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Home My WebLink About20191331.tiffCOLORADO Department of Public Health Et Environment Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board 1150 O St PO Box 758 Greeley, CO 80632 March 28, 2019 Dear Sir or Madam: RECEIVED APR 0 2 2019 WELD COUNTY COMMISSIONER On March 28, 2019, the Air Pollution Control Division will begin a 30 -day public notice period for DCP Operating Company, LLC - Lucerne 2. 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, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure 4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe John W. Hickenlooper, Governor ?uc 9- 2)\euD y181kq Larry Wolk, MD, MSPH, Executive Director and Chief Medical Officer CC. PL Cz' P) t1l-CS T) PwCsrvl(F,Rlc.prid )) 141211G 2019-1331 Air Pollution Control Division Notice of a Proposed Project or Activity Warranting Public Comment Website Title: DCP Operating Company, LLC - Lucerne 2 - Weld County Notice Period Begins: March 28, 2019 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 Operating Company, •LLC Facility: Lucerne 2 Natural gas processing plant 31495 Weld County Rd 43 Weld County The proposed project or activity is as follows: DCP is requesting to replace two existing turbines with two new, lower-NOx turbines; adjust the control scenario for the TEG dehy to recycle the still vent instead of routing to a combustor; and add four points (300 bbl produced water tank, 300 bbl methanol tank, pressurized condensate unloading and plant flare) that are existing but previously considered below APEN- thresholds. 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 12WE2024 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. Comments may be submitted using the following options: • Use the web form at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices. This page also includes guidance for public participation • Send an email to cdphe.commentsapcd@state.co.us • Send comments to our mailing address: Carissa Money Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 COLORADO h k Envubrimerti Colorado Air Permitting Project Project Details Review Engineer: Package #: Received Date: Review Start Date: Section 01- Facility Information Carissa.Money 38s6o4 ,, DCP Operating Company, LP Company Name: County AIRS ID: Plant AIRS ID: Facility Name: Physical Address/Location: Type of Facility: What industry segment? Is this facility located in a NAAQS non -attainment area? If yes, for what pollutant? ®Carbon Monoxide (CO) 0107 Lucerne 2'Natural Gas Processor Plant 31384 Weld County Road 43 *Ural Gas Processing Plant E l: n & Production Section 02 - Emissions Units In Permit Application Yes Particulate Matter (PM) Ozone (NOx & VOC) AIRs Point # Emissions Source Type Emissions Control? Permit # Issuance # Self Cert Required? Action Engineering Remarks 1 111117113111 t 1� fz1 1113i111i�11��1]1113 1E 1� �a 3 „„3E1J, 3E 1111111311i111,71�3,E.:..;.. 7, ' 1,1_E:.... .. „ - � Turbnie _ .,'�.: _ � .. No 12WE2024 4 V{ ' .�,.:- '? Ak! 6( ,Fss� # ,. •' di rcatitn =.lower p rSe IaCrln lg unl ra Nox unit .. ..� Turbine No 12WE2024 4 Permit Modification Replacing unit with lower-Nox unit 7_" Amine Sweetening Unit Yes._ ` 7.2WE2024 4 Permit Modification - Adjusting combustion emissions l 3'11 '��t 48 r. TEG Dehydrator Yes 12WE2024 4 Permit Modification Adjusting control scenarios. o Condensate Storage Tank o Yes 12WE2024 4 Permit Modification Adjusting combustion emissions Ji 33 � , � i '71711 i1 111i 9,91 Hydmcarbon Liquid Loading Yes 12WE2024 311 -4 Permit Modification Ad usti emissions 1 1? �� 5 r 1 7 11 31 113j377,7 � l ydrocarbon Li quid Loading y qy No 12WE2024 ' 4 Permit Issuance lal New point (point is previously but e permitted ), fi 3u13 13iE�..r> 733133Y3I3j3�j31 " 057 Produced Water Storage Tank a __ Yes 12WE2024 4 _._ Permit Initial Issuance New point (point is existing but not previously permitted) PE7"`:1111 J7�' ii JE EE�k �� 13�7fUjj119>IJ,t 9111J1d. a6 r .' ,71711711W7i i11 E `E<, 058 � � _ - Other (Explain}_ No 12WE2024 4 Permit Initial Issuance 300 bbl methanol storage tank. New point (point is existing but not previously permitted) 17 j711�11��-''�>:J:l�l�i�� ,059 - •. � Process Flare Yes 12.WE2024 4 Permit Initial - ' Issuance ' point New(point is existing but not previously permitted) Colorado Air Permitting Project Section 03 - Description of Project In this modification, DCP is requesting to replace the existing turbines with new, lower-NOx turbinesadjust the control scenarios for the TEG dehy so that the still vent is now primarily recycled, and add four points that are existing but previously considered insignificant. DCP is also adjusting combustion emissions for two points. With this modification, there is an overall decrease €n emissions. However, DCP is adding four new points and one point, the plant flare, is requiring a new synthetic minor li€mit. Thus, public comment is required. Since this request is a relaxation of project emission limits established in CP3, total project emissions for Lucerne II expansion were also re-evaluated (see worksheet "Total Project Emissions" and history file for more details). Total project emissions for each criteria pollutant are below significant emission rates. The permit condition will be updated to reflect total project emissions. Since this permit will include new points, the new points will need to go through self -certification and require short-term limits. Section 04 - Public Comment Requirments Is Public Comment Required? Yes If yes, why?' Requesting Synthetic Minor Permit Section 05 - Ambient Air Impact Analysis Requirements Was a quantitative modeling analysis required?2 No If yes, for what pollutants? If yes, attach a copy of Technical Services Unit modeling results summary. Section 06 - Facility -Wide Stationary Source Classification Is this stationary source a true minor? Is this stationary source a synthetic minor? If yes, explain what programs and which pollutants here: Yes";- Is this stationary source a major source? If yes, explain what programs and which pollutants here: Prevention of Significant Deterioration (PSD): CO Title V Operating Permits (OP) : NOx, CO, VOC Non -Attainment New Source Review (NANSR): NOx, VOC Turbine Emissions Inventory Section 01 -Administrative Information Facility AIRs ID: 123 County 0107 044 and 045 Plant Point *Emissions for points 044 and 045 were estimated through the same method. As such, this spreadsheet provides an analysis for both turbine units as emissions are identical from each. Section 02 - Equipment Description Details Detailed Emissions Unit One (1) Solar, Taurus 70 naturai gas fired combusto3turbine(SN: to be determined), rated at 65.93 MMBtu/nr heat;_ Description: input and 9,012 horsepoaer(HP). Emission Control Device Equipped with Dry LowNOx combustion systemic„ Description: .Combustion;, system in considered integral to the process and net an add-on control device. -_ Requested Overall VOC & HAP Control Efficiency %: Dry Low NOx is considered an integral control device. Section 03- Processing Rate Information for Emissions Estimates Heat Input Rate = Heat content of waste gas= Actual Hours of Operation = Requested Hours of Operation = Actual heat input rate = Requested heat input rate = Potential to Emit (PTE) heat input rate = Actual Fuel Consumption = Requested Fuel Consumption = Potential to Emit (PTE) Fuel Consmption = Section 04- Emissions Factors & Methodologies Normal Operation Emission Factors Turbine 65.f MMBtu/hr Btu/scf hrs/year Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (Ib/MMscf) (Fuel (Fuel Input) Consumption) 0.0021........ 1.9070 0.0066 5.9935 0.0066 5.9935 500 fd!0,0034 3.0875 0.0399 36.270 CO 0.0608 55.167 Formaldehyde 3/ ,0.0007 0.6448 Acetaldehyde : '4.00E -0S 3.63E-02 Acrolein 6.40E-06 Benzene 5.81E-03 20E-05 1.09E-02 1,3 -Butadiene Ethylbenzene 4.30E-07 a?!. 3.90E — .20E -05'i 2.91E-02 Toluene 130-04_._tc..E 1.18E-01 2.20E-06 6.40E-0'. PAH 2.00E-03 5.81E-02 Xylene Section 05 - Emissions Inventory Sub -Total Emissions for Normal Operation Potential to Emit Actual Emissions Requested Permit Limits Criteria Pollutants Uncontrolled Uncontrolled Controlled Uncontrolled Controlled (tons/year) (tons/year) (tons/year) (tons/year) (tons/year) Ibs/month VOC 0.61 0.61 0.61 - 0.61 0.6 103 PM10 1.91 - 1.91 1.91 1.91 1.9 324 PM2.5 1.91 L91 1.91 1.91 1.9 324 SOx 0.98 0.98 0.98 0.98 1.0 167 NOx 11,54 11.54 11.54 11.54 11.5 1961 CO 17.56 17.56 17.56 17.56 17,6 2983 Potential to Emit Actual Emissions Requested Permit Limits Requested Permit Limits Hazardous Air Pollutants Uncontrolled Uncontrolled Controlled Uncontrolled Controlled Uncontrolled Controlled (tons/year) (tons/year) (tons/year) (tons/year) (tons/year) )Ibs/year) (Ibs/year) Formaldehyde 2.052E-01 2.052E-01 2.052E-01 2.052E-01 2.052E-01 410 410 Acetaldehyde 1.156E-02 1.156E-02 1.156E-02 1.156E-02 1.156E-02 23 23 Acrolein 1.850E-03 1.850E-03 1.850E-03 1.850E-03 1.850E-03 4 4 Benzene 3.468E-03 3.468E-03 3.468E-03 3.468E-03 3.468E-03 7 7 1,3 -Butadiene 1.243E-04 1.243E-04 1.243E-04 1.243E-04 1.243E-04 0 0 Ethylbenzene 9.249E-03 9.249E-03 9.249E-03 9.249E-03 9.249E-03 18 18 Toluene 3.757E-02 3.757E-02 3.757E-02 3.757E-02 3.757E-02 75 75 PAH 6.359E-04 6.359E-04 6.359E-04 6.359E-04 6.359E-04 1 1 Xylene 1.850E-02 1.850E-02 1.550E-02 1.850E-02 1.850E-02 37 37 hrs/year From 1st app From 2nd app Adjusting for HHV Ratio of Heat corn Corrected HHV adjustment 72.67243243 1.209251101 79.78969277 72.589 578,072.40 MMBTU per year HHV MMBtu/hr lb/Mmbtu tpy 578,072.40 MMBTU per year 79.78969277 0.039854523 13.92831 578,072.40 MMBTU per year 636.57 MMscf/year 636.57 MMscf/year 636.57 MMscf/year Emission Factor Source 6T j If calculating emissions using Ib/MMscf Ib/MMscf 54.1 43.76026671 13.92831 Startup/Shutdown Emission Rates Event per yr Startups per yr Shutdowns per yr Min per even 10 10 10 10 Emissions per event (Ibs) Emissions lb/yr (tpy) Startup Shutdown Startup Shutdown Startup Shutdown 180 80 0.09 0.04 10 10 0.005 0.005 CO 88 62 880 620 0.44 0.31 Total Permitted Emissions for Normal Operation Plus Start-up/Shutdown Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit limits Uncontrolled Controlled (tons/year) (tons/year) VOC 0.74 I 0.7 al emiss 0.13 0.01 0.75 3 of 33 K:\PA\2012\12W E2024.CP4.xlsx Turbine Emissions Inventory PM10 PM2.5 SOx NOx CO 1.91 1.9 1.91 1.9 0.98 1.0 11.55 11.5 18.30 18.3 Section 06 - Regulatory Summary Analysis Regulation 1 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 III.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: III.A.1.b. For fuel burning equipment with designed heat inputs greater than 1x105BTU per hour, but less than or equal to 500x105 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI).°'u5 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. The turbines covered under points 044 and 045 each have a design heat input rate of 65.99 MMBtu/hr. As a result, the turbines are subject to this portion of the regulation. Using the above equation, the allowable particulate emission limitation is 0.160 Ib/MMBtu. The AP -42 emission factor of 6.6x10 a lb/MMBtu used in the calculations above is below this particulate emission threshold. Section V1.B.4. New sources of sulfur dioxide shall not emit or cause to be emitted sulfur dioxide in excess of the following process -specific limitations (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates.) VI.B.4.c.(I). 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. The turbines covered under points 044 and 045 have a design heat input rate of 65.99 MMBtu/hr. As a result, the turbines are subject to this portion of the regulation. The AP -42 emission factor of 3.4x10 a lb/MMBtu used in the calculations above is below this sulfur dioxide emission threshold. Regulation 2 Section I.A - No person, wherever located, shall cause or allow the emissionof odorous air contaminants from any single source such as to result in detectable odors which are measured in excess of the following linits: 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 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. Applicant is required to file an APEN since emissions exceed 1 ton per year NOc. Part B — Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled NOx emissions from this facility are greater than the 2.0 TPY threshold (Reg. 3, Part 6, Section II.D.2.a) Regulation 6 Part B Section II: Standards of Performance for New Fuel Burning Equipment: 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: II.C.2. 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)-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. If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates. II.C.3. Greater than 20 percent opacity. II.D 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: II.D.3.a. Sources with a heat input of less than 250 million Btu per hour: 0.8 lbs. 5O2/million Btu The turbines each have a design heat input rate of 65.99 MMBtu/hr and were constructed after 01/30/79. As a result, the turbines are subject to this portion of the regulation. Using the above equation in II.C.2., the allowable particulate emission limitation is 0.160 lb/MMBtu. The AP -42 emission factor of 6.6010-3 lb PM/MMBtu used in the calculations above is below this particulate emission threshold. Additionally, the AP -42 emission factor of 3.4010-3 lb SOx/MMBtu used in tiecalculations above is below this sulfur dioxide emission threshold of 0.8 lb SOx/MMBtu. NSPS GG: The provisions of this subpart are applicable to the following affected facilitiesrAll 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. The heat input at peak load for each of these turbines (points 044 8: 045) is 65.99 MMBtu/hr which is greater than 10 MMBtu/hr. As a result, the turbines would be subject to this NSPS; however, the turbines are also subject to NSPS KKKK (see applicability discussion below). According to NSPS KKKK §60.4305(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. As a result, NSPS GG does not apply to these points. 0.160121 4 of 33 K:\PA\2012\12 W E2024.CP4.xlsx Turbine Emissions Inventory NSPS KKKK: 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. Each of these turbines (Points 044 & 045) has a heat input at peak load of 65.99 MMBtu/hr (5 10MMBtu/hr) and commenced construction after February 18, 2005. As a result, NSPS KKKK applies to each of these turbines. The applicable requirements have been included in the permit. Regulation 7 Section XVI.D. Requirements for major sources of NOx XVI.D.1. Section XVI.D. applies to the owners and operators of any stationary combustion equipment with uncontrolled actual emissions of NOx equal to or greater than five (5) tpy and that existed at a major source of NOx as of June 3, 2016 located in the.8-Hr Ozone Controle area. The turbines covered under points 044 and 045 are listed sources under this portion of the regulation and have uncontrolled actual NOX emissions greater than five (5) tons per year. However, the turbines are being replaced and the new turbines were not on -site as of June 16, 2016. Thus the new turbines are not subject. MACT MACT YYYY: You are subject to this subpart if you own or operate a stationary combustion turbine located at a major source of HAP emissions. These turbines are not subject to MACT YYYY because they are located at an area source of HAP emissions. Section 07 - Initial and Periodic Sampling and Testing Requirements The new units will be requierd to have an initial stack test for NOx and CO. The permit will also require ongoing annual stack test for Nox and CO. The units will also be subject to on -going stack testing per NSPS KKKK. The new units will also be subject to on -going portable analyzer testing to ensure Nox and CO are tested. Section 08 -Technical Analysis Notes 5j•VYlth this modification/ thesource is requesting to replace two existing combustion turbbies (the units cortonenced operation 6(2412015}with like kind replacements, except the new turbines will have an even lower NOx emission rate. The existingtwoturbines covered under Points 044 and 045 were permitted based on a manufacturer guaranteed NOx emission rate of 13 ppm. The new turbines have a manufacturer guaranteed rate of 10PPMNOx. The division has : not previously permitted turbines at this low of a NOx emission rate. • rSeverally, turbines have been permitted based on a NOxemission rate around 15 ppm. I reviewed stack testing and portable testingfor existing DCP Solarturbines permitted under Points 044 and= 045�andtesting₹esults did routinely show 10 ppm or lower'Nox emission .'. rates. The initial stacktesting and recent portable analyzer testingfotthe existing Soiarturbines atLucerne II showed 7ppm NOx. .Ialso reviewed stack testingforexistingturhines at Mewbourn and resultsforthese turbines were between 5 ppm- 13. ppm NOx, With this modification, thesource is also requesting to revise the gas throughput based on tsing a natural gas heat,input (iiHV) of 1098 btu/scf. The permit limit -was previously based on 999 feu/set. It is accepifableto adjust the gas process limit bce this heat content is based ocr coot gas samples of the Icy lu erne II esbite gas One issue withthe heatinput value,. though,sthe Solar guaranteed .. emission rate is basedon a gas heat input (ENS) of 9➢8.1 btu/ sof.When I asked questions aboutthis issue, DCP provided revised calculations on 1S/15/2018 However, these revised calculations did not correctly adjust the rating of the turbine for heat content (DCP had simply multiplied the heat content onthe specsheet, 65.99 MM9tujhr by afactor of 1.1). I requested DCP use the correct adjusted.. heat input by multiplying 65.99 MMBtu/hr by a ratio of the site specific heatcontent of 1098 htu/scf andthe LHV heat content on the spec sheet of 908.1 btu/scf.Also, DCP used the lhjhr emission rate and then divided it by -the higher heat input value -This approach is incorrect .I asked DCP to use the Ib/MMBtufactor and multiply by the higher heat input After significant backand forth emai Iswith DCP, I will establish permit limits based on the specification sheet_ DEP isn't requesting for buffers so l will take emissions and turbine rating directly from the spec sheet will set the permit emission limits based on 10 ppm Nov but will require initial stacktestiag since the units are new I wilt also require on goings€ack testing and portable analyzer Yestingtademonstrate �! mpkance wEth NOx and CO emissions. While the units will be3ubject to NSP�5 KK$K testing the NSPS limit is Z5'ppm NOx.Thus, the addAienal s3acktestingwRYensure the saurca is demoiisirating compliance with the 10: ppm NOx emission rate £piing permitted emission The source is using the same emssioafactors from the previous permit issuance for altthe other pollutants. AIRS Point # 044 and 045 Process # SCC Code 01 K Section 09 - Inventory 5CC Coding and Emissions Factors Uncontrolled Emissions Pollutant Factor Control °6 Units PM10 6.60E-03 0 lb/MM Btu Input PM2.5 6.60E-03 0 lb/MM Btu Input NOx 3.99E-02 0 lb/MMBtu Input VOC 2.10E-03 0 lb/MMBtu Input CO 6.08E-02 0 lb/MMBtu Input SOx 3.40E-03 0 lb/MMBtu Input Formaldehyde 7.10E-04 0 lb/MMBtu Input Acetaldehyde 4.00E-05 0 lb/MMBtu Input Acrolein 6.40E-06 0 lb/MMBtu Input Benzene 1.20E-05 0 lb/MMBtu Input 1,3 -Butadiene 4.30E-07 0 lb/MMBtu Input Ethylbenzene 3.20E-05 0 lb/MMBtu Input Toluene 1.30E-04 0 lb/MMBtu Input PAH 2.20E-06 0 lb/MMBtu Input Xylene 6.40E-05 0 Ib/MMBtu Input *Emissions for points 118-119 were estimated through the same method. As such, this spreadsheet provides an analysis for each turbine as emissions are identical from each. 5 of 33 K:\PA\2012\12 W E2024.CP4.xisx DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # AIRS ID 12WE2024 Issuance 4 123/0107/047 Section 02 - Equipment Description Details One (1) methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf per day (Fabwell, Model 108" amine contactor, Serial number: 13-1311-1). This emissions unit is equipped with three (3) electric amine recirculation pumps (Baker Hughes HPHVMARK) 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 (VRU) with a maximum 3% annual downtime. Flash tank emissions during VRU downtime will be routed to the plant flare with 95% destruction efficiency. The acid gas stream from the still vent condenser outlet is routed to a regenerative thermal oxidizer (RTO) (Anguil, Model 150, Serial Number: 17714) rated at 10,000 scf/min. Destruction efficiency for the RTO is a minimum of 96% for VOC. The acid gas stream from the still vent condenser outlet is routed to a backup thermal oxidizer (TO) during RTO downtime with a minimum destruction efficiency of 96%. Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Amine Still Vent and Flash Tank Requested Gas Throughput Limit = Potential to Emit (PTE) Gas Throughput = Secondary Emissions - Combustion Device(s) Heat content of flash tank waste gas= Volume of flash tank waste gas emitted = Heat content of still vent waste gas= Volume of still vent waste gas emitted = Section 04 - Emissions Factors & Methodologies MMscfd MMscf/yr 7130 MMscf/yr Btu/scf MMscfd (from Promax model) Btu/scf MMscfd (from Promax model) The source used Promax to estimate emissions. The same model used for the initial permit and the last issuance was used for this application. Also, the source changed the heat content of the acid gas stream from 5.12 btu/scf to 12.5 btu/scf. The model was based on the following parameters: Inlet Gas Pressure 900.5 psig Inlet Gas Temperature 78.14 deg F Amine Recirculate Rate 945 gpm Promax Results Flash Tank VRU Control 97% Flare 95% Pollutant Uncontrolled (lb/hr) Uncontrolled (lb/yr) Uncontrolled (tpy) Controlled (lb/hr) Controlled (lb/yr) Controlled (tpy) % Control VOC 127.22 1,114,405 557.20 0.1908 1672 0.8 99.9% Benzene 1.24 10,862 5.43 1.86E-03 16.3 8.1E-03 99.9% Toluene 0.51 4,468 2.23 7.65E-04 6.7 3.4E-03 99.9% Ethylbenzene 0.02 175 0.09 3.00E-05 0.3 1.3E-04 99.9% Xylenes 0.03 263 0.13 4.50E-05 0.4 2.0E-04 99.9% n -Hexane 1.91 16,732 8.37 2.87E-03 25.1 1.3E-02 99.9% Hydrogen sulfide 0.03 263 0.13 4.50E-05 0.4 2.0E-04 99.9% Still Vent Pollutant Uncontrolled (lb/hr) Uncontrolled (lb/yr) Uncontrolled (tpy) Controlled (lb/hr) Controlled (lb/yr) Controlled (tpy) % Control VOC 38.10 333,731 166.87 1.5239 13,349 6.67 96.0% Benzene 14.72 128,947 64.47 0.5888 5,158 2.6 96.0% Toluene 6.99 61,232 _ 30.62 0.2796 2,449 1.2 96.0% Ethylbenzene 0.254 2,225 1.11 0.0102 89 4.5E-02 96.0% Xylenes 0.5306 4,648 2.32 0.0212 186 9.3E-02 96.0% n -Hexane 0.174 1,524 0.76 0.0070 61 3.0E-02 96.0% Hydrogen sulfide 3.96 34,690 17.34 0.1584 1,388 6.9E-01 96.0% RTOITO 96% Total For Flash and Still Pollutant Uncontrolled (lb/hr) Uncontrolled (lb/yr) Uncontrolled (tpy) Controlled (lb/hr) Controlled (lb/yr) Controlled (tpy) % Control EF (lb/MMscf) VOC 165.31 1,448,136 724.1 1.714709 15,021 7.5 99.0% 17.25 Benzene 15.96 139,810 69.9 0.59066 5,174 2.6 96% 1.665 230 MMscfd 7130 MMscf/mor 83950 MMscf/ VOC Emissions for Alt( hr/yr 146 312 tpy 2.8 0.2 20987.5 MMscf/quarter K:\PA\2012\12 W E2024.CP4.xlsx 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # AIRS ID Toluene 7.5 65,700 32.9 0.280365 2,456 1.2 96% 0.783 Ethylbenzene 0.274 2,400 1.2 0.01019 89 0.0 96% 0.029 Xylenes 0.5606 4,911 2.5 0.021269 186 0.1 96% 0.058 n -Hexane 2.084 18,256 9.1 0.009825 86 0.0 99.5% 0.217 Hydrogen sulfide 3.99 34,952 17.5 0.158445 1,388 0.7 96% 0.416 12WE2024 Issuance 4 123/0107/047 Direct Venting of Still Vent Hours/yr 146 Pollutant Uncontrolled (lb/hr) Uncontrolled (Ib/yr) Uncontrolled (tpy) VOC 38.10 5562.18536 2.8 Benzene 14.72 2149.12 1.1 Toluene 6.99 1020.54 0.5 Ethylbenzene 0.25 37.084 0.0 Xylenes 0.53 77.4676 0.0 n -Hexane 0.17 25.404 0.0 Hydrogen sulfide 3.96 578.16 0.3 Secondary Emissions SOx Emissions Inlet H2S (lb/hr) Recycled H2S emissions I Combusted H2S emission H2S Converted (lb/hr) SOx Emissions (lb/hr) SOx Emissions (tpy) Flash Tank Still Vent/RTC Still Vent/TO 0.03 3.96 0.02910 0.00086 0.0009 0.0016 0.0070 0.00 3.80 3.80 7.15 31.30 7.15 1.11 Still Vent Flow 7.86 MMscfd 47.815 MMscf/ 4.061 MMscf/ pt 0.1314 0.127458 0.003745 0.003745 0.007039 NOx and CO Plant Flare Combustion (during VRU downtime) Flash Tank Flow 0.3148 MMscfd, from Promax model 3.4 MMscf/yr Flash Tank Heat content 937.9600 Btu/scf (Promax model estimated 937.96 btu/scf for this stream) Operating time 262.8000 hr/yr Pollutant Emission Factor Emissions EF lb/MMBtu Source lb/yr tpy lb/MMscf NOx 0.068 AP -42, Ch 13 219.9 0.11 63.781 CO 0.31 AP -42, Ch 13 1,002.3 0.50 290.77 RTO Combustion Fuel Burner and supplemental I 9.58 MMscf/yr 0.81 MMscf/31-day Pollutant Emission Factor Emissions EF lb/MMscf Source lb/yr tpy lb/MMscf NOx 100.0 AP -42, Ch 1.4 1031.3 0.52 107.65 CO 84.0 AP -42, Ch 1.4 866.3 0.43 90.424 VOC 5.5 AP -42, Ch 1.4 56.7 0.03 5.9206 PM Total 7.6 AP -42, Ch 1.4 78.4 0.04 8.1812 SO2 0.6 AP -42, Ch 1.1 6.2 0.00 0.6459 Waste Gas Still Vent Flow Still Vent Heat content 7.86 MMscfd 12.5000 Btu/scf lb/MMBtu 0.0980 0.0824 0.0054 0.0075 0.0006 2868.9 ,MMScf/yr 243.66 MMscf/31-day Pollutant Emission Factor Emissions EF lb/MMBtu Source lb/yr tpy lb/MMscf NOx 0.068 AP -42, Ch 13. 2,438.6 1.22 0.850 CO 0.31 .. AP -42, Ch 13.. 11,117.0 5.56 3.875 TO Combustion Pilot Light Pilot light operation Burner Rating Heat content Still Vent Flow TO Days of operation K:\PA\2012\12 W E2024.CP4.xlsx 0.1000 MMBtu/hr 8760.0000 hr/yr 30.88 MMBtu/hr 1098.0000 Btu/scf 4.0938 MMBtu/hr 312.0000 hr/yr, assuming 13 days per year of operation 4.01 0.8 468.731026 RTO burner 0.05 Mmbtu/hr 0.3989071 MMscf/yr Total for RTO tpy 1.7 6.0 Total supplemental fuel, MMscf/yr 2017 stack 0.015333 5.596667 7.835333 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # AIRS ID Pollutant Emission Factor Emissions EF Ib/MMBtu Source lb/yr tpy lb/MMscf NOx 0.138 TCEQguidanc 1,626.7 0.81 0.5649 CO 0.31 AP -42, Ch 13.. 3,654.2 1.83 1.2691 12WE2024 Issuance 4 123/0107/047 Section 05 - Emissions Inventory Scenario 1- Still vent gas routed to RTO Pollutant Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (Ib/yr) Controlled (tpy) lb/31 day VOC . 333,788 166.9 13,406 6.7 1,139 Nox 3,470 1.73 3,470 1.7 295 CO 11,983 5.99 11,983 6.0 1,018 SO2 62,598 31.3 62,598 31.3 5,317 H2S 34,690 17.34 1,388 0.7 118 Scenario 2 - Still vent gas routed to TO Pollutant Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (Ib/yr) Controlled (tpy) VOC 51,577 25.8 475 0.2 Nox 1,627 0.81 1,627 0.8 CO 3,654 1.83 3,654 1.8 SO2 - 2,230 1.1 2,230 1.1 H2S 1,236 0.62 49 0.02 Scenario 3 - Still vent gas routed to atmosphere Pollutant Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (lb/yr) Controlled (tpy) VOC 5,562 2.8 5,562 2.8 Nox CO SO2 H2S 578 0.29 578 0.3 Scenario 4 - Flash tank gas routed to Plant Flare Pollutant Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (lb/yr) Controlled (tpy) VOC 33,432 16.7 1,672 0.8 Nox 220 0.1 220 0.1 CO 1,002 0.5 1,002 0.5 SO2 18 0.01 18 0.01 H2S 9 0.0 0.4 0.00 Total Emissions Summary - on APEN Pollutant Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (Ib/yr) Controlled (tpy) % Control EF (lb/MMscf) VOC 1,448,136 724.1 21,115 10.6 98.5% 17.2499809 Nox 5,316 2.66 5,316 2.7 0.0% CO 16,640 8.32 16,640 8.3 0.0% SO2 64,841 32.4 64,841 32.4 0.0% 0.77237892 H2S 34,952 17.48 2,016 1.0 94.2% 0.41634783 Benzene 139,810 69.9 7,507 3.75 94.6% 1.6653913 Toluene 65,700 32.9 3,564 1.78 ! 94.6% 0.7826087 Ethylbenzene 2,400 1.2 130 0.06 94.6% 0.0285913 Xylenes 4,911 2.5 270 0.14 94.5% 0.05849739 n -Hexane 18,256 9.1 114 0.06 99.4% 0.21746087 Table to check summary emissions Pollutant VOC Nox CO SO2 H2S Section 06 - Regulatory Analysis Regulation 3 Part A APEN Requirements APEN is required since actual uncontrolled VOC emissions are greater than 2 tpy. Part B - Construction Permit Requirements Permit is required since facility -wide actual uncontrolled VOC emissions from all APEN-required points are greater than 5 tpy. Part B - RACT Uncontrolled Uncontroll I Controlled I Controlled (lb/yr) I ed (tpy) (lb/yr) (tpy) 424,360 212.18 21,115 10.56 5,316 2.66 5,316 2.66 16,640 8.32 16,640 8.32 64,845 32.42 64,845 32.42 36,512 18.26 2,016 1.01 THECONTROLLED VA K:\PA\2012\12W E2024.CP4.xlsx 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # AIRS ID 12WE2024 Issuance 4 123/0107/047 Since the amine unit was constructed after Nov 2007, the unit is subject to RACT per Reg 3, Part B, III.D.2. The source is not modifying the control strategy or increasing VOC emissions. The control strategy was discussed and approved in the PA for Issuance 3. The unit will comply with RACT by routing still vent vapors to an RTO as primary control and a TO for backup control. Both devices must achieve 96% VOC control. Flash tank vapor are recycled via a VRU to the plant inlet or to the plant flare during VRU downtime. Also, during unplanned events, there will be minimal time of direct venting of still vent vapors, 146 hr/yr and the amount of emissions directly vented are minimal, —2.8 tpy uncontrolled VOC. The Division considers this control option to satisfy RACT for this facility set-up with the technical restraints. Regulation 6 NSPS LLL Amine unit is not subject to NSPS LLL because the unit was not constructed between 1/24/1984 and 8/22/2011 NSPS 0000 The facility is an onshore natural gas processing plant and the amine unit was constructed after 8/23/2011 but before 9/18/2015. Thus, the amine unit must meet the de minimis exemption Regulation 7 — Volatile Organic Compounds No Reg 7 requirements Regulation 8 - Control of HAPs No MACT requirements Section 07 - Initial and Periodic Sampling and Testing Requirements. Does the company use a site specific emisions factor to estimate emissions? If no, the permit will contain an "Initial Compliance" testing requirement to collect a site -specific extended gas analysis. With this modification, the source is using the same model res ults from the initial construction permit application. The compliance method for this amine unit is unique because the source is using waste gas flow metering and waste gas composition to calculate actual emissions instead of using model results. Because of this compliance method, sampling of the waste gases is needed. The source also needs site specific sampling to confirm inlet 112S concentrations. The existing permit requires initial and ongoing sampling of the inlet stream for H2S and waste gas stream for VOC and HAPs. The source provided an initial sample (received 12/21/2015) with the self - certification package. Ongoing sampling will remain in the permit. An initial sample is not needed for this modification since the source can continue to use the ongoing sampling results. I also confirmed the initial H25 sample for inlet gas/pre-amine gas, collected 11/4/2016, showed 0.0001 mol% H25 and the feed gas stream in the model is 0.000473 mot %, Thus, the initial sample is lower than the basis for permit limits. - Does the company request a control device efficiency greater than 95% for a flare or sT it y� combustion device? If yes, the permit will contain and intial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentratior The source already tested (tested on 11/2015 and 11/15/2016) and demonstrated compliance with 96% control efficiency for the RIO and with emission limits. The latest stack test results were approved by the Division 2/5/2017. While not required per the permit, the last stacktest included testing on the TO which also passed the 96% control efficiency and demonstrated compliance with emission limits, The RTO and amine unit are still subject to annual testing to confirm on -going compliance with emission limits but an initial test will not be required. The requested control efficiencyfor the flare is 95% so stack testing is not warranted for the flare. Section 08 -Technical Analysis Notes With this modification, the source is requesting to now account for the burner and supplemental fuel routed to the RTO. I have asked DCP in previous modifications for this unit about supplemental fuel to the RTO and DCA stated supplemental fuel was not needed. I had requested supplemental fuel to be monitored during stack testing and the field notes show supplemental fuel was used during the 2016 stack test. Based on the recorded value from the field notes, average supplemental fuel gas flow was 14.32 mscf/days which equals 52 MMscf/yr. In this application, the source included a burner/supplemental fuel rate of 9.58 MMscf/yr stating this value is based on RTO meter fuel usage plus 40% buffer. I requested the source to provide documentation of the RTO burner and supplemental fuel rate. DCP stated in a response received 1/8/2019 that they do not need to provide the burner design rating because they will take a limit on how much fuel is routed to the unit which is based on expected flow. OCR also stated that the RTO is not operated in "SFr" mode and that supplemental fuel is not needed. The permit will include conditions to ensure supplemental fuel is not routed through the "SFI" line and to ensure the RTO is not operated in "SFI mode. The 2016 stack test also included field data for the TO supplemental fuel. When the TO was warming up, the fuel flow was 1360.12 scfm which equates to 25.8 MMscf/yr at 312 hr/yr. During the actual testing of the TO when the TO was burning waste gas, the fuel, gas flow rate was 3987.5 scfm which is 74.6 MMscf/yr at 312 hr/yr. The source has permitted the TO based on a supplemental fuel rate of 8.8 MMscf/yr. I asked DCP about the values from the stack test and the values used in the application. DCP stated in an email response received 11/15/2018 that the TO panel was off by a factor of 14 during the stack test so the fuel flow should have been 398.75 scfm. OCR stated they, provided the corrected values in inspection records. The source is also requesting to update the CO emission factor for AP -42, Chapter 13.5 to the revised value. The source is also reques Chapter 1.4 emission factors for the RTO pilot but use Chapter 13.5 and TCEQflare emission factors for the TO pilot. DCP also is updating the fuel heat content from 999>btu/scf to 1.0 The permit will be updated to reflect RTO and TO minimum combu K:\PA\2012\12 W E2024.CP4.xlsx 98 btu/scf which is based on site -specific sampling of the residueg n chamber temperatures based on the lateststack testing. 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # AIRS ID 12WE2024 Issuance 4 123/0107/048 Section 02 - Equipment Description Details One (1) triethylene glycol (TEG) dehydrator unit with a design capacity of 230 MMscf/day (Prof Projects Inc., Model T-9600, serial number: 5518). This emissions unit is equipped with two (2) electric glycol pumps (Cat Pumps/3541.0110) 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 tank emissions routed to a closed loop system that utilizes a vapor recovery unit (VRU) with a maximum 3.5% annual downtime. Flash tank emissions during VRU downtime will be routed tothe plant flare with 95% destruction efficiency. The still vent emissions are routed to a condenser and then to a VRU with a maximum 3.5% annual downtime to recycle the emissions to the plant inlet. Still vent emisions during VRU downtime will be routed to the plant flare with 95% destruction efficiency. Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Dehy Still Vent and Flash Tank Requested Gas Throughput Limit = � 3t MMscfd MMscf/yr Potential to Emit (PTE) Gas Throughput 83 MMscf/yr Secondary Emissions - Combustion Device(s) Heat content of flash tank waste gas= Volume of flash tank waste gas emitted Heat content of still vent waste gas= Volume of still vent waste gas emitted Section 04 - Emissions Factors & Methodologies Btu/scf (calculated by DCP based on Glycalc Report composition for Flash Tank Off Gas) scf/hr (from Glycalc Report - Flash Tank Off Gas Stream) Btu/scf (calculated by DCP from Glycalc report) scf/hr (from Glycalc model - Condenser vent gas stream) The source used GRI Glycalc 4.0 to estimate emissions. For this modification, the source is updating the Glycalc model based on a site -specific wet gas sample (collected 5/10/2018) for the wet gas composition, pressure and temperature. With this sample, the wet gas temperature used in the model decreased from 110 deg F to 100 deg F and the wet gas pressure increased from 850 psig to 920 psig. The source is using the same gas flow rate of 230 MMscf/day, same water content of 5 lbs H2O/MMscf and same TEG rate of 40 gpm. The source is also using the same flash tank parameters from Issuance 3 which include a flash tank pressure of 65 psig and temperature of 175 deg F. The model was based on the following parameters: Inlet Gas Pressure 920 psig Flash Tank tk Pressure 65 psig Inlet Gas Temperature 100 deg F Flash Tank Temperature 175 deg F Glycol Recirculate Rate 40 gpm Glycalc Results (in tons per year) Flash Tank VRU Control 97% Flare 95% Pollutant Uncontrolled (lb/hr) Uncontrolled (lb/yr) Uncontrolled OM() ControlW (lb/hr) Controlled (lb/yr) Controlled (tpy) % Control VOC HAPs 106.0292 928815.792 464.407896 0.185551 1625.428 0.8127138 99.8% 2.3217 20338.092 10.169046 0.004063 35.59166 0.0177958 99.8% Benzene 0.6783 5941.908 2.970954 0.0011.87 10.39834 0.0051992 99.8% Toluene 0.2504 2193.504 1.096752 0.000438 3.838632 0.0019193 99.8% Ethylbenzene 0.0056 49.056 0.024528 9.8E-06 0.085848 4.292E-05 99.8% Xylenes 0.0221 193.596 0.096798 3.87E-05 0.338793 0.0001694 99.8% n -Hexane 1.3634 11943.384 5.971692 0.002386 20.90092 0.0104505 99.8% Still Vent Pollutant Uncontrolled (lb/hr) Uncontrolled (lb/yr) Uncontrolled (tpy) Controlled (lb/hr) Controlled (lb/yr) Controlled (tpy) % Control VOC HAPs 91.387 800550.12 400.27506 0.159927 1400.963 0.7004814 99.8% 32.1726 281831.976 140.915988 0.056302 493.206 0.246603 99.8% Benzene 18.7379 164144.004 82.072002 0.032791 287.252 0.143626 99.8% Toluene 9.5871 83982.996 41.991498 0.016777 146.9702 0.0734851 99.8% Ethylbenzene 0.3348 2932.848 1.466424 0.000586 5.132484 0.0025662 99.8% Xylenes 1.8304 16034.304 8.017152 0.003203 28.06003 0.01403 99.8% n -Hexane 1.6802 14718.552 7.359276 . 0.00294 25.75747 0.0128787 99.8% Buffer 1.1 K:\PA\2012\12W E2024.CP4.xlsx 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # 12WE2024 Issuance 4 AIRS ID 123/0107/048 Total For Flash and Still 230 MMscfd 7130 MMscf/mor 83950 MMscf 20987.5 MMscf/ouarte Pollutant Uncontrolled (lb/hr) Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (lb/hr) Controlled (Ib/yr) Controlled (tpy) Control EF (lb/MMscf) (Ib/MMscf) VOC HAPs 217.15782 1,902,303 951.2 0.380026 3,329 1.66 100% 22.66 37.94373 332,387 166.2 0.066402 582 0.29 100% 3.959 Benzene 21.35782 187,095 96.5 0.037376 327 0.16 100% 2.229 Toluene 10.82125 94,794 47.4 0.018937 166 0.08 100% 1.129 Ethylbenzene 0.37444 3,280 1.6 0:000655 6 0.00 100% 0.039 Xylenes 2.03775 17,851 8.9 0.003566 31 0.02 100% 0.213 n -Hexane 3.34796 29,328 14.7 0.005859 51 0.03 100% 0.349 Secondary Emissions Plant Flare Combustion during VRU downtime for still vent and flash tank) Operating time 306.6000 hr/yr Pollutant Emission Factor Emissions EF lb/MMBtu Source lb/yr tpy lb/MMscf NOx 0.068 AP -42, Ch 13 164.1 0.08 143.15 CO 0.31 AP -42, Ch 13 748.3 0.37 652.58 For combustion of still vent emissions, the source used gas flaw rate and heat content of the "condenser vent gas stream" and not the "regenerator overheads stream" from the Glycalc report. While the source is not using the condenser as an air pollution control device, it is still acceptable to use the condenser overhead stream properties when calculating combustion emissions since the condenser is needed for liquids knockout prior to routing the stream to a combustion device. Section 05 - Emissions Inventory Total Emissions Summary Pollutant Uncontrolled (Ib/yr) Uncontrolled (tpy) Controlled (Ib/yr) Controlled (tpy) °A Control EF (Ib/MMscf) VOC 1,902,303 951.2 3;329 1.7 99.8% 22.659946 Nox 164 0.1 164 0.1 0.0% CO 748 0.4 748 0.4 0.0% SO2 0 0.00 0 0.0 #DIV/01 0 H2S 0 0.00 0 0.0 #DIV/01 0 Benzene 187,095 93.55 327 0.16 99.8% 2.2286421 Toluene 94,794 47.40 166 0.08 99.8% 1.1291739 Ethylbenzene 3,280 1.64 6 0.00 99.8% 0.039072 Xylenes 17,851 8.93 31 0.02 99.8% 0.2126348 n -Hexane 29,328 14.66 51 0.03 99.8% 0.3493523 Controlled lb/month 283 14 64 0 0 K:\PA\2012\12 W E2024.CP4.xlsx 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # 12WE2024 Issuance 4 AIRS ID 123/0107/048 Section 06 - Regulatory Analysis Regulation 3 Part A APEN Requirements APEN is required since actual uncontrolled VOC emissions are greater than 2 tpy. NOx and CO emissions are below APEN thresholds Part B - Construction Permit Requirements Permit is required since facility -wide actual uncontrolled VOC emissions from all APEN-required points are greater than 5 tpy. Regulation 7 — Volatile Organic Compounds XII.H VOLATILE ORGANIC COMPOUND EMISSIONS FROM OIL AND GAS OPERATIONS This source is subject to this section since it is located in an attainment area. Per XII.A.4, the dehy is only subject to sections XII.B and XII.H. Thus, the dehy is subject to the control standard but the control device is not subject to the control requirements in Section XII.C.1.d. XVII.D STATEWIDE CONTROLS FOR OIL AND GAS OPERATIONS Per Reg 7, Section XVII.B.5, dehydrators subject to an emission control requirement under 40 CFR Part 63 are exempt_from Section XVII. However, as discussed below in MACT HH, this dehy is not subject to a control standard under MACT because it is meeting the benzene exemption. Thus, the dehy must still be evaluated under Regulation 7 XVII.D This dehy is subject to XVII.D.2 because actual uncontrolled VOC emissions are greater than 15 tpy. This dehy is subject to XVII.D.3 because per XVII.D.4.a the dehydrator will be constructed after 5/1/2015 and uncontrolled actual emissions of VOC are greater than 2 tpy. The dehy is also subject to the control device requirements in XVII.B. While the flash tank is primarily controlled by the VRU, during VRU downtime, the flash tank is routed to the open flare. Since the open flare is not the primary destination for flash tank emissions, the open flare is approved as an alternative emission control device (Per PS Memo 15-03). - Regulation 8 - Control of HAPs PartE- MACTHH Since this facility is a natural gas processing plant, all emissions from the facility are aggregated when determining major HAP status. Thus, the site is a synthetic minor source of HAPs and is then an area source of HAPs per MACT HH. As specified in 63.760(b)(2), the only affected sources for area sources are TEG dehydrators. With this modification to the control scenario for the still vent, this TEG dehy now qualifies for the benzene exemption specified in 63.764 (e)(1)(ii). Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use a site specific emisions factor to estimate emissions? If no the permit will contain an"Initial Compliance testing requirement to collect a site -specific extended gas analysis. 1An s Itha3,sample, ty rjo reeled for t[trs €nadM tatton s€nce # e; raurre € ptcongipae #o use the ongoing sampl),(rly suits Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and intial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentra Section 08 - Technical Analysis Notes lent inlet via a VRU and then to plant fa; l siemodificatio t o ource is requesting to change the control strategy for the still vent Previously. the still vent was rou#ed to an enclosed combustor. The source is nesting to nstaltprtmary and secondary VRUs for the still vent to route emissions back to the plant inlet The sou, ----5 is also requesting emissions orfa maximum of 3 ..`"!',..downtime downtime of theVRUs: During downtime, the still vent emissions will now be routed to the plant flare The flash tank was previously p Twitted to oe routed back to the plant inlet via a VRU and a maximum of 3 % downtime. With this modification the source :s requesting to increase the downtime from 3% to 3.51. The flash tank emissions will continue to be routed to the plant flare during VRU downtime On the APEN, DCP modified the uncontrolled ernissions to only represent emissions during VRU downtime prior to combustion) Since DCP has operated the unit without recycling and is now modifying the control strategy, to re rcuteemissions to plant inlet it is not appropriate to change the uncontrolled emissions to any reflect dunng VRU downtime. The uncontrolled emissions will be represented on, the APEN as they have previously which is total uncontrolled from still vent and -lash tank. With this modification, DCP is now permitting the plant flare.' However, emissions associated with the dehy during "RU downtime will still be included at this point. K:\PA\2012\12WE2024.CP4.xlsx 123/0107 DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit# 12WE2024 AIRS ID 123/0107/050 Section 02 - Equipment Description Details Issuance 4 Detailed Emissions Unit dour(4)standize{)`.atmdspherie'canciensaYerSfarage vessels wnneetedvia liquid:'manfiaiU. Each tapir has.: Description: 1,000 hbt EmisSigiC5are routed to an enclosed combustor witha minimum d2s₹ructiart efficiency of Emission Control Device Endpsedll- Description: Requested Overall VOC & HAP Control Efficiency %5: Section 03 - Processing Rate Information for Emissions Estimates' Primary Emissions - Storage Tank(s) Actual Condensate Throughput'. Requested Permit Limit Throughput' = Potential to Emit (PTE) Condensate Throughput' = Barrels jbbl) per year Barrels (bbl) per year Barrels (bbl) per year Secondary Emissions - Combustion Device(s)a Heat content of waste gas9= �� ,77�8tu scf Volume of waste gas emitted per BBL of liquid 30 xNav?ieeiReeec' produced = ��s�s.;;�;;;;;;;�tp'22'scf/bbl Actual heat content of waste gas routed to combustion device = Request heat content of waste gas routed to combustion device = Actual Condensate Throughput While Emissions Controls Operating' = 30,660,000 gal/yr 0.7608936 MMscf/yr 0 MMBTU per year 2,798 MMBTU per year Potential to Emit (PTE) heat content of waste gas routed to combustion device = 2,798 MMBTU per year Section 04 - Emissions Factors & Methodologies Will this storage tank emit flash emissions711 Enclosed Combustor Pilot Light Pilot Rating Heat content Fuel 0.1600 MMBtu/hr 1098.00 btu/scf 1.28 MMscf/yr 0.11 MMscf/31-day : Total gas volume Pollutant Emission Factor Emissions EF lb/MMscf Source Iblyr tpy lb/MMscf NOx 100.0 AP -42, Ch 1.4 137.4 0.07 107.65 CO 84.0 AP -42, Ch 1.4 115.4 0.06 90.424 VOC 5.5 AP -42, Ch 1.4 7.6 0.004 5.9206 PM Total 7.6 AP -42, Ch 1.4 10.4 0.005 8.1812 SO2 0.6 AP -42, Ch 1.4 0.8 0.000 0.6459 Condensate Storage Tanks Control Device 182500 730000 2.0 MMscf/yr 0.173039141 Pollutant Toluene Uncontrolled E.F.12 Controlled E.F. Uncontrolled (lbs/bbl (Ibs/bbl E.F.13 (Ibs/MMBtu Condensate Condensate Throughput) Throughput) 90 f.,.,.,,:, .. 0.00010 0!0057 ' 0.00029 Ethylbenzene di7.0904 s 0.00002 Xylene n -Hexane 224 TMP 0.00022 0.00055 0.00000 waste heat combusted) 0 Uncontroled E.F.14 (lbs/bbl Condensate Throughput) 0.00003 0.0012 Emissions Factor Source Citation Section 05 - Emissions Inventory Potential to Emit Requested Permit Limits Actual Emissions Criteria Pollutants Uncontrolled Uncontrolled" Controlled Uncontrolled Controlled (tons/year) (tons/year) (tons/year) (tons/year) (tons/year) PM10 0.0 0.0 0.02 0.0 0.0 PM2.5 0.0 0.0 0.02 0.0 0.0 NOx 0.164 0.2 0.2 0.0 0.0 VOC 55.3 55.3 2.8 0.0 0.0 Uncontrolled EF Controlled EF lb/bbl 0.00004 0.00004 0.0004 0.1516 0.00004 0.00004 0.0004 0.0076 K:\PA\2012\12 W E2024.CP4.xlsx 13 of 33 223/0107 DCP Operating Company, LP , Lucerne 2 Natural Gas Processing Plant Permit # AIRS ID CO Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Requested Permit Limits . Uncontrolled Controlled (tons/year) (tons/year) Actual Emissions Uncontrolled Controlled (tors/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224TMP 7.5E-01 0.75 0.04 0.0E+00 0.0E+00 1,505 75 2.1E+00 2.09 0.10 0.0E+00 0.0E+00 4,173 209 1.5E-01 0.15 0.01 0.0E+00 0.0E+00 310 15 1.6E+00 1.58. 0.08 0.0E+00 0.0E+00 3,155 158 4.1E+00 4.05 0.20 0.0E+00 0.0E+00 8,102 405 3.0E-03 0.003 0.0001 0.0E+00 0.0E+00 6 0 12WE2024 Issuance 4 123/0107/050 0.491 0.5 0.5 0.0 0.0 C 0.0013 0.0013 K:\PA\2012\12W E2024.CP4.xlsx 14 of 33 123/0107 -DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit# 12WE2024 Issuance4 AIRS ID 123/0107/050 Section 06 - Regulatory Summary Analysis Regulation 7, Section XII.C, D, E, F Regulation 7, Section XII.G, C Regulation 7, Section XVII.B, C.1, C.3 Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart Kb Regulation 6, Part A, NSPS Subpart 0000 Regulation 8, Part E, MAC! Subpart HH (See regulatory applicability worksheet for detailed analysis) Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions?, If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? If yes, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company use a site specific emisions factor to estimate emissions? If yes, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific -sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. ■ Does the company request a control device efficiency greater than 95% for a flare oP combustion device? If yes, the permit will contain and intial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 -Technical Analysis Notes" For this modification the source Is only adjusting combustion emissions associated with the enclosed combustor. The source is adding the pilot tight at the enclosed combustor.There are no changes to the tank emissions. As discussed in the PA for Issuance 3, the source used EPA Tanks 4.0.9.d to calculate working and breathing emissions and assumed default properties of Gasoline RVP 10 and. meteorological data for Denver, CO `This approach was also used in the initial application. The source is increasing the waste gas flawra e from 72.63 sc€/hr to 86,86 sef/hr because the calculations were adjusted to 12.2 psis instead of 14.7 pale, which was used in the last: application. The source is also increasing heat content from 3397 btu/scf to 3577 btu/scf. The Source is also using NOX and CO emission factors from AP - 42 Chapter 13 instead of AP -42 Chapter 1.4. ) The source had allocated pilot light emissions to all sources resub)ectto nt gall the pilot light emissions under the tanks. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 0 Process # SCC Code 01 ro:�tedto the control device. Since the tanks a control and to simplify compliance de s -n tratlon,thepermitisbasedonassumin Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.00 0 lb/1,000 ga PM2.5 0.00 0 lb/1,000ga NOx 0.01 0 I lb/1,000 ga VOC 3.6 95 lb/1,000 ga CO 0.03 0 lb/1,000 ga Benzene 0.05 95 lb/1,000ga Toluene 0.14 95 lb/1,000 ga ' Ethylbenzene Q.01 95 lb/1,000 ga Xylene Q.10 95 lb/1,000ga n -Hexane Q.26 95 lb/1,000ga 224 IMP Q.00 95 lb/1,000 ga K:\PA\2012\12WE2024.CP4.xlsx 15 of 33 123/0107 Condensate Tank Regulatory Analysis Worksheet Colorado Regulation 1 All storage tanks are subject to Regulation 1, Section II.A.1: 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 1. 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 8 of this regulation. Colorado Regulation 3 ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 2 TPY? If yes, source requires an APEN and go to next question. If no, source does not need an APEN and is APEN-exempt/permit-exempt 2. Is the construction date (service date) prior to December 30, 2002? If yes, source is APEN-required/permit-exempt. If no, go to the next question 3. Are total facility uncontrolled VOC emissions from the greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY? If yes, source requires a permit. If not, source is APEN-required/permit-exempt. NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY? If yes, source requires an APEN and go to next question. If no, source does not need an APEN and is APEN-exempt/permit-exempt 2. Is the construction date (service date) prior to December 30, 2002? If yes, source is APEN-required/permit-exempt. If no, go to the next question 3. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY? If yes, source requires a permit. If not, source is APEN-required/permit-exempt. Colorado Regulation 7, Section XII 1. Is this storage tank located in the 8 -hr ozone non -attainment area or attainment/maintenance area? If yes, proceed to the next question. If no, the condensate storage tank is not subject to Regulation 7, Section XII. 2. Is this storage tank located at an oil and gas exploration and production operation', natural gas compressor station or natural gas drip station? If yes, proceed to the next question. If no, the condensate storage tank is not subject to Regulation 7, Section XII. 3. Is this storage tank located upstream of a natural gas processing plant? If yes, the condensate storage tank is subject to Regulation 7, Section XII as provided below, unless qualified for the company wide emissons exemption per footnote 2'. If no, the condensate storage tank is not subject to Regulation 7, Section XII. Section XII.C.1 —General Requirements for Air Pollution Control Equipment —Prevention of Leakage Section XII.C.2 — Emission Estimation Procedures Section XII-D— Emissions Control Requirements Section XII.E — Monitoring Section XII.F — Recordkeeping and Reporting COlerado Regulation 7, Section 011.13 1. Is this storage tank located in an ozone non -attainment or attainment maintenance area? If yes, proceed to the next question. If no, the condensate storage tank is not subject to Regulation 7, Section XII.G 2. Is this storage tank located at a natural gas processing plant? If yes, proceed to the next question. If no, the condensate storage tank is not subject to Regulation 7, Section 311.6 3. Does this storage tank exhibit"Flash" (e.g. storing non -stabilized liquids) emissions and have uncontrolled actual emissions greater than or equal to 2 tons per year VOC? If yes, Regulation 7, Section XII.G applies as provided below. If no, the condensate storage tank is not subject to Regulation 7, Section XII,G, Section XII.G.2 - Emissions Control Requirements Section XII.C.1 —General Requirements for Air Pollution Control Equipment —Prevention of Leakage Section XII.C.2 — Emission Estimation Procedures Colorado Regulation 7. Section XVII 1. Is this condensate storage tank' located at an oil and gas exploration and production operation , well production facility', natural gas compressor station' or natural gas processing plant? If yes, proceed to the next question. If no, the storage tank is not part of the affected source category for Regulation 7, Section XVII. 2. Is this condensate storage tank a fixed roof storage tank? If yes, proceed to the next question- If no, the storage tank is not subject to Regulation 7, Section XVII because it does not meet the definition of storage tank per XVII.A.15. 3. Are uncontrolled actual emissions' of this storage tank equal to or greater than 6 tons per year VOC? If yes, the storage tank is subject to the following provisions of Regulation 7, Section XVII: Section XVII.B —General Provisions for Air Pollution Control Equipment and Prevention of Emissions 7:" Section XVII.C.1 - Emissions Control and Monitoring Provisions Section XVII.C.3 - Recordkeeping Requirements 4. Does the condensate storage tank contain only "stabilized" liquids? If no, the following additional provisions apply. If yes, Section XVII.C.2 provisions do not apply. Section XVII.C.2 - Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR, Part 60, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels 1. Is the individual storage vessel capacity greater than or equal to 75 cubic meters (m') ["472 BBB)? If yes, proceed to the next question. If no, NSPS Kb does not apply since the storage vessel capacity is below the applicable threshold. 2. Does the storage vessel meet the following exemption in 60,111b(d)(4)? If yes, then the storage vessel is exempt from NSPS Kb. If no, proceed to next question. a. Does the vessel has a design capacity less than or equal to 1,589.874 m' ["10,000 BBL] used for petroleum' or condensate stored, processed, or treated prior to custody transfer' as defined in 60.111k? 3. Was this condensate storage tank constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) after July 23,1984? If yes, proceed to the next question. If no, NSPS Kb does not apply since this tank was constructed prior to the applicability date. 4. Does the tank meet the definition of "storage vessel"' in 60.11lb? If yes, proceed to the next question. If no, NSPS Kb Is not applicable to the condensate storage tank since It is not a storage vessel. 5. Does the storage vessel store a "volatile organic liquid (VOL)"s as defined in 60.111h? If yes, proceed to the next question. If no, NSPS Kb is not applicable to the condensate storage tank since it does not store a VOL 6. Does the storage vessel meet any one of the following additional exemptions: a. Is the storage vessel a pressure vessel designed to operate in excess of 204.9 kPa ['29.7 psi]andwithout emissions to the atmosphere (60.11ob(d)(2))?; or b. The design capacity is greater than or equal to 151 m' [-950 BBL] and stores a Squid with a maximum true vapor pressures less than 3.5 kPa (60.11ob(b))?; or c. The design capacity is greater than or equal to 75 Ma ["472 BBL] but less than 151 ms ['950 BBL] and stores a liquidwith a maximum true vapor pressures less than 15.0 kPa(60.11ob(b))? If yes, NSPS KB Is not applicable to the condensate storage tank based on the exemption criteria. If no, NSPS Kb Is applicable to this condensate storage tank, Including but not limited to, the following provisions: 660.7 - General Provisions, Notification and Record Keeping 660.112b- Emissions Control Standards for VOC 660.1136- Testing and Procedures 660.11Sb - Reporting and Recordkeeping Requirements tan Yes §60.116b - Monitoring of Operations 40 CFR, Part 60, Subpart 0000. Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution 1. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 602) after August 23, 2011? If yes, proceed to the next question. If no, NSPS 0000 does not apply since this tank was constructed prior to the applicability date, 2. Does this condensate storage vessel meet the definition of "storage vessel"' per 60.5430? If yes, proceed to the next question. If no, NSPS 0000 is not applicable. 3. Is this condensate storage vessel located at a facility in the onshore oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the industry? If yes, proceed to the next question. If no, NSPS 0000 is not applicable. 4. Are potential VOC emissions' from the individual storage vessel greater than or equal to 6 tons per year? If yes, proceded to the next question. If no, the storage vessel is not subject to NSPS 0000. 5. Is the storage vessel subject to and controlled in accordance with requirements for storage vessels in 40 CFR Part 60 Subpart Kb or 40 CFR Part 63 Subpart HH? If yes, the storage vessel is not 60.5295(h). If no, the storage vessel Is subject to NSPS 0000, including subject to NSPS 0000 per but not limited to, the following provisions: - §60.7- General Provisions, Notification and Record Keeping per Table 3 §60.5395 - Emissions Control Standards for VOC §60.6413 - Testing and Procedures §60.5395(g) - Notification, Reporting and Recordkeeping Requirements §60.5416(c) - Cover and Closed Vent System Monitoring Requirements 460.5417 - Control Device Monitoring Requirements - [Note: If a storage vessel is previously determined to be subject to NSPS 0000 due to emissions above 6 tons per year VOC on the applicability determination date, It should remain subject to NSPS 0000 per 60.5365(e)(2) even if potential VOC emissions drop below 6 tons per year] 40 CFR. Part 63, Subpart MACE HH, OII and Gas Production Facilities 1. Is the tank located at a facility that is major' for HAPs? If yes, proceed to next question. If no, there are no MACE HH requirements for condensate storage tanks located at an area source. 2. Is the storage tank located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids' (63.760(a)(2)); OR b. A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end user' (63.760(a((3)(? If yes, proceed to next question. If no, the facility is not an affected source under MACT HH. 3. Does the tank meet the definition of "storage vessel"' in 63.761? If yes, proceed to next question. If no, MACT HH is not applicable to the condensate storage tank since It is not a storage vessel. 4. Does the tank meet the definition of"storage vessel with the potential for flash emissions"' per63.761? If yes, proceed to nextquestion. If no, MACT HH is not applicable to the condensate storage tank since it is not a storage vessel with the potential for flash. 5. Is the tank subject to control requirements under 40 CFR Part 60, Subpart Kb or Subpart 0000? a. If yes, per 63.766 (d), the tank is not subject to MACT HH. If the tank is controlled per NSPS 0000, the source must submit periodic reports per 63.775(e). b. If no, MACE HH Is applicable to the condensate storage tank per 63.764(c)(2(, including but not limited to, the following provisions: 463.766- Emissions Control Standards §63.773- Monitoring §63.774- Recordkeeping §63.775 - Reporting Hydrocarbon Loadout Emissions Inventory Section 01- Administrative Information Facility AIRS ID: County Plant „a�iaa Point Section 02- Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Is this loadout controlled? Collection Efficiency: Control Efficiency: 95.00 Requested Overall VOC & HAP Control Efficiency %: Section 03- Processing Rate Information for Emissions Estimates Primary Emissions - Hydrocarbon Loadout Actual Volume Loaded = Requested Permit Limit Throughput= Potential to Emit (PTE) Volume Loaded = Barrels (bbl) per year Actual Volume Loaded While Emissions Controls Operating = Requested MgnthlyThroughput= I0.) Barrels (bbl) per year 62000 Barrels (bbl) per month 1))li3�; 39nt`;IOQD Barrels (bbl) per year 3nbdf�m3ffffil..,.aa..,ro,�a Secondary Emissions- Combustion Device(s) Heat content of waste gas= ill Volume of waste gas emitted per year = Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Btu/scf 1015372 scf/year Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04- Emissions Factors & Methodologies Does the company use the state default emissions factors to estimate emissions? Are the emissions factors based on a stabilized hydrocarbon liquid sample drawn at the facility being permitted? Loading Loss Equation L=12.46•S•P•M/T 0 MMBlU per year 3,734 MMBTU per year 3,734 MMBTU per year Barrels (bbl) per year A site specific stabilized hydrocarbon liquid sample must be provided to develop a site specific emissions factor. Factor Meaning Value Units Source S Saturation Factor 0.6 /zc;tr w ,Af-;/Pi�EfratoEo 5:2 Tabin;5.2-1Subu r van las dfzsg t3ed'acefest�No"'ema'i Sezr'sce. {"r»'F1. P True Vapor Pressure 5'0032:,.;; psia psia, source stated basedon similar DCP site buttlis valor also: agrees ss:th AF -42 Figure 7.1140 M Molecular Weight of Vapors G ) Ib/Ib-tool Al' lb/lb-mole, based an 40, Table 7,1-2 tar gassfloe RVP 10 T Liquid Temperature 51 2.4�'i Rankine deg, R, 3338 deg F(EPATanks shows 5245 sothrs values acceptable) L Loading Losses 4.817365462 lb/1000 gallons 0.202329349 Ib/bbl Component Mass Fraction Emission Factor Units Source Benzene .00136 0.002754457 lb/bbl Bowdon roodenoute sample from neeebyDC,alfe 3..i31ll11111hu, ..,3iI'f13,= Toluene 0.0377 0.007633372 lb/bbl =8asad oe condenmte sample from nearby DOS sit ylft$W' fl UM Ethylbenzene '. 