will work with the facility to make corrections. Once a construction permit is issued, the facility operator must comply with the requirements of the O&M Plan upon commencement of operation. Operators are not required to use this template. Independent case specific O&M Plans may be developed and submitted for approval with the permit application. However, the Division encourages the use of this template to expedite the permit application approval process. Submittal Date: 10/03/2013 Section 1 - Source Identification For new permits some of this information (i.e. Facility AIRS ID, Facility Equipment ID, Permit Number, and AIRS Point ID) may not be known at the time of application. Please only fill out those fields that are known and leave the others blank. Company Name: Facility Name: DCP Midstream, L.P. Lucerne Natural Gas Processing Plant Facility Location: 31495 Weld County Road 43, Greeley, CO Facility AIRS ID (for existing facilities) 048 Units Covered by this O&M form Facility Equipment ID D-01 Permit Number AIRS Point ID Glycol Type Used ° TEG a Glycol types include Ethylene Glycol (EG), Di -Ethylene Glycol (DEG), and Tri-Ethylene Glycol (TEG) Emission Points and Control Status: Check the appropriate boxes indicating whether the dehydration system(s) are equipped with aflash tank and whether or not the flash tank (if present) and still vent emissions are controlled or recycled or vented to atmosphere. ® Flash Tank ® Controlled/Recycled ❑ Vented to atmosphere Section 2 - Maintenance Schedules Check one of the following: ® Still Vent ® Controlled/Recycled O Vented to atmosphere Facility shall follow manufacturer recommendations for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Page 1 of 4 DehydratorO&M_v2.5 Colorado Department of Public Health and Environment Air Pollution Control Division Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the division upon request and should be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. Section 3 - Monthly Emission Modeling or Calculations The following box must be checked for O&M plan to be considered complete. N The source will calculate emissions based on the methods and emission factors provided in the permit application and approved by the division, as reflected in the construction permit. Please see the operation and maintenance plan guidance document for further details and examples of emission calculations. Section 4 — General Monitoring Requirements Table 1 below details the schedule on which the source must monitor each of the listed operating parameters depending on the requested permitted emissions at the facility. Check the appropriate box based on facility wide permitted VOC emissions. Table 1 Parameter Monitoring Frequency 11 Permitted Facility ❑ Permitted Facility Emissions < 80 tpy VOC Emissions ≥ 80 tpy VOC Lean Glycol Circulation Rate Daily Weekly Wet Gas Inlet Temperature Weekly Monthly Wet Gas Inlet Pressure Weekly Monthly Volume of Gas Processed Monthly Monthly Chiller (Cold Separator) Pressure (EG units only) Weekly Monthly Chiller (Cold Separator) Temperature (EG units only) Weekly Monthly Tables 2 and 3 outline the methods by which the source may monitor the lean glycol recirculation rate and the volume of gas processed, respectively. In Tables 2 and 3 the source must chose one primary monitoring method and, optionally, up to two backup monitoring methods. Check each box that applies. Table 2 Primary Back-up Lean Glycol Recirculation Rate Monitoring Method r Glycol flow meter(s) — including flow from all injection points or pumps ❑ ❑ Record strokes per minute and convert to circulation rate — pump make/model and stokes per minute/ circulation rate relationship must be made available to the division upon request ❑ ❑ Assume maximum design pump rate b— pump make/model and circulation rate specifications must be made available to the division upon request "Note: if you are requesting to permit at a rate lower than the maximum design pump rate then this option should not be used as it will create de facto non-compliance. Table 3 Primary Back-up Volume of Gas Processed Monitoring Method // Metered // Inlet ❑ Outlet ❑ Fuel Gas ❑ Compressor Discharge ❑Other: •❑ Metered ❑ Inlet ❑ Outlet ❑ Fuel Gas O Compressor Discharge ❑Other: ❑ ❑ Assume maximum design rate` specifications shall be made available to the division upon request ❑ ❑ Other (to be approved by the division): attach method explanation and sample calculations `Note: if you are requesting to permit at a rate lower than the maximum contactor design rate then this option should not be used as it will create de facto non-compliance. Page 2 of 4 DehydratorO&M_v2.5 Colorado Department of Public Health and Environment Air Pollution Control Division Section 5 - Emission Control or Recycling Equipment Monitoring Requirements Table 4 below details the monitoring frequency for control equipment depending on the type of control equipment used and the requested permitted emissions at the facility. Check the appropriate box for "Monitoring Frequency" based on the facility - wide permitted VOC emissions. In addition, indicate still vent and flash tank emissions controls by checking the appropriate boxes. Table 4 Emissions Control or Recycling Method Still Vent Flash Tank Parameter Monitoring Frequency X1 Permitted Facility ❑ Permitted Facility Emissions < 80 tpy VOC Emissions ≥ 80 tpy VOC Condenser Condenser Outlet Temperature Weekly Monthly 0❑ Thermal Oxidizer ❑ ❑ Combustion Chamber Temperature e Daily Weekly Combustor or Flare Pilot Light Monitoring r Daily Weekly .0 Method 22 Readings Daily Weekly Recycled or Closed Loop System (Including Vapor Recovery Units) ❑ To be determined by the source and approved by the division 8 ►/ Re-routed to Reboiler Burner ❑ ❑ To be determined by the source and approved by the division n 'Maximum Condenser Outlet Temperature If the equipment is controlled with a secondary control device and no control efficiency is being claimed for the condenser then the condenser outlet temperature does not need to be monitored and there will be no maximum condenser outlet temperature. For all other equipment the maximum condenser outlet temperature shall be: Select one of the following options from Table 5: Table 5 ❑ 160°F ® 145 ° F (Upon approval from the division) — attach supporting documentation if a higher limit is requested ° Minimum Thermal Oxidizer Combustion Chamber Temperature If the facility uses a thermal oxidizer to control emissions then the minimum combustion chamber temperature shall be: Select one of the following options from Table 6: Table 6 1400 ° F U ° F Based on manufacturer specifications. Specifications must be submitted with the permit application and made available to the Division upon request B Based on testing performed. The test data shall be submitted and attached to the O&M Plan Page 3 of 4 OehydratorO&M_v2.5 Colorado Department of Public Health and Environment Air Pollution Control Division r Pilot Light Monitoring Options If the facility uses a Combustor or Flare then the source must indicate the method by which the presence of a pilot light will be monitored in Table 7. One primary method for Pilot Light Monitoring must be checked and, optionally, up to two backup methods can be checked. Table 7 Primary Back-up Monitoring Method ❑ ❑ Visual Inspection ❑ O Optical Sensor r Auto -Igniter Signal F2 ❑ Thermocouple g Recycled or Closed Loop System Monitoring Plan In the space provided below please provide a brief description of the emission control or recycling system, including an explanation of how the system design ensures that emissions are being routed to the appropriate system at all times, or during all permitted runtime. The flash tank emissions are being routed to the VRU. To be conservative, 99% control efficiency is being taken for the VRU to account for a 1% annual downtime. Emissions during this downtime will be routed to a flare with 95% destruction efficiency. Method 22 readings for the flare should only be required during VRU downtime. Reboiler Burner Control Monitoring Plan In the space provided below please provide a brief description of the emission control system, including an explanation of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Section 6 — Recordkeeping Requirements The following box must be checked for O&M plan to be considered complete. Synthetic minor sources are required to maintain maintenance and monitoring records for the requirements listed in sections 2, 3, 4 and 5 for a period of 5 years. If an applicable Federal NSPS, NESHAP or MACT requires a longer record retention period the operator must comply with the longest record retention requirement. Section 7 - Additional Notes and O&M Activities Please use this section to describe any additional notes or operation and maintenance activities. Note: These templates are intended to address operation and maintenance requirements of the State of Colorado for equipment operated at synthetic minor facilities. If the facility or equipment is subject to other state or federal regulations with duplicative requirements, the source shalt follow the most stringent regulatory requirement. Page 4 of 4 Detrydratoro&M_v2.5 Form APCD-304 Colorado Department of Public Health and Environment Air Pollution Control Division Operating and Maintenance Plan Template for Condensate and Mixed Liquid Storage Tanks Ver. September 19, 2013 dnDe arunent of Publicflealth andEnvironnrent The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (O&M Plan) for condensate and mixed liquid storage tanks permitted at synthetic minor facilities in the State of Colorado. An O&M Plan shall be submitted with the permit application. One O&M Plan may be used for multiple tanks at one facility if each are controlled and monitored in the same manner. If the O&M Plan template is completed correctly, the Division will approve the O&M Plan and a construction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly, the Division will work with the facility to make corrections. Once a construction permit is issued, the facility operator must comply with the requirements of the O&M Plan upon commencement of operation. Operators are not required to use this template. Independent case specific O&M Plans may be developed and submitted for approval with the permit application. However, the Division encourages the use of this template to expedite the permit application approval process. Submittal Date: 10/03/2013 Section 1 - Source Identification For new permits some of this information (i.e. Facility AIRS ID, Facility Equipment ID, Permit Number, and AIRS Point ID) may not be known at the time of application. Please only fill out those fields that are known and leave the others blank. Company Name: Facility Name: DCP Midstream, LP Lucerne Natural Gas Processing Plant Facility Location: 31495 Weld County Road 43, Greely, CO Facility AIRS ID (for existing facilities) 050 Units Covered by this O&M form Facility Equipment ID Tanks Permit Number AIRS Point ID Tank Type' C Controlled (Y/N) Y Tank types include condensate (C) and mixed liquid (ML) Section 2 - Maintenance Schedules Check one of the following: Facility shall follow manufacturer recommendations for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the division upon request and should be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. Page 1 of 4 storageTanko&M v1.5 Colorado Department of Public Health and Environment Air Pollution Control Division Section 3 - Monthly Emission Modeling or Calculations The following box must be checked for O&M plan to be considered complete. The source will calculate emissions based on the methods and emission factors provided in the permit application and approved by the division, as reflected in the construction permit. Please see the operation and maintenance plan guidance document for further details and examples of emission calculations. Section 4 — General Monitoring Requirements All condensate collection, storage, processing and handling operations, regardless of size, shall be designed, operated and maintained to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. Table 1 below details the schedule on which the source must monitor each of the listed operating parameters depending on the requested permitted emissions at the facility. Check the appropriate box based on the facility wide permitted VOC emissions. Table 1 Parameter Monitoring Frequency a Permitted Facility Permitted Facility Emissions < 80 tpy VOC Emissions≥ 80 tpy VOC Condensate Throughput Monthly Monthly Separator Temperature (if present) Weekly Monthly Separator Pressure (if present) Weekly Monthly Table 2 outlines condensate and mixed liquid throughput monitoring methods. The source must chose one primary monitoring method and, optionally, may chose up to two backup methods. Check each box that applies. Table 2 Primary Back-up Condensate or Mixed Liquid Throughput Monitoring Method ❑ Inlet meter(s) ❑ ❑ Tank level measurements which take into account all additions and loadout activity a a Sales or haul tickets ❑ ❑ Other (to be approved by the division): attach method explanation and sample calculations Section 5 - Emission Control or Recycling Equipment Monitoring Requirements If a control device is used then leakage of VOCs to the atmosphere must be minimized as follows: • Thief hatch seals shall be inspected for integrity annually and replaced as necessary; • Thief hatch covers shall be weighted and properly seated; • Pressure relief valves (PRV) shall be inspected annually for proper operation and replaced as necessary; • PRVs shall be set to release at a pressure that will ensure flashing, working and breathing losses (as applicable) are routed to the control device under normal operating conditions; • Annual inspections shall be documented with an indication of status, a description of any problems found, and their resolution. Page 2 of 4 StorageTankO&M_v1.5 Colorado Department of Public Health and Environment Air Pollution Control Division Table 3 below details the monitoring frequency for control equipment depending on the type of control equipment used and the requested pennitted emissions at the facility. Check the appropriate box for "Monitoring Frequency" based on the facility -wide permitted VOC emissions. In addition, indicate storage tank emissions controls by checking the appropriate boxes. Table 3 Emissions Control or Recycling Method Parameter Monitoring Frequency @ Permitted Facility ❑ Permitted Facility Emissions < 80 tpy VOC Emissions ≥ 80 tpy VOC Thermal Oxidizer ❑ Combustion Chamber Temperature Daily Weekly Combustor or Flare Pilot Light Monitoring C Daily Weekly @ Method 22 Readings Daily Weekly Recycled or Closed Loop System (Including Vapor Recovery Units) ❑ To be determined by the source and approved by the division d Re-routed to Reboiler Burner ❑ To be determined by the source and approved by the division u Minimum Thermal Oxidizer Combustion Chamber Temperature If the facility uses a thermal oxidizer to control emissions then the minimum combustion chamber temperature shall be: Select one of the following options from Table 4: Table 4 ❑ 1400"F ❑ o F Based on manufacturer specifications. Specifications must be submitted with the permit application and made available to the Division upon request II Based on testing performed. The test data shall be submitted and attached to the O&M Plan `Pilot Light Monitoring Options If the facility uses a Combustor or Flare then the source must indicate the method by which the presence of a pilot light will be monitored in Table 5. One primary method for Pilot Light Monitoring must be checked and, optionally, up to two backup methods may be checked. Table 5 Primary Back-up Monitoring Method ❑ ►1 Visual Inspection ❑ ❑ Optical Sensor • N Auto -Igniter Signal �� ❑ Thermocouple d Recycled or Closed Loop System Monitoring Plan In the space provided below please provide a brief description of the emission control or recycling system, including an explanation of how the system design ensures that emissions are being routed to the appropriate system at all times, or during all permitted runtime. Page 3 of 4 StorageTanko&M v1.5. Colorado Department of Public Health and Environment Air Pollution Control Division Reboiler Burner Control Monitoring Plan In the space provided below please provide a brief description of the emission control system, including an explanation of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Section 6 — Recordkeeping Requirements The following box must be checked for O&M plan to be considered complete. Synthetic minor sources are required to maintain maintenance and monitoring records for the requirements listed in sections 2, 3, 4 and 5 for a period of 5 years. If an applicable Federal NSPS, NESHAP or MACT requires a longer record retention period the operator must comply with the longest record retention requirement. Section 7 - Additional Notes and O&M Activities Please use this section to describe any additional notes or operation and maintenance activities. Note: These templates are intended to address operation and maintenance requirements of the State of Colorado for equipment operated at synthetic minor facilities. If the facility or equipment is subject to other state or federal regulations with duplicative requirements, the source shall follow the most stringent regulatory requirement. Page 4 of 4 StorageTankO&M_v1.5 Operating and Maintenance Plan for Truck Loading This Operating and Maintenance Plan (O&M Plan) is developed for truck loading in the State of Colorado to satisfy the O&M Plan requirements of the Colorado Department of Public Health and Environment (CDPHE) Air Pollution Control District (APCD) construction permit application. Submittal Date: 10/03/2013 Section 1 — Source Identification Company Name: DCP Midstream, LP Facility Name: Lucerne Natural Gas Processing Plant Facility AIRS ID (for existing facilities):051 Facility Location: 31495 Weld County Road 43, Greeley. CO Units Covered by this O&M form Facility Equipment ID LOAD Permit Number 12WE2024 AIRS Point ID 051 Material Loaded Condensate Controlled (Y/N) Y Section 2 — Maintenance Schedules Check one of the following: ❑ Facility shall follow manufacturer recommendations for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. El Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the division upon request and should be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. Section 3 — Monthly Emission Modeling or Calculations The following box must be checked for O&M plan to be considered complete. The source will calculate emissions based on the methods and emission factors provided in the permit application and approved by the division, as reflected in the construction permit. Section 4- General Monitoring Requirements All condensate truck loading operations shall be designed, operated and maintained to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. Table 1 below details the schedule on which the source must monitor each of the listed operating parameters depending on the requested permitted emissions at the facility. Check the appropriate box based on the facility wide permitted VOC emissions. Page 1 of 3 Table 1 Parameter Monitoring Frequency O Permitted Facility Emissions > 80 0 Permitted Facility Emissions < tpy VOC 80 tpy VOC Condensate Truck Loading Throughput Monthly Monthly Table 2 outlines condensate truck loading throughput monitoring methods. The source must choose one primary monitoring method and, optionally, may choose up to two backup methods. Check each box that applies. Table 2 Primary Back-up Condensate Truck Loading Monitoring Method ❑ Inlet meter(s) ❑ O Tank level measurements which take into account all additions and loadout activity ® ; 0 Sales or haul tickets O O Other (to be approved by the division): attach method explanation and sample calculations Section 5 — Emission Control or Recycling Equipment Monitoring Requirements Table 3 below details the monitoring frequency for control equipment depending on the type of control equipment used and the requested permitted emissions at the facility. Check the appropriate box for "Monitoring Frequency" based on the facility - wide permitted VOC emissions. In addition, indicate truck loading emissions controls by checking the appropriate boxes. Table 3 Emissions Control or Recycling Method Parameter Monitoring Frequency ►-i Permitted Facility 0 Permitted Facility Emissions < 80 tpy VOC Emissions ≥ 80 tpy VOC Thermal Oxidizer ❑ Combustion Chamber Temperature Daily Weekly Combustor or Flare Pilot Light Monitoring a Daily Weekly 0 Method 22 Readings Daily Weekly Recycled or Closed Loop System (Including Vapor Recovery Units) O To be determined by the source and approved by the division Re-routed to Reboiler Burner O To be determined by the source and approved by the division " Pilot Light Monitoring Options If the facility uses a Combustor or Flare then the source must indicate the method by which the presence of a pilot light will be monitored in Table 4. One primary method for Pilot Light Monitoring must be checked and, optionally, up to two backup methods may be checked. Table 4 Primary Back-up Monitoring Method ❑ ® Visual Inspection ❑ O Optical Sensor ❑ ❑ Auto -Igniter Signal O Thermocouple Page 2 of 3 Section 6 — Recordkeeping Requirements The following box must be checked for O&M plan to be considered complete. ® Synthetic minor sources are required to maintain maintenance and monitoring records for the requirements listed in sections 2, 3, 4, and 5 for a period of 5 years. If an applicable Federal NSPS, NESHAP or MACT requires a longer record retention period the operator must comply with the longest record retention requirement. Section 7 — Additional Notes and O&M Activities Please use this section to describe any additional notes or operation and maintenance activities. Page 3 of 3 11. ATTACHMENT I - REGULATORY ANALYSIS This section addresses the applicability of the federal and state regulatory programs for the equipment at the proposed Lucerne 2 Expansion: 9 Colorado Department of Public Health and Environment (CDPHE) Air Pollution Control District (APCD) regulations 9 New Source Performance Standards (NSPS) in 40 CFR Part 60 9 National Emission Standards for Hazardous Air Pollutants (NESHAP) in 40 CFR Part 61 > NESHAP in 40 CFR Part 63, i.e., MACT standards Nonattainment New Source Review (NNSR) 9 Prevention of Significant Deterioration (PSD) 11.1. COLORADO STATE REGULATIONS The following paragraphs provide source -specific and facility -wide CDPHE APCD regulations. 11.1.1. CDPHE APCD Regulation 3, Part A, Section II: The Air Pollution Emission Notice (APENs) forms for the equipment subject to APEN reporting are provided in Section 4 (Attachment B) of this application. 11.1.2. Concerning Construction Permits (Regulation 3, Part B) The Lucerne 2 Expansion as proposed will be subject to this regulation and this application serves to apply for the required construction permit prior to construction. 11.1.3. Concerning Operating Permits (Regulation 3, Part C) The existing Lucerne Plant is a major source with respect to the Title V Operating Permit Program. After the proposed Lucerne 2 Expansion, the Plant will continue to be a major source under the Title V Program. DCP Midstream will be required to submit an application in order to incorporate this modification in the existing Title V Permit within 12 months of the startup of the proposed Lucerne 2 Expansion sources. 11.1.4. Concerning Major Stationary Source New Source Review and Prevention of Significant Deterioration (Regulation 3, Part D) The proposed Lucerne 2 Expansion will be a major source of GHGs and minor source of other pollutants with respect to PSD permitting. The Lucerne 2 Expansion is subject to this regulation and will comply with all applicable parts of this regulation. 11.1.5. Volatile Organic Compound Emissions from Oil and Gas Operations (Regulation 7, Section XII) The existing Lucerne Plant and Lucerne 2 Expansion is located in the 8 -hour Ozone Control Area (nonattainment area) and is subject to Section XII of this regulation and will comply with all applicable parts of this regulation. The existing facility is currently in compliance with NSPS Subpart KKK. DCP will incorporate the Lucerne 2 Expansion equipment into the existing LDAR program within 180 days of startup. The Lucerne 2 Expansion atmospheric condensate tanks store stabilized condensate and will be controlled with an enclosed combustor. DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 11-1 The Lucerne 2 Expansion glycol dehydrator will also be controlled by the enclosed combustor and will be in compliance with control requirements of Section XII.C. 11.1.6. Control of Emissions from Stationary and Portable Engines in the 8 -Hour Ozone Control Area (Regulation 7, Section XVI) The proposed Lucerne 2 Expansion compressor engines will be electric -powered and thus will have no emissions. Therefore, Section XVI does not apply to the Lucerne 2 Expansion. 11.1.7. Statewide Controls for Oil and Gas Operations and Natural Gas -Fired Reciprocating Internal Combustion Engines (Regulation 7, Section XVII) Section XVII.E. applies to natural gas -fired reciprocating combustion engines. The proposed Lucerne 2 Expansion compressor engines will be electric -powered. Therefore, Section XVII does not apply to the Lucerne 2 Expansion. 11.2. NEW SOURCE PERFORMANCE STANDARDS The following NSPS subparts in 40 CFR Part 60 are potentially applicable to the proposed Lucerne 2 Expansion emission sources: Table 11-1. Potentially Applicable NSPS Subparts Subpart Description Applicability Affected Sources (IDJ Subpart A General Provisions Yes All sources listed below Subpart Dc Standards of Performance for Small Industrial- Commercial -Institutional Steam Generating Units Yes Hot Oil Heater (ID HT -02) Subpart Kb Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced after July 23, 1984 Yes Tanks (ID TANKS) Subpart KKK Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing Plants No Fugitives (ID FUG) Tanks (ID TANKS) See NSPS 0000 Subpart LLL Standards of Performance for Onshore Natural Gas Processing: SO2 Emissions No N/A Subpart KKKK Standards of Performance for Stationary Combustion Turbines Yes Two Solar Taurus 70 Turbines (IDs TURB-1 and TURB-2) Subpart 0000 Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution Yes Fugitives (ID FUG2) DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 11-2 HT -02 Each potentially applicable NSPS subpart of 40 CFR Part 60 is discussed in the subsections below. 