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Home My WebLink About20161156 A CDPHE COLORADO Co Department of Public Health&Environment Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board 11500 St PO Box 758 RECEIVED Greeley, CO 80632 March 22, 2016 MAR 2 8 2016 WELD COUNTY COMMISSIONERS Dear Sir or Madam: On March 23, 2016, the Air Pollution Control Division will begin a 30-day public notice period for DCP Midstream, LP - Greeley Natural Gas Processing Plant. 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 beginning of the public notice period. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health Et Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, ., ) �® H Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure 2016-1156 /10(Q 4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe John W. Hickenlooper, Governor , Larry Wolk,MD,MSPH, Executive Director and Chief Medical Officer *.; CopHE Air Pollution Control Division 171 Co Notice of a Proposed Project or Activity Warranting Public Comment Website Title: DCP Midstream, LP - Greeley Natural Gas Processing Plant - Weld County Notice Period Begins: March 23, 2016 Notice is hereby given that an application for a proposed project or activity has been submitted to the Colorado Air Pollution Control Division for the following source of air pollution: Applicant: DCP Midstream, LP Facility: Greeley Natural Gas Processing Plant Natural gas processing plant SW Section 25, T5N, R66W Weld County The proposed project or activity is as follows: Natural gas processing plant modifying an existing EG glycol dehydrator and permitting a plant flare to handle maintenance and malfunction emissions. The Division has determined that this permitting action is subject to public comment per Colorado Regulation No. 3, Part B, Section III.C due to the following reason(s): • the source is requesting a federally enforceable limit on the potential to emit in order to avoid other requirements The Division has made a preliminary determination of approval of the application. A copy of the application, the Division's analysis, and a draft of Construction Permit 15WE0939 have been filed with the Weld County Clerk's office. A copy of the draft permit and the Division's analysis are available on the Division's website at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices The Division hereby solicits submission of public comment from any interested person concerning the ability of the proposed project or activity to comply with the applicable standards and regulations of the Commission. The Division will receive and consider written public comments for thirty calendar days after the date of this Notice. Any such comment must be submitted in writing to the following addressee: Stephanie Spector Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 cdphe.commentsapcd@state.co.us 1 ::,.__,..,:„,, „ 4, , ., , . STATE OF COLORADO COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT p AIR POLLUTION CONTROL DIVISION ,75' ` _.,,,.% TELEPHONE: (303)692-3150 * � _n **/876*r CONSTRUCTION PERMIT PERMIT NO: 1 5YY E0939 Issuance 1 DATE ISSUED: ISSUED TO: DCP Midstream, LP THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Oil and gas facility, known as the Greeley Natural Gas Processing Plant, located in the SW of Section 25, Township 5 North, Range 66 West, in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: Facility AIRS Equipment Point Description ID One (1) Ethylene Glycol (EG) natural gas dehydration unit (make, model, serial number: not submitted) with a design capacity of 33.0 MMscf per day. This emissions unit is equipped with one (1) primary and one (1) backup Kerr-Model KZ-3150, electric-glycol pump with a limited capacity of 6 gallons per minute. This unit is P-130 111 equipped with a flash tank, reboiler and still vent. Emissions from the flash tank are routed to a vapor recovery unit (VRU). During VRU downtime (maximum 5% annual downtime), emissions from the flash tank are routed to the enclosed combustor. Emissions from the still vent are routed directly to the enclosed combustor (maximum 5% annual downtime). Flare 122 Plant flare with a destruction efficiency of 95% to handle maintenance and malfunction emissions. 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: REQUIREMENTS TO SELF-CERTIFY FOR FINAL AUTHORIZATION 1. YOU MUST notify the Air Pollution Control Division (the Division) no later than fifteen days of the latter of commencement of operation or issuance of this permit, l submitting a Notice of Startup form to the Division. The Notice of Startup form may be downloaded online at https://www.colorado.gov/pacific/cdphe/other-air-permittinq-notices. Failure to notify the Division of startup of the permitted source is a violation of Air Quality AIRS ID: 123/0099 Page 1 of 13 Dehy SM/M Version 2012-1 C. •:.do I p o' Public Health and Environment A , Air Pollution Control Division Control Commission (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) of the latter of commencement of operation or issuance of this permit, compliance with the conditions contained in this permit shall be demonstrated to the Division. It is the owner or operator'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 following information shall be provided to the Division within fifteen (15)days of the latter of commencement of operation or issuance of this permit. • manufacturer • model number • serial number This information shall be included with the Notice of Startup 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 AIRS Pounds per Month Emission Type Equipment ID Point NO„ VOC CO P-130 111 --- 34 --- Point (Note: Monthly limits are based on a 31-day month.) The owner or operator shall calculate monthly emissions based on the calendar month. Annual Limits: Facility AIRS Tons per Year Emission Type AIRS ID: 123/0099 Page 2 of 13 C do E ?p rthi ft o Public Health and Environment Air Pollution Control Division Equipment ID Point NO„ VOC CO P-130 111 --- 0.2 --- Point Flare 122 2.6 19.8 11.4 Point See"Notes to Permit Holder"for information on emission factors and methods used to calculate limits. During the first twelve (12) months of operation, compliance with both the monthly and annual emission limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is required. Compliance with the annual limits 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 twelve (12) month total. By the end of each month a new twelve-month total shall be calculated based on the previous twelve months' data. The permit holder shall calculate emissions each month 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 permitted emission units, requiring an APEN, at this facility. 8. 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, VRU downtime 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. 