0.11028 0.000568637 lb/bbl :eased on condensate sample from nearby I3CfliitAlinallibinEllEb Xylene 311Ci3 1 a 0.0285 0.005769703 lb/bbl - Based on condensate sample from nearby DCf? t E n -Hexane 5.3.0,0733 0-014820625 lb/bbl Based on condensate sample from onarhy DtA3te 311 3i,,,'Ag. 224 TMP =00001 1.09871E-05 lb/bbl --,eased on condenste sample from nearby DCP Site Pollutant ®' IMMEME Hydrocarbon Loadout Uncontrolled Controlled (Ib/bbl) (lb/bbl) (Volume Loaded) 0,0101 0.0001 0.0004 0.0000 0.0003 0.0007 0.0000 Pollutant INIIMEEMINE H. (Volume Loaded) 0.0028 0.0076 00006 0.0058 00148 0,0000 Control Device Uncontrolled (lb/MMBtu) Uncontrolled (Ib/bbl) (Volume Loaded) 0.00004 0.00004 0.0000 0.0003 0,0016 (waste heat combusted) ......0007` ...0.0075 0.0680'', Emission Factor Source Emission Factor Source 4 18 of 33 K:\PA\2012\12 W E2024.CP4.xlsx Hydrocarbon Loadout Emissions Inventory Section 05 - Emissions Inventory Potential to Emit Actual Emissions Requested Permit Limits Requested Monthly Limits Criteria Pollutants Uncontrolled Uncontrolled Controlled Uncontrolled Controlled Controlled (tons/year) (tons/year) (tons/year) (tons/year) (tans/year) (Ibs/month) PM10 0.01 0.00 0.00 0.01 0.01 2 PM2.5 0.01 0.00 0.00 0.01 0.01 2 sox 0.00 0.00 0.00 0.00 0.0 0 NOx 0.13 0.00 0.00 0.13 0.1 22 VOC 73.85 - 0.00 0.00 73.85 3.7 627 CO 0.58 0.00 ' 0.00 0.58 0.6 98 Potential to Emit Actual Emissions Requested Permit Limits Hazardous Air Pollutants Uncontrolled Uncontrolled Controlled Uncontrolled Controlled (lbs/year) (lbs/year) (lbs/year) (lbs/year) (lbs/year) Benzene 2011 0 0 2011 101 Toluene 5572 0 0 5572 279 Ethylbenzene 415 0 0 415 21 Xylene 4212 0 0 4212 211 n -Hexane 10819 0 0 10819 541 224 TMP 8 0 0 0 0 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit RACP- Regulation 3, Part B, Section III.D.2.a (See regulatory applicability worksheet for detailed analysis) The loadout must operate with submerged fill and loadout emissions must be routed to flare to satisfy RACE. Section 07- Initial and Periodic Sampling and Testing Requirements Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes For this modification; the coo otaltgadjusting combus�tab.emissf n associated With _he enclosed combusto DCP proposed to allocate the pilot IighE for the enclosed combust r`ECovrevei added to the condensateaanks (Po nt OSOI. Ther. are n to the loadout emissionsdiscussed in the PA for issuance 3, the source used AP 42, Chapter 5.2 to calCWate [badirrgiP € Waafs s o used tR the mural ap h Tb Source s increasing thew stages floWrate c,pc fr3f/ y S. scf h7to t.25Slshr because the r,Iculat re adjusted to12.2',pore ln8tead of,14- apftgeafjg 7(rw odfae i � (spt ncreas ng It aticontent from 3397 btu/scfto 3672 b)yJ l i oiitc t5 alsvi:using NOXl- and COCU eswn factors from A. a:04a:044J gtapto-13 instead Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 051 Process# SCC Code 01 4-06-001-32 Crude Oil: Submerged Loading Normal Service (S=0.6) Uncontrolled Emissions Pollutant Factor Control % Units PM10 0,00 0 lb/1,000 gallons transferred PM2.5 0.00 0 lb/1,000 gallons transferred SOx 0.00 0 lb/1,000 gallons transferred NOx 0.01 0 lb/1,000 gallons transferred VOC 4.8 95 lb/1,000 gallons transferred CO 0.04 0 lb/1,000 gallons transferred Benzene 0.07 95 lb/1,000 gallons transferred Toluene 0.18 95 lb/1,000 gallons transferred Ethylbenzene 0.01 95 lb/1,000 gallons transferred Xylene 0.14 95 lb/1,000 gallons transferred n -Hexane 0.35 95 lb/1,000 gallons transferred 224 TMP 0:00 95 lb/1,000 gallons transferred 19 of 33 K:\PA\2012\12 W E2024.CP4.xlsx Hydrocarbon Loadout Regulatory Analysis Worksheet Colorado Re- lotion 3 Perts A and R- AP EN and Penult Requirements Source is in the Non -Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section ll.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, section 11.0.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than lO TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section 11.0.31? Not enough Information NON -ATTAINMENT 1: Are uncontrolled emissions from any criteria pollutants from this individual source greaterthan 1 TPY (Regulation 3, Part A, Section ll.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section 11.0.1.0? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate vla splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section HHA.21? (Source requires a permit EEE Et., ly'. Yell Go to next Go to quesi The loadou 7. RACT-Are uncontrolled VOC emissions from the loadout operation greater than 20 tpy (Regulation 3, Part B, Section lll.D.2.a)? 'aW The loadou 'The loadout must operatewith submerged fin and loadout emissions must be routed to flare to satisfy RACT. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, end Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not applyto a particular situation based upon the individual facts and circumstances. This document does not changeor substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act., its implementing regulations, and Air Quality Control Commission regulations, the language of the statute orragulatlon will control. The use of non -mandatory language such as recommend,"may,"should,' and 'can,'is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and 'required' are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Hydrocarbon Loadout Emissions Inventory Section 01- Administrative Information (Facility AlRs ID: Co, 0107 D56 Plant Pc nt Section 02- Equipment Description Details Unloading of condensatefrum pressunaed tank trucks to pressurized condensate feed to Detailed Emissions Unit Description: and emissions only released tothe atmosphere during hose disonnect. Emission Control Device Description: Is this loadout controlled? cm this coerce are not controlled. Requested Overall VOC & HAP Control Efficiency %: Section 03- Processing Rate Information for Emissions Estimates Primary Emissions - Hydrocarbon Loadout Truck Loadout Capacity Condensate Unloaded Loadouts/month Loadouts/year Secondary Emissions - Combustion Device(s) 70011 gallons/load 1:405,250.7: gallons/month 401,500.00 bbl/year 201 loadout/month 2,409.00 Ioadout/year Section 04- Emissions Factors & Methodologies Loadout Hose Parameters Liquid Hose Diameter Vapor Hose Diameter Liquid Hose Length* Vapor Hose tenth" Liquid Hose Volume Vapor Hose Volume 0.166666667 0:166666667 feet feet feet feet cubic feet cubic feet 5 1.5 0.0327 0.0327 Tank and Truck Pressure Tank ad truck prsure 97 109.2 psig psia Load u vapor balance 0.00 MMBTU per year MMBTU per year MMBTU per year • Notes: *Length accounts for length of isolation valve on pressurized hose. There are two hoses connected to each truck during loadout. PVrenRT Where: P = pressure in hose at time of disconnect = storage tank pressure (psia) V =volume of hoses (cubic feet) umber of lb -males of product in hoses R =Universal gas constant =10.73 fta3 * psi / Ibmole / degR T = average loadout temperature = 60'F = 519.67R Vapor Density n 0.000640876 Ihmol n/V 0.019583724 lbmol/ft^3 MW f� ,.__ ;4/l.01b/Ibmol Vapor Density 0.861304733 lb/ft03 Liquid Density SGT(';; _(1.6152 Density of Water ) 8.33 lb/gallon Liquid Density 5.141276 Ih/gallon 38.45674448 Ih/ft^3 Notm: 1. All liquid lines contain liquid products at individual specific gravity. 2. All vapor retum lines contain products that behave as ideal gases et 60'F and storage tank pressure. Uncontrolled VOC Emissions: Vapor Emissions 67.90 lb/year 0.03 tpy Liquid Emissions 3,031.71 lb/year 1.52 tpy Total _missions 1.55 oCP requested Total 1.55 tpy 5.66 i6/month 252.64 lb/month Component Mass Fraction Source Benzene 0.905% Renrccentat c c S: mple fSee Section 00 for notes) Toluene 0.953% Re prtrsentative Sample )5 Section 06 for notes) Ethylbenzene 0.150% eoresentatniasnmp (Sae Sect on 08 iv: notes) %yiene 0,01% 1. rre,entat teS'''''P''.I.,er S,...a.:. notes} n -Hexane 0.075% 0rpre ettatv_Sramp(Sae_ Senr,an 08 fernotes) 224 TMP 0.304% Retire entaGve Sara pl (See Scct o t CII ,or netccl 0.12915052 total tons per month 21 of 33 K:\PA\2012\ 12WE2024.CP4.xls% Hydrocarbon Loadout Emissions Inventory Pollutant Hydrocarbon loadout Uncontrolled Controlled )lb/loadout event) (lb/loadout event) (Volume Loaded) (Volume Loaded) 0.0006 0.0039 Emission Factor Source MMIlMnIMMEt Pollutant 0.0039 Control Device Uncontrolled (Ib/MM Btu) Uncontrolled )lb/bbl) (Volume Loaded) 0.00E+00 0.00E+00 0.00E+00 0.ODE +00 0.00E+00 (waste heat combusted) Section 05- Emissions Inventory Emission Factor Source Criteria Pollutants Potential to Emit Uncontrolled (tom/year) Actual Emissions Uncontrolled Controlled (tom/year) (tore/year) Requested Permit Limits Uncontrolled Controlled (tom/year) (tons/year) PM10 PML5 SOx NOx VOC CO 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.55 1.55 1.55 1.55 1.55 0.00 0.00 0.00 0.00 0.00 Hazardous Air Pollutants Potential to Emit Uncontrolled (Ibs/year) Actual Emissions Uncontrolled Controlled (Ibs/year) (IM/Year) Requested Permit Limits Uncontrolled Controlled (Ibs/year) (Ibs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP 29.92 29.92 29.92 30 30 _ 29.53 29.53 29.53 30 30 1.55 1.55 1.55 2 2 9.34 9.34 9.34 9 9 250.30 250.30 250.30 250 250 9.41 9.41 9.41 9 9 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, 8 RACE- Regulation 3, Part B, Section II I.D.2.a (See regulatory applicability worksheet for detailed analysis) Section 07- Initial and Periodic Sampling and Testing Requirements You have indicated above the source is not controlled. The following question does t require an answer. Source requires a permit The loadout operation must satisfy RACi. 263 Section 08 - Technical Analysis Notes This operation is en existing operation that had previously been classified as an inngnificant activity. The source is now requesting to permit the operation above APEN-thresholds. TM. unloading -accounts fnr condensate that wit( he trucked: in front pressurized storage tanks at field booster stations and unloaded at the facility . The condensate is combined with the condensate produced at this facility upstream of the stabilizer and is ffashed and stabilized before discharge tustoragetanks(fyint000). Based on the information provided in the application, emissions only occur from a pressurized loadout operation when the hoses used to transfer fluids are disconnected and vented to the atmosphere Loadout occurs from a pressurized tank -truck . essel to a pressurized storage vessel (condensate feedtanks) operating at the same pressure.. DIP used the same emissions Calculation approach as for their proposed Big Horn GasPlant 18V/E0465). The molecular weight of the gas, density of Me liquid and mass fractions ofHAPs used to estimate the HAP emissions were obtained from a representative sample of unstablized condensatotaken from DCP's O'Connor Plant on. 2/5/141 W hl(e the sample isnotSite specificand more than one-year old, it was determined an Initial compliance test requiting site -specific sample_ be obtained was not required since the condensate being trucked in Will be of composition p Q p ry significantly reporting based on the assuming the tire volume afhose is varyingcm and ); y representative t osarhp,(e I addition, is conservatively eporting (n this emitted. Requiringsrb00 initial specific obtained and used to estimate etossio s from this source not have a significant impact th p from 21 sour anm p p g pa hepermitoremissions and is not warranted at This is a new source (came into service after-13/20/07(located lathe ozone nunattalnniet area. As a result, this source issubject to RACi. Based: on inforto ton provided, the loadout operation transfers fluid front pressurized_ storage veweis to pressurized tank trucks As the loadodt. operation Is conducted the vapors dlsplaced from the memorized trucks is routed back tthe pressurized storage vessels As a rult, endssions only occur when the liquid l and vapor hoses are disconnected after completion of the loadout operation. Based on this information, the operator is using vapor balance with pressurized vessels This method ofitherations satisfies RACE. AOCC Regulation? SectionV indicates 5Nopersonshall dispose of volatile organic compound's by evaporation or spillage unless RACE O utilized Emissionsthat result from the hose disconnect, as coveredby this emissions point, are less. than 20tpy VOC. The Division boon,sed 20 tpyas e' cutoff for requiring further PACT analysis; on loadout points at similar facilities, Therefore, no -further RACT analysis is necessary for this point ' AIRS Point U 056 Process If 01 5CC Code Section 09- Inventory 5CC Coding and Emissions Factors Uncontrolled Emissions Pollutant Factor Control % Units VOC 1.846-01 0 Ib/1,000 gallons transferred n -Hexane 1.486-02 0 lb/1,000 gallons transferred 22 of 33 K:\PA\2012\12 W E2024.CP4.xlsx Hydrocarbon Loadout Regulatory Analysis Worksheet Colorado Re ulation 3 Parts A and B - APEN and Permit Requirements ' Source is in the Non -Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section II.D.1.a)? 2. Is the loadout located at an exploration and production site (e.g., well pad) (Regulation 3, Part B, Section II.D.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10TPY (Regulation 3, Part B, Section II.D.3)? 'Not enough information NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1TPY (Regulation 3, Part A, Section ll.D.1.a)? 2. Is the loadout located at an exploration and production site.(e,g„ well pad) (Regulation 3, Part B, Section 11.0.1.1)? 3. Is the loadout operation loading less than 10,000 gallons (238 BBLs) of crude oil per day on an annual average basis? 4. Is the loadout operation loading less than 6,750 bbls per year of condensate via splash fill? 5. Is the loadout operation loading less than 16,308 bbls per year of condensate via submerged fill procedure? 6. Are total facility uncontrolled VOC emissions from the greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY (Regulation 3, Part B, Section 11.0.2)7 It req mi Go to next question. 7. RACE -Are uncontrolled VOC emissions from the loadout operation greater than 20 tpy (Regulation 3, Part B, Section III.D.2.a) i The loadout nperRACT. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, Its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as "recommend," may," "should," and "can," is intended to describe APCD interpretations and recommendations. Mandatory terminology such as "must" and "required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself. Soto question 6 The loadout requires a permit The loadout operation must satisfy RACI. Produced Water Storage Tank(s) Emissions Inventory Section 01- Administrative Information Facility AIRs ID: County Plant 057 Pain Section 02 - Equipment Description Details Detailed Emissions Unit Description: One (1) 400 bbl fir Emission Control Device tit*. Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Produced Water Throughput = 'Requested Permit Limit Throughput = Potential to Emit (PTE) Produced Water Throughput = Secondary Emissions - Combustion Device(s) Heat content of waste gas= f,aUi'i`i\ 3b7T Btu/scf Volume of waste gas emitted per BBL of liquids produced = u-;;;Ilyf100'4f,:scf/bbl Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Barrels (bbl) per year Barrels (bbl) per year Barrels (bbl) per year Actual Produced Water Throughput While Emissions Controls Operating= 8, -s�'37z.. �� Requested Monthly Throughput = 2548 Barrels (bbl) per month 0 MMBTU per year 199 MMBTU per year Potential to Emit (PTE) heat content of waste gas routed to combustion device = 199 MMBTU per year Section 04- Emissions Factors & Methodologies Will this storage tank emit flash emissions? Emission Factors Produced Water Tank Pollutant Uncontrolled Controlled (lb/bbl) (Ib/bbl) (Produced Water Throughput) (Produced Water Throughput) VOC 0,262 0.0131 0.0004 0.000 0.000 0.000 0.0011 0.000 Control Device Benzene Toluene .._0.007 Ethylbenzene Xylene n -Hexane 224 TMP 0:022 ;l7 Emission Factor Source Emission Factor Source Pollutant Uncontrolled Uncontrolled (Ib/MMBtu) (lb/bbl) (waste heat combusted) (Produced Water Throughput) PM10 PM2.5 4.94E-05 4.94E-05 0.0005 0,0021 0.0075 NOx CO 0.3100 vo. Section OS - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC PM10 PM2.5 NOx CO 3.9 0.0 0.0 3.9 0.2 33 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0 0.0 0.0 0,0 0.0 0.007 1 0.0 0.0 0.0 0.0 0.03 5 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (Ibs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene "Ethylbenzene Xylene n -Hexane 224 TMP 210 0 0 210 11 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 660 0 0 660 33 0 0 0 0 0 ion 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XVII.B, C.1, C.3 Storage Tank is not subject to Regulation 7, Section XVII Regulation 7, Section XVII.C.2 Storage Tank is not subject to Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart 0000 Storage Tank is not subject to NSPS 0000 (See regulatory applicability worksheet for detailed analysis) 24 of 33 K:\PA\2012\12W E2024.CP4.xlsx Produced Water Storage Tank(s) Emissions Inventory Section 07- Initial and Periodic Sampling and Testing Requirements Does the company use a site specific emissions factor to estimate emissions? F; If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid water sample drawn at the facility being permitted and analyzed using flash liberation analysis? This sample should be considered representative which generally means site -specific and collected within one year of the application received date.'' However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor. See P5 Memo Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Questions 5.9 and 5.12 for additional guidance on testing. Section 08- Technical Analysis Notes tank is an existing tank but has not been;. source used state default emissronfador Section 09- Inventory SCC Coding and Emissions Factors AIRS Point # Process # SCC Code 057 01 4-04-003-15 Fixed Roof Tank, Produced Water, working+breathing+flashing losses Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.00 0 lb/1,000 gallons liquid throughput PM2.5 0.00 0 lb/1,000 gallonsliquid throughput NOx- 0.01 0 1b/1,000 gallons liquid throughput VOC 6.2 95 lb/1,000 gallons liquid throughput CO 0.05 0 lb/1,000 gallons liquid throughput Benzene 0.17 95 lb/1,000 gallons liquid throughput Toluene 0.00 95 lb/1,000 gallons liquid throughput Ethylbenzene 0.00 95 lb/1,000 gallons liquid throughput Xylene 0.00 95 lb/1,000 gallons liquid throughput n -Hexane 0.52 95 lb/1,000 gallons liquid throughput 224 TMP 0.00 95-lb/1,000 gallons liquid throughput 25 of 33 K:\PA\2012\ 121A1E2024.CP4.xlsx Produced Water Storage Tank Regulatory Analysis Worksheet Please note that NIPS Kb might be might be applicable for certain tanks at water management and injection facilities. If the tanks you are reviewing are at one of these facilities, please review N5 PS Kb. Colorado Re ulatlon 3 Parts A and APEN and Permit Requirements Source is in the Nan.Attainment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this Individual source greater than 2 TPY (Regulation 3, Part A, Section llA.l.e)7 2. Is the operator claiming less than 1% crude oil and Is the tank Ideated eta non-commercial facility for processing oil and gas wastewater? (Regulation 3, Part B, Section 11.0.1.M) 3. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part B, Section 11.0.3)7 'Not enough Information NON -ATTAINMENT 1 Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation3, Part A, Section ll.D.1.a)7 2. Is the operator claiming less than 1% crude oil and is the tank located at a non-commercial facility for processing oil and gas wastewater? (Regulation 3, Part B, Section II.D.1.M) 3. Are total facility uncontrolled VOC emissions greater than 2 TPY, NOx greater than 5 TPY or CO emissions greater than to TPY (Regulation3, Part B, Section 11.).2)7 'Source requires a permit Colorado Regulation 7, Section XVII 1. Is this tank located at a tansmisslon/storage facility? 2. Is this produced water storage tank' located at an oil and gas exploration and production operation , well production facility, natural gas compressor station' or natural gas processing plant? 3. Is this produced water storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions° of this storage tank equal to or greater than 6 tons per year VOC? wordi NEM No Yes 3 'Storage Tank is not subject to Regulation 7, section XVII Section XVII.B—General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1-Emissions Control and Monitoring Provisions Section XVI I.C.3 - Recordkeeping Requirements 5. Does the produced water storage tank contain only "stabilized" liquids? If no, the following additional provisions apply. 'Storage Tank is not subject to Regulation 7, Section XVII.C.2 Section XVII.C.2- Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR. Part 60. Subpart 0000, Standards of Performance far Crude Oil and Natural Gas Production. Transmission and efateibutlon 1. Is this produced water storage vessel located ata facility In the onshore oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the Industry? 