11.2.1. Subpart A - General Provisions Any source subject to a source -specific NSPS is also subject to the general provisions of NSPS Subpart A. Unless specifically excluded by the source -specific NSPS, Subpart A generally requires initial construction notification, initial startup notification, performance tests, performance test date initial notification, general monitoring requirements, general recordkeeping requirements, and semiannual monitoring and/or excess emission reports. 11.2.2. Subpart Dc - Small Industrial -Commercial -Institutional Steam Generating Units NSPS Subpart Dc applies to steam generating units for which construction, modification, or reconstruction is commenced after June 9, 1989 and that have a maximum design heat input capacity of greater than or equal to 10 MMBtu/hr and less than or equal to 100 MMBtu/hr. According to §60.41c(3), steam generating unit and process heater are defined as: Steam generating unit means a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in this subpart. Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst. According to these definitions, the table below lists the emission sources at the proposed Lucerne 2 Expansion considered to be steam generating units and are potentially subject to NSPS Subpart Dc. Table 11-2. Heaters Potentially Subject to NSPS Subpart Dc Heater Description Size (MMBtu/hr); Hot Oil Heater 50 The Hot Oil Heater (ID HT -02) is subject to recordkeeping and reporting requirements, since it will not burn coal, oil, or combinations of fuel that included coal and/or oil. DCP Midstream will comply with the fuel recordkeeping requirements and the construction and startup notification requirements. 11.2.3. Subpart Kb - Volatile Organic Liquid Storage Vessels NSPS Subpart Kb applies to volatile organic liquid storage vessels constructed, reconstructed, or modified after July 23, 1984 with a capacity of 19,813 gallons (gal) or more. The condensate storage tanks at the facility are proposed to be four (4) 42,000 gal tanks. These storage vessels are therefore subject to this subpart, and will be compliant with this subpart because the VOC emissions are routed to an enclosed combustor with 95% efficiency. Therefore, DCP Midstream will be in compliance with 40 CFR § 60.110 b(a)(3) requirements. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11-3 11.2.4. Subpart KKK - Equipment Leaks of VOC From Onshore Natural Gas Processing Plants NSPS Subpart KICK applies to onshore natural gas processing plants constructed, reconstructed, or modified after January 20, 1984. However, onshore natural gas processing plants constructed, reconstructed, or modified after August 23, 2011 will be subject to the new proposed NSPS Subpart 0000, as discussed in Section 11.2.7. 11.2.5. Subpart LLL - Onshore Natural Gas Processing: SO2 NSPS Subpart LLL applies to onshore natural gas processing facilities that contain sweetening units that commence construction or modification after January 20, 1984. However, onshore natural gas processing plants constructed, reconstructed, or modified after August 23, 2011 will be subject to the new proposed NSPS Subpart 0000, as discussed in Section 11.2.7. It is expected that the following exemptions will be available in the final NSPS Subpart 0000 for onshore natural gas processing facilities that contain sweetening units. According to §60.641, sweetening unit is defined as: Sweetening unit means a process device that separates the 112S and CO2 contents from the sour natural gas stream. The Lucerne 2 Expansion will contain an amine unit, which separates primarily CO2 contents from the natural gas stream. Additionally, small amounts of H2S will be removed in the process. The design capacity of the amine unit will be less than two long tons per day of H2S in acid gas (expressed as sulfur). Therefore, the amine unit qualifies for exemption from control requirements per §60.640(b). DCP will maintain documentation demonstrating that the facility's design capacity is less than two long tons per day of H2S in acid gas, expressed as sulfur, per §60.647(c). 11.2.6. Subpart KKKK - Stationary Combustion Turbines NSPS Subpart KKKK establish requirements for owners or operators of stationary combustion turbines with heat input at peak load equal to or greater than 10 MMBtu per hour and commenced construction, modification, or reconstruction after February 18, 2005. The two Solar Taurus combustion turbines will be constructed after February 18, 2005 and therefore are subject to the provisions of NSPS Subpart KKKK. Since the turbines are new, fire natural gas and have a HHV between 50 MMBtu/hr and 850 MMBtu/hr, they are subject to an emission limit of 25 ppm at 15 percent 02 or 690 ng/J of useful output (1.2 lb/MWh) for NOx per Table 1 of Subpart KKKK. The turbines must also comply with either of the following three limits for SO2 1) Must not discharge into the atmosphere any gas which contains SO2 in excess of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt -hour (lb/MWh)) gross output; 2) Must not burn any fuel which contains total potential sulfur emissions in excess of 26 ng 502/J (0.060 lb S02/MMBtu) heat input. If the turbine simultaneously fires multiple fuels, each fuel must meet this requirement. 3) For each stationary combustion turbine burning at least 50 percent biogas on a calendar month basis, as determined based on total heat input, it must not discharge into the atmosphere, any gas that contains 502 in excess of 65 ng 502/J (0.15 lb S02/MMBtu) heat input. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11-4 11.2.7. Subpart 0000 - Crude Oil and Natural Gas Production, Transmission, and Distribution NSPS Subpart 0000 includes new or updated emissions and work practice standards for the following source types located at the proposed Lucerne 2 Expansion: • Equipment leaks at onshore natural gas processing plants -Per 40 CFR § 60.5400 and § 60.5401, equipment leak components are subject to monitoring and leak detection programs. DCP will comply with the 500 ppm leak detection level and repair leaks as required under Subpart 0000. > Sweetening units - Per 40 CFR §60.5365(g), sweetening units located at onshore natural gas processing plants are affected facilities. However, per 40 CFR §60.5365(g) (3), facilities that have a design capacity less than 2 long tons per day of H25 in the acid gas, are only subject to recordkeeping and report keeping requirements. The Lucerne 2 facility will have a design capacity of less than 2 long tons per day of H25, and are only subject to the recordkeeping and reporting requirements. DCP Midstream will comply the requirements under 40 CFR §60.5423(c) by keeping an analysis throughout the life of the facility to demonstrate that the design capacity is less than 2 long tons/ day of H25. • Reciprocating Compressors - Per 40 CFR § 60.5385, reciprocating compressors are required to replace the rod packing before the compressor has operated for 26,000 hours, or prior to 36 months from the date of the most recent rod packing replacement. DCP will track and replace the rod packing accordingly and will maintain compliance with this requirement. • Storage Tanks — Per 40 CFR § 60.5395(d), NSPS Subpart 0000 does not apply to storage vessels subject to and controlled in accordance with the requirements for storage vessels in 40 CFR Part 60 Subpart Kb. Since the condensate storage tank is subject to Subpart Kb, it is exempt from requirements under Subpart 0000. 11.3. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS The Lucerne 2 Expansion modification will not change the area source status of the Lucerne Plant, with regards to emissions of HAPs. Therefore, the proposed Lucerne 2 Expansion equipment is not subject to any of the NESHAP subparts in 40 CFR Part 61. The following MACT subparts in 40 CFR Part 63 are potentially applicable to the emission sources at the proposed Lucerne 2 Expansion: DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11-5 Table 11-3 Potentially Applicable MACT Subparts Subpart Description Applicability Affected Sources (ID) Subpart A General Provisions Yes All sources listed below Subpart HH National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities Yes TEG Dehydrator (ID D-01) Subpart HHH National Emission Standards for Hazardous Air Pollutants From Natural Gas Transmission and Storage Facilities No N/A Subpart YYYY National Emission Standards for Hazardous Air Pollutants For Stationary Combustion Turbines No N/A Subpart DDDDDD National Emission Standards for Hazardous Air Pollutants For Industrial, Commercial, and Institutional Boilers and Process Heaters No N/A Subpart JJJJJJ National Emission Standards for Hazardous Air Pollutants For Industrial, Commercial, and Institutional Boilers Area Sources No N/A Each applicable MACT Subpart of 40 CFR Part 63 is discussed in the subsections below. 11.3.1. Subpart A - General Provisions Any source subject to a source -specific NESHAP is also subject to the general provisions of NESHAP Subpart A. Unless specifically excluded by the source -specific NESHAP, Subpart A generally requires initial construction notification, initial startup notification, performance tests, performance test date initial notification, general monitoring requirements, general recordkeeping requirements, and semiannual monitoring and/or excess emission reports. 11.3.2. Subpart HH - Oil and Natural Gas Production Facilities MACT Subpart HH applies to emission points at oil and natural gas production facilities that are HAP major or HAP area sources and that process, upgrade, or store either hydrocarbon liquids or natural gas prior to the point of custody transfer. As an area source and facility that processes natural gas, the Lucerne 2 Expansion will be potentially subject to the requirements of Subpart HH. According to §63.760(b)(2), the affected sources at HAP area sources include all TEG dehydrator units, as listed below: Table 11-4. TEG Dehydrators Potentially Subject to MACT Subpart HH \,- ID Unit Description D-01 TEG Dehydrator * * The TEG Dehydrator will be controlled by the enclosed combustor The TEG dehydrator standards of Subpart HH will apply to the dehydrator located at the Lucerne 2 Expansion. According to §63.764(e)(1)(i) and (ii),the owner/operator is exempt from the general standards if the flowrate of TEG is less than 3 MMscf/day to the dehydrator or if the benzene emissions from the dehydrator are less than DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11-6 1.0 tpy, respectively. The TEG unit at the Lucerne 2 Expansion has a PTE of benzene greater than 1 tpy and throughput greater than 3 MMscf/day; therefore, the unit will be subject to this subpart. DCP Midstream will comply with the appropriate notifications and recordkeeping. 11.3.3. Subpart HHH - Hazardous Air Pollutants From Natural Gas Transmission and Storage Facilities MACT Subpart HHH applies to natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end user and are major sources of HAP emissions. Per 40 CFR 63.1270(a), the Lucerne 2 Expansion is not an affected source since it is not a major source of HAP emissions and it is not considered a natural gas transmission or storage facility. 11.3.4. Subpart YYYY - Hazardous Air Pollutants From Stationary Combustion Turbines MACT Subpart YYYY applies to combustion turbines at major sources of HAP emissions. The Lucerne Plant with the proposed Lucerne 2 Expansion will not be a major source of HAPs. Therefore, Subpart YYYY does not apply to the Plant 11.3.5. Subpart DDDDD - Industrial, Commercial, and Institutional Boilers and Process Heaters MACT Subpart DDDDD establishes emission limits, operational standards, and compliance demonstration requirements for HAP emissions from industrial, commercial, and institutional boilers and process heaters operating within major sources of HAP emissions. Per 40 CFR §63.7485, the process heaters located at the Lucerne Plant are not subject to this subpart since they will not operate within a major source of HAP emissions. 11.3.6. Subpart JJJJJJ - Industrial, Commercial, and Institutional Boilers Area Sources MACT Subpart JJJJJJ establishes emission limits, operational standards, and energy assessment requirements for HAP emissions from industrial, commercial, and institutional boilers operating within area sources of HAP emissions. According to 63.11194(a)(1), an affected source is the collection of all existing industrial, commercial, and institutional boilers within a subcategory (coal, biomass, oil). Units at the Lucerne Plant and the Lucerne 2 Expansion are not subject to Subpart JJJJJJ since they are exclusively natural gas -fired, and therefore do not fit into one of the subcategories covered by the rule. 11.4. NNSR APPLICABILITY REVIEW The Lucerne Plant is located in Weld County, north of Greeley, Colorado. Weld County is currently attainment or unclassifiable for all criteria pollutants with the exception of the 8 -hour ozone standard.21 A major source in the nonattainment area is a source with the PTE of 100 tons per year (tpy) or more of NOx or VOC.22 Since the existing Lucerne facility is considered a major source under the NNSR program with emissions of NOx and VOC exceeding the 100 tpy major source threshold, the emissions from the Lucerne 2 Expansion were compared to the Significant Emission Rates (SERs; i.e., 100 tpy for NOx and VOC) to determine if NNSR is required. As shown in Table 1-4 located in Section 1 of this application, the proposed modification will not result in emissions above the respective SERs and therefore, the project will not trigger NNSR for NOx or VOC. \ \ http://www.epa.gov/oar/oagps/areenbook/ancl3.html, accessed April 17, 2012. 22 CDPHE APCD Regulation 3, Part D, Section II.a.24(b), effective December 15, 2011 (http://www.cdphe.state.co.us/re¢ulations/airregs/5CCR1001-5.pdf). DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11-7 11.5. PSD APPLICABILITY REVIEW The Lucerne Plant with the proposed Lucerne 2 Expansion will be a major source of GHGs with respect to PSD permitting (i.e., COze emissions > 100,000 tpy). According to EPA guidance, the "major for one, major for all" PSD policy applies to GHGs for any project occurring on or after July 1, 2011. Therefore, if a site is major for GHGs only, then criteria pollutant emissions must be compared to the Significant Emission Rates (SERs; i.e., 40 tpy for N0x/SOz/VOC, 100 tpy for CO, 25 tpy for PM, 15 tpy for PMio, and 10 tpy for PM2.5) when determining PSD applicability for these pollutants. As shown in Table 1-4, the proposed Lucerne 2 Expansion emissions for all non-GHG pollutants are less than their respective SER. Therefore, the proposed Lucerne 2 Expansion will be a minor source with respect to all non-GHG emissions. r DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 11-8 12. ATTACHMENT J - GHG BACT ANALYSIS This section discusses the approach used in completing the GHG BACT analysis, as well as documenting the emission units for which the GHG BACT analyses were performed. 12.1. BACT DEFINITION The requirement to conduct a BACT analysis is set forth in the PSD regulations in 40 CFR §52.21(j)(2): (I) Control Technology Review. (2) A new major stationary source shall apply best available control technology for each regulated NSR pollutant that it would have the potential to emit in significant amounts. BACT is defined in the PSD regulations 40 CFR §52.21(b)(12)(emphasis added) in relevant part as: ...an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case -by -case basis taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such a source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. Although this definition was not changed by the Tailoring Rule, differences in the characteristics of criteria pollutant and GHG emissions from large industrial sources present several GHG-specific considerations under the BACT definition which warrant further discussion. Those underlined terms in the BACT definition are addressed further below. 12.1.1. Emission Limitation BACT is "an emission limitation," not an emission reduction rate or a specific technology. While BACT is prefaced upon the application of technologies reflecting the maximum reduction rate achievable, the final result of BACT is an emission limit. Typically when quantifiable and measurable23, this limit would be expressed as an emission rate limit of a pollutant (e.g., lb/Mk/11Ru, ppm, or lb/hr).24 Furthermore, EPA's guidance on GHG BACT has indicated that GHG BACT limitations should be averaged over long-term timeframes such as 30- or 365 -day rolling average.25 23 The definition of BACT allows use of a work practice where emissions are not easily measured or enforceable. 40 CFR §52.21(b)(12). 24 Emission limits can be broadly differentiated as "rate -based" or "mass -based." For a turbine, a rate -based limit would typically be in units of lb/MMBtu (mass emissions per heat input). In contrast, a typical mass -based limit would be in units of lb/hr (mass emissions per time). 25 PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, page 46. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-1 12.1.2. Each Pollutant Since BACT applies to "each pollutant subject to regulation under the Act," the BACT evaluation process is typically conducted for each regulated NSR pollutant individually and not for a combination of pollutants.26 For PSD applicability assessments involving GHGs, the regulated NSR pollutant subject to regulation under the Clean Air Act (CAA) is the sum of six greenhouse gases and not a single pollutant.27 In the final Tailoring Rule preamble, EPA went beyond applying this combined pollutant approach for GHGs to PSD applicability and made the following recommendations that suggest applicants should conduct a single GIG BACT evaluation on a COze basis for emission sources that emit more than one GHG: However, we disagree with the commenter's ultimate conclusion that BACT will be required for each constituent gas rather than for the regulated pollutant, which is defined as the combination of the six well - mixed GHGs. To the contrary, we believe that, in combination with the sum -of -six gases approach described above, the use of the CO2e metric will enable the implementation offlexible approaches to design and implement mitigation and control strategies that look across all six of the constituent gases comprising the air pollutant (e.g, flexibility to account for the benefits of certain CH4 control options, even though those options may increase CO2). Moreover, we believe that the CO2e metric is the best way to achieve this goal because it allows for tradeoffs among the constituent gases to be evaluated using a common currency.2d For the proposed project, the GHG emissions are driven primarily by CO2. CO2 emissions represent more than 99% of the total CO2e for the project as a whole. As such, the following top -down GHG BACT analysis should and will focus on CO2. 12.1.3. BACT Applies to the Proposed Source BACT applies to the type of source proposed by the applicant. BACT does not redefine the source. The applicant defines the source (i.e., its goals, aims and objectives). Although BACT is based on the type of source as proposed by the applicant, the scope of the applicant's ability to define the source is not absolute. A key task for the reviewing agency is to determine which parts of the proposed process are inherent to the applicant's purpose and which parts may be changed without changing that purpose. The proposed project is discussed in Section 1 of and a process description has been included in Section 9 (Attachment G) of this application to aid the technical reviewers in need and scope of this project and how GHG BACT should be reviewed in light of this detailed information. 12.1.4. Case -By -Case Basis Unlike many of the CAA programs, the PSD program's BACT evaluation is case -by -case. BACT permit limits are not simply the requirement for a control technology because of its application elsewhere or the direct transference of the lowest emission rate found in other permits for similar sources, applied to the proposed source. EPA has explained how the top -down BACT analysis process works on a case -by -case basis. To assist applicants and regulators with the case -by -case process, in 1990 EPA issued a Draft Manual on New Source Review permitting which included a "top -down" BACT analysis. In brief the top -down process provides that all available control technologies be ranked in descending order of control effectiveness. The PSD applicant first examines the most stringent--or"top"--alternative. That alternative is established as BACT unless the applicant demonstrates, and the permitting authority in 26 40 CFR 552.21(b)(12) 27 40 CFR § 52.21(b) (49) (i) 2675 FR 31,531, Prevention of Significant Deterioration and Title VGreenhouse Gas Tailoring Rule; Final Rule, June 3, 2010. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-2 its informed judgment agrees, that technical considerations, or energy, environmental, or economic impacts justify a conclusion that the most stringent technology is not "achievable" in that case. If the most stringent technology is eliminated in this fashion, then the next most stringent alternative is considered, and so on.29 The five steps in a top -down BACT evaluation can be summarized as follows: > Step 1. Identify all available control technologies; • Step 2. Eliminate technically infeasible options; 9 Step 3. Rank the technically feasible control technologies by control effectiveness; > Step 4. Evaluate most effective controls; and > Step 5. Select BACT. While this EPA -recommended five -step process can be directly applied to GHGs without any significant modifications, it is important to note that the top -down process is conducted on a unit -by -unit, pollutant -by - pollutant basis and only considers the portions of the facility that are considered "emission units" as defined under the PSD regulations.30 12.1.5. Achievable BACT is to be set at the lowest value that is "achievable." However, there is an important distinction between emission rates achieved at a specific time on a specific unit, and an emission limitation that a unit must be able to meet continuously over its operating life. As discussed by the DC Circuit Court of Appeals: In National Lime Ass'n v. EPA, 627F.2d 416, 431 n.46 (D.C. Cir. 1980), we said that where a statute requires that a standard be "achievable," it must be achievable" under most adverse circumstances which can reasonably be expected to recur "31 EPA has reached similar conclusions in prior determinations for PSD permits. Agency guidance and our prior decisions recognize a distinction between, on the one hand, measured 'emissions rates,' which are necessarily data obtained from a particular facility at a specific time, and on the other hand, the 'emissions limitation' determined to be BACT and set forth in the permit, which the facility is required to continuously meet throughout the facility's life. Stated simply, if there is uncontrollable fluctuation or variability in the measured emission rate, then the lowest measured emission rate will necessarily be more stringent than the "emissions limitation" that is "achievable" for that pollution control method over the life of the facility. Accordingly, because the "emissions limitation" is applicable for the facility's life, it is wholly appropriate for the permit issuer to consider, as part of the BACT analysis, the extent to which the available data demonstrate whether the emissions rate at issue has been achieved by other facilities over a long term.32 i A 29 Draft NSR Manual at B-2. "The NSR Manual has been used an a guidance document in conjunction with new source review workshops and training, and as a simple guide for state and federal permitting officials with respect to PSD requirements and policy. Although it is not binding Agency regulation, the NSR Manual has been looked to be this Board as a statement of the Agency's thinking on certain PSD issues. E.g., In re RockGen Energy Ctr., 8 E.A.D. 536, 542 n. 10 (EAB 1999), In re Knauf Fiber Glass, GmbH, 8 E.A.D. 121, 129 n. 13 (EAB 1999)." In re Prairie State Generating Company 13 E.A.D. 1, 13 n 2 (2006) 3° Pursuant to 40 CFR §52.21(a)(7), emission unit means any part of a stationary source that emits or would have the potential to emit any regulated NSR pollutant. 21 As quoted in Sierra Club v. U.S. EPA (97-1686). 32 U.S. EPA Environmental Appeals Board decision, In re: Newmont Nevada Energy Investment L.L.C. PSD Appeal No. 05-04, decided December 21, 2005. Environmental Administrative Decisions, Volume 12, Page 442. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-3 L \i Thus, BACT must be set at the lowest feasible emission rate recognizing that the facility must be in compliance with that limit for the lifetime of the facility on a continuous basis. While viewing individual unit performance can be instructive in evaluating what BACT might be, any actual performance data must be viewed carefully, as rarely will the data be adequate to truly assess the performance that a unit will achieve during its entire operating life. To assist in meeting the BACT limit, the source must consider production processes or available methods, systems or techniques, as long as those considerations do not redefine the source. 12.1.6. Production Process The definition of BACT lists both production processes and control technologies as possible means for reducing emissions. 12.1.7. Available The term "available" in the definition of BACT is implemented through a feasibility analysis - a determination that the technology being evaluated is demonstrated or available and applicable. 12.1.8. Floor For criteria pollutants, the least stringent emission rate allowable for BACT is any applicable limit under either New Source Performance Standards (NSPS - Part 60) or National Emission Standards for Hazardous Air Pollutants (NESHAP - Parts 61). Since no GHG limits have been incorporated into any existing NSPS or Part 61 NESHAPs, no floor for a GHG BACT analysis is available for consideration. On March 27, 2012, the EPA Administrator signed proposed Standards of Performance for GHG Emissions for Electric Utility Generating Units by adding Subpart TTTT to 40 CFR Part 60 (NSPS Subpart TTTT). Per proposed 40 CFR 60.5509, the rule applies to electric generating units with a base load rating of more than 250 MMBtu/hr heat input of fossil fuel. The simple cycle combustion turbines from the proposed project have a heat input capacity of 65 MMBtu/hr, hence these are not subject to the proposed NSPS Subpart TTTT. 12.2. GHG BACT ASSESSMENT METHODOLOGY GHG BACT for the proposed project has been evaluated via a "top -down" approach which includes the steps outlined in the following subsections. EPA's March 2011 GHG Permitting Guidance generally directed that a BACT review for GHGs should be done in the same manner as it is done for any other regulated pollutant.33 It should be noted that the scope of a BACT review was clarified in two ways with respect to GHGs: EPA stressed that applicants should clearly define the scope of the project being reviewed. 