9. The emission points in the table below shall be operated and maintained with the control equipment as listed in order to reduce emissions to less than or equal to the limits established in this permit (Reference: Regulation No.3, Part B, Section III.E.) Facility AIRS Pollutants Equipment Point Control Device Controlled ID Flash Tank:Vapor recovery unit(VRU). During VRU P-130 111 downtime, emissions are controlled by an enclosed VOC and HAPS corn bustor. P-130 111 Still Vent: Enclosed combustor. VOC and HAPS Flare 122 Open flare VOC and HAPS 10. Point 111: 95% of emissions that result from the flash tank associated with this dehydrator shall be recycled and recompressed. Maximum of 5% downtime from the flash tank associated with this dehydrator shall be routed to the enclosed combustor. PROCESS LIMITATIONS AND RECORDS 11. 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 owner or operator and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, II.A.4) Process/Consumption Limits Facility AIRS Process Parameter Annual Monthly Limit Equipment Point Limit (31 days) AIRS ID: 123/0099 Page 3 of 13 mss: C• :do I -p = o Public Health and Environment Air Pollution Control Division ID P-130 111 Natural gas throughput 12,045 1023 MMscf/yr MMscf/month Flare 122 Natural gas volume 55.91 MMscf/yr The owner or operator shall calculate monthly process rates based on the calendar month. During the first twelve (12) months of operation, compliance with both the monthly and annual throughput limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is required Compliance with the annual throughput 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 throughput each month and keep a compliance record on site or at a local field office with site responsibility, for Division review. 12. Point 111: This unit shall be limited to the maximum lean glycol circulation rate of 6.0 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) STATE AND FEDERAL REGULATORY REQUIREMENTS 13. The permit number and AIRS ID point number (e.g. 123/4567/890) shall be marked on the subject equipment for ease of identification. (Reference: Regulation Number 3, Part B, III.E.) (State only enforceable) 14. 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. Emission control devices subject to Regulation 7, Sections XII.C.1.d orXVIl.B.2.b shall have no visible emissions. (Reference: Regulation No. 1, Section II.A.1. &4.) 15. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable) 16. Point 111: 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. 17. Point 111: This equipment is subject to the control requirements for glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State only enforceable). a. 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. b. Beginning May 1, 2015, 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 95 percent on a rolling twelve-month basis through the use of air pollution control AIRS ID: 123/0099 Page 4 of 13 t 111 C do p o Public Health and Environment Air Pollution Control Division equipment. If a combustion device is used, it shall have a design destruction efficiency of at least 98% for hydrocarbons. This source shall comply with all applicable general provisions of Regulation 7, Section XVII. 18. Point 111: The flare 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. 19. Point 122: The Division has determined this flare shall comply with the New Source Performance Standards requirements of Subpart A Section §60.18, General Control Device and Work Practice Requirements, including, but not limited to, the following: a. §60.18(b) Flares. Paragraphs (c) through (f) apply to flares. b. §60.18(c)(1) Flares shall be designed for and operated with no visible emissions as determined by the methods specified in paragraph (f), except for periods not to exceed a total of 5 minutes during any 2 consecutive hours. c. §60.18(c)(2) Flares shall be operated with a flame present at all times, as determined by the methods specified in paragraph (f). d. §60.18(c)(3) An owner/operator has the choice of adhering to either the heat content specifications in paragraph (c)(3)(ii) of this section and the maximum tip velocity specifications in paragraph (c)(4) of this section, or adhering to the requirements in paragraph (c)(3)(i) of this section. 1.a.i.1.1.1.1 §60.18(c)(3)(i)(A) Flares shall be used that have a diameter of 3 inches or greater, are nonassisted, have a hydrogen content of 8.0 percent (by volume), or greater, and are designed for and operated with an exit velocity less than 37.2 m/sec (122 ft/sec) and less than the velocity, Vmax, as determined by the following equation: Vmax= (XH2-K1)* K2 Where: Vmax= Maximum permitted velocity, m/sec. K1 = Constant, 6.0 volume-percent hydrogen. K2 = Constant, 3.9(m/sec)/volume-percent hydrogen. XH2=The volume-percent of hydrogen, on a wet basis, as calculated by using the American Society for Testing and Materials (ASTM) Method D1946-77. (Incorporated by reference as specified in§60.17). (ii) §60.18(c)(3)(i)(B) The actual exit velocity of a flare shall be determined by the method specified in paragraph (f)(4) of this section. (iii) §60.18(c)(3)(ii) Flares shall be used only with the net heating value of the gas being combusted being 11.2 MJ/scm (300 Btu/scf) or greater if AIRS ID: 123/0099 Page 5 of 13 C. 1 :do ir -p. o Public Health and Environment 11, Air Pollution Control Division the flare is steam-assisted or air-assisted; or with the net heating value of the gas being combusted being 7.45 MJ/scm (200 Btu/scf) or greater if the flare is nonassisted. The net heating value of the gas being combusted shall be determined by the methods specified in P paragraph (f)(3) of this section. e. §60.18(c)(5)Air-assisted flares shall be designed and operated with an exit velocity less than the velocity, V,,ax, as determined by the method specified in paragraph (f)(6). f. §60.18(c)(6) Flares used to comply with this section shall be steam-assisted, air- assisted, or nonassisted. g. §60.18(d) Owners or operators of flares used to comply with the provisions of this subpart shall monitor these control devices to ensure that they are operated and maintained in conformance with their designs. Applicable subparts will provide provisions stating how owners or operators of flares shall monitor these control devices. h. §60.18(e) Flares used to comply with provisions of this subpart shall be operated at all times when emissions may be vented to them. i. §60.18(f)(1) Method 22 of appendix A to this part shall be used to determine the compliance of flares with the visible emission provisions of this subpart. The observation period is 2 hours and shall be used according to Method 22. j. §60.18(f)(2) The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent device to detect the presence of a flame. k. §60.18(f)(3) The net heating value of the gas being combusted in a flare shall be calculated using the following equation: n HT - K t CiMi f=1 Where: HT = Net heating value of the sample, MJ/scm; where the net enthalpy per mole of offgas is based on combustion at 25 °C and 760 mm Hg, but the standard temperature for determining the volume corresponding to one mole is 20 °C; K = Constant. 