2. Was this produced water storage vessel constructed,reconstructed, or modified (see definitions 40 CFR,60.2) betweenAugust 23, 2011 and September 18, 20157 3. Are potential VOC emissions' from the individual storage vessel greater than or equal to a tons per year? 4. Does this produced water storage vessel meet the definition of "storage vessel"' per 6054307 'Storage Tank Is not subject to NSPS 0000 Subpart A, General Emulsions per 460.5425 Table 3 §60.5395 - Emissions Control Standards for VOC §60.5413 -Testing and Procedures §60.5395(g) -Notification, Reporting and Recordkeeping Requirements §60.5416(c)- Cover and Closed Vent System Monitoring Requirements §60.5417 -Control Device Monitoring Requirements• (Note, if a storage vessel Is previously determined to he subject to NSPS 0000 due to emissions above 6 tons per year VOC on the applicability determination date, it should remain subject to NSPS 0000 per 60.5355(e)(2) even if potential VOC emissions drop below 6 tons per year] RACE Review RACE review is required If Regulation 7 does not apply AND if the tank is in the non -attainment area. If the tank meats both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Act, its implementing regulations, and Air Qualify Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act„ its implementing regulations, and Air Quality Control Commission regulations, the language of the statute or regulation will control. The use of non -mandatory language such as 'recommend,"may," "should," and "can,"is intended to describe APCO interpretations and recommendations. Mandatory terminology such as "must" and required" are intended to describe controlling requirements under the terms of the Clean Air Act and Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of itself Yes Source Req Go to next Source Req Continue-' Continue-' Go to then Storage Tar 'Storage Tar MMIN Continue-' Go to then Storage Tar Produced Water Storage Tank(s) Emissions Inventory - 001 Produced Water Tank Facility AIRS ID: County Plant Point Section 02- Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions -Storage Tank(s) Actual Produced Water Throughput = Requested Permit Limit Throughput = ij3j62 Barrels (bbl) per year Potential to Emit (PTE) Produced Water Throughput = tnaliMaIMBerrels (bbl) per year Actual Produced Water Throughput While Emissions Controls Operating= Requested Monthly Throughput = 302.4681 3629.618 308 Barrels (bbl) per month Secondary Emissions - Combustion Device(s) Heat content of waste gas= Volume of waste gas emitted per BBL of liquids produced = Actual heat content of waste gas routed to combustion device = Requested heat content of waste gas routed to combustion device = Barrels (bbl) per year Btu/scf cf/bbl Potential to Emit (PTE) heat content of waste gas routed to combustion device = Section 04- Emissions Factors & Methodologies Will this storage tank emit flash emissions? 0 MMBTU per year 0 MMBTU per year 0 MMBTU per year Pollutant ISZEMME IMMEEEMI Produced Water Tank Uncontrolled Controlled (lb/bbl) (lb/bbl) (Produced Water Throughput) Pollutant aszr (Produced Water Throughput) 0.000 0.000 0.000 0.000 0.000 Control Device Uncontrolled Uncontrolled (Ib/MMBtu) (lb/bbl) (waste heat combusted) (Produced Water Throughput) 0.0000 0.0000 0.0000 0.0000 Emission Factor Source Emission Factor Source Section 05 -Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) VOC PM10 PM2.5 NOx CO 0.2 0.0 0.0 0.2 0.2 39 0.0 0.0 0.0 0.0 0.0 0 0,0 0.0 0.0 0.0 0.0 0 0,0 0.0 0.0 0.0 0.0 0 0.0 0.0 0;0 0.0 0.0 0 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane Methanol 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 461 0 0 461 461 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source is APEN required since methanol emissions > 250 lb/yr. It is also permit required since facility -wide VOC emissions>5 tpy Regulation 7, Section XVII.B, C.1, C.3 Not applicable - Regulation 7, Section XVII.C.2 Tank is not subject since uncontrolled actual emissions are less than 6 tpy _ Regulation 6, Part A, NSPS Subpart 0000 Tank is not subject since uncontrolled actual emissions are less than 6 tpy See regulatory applicability worksheet for detailed analysis) 27 of 33 K:\PA\2012\12 W E2024.CP4.xlsx Produced Water Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use a site specific emissions factor to estimate emissions? If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid water sample drawn at the facility being permitted and analyzed using flash liberation analysis? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an alder site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor. See PS Memo 14-03, Questions 5.9 and 5.12 for additional guidance on testing. ' Does the company request a control device efficiency greater than 95% for a flare or combustion device? If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08- Technical Analysis Notes AIRS Point # 058 Section 09 - Inventory SCC Coding and Emissions Factors Process # SCC Code 01 4-04-003-15 Fixed Roof Tank, Produced Water, working+breathing+flashing losses Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.00 0 lb/1,000 gallons liquid throughput PM2.5 0.00 0 lb/1,000 gallons liquid throughput NOx 0.00 0 lb/1,000 gallons liquid throughput VOC 3.0 0 lb/1,000 gallons liquid throughput CO 0.00 0 lb/1,000 gallons liquid throughput Benzene 0.00 0 lb/1,000 gallons liquid throughput Toluene 0.00 0 lb/1,000 gallons liquid throughput Ethylbenzene 0.00 • o lb/1,000 gallons liquid throughput Xylene 0.00 0 lb/1,000 gallons liquid throughput n -Hexane . 0.00 0 lb/1,000 gallons liquid throughput Methanol 3.03 0 lb/1,000 gallons liquid throughput 28 of 33 K:\PA\2012\ 12WE2024.CP4.xlsx Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Section 01- Administrative Information Facility AIRs ID: 123 -,0107 059 t' Plant Point Section 02 - Equipment Description Details Maintenance activities and purging of gas. Activities are controlled by an elevated open process flare. Purge gas prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is residue gas and helps the flare maintain a minimum required positive flow through the system. Also includes combustion from pilots. The flare is also a back up control device. Control Efficiency ' 95% Section 03 - Processing Rate Information for Emissions Estimates Flare Pilot Rating . . 0.256932 MMBtu/hr based on manufacturer's spec of 78 scfh per pilot and assuming 3 pilots Fuel Gas Heat Value 1098 Btu/scf 0.256932 MMBtu/hr 2.04984 MMscf/yr 2250.72432 MMBtu/yr 0.174 Flare Purge Gas Rate 1585.1 scf/hr 1.740 MMBtu/hr 13.89 MMscf/yr 15246.2526 MMBtu/yr 1.179 Residue Gas Slowdown to Fli 372.32 scf/hr 0.40881 MMBtu/hr 3.26 MMscf/yr 3581.15247 MMBtu/yr 0.277 Residue Gas Heat Value 1098 Btu/scf Inle Gas Slowdown to Flare 1546.46 scf/hr 2.02741 MMBtu/hr 13.55 MMscf/yr 17760.1034 MMBtu/yr 1.151 Inlet Gas Heat Value 1311 Btu/scf Refrig System Slowdown to F 250.17 scf/hr 0.62943 MMBtu/hr 2.19 MMscf/yr 5513.78683 MMBtu/yr 0.186 Refrig Gas Heat Value 2516 Btu/scf Purge + Maintenance 32.89 MMscf/yr Hours of operation 8760 hr/yr Total 5.06301594 MMBtu/hr 34.93531800 MMscf/yr MMscf/month 2.967 Section 04- Emissions Factors & Methodologies PURGE GAS AND RESIDUE GAS SLOWDOWN 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/Ib-mol) at 60F and 1 atm Maximum Vent Rate I 1957.42 scf/hr RequestedThroughput (0) 17 MMscf/yr 1957.4 scf/hr I 0.047 MMscf/d 1.46 MMscf/mo % Vented 100% MW 18.30016Hb-mol Component mole % MW Ibx/Ibmol mass fraction E lb/hr Ib/yr tpy Helium 0 4.0026 0.000 0.000 Helium 0.0 0 0.00 CO2 1.3323 44.01 0.586 0.032 CO2 3.0 26528 13.26 N2 0.587 28.013 0.164 0.009 N2 0.8 7440 3,72 methane 85.9465 16.041 13.787 0.753 methane 71.2 623747 311.87 ethane 10.9474 30.063 3.291 0.180 ethane 17.0 148899 74.45 propane 1.1818 44.092 0.5211 0.028 propane 2.7 23575 11.79 isobutane 0.0272 58.118 0.0158 0.001 isobutane 0.1 715 0.36 n -butane 0.0384 58.118 0.0223 0.001 n -butane 0.1 1010 0.50 isopentane 0.0014 72.114 0.0010 0.000 isopentane 0.0 46 0.02 n -pentane 0.0008 72.114 0.0006 0.000 n -pentane 0.0 26 0.01 cyclopentane 70.13 0.0000 0.000 cyclopentane 0.0 0 0.00 n -Hexane 86.18 0.0000 0.000 n -Hexane 0.0 0 0.00 cyclohexane 84.16 0.0000 0.000 cyclohexane 0.0 0 0.00 Other hexanes 86.18 0.0000 0.000 Other hexanes 0.0 0 0.00 heptanes 100.21 0.0000 0.000 heptanes 0.0 0 0.00 methylcyclohexane 98.19 0.0000 0.000 methylcyclohexane 0.0 0 0.00 224-TMP 114.23 0.0000 0.000 224-TMP 0.0 0 0.00 Benzene 78.12 0.0000 0.000 Benzene 0.0 0 0.00 Toluene 92.15 0.0000 0.000 Toluene 0.0 0 0.00 Ethylbenzene 106.17 0.0000 0.000 Ethylbenzene 0.0 0 0.00 Xylenes 106.17 0.0000 0.000 Xylenes 0.0 0 0.00 C8+ Heavies 315.000 0.0000 0.000 C8+ Heavies 0.0 0 0.00 Notes 100.0628 VOC mass fraction: 0.0306 Total VOC Emissions (Uncontrolled) 12.69 Mole % MW, and mass fractions are oased on data from Meter #306409 for Lucerne 2. DCP also provided a 2017 extended gas analysis showing HAPs at 'NIL". Emissions are based on 8760 hours of operation per year. MW of C8+ is assumed to be 315 INLET GAS BLOWDOWN Maximum Vent Rate I 1546.46 scf/hr RequestedThroughput (Q) 13.5 MMscf/yr % Vented I 100% MW 22.700lb/fb-mol 1546.5 scf/hr 0.037 MMscf/d 1.15 MMscf/mo Component 'Imole% BMW Ibx/Ibmol I mass fraction IE IIblhr Ilb/yr Itpy 2.79 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division Helium 0.02 4.0026 0.001 0.000 Helium 0.0 29 0.01 CO2 2.3 44.01 1.012 0.045 CO2 4.1 36181 18.09 N2 - 0.47 28.013 0.132 0.006 N2 0.5 4706 2.35 methane .71.51128 16.041 11.471 0.505 methane 46.8 410024 205.01 ethane 13.8985 30.063 4.178 0.184 ethane 17.0 149350 74.67 propane 7.6347 44.092 3.3663 0.148 propane 13.7 120325 60.16 isobutane 0.8657 58.118 0.5031 0.022 isobutane 2.1 17984 8.99 n -butane 2.328 58.118 1.3530 0.060 n -butane 5.5 48361 24.18 isopentane 0.3815 72.114 0.2751 0.012 isopentane 1.1 9834 4.92 n -pentane 0.395 72.114 0.2849 0.013 n -pentane 1.2 10182 5.09 cyclopentane 0.021 70.13 0.0147 0.001 cyclopentane 0.1 526 0.26 n -Hexane 0.0446 86.18 0.0384 -- 0.002 n -Hexane 0.2 1374 0.69 cyclohexane 0.0096 84.16 0.0081 0.000 cyclohexane 0.0 289 0.14 Otherhexanes 0.0847 86.18 0.0730 0.003 Otherhexanes 0.3 2609 1.30 heptanes 0.0166 100.21 0.0166 0.001 heptanes 0.1 595 0.30 methylcyclohexane 0.0041 98.19 0.0040 0.000 methylcyclohexane 0.0 144 0.07 224-TMP 0 114.23 0.0000 0.000 224-TMP 0.0 0 0.00 Benzene 0.0088 78.12 0.0069 0.000 Benzene 0.0 246 . 0.12 Toluene 0.0026 92.15 0.0024 0.000 - Toluene 0.0 86 0.04 Ethylbenzene 0.0001 106.17 0.0001 0.000 Ethylbenzene 0.0 4 0.00 Xylenes 0.0004 106.17 0.0004 0.000 Xylenes 0.0 15 0.01 C8+ Heavies 0.0025 315.000 0.0079 0.000 . C8+ Heavies 0.0 281 0.14 99.99968 VOC mass fraction: .2623 Emissions (Uncontrolled) PLUS lIJE, Safety factor Notes Mole %, MW, and mass fractions are based on 5/10/18 analysis of Pre -amine gas at Lucerne II Emissions are based on 8760 hours of operation per year. MW of C8+ is assumed to be 315 REFRIGERANT GAS BLOWDOWN Maximum Vent Rate I 250.17 scf/hr RequestedThroughput (Q) 2.2 MMscf/yr 250.2 sct/hr I 0.006 MMscf/d I 0.19 MMscf/mo % Vented 100% MW 43.900 Ib/Ib-mol Component mole % MW Ibx/Ibmol mass fraction E lb/hr Ib/yr tpy . Helium 0 4.0026 0.000 0.000 Helium 0.0 0 0.00 CO2 0 44.01 0.000 0.000 CO2 0.0 0 0.00 N2 0 28.013 0.000 0.000 N2 0.0 0 0.00 methane 0 16.041 0.000 0.000 methane 0.0 0 0.00 ethane 0.5073 30.063 0.153 0.003 ethane 0.1 882 0.44 propane 99.4447 44.092 43.8472 0.999 propane 28.9 253537 126.77 isobutane 58.118 0.0000 0.000 isobutane 0.0 0 0.00 n -butane 0.048 58.118 0.0279 0.001 n -butane 0,0 161 0.08 isopentane 72.114 0.0000 0.000 isopentane 0.0 0 0.00 n -pentane 72.114 0.0000 0.000 n -pentane 0.0 0 0.00 cyclopentane 70.13 0.0000 0.000 cyclopentane 0.0 0 0.00 n -Hexane 86.18 0.0000 0.000 n -Hexane 0.0 0 0.00 cyclohexane 84.16 0.0000 0.000 cyclohexane 0.0 0 0.00 Otherhexanes 86.18 0.0000 0.000 Otherhexanes 0.0 0 0.00 heptanes 100.21 0.0000 0.000 heptanes 0.0 0 0,00 methylcyclohexane 98.19 0.0000 . 0.000 methylcyclohexane 0.0 0 0.00 224-TMP 114.23 0.0000 0.000 224-TMP 0.0 0 0.00 Benzene 78.12 0.0000 0.000 Benzene 0.0 0 0.00 Toluene 92.15 0.0000 0.000 Toluene 0.0 0 0.00 Ethylbenzene 106.17 0.0000 0.000 Ethylbenzene 0.0 0 0.00 Xylenes 106.17 0.0000 0.000 Xylenes 0.0 0 0.00 C8+ Heavies 315.000 0.0000 0.000 C8+ Heavies 0.0 0 0.00 100 DC PLUS ETHANE mass fraction: 1.0029 Total VOC + Ethane Emissions (Uncontrolled) Notes 127.3 Mole %, MW, and mass fractions are based on 7/10/17 Liquids analysis at Lucerne II. Application did not include the analytical report Emissions are based on 8760 hours of operation per year. MW of C8+ is assumed to be 315 Sub -Total of Uncontrolled VOC and HAP Emissions tpy lb/yr VOC 257.0 Benzene 0.1229 246 Toluene 0.0428 86 Ethylbenzene 0.0019 4 Xylene 0.0076 15 n -Hexane 0.7 1374 0 PILOT LIGHT COMBUSTION EMISSIONS Pollutant Uncontrolled Emission Factors Emission Factor Source Total Emissions Ib/MMscf lb/MMBtu lb/yr tpy VOC 5.50 0.0054 A�tha t 2.'' 0.01 Benzene 0.0021 L+.0000 ',A'42`C4 f�I`P3,'' P0.0046 0.000 Toluene 0.0034 0.0000 . 1k 9 0.0075 0.0.00 Ethylbenzene 0.0 0.000 Xylene n -Hexane 1.800 0.0016 ;f •„ ,• f ,«. ,,., : !s".`,. 4.0 0.002 A check for H2S emissions H2S lb/MMscf H2S in Process Gas 15633 Acid Gas Molar Volume to Molar Mass 7.4721 502 2.6042 H2S 0.1154 0.4616 41.7773 H2S in Process Gas SO2 combustion emissions 6 ppm 379 64.05 34.08 19 lb/yr 35 lb/yr SOURCE CONSEF 1 5.9206 0.0023 1.9376 Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment Air Pollution Control Division 224 - Trimethylpentane ! -'� _ ` - 0.0 0.000 PM10 ",z 7 6 ....110075 s„ 16.8 , - 0.0..: PM2.5 7.6"""" "` "--0.0075 ";; - r __ �_ ,_ .,-- _ � : t - -::168 0.0- 502 J":, i.' 0.6 "" - . 0.0006 NOx 1110.000000'. 0.0980 . 2 % ` - 220.? .' 0.1 CO 84.000000 0.0824 A2 &Z€ 185.4 D. COMBUSTION EMISSIONS FOR PURGE GAS/BLOWDOWN/MAINTENANCE ACTIVITIES Pollutant Uncontrolled Emission Factors Emission Factor Source Uncontrolled Emissions Controlled Emissions lb/MMscf lb/MMBtu lb/yr tpy lb/yr tpy VOC 15632.8 ; � „ ; � r v�', :514091 ' 257,046 ' .ii- 5705.,"!P IBZ 9" "., Benzene -' 7.4721 - 3 m .46. - 0.123 12 '.. Toluene 2,6042 ,<; -;86 0.043' 4__.�"- ORMAR Ethylbenzene 0.1154 --`� - : 4 0.002 0 0.0 Xylene : 0.4616 '. ,; "i t ?�-'1,'---- ,-- 15 -,0.008 1..3 % "... 0.0 n -Hexane 104 224-Trimethylpentane 0.00013 : 0.000 0.-; 01 -�- PM10 „ PM2.5 "• . , f 3 �`J' ra-�`�»�'.. ..: ;, ., ' : 0 'tl 502 3 th2y� ,i .zi 0! id . NOx 87 056 3' ., 11646660 .. - �� - _ ,' 2863 143 , , ! 3 .2863., : . 1' 4 CO _ - 396.87 03100 "_ , a ) �`� .;>�` ,130S1 6.53 13051 " _ _5,5 EF for permit 8.1812 8.1812 lb/31 day 0.6459 19 107.65 16 90.424 Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) PM10 0.0 0.0 0.01 PM2.5 0.0 0.0 0.01 SO2 0.0 0.00 Nox 1.5 1.5 1.5 CO 6.6 6.6 6.6 VOC 257.1 257.1 12.9 Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Kequestec Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (Ib/yr) (ib/yr) Benzene 1.2E-01 0.12 0.01 246 12 Toluene 4.3E-02 0.04 0.00 86 4 Ethylbenzene 1.9E-03 0.00 0.00 4 0 Xylene 7.6E-03 0,01 0.00 15 1 n -Hexane 6.9E-01 0.69 0.03 1378 73 224 TMP 0.0E+00 0.00 0.00 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Unit is required to have an APEN and a permit Regulation 7, Section XVII.B Unit is used to comply with Reg 7 Regulation 7, Section XVII.B.2.e Unit is used as an alternative control device for Reg 7 Produced Natural Gas Venting/Flaring Preliminary Analysis Section 07 - Initial and Periodic Sampling and Testing Requirements Was a site -specific gas sample collected within a year of application submittal used to estimate emissions? If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limits Colorado Department of Public Health and Environment Air Pollution Control Division Does the company request a control device efficiency greater than 95% for a flare or combustion device? t'.= If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 - Technical Analysis Notes -- In this application, DCP is requesting to permit the existing plant flare. OCR informed the division in December 2017 that the plant flare had exceeded APEN thresholds and should have been permitted. In previous permit modifications, the division asked DCP about the plant flare and OCR had insisted the plant flare was an insignificant activity, Since January 2018, DCP has modified the plant to re-route several streams that were not permitted to vent to the plant flare such as streams from the condensate stabilization system. In addition, with this modificat€on, DEP is now correcting the permit to include streams that will continue to be routed to the plant flare. With this modification, DCP is accounting for purge gas and routine maintenance gas routed to the plant flare. PCP is also accounting for the pilot light, OCR provided flare specification sheets to the division's enforcement groupin June 2018. These specification sheets document a pilot flow rate of 78 scfh and DCP stated there are 3 pilots. With the June 2018 submittal, OCR clarified there is a warm flare header and cold flare header and the specification sheet states a minimum purge rate for cold header is 1040 scfh and 290 scfh for the warm header. OCR stated an additional 111 scfh is needed in the warm header to prevent a vacuum on the header. DCP then added, a 10% buffer to the total purge rate which equals 1585.1 scfh. DCP is also assuming the gas composition of residue gas for the purge gas. DCP provided a gas analysis in the application that was based on meter readings. This analysis did not include HAPs. I requested an extended gas analysis to document HAPs. DCP provided an extended gas analysis of residue gas collected 8/23/2017; this sample showed HAPs were below detection limit. I informed DCP that other gas plants have shown HAPs in residue gas. The permit will include a condition to sample the gas routed to the flare. In DCP's June 2018 submittal, DCP only included pilot and purge gas. In the October 2018 submittal, OCR is now also including routine maintenance emissions. Routine maintenance emissions should be included when determining permitted emissions DCP assumed blowdowns from residue gas at 372.32 scfh, inlet gas at 1546.46 scfh and the refrigerant system at 250.17 scfh. OCR also used site -specific pre -amine inlet gas analysis collected 5/10/2018 to estimate inlet gas composition and a site -specific refrigerant liquids analysis collected 7/10/2017 to estimate refrigerant gas composition. For ongoing compliance, DCP will be required to sample the gas composition and meter the volume routed to the flare. This flare is used as backup control device for the TEG dehy (point 048) when theVRU is down for either the still vent or flash tank. This flare is also used as a backup control device for the enclosed combustor controlling the condensate tanks (point 050). Since the TEG dehy and condensate tanks are subject to Regulation 7 requirements, the flare must comply with Regulation 7. Since this flare is an open flare, it must meet the alternative control device requirements. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 059 Process # SCC Code 01 Uncontrolled Emissions Pollutant Factor Control % PM10 0.480 0.0% PM2.5 0.480 0.0% N0x 88.264 0.0% V0C 14715.9 95.0% CO 378.893 0.0% Benzene 7.0338 95.0% Toluene 2.4516 95.0% Ethylbenzen. 0.1086 95.0% Xylene 0.4345 95.0% n -Hexane 39.4397 95.0% 224 TMP 0.0000 #DIV/0l Summary of Project Emissions DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Permit # 12WE2024 AIRS ID 123/0107 PTE - WITH ENFORCEABLE CONTROLS Description erm ted Emissions 'ricr 02 TSP PM10 ns H2S I SO2 I NOx I VOC I PM2.5 Fug VOC I CO Total Facility (TPY) Total Permitted Facility (TPY) 8 8 12.6 225.1 117 8 13.8 231.1 i.n' an: Total Facility (TPY) 13.6 13.6 46.27 241.4 143.55 13.2 31.08 286.03 Total Permitted Facility (TPY) 13.4 13.4 46.27 238.8 142.95 13 31.08 283.23 Project emissions (TPY) 5.4 5.4 33.8 37.4 33.12 5 0 52.1 Facility. rri lions of od ific< Total Facility (TPY) 13.2 13.2 1 47.2 243.6 146.9 13.2 34.8 293 Total Permitted Facility (TPY) 13 13 1 47.2 240.65 146.3 13 34.8 289.9 Change in permitted emissions (TP -0.4 -0.4 1 0.9 1.85 3.3 0 3.7 6.6 Project emissions for Lucerne II ad 5 5 1 34.7 39.6 36.5 5 21 59.1 PTE - WITH ENFORCEABLE CONTROLS Description TSP I PM10 I H2S I SO2 iaatii NOx I VOC PM2.5 I Fug VOC I CO' Total Facility (TPY) 13.0 13.0 1.0 47.1 238.2 149.7 13.0 34.8 300.9 Total Permitted Facility (TPY) 12.7 12.7 1.0 47.0 234.8 145.8 12.7 34.8 297.4 Change in permitted emissions (TP -0.4 -0.4 0.0 -0.2 -5.8 -0.5 -0.4 0.0 7.5 Project emissions for Lucerne II ad 4.8 4.8 1.0 34.6 34.1 38.2 4.8 21.0 66.8 12310107 DCP Midstream. LP Lucerne Gas Processing Plant SWI/4. section 28, TEN, 065W Weld County Edited 1/30/2019 PTE -UNCONTROLLED POINT PERMIT' Description TSP PM10 H25 502 NOx VOC PM2.6 Fug VOC CO Reports ble HAPa Total HAPe TSP PM10 H23 502 NOx VOC PM2.5 Fug VOC CO Reporla ble HAPS Total RAPS REMARKS Previous. FACILRY TOTAL 13.2 13,2 1.0 47.2 243.6 144.9 13.2 34.6 293.0 23.1 24.0 13,2 13.2 17.6 47.2 1457.1 2,262.3 13.2 178.6 1202.0 763.3 771.3 Based an June 2016 spreadsheets Previous Permitted Facility total • 13.0 13.0 1.0 47.2 240.7 146.3 13.0 34.6 289.9 23.1 24.7 000 aV040.? 