34 DCP has provided this information in Section 1 and Section 9 (Attachment G) of this application. 33 PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, page 17. 34 PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, pages 22-23. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-4 > EPA clarified that the scope of the BACT should focus on the project's largest contributors to COze and may subject less significant contributors for COze to less stringent BACT review.35 Because the project's GHG emissions are dominated by the amine unit via the RTO (and more specifically direct CO2 emissions) and combustion turbines, this BACT analysis focuses mainly on these predominant sources of COze from the project. However, GHG emissions from small emission sources such as storage tanks are also included in the BACT analysis. 12.2.1. Step 1 - Identify All Available Control Technologies Available control technologies for COze with the practical potential for application to the emission unit are identified. The application of demonstrated control technologies in other similar source categories to the emission unit in question can also be considered. While identified technologies may be eliminated in subsequent steps in the analysis based on technical and economic infeasibility or environmental, energy, economic or other impacts, control technologies with potential application to the emission unit under review are identified in this step. Under Step 1 of a criteria pollutant BACT analysis, the following resources are typically consulted when identifying potential technologies: 1. EPA's Reasonably Available Control Technology (RACT)/Best Available Control Technology (BACT)/Lowest Achievable Emission Reduction (LAER) Clearinghouse (RBLC) database; 2. Determinations of BACT by regulatory agencies for other similar sources or air permits and permit files from federal or state agencies; 3. Engineering experience with similar control applications; 4. Information provided by air pollution control equipment vendors with significant market share in the industry; and/or S. Review of literature from industrial technical or trade organizations. A search of the RBLC database showed GHG BACT records for CO2e. However, since it is a new requirement, the records do not contain sources applicable to the Lucerne 2 Expansion. Primarily, DCP will rely on items (2) through (5) and preliminary information from the EPA BACT GHG Workgroup for data to establish BACT. EPA's "top -down" BACT analysis procedure also recommends the consideration of inherently lower emitting processes as available control options under Step 1.36 For GHG BACT analyses, low -carbon intensity fuel selection is the primary control option that can be considered a lower emitting process. DCP proposes the use of pipeline quality natural gas only for all combustion equipment associated with the proposed project. Table C-1 of 40 CFR Part 98 shows CO2 emissions per unit heat input (MMBtu) for a wide variety of industrial fuel types. Only biogas (captured methane) and coke oven gas result in lower CO2 emissions per unit heat input than natural gas, but these fuel types are not readily available for this project. Additionally, EPA's GIG BACT guidance suggests that carbon capture and sequestration (CCS) be evaluated as an available control for substantial, large projects such as steel mills, refineries, and cement plants where CO2e emissions levels are in the order of 1,000,000 tpy, or for industrial facilities with high -purity CO2 streams.37 However, EPA explained that "[t]his does not necessarily mean CCS should be selected as BACT for such sources." The proposed project emissions are approximately 265, 586 tpy CO2e (including maintenance emissions from compressor blowdowns). Only the amine unit (used to remove CO2 from the inlet gas), which 35 PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, page 31. =e PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, page 24. PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, pages 32-33. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-5 exhausts through the RTO, results in a concentrated CO2 stream with sulfur compound and VOC impurities. All other emission sources result in low purity CO2 streams. Nonetheless, CCS is evaluated as a control option for the proposed project. 12.2.2. Step 2 - Eliminate Technically Infeasible Options After the available control technologies have been identified, each technology is evaluated with respect to its technical feasibility in controlling GHG emissions from the source in question. The first question in determining whether or not a technology is feasible is whether or not it is demonstrated. If so, it is feasible. Whether or not a control technology is demonstrated is considered to be a relatively straightforward determination. Demonstrated "means that it has been installed and operated successfully elsewhere on a similar facility." Prairie State, slip op. at 45. "This step should be straightforward for control technologies that are demonstrated --if the control technology has been installed and operated successfully on the type of source under review, it is demonstrated and it is technically feasible."38 An undemonstrated technology is only technically feasible if it is "available" and "applicable." A control technology or process is only considered available if it has reached the licensing and commercial sales phase of development and is "commercially available .39 Control technologies in the R&D and pilot scale phases are not considered available, Based on EPA guidance, an available control technology is presumed to be applicable if it has been permitted or actually implemented by a similar source. Decisions about technical feasibility of a control option consider the physical or chemical properties of the emissions stream in comparison to emissions streams from similar sources successfully implementing the control alternative. The NSR Manual explains the concept of applicability as follows: "An available technology is "applicable" if it can reasonably be installed and operated on the source type under consideration."40 Applicability of a technology is determined by technical judgment and consideration of the use of the technology on similar sources as described in the NSR Manual. 12.2.3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness All remaining technically feasible control options are ranked based on their overall control effectiveness for GHG. For GHGs, this ranking may be based on energy efficiency and/or emission rate. 12.2.4. Step 4 - Evaluate Most Effective Controls and Document Results After identifying and ranking available and technically feasible control technologies, the economic, environmental, and energy impacts are evaluated to select the best control option. If adverse collateral impacts do not disqualify the top -ranked option from consideration it is selected as the basis for the BACT limit. Alternatively, in the judgment of the permitting agency, if unreasonable adverse economic, environmental, or energy impacts are associated with the top control option, the next most stringent option is evaluated. This process continues until a control technology is identified. EPA recognized in its BACT guidance for GHGs that " [ejven if not eliminated at Step 2 of the BACT analysis, on the basis of the current costs of CCS, we expect that 36 NSR Workshop Manual (Draft), Permitting, page B.17. 39 NSR Workshop Manual (Draft), Permitting, page B.18. NSR Workshop Manual (Draft), Permitting, page B.18. DCP Midstream LP I Lucerne 2 Trinity Consultants Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Expansion 12-6 CCS will often be eliminated from consideration in Step 4 of the BACT analysis, even in some cases where underground storage of the captured CO2 near the power plant is feasible."4' The energy, environment, and economic impacts analysis under Step 4 of a GHG BACT assessment presents a unique challenge with respect to the evaluation of CO2 and CH4 emissions. The technologies that are most frequently used to control emissions of CH4 in hydrocarbon -rich streams (e.g., flares and thermal oxidizers) actually convert CH4 emissions to CO2 emissions. Consequently, the reduction of one GHG (i.e., CH4) results in a proportional increase in emissions of another GHG (i.e., CO2). However, since the GWP of CH4 is 21 times higher than CO2, conversion of CH4 emissions to CO2 results in a net reduction of CO2e emissions. Permitting authorities have historically considered the effects of multiple pollutants in the application of BACT as part of the PSD review process, including the environmental impacts of collateral emissions resulting from the implementation of emission control technologies. To clarify the permitting agency's expectations with respect to the BACT evaluation process, states have sometimes prioritized the reduction of one pollutant above another. For example, technologies historically used to control NOx emissions frequently caused increases in CO emissions. Accordingly, several states prioritized the reduction of NOx emissions above the reduction of CO emissions, approving low NOx control strategies as BACT that result in higher CO emissions relative to the uncontrolled emissions scenario. 12.2.5. Step 5 - Select BACT In the final step, the BACT emission limit is determined for each emission unit under review based on evaluations from the previous step. Although the first four steps of the top -down BACT process involve technical and economic evaluations of potential control options (i.e., defining the appropriate technology), the selection of BACT in the fifth step involves an evaluation of emission rates achievable with the selected control technology. BACT is an emission limit unless technological or economic limitations of the measurement methodology would make the imposition of an emissions standard infeasible, in which case a work practice or operating standard can be imposed. Establishing an appropriate averaging period for the BACT limit is a key consideration under Step 5 of the BACT process. Localized GHG emissions are not known to cause adverse public health or environmental impacts. Rather, EPA has determined that GHG emissions are anticipated to contribute to long-term environmental consequences on a global scale. Accordingly, EPA's Climate Change Workgroup has characterized the category of regulated GHGs as a "global pollutant." Given the global nature of impacts from GHG emissions, NAAQS are not established for GHGs in the Tailoring Rule and a dispersion modeling analysis for GHG emissions is not a required element of a PSD permit application for GHGs. Since localized short-term health and environmental effects from GHG emissions are not recognized, DCP proposes only an annual average GHG BACT limit. 12.3. GHG BACT REQUIREMENT The GHG BACT requirement applies to each new emission unit from which there are emissions increases of GHG pollutants subject to PSD review. The estimated emissions increase of GHGs from the proposed project will be greater than 100,000 tpy on a CO2e basis primarily due to the removal of CO2 in the amine unit which is emitted when the process gas streams are combusted and released by the RTO. Potential emissions of GHGs from the proposed project will result from the following emission units: ^� PSD and Title V Permitting Guidance for Greenhouse Gases. March 2011, pages 42-43. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-7 Amine Unit (Direct Emissions); > TEG Dehydration Unit; • Amine Unit (Indirect Emissions from combustion in the RT0); • Combustion Turbines; > Hot Oil Heater; > Fugitive Emissions from Piping Components; and > Emergency Flare. Table 1-3 provides a summary of the estimated maximum annual potential to emit GHG emission rates for the proposed project. GHG emissions for each emission unit were estimated based on proposed equipment specifications as provided by the manufacturer and the default emission factors in the EPA's Mandatory Greenhouse Reporting Rule (4O CFR 98, Subpart C and Subpart W). The following guidance documents were utilized as resources in completing the GHG BACT evaluation for the proposed project: > PSD and Title V Permitting Guidance for Greenhouse Gases (hereafter referred to as General GHG Permitting Guidance)42 > Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and Industrial Boilers (hereafter referred to as GHG BACT Guidance forBoilers)43 > Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from the Petroleum Refining Industry (hereafter referred to as GHG BACT Guidance for Refineries)44 12.4. GHG BACT EVALUATION FOR PROPOSED EMISSION SOURCES The following is an analysis of BACT for the control of GHG emissions from the project following the EPA's five - step "top -down" BACT process. The table at the end of this section summarizes each step of the BACT analysis for the emission units included in this review. Table 12-1 provides a summary of the proposed BACT limits discussed in the following sections. 43 U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning http: //www.epa.goyinsrighgdocsighgpermittingguidance.pdf 43 U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning http://www.epa.gov/nsr/ghgdocs/iciboilers.pdf ^^ U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning http: / /www.epa.gov/nsr/ghgdocs/refineries.pdf DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants and Standards, (Research Triangle Park, NC: March 2011). and Standards, (Research Triangle Park, NC: October 2010). and Standards, (Research Triangle Park, NC: October 2010). 12-8 Table 12-1. Potential GHG BACT Limits for Lucerne 2 Expansion ,,,, 99% DRE of Methane Amine Unit TEG Dehydration Unit 95% DRE of Methane Combustion Turbines and WHRU 40% Thermal Efficiency Hot Oil Heater 315 MMscf/yr fuel limit Emergency Flare Work Practice Standards Fugitive Emissions from Piping Components Work Practice Standards Detailed BACT analysis is conducted for all CO2e contributors. 12.5. OVERALL PROJECT ENERGY EFFICIENCY CONSIDERATIONS While the five -step BACT analysis is the EPA's preferred methodology with respect to selection of control technologies for pollutants, EPA has also indicated that an overarching evaluation of energy efficiency should take place as increases in energy efficiency will inherently reduce the total amount of GHG emissions produced by the source 45 As such, overall energy efficiency was a basic design criterion in the selection of technologies and processing alternatives to be installed for the Lucerne 2 Expansion project. i The proposed 230 MMscfd expansion project at the Lucerne Plant will be designed and constructed using all new, energy efficient equipment. The proposed expansion is designed for the need for additional processing capacity to process the rapidly growing gas volumes that are being developed. This is accomplished using a state of the art recovery process incorporating multiple exchangers for maximum heat recovery/integration and high efficiency mass transfer equipment. 12.6. AMINE UNIT (DIRECT EMISSIONS) The amine unit at the Lucerne 2 Expansion will be used to remove CO2 in order to meet pipeline quality natural gas specifications. Because the amine unit is designed to remove CO2 from the natural gas, the generation of CO2 is inherent to the process, and a reduction of the CO2 emissions by process changes would only be achieved by a reduction in the process efficiency and would result in more CO2 in the gas which would be released downstream. 12.6.1. Step 1 - Identify All Available Control Technologies The available GHG emission control options for the process emissions (amine unit acid gas stream and TEG Unit): Carbon Capture and Sequestration Flare/Combustor Thermal Oxidizer 45 PSD and Title V permitting Guidance for Greenhouse Gases. March 2011, pages 21-22. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-9 > Condenser • Proper Design and Operation > Use of Tank Off -gas Recovery Systems 12.6.1.1. Carbon Capture and Sequestration As CO2 separation is one of the primary objectives of the amine unit, the amine regeneration unit produces a gas stream with a high CO2 content compared to a typical exhaust stream from a combustion unit. Accordingly, CCS is one possible option for control of GHG emissions from the amine regeneration unit. It is assumed CCS would sequester at least 90% of the CO2 from the source in question. An effective CCS system would require three elements: > Separation technology for the CO2 exhaust stream (i.e., "carbon capture" technology), > Transportation of CO2 to a storage site, and > A viable location for long-term storage of CO2. These three elements work in series. To execute a CCS program as BACT, all three elements must be 'available' for this project. Geologic sequestration of CO2 can be achieved by one of two methods: (1) CO2 can be used in Enhanced Oil Recovery (FOR) projects, or (2) a well dedicated to CCS (i.e., a Class VI well) can be drilled and permitted. EOR technology enhances oil recovery rates by reinjecting CO2 and hydrocarbon gases recovered from the well (and CO2 from external sources, as needed) into the geologic formation to maintain well pressure. This technology is designed to maintain pressure in an active well, rather than for the long term sequestration of CO2. Consequently, FOR projects are not designed with the same considerations for permanent CO2 sequestration when compared to Class VI wells intended specifically for CCS. While FOR has been commercially demonstrated FOR cannot be considered an available technology in this BACT assessment for the following reason: The DCP Lucerne facility is not designed to perform EOR. If DCP sold CO2 as a commodity to FOR injection fields, the lifetime of the contract(s) must equal the lifetime of the facility; else FOR would not be a sustainable control option for the DCP Lucerne facility. This would pose significant logistical challenges, such as matching the relatively constant output of CO2 at the facility to the varying CO2 demand of an FOR system. As FOR operation continues and the CO2 content of a formation increases, more CO2 would be recovered from the well(s) for reinjection, resulting in a declining demand for supplemental CO2 from external sources over the lifetime of a given FOR project.46 Therefore, FOR cannot be considered as an available BACT technology. For these reasons FOR is not considered an available technology for the permanent sequestration of CO2 from the DCP Lucerne facility. However, to ensure that the option to use CCS technology to capture CO2 emissions from the Lucerne facility is thoroughly evaluated in this application, discussions of the technical and economic feasibility of CCS are presented in Steps 2 and 4 of this BACT analysis, respectively. DCP conducted research and analysis to determine the technical feasibility of CO2 capture and transfer. Since most of the CO2 emissions from the proposed project are generated from the amine unit, DCP evaluated potential options to capture and transfer the CO2 to an off -site facility for injection. 46 MIT Laboratory for Energy and the Environment, "The Economics of CO2 Storage," August 2003, p. 37. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-10 Based on the results of these studies, capture and transfer of C02 from the amine treatment unit is technically feasible. A study was performed to evaluate the potential options for capture and transfer of C02 from the Lucerne Plant (located near Greeley in Weld County, CO) to nearby C02 injection wells. The transfer of the CO2 stream would require further treatment to remove contaminants and compression for transfer via a new pipeline. Since capture and transfer of C02 for off -site transfer is technically feasible for the proposed project, this option is further evaluated for energy, environmental, and economic impacts. 12.6.1.2. Flare/Combustor One option to reduce the GHGs emitted from the Lucerne 2 Expansion is to send stripped amine acid gases and dehydrator waste gases to a flare. Flares and combustors are examples of control devices in which the control of certain pollutants causes the formation of collateral GHG emissions. The control of CH4 in the process gas at the flare results in the creation of additional C02 emissions via the combustion reaction mechanism. However, given the relative GWPs of C02 and CH4 and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional C02 emissions. In general, flares have a destruction efficiency rate (DRE) of 98%, resulting in minor CH4 emissions from the process flare due to incomplete combustion of CH4. Additionally, flares and combustors require the use of a continuous pilot ignition system or equivalent that results in additional GHG emissions. 12.6.1.3. Thermal Oxidizers Another option to reduce the GHGs emitted from the Lucerne 2 Expansion is to send stripped amine acid gases and dehydrator waste gases to a thermal oxidizer (TO). The TO is an example of a control device in which the control of certain pollutants causes the formation of collateral GHG emissions, the control of CH4 in the process gas at the TO results in the creation of additional CO2 emissions via the combustion reaction mechanism. However, given the relative GWPs of C02 and CH4 and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional C02 emissions. A regenerative thermal oxidizer (RTO) has a high efficiency heat recovery. This allows the facility to recover heat from the exhaust stream, reducing the overall heat input of the plant. In general, TOs have a destruction efficiency rate (DRE) greater than of 99%, resulting in minor CH4 emissions from the process flare due to incomplete combustion of CH4. In contrast with a flare or a combustor, which requires the use of additional fuel to maintain a constant pilot, a RTO only uses additional natural gas to get up to the optimum temperature for combustion resulting in lower use of assist gas and lower GHG emissions due to pilot burning when compared to a flare or a combustor. 12.6.1.4. Condenser Condensers are supplemental emissions control that reduces the temperature of the still column vent vapors on amine units to condense water and VOCs, including CH4. The condensed liquids are then collected for further treatment or disposal. The reduction efficiency of the condensers is variable and depends on the type of condenser and the composition of the waste gas, ranging from 50-98% of the CH4 emissions in the waste gas stream. 12.6.1.5. Proper Design and Operation The amine unit will be among the new equipment installed on site. New equipment has better energy efficiency, hence reducing the GHGs emitted during combustion. The amine unit will be fired by using pipeline quality natural gas to minimize the GHG emissions and will operate at a minimum circulation rate with consistent amine concentrations. By minimizing the circulation rate, the amine unit avoids pulling out additional VOCs and GHGs DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 12-11 . ease VOC and GHG emissions into the atmosphere. The amine unit still a by an RTO with a 96% DRE for VOCs and 99% for CH4.47 The unit is recycling off -gas back to the plant inlet, including CH4, from the rich amine stream .alting in a reduction of waste gases created. ,, Tank Off -gas Recovery Systems unit will be equipped with a flash tank. The flash tank will be used to recycle the off -gases back into ant for reprocessing, instead of venting to the atmosphere or combustion device. The use of flash tanks creases the effectiveness of other downstream control devices. 12.6.2. Step 2. Eliminate technically infeasible options The technical infeasibility of CCS is discussed below. CCS has been classified as an unavailable control technology in Step 1, but voluntary analysis of the technology through Steps 2 and 4 of this BACT analysis is also provided to demonstrate its technical infeasibility and extreme costs. All other control technologies listed in Step 1 are considered technically feasible for implementation at the Lucerne facility. As explained in EPA's 1990 Draft New Source Review Manual: "[I]f the control technology has been installed and operated successfully on the type of source under review, it is demonstrated and it is technically feasible. For control technologies that are not demonstrated in the sense indicated above the analysis is somewhat more involved." "Two key concepts are important in determining whether an undemonstrated technology is feasible: 'availability' and 'applicability.'.... a technology is considered 'available' if it can be obtained by the applicant through commercial channels or is otherwise available within the common sense meaning of the term. An available technology is 'applicable' if it can reasonably be installed and operated on the source type under construction. A technology that is available and applicable is technically feasible". 48 Geologic CO2 storage is not a feasible technology because CO2 storage systems are still in the testing phase of development by the US Department of Energy (DOE). Until this testing is complete, geologic carbon storage is not considered to have been operated successfully or, therefore, available. Carbon sequestration poses a number of issues before the technology can be safely and effectively deployed on the commercial scale. For example, the following items still need to be proven and documented on a large-scale (greater than 1 million metric tons CO2 injected). Permanent storage must be proven by validating that CO2 will be contained in the target formations. Technologies and protocols must be developed to quantify potential releases and to confirm that the projects do not adversely impact underground sources of drinking water (USDWs) or cause CO2 to be released to the atmosphere. > Long term monitoring of the migration of CO2 during and after project completion must be completed. Methodologies to determine the presence/absence of release pathways must be developed. > Effective regulatory and legal framework must be developed for the safe, long term injection and storage of CO2 into geological formations. 47 The actual DRE of the RTO is 99% per the manufacturer. For conservatism, DCP is applying a lower DRE of 96% for VOCs but applying 99% control for CH4. 