7 ` 1 1 {g mole} { MJ ) 1.740 x 10- ppm scm +TccaT were the standard temperature for {g mole) is 20°C; scm C; = Concentration of sample component i in ppm on a wet basis, as measured for organics by Reference Method 18 and measured for hydrogen and carbon monoxide by ASTM D1946-77 or 90 (Reapproved 1994) (Incorporated by reference as specified in §60.17); and H,= Net heat of combustion of sample component i, kcal/g mole at 25°C and 760 mm Hg. The heats of combustion may be determined using ASTM D2382-76 or 88 or D4809-95 (incorporated by reference as specified in §60.17) if published values are not available or cannot be calculated. AIRS ID: 123/0099 Page 6 of 13 1i 10 • C do p t ofi Public Health and Environment Air Pollution Control Division I. §60.18(f)(4) The actual exit velocity of a flare shall be determined by dividing the volumetric flowrate (in units of standard temperature and pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross sectional area of the flare tip. m. §60.18(f)(5) The maximum permitted velocity, Vmax, for flares complying with paragraph (c)(4)(iii) shall be determined by the following equation. Logic) (Vmax)=(HT+28.8)/31.7 Vmax= Maximum permitted velocity, M/sec 28.8=Constant 31.7=Constant HT = The net heating value as determined in paragraph (f)(3). n. §60.18(f)(6) The maximum permitted velocity, Vmax, for air-assisted flares shall be determined by the following equation. Vmax= 8.706+0.7084 (HT) Vmax= Maximum permitted velocity, m/sec 8.706=Constant 0.7084=Constant HT = The net heating value as determined in paragraph (f)(3). OPERATING & MAINTENANCE REQUIREMENTS 20. Upon issuance of this permit, the owner or operator shall follow the most recent 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 21. Point 111: The owner or operator shall demonstrate compliance with opacity standards, using EPA Method 22 to determine the presence or absence of visible emissions. "Visible Emissions" means observations of smoke for any period or periods of duration greater than or equal to one (1) minute in any fifteen (15) minute period during normal operation. (Reference: Regulation No. 7, Section XVII.A.II) 22. Point 111: 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.) 23. Point 111: A source initial compliance test shall be conducted on emissions point 111 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 AIRS ID: 123/0099 Page 7 of 13 il C.,• :do i -p. o Public Health and Environment I Air Pollution Control Division 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) Volatile Organic Compounds using EPA approved methods. 24. Point 122:The operator shall complete an initial site specific extended gas analysis within one hundred and eighty days (180) after commencement of operation or issuance of this permit, whichever comes later, of the natural gas routed to this emissions unit in order to verify the VOC, benzene, toluene, ethylbenzene, xylenes, n-hexane, and 2,2,4- trimethylpentane content(weight fraction)of this emission stream and using volume from the flare meter along with a 95% DRE to demonstrate compliance with emission limits. Results of testing shall be used to calculate site-specific emission factors for the pollutants referenced above(in units of TPY emission limit) using Division approved methods. Results of site-specific sampling and emissions factor analysis shall be submitted to the Division as part of the self-certification and demonstrate the emissions factors established through this initial testing are less than or equal to, the emissions factors established in the permit application and "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this sampling and analysis is greater than the emissions factors established in the permit application and "Notes to Permit Holder"the operator shall submit to the Division within 60 days, a request for permit modification to update emissions factors and emissions limits specified in this permit. 25. Point 122: The owner or operator shall demonstrate compliance with opacity standards using EPA Method 9 to measure opacity from the flare. (Reference: Regulation No. 1, Section II.A.5). Periodic Testing Requirements 26. Point 111: The owner or operator shall complete an extended wet gas analysis prior to the inlet of the EG 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. 27. Point 111: The owner or operator shall demonstrate compliance with opacity standards, using EPA Method 22 to determine the presence or absence of visible emissions per the frequency required in the O&M Plan. "Visible Emissions" means observations of smoke for any period or periods of duration greater than or equal to one (1) minute in any fifteen (15) minute period during normal operation. (Reference: Regulation No. 7, Section XVII.A.II) 28. Point 122: On an annual basis, the operator shall complete a site specific extended gas analysis of the natural gas routed to this emissions unit in order to verify the VOC content (weight fraction) of this emission stream and using volume from the flare meter along with a 95% DRE to demonstrate compliance with emission limits. Results of testing shall be used to calculate site-specific emission factors for the pollutants referenced above (in units of TPY permit limit) using Division approved methods. Emission factors established through this periodic testing shall be less than or equal to, the emissions factors established in the permit application and "Notes to Permit Holder" for this emissions point. If the site specific emissions factor developed through this sampling and analysis is greater than the emissions factor established in the permit application and "Notes to Permit Holder"the operator shall submit to the Division within 60 days, a request for permit modification to update emissions factors and emissions limits specified in this permit. The owner or operator shall continue to use the emissions factors established in the permit application and"Notes to Permit Holder" to calculate actual emissions and demonstrate compliance with the emissions limits specified in this permit unless a modification is submitted to the Division. Records of site-specific AIRS ID: 123/0099 Page 8 of 13 Co T,do par'tfnet or Public Health and Environment Air Pollution Control Division sampling and emissions factor analysis shall be recorded and maintained by the operator and made available to the Division for inspection upon request. ADDITIONAL REQUIREMENTS 29. A revised Air Pollutant Emission Notice(APEN)shall be filed: (Reference: Regulation No. 3, Part A, II.C) a. Annually by April 30th 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 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. 30. This source is subject to the provisions of Regulation No. 