4,21.4/-S!r.4!.7042GS:;MOW 00 0.0 00 00 3/,,-?-. '2. 2003 002 Aoo. , 000 0 0 1Y 1/0 0.22W042 121 :104,2. '4 ,F;r,P 00 1 G 2203 0.2 -4 .!. - k 4Ai 4C A,+0/ 0 00 0 n3 .. ;:J5 COS T - .;_ 0.0 1,. . v 0 No730,1,0 073 .f 0e,f304f02 .A:4u✓l.xl}A v.tOs3G5r.;ivi:1J 00 u0 pr5r -1,7 'ik 007 I1eS rlsrx: _E 00 CO . 1e'zd 003 03,4£0442 V3 GL ('DEN!_'" t£8' JD 00 <:u �, 2001 0.'n : 5 - -5 /A , r Wa 00 00 ao Pa.0- 5 010 /3603.3., .01 P.35.014.1450!..22 - � 00 LPT, (4,,'a4/ 2.33 Off '4£400 7.7,0',,, -tar :,-.n.,A.e TAWS 00 •, 0 F0 C,._c0/0 IMO 072 F 1 O,0 L 3.,0/' TAW 0.0 00 O.O cor.oZort 3533 0;7 . .130`/2 0033E-135.3 -. 300074 COA'E 1004 - 2/0 07 00 !i.1: 005 Cectseikn0 2003 014 98WE305 Equipment Leaks 13.8 0.7 0.7 47.3 2.5 2,5 No change 015 96WE905 1232 HP Waukesha L7042 ICE 0.3 as 0.0 23.8 11.9 0.8 23.8 0.3 0.4 0.8 0.8 0.0 155.8 11.9 00 139.2 1.0 1.3 No change /40 0501£&95 o0,42s2os Em21',u='T•W21 .._ 00 00 00 072 ,'7,0ou' 0/0 017 96WE905 1232 HP Waukesha L71342 ICE 0.8 0.8 0.0 23.8 11.9 0.8 23.3 03 0.4 0.8 0.8 0.0 155.8 11.9 0.8 1392 1.0 1.3 No change 018 e6WE905 1232 HP Waukesha L7042 ICE 0.8 0.8 0.0 23.8 11.9 0.8 23.6 03 0.4 0.8 0.8 0.0 155.8 11.9 0.8 139.2 1.0 1.3 No change 019 96WE905 1232 HP Waukesha L7042 ICE 0.8 0.8 0.0 23.8 11.0 0.8 23.8 0.3 0.4 0,8 0.8 0.0 155.8 11.9 0.8 1392 1,0 1,3 No change 070 900/3005 WA'vNES'.':4. 3120'1.- F-,;30%. .SW: 305300 '0 0.0- 2r PI'S G', 2.3222210 025 46540405 Gi.70^.. f305.0,90.,:.330/4 5'':57044 - 00 0 0.0` r .,SGsr'.nrsln,.: 20:10 242 0.ro1£'04OD v1Nly'0 01/14352.1,322. S77.7 200031 4..1/ 00 00 0., P/S Cerx:e:002 2002 003 03/40026, 00050 C2012,0,10v.,,:! 0.0 00 0.0✓.0 FT5 C&,. OW: 200S 024 04WE1301 1232 HP Waukesha L7042 ICE 0.8 0.8 00 118 8.3 0.8 23.8 03 04 as 0.8 0.0 130.9 17.8 08 95.2 1.0 1.3 No change 025 041/V51302 1232 HP Waukesha L7042 ICE 08 08 0.0 11.3 8.3 0,8 23.8 03 0.4 0.8 0.8 0.0 130.9 17.8 0.8 95.2 1,0 1.3 No change 002 0/sOn-I/OS F,W - 0n O 2701''O',P7S 0,00,4001,, 000 .. -' 307 ;aaa5 :0 ah4200 00 o 00 0 0' :3 0.,07; a in - Y 0,.,0v100.", - "co` ra.., /,O .., co<;."2.,o 0o. Lan 'sv. 4 't:0225_p 0D f no u. 0. no000/, ' ,.. 0ted 029 05W E0958 ., 1232 HP Waukesha 47042 ICE 0.8 0.8 0.0 23.8 11.9 0.8 23.8 D.3 0,4 08 02 0.0 155.8 11.9 0.8 139,2 1 0 1,3 No change 030 003E0050371 REGENERATION GAS HEATER 0,2 0.2 2.5 02 2,1 DA 0.0 02 02 2.5 0.2 21 00 0.0 No change(APEN-required/permkexamp0 031 0`03";05100 f.' /,,'ear 03300:0 220 HP. SM: Tar, 00 .0 00 a, PT£ Geocdxr: 200'2 032 074550021 WAUKESHA L7042001 RICE, SN: 0-17495/1 1.0 1.0 0.0 28S 14.3 1.0 28.5 02 0.5 1.0 1.0 0.0 185.5 28.5 1.0 1285 1.`. 6 No change 033 071111E0379 WAUKESHA L5794 GS/ SN: 0-17413/1 0.9 09 26,7 13.3 O9 26.7 0.4 0.1 0.8 0.9 185.2 26.7 0.9 1159 1, 5,4 No change 0.94 06'05700 Co; Cm,..421, G2006 TALE7 ;e.scs,vmssiew;op0iio ,220 HP 02 '19 2..O kW. ra . 025 POKE:22'2,N I4 LEh' erg. 23' I e. 00 d aan . 030 03i44:0014 r7 003,0ill, 0 s,a, T,L0. Notuol./00410,,,,,000,0-,, 0 '4d 20 0.n an P -025 0 6W 31/303,31,. 2:2,7 G2 f P F' : 0D 0� 00 8 ,.37 • 00 ,2.2 '.0/. ,q^e,k10 i.iP n „, 0D t ,..0250.! 030 ,009 2010 M. <..<._00 r.. _ a .0 ... HP 00 00 ` 1'5(150142 -' I 00 '40 ,.. 1 f0/ S' .. 285".2. 1 . -._ _. O0 oO r: 4 h . . 0.2/0:0..20!, Sala, '0/1.,535 o,.., awy,SOP ,2_ .,: O0 00 mr:'z.'2'010.4ve.Ood,440:0000,20 042 OBWE0020 Amino unk wl Thermal oxidizes, model 3SN: TED 12.3 0.8 5.7 4,3 4.5 4.5 12.3 0.0 569.7 4,3'450.0 4508 No change 043 08W00921 Two Amine regeneration heaters, model8 SNs: IMO 0.5 0.5 2,6 04 0.5 5.1 00 0.1 0,5 0.5 2.6 04 0.5 5.1 0.0 0,1 No change 044 12W02024 Natural gas turbine rated 165.99 MmbtU/hr 1,9 1.9 1.D 11.5 0.7 1.9 18.3 02 0,3 ' 1,9 1.9 1,0 11.5 0.7 1.9 183 02 0,3 Ropalced Updated 11rb/heat 3400000ntent from No,99 rUld/Ou/scf to 098 045 12111/02024 Natural gas turbine ratedel 05.99 Mmbtufhr 1,9 1.9 1,0 11.5 0,7 1.9 13,3 02 0.3 1.9 1,9 1.0 11.5 0.7 t,9 18,3 0.2 0,3 Rapakod turbine with.lowed- Nos rated turbine. Updated heat content franc 00 btelscf to 1096 046 - 12WE2024 Hot on heater design capacity of 53,8 MMBtu/hr 0,B 0.8 01 5,8 09 0.B 13.2 03 0.3 0.8 0.8 0,1 5.8 0.9 0.8 13.2 0.3 0.3 No change 047 12WE2024 230 MMSCFD Amine sweetening unk and RTO 0.0 00 1.0 32.4 2,7 10.8 0.0 83 5.8 5.8 0,0 0.0 17,5 32,4 2.7 724,1 0.0 8.3 115.5 115.5 Updating emissions to beam. for RTC bursar and eupplem3Mal fuel. No change to amine 032/ 003095 tank emissions 048 12WE2024 230 MMSCFD TEO dehydrator 01 1,7 0.4 03 0,3 0,1 551.2 0.4 166.2 1602 Modifying control for still vent to now res)e/4 to plant mlet (previously controlled by combustor/ except tar 3,5%downpmo to plant gam. Increasing fish tank downtimeta flare from 3h to 3.5%. '29 .022/02024 20.300,30:0,,,,030703I0,310.0 00 0,0 0.0 00 0,31.0,310,0s dw3h Point 047 050 12WE2024 4-1000 BBL condensate storage tanks 0.2 2.8 05 0.4 0,4 02 55,3 0.5 8.6 8,6 Adjw8n0 combustion embsicns. No change to tank emissions 051 12WE2024 Truck loadodt 0.1 3.7 a6 0,6 0.0 0.1 73.9 06 11,5 11,5 Adjusting combustion emissions.. No change toloodou emissions 052 12WE2024 Fugitive ea/dement leaks 21.0 07 0.7 131.3 4.4 44 No charge 053 NA Point created in PTA by mistake -not a place of equipment ^ 00 'nO C.4 0.0 Point created In PTS by mistake- note place of equlpm 054 NA Point created in PTA by mistake -not a place of equipment 0.0 00 ri Paint created in PTS by mistake- not a place of equipm 055 NA Point created in PTS. by mistake- not a piece of 53412 0nt 20 00 0.0 .^•0 Point created in PTSOV mistake- not a piece of equipm 056 12WE2024 Prsseuiaadunbarong of raw condensate 1.8 0.1 02 1.6 01 0.2 Now point - /Met!ng operationthat had not been previously 00rm1604 057 12WE2024 One 400 bbl produced waterstcregetank --- 0.0 0.2. 0,0 00 8.0 00 3.9 0.0 03 04 blow point- existing tank that had not boon previously permNsl 058 12W22024 One 300 bpi methanol storage tank 02 0.2 02 02 0.2 0.2 New point- existing tank that had not been previously nnilmd 059 12WE2024 Plan1Bare 0.0 0.0 1,5 12,9 0.0 08 0.0 0.0 0.0 0.0 1,5 257.1 0.0 8.6 0.7 0,9 New Wirt- existing flare that had not been previously permitted Insignificant sources for Plant 2 oxplansion 0,1 0.1 0.1 07 2.2 0.1 0.6 02 02 0,1 0,1 0.1 0.7 2.2 0.1 O6 52 02 Booed 0120I8ty vide fnnn submitted 1l/15/2.018 insignificant sources for existing Prairie Plant 0,2 1.7 0.0 02 1.7 0,8 Based on facility wide 10,00.bm6ted 11/1512016 Total Facility ITPY1 13,0 13,0 1.0 47.1 238,2 146.7 13.0 34,8 300.9 17.0 18,8 13,0 13,0 17,5 47.1 1451.7 2754.0 13.0 178.6 1,206,9 771.3 774,7 _ Total Permitted Facility /TP10 12,7 12,7 1A 47,0 234.6 145.8 12.7 34,8 297.4 16,8 18.5 Change In permitted emissions ITPYI -0.4 -0.4 0.0 -0.2 45.8 .0.5 -0.4 0,0 7.5 -0.2 -6.2 Prole, egots?fans for L!Fe ne ll addlbon (TPY) 4.8 42 1,0 34.6 34.1 38.2 4.8 21.0 86.8 El - 9,4 123/0107 DCP Midstream, LP Lucerne Gas Processing Plant SW1/4, section 28, MN, R65W Weld County PTE - with Enforceable Controls POINT PERMIT Description Formaldehyde Acetaldehyde Benzene Acrolein r 3adIamene Toluene Elhylleessene Xylenes n -Hexane 224 TMP McOH DEA TOTAL (payl TOTAL REPORTABL E (rev) Individual HAP IIpy) 001 d�d4tR .081152 4 f-'Sl'i+ ih:.itK._ .s L-7042081 17007?F 0.0 002 Not used 0.0 0 003 5544%50.93 WAUKESHA F-:45210;: 4iti;iP O.G tr 0 004 547,8!036(4-1 W010/156/1A 0 704.2051 / /001/P 0 0 0 005 Not used 00 0 0 (106 0354'50480 WAUKESHA 0.704206) 1100Y,P 0.0 0 0 007 Not used 0.0 3 0 00.6 03550469 NG GUY GEFi'S 10.5E65CFD 0.0 U 009 5455216 WAUKESHA L..70420:SI NWGHP 0.0 U . 010 50,1/5562 WAUK,5:SH.AF4?521 GU4i0HP 0.0 0 0 01, 965E905 THREE 300 BBL CONDENSATE TANKS 0.0 0 0. 012 961'5135 2'10 BBL C OND. TANK 0.0 0 013 16M/5135-3 300 001., COND. TANK n..1 a 0 o 014 96W9905 Equipment Leaks 1476 0.7 0.7 0.7 015 96WE905 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 8 126 0.4 0.3 0.2 010 5614%E905 Waukesha ,Endure (7400);4 0.0 0.0 0.0 017 96WE905 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 8 126 0.4 0.3 0.2 018 96WE905 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 8 126 0.4 0.3 0.2 019 96WE905 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 8 126 0.4 0.3 0.2 020 90W/N/05 WAUKESHA. 5101)51.: F-3521, SN: 365350 Q0 0.0 0., .22 9340'5905 GLYCOL DEHYDRATION SYSTEM u. u" 0.0 00 (!,0 030/50409 WA✓K55/54 03.521051, 5;N: 383031 0.0 0.0 0.0 023 .344/50490 31Yrr1 Dehydration Unit 0.0 0.0 0.0 024 04WE1301 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 8 126 0.4 0.3 0.2 025 04WE1302 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 8 126 0.4 0.3 0.2 026 0155/303 Punitive equipment 1AuS$ 0.0 0.0 0.0 _ 02? --- Depressurizing of The gas processing plant in preparation to shutdown 0.0 0.0 0 0 029 ..... Venting of pressralled coruiensete tank Minn, VR'U is 00)00 0.0 0.0 0.0 029 05WE0958 1232 HP Waukesha L7042 ICE 405 115 65 115 23 1 B 126 0.4 0.3 0.2 030 05WE0959 REGENERATION GAS HEATER 4 91 0.0 D.0 0.D 031 950P41r-100 Cererpiliar 533087OO 0.0 0.0 00 032 07WE0021 WAUKESHA L7042GSI RICE, EN: C-17495/1 497 141 60 133 33 28 1 10 0 0 155 0.5 0.5 0.2 033 07WE0579 WAUKESHA L5794 GSI, SN: C-17419/1 455 129 73 122 26 1 9 141 0.5 0.4 0.2 034 0841/'509122.0 Caterpillar 03603 TALE Natterat gas compression engine 2370 HP 0.0 0.0 00 035 0545%50913.0 Caterpillar 03608 TALE Natural aes compression engine 2370 HP 0.0 0.0 0.0 030 !1811150914. C. Caterpillar 553508 TALE Natural gas compression eligino 2370 Fir' 0.0 0.0 0.0 037 03500005.0 �� i r'a„kas'ha L7042 051 Nato/at eas oompiessie0 600100 1232 HP i ) .b 0.0 0 0 038 085E0016, 0 Waukesha 07042 0S'1 Natural yes c0rn5ressicn 8011/00 1232 HP 0.0 0.0 0 0 039 08550817.0 Waukesha 07042 GS! Nature/ gas 00rnpreasion titki/rn) 1232 HP • 0.0 0.0 0 0 040 0101/5)1918.0 Solar Saturn 50(502 nEEGx; power gvnerabor; SN: 7B > 0.0 0.0 1(0 041 "� 541%50919. C Solar Saturn 50 (SvL.0Nbx1 power generation SN: TBD 0 0.0 0.0 042 08WE0920 Amine unit w/ Thermal oxidizer, model & SN: TBD 443 349 23 177 15 6008 4.5 4.5 4.0 043 08WE0921 Two Amine regeneration heaters, model & SNs: TBD 10 243 0.1 0.0 0.1 044 12WE2024 Natural gas turbine rated at 8534 HP 410 23 7 4 75 18 37 0.3 0.2 0.2 045 12WE2024 Natural gas turbine rated at 8534 HP 410 23 7 4 75 18 37 0.3. 0.2 0.2 046 12WE2024 Hot oil heater design capacity of 50 MMBiu/hr 24 1 1 567 0.3 0.3 0.3 047 12WE2024 230 MMSCFD Amine sweetening unit 7507 3564 130 270 114 5.8 • 5.8 3.8 048 12WE2024 230 MMSCFD TEG dehydrator 327 166 6 31 51 0.3 0.3 0.2 '413 1214/5'2024 1,7e,uenerankn 11rer'rhOi .366100? 0.0 0.0 0.0 050 12WE2024 4-1000 BBL condensate storage tanks 75 209 15 158 405 0.4 0.4 0.2 051 12WE2024 Truck loadout 101 279 21 211 541 0.6 0.6 0.3 052 12WE2024 Fugitive equipment leaks 65 43 3 11 1314 0.7 0.7 0.7 053 NA Point created in PIS by mistake - not a piece of equipment 0.0 0.0 0.0 054 NA Point created in PTS by mistake - not a piece of equipment 0.0 0.0 0.0 055 NA Point Seated in PTS by mistake - not a piece of equipment 0.0 0.0 0.0 056 12WE2024 Pressurized unloading of raw condensate 30 30 2 9 250 9 0.2 0.1 0.1 057 12WE2024 One 400 bbl produced water storage tank 11 33 0.0 0.0 0.0 058 12WE2024 One 300 bbl methanol storage tank 461 0.2 0.2 0.2 059 12WE2024 Plant flare 12 4 1 73 0.0 0.0 0.0 Insignificant sources for Plant 2 explansion 63 23 24 12 357 . 0.2 0.2 Insignificant sources for existing Prairie Plant 0.0 0.0 I I 0.0 0.0 0'069 3)66 LOLL 0'0 9'100 0'0 604 1'03 '60 1'301 0'0 0'1 9'891 l'1 £'9 (Adl) 701011 0'0 0'0 0'0 Weld aple)d 6u!slxa lo; 9901600 )ue0ylu6lsul 3'0 30 .0'0 Z'0 LSE 31 43 £3 £9 uolsueldxa 3 ueld loy saamos )ueogluOlsul L'O L'O 6'0 9L3) 91 4 98 940 wen Weld 430336631 690 Z'0 Z'0 3'0 L94 Busy 668)01s loueylaw Nu 00E auO 03033663) 090 E 0 EO 4'0 099 013 hue) a6eiols la)em paonpold 1119 000 au0 430Z3M3 LSO 1'0 1'0 Z'0 6 093 6 Z 0£ 0£ alesuapuo° Mel )0 6ulpeo1un pazllnssald 430336621 950 0'0 0'0 0'0 luawdmbo 10 aoald a you - aHe)slw Aq Sld ul poison mod VN 990 0'0 0'0 0'0 )uawdlnba )0 6oald a you - ageyslw Aq Old LB palms )ulod ON 490 0'0 0.0 0'0 _ luawdlnba yo aoald a lou - allelsuu Aq Sld ul poison mod ON £90 0'4 0'4 4'0 3908 19 03 L9Z 004 slleal }uawd!nba angl6n6 430336631 Z90 4'9 9'11 9' 1) 61801 0104 014 3109 1103 )nopeol.>I°oil 030Z3M31 190 I'4 98 9'9 0019 901E 016 £114 9091 we, a6el°ls ayesuapuoo 188 0001-0 430336661 090 00 0'0 OD 2azrplxo !94"-"19 anr)9.6919040! )Z 06.64061 610 9'66 3'991 3'99) 90360 198L1 083£ 96146 960L8) 1o)elpAyap 931 Od3SWW 0£Z 93032MZ1 800 6"69 9'911 9'911 99381 1L64 0046 00699 019661 Bun 6uluayaams sulpV OAOSWW 063 90033/1A31 L40 £'0 EO EO L99 L L 03 14/n18WW 051° 6B°ede0 u6lsep layeay Bo WH 40003A/131 940 Z'0 3'0 CO L£ 81 96 4 L £Z 010 dH 4£99 Is pale! aulglny se6 lem)eN 46033MZ1 900 010 60 £'0 L£ 81 91 4 L £6 014 dH 4£981e pale! aulgm) se6 lem)8N 060Z3MZ1 400 1'0 0'0 00 £90 01 081 IONS '8 lap°w '010yeay uOllelaua6al aulwV °Ml 136096690 £90 4'004 9090 9'094 Z6L009 6141 431[1 3800 9364£ 09344 081 INS '8 lap0w 'lazlplx° lew1ayl /M Bun gulp) 03603A/190 000 00 0'0 0.0 0101 :NS 1056)0000 J090;fxot t;°.>100 wmes )610.1 0,"916094060 L<-0 0.0 0'0 00 0£+,L :Ns, 9068205612.10:600 (00^,o 6s 06 0:9160 xios f1116O3,14-do 01-0 11 0'0 0'0 01'10201 NO00 0010m(10;0," 10 01' 1,:00`,1 100 6102'10)100900M 1 0100.3/1160 050 OD 0'0 ( 0 d? 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(Adl) 101011 O ntrol Division eaith Er Environment CONSTRUCTION PERMIT Permit number: Date issued: Issued to: 12WE2424 Facility Name: Plant AIRS ID: Physical Location: County: General Description: Issuance: 4 DCP Operating Company, LP Lucerne Natural Gas Processing Plant 123/0107 31495 Weld County Road 43 Weld County Natural Gas Processing Plant Equipment or activity subject to this permit: Facility Equipment ID AIRS Point Equipment Description Emissions Control Description TURB-1 044 One (1) natural gas -fired combustion turbine (Solar, Model Taurus 70, Serial number: 1059B), equipped with low NOx burners, site rated at 9,012 horsepower at 11,494 RPM. The turbine is design rated for a heat input of 65.99 MMBtu/hr (LHV) 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. None TURB-2 045 One (1) natural gas -fired combustion turbine (Solar, Model Taurus 70, Serial number: 1060B), equipped with low NOx burners, site rated at 9,012 horsepower at 11,494 RPM. The turbine is design rated for a heat input of 65.99 MMBtu/hr (LHV) 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. None COLORADO Air Pollution Control Division tx,,wrtrnent Punt 8 Fn rwri; we Page 1 of 57 ca n ' of o heater and regeneration he ; r Ingle f inlet and single outlet stac , •ptimize• •rocess Furnaces, Inc., (OPF), models H-9000 and H-741, serial number: J131130 and J131131), equipped HT -02 046 with low NOx burners. The heaters are design rated at a combined heat input of None 53.6 MMBtu/hr. The heaters are fueled by natural gas. The hot oil heater is used to supplement the waste heat recovery unit (WHRU) provided from Points 044 and 045. One (1) methyldiethanolamine (MDEA) natural gas sweetening system for acid gas removal with a design capacity of 230 MMscf per day (Fabwell, Model 108" amine contactor, Serial number: 13-1311-1). This emissions unit is equipped with three (3) The amine flash stream is routed back to the plant inlet through a closed loop system that utilizes a vapor recovery unit (VRU) with a maximum 3% annual downtime. Flash tank emissions during VRU downtime will be routed to the plant flare (Point 059) with 95% destruction efficiency. The acid gas stream from the still vent condenser AU -02 047 electric amine recirculation pumps (Baker Hughes HPHVMARK) with a total limited capacity of 945 gallons per minute of lean amine. This system includes a natural gas/amine contactor, reflux condenser, a outlet is routed to a regenerative thermal oxidizer (RTO) (Anguil, Model 150, Serial Number: flash tank, still vent and an indirect -fired hot oil (or waste heat from the WHRUs) amine regeneration reboiler (point 046). 17714) rated at 10,000 scf/min. Destruction efficiency for the RTO is a minimum of 96% for VOC. The acid gas stream from the still vent condenser outlet is routed to a backup thermal oxidizer (TO) during RTO downtime with a minimum destruction efficiency of 96%. COLORADO Air Pollution Control Division 1.L.≥bze rt..df}:L";aC �ft*atifl?i i'FiPr "r;s r[ Page 2 of 57 D-01 048 One (1) triethylene glycol (TEG) dehydrator unit with a design capacity of 230 MMscf/day (Prof Projects Inc., Model T-9600, Serial number: 5518). This emissions unit is equipped with two (2) electric glycol pumps (Cat Pumps/3541.0110) with a limited total combined capacity of 40 gallons per minute. This system includes a reboiler, BTEX condenser, still vent, and flash tank. The flash tank . emissions are routed back to the plant inlet through a closed loop system that utilizes a vapor recovery unit (VRU) with a maximum 3.5% annual downtime. Flash tank emissions during VRU downtime will be routed to the Plant flare (Point 059) with 95% destruction efficiency. The still vent emissions are routed to a condenser and then back to the Plant inlet through a closed loop system that utilizes a VRU with a maximum 3.5% annual downtime. Still vent emissions during VRU downtime will be routed to the plant flare (Point 059) with 95% destruction efficiency. TANKS 050 Four (4) stabilized atmospheric condensate storage tanks. Each tank has a capacity of 1,000 bbl. Emissions are routed to an enclosed combustor (Abutec) with a minimum destruction efficiency of 95%. Emissions will be routed to the plant flare with 95% destruction efficiency during any combustor downtime. LOAD 051 Condensate truck loading. Emissions from the loadout will be controlled by an enclosed combustor (Abutec) with a minimum destruction COLORADO Air Pollution Control Division Page 3 of 57 efficiency of 95%. Emissions will be routed to the plant flare with 95% destruction efficiency during any combustor downtime. FUG 052 Fugitive emission component leaks from a natural gas processing plant associated with the Lucerne 2 expansion project. None UL 056 Pressurized unloading of raw unstabilized condensate from pressurized tanks trucks to pressurized condensate feed tanks using vapor balance. Emissions result from gas vented during hose disconnect. None PW TANK 057 One (1) 400 bbl fixed roof produced water storage tank. Emissions are routed to an enclosed combustor (Abutec) with a minimum destruction efficiency of 95%. Emissions will be routed to the plant flare with 95% destruction efficiency during any combustor downtime. METHANOL 058 One (1) 300 bbl fixed roof methanol storage tank. None F-1 059 Routine maintenance activities, purging of gas and malfunctions. Activities are controlled by an elevated open air assisted process flare. Purge gas prevents low flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is residue gas and helps the flare maintain a minimum required positive flow through the system. Flare is also used as back-up control device. Open flare (Zeeco, Model HSLF) with 95% destruction efficiency. 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 in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. Point 048: The glycol pump may be replaced with another glycol pump in accordance with the provisions of the Alternate Operating Scenario (AOS) in this permit. 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), COLORADO Air Pollution Control Division Page 4 of 57 to th -- ,; ic.: -ral "" a •ndit; ins included in this document and the following speci REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION 1. Points 044-045, 048 and 056-059: 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, by submitting aNotice of Startup form to the Division. The Notice of Startup form may be downloaded . online at www.colorado.gov/cdphe/air/manage-permit. Failure to notify the Division of startup of the permitted source is a violation of Air Quality Control Commission (AQCC) Regulation No. 3, Part B, Section III.G.1 and can result in the revocation of the permit. 2. Points 044-045, 048 and 056-059: 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. Points 044-045, 048 and 056-059: 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. Points 044-045, 047, 048 and 056-059: 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 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 6. 