48 U.S. EPA, Draft New Source Review Manual, p. B.17, 1990. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-12 A conservative estimate on the cost of equipment for the above purposes is assumed to be $50,000,000.53 The cost of transportation to the closest pipeline (assuming 15 miles away) was calculated using the NETL method. The net cost of transfer (including materials, labor, miscellaneous, right of way, interest rates) was estimated to be roughly $1.5 million/yr as shown at the end of this section. DCP estimates the net capital cost for the project is equal to about $200,000,000. The capital cost for DCP's Lucerne 2 Expansion and the expected CCS capital cost were both annualized. A ratio of the CCS capital cost to DCP's project cost was taken to determine the additional amount that DCP would need to invest in order to successfully implement CCS. The project specific ratio is determined to be roughly 34%. Therefore, the employment of CCS in the current system is conclusively proved to be an economically infeasible option. In addition to being economically infeasible, installation of CCS will also increase energy demand by approximately 15-30%.54 In addition to increased emissions from the additional equipment, the addition of compressors will drive the emissions of other pollutants, such as NOx and CO, up and will also contribute to making the project PSD major for NOx due to the emissions increasing above PSD major source threshold. In conclusion, while CCS is an attractive option for an amine vent stream that contains fairly concentrated CO2, there are other reasons for technical, economical, and environmental infeasibility. Additionally, as discussed above, vent gases resulting from the processing of natural gas through amine units are often combusted by using a flare, combustor or a RTO before they are released into the atmosphere to reduce the amount of released VOCs and HAPs. These control options have varying destruction efficiency rates which ultimately results in higher or lower GHG emissions. However, flares and combustors do not allow for heat recovery and increased energy efficiency that enclosed combustion systems like a RTO can offer. Consequently, DCP has elected to use a RTO as the primary control technology for the amine unit. 12.6.5. Step 5. Select BACT DCP proposes the following design elements and work practices as BACT for the amine unit: > Regenerative thermal oxidizer (RT0); > Proper Design and Operation of amine units; and A Use of Tank Off -gas Recovery Systems. In addition, DCP proposes a 99% DRE offered by the RTO for control of the methane emissions. This includes CO2 and CH4 emissions, with CO2 emissions being more than 99% of the total emissions. Compliance with these emission limits and throughput limits will be demonstrated by monitoring amine throughput rate and performing calculations consistent with those in Attachment C of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average ratio of short tons of CO2e per year emission rates per throughput do not exceed these limits. 53 $50 million based on best engineering estimate for the units required. 54 Prospects for Carbon Capture and Storage Technologies http: / /www. rfforg/documents/RFF-DP-02-68. pdf DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-15 12.7. TEG DEHYDRATOR 12.7.1. Step 1 — Identify All Available Control Technologies The available GHG emission control strategies for the RTO combustion emissions include: > Carbon Capture and Sequestration > Flare/Combustor > Thermal Oxidizer 9 Condenser > Proper Design and Operation > Use of Tank Off -gas Recovery Systems 12.7.1.1. Carbon Capture and Sequestration A detailed discussion of CCS technology is provided in Section 12.6.1.1. 12.7.1.2. Flare/Combustor A detailed discussion on the flare/combustor is provided in Section 12.6.1.2. 12.7.1.3. Thermal Oxidizer A detailed discussion on the thermal oxidizer is provided in Section 12.6.1.3. 12.7.1.4. Condenser A detailed discussion on the condenser is provided in Section 12.6.1.4. 12.7.1.5. Proper Design and Operation The TEG dehydrator will be one of the new equipment installed on site. New equipment has better energy efficiency, hence reducing the GHGs emitted during combustion. The new equipment will operate at an optimal circulation rate. By optimizing the circulation rate, the equipment avoids pulling out additional VOCs and GHGs in the glycol stream, which would increase VOC and GHG emissions into the atmosphere. The TEG dehydrator regeneration overhead stream will be controlled with a condenser and an enclosed combustor with a 95% DRE 55 The unit is equipped with a flash tank for recycling off -gas back to the plant inlet, including CO2 and CH4, from the rich dehydrator stream prior to regeneration, resulting in a reduction of waste gases created. 12.7.1.6. Use of Tank Off -gas Recovery Systems The TEG dehydrator will be equipped with a flash tank. The flash tank will be used to recycle the off -gases back into the plant for reprocessing, instead of venting to the atmosphere or combustion device. The use of flash tanks increases the effectiveness of other downstream control devices. 55 An enclosed combustor can demonstrate DRE as high as 98%. For conservatism, DCP is applying a tower DRE of 95%. DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 12-16 12.7.2. Step 2 - Eliminate Technically Infeasible Options As discussed above under the amine unit BACT section, all the above options are technically feasible. CCS does have its challenges, however DCP is continuing this assessment with the assumption that CCS is technically feasible 12.7.3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness CCS (i.e., sequestration or transfer of CO2) is the most effective control option for the control of the CO2 streams from the TEG dehydrator, since it provides approximately 90% CO2 control of the dehydrator vent stream, based on literature review. Other control technologies do not destroy or reduce the amount of CO2 produced by the TEG dehydrator. Therefore, given the relative GWPs of CO2 and CH4, 1 and 21 respectively, and the destruction of VOCs and HAPs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional CO2 emissions. RTO have higher destruction efficiencies compared to flares/combustors, 99% and 98% respectively, and uses less pilot gas fuel, resulting in overall lower GHG emissions. The implementation of good combustion, operating, and maintenance practices; and the use of condensers and flash tanks for off -gas recycle are technically feasible control options for minimizing GHG emissions from fuel combustion and waste gas streams, respectively 12.7.4. Step 4 - Evaluate Most Effective Control Options The TEG dehydrator vent stream does not contain a pure CO2 stream since most of the CO2 is stripped out in the upstream amine unit. Therefore, in addition to compression and transmission of CO2, a process to isolate and purify the CO2 is also required. This adds more reasons for technical, economical, and environmental infeasibility. Additionally, as discussed above, vent gases resulting from the processing of natural gas through TEG dehydrators are often combusted by using a flare, combustor or a RTO before they are released into the atmosphere to reduce the amount of released VOCs and HAPs. These control options have varying destruction efficiency rates which ultimately results in higher or lower GHG emissions. DCP has elected to use a flare or an enclosed combustor as the primary control technology for the TEG dehydrator because of unsafe operations that result from routing the vent to a RTO. In DCP's experience, routing the dehydrator vent stream to a RTO results in uncontrolled detonation that raises safety concerns. 12.7.5. Step 5 - Select BACT for the RTO DCP proposes the following design elements and work practices as BACT for the TEG dehydrator: > Flare (enclosed combustor); > Proper Design and Operation of TEG dehydrators; > Use of Tank Off -gas Recovery Systems; and > Use of a Condenser. In addition, DCP proposes a 95% DRE with the use of an enclosed combustor on the methane portion of the still vent stream. i DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-17 Compliance with these emission limits and throughput limits will be demonstrated by monitoring inlet gas throughput rate and performing calculations consistent with those in Attachment A of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average ratio of short tons of CO2e per year emission rates per throughput do not exceed these limits. 12.8. AMINE UNIT (INDIRECT EMISSIONS a RTO) 12.8.1. Step 1 — Identify All Available Control Technologies The available GHG emission control strategies for the RTO combustion emissions include: > Carbon Capture and Sequestration; > Proper RTO Design, Operation, and Maintenance; > Fuel Selection; and > Good Combustion Practices. 12.8.1.1. Carbon Capture and Sequestration A detailed discussion of CCS technology is provided in Section 12.6.1.1. 12.8.1.2. Proper RTO Design, Operation, and Maintenance Good RTO design can be employed to destroy any VOCs and CH4 entrained in the waste gas from the amine unit. Good RTO design includes flow measurement and monitoring/control of waste gas heating values. In addition, periodic tune-up and maintenance will be performed per the manufacturer recommendation. 12.8.1.3. Fuel Selection The fuel for firing the proposed RTO will be limited to natural gas fuel. Natural gas has the lowest carbon intensity of any available fuel for the RTO. In addition, the RTO will utilize the gas -fired burner system to bring the RTO up to combustion temperature during startup only. After the system has reached temperature, the burners will be shut off and the system will function using the energy content of the amine waste stream alone to support combustion. 12.8.1.4. Good Combustion, Operating, and Maintenance Practices Good combustion and operating practices are a potential control option, achieved by improving the fuel efficiency of the RTO. Good combustion practices also include proper maintenance and tune-up of the RTO at least annually per the manufacturer's specifications. 12.8.2. Step 2 — Eliminate Technically Infeasible Options All control options identified in Step 1 are technically feasible. 12.8.3. Step 3 — Rank Remaining Control Technologies by Control Effectiveness CCS (i.e., sequestration or transfer of CO2) is the most effective control option for the control of the CO2 stream from the amine unit to the RTO, since it provides approximately 90% CO2 control of the gas stream, based on literature review. DCP Midstream LP r Lucerne 2 Expansion Trinity Consultants 12-18 Good RTO design and operation result in approximately 1-15% and 1-10% reduction in GHG emissions, respectively. 56 Low carbon fuel selection and the implementation of good combustion, operating, and maintenance practices are technically feasible control options for minimizing GHG emissions from fuel combustion. 12.8.4. Step 4 - Evaluate Most Effective Control Options The only technically feasible technology listed in Step 3 that may have additional energy, environmental, and economic impacts is CO2 capture and transfer. While the process exhaust stream is relatively high in CO2 content, additional processing of the exhaust gas will be required to implement CCS. These include separation (removal of other pollutants from the combustion gases), capture, and compression of CO2, transfer of the CO2 stream and sequestration of the CO2 stream. These processes require additional equipment to reduce the exhaust temperature, compress the gas, and transport the gas via pipelines. These units would require additional electricity and generate additional air emissions, of both criteria pollutants and GHG pollutants. This would result in negative environmental and energy impacts. Therefore, based on the pipeline transfer cost, although technically feasible, off -site transfer is not regarded as a viable or economically feasible CO2 control option. Additionally, CO2 capture and transfer would have negative environmental and energy impacts, as discussed above. 12.8.5. Step 5 — Select BACT for the RTO DCP proposes the following design elements and work practices as BACT for the RTO: • Proper RTO design, ? Proper operation and maintenance procedures; and • Use of natural gas as fuel. Compliance with emission limits and throughput limits will be demonstrated by monitoring inlet gas throughput rate and performing calculations consistent with those in Section 5 (Attachment C) of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average throughput and short tons of CO2e per year emission rates do not exceed these limits. 56 Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Petroleum Refining Industry, U.S. EPA, October 2010, Section 3. OCR Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-19 12.9. COMBUSTION TURBINE The proposed combustion turbines (CT) will be a simple cycle natural gas fired units. They will be equipped with SoLoNOxTM that guarantees uniform air/fuel ratio mixture, resulting in lower GHG emissions. The CT generates GHGs from fuel combustion: CO2, CH4, and N2O. CO2 emissions result from the combustion of carbon - containing fuel (i.e. natural gas). CH4 emissions result from incomplete combustion of natural gas and N2O emissions result from partial oxidation of nitrogen in the combustion air used. The following section presents BACT evaluations for GHG emissions from the proposed process CT. 12.9.1. Step 1 — Identify All Available Control Technologies The following table summarizes the available CO2 emission control strategies for combustion turbines that were analyzed as part of this BACT analysis. • Carbon Capture and Sequestration; > Selection of Efficient Combustion Turbine; > Fuel Selection; and > Good Combustion Practices, Operating, and Maintenance Practices. 12.9.1.1. Carbon Capture and Sequestration As previously discussed, the contribution of CO2e emissions from the combustion turbines is a fraction of the scale for sources where CCS might ultimately be feasible. Although we believe that CCS is not BACT in this case, as directly supported in EPA's GHG BACT Guidance, a detailed rationale is provided to support this conclusion. i -\ For the combustion turbine, CCS would involve post combustion capture of the CO2 from the turbine and sequestration of the CO2 in some fashion. Carbon capture is an established process in some industry sectors although not in the natural gas compression sector in continuous and/or seasonal operations. In general, carbon capture could be accomplished with low pressure scrubbing of CO2 from the exhaust stream with either solvent (e.g., amines and ammonia), solid sorbents, or membranes. However, only solvents have been used to - date on a commercial (yet slip stream) scale and solid sorbents and membranes are only in the research and development phase. A number of post -combustion carbon capture projects have taken place on slip streams at coal-fired power plants. Although these projects have demonstrated the technical feasibility of small-scale CO2 capture on a slipstream of a power plant's emissions using various solvent based scrubbing processes, until these post -combustion technologies are installed fully on a power plant, they are not considered "available" in terms of BACT. Larger scale CCS demonstration projects have been proposed through the DOE Clean Coal Power Initiative (CCPI); however, none of these facilities are operating, and, in fact, they have not yet been fully designed or constructed.57 Additionally, these demonstration projects are for post -combustion capture on a pulverized coal (PC) plant using a slip stream versus the full exhaust stream. Also, the exhaust from a PC plant would have a significantly higher concentration of CO2 in the slipstream as compared to a more dilute stream from the combustion of natural gas.58 In addition, the compression of the CO2 would require additional power demand, resulting in additional fuel consumption (and CO2 emissions) 59 57 Report of the Interagency Task Force on Carbon Capture a Storage, August 2010, p. 32. 58 Report of the Interagency Task Force on Carbon Capture a Storage, August 2010, p. A-7. 59 Report of the Interagency Task Force on Carbon Capture a Storage, August 2010, http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf, p. 29 DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 12-20 12.9.1.2. Selection of Efficient Combustion Turbine New, state of the art turbines are designed to operate efficiently. DCP selected a top of the line Solar Turbine equipped with SoLoNOxTM, a patented control that guarantees uniform air/fuel ratio mixture resulting in lower GHG emissions. 12.9.1.3. Fuel Selection The fuel for firing the proposed combustion turbine is natural gas only. Natural gas has the lowest carbon intensity of any available fuel for the combustion turbine. 12.9.1.4. Good Combustion, Operating, and Maintenance Practices Good combustion, operating, and maintenance practices are a potential control option for improving the fuel efficiency of the combustion turbines. Natural gas -fired combustion turbines typically operate in a lean pre -mix mode to ensure an effective staging of air/fuel ratios in the turbine to maximize fuel efficiency and minimize incomplete combustion. Furthermore, the turbine is sufficiently automated to ensure optimal fuel combustion and efficient operation leaving virtually no operator ability to further tune these aspects of operation. Good combustion practices also include proper maintenance and tune-up of the combustion turbine at least twice annually per the manufacturer's specifications. 12.9.2. Step 2 — Eliminate Technically Infeasible Options Given the limited deployment of only slipstream/demonstration applications of CCS and the quantity and quality of the CO2 emissions stream, CCS is not commercially available as BACT for the combustion turbine and is therefore considered infeasible and not BACT for the proposed combustion turbine. This is supported by U.S. EPA's assertion that CCS is considered "available" for projects that emit CO2 in "large" amounts and high purity CO2 streams.6° This emission unit, by comparison, emits CO2 in small amounts and low purity CO2 stream. All other control options are technically feasible. 12.9.3. Step 3 — Rank Remaining Control Technologies by Control Effectiveness Installation of the most efficient combustion turbine (i.e., combustion turbine with waste heat recovery), low carbon fuel selection, and the implementation of good combustion, operating, and maintenance practices are the remaining technically feasible control options for minimizing CO2 emissions from the CTs. Since DCP proposes to implement all these control options, ranking these control options is not necessary. 12.9.4. Step 4 — Evaluate Most Effective Control Options No adverse energy, environmental, or economic impacts are associated with turbine selection, low -carbon fuel selection, and good combustion, operating, and maintenance practices. 12.9.5. Step 5 — Select BACT for the Combustion Turbines DCP proposes the following design elements and work practices as BACT for the CTs: b0 PSD and Title V permitting Guidance for Greenhouse Gases. March 2011, page 32. "For the purposes of a BACT analysis for GHGs, U.S. EPA classifies CCS as an add-on pollution control technology86 that is "available"8r for facilities emitting CO2 in large amounts, including fossil fuel -fired power plants, and for industrial facilities with high -purity CO2 streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing). The proposed project is not any of the cases U.S. EPA suggests above. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-21 > Installation of an efficient CT; > Use of natural gas as fuel; > Increase overall energy efficiency via utilizing the waste gas heat from the turbines; and > Implementation of good combustion, operating and maintenance practices. For the proposed CTs with a waste heat recovery unit, DCP proposes a thermal efficiency limit of 40% for both turbines. Compliance with this emission limit will be demonstrated by monitoring fuel consumption and performing calculations consistent with Section 5 (Attachment C) of the application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling short tons of CO2e/yr emission rate does not exceed this limit. Through this proposed BACT limit, DCP limits the maximum fuel consumption and CO2e emissions, effectively requiring efficient operation at the design heat rate, when operating at 100% load (as inefficient turbine operation would require additional fuel consumption which is undesirable from an operator's perspective). Furthermore, the proposed unit contains modern process control technologies that continually seek to optimize efficiency from the turbine. 12.10. HOT OIL HEATER GHG emissions from the proposed process heater include CO2, CH4 and N2O which result from the combustion of natural gas. The following section presents BACT evaluations for GHG emissions from the proposed process heater. 12.10.1. Step 1 - Identify All Available Control Technologies The available GHG emission control strategies for the process heater that were analyzed as part of this BACT analysis include: > Carbon Capture and Sequestration; > Fuel Selection; > Good Combustion, Operating, and Maintenance Practices; > Heat Integration; and > Efficient Heater Design. 12.10.1.1. Carbon Capture and Sequestration As previously discussed, the contribution of CO2e emissions from the heater is a fraction of the scale for sources where CCS might ultimately be feasible. Although we believe that it is obvious that CCS is not BACT in this case, as directly supported in EPA's GHG BACT Guidance, a detailed rationale is provided to support this conclusion. For the process heater, CCS would involve post combustion capture of the CO2 from the heater and sequestration of the CO2 in some fashion. In general, carbon capture could be accomplished with low pressure scrubbing of CO2 from the exhaust stream with solvents (e.g., amines and ammonia), solid sorbents, or membranes. However, only solvents have been used to -date on a commercial (yet slip stream) scale and solid sorbents and membranes are only in the research and development phase. A number of post -combustion carbon capture projects have taken place on slip streams at coal-fired power plants. Although these projects have demonstrated the technical feasibility of small-scale CO2 capture on a slipstream of a power plant's emissions using various solvent based DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-22 scrubbing processes, until these post -combustion technologies are installed fully on a power plant, they are not considered "available" in terms of BACT. Larger scale CCS demonstration projects have been proposed through the DOE Clean Coal Power Initiative (CCPI); however, none of these facilities are operating, and, in fact, they have not yet been fully designed or constructed.61 Additionally, these demonstration projects are for post -combustion capture on a pulverized coal (PC) plant using a slip stream versus the full exhaust stream. Also, the exhaust from a PC plant would have a significantly higher concentration of CO2 in the slipstream as compared to a more dilute stream from the combustion of natural gas.62 In addition, the compression of the C02 would require additional power demand, resulting in additional fuel consumption (and C02 emissions) 63 12.10.1.2. Fuel Selection Natural gas has the lowest carbon intensity of any available fuel for the process heater. The proposed process heater will be fired with only natural gas fuel. 12.10.1.3. Good Combustion, Operating, and Maintenance Practices Good combustion and operating practices are a potential control option by improving the fuel efficiency of the process heater. Good combustion practices also include proper maintenance and tune-up of the process heater at least annually per the manufacturer's specifications. 12.10.1.4. Heat Integration The plant is equipped with multiple process -to -process cross heat exchangers for maximum heat integration and high efficiency mass transfer equipment to recover heat and reduce the overall energy use at the plant. The process -to -process cross heat exchangers minimizes the size of the process heater to meet the process demands of the plant. 12.10.1.5. Efficient Heater Design Efficient heater design and proper air -to -fuel ratio improve mixing of fuel and create more efficient heat transfer. Since DCP is proposing to install a new heater, this heater will be designed to optimize combustion efficiency. Preheating the fuel gas and air reduces the heating load on the heater and leads to increased thermal efficiency. Air from the exhaust is routed in such a way to heat the fuel gas and intake air. However, this technology is feasible for large heaters (>100 MMBtu/hr), and also preheating has the potential of increasing NO2 emissions. The hot oil heater will be equipped with next generation ultra-low-NOx burners (NGULNB), and will have a burner management system. Other design options that can be utilized include intelligent flame ignition, flame intensity controls, and flue gas recirculation. DCP will maintain a record of the manufacturer's certificate and maintain the heater as suggested by the manufacturer. 12.10.2. Step 2 — Eliminate Technically Infeasible Options As discussed below, CCS is deemed technically infeasible for control of GHG emissions from the process heater. All other control options are technically feasible. 61 Report of the Interagency Task Force on Carbon Capture Ft Storage, August 2010, p. 32. 62 Report of the Interagency Task Force on Carbon Capture & Storage, August 2010, p. A-7. 63 Report of the Interagency Task Force on Carbon Capture Et Storage, August 2010, http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf, p. 29 DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-23 12.10.2.1. Carbon Capture and Sequestration The feasibility of CCS is highly dependent on a continuous CO2 -laden exhaust stream, and CCS has not been tested or demonstrated for such small combustion sources. Given the limited deployment of only slipstream/demonstration applications of CCS and the quantity and quality of the CO2 emissions stream, CCS is not commercially available as BACT for the process heater and is therefore infeasible. This is supported by EPA's assertion that CCS is considered "available" for projects that emit CO2 in "large" amounts 64 This project and these emission units, by comparison, emit CO2 in small quantities. Therefore, CCS is not considered a technically, economically, or commercially viable control option for the proposed process heater. CCS is not considered as a control option for further analysis. 