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 the issuance of this permit. GENERAL TERMS AND CONDITIONS 31. 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. 32. 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. AIRS ID: 123/0099 Page 9 of 13 C.�:do I p =i o Public Health and Environment Air Pollution Control Division 33. This permit is issued in reliance upon the accuracy and completeness of information supplied by the owner or operator 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 owner or operator or owner or operator's agents. It is valid only for the equipment and operations or activity specifically identified on the permit. 34. 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. 35. 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 owner or operator, or the Division revokes a permit, the owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 36. 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. 37. 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 Spector, PE Permit Engineer Permit History Issuance Date Description Issuance 1 This Issuance Issued to DCP Midstream, LP. Modification to EG dehydrator(on Title V permit 95OPWE038) and addition of a permittable plant flare. Source at a major facility. AIRS ID: 123/0099 Page 10 of 13 C. p o 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 maybe revised upon request of the owner or operator 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 complete 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 owner or operator 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: https://www.colorado.gov/pacific/cdphe/aqcc-regs 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. Uncontrolled Emission Are the Controlled AIRS Rate emissions Emission Point Pollutant CAS# (Ib/yr) reportable? Rate(Ib/yr) Benzene 71432 953 Yes 101 Toluene 108883 46 No 5 111 Ethylbenzene 100414 2 No Xylenes 1330207 32 No 4 n-hexane 110543 48 No 2 Benzene 71432 2379 Yes 119 Toluene 108883 2049 Yes 102 Ethyl benzene 100414 32 No 2 122 Xylenes 1330207 372 Yes 19 N-hexane 110543 11749 Yes 591 2,2,4-TMP 540841 16 No 1 5) The emission levels contained in this permit are based on the following emission factors: Point 111: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Point 122: Emission Emission CAS# Pollutant Factors Factors Source Uncontrolled Controlled AIRS ID: 123/0099 Page 11 of 13 C. : :do p o Public Health and Environment ' Air Pollution Control Division NOx 92.0 Ib/MMscf --- Engineering Calculation CO 406.0 Engineering Calculation ___ lb/MMscf VOC 14183 709 lb/MMscf Engineering Calculation lb/MMscf 71432 Benzene 42.551 2.1275 Engineering Calculation lb/MMscf lb/MMscf 108883 Toluene 36.648 1.8324 Engineering Calculation lb/MMscf lb/MMscf 100414 Ethylbenzene 0.572 0.0286 Engineering Calculation lb/MMscf lb/MMscf 1330207 Xylenes 6.654 0.3327 Engineering Calculation lb/MMscf lb/MMscf 110543 n-hexane 210.141 10.5071 Engineering Calculation Ib/MMscf lb/MMscf 540841 2,2,4-TMP 0.286 0.0143 Engineering Calculation Ib/MMscf lb/MMscf Note: The uncontrolled VOC and HAP emissions for this point were calculated using the December 19,2014 analysis of a gas sample collected from the Greeley Gas Plant.The controlled VOC and HAP emissions factors for point 003 are based on the flare control efficiency of 95%. 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 Status Requirement Operating Permit Major Source of: NOx, CO, VOC NANSR Major Source of: NOx, VOC PSD Synthetic Minor Source of: CO MACT HH Area Source Requirements: Not Applicable 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 KKKK 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 AIRS ID: 123/0099 Page 12 of 13 I 77'1 ) Cotdo p rmet of Public Health and Environment Air Pollution Control Division 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 9) A self certification form and guidance on how to self-certify compliance as required by this permit may be obtained online at: http://www.colorado.gov/pacific/cdphe/air-permit self certification AIRS ID: 123/0099 Page 13 of 13 Construction Permit Application Preliminary Analysis Summary Section 1 —Applicant Information Company Name: DCP Midstream, LP Permit Number: 15WE0939 Source Location: Greeley Natural Gas Processing Plant SW Section 25,T5N, R66W, Weld County (non-attainment) Equipment Description: EG dehydrator AIRS ID: 123-0099-111 Date: October 15, 2015 Review Engineer: Stephanie Spector, PE Control Engineer: Chris Laplante Section 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? X Yes No If you answered "no" to any of the above, when did you mail an See Section 14 Information Request letter to the source? On what date was this application complete? May 4, 2015 Section 4—Source Description AIRS Point Equipment Description One (1) Ethylene Glycol (EG) natural gas dehydration unit (make, model, serial number: not submitted)with a design capacity of 33.0 MMscf per day. This emissions unit is equipped with one (1) primary and one (1) backup Kerr-Model KZ-3150, electric-glycol 111 pump with a limited capacity of 6 gallons per minute. This unit is equipped with a flash tank, reboiler and still vent. Emissions from the flash tank are routed to a vapor recovery unit (VRU). During VRU downtime (maximum 5% annual downtime), emissions from the flash tank are routed to the enclosed combustor. Emissions from the still vent are routed directly to the enclosed combustor(maximum 5% annual downtime). Is this a portable source? Yes X No Is this location in a non-attainment area for any criteria Yes No pollutant? If"yes", for what pollutant? PM,() CO X Ozone Is this location in an attainment maintenance area for Yes X No any criteria pollutant? If"yes", for what pollutant? (Note: These pollutants are subject to minor source PM,o CO Ozone RACT per Regulation 3, Part B, Section III.D.2) Page 1 Is this source located in the 8-hour ozone non- attainment region? (Note: If"yes" the provisions of X Yes No Regulation 7, Sections XII and XVII.C may apply) Section 5—Emission Estimate Information AIRS Point Emission Factor Source 111 GRI Gly-Calc v4.0 (Refer to Section 14 for calculations) Did the applicant provide actual process data for the emission inventory? X Yes No Basis for Potential to Emit(PTE) AIRS Point Process Consumption/Throughput/Production 111 12,045 MMSCF per year, 6.0 gallons per minute glycol circulation rate Basis for Actual Emissions Reported During this APEN Filing (Reported to Inventory) AIRS Point Process Consumption/Throughput/Production Data Year 111 12,045 MMSCF per year, 6.0 gallons per minute glycol circulation rate 2014 Basis for Permitted Emissions(Permit Limits) AIRS Point Process Consumption/Throughput/Production 111 12,045 MMSCF per year, 6.0 gallons per minute glycol circulation rate Does this source use a control device? X Yes No %Reduction AIRS Point Process Control Device Description Granted 111 01 Flash tank:VRU 100 111 02 Still vent: Combustor 95 Section 6—Emission Summary (tons per year) Point NO, VOC CO Single HAP Total HAP PTE: 111 0.1 6.5 0.7 0.5 (benzene) 0.5 Uncontrolled point 111 0.1 6.5 0.7 0.5 (benzene) 0.5 source emission rate: Controlled point 111 0.1 0.2 0.7 0.02 (benzene) 0.03 source emission rate: Section 7—Non-Criteria/Hazardous Air Pollutants Uncontrolled Are the Controlled Emission Pollutant CAS# BIN Emission Rate emissions (lb/yr) reportable? Rate(lb/yr) Benzene 71432 A 953 Yes 48 Toluene 108883 C 46 No 2 Ethylbenzene 100414 C 2 No --- Xylenes 1330207 C 32 No 2 n-Hexane 110543 C 48 No 2 Note: Regulation 3, Part A, Section II.