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 Process Pounds Per Month Emission Type NOx 5O2 VOC CO PM2.5 H2S TURB-1 044 01 1,961 167 103 2,983 324 -- Point TURB-2 045 01 1,961 167 103 2,983 324 -- Point COLORADO Air Pollution. Control Division a rtmont,A F ttc, capa3chs § tfttrorMerlt Page 5 of 57 UL 056 01 7 1 295 5,317 1,139 1,018 118 Point 263 Point PW TANK 057 01 1 33 5 Point F-1 059 01 243 2,183 1,108 Point 02 19 1 16 Point (Note: Monthly limits are based on a 31 -day month.) For Point 044 and 045 each, the following process designations apply: • (01) Turbine Emissions For Point 047, the following process designations apply: • (01) Still Vent Routed to RTO For Point 059, the following process designations apply: • (01) Purge gas and gas routed to flare due to routine maintenance activities; • (02) Pilot light The owner or operator shall calculate monthly emissions based on the calendar month. Facility -wide emissions of each individual hazardous air pollutant shall be less than 1,359 pounds per month. Facility -wide emissions of total hazardous air pollutants shall be less than 3,398 pounds per month. Annual Limits: Facility Equipment ID AIRS Point Process Tons per Year Emission Type NOx SO2 VOC CO PM2.5 H2S TURB-1 044 01 11.5 1.0 0.6 17.6 1.9 -- Point 02 0.005 -- 0.09 0.44 -- -- Point 03 0.005 -- 0.04 0.31 -- -- Point TURB-2 045 01 11.5 1.0 0.6 17.6 1.9 -- Point 02 0.005 -- 0.09 0.44 -- -- Point 03 0.005 -- 0.04 0.31 -- -- Point HT -02 046 01 5.8 0.1 0.9 13.2 0.8 -- Point AU -02 047 01 1.7 31.3 6.7 6.0 -- 0.7 Point 02 0.8 1.1 0.2 1.8 -- 0.02 Point 03 -- -- 2.8 -- -- 0.3 Point 04 0.1 0.01 0.8 0.5 -- -- Point COLORADO Air Pollution. Control Division Page 6 of 57 cili n •ID S F Tons per Year Emission Type NOx 5O2 VOC CO PM2.5 H2S D-01 048 01 0.1 -- 1.7 0.4 -- -- Point TANKS 050 01 0.2 -- 2.8 0.5 -- -- Point LOAD 051 01 0.1 -- 3.7 0.6 -- -- Point FUG 052 01 -- -- 21.0 -- -- -- Fugitive UL 056 01 -- -- 1.6 -- -- -- Point PW TANK 057 01 0.01 -- 0.2 0.03 -- -- Point METHANOL 058 01 -- -- 0.2 -- -- -- Point F-1 059 01 1.4 -- 12.9 6.5 -- -- Point 02 0.1 -- 0.01 0.1 -- -- Point See "Notes to Permit Holder" for information on emission factors and methods used to calculate limits. For Point 044 and 045 each, the following process designations apply: • (01) Turbine Emissions; • (02) Startup Turbine Emissions; • (03) Shutdown Turbine Emissions. For Point 047, the following process designations apply: • (01) Still Vent Routed to RTO; • (02) Still Vent Routed to TO; • (03) Still Vent Routed to Atmosphere; • (04) Flash Tank Routed to Plant Flare (Point 059) during VRU downtime. For Point 059, the following process designations apply: • (01) Purge gas and gas routed to flare due to routine maintenance activities; • (02) Pilot light. 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. The facility -wide emissions limitation for hazardous air pollutants shall apply to all permitted emission units at this facility. For points 044, 045, 047, 056, 057 and 059, 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. For all AIRS Points, 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 COLORADO Air Pollution Control Division eti^er'.4f Pis;t:c ±ratth & Eri:�rgrt';9@�L* Page 7 of 57 on s - or at a local field office with site responsibility, ng twe -month total shall apply to all permitted emission units, requiring an A , at this faci ity. 7. The emission points in the table below shall be operated and maintained with the emissions control equipment as listed in order to reduce emissions to less than or equal to the limits established in this permit. (Regulation Number 3, Part B, Section III.E.) Facility Equipment ID AIRS Point Process Control Device Pollutants Controlled AU -02 047 01 Still Vent: Regenerative Thermal Oxidizer (RTO) VOC and HAP 02 Still Vent: Thermal oxidizer during RTO downtime VOC and HAP 04 Flash tank: Recycled to plant inlet via VRU. Plant flare during VRU downtime (maximum 3% downtime) VOC and HAP D-01 048 01 Flash tank: Recycled to plant inlet via VRU. Plant flare during VRU downtime (maximum 3.5% downtime) Still Vent: Recycled to plant inlet via VRU. Plant flare during VRU downtime (maximum 3.5% downtime) VOC and HAP TANKS 050 01 Enclosed combustor. Emissions are routed to plant flare during combustor downtime. VOC and HAP LOAD 051 01 Enclosed combustor. Emissions are routed to plant flare during combustor downtime. VOC and HAP PW TANK 057 01 Enclosed combustor. Emissions are routed to plant flare during combustor downtime. VOC and HAP F-1 059 01 Open flare VOC and HAP 8. Point 047: For Process 01, the owner or operator shall calculate uncontrolled VOC and H2S emissions on a monthly basis using the most recent measured gas composition of the acid gas stream from the still vent and monthly measured flow volume of acid gas stream from the still vent to the RTO. A control efficiency of 96% for VOC and H2S, based on maintaining the minimum temperature requirements specified in Condition 63, shall be applied to the uncontrolled still vent emissions. 9. Point 047: For Process 02, the owner or operator shall calculate uncontrolled VOC and H2S emissions on a monthly basis using the most recent measured gas composition of the acid gas stream from the still vent and monthly measured flow volume of acid gas stream from the still vent to the TO. A control efficiency of 96% for VOC and H2S, based on maintaining the minimum temperature requirements specified in Condition 66, shall be applied to the uncontrolled still vent emissions. COLORADO Air Pollution Control Division imr, ties Arrrarril ?X $5}yyremeruE Page 8 of 57 10. Poin ° : or P 03 ow r or operator shall calculate uncontrolled VOC and mi; io o a m th basis ng the most recent measured gas composition of e aci: gas s ream rom e still ven, and monthly measured flow volume of acid gas stream from the still vent to the atmosphere. 11. Point 047: For Process 04, the owner or operator shall calculate uncontrolled VOC and H2S emissions on a monthly basis using the most recent measured gas composition of the amine flash tank stream during VRU downtime and monthly measured flow volume of amine flash tank stream during VRU downtime. A control efficiency of 95% for VOC and H2S shall be applied to uncontrolled flash tank emissions during VRU downtime based on operating the flare in compliance with requirements specified in this permit. 12. 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 extended wet gas analysis and recorded operational values including: total actual dehydrator gas throughput (measured at the inlet of the dehydrator), lean glycol recirculation rate, vapor recovery unit (VRU) downtime, flash tank temperature and pressure, wet gas inlet temperature, and wet gas inlet pressure. Recorded operational values, except for total actual gas throughput, shall be averaged on a monthly basis for input into GRI GlyCalc and be provided to the Division upon request. 13. 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.) 14. Point 052: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent extended 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. 15. Point 059: For Process 01, the owner or operator shall calculate uncontrolled VOC and HAP emissions on a monthly basis using the most recent measured gas composition for each header routed to the plant flare and most recent monthly measured flow volume for each header. A control efficiency of 95% for VOC and HAPs, based on operating the flare in compliance with requirements specified in this permit, shall be applied to the uncontrolled VOC and HAP emissions. Compliance for Process 01 shall be based on the sum of VOC and HAP emissions from all inlets to the flare, including but not limited to, the sum of the cold flare header plus warm flare header. PROCESS LIMITATIONS AND RECORDS 16. 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 Equipment AIRS Annual Monthly Limit ID Point Process Process Parameter Limit (31 days) COLORADO Air Pollution Control Division 1.?'^ art£;`rcn: oY Paat€:cEnvuor:;:3M Page 9 of 57 TURB-1 0 su ion of natural gas as a fuel 636.6 MMscf/yr 54.1 MMscf/month 044 02 Ten minute turbine startup event 10 events/yr --- 03 Ten minute turbine shutdown event 10 events/yr --- TURB-2 045 01 Consumption of natural gas as a fuel 636.6 MMscf/yr 54.1 MMscf/month 02 Ten minute turbine startup event 10 events/yr --- 03 Ten minute turbine shutdown event 10 events/yr --- HT -02 046 01 Natural Gas Combusted 315 MMscf/yr ___ AU -02 047 01 Natural Gas Throughput 83,950 MMscf/yr 7,130 MMscf/month Still vent waste gas routed to RT0 2,868.9 243.66 Combustion of supplemental fuel and fuel routed to RT0 burner 9.6 MMscf/yr 0.81 MMscf/month 02 Still vent waste gas routed to TO 102.2 MMscf/yr ___ Combustion of supplemental fuel and pilot fuel at TO 9.6 MMscf/yr ___ 03 Still vent waste gas vented directly to atmosphere 47.8 MMscf/yr --- 04 Flash tank gas vented to flare 3.4 MMscf/yr --- D-01 048 01 Natural gas Throughput 83,950 MMscf/yr 7,130 MMscf/month Flash tank gas vented to the open flare 0.8 MMscf/yr ___ Still vent gas (after the condenser) vented to the open flare 0.3 MMscf/yr _ _ TANKS 050 01 Condensate throughput 730, b bl/y0r 0 bl/y ___ LOAD 051 01 Condensate loaded 730,000 bbl/yr ___ UL 056 01 Pressurized unloading events 2,409 loads 201 loadout/month PW TANK 057 01 Produced water throughput 30,000 bbl/yr 2,548 bbl/month METHANOL 058 01 Methanol throughput 3,626 bbl/yr ___ F-1 059* 01 Combustion of purge gas and gas routed to flare via cold header and warm header 32.89 MMscf/yr 2.79 MMscf/month COLORADO Air Pollution Control Division „',fie(*nos 'Ji } afc�,V hgdit, {t , ti`f:'t"14,t Page 10 of 57 ring •utine maintenance activities 02 Combustion of pilot fuel 2.05 MMscf/yr 0.17 MMscf/month *Note: The open flare covered under point 059 will handle gas (inlet, propane and residue) routed to the flare during standard operational process/normal operation of equipment (i.e. purge gas and maintenance and blowdown activities). In addition, gas will be routed to this flare during any events that qualify as a malfunction per Colorado Common Provisions Regulation Section II.E and II.J. The process limit does not include gas routed to the flare during malfunction events or startup and shutdown events per the Colorado Common Provisions Regulation Section II.E and II.J. The process limit also does not include waste gas associated with the amine unit (Point 047) flash tank and dehydrator (Point 048) still vent and flash tank routed to this flare during VRU downtime. For Point 044 and 045 each, the following process designations apply: • (01) Turbine Emissions; • (02) Startup Turbine Emissions; • (03) Shutdown Turbine Emissions For Point 047, the following process designations apply: • (01) Still Vent Routed to RTO; • (02) Still Vent Routed to TO; • (03) Still Vent Routed to Atmosphere; • (04) Flash Tank Routed to Plant Flare (Point 059) during VRU downtime. For Point 059, the following process designations apply: • (01) Purge gas and gas routed to flare due to routine maintenance activities; • (02) Pilot light The owner or operator shall calculate monthly process rates based on the calendar month. For points 044, 045, 047, 048, 056, 057, and 059, 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. For all AIRS Points, compliance with the annual 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 throughput each month and keep a compliance record on site or at a local field office with site responsibility, for Division review. 17. 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 owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 18. Points 044 and 045: On a monthly basis, the owner or operator shall monitor and record the total number of turbine startup and shutdown events for each turbine. By the end of each month, the total number of startup and shutdown events for the previous months' data shall be calculated, and a new twelve month total shall be calculated and recorded based on the previous twelve months' data. The owner or operator shall use monthly records to demonstrate compliance with the process limits and to calculate emissions as described in this permit. ;COLORADO Air Pollution Control Division Page 11 of 57 19. 0 ' he •�,;: or `► - ator '' all install and maintain an operational continuous for . e ,,rater. owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 20. Point 047: For Process 01, the owner or operator shall continuously monitor and record the volumetric flow rate of natural gas processed by the amine unit contactor using an operational continuous flow meter at the inlet to the amine contactor. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 21. Point 047: For Process 01, the owner or operator shall continuously monitor and record the volumetric flow rate of waste gas (acid gas stream from the still vent) combusted using an operational continuous flow meter at the inlet to the regenerative thermal oxidizer (RTO). The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 22. Point 047: For Process 01, the owner or operator shall continuously monitor and record the volumetric flow rate of the fuel routed to the RTO burner, including supplemental fuel and burner fuel, using an operational continuous flow meter. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 23. Point 047: For Process 02, the owner or operator shall continuously monitor and record the volumetric flow rate of the waste gas (acid gas stream from the still vent) combusted at the TO using an operational continuous flow meter at the inlet to the thermal oxidizer. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 24. Point 047: For Process 02, the owner or operator shall continuously monitor and record the volumetric flow rate of the fuel routed to the TO burner, including pilot fuel and supplemental fuel, using an operational continuous flow meter. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 25. Point 047: For Process 03, the owner or operator shall monitor and record periods of direct venting of acid gas from the still vent on a daily basis. Periods of direct venting shall be defined as times when the waste gas vented from the amine unit still vent is not routed to the RTO or TO. The total hours of downtime and volume of waste gas (acid gas stream from the still vent) during periods of direct venting shall be recorded on a monthly basis. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 26. Point 047: For Process 04, the owner or operator shall continuously monitor and record the volumetric flow rate of the flash tank stream volume routed to the flare during VRU downtime using an operational continuous flow meter for the flash tank vent stream. The owner or operator shall use monthly throughput records in conjunction with VRU records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. COLORADO Aix Pollution Control Division Page 12 of 57 27. 0 For ": -ss ' , the ner or operator shall monitor and record VRU oint • a daily basis. VRU downtime shall be defined as times w en t e waste gas vented rom the amine unit flash tank is routed to the open flare (point 059) rather than the VRU. The total hours of VRU downtime, total volume of gas vented from the amine unit flash tank and total volume of gas vented from the amine unit flash tank during VRU downtime shall be recorded on a monthly basis. The owner or operator must use monthly VRU downtime records and monthly records of gas vented from the amine unit flash tank to demonstrate compliance with the limits specified in this permit. 28. 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). 29. Point 048: The volume of gas processed shall be measured by gas meter at the inlet of the dehydrator. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 30. Point 048: This unit shall be limited to the maximum lean glycol circulation 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. Glycol recirculation rate shall be monitored by one of the following methods: assuming maximum design pump rate, using glycol flow meter(s), or recording strokes per minute and converting to circulation rate. This maximum glycol circulation rate does not preclude compliance with the optimal glycol circulation rate (Loft) provisions under MACT HH. (Reference: Regulation Number 3, Part B, II.A.4) 31. Point 048: On a weekly basis, the owner or operator shall monitor and record operational values including: flash tank temperature, flash tank pressure, wet gas inlet temperature and wet gas inlet pressure. This information shall be maintained in a log on site and made available to the Division for inspection upon request. These records shall be maintained for a period of five years. 32. Point 048: The owner or operator shall monitor and record still vent vapor recovery (VRU) downtime on a daily basis. Still vent VRU downtime shall be defined as times when the waste gas vented from the glycol dehydrator still vent is routed to the open flare rather than the VRU. The total hours of still vent VRU downtime, total volume of gas processed and total volume of gas vented during VRU downtime shall be recorded on a monthly basis. The owner or operator must use monthly VRU downtime records, monthly gas processing records, and the calculation methods established in the Notes to Permit Holder to demonstrate compliance with the process and emission limits specified in this permit. 33. Point 048: The owner or operator shall monitor and record flash tank vapor recovery (VRU) downtime on a daily basis. Flash tank VRU downtime shall be defined as times when the waste gas vented from the glycol dehydrator flash tank is routed to the open flare rather than the VRU. The total hours of flash tank VRU downtime, total volume of gas processed and total volume of gas vented during VRU downtime shall be recorded on a monthly basis. The owner or operator must use monthly VRU downtime records, monthly gas processing records, and the calculation methods established in the Notes to Permit Holder to demonstrate compliance with the process and emission limits specified in this permit. COLORADO Air Pollution Control Division Page 13 of 57 34.E or P.'"""` 01 own or operator shall continuously monitor and record as rout to the flare, including, but not limited to, process gas, gas rom routine maintenance and purge gas, using flow meters. Each header to the flare, including, but not limited to, the cold flare header and warm flare header, shall be equipped with a flow meter. While the flare is operational, a purge gas flow rate of 441 scfh for each warm flare header and 1,144 scfh for each cold flare header shall be assumed at all times that the metered volume is below the detection level of the meter. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit for Process 01 and to calculate emissions as described in this permit. Compliance for Process 01 shall be based on the sum of all inlets to the flare, including, but not limited to, the sum of the cold flare header volumetric flow rate plus warm flare header volumetric flow rate. STATE AND FEDERAL REGULATORY REQUIREMENTS 35. 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 NOx VOC H2S SOx 40 40 10 40 34.1 38.2 1.0 34.6 TURB-2 045 HT -02 046 Hot Oil Heater and Regeneration Heater AU 02 047 230 MMscfd Amine Unit D-01 048 230 MMscfd TEG Dehy TANKS 050 Four 1,000 bbl Condensate tanks LOAD 051 Condensate loadout UL 056 Pressurized condensate unloading COLORADO Air Pollution Control Division 4' iaFYYc.Yu..^x PULItiC *??Sa l b EziseToP.mem Page 14 of 57 N 05 00 b Produced -,_ tank METHANOL 058 300 bbl Methanol tank F-1 059 Plant flare 36. The permit number and ten digit AIRS ID number assigned by the Division (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) 37. 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 or XVII.B.2.b shall have no visible emissions. (Reference: Regulation No. 1, Section II.A.1. a 4.) 38. This source is subject to the odor requirements of Regulation "No. 2. (State only enforceable) 39. 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 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 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 - NOx Monitoring o (a) Operator shall perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance with NOx emissions limits. If the NOx emission result from the performance test is less than or equal to 75 percent of the NOx emission limit for the turbine, you may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NOx emission limit for the turbine, you must resume annual performance tests. COLORADO Air Pollution Control Division tc%nix*:?4,s: Page 15 of 57 370) - SO2 Monitoring ra corn ith §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. • §S60.4400 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. 40. 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): (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)-° 26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. 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 VI.B.5.a) 41. 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: COLORADO Air Pollution Control Division Page 16 of 57 equ ment generating greater than one million but less Btu • := hour heat input, the following equation will be used etermine fhe allowable particulate emission limitation: PE=0.5(FI)-°-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. 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. 42. 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. (S 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 S 60.7. e. Performance tests shall be conducted as required under §60.8. 43. 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)). COLORADO Air Pollution Control Division Page 17 of 57 usted required under the previous condition shall owner Ar operator of the facility for a period of two years o owing a •ate o such record (40 CFR Part 60.48c(i)). 