12.10.3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness With elimination of CCS as a control option, the following remain as technically feasible control options for minimizing GHG emissions from the process heater: > low carbon fuel selection; > implementation of good combustion, operating, and maintenance practices; > heat recovery; and > efficient heater design. Since DCP proposes to implement all of these control options, ranking these control options is not necessary. 12.10.4. Step 4 - Evaluate Most Effective of Control Options No adverse energy, environmental, or economic impacts are associated with the above -mentioned technically feasible control options. 12.10.5. Step 5 - Select BACT for the Process Heater DCP proposes the following design elements and work practices as BACT for the process heater: > use of natural gas as fuel; > implementation of good combustion, operating, and maintenance practices; > heat recovery; and > efficient heater design. DCP proposes to limit the fuel in the heater to 315 MMscf/yr to minimize the CO2e emissions from the heater. These proposed emission limits are based on a 12 -month rolling average basis and include CO2, CH4, and N20 emissions, with CO2 emissions being more than 99% of the total emissions. 64 PSD and Title V permitting Guidance for Greenhouse Gases. March 2011, page 32. "For the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add-on pollution control technology86 that is "available"87 for facilities emitting CO2 in large amounts, including fossil fuel -fired power plants, and for industrial facilities with high -purity CO2 streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing). The proposed project is not any of the cases EPA suggests above. DCP Midstream LP j Lucerne 2 Expansion Trinity Consultants 12-24 Compliance with this emission limit will be demonstrated by monitoring fuel consumption and performing calculations consistent with the calculations included in Section 5 (Attachment C) of this application. These calculations will be performed on a monthly basis to ensure that the 12 -month rolling average short tons of CO2e per year emission rates do not exceed these limits. 12.11. EMERGENCY FLARE The emergency flare at the Lucerne Plant will be used to destroy the off -gas produced during emergency situations and during planned maintenance emissions from compressor blowdowns. GHG emissions will be generated by the combustion of natural gas as well as combustion of the vent gas to the flare. CO2 emissions are produced from the combustion of carbon -containing compounds (e.g., VOCs, CH4) present in the vent streams routed to the flare during compressor blowdowns and the pilot fuel. CO2 emissions from the flare are based on the estimated flared carbon -containing gases derived from heat and material balance data. In addition, minor CH4 emissions from the flare are produced due to incomplete combustion of CH4. The flare is an example of a control device in which the control of certain pollutants causes the formation of collateral GHG emissions. Specifically, the control of CH4 in the process gas by the flare results in the creation of additional CO2 emissions via the combustion reaction mechanism. However, given the relative GWPs of CO2 and CH4 and the destruction of VOCs, it is appropriate to apply combustion controls to CH4 emissions even though it will form additional CO2 emissions.65 The following sections present a BACT evaluation for GHG emissions from combustion of pilot gas and vent gas released to the flare during planned startup and shutdown events. 12.11.1. Step 1 — Identify All Available Control Technologies The available GHG emission control strategies for the flare that were analyzed as part of this BACT analysis include: 9 Carbon Capture and Sequestration; 9 Fuel Selection; > Flare Gas Recovery; 9 Good Combustion, Operating, Maintenance Practices; 9 Good Flare Design; and 9 Limited vent gas releases to flare 12.11. 1.1. Carbon Capture and Sequestration A detailed discussion of CCS technology is provided in Section 12.6.1.1. 12.11.1.2. Fuel Selection The pilot gas fuel for the proposed flare will be limited to natural gas fuel. Natural gas has the lowest carbon intensity of any available fuel. � J 65 For example, combusting 1 lb of CH4 (21 lb CO2e) at the flare will result in 0.02 lb CH4 and 2.7 lb CO2 (0.02 lb 0-14 x 21 CO2e/CH4 + 2.7 lb CO2 x 1 CO2e/CO2 = 2.9 lb CO2e), and therefore, on a CO2e emissions basis, combustion control of alit is preferable to venting the CH4 uncontrolled. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-25 12.11.1.3. Flare Gas Recovery Flaring can be reduced by installation of commercially available recovery systems, including recovery compressors and collection and storage tanks. The recovered gas is then utilized by introducing it into the fuel system as applicable. 12.11.1.4. Good Combustion, Operating, and Maintenance Practices Good combustion and operating practices are a potential control option for improving the combustion efficiency of the flare. Good combustion practices include proper operation, maintenance, and tune-up of the flare at least annually per the manufacturer's specifications. 12.11.1.5. Good Flare Design Good flare design can be employed to destroy large fractions of the flare gas. Much work has been done by flare and flare tip manufacturers to assure high reliability and destruction efficiencies. The flare tip is designed to allow for the proper flame temperature, residence time, mixing, and available oxygen to ensure as complete destruction as possible. Additional design includes pilot flame monitoring, flow measurement, and monitoring/control of waste gas heating value. 12.11.1.6. Limited Vent Gas Releases to Flare Minimizing the number and duration of compressor blowdowns and therefore limiting vent gases routed to the flare will help reduce emissions from maintenance of compressor blowdown activities. 12.11.2. Step 2 — Eliminate Technically Infeasible Options The technical infeasibility of CCS and flare gas recovery is discussed below. All other control technologies listed in Step 1 are considered technically feasible. 12.11.2.1. Carbon Capture and Sequestration With no ability to collect exhaust gas from a flare other than using an enclosure, post combustion capture is not an available control option. Pre -combustion capture has not been demonstrated for removal of CO2 from intermittent process gas streams routed to a flare. Flaring will be limited to emergency situations and during planned startup and shutdown events of limited duration and vent rates resulting in a very intermittent CO2 stream; thus, CCS is not considered a technically feasible option. Therefore, it has been eliminated from further consideration in the remaining steps of the analysis. 12.11.2.2. Flare Gas Recovery Installing a flare gas recovery system to recover flare gas to the fuel gas system is considered a feasible control technology for industrial process flares. Flaring at the Lucerne 2 Expansion will be limited to emergency situations and during planned startup and shutdown events of limited duration and vent rates. Due to infrequent maintenance of compressor blowdown activities and the amount of gas sent to the flare, it is technically infeasible to re-route the flare gas to a process fuel system and hence, the gas will be combusted by the flare for control. Therefore, the amount of flare gas produced by this project will not sustain a flare gas recovery system. For this project, flare gas recovery is infeasible. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-26 \ 2 12.11.3. Step 3 — Rank Remaining Control Technologies by Control Effectiveness With elimination of CCS and flare gas recovery as technically infeasible control options, the following control options remain as technically feasible control options for minimizing GHG emissions from the flare: > Fuel selection 9 Good combustion, operating, and maintenance practices 9 Good flare design 9 Limited vent gas releases to flare Since DCP proposes to implement all of these control options, ranking these control options is not necessary. 12.11.4. Step 4 — Evaluate Most Effective Control Options No significant adverse energy or environmental impacts (that would influence the GHG BACT selection process) associated with the above -mentioned technically feasible control options are expected. 12.11.5. Step 5 — Select BACT for the Flare DCP proposes the following design elements and work practices as BACT for the flare: 9 use of natural gas as pilot fuel; 9 implementation of good combustion, operating, and maintenance practices; 9 good flare design; and 9 limiting vent gas releases to the flare. The flare will meet the requirements of 40 CFR §60.18, and will be properly instrumented and controlled. Emission sources, such as electric compressors, whose maintenance blowdown emissions are routed to the flare, will be operated in manner to minimize the frequency and duration of such compressor blowdown activities and therefore, the amount of maintenance emissions from compressor blowdown vent gas released to the flare. DCP is not proposing a numerical BACT limit on GHG emissions from the flare since it is used to destroy the off - gas produced during emergency situations and during planned compressor blowdown activities. BACT for the emergency flare is the aforementioned work practice standards. 12.12. FUGITIVE COMPONENTS The following sections present a BACT evaluation of fugitive CO2 and CH4 emissions. It is anticipated that the fugitive emission controls presented in this analysis will provide similar levels of emission reduction for both CO2 and CH4. Fugitive components included in the proposed Lucerne 2 Expansion include traditional components such as valves and flanges. 12.12.1. Step 1 - Identify All Available Control Technologies In determining whether a technology is available for controlling GHG emissions from fugitive components, permits and permit applications and EPA's RBLC were consulted. Based on these resources, the following available control technologies were identified and are discussed below: > Installing leakless technology components to eliminate fugitive emission sources; DCP Midstream LP J Lucerne 2 Expansion Trinity Consultants 12-27 > Implementing various LDAR programs in accordance with applicable state and federal air regulations; > Implementing an alternative monitoring program using a remote sensing technology such as infrared camera monitoring; • Implementing an audio/visual/olfactory (AVO) monitoring program for odorous compounds; and • Designing and constructing facilities with high quality components and materials of construction compatible with the process. 12.12. 1. 1. Leakless Technology Components Leakless technology valves are available and currently in use, primarily where highly toxic or otherwise hazardous materials are used. These technologies are generally considered cost prohibitive except for specialized service. Some leakless technologies, such as bellows valves, if they fail, cannot be repaired without a unit shutdown which often generates additional emissions. 12.12.1.2. LDAR Programs LDAR programs have traditionally been developed for the control of VOC emissions. BACT determinations related to control of VOC emissions rely on technical feasibility, economic reasonableness, reduction of potential environmental impacts, and regulatory requirements for these instrumented programs. Monitoring direct emissions of CO2 is not feasible with the normally used instrumentation for fugitive emissions monitoring. However, instrumented monitoring is technically feasible for components in CH4 service. 12.12.1.3. Alternative Monitoring Program Alternate monitoring programs such as remote sensing technologies have been proven effective in leak detection and repair. The use of sensitive infrared camera technology has become widely accepted as a cost effective means for identifying leaks of hydrocarbons. 12.12.1.4. AVO Monitoring Program Leaking fugitive components can be identified through AVO methods. The fuel gases and process fluids in the Lucerne 2 Expansion piping components are expected to have discernable odor, making them detectable by olfactory means. A large leak can be detected by sound (audio) and sight. The visual detection can be a direct viewing of leaking gases, or a secondary indicator such as condensation around a leaking source due to cooling of the expanding gas as it leaves the leak interface. AVO programs are common and in place in industry. 12.12.1.5. High Quality Components A key element in the control of fugitive emissions is the use of high quality equipment that is designed for the specific service in which it is employed. For example, a valve that has been manufactured under high quality conditions can be expected to have lower runout on the valve stem, and the valve stem is typically polished to a smoother surface. Both of these factors greatly reduce the likelihood of leaking. 12.12.2. Step 2 - Eliminate Technically Infeasible Options Recognizing that leakless technologies have not been universally adopted as LAER or BACT, even for toxic or extremely hazardous services, it is reasonable to state that these technologies are impractical for control of GHG emissions whose impacts have not been quantified. Any further consideration of available leakless technologies for GHG controls is unwarranted. All other control options are considered technically feasible. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-28 12.12.3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness 12.12.3.1. WAR Programs Instrumented monitoring is effective for identifying leaking CH4, but may be wholly ineffective for finding leaks of CO2. With CH4 having a global warming potential greater than CO2, instrumented monitoring of the fuel and feed systems for CH4 would bean effective method for control of GHG emissions. Quarterly instrumented monitoring with a leak definition of 500 ppmv (2,000 ppmv for pumps and compressors), accompanied by intense directed maintenance, is generally assigned a control effectiveness of 95% (88% for pumps and compressors). 66 12.12.3.2. Alternative Monitoring Program Remote sensing using infrared imaging has proven effective for identification of leaks including CO2. The process has been the subject of EPA rulemaking as an alternative monitoring method to the EPA's Method 21. Effectiveness is likely comparable to EPA Method 21 when cost is included in the consideration. 12.12.3.3. AVO Monitoring Program Audio/Visual/Olfactory means of identifying leaks owes its effectiveness to the frequency of observation opportunities. Those opportunities arise as operating technicians make rounds, inspecting equipment during those routine tours of the operating areas. This method cannot generally identify leaks at a low leak rate as instrumented reading can identify; however, low leak rates have lower potential impacts than do larger leaks. This method, due to frequency of observation is effective for identification of larger leaks. 12.12.3.4. High Quality Components Use of high quality components is effective in preventing emissions of GHGs, relative to use of lower quality components. 12.12.4. Step 4 - Evaluate Most Effective Control Options No adverse energy, environmental, or economic impacts are associated with the above -mentioned technically feasible control options. 12.12.5. Step 5 - Select BACT for Fugitive Emissions Monitoring will be conducted at the facility following the protocol established in 40 CFR Subpart KKK. In addition, facility personnel will be trained to utilize AVO to monitor for leaks anytime they are in the plant. Any leaks discovered via LDAR or AVO will be repaired as quickly as practical. Since fugitive GI-IG emissions are estimations only, DCP proposes no numerical BACT limit. The proposed project will also utilize high -quality components and materials of construction, including gasketing, that are compatible with the service in which they are employed. Since DCP is implementing the most effective control options available, additional analysis is not necessary. s�TCEQ published BACT guidelines for fugitive emissions in the document Air Permit Technical Guidance for Chemical Sources: Equipment Leak Fugitives, October 2000. DCP Midstream LP Lucerne 2 Expansion Trinity Consultants 12-29 12.13. CONDENSATE STORAGE TANKS The storage tanks at the Lucerne 2 Expansion will be used to store condensate generated from the processing of natural gas. The condensate is processed through a stabilization process before entering the storage tanks. Stabilized condensate has no flashing losses and will have negligible emissions due to breathing and working losses. Furthermore, the condensate generated at the Lucerne Plant does not contain CO2, CH4, or any other GHG. However, DCP has chosen to equip the condensate storage tanks with fixed roofs coupled with an enclosed combustion device for the control of VOCs and HAPs. The enclosed combustor device generates negligible GHGs as a by-product from the combustion of VOCs and HAPs present in the condensate and the combustion of natural gas in the pilot. Since the emissions of GHG from the condensate storage tanks are negligible, further analysis of control is neither technically or economically feasible. 12.14, TRUCK LOADING The condensate generated at the Lucerne 2 Expansion will be loaded into trucks for off -site disposal. The condensate is processed through a stabilization process before entering the storage tanks. Stabilized condensate has no flashing losses and will have negligible emissions due to breathing and working losses. Furthermore, the condensate generated at the Lucerne Plant does not contain CO2, CH4, or any other GHG. However, DCP has chosen to use submerged loading coupled with an enclosed combustion device for the control of VOCs and HAPs. The enclosed combustor device generates negligible GHGs as a by-product from the combustion of VOCs and HAPs present in the condensate and the combustion of natural gas in the pilot. Since the emissions of GHG from the loading of condensate are negligible, further analysis of control is neither technically or economically feasible. DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants 12-30 APPENDIX A. MANUFACTURER SPECIFICATIONS DCP Midstream LP I Lucerne 2 Expansion Trinity Consultants Solar Turbines A Caterpillar Company PREDICTED EMISSION PERFORMANCE Customer DCP Midstream Prairie Gas Pia Job ID DN12-001 Inquiry Number Run By Leslie Witherspoon Date Run 8 -May -13 NOx EMISSIONS Engine Model TAURUS 70-10802S ESC CS/MD STANDARD DAY Fuel Type Water Injection CHOICE GAS NO Engine Emissions Data REV. 0.1 CO EMISSIONS UHC EMISSIONS 9055 HP 100.0% Load Elev. 4800 ft Rel. Humidity 30.0% Temperature 60.0 Deg. F PPMvd at 15% O2 ton/yr Ibm/MMBtu (Fuel LHV) Ibm/(MW-hr) (gas turbine shaft pwr) Ibm/hr 13.00 15.03 0.052 0.51 3.43 25.00 17.59 0.061 0.59 4.02 25.00 10.08 0.035 0.34 2.30 Notes 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-SoLoNOx equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES 9-98. Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as non -warranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut -down, malfunction, or transient event. Solar Turbines A Caterpillar Company Customer DCP Midstream Prairie Gas Pla Job ID DN12-001 Run By Leslie Witherspoon Date Run 8 -May -13 Engine Performance Code REV. 4.6.1.8.3 Engine Performance Data REV. 2.0 Elevation Inlet Loss Exhaust Loss feet in H2O in H2O Engine Inlet Temperature deg F Relative Humidity Driven Equipment Speed RPM Specified Load HP Net Output Power HP Heat Rate Btu/HP-hr Therm Eff Fuel Flow mmBtu/hr Nom Net Output Power HP Nom Heat Rate Btu/HP-hr Nom Therm Eff Nom Fuel Flow mmBtu/hr Engine Exhaust Flow Ibm/hr PT Exit Temperature deg F Exhaust Temperature deg F Fuel Gas Composition (Volume Percent) Fuel Gas Properties 4800 4.0 4.0 60.0 30.0 11513 FULL 8783 7528 33.802 66.12 9055 7302 34.847 66.12 178492 941 941 Methane (CH4) 97.49 Ethane (C2H6) 1.22 Propane (C3H8) 0.08 Nitrogen (N2) 1.21 Sulfur Dioxide (SO2) 0.0001 PREDICTED ENGINE PERFORMANCE Model TAURUS 70-10802S ESC Package Type CS/MD Match STANDARD DAY Fuel System GAS Fuel Type CHOICE GAS LHV (Btu/Scf) 908.1 Specific Gravity 0.5655 Wobbe Index at 60F 1207.6 This performance was calculated with a basic inlet and exhaust system. Special equipment such as low noise silencers, special filters, heat recovery systems or cooling devices will affect engine performance. Performance shown is "Expected" performance at the pressure drops stated, not guaranteed. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV. 4.6.1.8.3 CUSTOMER: DCP Midstream Prairie Gas Pla JOB ID: DN12-001 DATE RUN: 8 -May -13 RUN BY: Leslie Witherspoon --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 1 HP= 9883, %Full Load=100.0, Elev= 4800ft, %RH= 30.0, Temperature= O.OF GENERAL INPUT SPECIFICATIONS ENGINE FUEL: CHOICE GAS 25.09 in Hg AMBIENT PRESSURE 30.0 percent RELATIVE HUMIDITY 0.0003 --- SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = 993.0 SG = 0.6221 W.I. @60F (Btu/Scf) = 1259.0 Gas Fuel Suitability (GFS)# 20967 Methane (CH4) Ethane (C2H6) Propane (C3H8) I -Butane (C4H10) Nitrogen (N2) Sulfur Dioxide (502) = 86.1699 = 12.3500 0.4000 = 0.0100 1.0700 0.0001 STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: 29.92 in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: 29.92 in Hg Solar's turbines are capable of operating over a wide range of fuel blends, however Engineering review is required when methane drops below 80% or other constituents exceed standard boundaries. Performance as modeled here should be accurate, but note that alterations to the combustion and package systems may be necessary. GENERAL OUTPUT DATA 3483. 1bm/hr 1222.40 Scfm 20914. Btu/lbm 993. Btu/Scf 43954. Scfm 135976. Acfm 198732. lbm/hr 4627.0 deg R 4612.8 deg R 28.60 56.23 --- EXHAUST GAS ANALYSIS FUEL FLOW FUEL FLOW LOWER HEATING VALUE LOWER HEATING VALUE EXHAUST FLOW @ 14.7 PSIA & 60F ACTUAL EXHAUST FLOW CFm EXHAUST GAS FLOW ADIA STOICH FLAME TEMP, CHOICE GAS ADIA STOICH FLAME TEMP, SDNG MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 02 0.91 3.14 5.90 75.76 14.28 VOLUME PERCENT WET 0.96 3.34 0.00 80.52 15.18 VOLUME PERCENT DRY 2514. 9597. 7390. 147468. 31758. lbm/hr 0.72 2.76 2.12 42.34 9.12 g/(g FUEL) HOT OIL HEATER HT -02 EMISSION FACTOR REFERENCE OPTIMIZED PROCESS FURNACES, INC. 3995 S. Santa Fe P. O. BOX 7061 CHANUTE, KS 66720-0706 PHONE (620) 431-1260 FAX (620) 431-6631 October 1 2013 Saulsbury Industries Corporate Office: 2951 E. Interstate 20 Odessa, TX 79766 Attention: Reference: Gentlemen: Mr. Steve Henderson Your SL12-0008 DCP Lucerne Project Our Proposal No. 2013-009, Revision 1 Per our conversation, the following guarantee has been made by Callidus, our burner supplier on this project. Particulates/PM 2.5 (Rev 1) 0.0050 lb/MMBtu (Basis: (C4's and lighter) measured only as products of incomplete combustion, HHV.) If you have any additional questions, please let me know. Yours truly, OPTIMIZED PROCESS FURNACES, INC. Rob Phillips President Telephone: 620-431-1260 Fax: 620-431-6631 E-mail: phillipsr@optimizedpf.com RP/dke dA N U L Proposal For: Black & Veatch Corporation AES-110079 Anguil Environmental Systems, Into Regenerative Thermal Oxidizer' Date: Proposal #: Project: August 24, 2011 AES-1 10079 DCP Midstream LaSalle Natural Gas Processing Plant Greely, CO Prepared for: Black & Veatch Corporation 1 1401 Lamar Ave. Overland Park, KS 66211 Email: DCPLaSalle@BV.com Mr. J. Quinten Lovejoy Sr. Procurement Representative Phone: (913) 458-4741 Email: LoveioyJQ�a@,BV.com Mr. Kenneth Knoll Project Procurement Manager Email: KnolIKJLa'�.BV.com Submitted by: Scott Bayon Regional Sales Manager Scott.Bayon .Anquil.com Kyle Momenee Application Engineer Kyle.Momenee(a�Anauil.com Local Representative: Jim Taylor Tech Air Systems Phone: (303) 366-1919 Fax: (303) 366-2095 Email: techairRiuno.com ANGUIL ENVIRONMENTAL SYSTEMS, INC. 4 www.anguil.cam 1 8855 N. 55th Street • Milwaukee, Wisconsin 53223 s Phone : 414-365-6400 • Fax : 414-365-6410 1 fl J ANGUIL Proposal For: Black & V eatch Corporation "Our goal is to provide solutions today which help our customers remain profitable tomorrow" — Gene Anguil / Founder and CEO In Air ASS -110079 Background: • Founded in 1978 Second generation family owned and operated • Headquartered in Milwaukee, Wl, USA with offices in Asia and Europe • Over 1,650 oxidizers and countless heat recovery systems installed on six continents in a wide variety of industries Company Size and Make-up: - Annual sales in excess of $25 million • In-house engineering staff consists of chemical, mechanical and electrical engineers • Highly motivated employees who enjoy profit sharing and a rewarding work environment What Makes Anguil Unique? Regulatory compliance is guaranteed Broad range of technology solutions that ensure an unbiased equipment selection • Quality assurance program with complete factory acceptance testing prior to shipment • An established safety program with continuous training for Arguil technicians • Equipment is designed in Solidworks, ensuring accuracy and rapid completion Products: Air pollution control systems... Regenerative Thermal Oxidizers (RTO) • Catalytic, Recuperative and Direct -Fired Thermal Oxidizers • Concentrator systems Permanent Total Enclosures ...for VOC, HAP and odor abatement Heat and energy recovery systems... • Air-to-air heat exchangers Air -to -liquid heat exchangers • Heat -to -power • Energy Evaluations ...for improved efficiency and reduced operating costs Aftermarket: Service and Maintenance... • 24/7 Emergency service response • Operating cost reviews • System upgrades and retrofits • Spare parts and component packages • Preventive Maintenance Evaluations (PME) ... on any make or model, regardless of original manufacturer Partial List of Satisfied Customers: Boeing, Dow Chemical, Northrop Grumman, ExxonMobil, Johnson and Johnson, Peterbilt, Qualcomm, Rexam Beverage, Silgan Containers, Wyeth •�J ANGUIL ENVIRONMENTAL SYSTEMS, INC. wvaw.anguil.com 8855 N. 55c' Street • Milwaukee, Wisconsin 53223 O Phone : 414-365-6400 • Fax : 414-365-6410 2. ANGUIIL Proposal For: Black & V eatch Corporation Tats& of Contents AES-110079 Executive Summary 4 Design Specifications 7 Standard Equipment Specifications 8 Exceptions 17 Items Not Included 18 Pricing. and Deliver,' 19 Field Service Rates 2011 20 Standard Terms and Conditions 21 'Note: This proposal contains confidential and