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 X Yes No standard? Page 2 If"yes", complete the information listed below AIRS Point Process Pollutant Regulatory Basis Test Method 111 01 VOC, Regulation No. 3, Part B, Section III.E Extended gas HAPS analysis (periodic) Section 9-Source Classification On Title V permit Is this a new previously un-permitted source? Yes X No 95OPWE038 What is this facility classification? True Synthetic X Major Minor Minor Classification relates to what programs? X Title V PSD X NA NSR MACT Is this a modification to an existing permit? Yes X No Section 10—Public Comment Does this permit require public comment per CAQCC Regulation 3? Yes X No If"yes", for which pollutants?Why? For Reg. 3, Part B, III.C.1.a (emissions increase > 25/50 tpy)? Yes X No For Reg. 3, Part B, III.C.1.c.iii (subject to MACT)? Yes X No For Reg. 3, Part B, III.C.1.d (synthetic minor emission limits)? Yes X No Section 11 —Modeling Is modeling required to demonstrate compliance with National Ambient Yes X No Air Quality Standards(NAAQS)? AIRS Point Section 12— Regulatory Review Regulation 1 - Particulate, Smoke, Carbon Monoxide and Sulfur Dioxide 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 111 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. Regulation 2—Odor 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 111 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 Part A-APEN Requirements 111 Applicant is required to file an APEN since emissions exceed 1 ton per year VOC in a nonattainment area for ozone. Part B—Construction Permit Exemptions 111 Applicant is required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 2.0 TPY threshold(Reg. 3, Part B, Section ll.D.2.a) Regulation 6- New Source Performance Standards 111 None Page 3 Regulation 7—Volatile Organic Compounds Is this source subject to the control requirements of MACT HH? (Regulation 8-Hazardous 111 Air Pollutants review). No This source is subject to review for the Regulation 7 control requirements. Section XII.H: Is this source located in the non-attainment area? Yes 111 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. Section XVII.D (State only enforceable). 111 Applicant is required to reduce VOC emissions from this dehydrator by at least 95% since uncontrolled VOC emissions are greater than the 6.0 TPY threshold. Regulation 8—Hazardous Air Pollutants 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.ls facility a production field facility per 63.761 (Refer to Section 14 for definition)? No 111 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.Is this source subject to MACT HH? No 5.WHY? This facility is an area source of HAP. No area source requirements of HH apply to this EG or DEG dehydrator. Section 13—Aerometric Information Retrieval System Coding Information Point Process Process Throughput Emission Pollutant/ Fugitive Emission Control Description limit Factor CAS# (Y/N) Factor Source (°/0) 1.0714 VOC No GlyCalc 4.0 95 lbs/mmscf 0.0791 Benzene/ No GlyCalc 4.0 95 lbs/mmscf 71432 00038 Toluene/ 12,O45 Glycolsmmsc 01 MMSCF per 111 Dehydrator 0.0002 Ethylbenzeneyear No GlyCalc 4.0 95 lbs/mmscf / 100414 0.0027 Xylenes/ No GlyCalc 4.0 95 lbs/mmscf 1330207 0.0040 n-Hexane/ No GlyCalc 4.0 95 lbs/mmscf 110543 SCC 31000304-Glycol Dehydrators: Ethylene glycol: general Page 4 Section 14—Miscellaneous Application Notes AIRS Point 111 Glycol Dehydrator This application is for a modification to an existing EG dehydrator. This dehydrator is on operating permit(Title V) 95OPWE038, so this modification will issue a separate construction permit number. It will eventually be incorporated back into the operating permit. I emailed the operator on 10/19/2015: I am working on the modification of the EG dehydrator at the Greeley Natural Gas Processing Plant and have a question for you. The APEN is saying that this is Point 121 at the facility. However, the 102 form does not have a Point 121. I checked our database and should this modification be for Point 111? Please clarify for me when you have an opportunity. She replied on 10/21/2015: You're absolutely right, it's AIRS Point 111. Sorry about that, it's probably a carry-over from the other Reg 7 applications we submitted at the same time! Also, I wanted to submit some information on the flare at Greeley which will possibly require the flare to be a permitted source. I am assembling the application and should have it ready to go soon. I would like to find out if you think I can submit during your review of this modification application! I put the application on hold until I received the calculations from the flare. I received them via mail mid-December 2015 but was not able to get back onto the application until late January 2016. In order to determine emissions,the operator used GRI GlyCALC 4.0. The source assumed the inlet gas temperature of 95°F and pressure of 800 psig. The permitted glycol recirculation rate is 6.0 gallons per minute. The GlyCalc model was based off of an extended gas analysis dated 12/19/2014. The gas analysis was perfomed less than a year of submittal. An updated extended gas analysis will not be required because an extended gas analysis was performed within a year of this submittal and included with this package. Gly-Calc-Uncontrolled Emission factors VOC =((1.5436+4.9090)2000)/(33'365) = 1.0714 lb/mmscf Benzene=((0.4326+0.044)"2000)/(33'365) =0.0791 lb/mmscf Toluene=((0.0212+0.0016)'2000)/(33`365) =0.0038 Ib/mmscf Ethylbenzene=((0.0011+0.0001)2000)/(33*365) =0.0002 Ib/mmscf Xylenes=((0.0154+0.0006)*2000)/(33*365) =0.0027 lb/mmscf N-hexane= ((0.0089+0.0152)*2000)/(33*365) =0.0040 Ib/mmscf MACT HH indudes 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. 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. Based on the definitions above, this source qualifies as a natural gas processing plant. Does this dehydrator have a reboiler?Yes If Yes, what is the reboiler rated? 4.6 mmbtu/hr The source has a design rate less than 5 mmbtu/hr, it is APEN-exempt(Regulation No. 3, Part A, II.D.1.k), and is therefore also exempt from construction permitting requirements(Regulation no. 3, Part B, II.D.1.a). Criteria pollutant emission levels for this unit are based on factors from AP-42, Chapter 1.4, Small Boilers< 100 MMBtu/hr(7/1998). Page 5 AIRS Point 111 Glycol Dehydrator(continued) Operator provided comments on draft permit prior to public comment. My responses to the comments are in italics: 1. Page 1, Equipment Description for P-130—Please reflect the 5%downtime requested and as shown on the emission limits in the description of this unit as follows:One(1)Ethylene Glycol(EG)natural gas dehydration unit(make,model,serial number:not submitted)with a design capacity of 33.0 MMscf per day.This emissions unit is equipped with one(1)primary and one(1) backup Kerr-Model KZ-3150,electric-glycol pump with a docign limited capacity of 6 gallons per minute.This unit is equipped with a flash tank,reboiler and still vent.Emissions from the flash tank are routed to a vapor recovery unit(VRU). During VRU downtime(maximum 5%annual downtime),emissions from the flash tank are routed to the enclosed combustor.Emissions from the still vent are routed directly to the enclosed combustor(maximum 5%annual downtime). /have made these changes to the permit. 2. Page 2,Condition 7—DCP would like to request only annual limits for the Flare,AIRS Point 122.This is because the flare is meant to handle maintenance and malfunction emissions that don't follow a monthly schedule. For example,during a planned shutdown the Flare will see a lot more emissions for that month than during normal day-to-day operation. This could be problematic because the Flare may be out of compliance with a monthly limit but will still be in compliance with an annual limit. This makes sense;I will remove the monthly requirements for the flare from the permit condition. 3. Page 3,Condition 8—Unsure why this condition is included on this permit. Usually we see such a condition for construction permits that are facility-wide permits and are syn minor. Since the Greeley gas plant is a major source and has a Title V permit, tracking insignificant activities is already a requirement(also why is the requirement to remain below 250 tpy of criteria pollutants?)You are right;the facility is already major so insignificant tracking is already required. The 250 TPY limit is the limit to trigger PSD for CO. So the condition means to track insignificant and if it is over 250 TPY then PSD review would be required. I will remove this condition. 4. Page 3,Condition 10—Point 122 is an"Open Flare",not enclosed. I have made this change to the permit. 5. Page 3,Condition 11—This condition seems out of place. Usually construction permits with multiple AIRS points or source types have subsections under"State and Federal Regulatory Requirements"and this would fit better within a Dehy subcategory. Also note that 95%of flash tank emissions are requested to be recycled with 5%downtime to the enclosed combustor. Typically this is where this condition would be in the permit under"Emission Limits and Records"section if the condition is in the permit. I have modified it though to say: Point 111: 95%of emissions that result from the flash tank associated with this dehydrator shall be recycled and recompressed. Maximum of 5%downtime from the flash tank associated with this dehydrator shall be routed to the enclosed combustor. 6. Page 4,Condition 12—Please rename process parameter for Flare from Natural gas venting to Flare gas volume.I have made this change to the permit. 7. Page 4,Condition 13—Please include AIRS Point 111 at the beginning of this condition to note it's specifically for AIRS Point 111. I have made this change to the permit. 8. Page 4,State and Federal Regulatory Requirements: • Please include current Conditions 14 through 16 as currently included,but also include EG Dehy and Flare categories to include equipment specific regulations. • Please include the Reg 7 combustor specific language into this section as the main point of this application was to install a Reg 7 combustor on the EG dehy to comply with the revisions to Reg 7. /have added the Regulation 7 conditions. • The Flare is subject to 60.18 requirements. Please include language surrounding NSPS flares. /have added a condition for 60.18 requirements. • Please include earlier Condition 11 into the newly created EG Dehy category within this section of the permit. / will leave Condition 11 where it is. Like 1 said,that is typically where that condition is put in permits. 9. Page 4,Condition 17—Please reword Upon startup of these points to Upon issuance of this permit./have made this change to the permit. 10. Page 5—Initial Testing Requirements—there are no initial requirements for Point 111. Please include the requirement to pull an inlet EGA sample,and a Method 22 on the new enclosed combustor. /have added these conditions. It's almost like I wrote the draft for the flare but forgot to add the dehydrator. 11. Page 5,Condition 18—The outlet of the open flare cannot be tested(this is a plant open flare). As presented in the calculations, the intent is to pull an inlet EGA and use volume from the flare meter along with a 95%DRE to demonstrate compliance with emission limits. Please revise this condition and subsequently Condition 21 to allow for this method of compliance. /have modified these conditions. 12. Page 5—Periodic Testing Requirements—Please include periodic Method 22 on the enclosed combustor at the frequency specified on the O&M plan. Please feel free to look at Permit 10WE1659 Iss 5 for reference. Condition has been added to the permit. 13. Page 8, Notes to Permit Holder#4—Please remove"BIN"column from this table. Also,please revise the following HAP controlled emissions to match the permit application:Benzene 101 Ib/yr,Toluene 5 lb/yr,Xylenes 4 lb/yr. Please also add"n-" ahead of Hexane./have made these changes. 14. Page 9, Notes to Permit Holder#7—Under NANSR,please remove CO as a pollutant since this area is not non-attainment for CO. I have added another column that is for PSD and listed CO as synthetic minor. Page 6 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Division Information Engineer: Stephanie Spector, PE Attainment Status Control Engineer Chris Laplantel PM10 Attainment Review Date: 01/25/2016 PM2.5 Attainment Application Date: 12/15/2015 SOx Attainment NOx Nonattainmen VOC Nonattainmen Facility Information CO Attainment Permit No. 15WE0939 County# 123 Weld AIRs Facility# 0099 Point# 122 Facility Equipment ID Flare Company Name: DCP Midstream,LP Source Name: Greeley Natural Gas Processing Plant Source Location: SW 1/4 Section 25,T5N, R66W SIC: 1321 Elevation(feet)4691 New Permit Modification APEN X (CPI) (Issuance#) Required/Permit Exemot Transfer of APEN Ownership Exempt/Permit Exemot Equipment Description This source vents natural gas from: qas plant maintenance and malfunctions Emissions from this source are: routed to an open-flame flare Natural gas venting from gas plant maintenance and malfunctions. Emissions from this source are routed to an open-flame flare. Emission Calculation Method EPA Emission Inventory Improvement Program Publication:Volume II,Chapter 10-Displacement Equation(10.4-3) Ex=Q*MW*Xx/C Ex=emissions of pollutant x