proprietary information of Anguil Environmental Systems, Inc. and is not to be disclosed to any third parties without the express prior written consent of Anguil. ANGUIL ENVIRONMENTAL SYSTEMS, INC. o www.artgbil.com 3 8855 N. 55'h Street • Milwaukee, Wisconsin 53223 ® Phone : 414-365-6400 • Fax : 414-365-6410 ANGUIL Proposal For: Black & Veatch Corporation Executive Summary 1. Equipment Description AES-1 10079 Black & Veatch has requested a proposal for an oxidizer for the destruction of VOCs from an amine vent at DCPs LaSalle facility in Greely, CO. The VOCs are in an inert CO2 stream and will be combined with preheated fresh air, to prevent water and sulfuric/sulfurous acid condensation, prior to being delivered to a new 10,000 SCFM Regenerative Thermal Oxidizer (RTO). Key components of the oxidizer have been upgraded to either 316L Stainless Steel or vinyl ester coated carbon steel to protect against sulfur corrosion associated with hydrogen sulfide in the process stream, as well as carbonic acid corrosion. The RTO is designed with high heat recovery to reduce operating cost. Anguil has taken exception to the Black & Veatch specification and proposes a unit that is in accordance with Anguil's experience with DCP Midstream expectations. The proposed unit will meet all site -specific requirements, as well as BMS Level 2 requirements from DCP. 2. Facility to be Controlled DCP Midstream LaSalle Natural Gas Process Plant in Greely, CO 3. Processes Controlled Amine Vent Acid Gas 4. RTO Energy Recovery 95% Thermal Energy Recovery 5. Proposed Equipment Model 100 (10,000 SCFM) Regenerative Thermal Oxidizer (RTO) for sour gas application o. Anguil Benefits * Seamless integration with the current process * Fully automated PLC based controls * True 95% nominal heat transfer efficiency, adjusted for CO2/water content and altitude * 316L stainless steel poppet valve assemblies, media support grid and exhaust stack * Carbon steel reactor lined with vinyl ester coating to protect against corrosion * Modem for remote diagnostics * Field Tested and proven technology * Full equipment warranty * Factory test prior to shipment * 24 hour service support 7. Results * Anguil guarantees the conversion efficiency of 99% or an outlet concentration of 20 ppmv as C1 (methane), whichever is less stringent per EPA Method 25A. ANGUIL ENVIRONMENTAL SYSTEMS, INC. u www.anquil.com 4 8655 N. 55th Street • Milwaukee, Wisconsin 53223 o Phone : 414365-6400 • Fax : 414-365-6410 (. ANGUIL Proposal For: Black & V eatch Corporation Customer Process Specifications a Process Information*: Property Acid Gas Temperature (°F) 120 Pressure (psig) 8 Flowrate (ACFM) 3230 Flowrete (SCFM) 4,390 Vapor Fraction 1 Compound '`Acid Gas ,<.. (Iblhr) Water Vapor 377.26 Hydrogen Sulfide" 3.09 Carbon Dioxide 27;528.43 Nitrogen 0.00 Methane 4.16 Ethane 4.50 Propane 3.55 i-Butsne 8.58 n -Butane 3.42 i-Pentane 0.42 n -Pentane 0.42 n -Hexane 0.28 n-Heplane 0.13 n -Octane 0.07 Benzene 10.05 Toluene 8.29 Ethyl Benzene 0.62 xylene 2.34 Total Process Gas 4,090 SCFM Process Heat Release 3,84 Btulscf (18,790 Blu!b) Fresh Air for Oxidation of VOCs 157 SCFM Fresh Alr for 3% Stack o, 708 SCFM Recirculated Oxidation Chamber Flow (3% O2) for inlet Preheat 857 SCFM Total Preheated Fresh Air Flow 1,721 SCFM Inlet Flow to Oxidizer 5,811 SCFM Maximum Allowable Process Heat Release 33.93 BtulseT (18,790 Btuilb in 4,090 SCFM process gas) Total Preheated Fresh Air Flow 5,910 SCFM Flow to Oxidizer 10,000 SCFM RIO System Design Modal 100 RTO: 10,000 SCFM AES-110079 * Assumed no halogenated or chlorinated compounds are present. **Presence of Hydrogen Sulfide above 1 ppmv will require the use of an RTO designed for Sour Gas. The proposed RTO will be designed for Sour Gas ANGUIL ENVIRONMENTAL SYSTEMS, INC. a trki w,angudl.com 5 8855 N. 55° Street • Milwaukee, Wisconsin 53223 o Phone : 414-365-6400 • Fax : 414-365-6410 ANGUL Proposal For: Black & Veatch Corporation • Elevation: Ambient Temperature Range: • Facility Operating Schedule: • Facility Power: • Fuel Source: • Process Particulate: • Performance Requirements: O RTO location on Site: 4,800 FASL -20°F to 105°F 24 hr/day, 7 days/wk Assumed 480 V/60 Hz / 3 Ph Natural Gas Assumed to be negligible 99% VOC Destruction Outdoors AES-110079 Note: Equipment has been designed and sized based on these customer parameters. ANGUIL ENVIRONMENTAL SYSTEMS, INC. o w`tF£W.a€its._4i .cQ,m 6 8855 N. 55th Street • Milwaukee, Wisconsin 53223 0 Phone : 414-365-6400 • Fax : 414-365-6410 r kat AN UIL Proposal For: Black & V catch Corporation Design Specifications Size and Weight • Maximum Airflow (Includes Dilution Air): 10,000 SCFM AES-110079 o Approximate Footprint: 35' x 17' o Approximate Weight: 65,000 lb o Stack Height: 40' o Stack Diameter: 34" o Oxidizer Control Panel Location: Skid Mounted NEMA 3R Main Control Panel o Suggest Foundation Size: 41' x 20' Utilities Required • Fuel Requirements: 5 psig o Electrical Power. 480V/60 Hz/ 3 Ph o Required Compressed Air. 80-100 psig (-40°F dewpoint) 5-10 SCFM Operation Information • V0C Destruction Efficiency: 99% or an outlet concentration of 20 ppmv as Cl (methane), whichever is less stringent per EPA Method 25A. o Nominal Heat Transfer Efficiency: 95% System Process Fan Draft Design: Forced • System Process Fan HP: 100 HP Combustion Fan HP: Burner Installed Maximum Capacity: 4.0 MM BTU/hr • Operating Set Point: ::1550-1700°F *Note: All weights, dimensions, horsepower ratings, burner sizing, and specific engineering details within the proposal are approximate and will be confirmed by Anguil Environmental following order placement. ANGIJIL INVIROhlNEI1TAL SYSTEMS, INC. a INww,aig€li€.c. €ri 7 8855 N. 55"' Street • Milwaukee, Wisconsin 53223 o Phone : 414-365-6400 • Fax : 414-365-6410 ANGUIL Proposal For: Black & V eatch Corporation Standard Equipment Specifications AES-110079 The Anguil Regenerative Thermal Oxidizer (RTO) destroys Hazardous Air Pollutants (HAPs), Volatile Organic Compounds (VOCs) and odorous emissions that are discharged from industrial processes. Emission destruction is achieved through the process of high temperature thermal or catalytic oxidation, converting the pollutants to carbon dioxide and water vapor while reusing the thermal energy generated to reduce operating costs. How the RTO Works- VOC and HAP laden process gas enters the oxidizer through an inlet manifold to flow control, poppet valves that direct this gas into energy recovery chambers where it is preheated. The process gas and contaminants are progressively heated in the ceramic media beds as they move toward the combustion chamber. Once oxidized in the combustion chamber, the hot purified air releases thermal energy as it passes through the media bed in the outlet flow direction. The outlet bed is heated and the gas is cooled so that the outlet gas temperature is only slightly higher than the process inlet temperature. Poppet valves alternate the airflow direction into the media beds to maximize energy recovery within the oxidizer. The high energy recovery within these oxidizers reduces the auxiliary fuel requirement and saves operating cost. The Anguil oxidizer achieves high destruction efficiency and self-sustaining operation with no auxiliary fuel usage at concentrations as low as 3-4% LEL (Lower Explosive Limit). ANGUIL ENVIRONMENTAL SYSTEMS, INC. m www.ancull.con- 8 8855 N. 55°' Street • Milwaukee, Wisconsin 53223 a Phone : 414-365-6400 • Fax : 414-365-6410 ANGL1BL POPPET VALVES Proposal For: Black & V eatch Corporation AES-110079 Anguil's poppet valves are uniquely designed to divert high volume process air into and out of the oxidizer, properly balance VOC loading, maintain destruction efficiency and optimize heat recovery. We custom design, manufacture and install these vital components to ensure reliability and trouble free operation. Anguil has several poppet assemblies that have been operating continuously since 1993 and have required nothing but regular maintenance. SPECIFICATIONS • 316L Stainless Steel Shaft, Disk & Seat • Poppet Box Body: 316L Stainless Steel • Cylinder Actuator Supports: Plate Steel • Parker Hannifin Heavy Duty Pneumatic Cylinder: 90 psi, 10 CFM, -40"F • Heavy Duty, High Flow, 4 -way Parker Hannifin Solenoid Valve • Bolted Actuator Mountings with Shaft Guarding • Connecting Duct Work to Fan and Exhaust Stack ® Compressed air Accumulator Tank Included o End of Stroke Switches m Solenoid Valve Exhaust Flow Control • External insulation of the poppet valves for personnel protection and to prevent water condensation has not been included at this time. Anguil recommends that it will be the most cost effective to insulate onsite during installation. FEATURES o Vertical Shaft ® Double Acting, Three-way Air Flow Design: o Reliable Metal to Metal Seal: 1 MM+ cycles O Removable Machined Seats: <0.25% leakage at 18" W.C. O Valve Pressure Drop: Maximum of 2" W.C. O Rectangular Ports for Inlet/Outlet Ducting • Removable Actuator Mounting • Hinged Access Doors with Toggle clips ® Lockout Device with Padlock Provision • Quiet Operation o Over Temperature Protection o Short valve switch distance ADVANTAGES Energy Efficient — Compressed air consumption to switch solenoids from closed to open position is minimal Dependable — Two -disc system minimizes valve switch distance and wear Ease of Maintenance — Multiple hinged access doors make occasional cleaning and bearing maintenance easy ANGUIL ENVIRONMENTAL SYSTEMS, INC. m fkrtvw.arrg.iil.cnrn, 9 8855 N. 55th Street • Milwaukee, Wisconsin 53223 a Phone : 414-365-6400 • Fax : 414-365-6410 ANGUIL Proposal For: Black & V eatch Corporation HEAT TRANSFER MEDIA AES-1 10079 a Two (2) beds of high temperature chemical porcelain structured heat transfer media • Media has been adjusted to account for the -• high CO2 content to provide a true 95% thermal efficiency. The heat capacity of CO2 is higher than that of air (-70% nitrogen) meaning you need more energy to heat up the CO2. More media would be required to r.`° provide more preheat to the incoming CO2. 's -_-_-_ _ ---- a Ceramic media designed to provide optimum heat transfer surface area • Media bed for proper air distribution and optimum RTO performance • Low system pressure drop BURNER(S)/FUEL TRAIN r. n Maxon Kinemax Low NOx burner ® Fuel source -- Natural Gas a Fuel Train fabricated to FM Global specifications o Service platform and ladder • 3" burner view port • Fireye flame safety control with self -checking dynamic UV scanner a Carbon steel fuel train, no brass or cast iron • Pneumatic actuated natural gas firing rate valve included. Upgrade includes a higher class of valve and additional compressed air piping to each actuator. 9 Rosemount Natural Gas Flowmeter COMBUSTION AIR FAN • Twin City Fan, New York Blower or equal ® Pre -piped and pre -wired o TEFC motor • Inlet filter • Independent PLC controlled fuel and combustion air valves and actuators • Pneumatic actuated combustion air valve included. Upgrade includes a higher class of valve and additional compressed air piping to each actuator. ANGUIL ENVIRONMENTAL SYSTEMS, INC. a wvvuv.angssiil orn 10 8855 N. 55u' Street • Milwaukee, Wisconsin 53223 e Phone : 414-365-6400 • Fax : 414-365-6410 ANGUIL Proposal For: Black & V eatch Corporation AES-110079 SYSTEM CONTROLS* The system controls are located in a heated and air conditioned NEMA 3R control panel enclosure. In the event of a system shutdown, the touch screen will indicate the cause of the shutdown via a digital message in English. • NEMA 3R main control panel enclosure to be mounted on the oxidizer skid • Allen Bradley CompactLogix fully automated PLC (Programmable Logic Controller) controls • Allen Bradley PanelView 1000 display • Digital chart recorder. monitors combustion chamber and exhaust stack temperatures • Ethernet modem for remote diagnostics and service support • Digital Transmitters with HART Capability o Add a total of 6 Rosemount transmitters, in parallel with existing pressure switches, to display pressure readings through HMI o Included are the transmitters, additional wiring, additional sensing lines, additional 11O modules and PLC programming *System Control Scheme matches RTOs supplied to DCP Colorado locations (BMS Level 2). Rosemount transmitters am used. BMS Level 1 Control Scheme requires a Safety PLC, Ethernet Card, and Additional I/O. These BMS Level 1 items am not included at this time. VARIABLE FREQUENCY DRIVE (VFD) The variable frequency drive regulates the airflow through the system. It is controlled by a pressure transmitter located up -steam from the system fan. The VFD is mounted with the system controls in the control enclosure. It aids in minimizing operating cost by providing system fan turn -down during periods of low airflow. • Allen Bradley Powerflex VFD o Mounted in an Anguil supplied heated and air conditioned NEMA 3R panel enclosure ENERGY RECOVERY CHAMBERS The RTO's energy recovery chambers are rectangular cross -sections constructed ofryinylester ,coated carbon steel. They are reinforced to withstand the pressure requirement of the process air fan and all other applied loads. A 316L Stainless Steel support structure is also provided to support the oxidizer chambers, media support grid and the ceramic heat recovery media itself. In order to allow for routine inspection of the heat recovery media, cold face and media support grid, two hinged access doors complete with gaskets are included. a Two (2) carbon steel energy recovery chambers o Internally insulated: 6" thick, 8# density ceramic module insulation o. Insulation rated for 2300°F e Insulation modules: shop installed with 310 stainless steel reinforcements and mounting hardware o Internally coated with a vinyl ester coating to protect against sulfuric acid corrosion • Support Structure — 316L Stainless Steel construction • Media support grid —316L Stainless Steel construction • Two hinged access doors with gaskets 12 ANGUIL ENVIRONMENTAL SYSTEMS, INC. • www.anguil.com 8855 N. 556' Street • Milwaukee, Wisconsin 53223 • Phone : 414-365-6400 • Fax : 414-365-6410 .110,1 ANGU . Proposal For: Black & Veatch Corporation FRESH AIR PREHEAT SYSTEM AES-1 10079 Fresh air is used during oxidizer start-up/shut-down, purging during idle time and to provide oxygen for oxidation. Anguil recommends that, during normal operation, the fresh air be preheated above the sulfuric acid dewpoint prior to mixing with the process gas upstream of the system fan to prevent water condensation, and to ensure all parts in contact with the process stream are above the acid dewpoint. Anguil's design incorporates a fresh air preheat system that utilizes heat from the combustion chamber to heat fresh air. The amount of heat taken from the combustion chamber is controlled by the recycle damper. The damper position is controlled by a signal from the PLC with a pneumatic actuator and positioner. The proposed RTO inlet preheat temperature is 310°F. ✓ Recycle damper internally lined with hard refractory ▪ Sized based on a maximum combustion chamber temperature of 1800°F o 330 Stainless Steel shaft and blade o Step seat in the refractory • Static Mixer and Recirculation Duct to fan inlet will be constructed out of 316L Stainless Steel o The static mixer and recirculation duct will be constructed out of 316L Stainless Steel RTO SYSTEM FAN The system fan is sized for -1 in. W.C. at the RTO inlet. This is equivalent to 100' of ductwork, with two elbows and 2500 fpm maximum velocity from T -dampers to oxidizer inlet. Any additional ductwork, elbows or duct velocity may affect fan selection. o Twin City Fan, New York Blower or equal a VFD rated motor O Flexible connection on inlet/outlet of fan ANGUIL ENVIRONMENTAL SYSTEMS, INC. o wwvd,avaguil.com 11 8855 N. 55`x' Street • Milwaukee, Wisconsin 53223 e Phone : 414-365-6400 • Fax : 414-365-6410 CD ANGUIL Proposal For: Black & Veatch Corporation COMBUSTIOM CHAMBER The combustion chamber is a rectangular cross- section constructed of vinyl ester coated carbon steel and reinforced to withstand the pressure requirements of the process air fan and all other applied loads. The inverted "U" shape design provides the retention time to obtain the specified VOC destruction efficiency, In order to allow for routine inspection of the heat recovery media, insulation and b burner, two hinged access doors complete with gaskets are included. • Inverted "U" shaped oxidation chamber o Internally insulated: 8" thick, 8# density ceramic module insulation o Insulation rated for 2300°F o Insulation modules: shop installed with 310 stainless steel reinforcements and mounting hardware o Internally coated with a vinyl ester coating to protect against sulfuric acid corrosion • Hinged access doors with gaskets AES-110079 EXHAUST STACK • Constructed of 316L Stainless Steel • Free-standing exhaust stack with ladder and platform O Two (2) EPA tests ports: 90' to each other • An oxygen analyzer will be supplied in the RTO exhaust stack to control the dilution air and ensure 3% oxygen content in the RTO exhaust gas BAKE OUT The oxidizer can be operated off-line from the process in a bake -out mode to allow for the removal of organic build-up on the cold face of the heat exchange media. At a reduced airflow, the outlet temperature is allowed to reach an elevated temperature before the flow direction is switched. This hot air vaporizes organic particulate that may have collected on the cold face of the heat exchange media. The flow direction is then switched and the opposite cold face is cleaned. The area below the media support grid will be insulated to prevent the temperature of the outer skin from increasing during bake -out. ANGUIL ENVIRONMENTAL SYSTEMS, INC. a www.anguil.com 13 8855 N. 55th Street Milwaukee, Wisconsin 53223 o Phone : 414-365-6400 • Fax : 414-365-6410 `-J ANGUIL HOT SIDE BYPASS 0 O Proposal For: Black & Veatch Corporation AES-110079 This bypass will be used during periods of high solvent loading /Vows unit to handle high VOC loads Hot bypass damper internally lined with hard refractory 330 stainless steel shaft and blade Damper position controlled by PLC and driven with pneumatic actuator with positioner Internally lined bypass duct to mixing plenum Duct and valve sized based on maximum temperature of 1800°F Hot gas routed in refractory -lined duct to a mixing plenum on grade The refractory -lined duct will provide the necessary residence time to achieve the required DRE Duct will be manufactured out of carbon steel and internally coated with vinyl ester coatin to protect against carbonic acid corrosion. FRESH AIR PREHEAT SYSTEM MIXING PLENUM HOT SIDE BYPASS DUCT ANGUIL ENVIRONMENTAL SYSTEMS, INC. a www.aricstxil.com 34 8855 N. 55th Street • Milwaukee, Wisconsin 53223 s Phone : 414-365-6400 • Fax : 414-365-6410 ANGUI Proposal For: Black & Veatch Corporation SUPPLEMENTAL FUEL INJECTION SYSTEM (SFI) Ali S-1 10079 The Anguil Supplemental Fuel Injection (SFI) system is designed as a high efficiency means of controlling the RTO reaction chamber temperature. During system operation, when appropriate safeties have been satisfied, the burner and combustion air systems are turned off and the RTO combustion chamber temperature is maintained by injecting natural gas directly into the VOC laden airstream — typically at or near the inlet of the RTO system. The benefits of SF1 are: Provides high fuel efficiency by reducing combustion air a Provides ultralow NOx emissions with flameless operation a Provides a more uniform temperature profile throughout the RTO All natural gas injection systems enjoy these benefits, but not all systems are created equally. To date, Anguil's level of safety and controls for natural gas injection have been unmatched by our competitors. A few of the highlights are: Some gas injection systems are designed as solenoid -type full -on or full -off systems. Anguil uses modulating injection valves for more precise control. Some gas injection systems are not designed for proper mixing of the natural gas with the solvent laden airstream. Anguil's SFI system is designed with multiple levels of safeties and a custom designed injection quill to ensure a well mixed airstream is delivered to the RTO chamber. Natural gas injection is an excellent means of reducing system operating cost and providing a cleaner "bum" when properly designed and applied. Supplemental Fuel Injection (SFI) Custom Designed Injection Quill Supplemental Fuel Injection (SFI) Additional Fuel Train Piping ANGUIL ENVIRONMENTAL SYSTEMS, INC. a www.anguil.com 15 8855 N. 55th Street • Milwaukee, Wisconsin 53223 0 Phone : 414-365-6400 Fax : 414-365-6410 AL PAINTING Proposal For: Black & V Batch Corporation AES-1 10079 • All welds caulked prior to painting • Equipment to be blasted and painted prior to assembly of the fuel train, switches, and instruments • Al! exposed surfaces of the oxidizer will be primed and painted with two (2) shop coats of Anguil's standard high temperature coating • UV resistant polyurethane paint • Paint color can be specified by the customer • Access platforms, support structures, and access ladders are primed and painted with one coat of Anguil's standard coating. o Combustion air piping as well as natural gas and compressed air piping will be primed and painted with one coat of Anguil's standard coating. AI! other equipment will be the manufacturers standard paint and color. START-UP AND TRAINING SERVICES o Service technician will be provided for up to seven (7), eight -hour consecutive days to start-up and balance the oxidizer • 1 -day of operator training will be conducted during start-up. Training to include 1/2 day classroom sessions and on unit training ® In the event start-up is not completed due to the fault of Anguil, Anguil will remain on site at our cost. ® If customer process is not available during start-up, a return trip will be required on a time and materials basis. OPERATION 8: MAINTENANCE MANUALS o Two (2) hard copy sets of the Operation and Maintenance Manuals (O&M) containing the sequence of operation and drawings o CD-ROM of all Vendor Bulletins FINAL ASSEMBLY AND SHOP TEST We pre -assemble and pre-test modular components in our factory to provide significant savings of time and money during installation and start-up. Units are prewired and pre -piped at the factory for improved quality control and trouble -free start-up. • Temporary assembly of system • Inspection of the unit for manufacturing quality o Check fuel and electrical connections o Starting of burner and fuel train • Warning labels are installed a Test ports are installed • Run electrical rigid conduit • Fans and motors installed, cleared of debris and checked for quality • Valves to be cycled and set o Customer is invited to witness shop testing 16 ANGUIL ENVIRONMENTAL SYSTEMS, INC. e wvtrvnguil.com 8855 N. 55`" Street • Milwaukee, Wisconsin 53223 0 Phone : 414-365-6400 • Fax : 414-365-6410 ANGUIL Items Not Included Proposal For: Black & V eatch Corporation AES-110079 • Concrete pad / platform • Dumpster • Interconnecting wiring between process equipment / tee dampers • All natural gas piping to RTO fuel train • All compressed air piping to RTO air train (-40F dewpoint requirement) and tee dampers • Winterization of the pneumatic piping and sensing lines • Insulation and cladding for water condensation and personnel protection • Power source to RTO control panel • Ductworkidampers from process to oxidizer inlet • Insulation of ductwork, valves, fan and exhaust stack a Oxidizer system fan and combustion air fan disconnects not included a Personnel protection, security fencing and lighting • Moving of oxidizer obstructions, fencing, landscaping, etc. • Multiple installation trips if delays beyond Anguil's control • All roof and building penetrations • All fire suppression piping and controls • All required sound abatement equipment • Compliance testing a Phone line to modem • Taxes, permits a Overtime, holiday or weekend work • Mechanical and electrical installation (Can be quoted as an option) a Budget Freight (Can be quoted as an option) ANGUIL ENVIRONMENTAL SYSTEMS, INC, • www.angt 'r_l_cam 18 8855 N. 55t' Street • Milwaukee, Wisconsin 53223 o Phone : 414-365-6400 ' Fax : 414-365-6410 ANGUIL Exceptions Proposal For: Black & Veatch Corporation AES-110079 As agreed to, Anguil takes exception to Black & Veatch Specification 173458.67.6420. The equipment in this proposal is in accordance with DCP Midstream requirements for BMS Level 2 and meets the scope of supply for other Anguil installations on DCP Midstream sites. ANGUIL ENVIRONMENTAL SYSTEMS, INC. o www.anguil.ratra 17 8855 N. 55th Street Milwaukee, Wisconsin 53223 ® Phone : 414-365-6400 - Fax : 414-365-6410 ANGUIL Proposal For: Black & Veatch Corporation AES-1 10079 Pricing and Delivery One (1) Anguil Model 100 Sour Gas Regenerative Thermal Oxidizer will process 10,000 SCFM of VOC laden process gas, with the required fresh air for oxygen and temperature control, providing 99% destruction efficiency. EQUIPMENT PRICE F.O.B. Origin, Freight Prepaid & Add Sized for 5.89 MM SCFD and up to 33.93 Btu/ft3 FREIGHT $ 663,800.00 Pre -Pay and Add SHIPMENT: 18-22 weeks after approval of drawings (GA and P&ID) *`Due to the rapidly changing market price of metals, Anguil reserves the right to adjust the final price of the equipment accordingly to account for market price. TERMS: 30% down payment upon order placement prior to release of engineering drawings 30% due 8 weeks after receipt of purchase order 30% due prior to shipment or notification of readiness to ship 10% due upon start-up, not to exceed 60 days from shipment. NET 30 ALL PRICES HAVE BEEN QUOTED IN US DOLLARS ALL PRICES WILL REMAIN FIRM FOR 30 DAYS; THEREAFTER, A RE -QUOTE MAY BE REQUIRED ANGUIL ENVIRONMENTAL SYSTEMS, INC. • www.anquEl.cor 19 8855 N. 55th Street • Milwaukee, Wisconsin 53223 a Phone : 414-365-6400 • Fax : 414365-6410 I ANGUIL Proposal For: Black & V eatch Corporation Field Service Rates 2011 Field Service Engineer and Installation Supervision Straight Time (weekdays, 8 hours/day; min. of 8 hours) Overtime (more than 8 hours/day and Saturdays) Sundays and Holidays Emergency Service Rate (site visit within 48 hours of call) Controls Field Service Engineer Travel Time Trip Preparation Report Writing International Labor Rate Technical Phone Support Project Engineer Principal Engineer (weekdays, 8 hours/day; min. of 8 hours) Project Engineer (weekdays, 8 hours/day; min. of 8 hours) Electrical Engineer / Programming Travel and Living Expenses Airline ticket Hotel Car rental Meal allowance Meal allowance — International Airport parking Extra Luggage (tools, etc.), roundtrip Mileage $1,160/day $180/hour $200/hour $180/hour $175/hour $95/hour $100/visit $100/visit $1,275/day $100/hour $1,355/day $1,125/day $150/hour AES-110079 Cost + 15% Administrative fee Cost + 15% Administrative fee Cost + 15% Administrative fee $41/day $62/day $15/day $50/trip $0.78/mile Start -Up and Training Services $1,160/day plus travel and living exp. International Start -Up and Training Services $1,245/day plus travel and living exp. Equipment will be checked mechanically and electrically and all operational data will be verified 9 Service technician will be provided to start-up and balance the oxidizer ® Operator training conducted during start-up. Training includes classroom sessions and on unit training. Terms Net 30 days Terms subject to change upon credit review 2011 Holiday Schedule (premium rates apply) New Years Day Good Friday Memorial Day Independence Day Labor Day Thanksgiving (2 days) Christmas (3 days)New Years ANGUIL ENVIRONMENTAL SYSTEMS, INC. O tfJaliw..rnguil.cQm 20 8855 N. 55th Street • Milwaukee, Wisconsin 53223 a Phone : 414-365-6400 • Fax : 414-365-6410 --• ANGUIL Proposal For: Black & Veatch Corporation Standard Terms and Conditions AES-1 10079 1. General Anguil's prices are based on these terms and conditions of sale. These terms and conditions may not be modified unless prior written agreement is reached between both Anguil and Purchaser and signed by an authorized representative of Anguil. 