Q=Volumetric flow rate/volume of gas processed MW=Molecular weight of gas=SG of gas*MW of air Xx=mass fraction of x in gas C=molar volume of ideal gas(379 scf/lb-mol)at 60F and 1 atm Throughput(Q) 55.91 MMscf/yr I 6382.4 scf/hr 4.75 MMscf/mo MW 21.940 Ib/Ib-mol 0.001 MMscf/d mole% MW Ibx/lbmol mass fraction E lb/hr lb/yr tpy Helium 0 4.0026 0.000 0.000 Helium 0.0 0 0.00 CO2 2.53 44.01 1.113 0.051 CO2 18.8 164256 82.13 N2 0.21 28.013 0.059 0.003 N2 1.0 8678 4.34 methane 75.3452 16.041 12.086 0.551 methane 203.5 1782942 891.47 ethane 12.5156 30.063 3.763 0.171 ethane 63.4 555053 277.53 propane 5.3901 44.092 2.3766 0.108 propane 40.0 350596 175.30 isobutane 0.8511 58.118 0.4946 0.023 isobutane 8.3 72970 36.48 n-butane 1.793 b8.118 1.0421 0.04/ n-butane 1/.5 163/24 76.86 isopentane 0.4746 72.114 0.3423 0.016 isopentane 5.8 50489 25.24 n-pentane 0.4634 72.114 0.3342 0.015 n-pentane 5.6 49298 24.6b cyclopentane 0.0176 70.13 0.0123 0.001 cyclopentane 0.2 1821 0.91 n-Hexane 0.0926 86.18 0.0798 0.004 n-Hexane 1.3 11772 5.89 cyclohexane 0.0205 84.16 0.0173 0.001 cyclohexane 0.3 2545 1.27 Other hexanes 0.1732 86.18 0.1493 0.007 Other hexanes 2.5 22019 11.01 heptanes 0.0554 100.21 0.0555 0.003 heptanes 0.9 8190 4.09 methylcyclohexane 0.0152 98.19 0.0149 0.001 methylcyclohexane 0.3 2202 1.10 224-TMP 0.0001 114.23 0.0001 0.000 224-TMP 0.0 17 0.01 Benzene 0.0207 78.12 0.0162 0.001 Benzene 0.3 2386 1.19 Toluene 0.0151 92.15 0.0139 0.001 Toluene 0.2 2053 1.03 Ethylbenzene 0.0002 106.17 0.0002 0.000 Ethylbenzene 0.0 31 0.02 Xylenes 0.0024 106.17 0.0025 0.000 Xylenes 0.0 376 0.19 C8+Heavies 0.0139 -235.701 -0.0328 -0.001 C8+Heavies -0.6 -4833 -2.42 VOC mass fraction: 0.2242 Total VOC Emissions(Uncontrolled) 362.8 21.940 annual limit assuming 95%control 18.1 monthly limit assuming 95%control(lb/mo.) 3081.5 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Notes Mole%,MW,and mass fractions from Greeley Gas Plant gas analysis collected 12/19/14. Operator conservatively increased permitted VOC wt% Emissions are based on 8760 hours of operation per year. from 22.59 to 24.5%to allow for inlet EGA variance. This I calculated the average MW of C8+based on the average MW on the analysis for the gas.is about a 1.08455%increase so I will multiply the uncontrolled VOC emissions by 1.08455%to see if I get Flaring Information what the operator provided on the APEN. I calculated Equipment Description 393.5 TPY uncontrolled VOC(19.7 TPY controlled). The APEN shows 396.49 TPY uncontrolled and 19.8 TPY Manufacturer John Zink controlled. I am assuming this could be due to some Model EEF Series rounding throughput the calculation process. I will accept Serial Number 9027692 the operator's emission requests. Gas Heating Value 1300 Btu/scf Throughput 72683 MMBtu/yr Potential fuel usage 2.01 MMscf/yr Combustion emission factor source for combustion: AP-42:Chapter 1.4 100 lb NOX/MMscf 84 lb CO/MMscf 0.1 tpy NOX 0.1 tpy CO Combustion emission factor source: AP-42:Chapter 13.5 0.068 lb NOX/MMBtu 0.31 lb CO/MMBtu 2.5 tpy NOX 11.3 tpy CO Emissions Summary 2.6 tpy NOX Uncontrolled/PTE 11.4 tpy CO 396.5 tpy VOC Controlled 19.8 tpy VOC Operator Operator Uncontrolled uncontrolled Scenario A Controlled Controlled Total(Ib/yr) emissions Reportable? Total(lb/yr) emissions Benzene 2386 2379 Yes 119 119 Toluene 2053 2049 Yes 103 102 Ethylbenzene 31 32 No 2 2 Xylenes 376 372 Yes 19 19 n-hexane 11772 11749 Yes 589 591 224-TMP 17 16 No 1 1 Regulatory Applicability AQCC Regulation 1 This source is subject to the opacity requirements for flares in Section II.A.5:'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.' AQCC Regulation 2 Section I.A applies to all emission sources."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." AQCC Regulation 3 An APEN is required for this source because uncontrolled VOC emissions Part A: exceed one ton per year in a nonattainment area for ozone. A permit is required for this source because uncontrolled VOC emissions from this facility exceed two tons per year in a nonattainment area for ozone. Part B: This source is subject to Section III.D.2(Minor Source RACT)because it is located in a nonattainment area.RACT for this source has been determined to be the use of a flare to control emissions Is public comment Public Comment Required required? AQCC Regulation 7 Was the well newly constructed,hydraulically fractured,or recompleted on or after August 1,2014? No This separator is not subject to Reg 7 Section XVII.G Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Emission Factors for Permit Uncontrolled NOX 92.0 lb/MMscf natural gas vented CO 406.0 lb/MMscf natural gas vented VOC 14183 lb/MMscf natural gas vented Benzene 42.551 Ib/MMscf natural gas vented Toluene 36.648 lb/MMscf natural gas vented Ethylbenzene 0.572 lb/MMscf natural gas vented Xylenes 6.654 lb/MMscf natural gas vented n-Hexane 210.141 lb/MMscf natural gas vented 224-TMP 0.286 lb/MMscf natural gas vented Controlled NOX 92.0 lb/MMscf natural gas vented CO 406.0 lb/MMscf natura gas vented VOC 709 lb/MMscf natura gas vented Benzene 2.1275 b/MMsct natura gas vented I oluene 1.8324 b/MMsct natura gas vented tthylbenzene 0.0286 b/MMsct natura gas vented Xylenes 0.3327 b/MMsct natura gas vented n-Hexane 10.5071 b/MMsct natura gas vented 224-I MP 0.0143 b/MMsct natura gas vented ml d 1 ;, c i: lli oo z o o mmm 8 Ill 0 o o (� (� q ; _ U Q, d �` .o J ` Q v c A Y _' ,--..m r a ❑ ❑ ❑ W U c, z o 0 0 O o o a , a •,- ° o -Q mmm � > O1 1 d o W o .E 0 d 2 0 `.. i ' ` / I ° o N k y o a • on Y o O O 5 O O on U N IQs _ _ N U '� _ C '7 O �' h O �-. �-+ Z 7.--;)' v' o� ! 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C) o v O GG yip y '' .a t 7 ^y co p w E. O O ti t C aN) a8i Z ' .r .o W Z a Q o ,,°.-,' N o v G O C. 04 ,01, c Ca V) o r W •— O� o•.m p ''ll H O ▪ O O T C .~O. a) rr O w .r COx v N emu, 01 `� pU pU, 9 i 7 � ai a) 'Q m ry •c, 6, V v, o Q " S S Ca TA a U 74 Po S a 9 o — `O 0 ' C A p F -5^ p Cl) "It O r-, ,-i - .c. o -o C. O ° L r. 4r . CC a C) .l .. v a O — y — O l0: Q .� v �) Q. n 3 U r a)w 7 U bo O L '� > N •i W 0 w \ t9 Cl) v) w 0. U ,2 b C3 -d W . m a) oin O o C n c c c o I x U a≥ ^x d o o > ai o N j O p O ai °'c iz ( t 5 o U H H ^. o z > c-) a≥ o T T x c L n v) a � t u .. a. co H X ., C ." CDPHE General APEN - Form APCD-200 �. Air Pollutant Emission Notice (APEN) and co Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re-submittal. There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of specialty APENs is available on the Air Pollution Control Division (APCD) website at www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5)years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: .-95-0P-WE038-- 15WEc9 3g AIRS ID Number: 123 /0099/ 122 [Leave blank unless APCD has already assigned a permit#and AIRS ID] Section 1 - Administrative Information Company Name': DCP Midstream, LP Site Name: Greeley Natural Gas Processing Plant Site Location: Site Location SW 1/4 Section 25, T5N, R66W County: Weld NAICS or SIC Code: 1321 Mailing Address: (Include Zip Code) 370 17th St, Suite 2500 Denver, CO Permit Contact: Roshini Shankaran Phone Number: 303-605-2039 Portable Source E-Mail Address: Home Base: RShankaran@dcpmidstream.com 'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD.Any changes will require additional paperwork. A CO1OFcDo Form APCD-2O0 - General APEN - Revision 7/2015 1 ;: 330111 Permit Number: 95OPWE038- 150Em 9 39 AIRS ID Number: 123 /0099/ 12Z [Leave blank unless APCD has already assigned a permit#and AIRS ID] Section 2- Requested Action ❑r NEW permit OR newly-reported emission source(check one below) E STATIONARY source ❑ PORTABLE source -OR- ❑ MODIFICATION to existing permit(check each box below that applies) 0 Change fuel or equipment 0 Change company name ❑ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership2 0 Other(describe below) -OR- ❑ APEN submittal for update only(Please note blank APENs will not be accepted) -ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs)with a federally-enforceable limit on Potential To Emit(PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info£t Notes: Flare with a DRE of 95% to handle maintenance and malfunction emissions. DCP is requesting an annual limit of 55.91 MMscf/yr for the volume of emissions being routed to the flare. 2 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104)must be submitted. Section 3 - General Information General description of equipment and purpose: Plant Flare Manufacturer: John Zink Model No.: EEF Series Serial No.: 9027692 Company equipment Identification No. (optional): Flare For existing sources, operation began on: 2004 For new or reconstructed sources, the projected start-up date is: ❑ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Seasonal use percentage: Dec-Feb: Mar-May: June-Aug: Sept-Nov: COLORADO Form APCD-2OO - General APEN - Revision 7/2015 2 I Permit Number: ,t 8 3$. i5i,,1Eo93c AIRS ID Number: 123 /0099/ l 2:2- [Leave blank unless APCD has already assigned a permit#and AIRS ID] Section 4 - Processing/Manufacturing Information Et Material Use El Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process Actual Annual Requested Annual Description Rate Amount Permit Limit3 (Specify Units) (Specify Units) (Specify Units) Material Consumption: Finished Product(s): 3Requested values will become permit limitations. Requested limit(s)should consider future process growth. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 522877, 4468151 ❑ Check box if the following information is not applicable to the source because emissions will not be emitted from a stack. If this is the case, the rest of this section may remain blank. Discharge Height Operator Temp. Flow Rate Velocity Stack ID No. Above Ground Level (.F) (ACFM) (ft/sec) (Feet) Flare 65 Indicate the direction of the stack outlet: (check one) 0 Upward ❑ Downward ❑ Upward with obstructing raincap ❑ Horizontal ❑ Other (describe): Indicate the stack opening and size: (check one) 0 Circular Interior stack diameter (inches): • ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): coloFtoo Form APCD 200 General APEN Revision 7/2015 3 I �� Permit Number: _gQp.w.E0 I SwE 09 39 AIRS ID Number: 123 /0099/ Zz [Leave blank unless APCD has already assigned a permit#and AIRS ID] Section 6 - Combustion Equipment Et Fuel Consumption Information ❑✓ Check box if this information is not applicable to the source (e.g. there is no fuel-burning equipment associated with this emission source) Design Input Rate Actual Annual Fuel Use Requested Annual Permit Limit3 (MMBTU/hr) (Specify Units) (Specify Units) 0.24, 2.01 MMscf/yr(Fuel only),55.91 MMscf/yr(waste gas) From what year is the actual annual fuel use data? Indicate the type of fuel used4: ❑■ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content: ❑■ Other (describe): 55.91 MMscf/yr(Waste Gas) Heating value (give units): 1300 Btu/scf 3 Requested values will become permit limitations. Requested limit(s)should consider future process growth. 4 If fuel heating value is different than the listed assumed value, please provide this information in the"Other"field. Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ®Yes ❑ No If yes, please describe the control equipment AND state the overall control efficiency(%reduction): Pollutant Control Equipment Description Overall Control Efficiency (%reduction in emissions) TSP (PM) PM10 PM2.5 SO„ NO. CO VOC Flare 95% Other: RECE . COLORADO Form APCD-200 - General APEN - Revision 7/2015 4 I aba� Permit Number: lScJEO434 AIRS ID Number: 123 /0099/ 7_7_ [Leave blank unless APCD has already assigned a permit#and AIRS ID] Section 7(continued) From what year is the following reported actual annual emissions data? N/A Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Emission Uncontrolled Requested uested Annual Permit Factor Actual Annual Emissions 3 Pollutant Emission Emission Limit(s) Source Factor (Specify Units) (AP-42,Mfg. Uncontrolled Controlled5 Uncontrolled Controlled etc) (Tons/year) (Tons/year) (Tons/year) (Tons/year) TSP (PM) PKo PM2.5 SOX NOx 0.068 Ib/MMBtu AP-42 2.58 2.58 CO 0.31 Ib/MMBtu AP-42 11.35 11.35 VOC 14183 Ib/MMscf Mass Balance 396.49 19.83 Other: 3 Requested values will become permit limitations. Requested limit(s)should consider future process growth. 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non-Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non-criteria pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 ® Yes ❑ No lbs/year? If yes, use the following table to report the non-criteria pollutant (HAP) emissions from source: Uncontrolled Uncontrolled Controlled CAS Overall Emission Emission Factor Actual Actual Number Chemical Name Control Factor Source Emissions Emissions5 Efficiency (specify units) (AP-42,Mfg.etc) (lbs/year) (lbs/year) 110-54-3 n-hexane 95% 210.2 lb/MMscf Mass Balance 11,749 591 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. • COLORADO Form APCD-200 - General APEN - Revision 7/2015 5 Permit Number: 1 S w E m 9 39 AIRS ID Number: 123 /0099/ Z2 [Leave blank unless APCD has already assigned a permit 11 and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. \2 /I i./1ZU6 Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name(please print) Title Check the appropriate box to request a copy of the: ❑r Engineer's Preliminary Analysis conducted ❑r Draft permit prior to issuance ❑Q Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5)years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with$152.90 to: For more information or assistance call: Colorado Department of Public Health and Environment Small Business Assistance Program Air Pollution Control Division (303)692-3175 or(303)692-3148 APCD-SS-B 1 4300 Cherry Creek Drive South Or visit the APCD website at: Denver, CO 80246-1530 https://www.colorado.gov/cdphe/apcd Telephone: (303)692-3150 DEC - ?- COLORADO Form APCD-2O0 - General APEN - Revision 7/2015 6 I �� Hello