2. Warranty Any contract resulting from this proposal will require start-up assistance to validate our warranty. This will requires a technical service representative to be present at the time of initial start-up and must give release of operation of the equipment in accordance with the Seller's operating and maintenance manual. Anguil Environmental Systems, inc. (ANGUIL) warrants to the buyer that the products delivered will (a) be free from defects in material and manufacturing workmanship (b) conform to manufacturer's applicable product descriptions attached to Seller's quotation. If no product descriptions or specifications are attached to the quotation, manufacturer's specification in effect on the date of shipment will apply. The product warranties are for a period of 12 months from the date of start-up, if start-up is within thirty (30) days of shipment or 15 months from date of shipment, whichever shall occur first. The product warranties will apply provided the following conditions: • The equipment is operated and maintained as described in the Anguil operating manual provided with the equipment • Recommended routine maintenance must be performed and documented per Anguil instructions at recommended intervals. ▪ This warranty does not apply to heat damage that may occur due to improper use of the RTO, or due to fires that may occur due to excessive buildup of organic matter in the process ductwork. Warranty Exclusions Warranty coverage does not include: (a) freight, labor, travel, and living expenses associated with parts replacement, (b) normal maintenance items such as fan belts, fuses, light bulbs, spark igniters, bearings, seals, gasket, lubrication and cleaning of the equipment, (c) abrasion, corrosion or negligence in operating the equipment on the part of Buyer or Buyer's subcontractor(s). In the event the customer, or any installation contractor employed by the customer, contracts outside ANGUIL for installation work or erection of quoted equipment, the customer will assume full responsibility for workmanship resulting from said contract 3. Performance Guarantee Anguil guarantees the conversion effidency as stated in the proposal or an outlet concentration of 20 ppmv as C1 (methane), whichever is less stringent G The test methods to be used to show compliance is US EPA Method 25A • Anguil requires seven (7) days notice of the official testing to meet DRE guarantee. Anguil reserves the right to review of the test protocol prior to official testing to and to have personnel present at the official compliance test o Equipment is operating in accordance with Seller's written operating and maintenance instructions. o Anguil shall rely on process and chemical information provided by Purchaser or its agents and not be liable for undisclosed or unknown process or chemical materials. 4. Prices / Taxes Prices are quoted in U.S. dollars and may be accepted only within 60 days from date of quotation by Anguil. Anguil reserves the right to adjust the final price of the equipment according to the market price of metals. Any sales, use or other taxes and duties imposed on this sale are not included in the quoted price. If this order is placed from one of the following states; AZ, CA, GA, MA, MI, NJ, NY, Wi; and is taxable, sales tax can be added and will be billed separately to the Purchaser. Anguil will accept a valid exemption certificate from the Purchaser for those orders not taxable. If this order is placed from a state not listed, the Purchaser must provide one of the following; 1) Tax exempt certificate; 2) Pollution control exclusion certificate or 3) Self assessment letter to Anguil. ANGUIL ENVIRONMENTAL SYSTEMS, INC. G www.anquil.com 8855 N. 55`' Street • Milwaukee, Wisconsin 53223 a Phone : 414-365-6400 • Fax : 414-365-6410 21 ANGUIL Proposal For: Black & V eatch Corporation AES-110079 5. Cancellations Orders canceled by Purchaser must be in writing and will be subject to a cancellation fee on the following basis: On any orders canceled prior to the procurement of material and the commencement of fabrication the Purchaser will be subject to a cancellation fee of 15% of Contract value to cover costs incurred for Engineering services plus overhead and reasonable expenses including rep commission made or incurred by Anguil in the initial processing of the order. On orders cancelled after the initiation of production, payment shall be made on the basis of actual cost of labor, materials, components (cancellation fees if applicable) and work in progress plus overhead expenses. Upon written receipt of cancellation, Anguil will immediately stop all work except that necessary to effect termination. 6. Engineering Submittals Anguil will provide layout drawings to the Purchaser for approval and the Purchaser will be asked to comment on these drawings in regards to scope of work, dimensions, site interferences or specifications agreed upon at the time of sale. Approval of Purchaser does not relieve Anguil of obligations to perform to all other specifications of the contract. Final layout drawings will be used to prepare the fabrication drawings after they are returned with the Purchasers approval. Anguil will provide Process and Instrumentation Diagrams (P&ID) for approval and the Purchaser will be asked to comment on these drawings in regards to process verification, scope of supply, system features and instrumentation. Approval of Purchaser does not relieve Anguil of obligations to perform to all other specifications of the contract. Final P&ID drawings will be used to prepare the electrical schematics and controls after they are returned with the Purchaser's approval. All additional Engineering and or drafting costs associated with revising the layout drawings or P&ID as a result of changes requested by Purchaser after initial approval will be considered a Change Order and quoted to the Purchaser at Anguil's prevailing per hour rates. If any such changes cause an increase in the cost or time required for performance, a Change Order will be submitted for Purchase approval. Upon receipt of written approval, Anguil will be granted the authority to proceed with agreed upon changes. 7. Shipping Schedules Anguil will use its best efforts to meet delivery dates agreed to pursuant to the order of which these terms are a part. Anguil shall not be liable for any delay in delivery when such a delay is, directly or indirectly, caused by fires, floods, terrorism, accidents, riots, government interference, strikes, shortage of labor, materials or supplies, delays in transportation or any other causes beyond the reasonable control of Anguil. In the event of delay in performance due to any such cause, the date of delivery or time for completion will be adjusted to reflect the length of time lost by reason of such delay. If a delay in shipping is requested less than 6 weeks prior to shipment, Anguil will complete the system and invoice any "prior to shipment" payment milestone which will be due at the time of the original scheduled ship date. Upon completion of the system, Anguil at its option may place the equipment in storage facilities and the Purchaser will pay the cost of storage, special handling fees and insurance. Equipment held for the Purchaser shall be at the risk of the Purchaser. 8. Acceptance and Testing of Equipment Purchaser will upon delivery inspect and test the equipment and notify Anguil in writing within 30 days of installation or 90 days of shipment, whichever comes first, of all defects discovered including failure of the equipment to meet quoted performance standards. Failure to give such notice constitutes an irrevocable acceptance of the equipment and the equipment will be deemed to conform with the terms of this Agreement, and Purchaser will be bound to pay for the equipment. Upon notification of a defect as above provided, Anguil will repair the equipment and correct the system's performance. 9. Risk of Loss Quotations are F.O.B., place of shipment, unless otherwise noted. The risk of loss of the equipment shipped will pass to Purchaser upon Anguil's delivery of the equipment to a carrier. Claims for damage in shipment must be filed by Purchaser with the carrier. ANGUIL ENVIRONMENTAL SYSTEMS, INC. a vIrwr .arsguil.corn 22 8855 N. 55th Street • Milwaukee, Wisconsin 53223 Phone : 414-365-6400 • Fax : 414-365-6410 AtlU0 Proposal For: Black & Veatch Corporation AES-110079 10. Limitation of Liability In no event will Anguil, its subcontractors, or representatives be held responsible, or liable for any claim, whether in warranty, contract, tort or strict liability for any special, indirect, incidental or consequential damages resulting from the purchase of equipment (including but not limited to incidental or consequential damages for labor, lost profits, lost sales, injury to person or to property or any other incidental loss or damages). Purchaser agrees that Purchaser's exclusive remedy and Anguil's sole liability on any such claim will be limited to reimbursement from Anguil of the purchase price actually received by Anguil from Purchaser for the equipment in question. Anguil shall rely on process and chemical information provided by Purchaser or its agents and not be liable for undisclosed or unknown process or chemical materials (Please refer to Customer Process Specifications section in the proposal). 11. Security Interest Purchaser grants Anguil a security interest in the equipment to secure payment of the balance due hereunder. Purchaser authorizes Anguil to file this Agreement as a Financing Statement or to sign on behalf of Purchaser and file any other Financing Statements with respect to the equipment in any place Anguil deems necessary. 12. Attorney's Fees Purchaser will be liable for all reasonable expenses and attorney's fees incurred by Anguil in enforcing its rights and remedies under this Agreement. 13. Ordinances Any and all required licenses, certificates and operating permits will be the sole responsibility of the Buyer unless otherwise specified by Anguil. 14. Miscellaneous The terms and conditions contained herein and any other terms and conditions stated in Anguil's proposal or specifications attached hereto will constitute the entire agreement between Anguil and Purchaser. The terms and conditions stated herein are applicable to all orders accepted by Anguil unless otherwise specifically agreed to by Anguil in writing. Purchaser will be deemed to have assented to all such terms if any part of the described equipment is accepted. if Purchaser finds any terms not acceptable, Purchaser must so notify Anguil within 15 days. Any additional or different terms contained in Purchaser's order to response hereto will be deemed objected to by Anguil and will be of no effect. This proposal and its acceptance will be governed in all respects by the laws of Wisconsin. In the event of a breach, both parties agree that any suit will be brought in the jurisdiction of the Courts of Wisconsin. ORDER ACCEPTED BY: ANGUIL ENVIRONMENTAL SYSTEMS, INC. BUYER: BY: BY: PRINT: PRINT: TITLE: TITLE: DATE: DATE: ANGUIL ENVIRONMENTAL SYSTEMS, INC. o www.apguil.c raa 2:≥ 8855 N. 55th Street • Milwaukee, Wisconsin 53223 0 Phone ; 414-365-6400 Fax : 414-365-6410 Fs t 1. Proposal For: Black & Veatch Corporation Estirnated Fuei l!aage Process Flow 4,090 SCFM Process Temperature 120°F Ambient Temperature -20°F Inlet Preheat Temperature 350°F Combustion Chamber Temperature 1,550°F Destruction Efficiency 99% Nominal Heat Transfer Efficiency 95% AES-110079A FUEL GAS USAGE(BIU/HR) t390,00i) _ 1,100,000 900,000 700,000 500,000 300,000 _ 100,000 -100,000 _ Model 100 RTO Fuel Usage DCP - La Salle s rt 10 15 VOC LOADING (BTU/SCF) 1 20 25 - 30.. 35 Maximum Fuel Usage: 1,206,000 Btu/hr (0 BTU/SCF Loading) Point of Zero Fuel Usage: 5.70 BTU/SCF Loading ANGUIL ENVIRONMENTAL SYSTEMS, INC. o www.anguil.com 20 8855 N. 555i Street • Milwaukee, Wisconsin 53223 • Phone : 414-365-6400 • Fax : 414-365-6410 MBRNIIPu POINT SCRIM= TP. 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For FOR Pipeline Parameter Value Units Minimum Length of Pipeline 15 miles Average Diameter of Pipeline 6 inches CO2 emissions from RTO 154,348.53 Short tons/yr CO2 Capture Efficiency 90% Captured CO2 138,914 Short tons/yr CO2 Transfer Cost Estimation 1 Cost Type Units Cost Equation Cost ($) Pipeline Costs Materials $ Diameter (inches), Length (miles) $64,632 + $1.85 x L x (330.5 x D2 + 686.7 x D + 26,960) $1,257,277.05 Labor $ Diameter (inches), Lengthemilcs) $341,627 + $1.85 x L x (343.2 x D2 + 2,074 x D + 170,013) $5,747,665.55 Miscellaneous Diameter (inches), Length $150,166 + $1.58 x L x (8,417 x D + 7,234) $1,518,509.20 Right of Way $(miles) Diameter(inches), Length (miles) $48,037 + $1.20 x L x (577 x D +29,788) $646,537.00 Other Capital CO2 Surge Tank $ $1,150,636 $1,150,636.00 Pipeline Control System $ $110,632 $110,632.00 Operation & Maintenance (O&M) Fixed O&M I $/mile/yr I $8,632 $129,480.00 Total Pipeline Cost $10,560,736.80 Amortized Cost Calculation Equipment Life 2 10 years Interest rate 3 7% Capital Recovery Factor (CRF) 4 0.14 Total Pipeline Installation Cost (TCI) $10,431,257 $ (Pipeline + Other Capital) Amortized Installation Cost (TCI *CRF) $1,485,176 $/yr Amortized Installation + O&M Cost $1,614,656 $/yr CO2 Transferred 138,914 Short ons/yr Annuitized control cost per tons 12 $/ton-yr 1 Cost estimation guidelines obtained from "Quality Guidelines for Energy System Studies Estimating Carbon Dioxide Transport and Storage Costs", DOE/NETL-2O1O/1447, dated March 2010. 2 Pipeline life is assumed based on engineering judgment. 3 Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition. 4 Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) " Pipeline Life) / ((1 + Interest Rate (%)) ^ Pipeline Life - 1) S This cost estimation does not include capital and O&M costs associated with the compression equipment or processing equipment. DCP Midstream, LP Trinity Consultants Lucerne 2 Expansion Amortized Cost Calculation - For FOR Pipeline Equipment Life' 30 years Interest rate 2 7% Capital Recovery Factor (CRF)' 0.08 Total Capital Cost for Equipment(TCI)4 $50,000,000 $ (Pipeline + Other Capital) Amortized Installation Cost (TCI'CRF) $4,029,320 $/yr Amortized Installation -I- O&M Cost $4,158,800 $/yr CO2 Transferred 138,914 Short tons/yr Annuitized control cost per tons 30 $/ton-yr 1 Plant life is assumed based on engineeringjudgment. 2 Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition. 3 Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) A Pipeline Life) / ((1 + Interest Rate (%)) A Pipeline Life - 1) A Total equipment capital cost assumed conservatively to be $50 million. s This cost estimation includes the compression equipment and processing equipment. DCP Midstream, LP Trinity Consultants Lucerne 2 Expansion Amortized Cost Calculation - DCP Lucerne 2 Expansion Equipment Life" 30 years Interest rate 2 7% Capital Recovery Factor (CRF) 3 0.08 Total Capital Cost (TCI) " $200,000,000 $ (Pipeline + Other Capita]) Amortized Installation Cost (TCI'CRF) $16,117,281 $/yr CO2 Transferred 138,914 Short tons/yr r Plant life is assumed based on engineering judgment 2 Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition, 3 Capital Recovery Fraction = Interest Rate (%) x (1+ Interest Rate (%)) A Pipeline Life) / ((1 + Interest Rate (%)) A Pipeline Life - 1) 4 Total equipment capital cost assumed conservatively to be $200 million per internal DCP resources. Ratio of Capital Cost for CCS and Capital Cost for Project CCS Total" $ 5,514,496 DCP Total $ 16,117,281 Ratio : 34.21% " Taken as sum of Pipeline transfer amortized costs and CCS capital amortized costs. 2 DCP Lucerne 2 Expansion capital amortized cost DCP Midstream, LP Trinity Consultants Lucerne 2 Expansion the ENERGY lab QUALITY GUIDELINES FOR ENERGY SYSTEM STUDIES Estimating _.-r ':on. Dioxide Transport and Storage Costs Capilall "�� Vb�CAYITAL Cp5YS �I mi Ese'iMi.nilun'neconstraciion NATIONAL ENE;GY TECHNOLOGY LA3O?ATO?Y DOE/NETL-2010/1447 U.S. DEPARTMENT OF ENERGY >Z Transport, Storage &rlMonitoring Costf uality Guidelines for Energy SystemsrStud e, t Quality Guidelines for ergy Systems Studies Estimating CO2 Transport, Storage & Monitoring Costs Background This paper explores the costs associated with geologic sequestration of carbon dioxide (CO2). This cost is often cited at the flat figure of $5-10 per short ton of CO2 removed, but estimates can vary with values as high as $23 per short ton having been published recently [1, 2, 3]. The variability of these costs is due in part to the wide range of transportation and storage options available for CO2 sequestration, but may also relate to the dramatic rise of construction and material costs in the United States which has occurred over the last several years. This paper examines the transportation of CO2 via pipeline to, and storage of that CO2 in, a geologic formation representative of those identified in North America as having storage potential based on data available from the literature. Approach Geologic sequestration costs were assessed based on the pipeline transport and injection of super -critical CO2 into a geologic reservoir representative of those identified in North America as having storage potential. High pressure (2,200 psig) CO2 is provided by the power plant or energy conversion facility and the cost and energy requirements of compression are assumed by that entity. CO2 is in a super -critical state at this pressure which is desirable for transportation and storage purposes. CO2 exits the pipeline terminus at a pressure of 1,200 psig, and the pipeline diameter was sized for this to be achieved without the need for recompression stages along the pipeline length. This exit pressure specification: (1) ensures that CO2 remains in a supercritical state throughout the length of the pipeline regardless of potential pressure drops due to pipeline elevation changel; (2) is equivalent to the reservoir pressure — exceeding it after hydrostatic head is accounted for — alleviating the need for recompression at the storage site; and (3) minimizes the pipeline diameter required, and in turn, transport capital cost. The required pipeline diameter was calculated iteratively by determining the diameter required to achieve a 1,000 psig pressure drop (2,200 psig inlet, 1,200 psig outlet) over the specified pipeline distance, and rounding up to the nearest even sized pipe diameter. The pipeline was sized based on the CO2 output produced by the power plant when it is operating at full capacity (100% utilization factor) rather than the average capacity. The storage site evaluated is a saline formation at a depth of 4,055 feet (1,236 meters) with a permeability of 22 and and down -hole pressure of 1,220 psig (8.4 MPa) [4].2 This is considered an average storage site and requires roughly one injection well for each 10,300 short tons of CO2 injected per day [4]. An overview of the geologic formation characteristics are shown in Table 1. Table 1: Deep, Saline Formation Specification [4] Parameter Pressure Thickness Depth Permeability Pipeline Distance Injection Rate per Well Units MPa (psi) m (ft) m (ft) AYerage Case• 8.4 (1,220) 161 (530) 1,236 (4,055) Md 22 km (miles) 80 (50) tonne (short ton) CO2/day 9,360 (10,320) Changes in pipeline elevation can result in pipeline pressure reductions due to head losses, temperature variations or other factors. Therefore a 10% safety margin is maintained to ensure the CO2 supercritical pressure of 1,070 psig is exceeded at all times. 2 "md", or millidarcy, is a measure of permeability defined as 10.12 Darcy. National Energy Technology Laboratory Office of Systems, Analyses, and Planning 27ransport, Storage & Monitoring Costs uality Guidelines for Energy Systems Studies' Cost Sources & Methodology The cost metrics utilized in this study provide a best estimate of T, S, & M costs for a "typical" sequestration project, and may vary significantly based on variables such as terrain to be crossed by the pipeline, reservoir characteristics, and number of land owners from which sub -surface rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics found in the literature, escalated to June 2007 -year dollars using appropriate price indices. These costs were then verified against values quoted by any industrial sources available. Where regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of underground pore volume, analogous existing policies were used for representative cost scenarios. The following sections describe the sources and methodology used for each metric. Cost Levelization and Sensitivity Cases Capital costs were levelized over a 30 -year period and include both process and project contingency factors. Operating costs were similarly levelized over a 30 -year period and a sensitivity analysis was performed to determine the effects of different pipeline lengths on overall and avoided costs as well as the distribution of transport versus storage costs. In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur over a longer time period, up to 100 years. In these cases a capital fund is established based on the net present value of the cost outlay, and this fund is then levelized as described in the previous paragraph. Following the determination of cost metrics, a range of CO2 sequestration rates and transport distances were assessed to determine cost sensitivity to these parameters. Costs were also assessed in terms of both removed and avoided emissions cost, which requires power plant specific information such as plant efficiency, capacity factor, and emission rates. This paper presents avoided and removed emission costs for both Pulverized Coal (PC) and Integrated Gasification Combined Cycle (IGCC) cases using data from Cases 11 & 12 (Supercritical PC with and without CO2 Capture) and Cases 1 & 2 (GEE Gasifier with and without CO2 Capture) from the Bituminous Baseline Study [5]. Transport Costs CO2 transport costs are broken down into three categories: pipeline costs related capital expenditures and O&M costs. Pipeline costs are derived from data published in the Oil and Gas Journal's (O&GJ) annual Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2 pipeline, as noted in various studies [4, 6, 7]. The University of California performed a regression analysis to generate the following cost curves from the O&GJ data: (1) Pipeline Materials, (2) Direct Labor, (3) Indirect Costs3, and (4) Right-of-way acquisition, with each represented as a function of pipeline length and diameter [7]. Related capital expenditures were based on the findings of a previous study funded by DOE/NETL, Carbon Dioxide Sequestration in Saline Formations — Engineering and Economic Assessment [6]. This study utilized a similar basis for pipeline costs (Oil and Gas Journal Pipeline cost data up to the year 2000) but added a CO2 surge tank and pipeline control system to the project. Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored report entitled Economic Evaluation of CO2 Storage and Sink Enhancement Options [4]. This study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (a) 3 Indirect costs are inclusive of surveying, engineering, supervision, contingencies, allowances for funds used during construction, administration and overheads, and regulatory filing fees. National Energy Technology Laboratory Office of Systems, Analyses, and Planning do not report operating costs, or (b) report them in absolute terms for one pipeline, as opposed to as a length - or diameter -based metric. Storage Costs Storage costs were broken down into five categories: (1) Site Screening and Evaluation, (2) Injection Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the exception of Pore Volume Acquisition, all of the costs were obtained from Economic Evaluation of CO2 Storage and Sink Enhancement Options [4]. These costs include all of the costs associated with determining, developing, and maintaining a CO2 storage location, including site evaluation, well drilling, and the capital equipment required for distributing and injecting CO2. Pore Volume Acquisition costs are the costs associated with acquiring rights to use the sub -surface area where the CO2 will be stored, i.e. the pore space in the geologic formation. These costs were based on recent research by Carnegie Mellon University which examined existing sub -surface rights acquisition as it pertains to natural gas storage [8]. The regulatory uncertainty in this area combined with unknowns regarding the number and type (private or government) of property owners requires a number of "best engineering judgment" decisions to be made, as documented below under Cost Metrics. Liability Protection Liability Protection addresses the fact that if damages are caused by injection and long-term storage of CO2, the injecting party may bear financial liability. Several types of liability protection schemas have been suggested for CO2 storage, including Bonding, Insurance, and Federal Compensation Systems combined with either tort law (as with the Trans -Alaska Pipeline Fund), or with damage caps and preemption, as is used for nuclear energy under the Price Anderson Act [9]. At present, a specific liability regime has yet to be dictated either at a Federal or (to our knowledge) State level. However, certain state governments have enacted legislation which assigns liability to the injecting party, either in perpetuity (Wyoming) or until ten years after the cessation of injection operations, pending reservoir integrity certification, at which time liability is turned over to the state (North Dakota and Louisiana) [10, 11, 12]. In the case of Louisiana, a trust fund of five million dollars is established for each injector over the first ten years (120 months) of injection operations. This fund is then used by the state for CO2 monitoring and, in the event of an at -fault incident, damage payments. This study assumes that a bond must be purchased before injection operations are permitted in order to establish the ability and good will of an injector to address damages where they are deemed liable. A figure of five million dollars was used for the bond based on the Louisiana fund level. This Bond level may be conservative, in that the Louisiana fund covers both liability and monitoring, but that fund also pertains to a certified reservoir where injection operations have ceased, having a reduced risk compared to active operations. This cost may be updated as more specific liability regimes are instituted at the Federal or State levels. The Bond cost was not escalated. Monitoring Costs Monitoring costs were evaluated based on the methodology set forth in the 'EA Greenhouse Gas R&D Programme's Overview of Monitoring Projects for Geologic Storage Projects report [13]. In this scenario, operational monitoring of the CO2 plume occurs over thirty years (during plant operation) and closure monitoring occurs for the following fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic seismic survey, EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases. National Energy Technology Laboratory Office of Systems, Analyses, and Planning CO2 Transport, Storage & Monitoring Costs Quality Guidelines for Energy Systems Studies Cost Metrics The following sections detail the Transport, Storage, Monitoring, and Liability cost metrics used to determine CO2 sequestration costs for the deep, saline formation described above. The cost escalation indices utilized to bring these metrics to June -2007 year dollars are also described below. Transport Costs The regression analysis performed by the University of California breaks down pipeline costs into four categories: (1) Materials, (2) Labor, (3) Miscellaneous, and (4) Right of Way. The Miscellaneous category is inclusive of costs such as surveying, engineering, supervision, contingencies, allowances, overhead, and filing fees [7]. These cost categories are reported individually as a function of pipeline diameter (in inches) and length (in miles) in Table 2 [7]. The escalated CO2 surge tank and pipeline control system capital costs, as well as the Fixed O&M costs (as a function of pipeline length) are also listed in Table 2. Fixed O&M Costs are reported in terms of dollars per miles of pipeline per year. Storage Costs Storage costs were broken down into five categories: (1) Site Screening and Evaluation, (2) Injection Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Space Acquisition. Additionally, the cost of Liability Protection is also listed here for the sake of simplicity. Several storage costs are evaluated as flat fees, including Site Screening & Evaluation and the Liability Bond required for sequestration to take place. As mentioned in the methodology section above, the site screening and evaluation figure of $4.7 million dollars is derived from Economic Evaluation of CO2 Storage and Sink Enhancement Options [4]. Some sources in Table 2: Pipeline Cost Breakdown [4, 6, 71 Pipeline Costs Materials Diameter (inches), Length (miles) $64,632 +$1.85 x Lx (330.5x D2 + 686.7x D +26,960) Labor Diameter (inches), Length (miles) $341,627+$1.85x Lx (343.2 x D2 + 2,074 x D+170,013) Miscellaneous Diameter (inches), Length (miles) $150,166+$1.58x Lx (8,417 x D+ 7,234) Right of Way Diameter (inches), Length (miles) $48,037 + $1.20 x Lx (577 x D + 29,788) Other Capital CO2 Surge Tank $1,150,636 Pipeline Control System $110,632 O&M Fixed O&M $/mile/year $8,632 National Energy Technology Laboratory Office of Systems, Analyses, and Planning CO2 Transport, Storage & Monitoring Costs`'"'` Quality Guidelines for Energy Systems Studies industry, however, have quoted significantly higher costs for site screening and evaluation, on the magnitude of $100 to $120 million dollars. The higher cost may be reflective of a different criteria utilized in assessing costs, such as a different reservoir size — the reservoir assessed in the higher cost case could be large enough to serve 5 to 7 different injection projects — or uncertainty regarding the success rate in finding a suitable reservoir. Future analyses will examine the sensitivity of overall T, S, and M costs to higher site evaluation costs. Pore Space Acquisition costs are based on acquiring long-term (100 -year) lease rights and paying annual rent to land -owners once the CO2 plume has reached their property. Rights are acquired by paying a one-time $500 fee to land -owners before injection begins, as per CMU's design criteria [8]. When the CO2 plume enters into the area owned by that owner (as determined by annual monitoring), the injector begins paying an annual "rent" of $100 per acre to that owner for the period of up to 100 years from plant start-up [8]. A 3% annual escalation rate is assumed for rental rate over the 100 -year rental period [8]. Similar to the CMU study, this study assumes that the plume area will cover rights need to be acquired from 120 landowners, however, a sensitivity analysis found that the overall acquisition costs were not significantly affected by this: increasing the Table 3: Geologic Storage Costs [4, 8, 11] Cost Type Units Cost Capital Site Screening and Evaluation $ $4,738,488 Injection Wells $/injection well 1'2'3 (see formula) 240 714 x e0.0008X,i'e»—dep,h Injection Equipment $/injection well (see formula)- 7,389 $94,029 0.s x 280 x # of injection wells) Liability Bond $ $5,000,000 Declining Capital Funds Pore Space Acquisition $/short ton CO2 $0.334/short ton CO, O&M Normal Daily Expenses (Fixed O&M) $/injection well $11,566 Consumables (Variable O&M) $/yr/short ton CO2/day $2,995 Surface Maintenance (Fixed O&M) see formula 7,389 $23,478 0.5 x 280 x # of injection wells Subsurface Maintenance (Fixed O&M) $/ft-depth/inject. well $7.08 The units for the "well depth" term in the formula are meters of depth. 'The formulas at right describe the cost per injection well and in each case the number of injection wells should be multiplied the formula in order to determine the overall capital cost. 'The injection well cost is $508,652 per injection well for the 1,236 meter deep geologic reservoir assessed here. National Energy Technology Laboratory Office of Systems, Analyses, and Planning Monitoring Costs Guidelines for Energy Systems Studies number of owners to 120,000 resulted in a 110% increase in costs and a 1% increase in the overall LCOE of the plant [8]. However, this assumption will be revisited in future work. To ensure that Pore Space Acquisition costs are met after injection ceases, a sinking capital fund is set up to pay for these costs by determining the present value of the costs over the 100 -year period (30 years of injection followed by 70 additional years), assuming a 10% discount rate. The size of this fund — as described in Table 3 — is determined by estimating the final size of the underground CO2 plume, based on both the total amount of CO2 injected over the plant lifetime and the reservoir characteristics described in Table 1. After injection, the CO2 plume is assumed to grow by 1% per year [9]. The remaining capital costs are based on the number of injection wells required, which has been calculated to be one injection well for every 10,320 short tons of CO2 injected per day. O&M costs are based on the number of injection wells, the CO2 injection rates, and injection well depth. Monitoring Costs Monitoring costs were evaluated based on the methodology set forth in the lEA Greenhouse Gas R&D Programme's Overview of Monitoring Projects for Geologic Storage Projects report [13]. In this scenario, operational monitoring of the CO2 plume occurs over thirty years (during plant operation) and closure monitoring occurs for the following fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic seismic survey, EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases. Operational and closure monitoring costs are assumed to be proportional to the plume size plus a fixed cost, with closure monitoring costs evaluated at half the value of the operational costs. The CO2 plume is assumed to grow from 18 square kilometers (km2) after the first year to 310 km2 in after the 30th (and final) year of injection. The plume grows by 1% per year thereafter, to a size of 510 km2 after the 801h year [9].The present value of the life -cycle costs is assessed at a 10% discount rate and a capital fund is set up to pay for these costs over the eighty year monitoring cycle. The present value of the capital fund is equivalent to $0.377 per short ton of CO2 to be injected over the operational lifetime of the plant. Cost Escalation Four different cost escalation indices were utilized to escalate costs from the year -dollars they were originally reported in, to June 2007 -year dollars. These are the Chemical Engineering Plant Cost Index (CEPI), U.S. Bureau of Labor Statistics (BLS) Producer Price Indices (PPI), Handy -Whitman Index of Public Utility Costs (HWI), and the Gross -Domestic Product (GDP) Chain -type Price Index [14, 15, 16]. Table 4 details which price index was used to escalate each cost metric, as well as the year -dollars the cost was originally reported in. Note that this reporting year is likely to be different that the year the cost estimate is from. Cost Comparisons The capital cost metrics used in this study result in a pipeline cost ranging from $65,000 to $91,000/inch- Diameter/mile for pipeline lengths of 250 and 10 miles (respectively) and 3 to 4 million metric tonnes of CO2 sequestered per year. When project and process contingencies of 30% and 20% (respectively) are taken into account, this range increases to $97,000 to $137,000/inch-Diameter/mile. These costs were compared to contemporary pipeline costs quoted by industry experts such as Kinder -Morgan and Denbury Resources for verification purposes. Table 5 details typical rule -of -thumb costs for various terrains and scenarios as quoted by a representative of Kinder -Morgan at the Spring Coal Fleet Meeting in 2009. As shown, the base NETL cost metric falls midway between the costs quoted for "Flat, Dry" terrain ($50,000/inch-Diameter/mile) and "High Population" or "Marsh, Wetland" terrain ($100,000/inch-Diameter/mile), although the metric is closer to the "High Population" or "Marsh, Wetland" when contingencies are taken into account [17]. These costs were stated to be inclusive of right-of-way (ROW) costs. National Energy Technology Laboratory Office of Systems, Analyses, and Planning OZ Transport, Storage & Monitoring Costs i ystems Studies ual tyrGu defines forEnetgy arch. 201 Table 4: Summary of Cost Escalation Methodolo Cost Metric Year -S Index Utilized Transport Costs Pipeline Materials 2000 HWI: Steel Distribution Pipe Direct Labor (Pipeline) 2000 HWI: Steel Distribution Pipe Indirect Costs (Pipeline) 2000 BLS: Support Activities for Oil & Gas Operations Right -of -Way (Pipeline) 2000 GDP: Chain -type Price Index CO2 Surge Tank 2000 CEPI: Heat Exchangers & Tanks Pipeline Control System 2000 CEPI: Process Instruments Pipeline O&M (Fixed) 1999 BLS: Support Activities for Oil & Gas Operations Storage Costs Site Screening/Evaluation 1999 BLS: Drilling Oil & Gas Wells Injection Wells 1999 BLS: Drilling Oil & Gas Wells Injection Equipment 1999 HWI: Steel Distribution Pipe Liability Bond 2008 n/a Pore Space Acquisition 2008 GDP: Chain -type Price Index Normal Daily Expenses (Fixed) 1999 BLS: Support Activities for Oil & Gas Operations Consumables (Variable) 1999 BLS: Support Activities for Oil & Gas Operations Surface Maintenance 1999 BLS: Support Activities for Oil & Gas Operations Subsurface Maintenance 1999 BLS: Support Activities for Oil & Gas Operations Monitoring Monitoring 2004 BLS: Support Activities for Oil & Gas Operations Ronald T. Evans of Denbury Resources, Inc. provided a similar outlook, citing pipeline costs as ranging from $55,000/inch-Diameter/mile for a project completed in 2007, $80,000/inch-Diameter/mile for a recently completed pipeline in the Gulf Region (no wetlands or swamps), and $100,000/inch-Diameter/mile for a currently planned pipeline, with route obstacles and terrain issues cited as the reason for the inflated cost of that pipeline [18, 19]. Mr. Evans qualified these figures as escalated due to recent spikes in construction and material costs, quoting pipeline project costs of $30,000/inch-Diameter-mile as recent as 2006 [18, 19]. A second pipeline capital cost comparison was made with metrics published within the 2008 lEA report entitled CO2 Capture and Storage: A key carbon abatement option. This report cites pipeline costs ranging from $22,000/inch-Diameter/mile to $49,000/inch-Diameter/mile (once escalated to December -2006 dollars), between 25% and 66% less than the lowest NETL metric of $65,000/inch-Diameter/mile [20]. The lEA report also presents two sets of flat figure geologic storage costs. The first figure is based on a 2005 Intergovernmental Panel on Climate Change report is similar to the flat figure quoted by other entities, citing Table 5: Kinder -Morgan Pipeline Cost Metrics [171 Flat, Dry $50,000 Mountainous $85,000 $100,000 $300,000 $100,000 $700,000 Marsh, Wetland River High Population Offshore (150'-200' depth) National Energy Technology Laboratory Office of Systems, Analyses, and Planning storage costs ranging from $0.40 to $4.00 per short ton of CO2 removed [20]. This figure is based on sequestration in a saline formation in North America. A second range of costs is also reported, citing CO2 sequestration costs as ranging from $14 to $23 per short ton of CO2 [13]. This range is based on a Monte Carlo analysis of 300 gigatonnes (Gt) of CO2 storage in North America [20]. This analysis is inclusive of all storage options (geologic, enhanced oil recovery, enhanced coal bed methane, etc.), some of which are relatively high cost. This methodology may provide a more accurate cost estimate for large-scale, long-term deployment of CCS, but is a very high estimate for storage options that will be used in the next 50 to 100 years. For example, 300 Gt of storage represents capacity to store CO2 from the next -150 years of coal generation (2,200 million metric tonnes CO2 per year from coal in 2007, assuming 90% capture from all facilities), meaning that certain high cost reservoirs will not come into play for another 100 or 150 years. This $14 to $23 per short ton estimate was therefore not viewed as a representative comparison to the NETL metric. Results Figure 1 describes the capital costs associated with the T&S of 10,000 short tons of CO2 per day (2.65 million metric tonnes per year) for pipelines of varying length. This storage rate requires one injection well and is representative of the CO2 produced by a 380 MW9 super -critical pulverized coal power plant, assuming 90% of the CO2 produced by the plant is captured. Figure 2 presents similar information for Fixed, Variable, and total (assuming 100% capacity) operating expenses. In both cases, storage costs remain constant as the CO2 flow rate and reservoir parameters do not change. Also, transport costs — which are dependent on both pipeline length and diameter — constitute the majority of the combined transport and storage costs for pipelines greater than 50 miles in length. The disproportionately high cost of CO2 transport (compared to storage costs) shown in Figures 1 and 2, and the direct dependence of pipeline diameter on the transport capital cost, prompted investigation into the effects of pipeline distance and CO2 flow rate on pipeline diameter. Figure 3 describes the minimum required pipeline diameter as a function of pipeline length, assuming a CO2 flow rate of 10,000 short tons per day (at 100% Figure 1: Capital Cost vs. Pipeline Length Pipeline Diameter'is listed in the Blue Boxes. National Energy Technology Laboratory Office of Systems, Analyses, and Planning Storage &,Monttortng Costs roes for Energy Systems Studies'. Figure 2: Operating and Maintenance Cost vs. Pipeline Length Pipeline Diameter is ,t listed in the Blue Boxes. utilization factor) and a pressure drop of 700 psi in order to maintain single phase flow in the pipeline (no recompression stages are utilized). Figure 4 is similar except that it describes the minimum pipe diameter as a function of CO2 flow rate. A sensitivity analysis assessing the use of boost compressors and a smaller pipeline diameter has not yet been completed but may provide the ability to further reduce capital costs for sufficiently long pipelines. Figure 3: Minimum Pipe Diameter as a function of Pipeline Length 25 20 N Gl V 15 L d d R 10 O m c d a. 5 a 0 PipelineD ameterfora COZ flow rate oflO.000 short . tons perday (2 65 million metric tonnes per year) • 0 50 100 150 200 250 300 350 400 450 500 550 Pipeline Distance (miles) National Energy Technology Laboratory Office of Systems, Analyses, and Planning Q2 Transport, ualtty Guidelinesrfor Energy Systems Studies •r..�. 4«:. '"'Y , ^�9..aa,o-, F 4�'5,a s,4�u� �j- 4 uik, .. r��n - , . Figure 4: Pipe Diameter as a Function of CO2 Flow Rate Pipeline Diameterfara 5O mile long Pipeline Figures 5 and 6 describe the relationship of T&S costs to the flow rate of CO2. The costs are evaluated for a 50 mile pipeline and a 700 psig CO2 pressure drop over the length of the pipeline. Storage capital costs remain constant up until 10,000 shod tons of CO2 per day, above which a second injection well is needed and the cost increases as shown in Figure 5. A third injection well is needed for flow rates above 21,000 short tons per day and the capital requirement increases again for the 25,000 short tons per day flow rate due to an increase in pipeline diameter. Transport capital costs outweigh storage costs for all cases, as expected based on the results shown in Figure 1. Unlike storage capital costs, the operating costs for storage constitute a significant portion of the total annual O&M costs — up to 44% at 25,000 short tons of CO2 per day — as shown in Figure 6. Transport operating costs are constant with flow rate based on a constant pipeline length. Figure 5: Capital Requirement vs. CO2 Flow Rate Capita/ Coats fora 50 mile long Pipe)ine g $200 vi $150 $100 a R o $50 $0 2,500 5,000 0,000 15,000 CO2 Flowrate (short tons/day) 25,000 ■Monitoring s Transport ❑Storage National Energy Technology Laboratory Office of Systems, Analyses, and Planning Transport, Sto•rage &�Monitoring Costs• uality,Guidelines for Energy Systems Studies Figure 6: Operating and Maintenance Cost vs. CO2 Flow Rate O&MCaStsfofa50milelongPipeline"' " Lastly, CO2 avoidance and removal costs associated with T&S were determined for PC and IGCC reference plants found in the Baseline Study.4 Because the C02 flow rate is defined by the reference plant, costs were determined as a function of pipeline length. Figure 7 shows that T&S avoided costs increase almost linearly with pipeline length and that there is very little difference between the PC and IGCC cases. This is the result of identical pipelines for each case (same distance, identical diameter) with only a change in capacity factor for each case. Figure 8 is similar to Figure 7 and shows the T&S removed emission cost. Figure 7: Avoided Emission Costs for 550 MW Power Plants vs. Pipeline Length $80 $70 o $60 o c Ov $50 N0 o w Yo d N 0 $20 $40 $30 $10 $0 0 100 200 300 400 Pipeline Length (miles) 500 600 —� IGCC —0—PC 4 Avoided cost calculations are based upon a levelized cost of electricity reported in Volume 1 of NETL's Cost and Performance Baseline for Fossil Energy Plants study. Electricity costs are levelized over a 30 year period, utilize a capital charge factor of 0.175, and levelization factors of 1.2022 and 1.1568 for coal costs and general O&M costs, respectively [3]. National Energy Technology Laboratory Office of Systems, Analyses, and Planning ransport, Storage '& Monitoring Costs Guidelines for Energy Systems Studies Addressing our initial topic, we see that our T&S avoided emission cost of $5 to $10 per short ton of CO2 is associated with a pipeline length of 30 to 75 miles for the reference reservoir and our IGCC reference plant, or 50 to 95 miles for our PC reference plant. The T&S removal cost of $5 to $10 per short ton of CO2 is associated with a pipeline length of 40 to 100 miles for an IGCC and 40 to 115 for a PC plant. Both of these ranges apply to the reference reservoir found in Table 1. Figure 8: Removed Emission Costs for 550 MW Power Plants vs. Pipeline Length $60 $50 N O $40 o .2U N O o $30 we 'O O z o JP.e $20 m $10 $0 100 200 300 400 Pipeline Length (miles) 500 0 600 - IGCC - PC Conclusions • T&S avoided emission cost of $5 to $10 per short ton of CO2 is associated with a pipeline length of 30 to 75 miles for our reference IGCC plant and the reference reservoir found in Table 1, or pipeline lengths of 50 to 95 miles for the PC plant. • T&S removed emission cost of $5 to $10 per short ton of CO2 is associated with a pipeline length of 40 to 100 miles for an IGCC and 40 to 115 for a PC plant. Both of these ranges apply to the reference reservoir found in Table 1. Capital costs associated with CO2 storage become negligible compared to the cost of transport (i.e. pipeline cost) for pipelines of 50 miles or greater in length. • Transport and storage operating costs are roughly equivalent for a 25 mile pipeline but transport constitutes a much greater portion of operating expenses at longer pipeline lengths. Transport capital requirements outweigh storage costs, independent of CO2 flow rate, at a pipeline length of 50 miles and the reference reservoir. • Operating expenses associated with storage approach transport operating costs for flow rates of 25,000 short tons of CO2 per day at a 50 mile pipeline length. \`---1 National Energy Technology Laboratory Office of Systems, Analyses, and Planning utdeltries for tern§ u,,. Future Work This paper has identified a number of areas for investigation in future work. These include: e Investigation into the apparent wide variability in site characterization and evaluation costs, including a sensitivity analysis to be performed to determine the sensitivity of overall project costs across the reported range of values. Continued research into liability costs and requirements. e Further evaluation and sensitivity analysis into the number of land -owners pore space rights will have to be acquired from for a given sequestration project. National Energy Technology Laboratory Office of Systems, Analyses, and Planning eltnes for ;;isµ., ems"' Refer ences 1. CCS GUIDELINES: Guidelines for Carbon Dioxide Capture, Transport, and Storage, World Resources Institute, Washington DC, 2008. 2. The Future of Coal: Options fora Carbon -Constrained World. J. Katzer, et al, Massachusetts Institute of Technology, 2007. 3. Ken Hnottavange-Telleen, "CCS: Global Hurdles, Additional Investment and Costs for a CTL Unit," World CTL Conference, Washington, DC, March 27th, 2009. 4. Economic Evaluation of CO2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL, EPRI, December 2002. 5. Cost and Performance Baseline for Fossil Energy Plants: Volume 1: Bituminous Coal and Natural Gas to Electricity. Prepared by Research and Development Solutions, LLC for US DOE/NETL. Pittsburgh, PA, May 2007. 6. Carbon Dioxide Sequestration in Saline Formations — Engineering and Economic Assessment. Prepared by Battelle for US DOE/NETL. Morgantown, WV, July 2001. 7. Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen Pipeline Costs. N. Parker, Institute of Transportation Studies, University of California, Davis, CA, 2004. 8. Implications of Compensating Property -Owners for Geologic Sequestration of CO2. Gresham, R. L., Apt, J., et. al, Department of Engineering and Public Policy, Carnegie Mellon University, Pittsburgh, PA, 2009. 9. "Climate Change and Carbon Sequestration: Assessing a Liability Regime for Long -Term Storage of Carbon Dioxide". Klass, A.B., Wilson, E.J., 58 Emory Law Journal 103 (2008). 10. Senate Bill No. 2095, 61st Legislative Assembly of North Dakota, January 6th, 2009. 11. House Bill No. 661, Louisiana House of Representatives Regular Session, 2009. 12. Enrolled Act No. 20 (Original House Bill No. 58), 601h Legislature of the State of Wyoming, General Session, 2009. 13. Overview of Monitoring Requirements for Geologic Storage Projects. lEA Greenhouse Gas R&D Programme, Report Number PH4/29, November 2004. 14. Handy -Whitman Index of Public Utility Costs, Gas Transmission and Distribution Pipe Materials Indexes, February 2008. 15. U.S. Bureau of Labor Statistics Producer Price Index, Support activities for oil and gas operations, Series Id: PCU213112213112, February 2008. 16. U.S. Bureau of Labor Statistics Producer Price Index, Drilling Oil and Gas Wells, Series Id: PCU213111213111, February 2008. 17. Jeffrey Layne, "Operating Experience with CO2 Pipelines," Proceedings of the EPRI Coal Fleet for Tomorrow: General Technical Meeting, Houston, TX, April 21 -23rd, 2009. 18. Statement of Ronald T. Evans of Denbury Resources, Inc., before the U.S. Senate Committee on Energy and Natural Resources. Hearing on the Policy Aspects of Carbon Capture, Transportation, and Sequestration and Related Bills, S.2323 and S.2144, January 31, 2008. htto://energy.senate.gov/public/index.cfm?FuseAction=Hearings.Testimonv&Hearinq ID=1672&Witne ss ID=4847 19. Personal communication with Ronald T. Evans of Denbury Resources, Inc. December 30th, 2009. 20. CO2 Capture and Storage: A key carbon abatement option, International Energy Agency, Paris France, 2008. 21. "CO2 Flow Modeling and Pipe Diameter Determination", Jared P. Ciferno, Howard Mcllvried, SAIC, February 2003. National Energy Technology Laboratory Office of Systems, Analyses, and Planning Contacts Thomas J. Tarka, P.E. Senior Energy Systems Engineer Office of Systems, Analyses & Planning National Energy Technology Laboratory 626 Cochrans Mill Road P.O. Box 10940 Pittsburgh, PA 15236 412-386-5434 thomas.tarka a(U).netl.doe.gov John G. Wimer Director, Systems Division Office of Systems, Analyses & Planning National Energy Technology Laboratory 3601 Collins Ferry Road P.O. Box 880 Morgantown, WV 26507 304-285-4124 john.wimera(�netl.doe.gov Hello