44. Point 046: This source is subject to Regulation Number 7, Section XVI.D. The operator shall comply with all applicable requirements of Section XVI including but not limited to: • XVI.D.6. Combustion process adjustment • XVI.D.6.a. As of January 1, 2017, this Section XVI.D.6. applies to boilers, duct burners, process heaters, stationary combustion turbines, and stationary reciprocating internal combustion engines with uncontrolled actual emissions of N0x equal to or greater than five (5) tons per year that existed at major sources of N0x as of June 3, 2016. • XVI.D.6.b Combustion process adjustment o XVI.D.6.b.(i) When burning the fuel that provides the majority of the heat input since the last combustion process adjustment and when operating at a firing rate typical of normal operation, the owner or operator must conduct the following inspections and adjustments of boilers and process heaters, as applicable: • XVI.D.6.b.(i)(A) Inspect the burner and combustion controls and clean or replace components as necessary. • XVI.D.6.b.(i)(B) Inspect the flame pattern and adjust the burner or combustion controls as necessary to optimize the flame pattern. • XVI.D.6.b.(i)(C) Inspect the system controlling the air -to -fuel ratio and ensure that it is correctly calibrated and functioning properly. • XVI.D.6.b.(i)(D) Measure the concentration in the effluent stream of carbon monoxide and nitrogen oxide in ppm, by volume, before and after the adjustments in Sections XVI.D.6.b.(i)(A) through (C). Measurements may be taken using a portable analyzer. o XVI.D.6.b.(v) The owner or operator must operate and maintain the boiler, duct burner, process heater, stationary combustion turbine, or stationary internal combustion engine consistent with manufacturer's specifications, if available, or good engineering and maintenance practices. o XVI.D.6.b.(vi) Frequency • XVI.D.6.b.(vi)(A) The owner or operator must conduct the initial combustion process adjustment by April 1, 2017. An owner or operator may rely on a combustion process adjustment conducted in accordance with applicable requirements and schedule of a New Source Performance Standard in 40 CFR Part 60 or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63 to satisfy the requirement to conduct an initial combustion process adjustment by April 1, 2017. • XVI.D.6.b.(vi)(B) The owner or operator must conduct subsequent combustion process adjustments at least once every twelve (12) COLORADO .Air Pollution Control Division ra- w Fut G a "r; v rr r:7ver`.C Page 18 of 57 itial combustion adjustment, or on the applicable to Sections XVI.D.4.a. or XVI:D.4.b. • XVI.D.6.c. As an alternative to the requirements described in Sections XVI.D.6.b.(i) through XVI.D.6.b.(v): o XVI.D.6.c.(i) The owner or operator may conduct the combustion process adjustment according to the manufacturer recommended procedures and schedule; or o XVI.D.6.c.(ii) The owner or operator of combustion equipment that is subject to and required to conduct a period tune-up or combustion adjustment by the applicable requirements of a New Source Performance Standard in 40 CFR Part 60 or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63 may conduct tune-ups or adjustments according to the schedule and procedures of the applicable requirements of 40 CFR Part 60 or 40 CFR Part 63. o XVI.D.6.c.(iii) The owner or operator may comply with applicable recordkeeping requirements related to combustion process adjustments conducted according to a New Source Performance Standard in 40 CFR Part 60 or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63. • XVI.D.7. Recordkeeping. The following records must be kept for a period of five years and made available to the Division upon request: • XVI.D.7.f. For stationary combustion equipment subject to the combustion process adjustment requirements in Section XVI.D.6., the following recordkeeping requirements apply: o XVI.D.7.f.(i) The owner or operator must create a record once every calendar year identifying the combustion equipment at the facility subject to Section XVI.D. and including for each combustion equipment: • XVI.D.7.f.(i)(A) The date of the adjustment; • XVI.D.7.f.(i)(B) Whether the combustion process adjustment under Sections XVI.D.6.b.(i) through XVI.D.6.b.(v) was followed, and what procedures were performed; • XVI.D.7.f.(i)(C) Whether a combustion process adjustment under XVI.D.6.a. through XVI.D.6.b. was followed, what procedures were performed, and what New Source Performance Standard or National Emission Standard for Hazardous Air Pollutants applied, if any; and • XVI.D.7.f.(i)(D) A description of any corrective action taken. • XVI.D.7.f.(i)(E) If the owner or operator conducts the combustion process adjustment according to the manufacturer recommended procedures and schedule and the manufacturer specifies a combustion process adjustment on an operation time schedule, the hours of operation. • XVI.D.7.f.(i)(F) If multiple fuels are used, the type of fuel burned and heat input provided by each fuel. €COLORADO t ( Air Pollution Control Division partrrof: %3f P,L"uC g" H Erosh'rk. m flt Page 19 of 57 ner operator must retain manufacturer recommended ificati•,,,'s and maintenance schedule if utilized under Sec ion X �.:.a. for t e ife of the equipment. o XVI.D.7.f.(iii) As an alternative to the requirements described in Section XVI.D.7.f.(i), the owner or operator may comply with applicable recordkeeping requirements related to combustion process adjustments conducted according to a New Source Performance Standard in 40 CFR Part 60 or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63. 45. 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 o §60.5365(8)(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. 46. Point 048: This source is subject to Regulation Number 7, Section XII.H. The operator shall comply with all applicable requirements of Section XII and, specifically, shall: • Comply with the emission control requirements for glycol natural gas dehydrators (Regulation Number 7, Sections XII.B and XII.H); • Comply with the recordkeeping, monitoring, and reporting for glycol natural gas dehydrators (Regulation Number 7, Section XII.H.5 and 6); and • Ensure 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 on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. (Regulation Number 7, Section XII.H.1.) 47. Point 048 and 059: The open plant flare, which receives still vent and flash tank gas during VRU downtime, is approved as an alternative emissions control equipment per Regulation No. 7, Section XVII.B.2.e. provided the following conditions are maintained: • The open flare will not be the primary destination for emissions from the still vent or flash tank. • The open flare will have no visible emissions during normal operations, as defined under Regulation Number 7, XVII.A.17, and be designed so that an COLORADO Air Pollution Control Division G µirYl n -:.k i`^„ °i C s,.sa31 � & F:nsYrfY-lkca Page 20 of 57 ual observation from the outside of the open flare, nt mea , approved by the Division, determine whether it is operating proper y egula ion 7, Section XVII.B.2.b). • The open flare will be equipped with an operational auto -igniter upon installation of the combustion device (Regulation 7, Section XVII.B.2.d(i)). 48. 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). These requirements include, but are not limited to: XVII.D.3. Beginning May 1, 2015, still vents and vents from any flash separator or flash tank on a glycol natural gas dehydrator located at an oil and gas exploration and production operation, natural gas compressor station, or gas -processing plant subject to control requirements pursuant to Section XVII.D.4., shall reduce uncontrolled actual emissions of hydrocarbons by at least 95 percent on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. If a combustion device is used, it shall have a design destruction efficiency of at least 98% for hydrocarbons. XVII.D.4. The control requirement in Section XVII.D.3. shall apply where: XVII.D.4.a. Uncontrolled actual emissions of VOCs from a glycol natural gas dehydrator constructed on or after May 1, 2015, are equal to or greater than two (2) tons per year. Such glycol natural gas dehydrators must be in compliance with Section XVII.D.3. by the date that the glycol natural gas dehydrator commences operation. 49. Point 048: The glycol dehydration unit at this facility is subject to National Emissions Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities; Subpart HH. This facility shall be subject to applicable area source provisions of this regulation, as stated in 40 C.F.R Part 63, Subpart A and HH including but not limited to the following: (Regulation Number 8, Part E, Subpart A and HH) MACT HH Applicable Requirements Area Source Benzene emissions exemption §63.764 - General Standards §63.764 (e)(1) - The owner or operator is exempt from the requirements of paragraph (d) of this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in §63.774(d)(1). §63.764 (e)(1)(ii) — The actual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere are less than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart. COLORADO Air Pollution Control Division Page 21 of 57 §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration 77 • ) - Determination of glycol dehydration unit flowrate, benzene emissions, or BTEX emissions. The procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas flowrate, benzene emissions, or BTEX emissions. §63.772(b)(2) - The determination of actual average benzene emissions from a glycol dehydration unit shall be made using the procedures of either paragraph (b)(2)(i) or (b)(2)(ii) of this section. Emissions shall be determined either uncontrolled, or with federally enforceable controls in place. §63.772(b)(2)(i) — The owner or operator shall determine actual average benzene emissions using the model GRI-GLYCaIc TM Version 3.0 or higher, and the procedures presented in the associated GRI-GLYCaIc TM Technical Reference Manual. Inputs to the model shall be representative of actual operating conditions of the glycol dehydration unit and may be determined using the procedures documented in the Gas Research Institute (GRI) report entitled "Atmospheric Rich/Lean Method for Determining Glycol Dehydrator Emissions" (GRI-95/0368.1); or §63.772(b)(2)(ii) - The owner or operator shall determine an average mass rate of benzene emissions in kilograms per hour through direct measurement using the methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §63.7(f). Annual emissions in kilograms per year shall be determined by multiplying the mass rate by the number of hours the unit is operated per year. This result shall be converted to megagrams per year. §63.774 - Recordkeeping Requirements §63.774 (d)(1) - An owner or operator of a glycol dehydration unit that meets the exemption criteria in §63.764(e)(1)(i) or §63.764(e)(1)(ii) shall maintain the records specified in paragraph (d)(1)(i) or paragraph (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit. §63.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). 50. 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 S 63.4. b. Operation and maintenance requirements in § 63.6(e)(1). c. Notification requirements in § 63.9(j). COLORADO Aix Pollution Control Division ^.�itmt tvr':&l,m^.:rh`rrzon Page 22 of 57 g requirements in S 63.10(b), except as provided 51. Point 050: The enclosed combustor covered by this permit is subject to Regulation No. 7, Section XVII.B General Provisions (State only enforceable). These requirements include, but are not limited to: XV1I.B.2.b If a 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. XVII.B.2.d Auto -igniters: All combustion devices used to control emissions of hydrocarbons must be equipped with and operate an auto -igniter as follows: XVII.B.2.d.(i) All combustion devices installed on or after May 1, 2014, must be equipped with an operational auto -igniter upon installation of the combustion device. XVII.B.2.d.(ii) All combustion devices installed before May 1, 2014, must be equipped with an operational auto -igniter by or before May 1, 2016, or after the next combustion device planned shutdown, whichever comes first. 52. Point 050: The storage tanks covered by this permit are subject to Regulation 7, Section XVII.C emission control requirements. These requirements include, but arenot limited to: Section XVII.C.1. Control and monitoring requirements for storage tanks XVII.C.1.a. 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.1.b. Owners or operators of storage tanks with uncontrolled actual emissions of VOCs equal to or greater than six (6) tons per year based on a rolling twelve- month total must operate air pollution control equipment that achieves an average hydrocarbon control efficiency of 95%. If a combustion device is used, it must have a design destruction efficiency of at least 98% for hydrocarbons. XVII.C.1.b.(i) Control requirements of Section XVII.C.1.b.must be achieved in accordance with the following schedule: XVII.C.1.b.(i)(a) A storage tank constructed on or after May 1, 2014, must be in compliance within ninety (90) days of the date that the storage tank commences operation. XVII.C.1.b.(i)(b) A storage tank constructed before May 1, 2014, must be in compliance by May 1, 2015. XVII.C.1.d. Beginning May 1, 2014, or the applicable compliance date in Section XVII.C.1.b.(i), whichever comes later, owners or operators of storage tanks subject to Section XVII.C.1. must conduct audio, visual, olfactory ("AVO") and additional visual inspections of the storage tank and any associated equipment (e.g. separator, air pollution control equipment, or other pressure reducing COLORADO Air Pollution Control Division Page 23 of 57 e fr uency as liquids are loaded out from the storage ns are of required more frequently than every seven (7) ays but must •e con • ucte• at least every thirty one (31) days. Monitoring is not required for storage tanks or associated equipment that are unsafe, difficult, or inaccessible to monitor, as defined in Section XVII.C.1.e. The additional visual inspections must include, at a minimum: XVII.C.1.d.(i) Visual inspection of any thief hatch, pressure relief valve, or other access point to ensure that they are closed and properly sealed; XVII.C.1.d.(ii) Visual inspection or monitoring of the air pollution control equipment to ensure that it is operating, including that the pilot light is lit on combustion devices used as air pollution control equipment; XVII.C.1.d.(iii) If a combustion device is used, visual inspection of the auto - igniter and valves for piping of gas to the pilot light to ensure they are functioning properly; XVII.C.1.d.(iv) Visual inspection of the air pollution control equipment to ensure that the valves for the piping from the storage tank to the air pollution control equipment are open; and XVII.C.1.d.(v) If a combustion device is used, inspection of the device for the presence or absence of smoke. If smoke is observed, either the equipment must be immediately shut-in to investigate the potential cause for smoke and perform repairs, as necessary, or EPA Method 22 must be conducted to determine whether visible emissions are present for a period of at least one (1) minute in fifteen (15) minutes. XVII.C.1.e. If storage tanks or associated equipment is unsafe, difficult, or inaccessible to monitor, the owner or operator is not required to monitor such equipment until it becomes feasible to do so. XVII.C.3. Recordkeeping XVII.C.3. The owner or operator of each storage tank subject to Sections XII.D. or XVII.C. must maintain records of STEM, if applicable, including the plan, any updates, and the certification, and make them available to the Division upon request. In addition, for a period of two (2) years, the owner or operator must maintain records of any required monitoring and make them available to the Division upon request, including: XVII.C.3.a. The AIRS ID for the storage tank. XVII.C.3.b. The date and duration of any period where the thief hatch, pressure relief device, or other access point are found to be venting hydrocarbon emissions, except for venting that is reasonably required for maintenance, gauging, or safety of personnel and equipment. XVII.C.3.c. The date and duration of any period where the air pollution control equipment is not operating. XVII.C.3.d. Where a combustion device is being used, the date and result of any EPA Method 22 test or investigation pursuant to Section XVII.C.1.d.(v). XVII.C.3.e. The timing of and efforts made to eliminate venting, restore operation of air pollution control equipment, and mitigate visible emissions. COLORADO iz Pollution Contact Division Page 24 of 57 ass. iated with the storage tank that is designated as ficu o nacces-le to monitor, as described in Section XVII.C.1.e., an exp anation stating why t e equipment is so designated, and the plan for monitoring such equipment. 53. The storage tanks covered under AIRS point 050 are 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 W, §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 (S60.18) 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 (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). • §60.115b - Reporting and recordkeeping requirements COLORADO Air Pollution Control Division Page 25 of 57 nsta ng a closed vent system and flare to comply with nner or f" erator shall meet the following requirements. ■ §60.115b(d)(1) A report containing the measurements required by 560.18(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. • 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 • 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. (5 60.12) • Written notification of construction and initial startup dates shall be submitted to the Division as required under § 60.7. • Records of startups, shutdowns, and malfunctions shall be maintained, as required under S 60.7. • Written notification of opacity observation or monitor demonstrations shall be submitted to the Division as required under § 60.7. • Excess Emission and Monitoring System Performance Reports shall be submitted as required under § 60.7. COLORADO Air Pollution Control Division Page 26 of 57 a be • ducted as required under § 60.8. ity s : rds shall be demonstrated according to S 60.11. • The flare shall be designed and operated, and records and reports shall be furnished, as required under § 60.18. 54. Point 051 and 056: The owner or operator shall follow loading procedures that minimize the leakage of VOCs to the atmosphere including, but not limited to (Reference: Regulation 3, Part B, III.E): a. Hoses, couplings, and valves shall be maintained to prevent dripping, leaking, or other liquid or vapor loss during loading and unloading. b. All compartment hatches (including thief hatches) shall be closed and latched at all times when loading operations are not active, except for periods of maintenance, gauging, or safety of personnel and equipment. c. The owner or operator shall inspect loading equipment and operations on site at the time of the inspection to ensure compliance with Condition 54 (a) and (b) above. The inspections shall occur at least monthly. Each inspection shall be documented in a log available to the Division on request. 55. Point 051 and 056: All hydrocarbon liquid loading operations, regardless of size, shall be designed, operated and maintained so as to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. 56. The reciprocating compressors grouped with the fugitive emissions addressed by AIRS ID 052 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). • §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. • §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). 57. Point 052: The fugitive component emissions from this point that commenced construction, modification or reconstruction after August 23, 2011, are subject to the €COLORADO Air Pollution Control Division Page 27 of 57 and . equirements of Regulation No. 6, Part A, Subpart ance fo rude Oil and Natural Gas Production, Transmission mg, :ut not imited 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). • S 60.5415: Owner or operator must demonstrate continuous compliance with the standards using the requirements in §60.5415(f). • S 60.5421: Owner or operator must comply with the recordkeeping requirements of §60.5421(b). • S 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 S 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). 58. Point 052: This source is subject to Regulation enforceable). Natural gas -processing plants located (State Only: or any specific Ozone Nonattainment shall comply with requirements of Regulation No. requirements of Sections XII.B., XII.C.1.a., XII.C.1.b. No. 7, Section XII.G (State only in the 8 -hour Ozone Control Area or Attainment/Maintenance Area) 7, Section XII.G., as well as the , XII.H., XII.J., XII.K., and XVI. • XII.G.1. For fugitive volatile organic compound emissions from leaking equipment, the leak detection and repair (LDAR) program as provided at 40 CFR Part 60, Subpart OOOO (July 1, 2017) applies, regardless of the date of construction of the affected facility, unless subject to the LDAR program provided at 40 CFR Part 60, Subpart 0000a (July 1, 2017). • XII.G.3. Natural gas processing plants within the 8 -hour Ozone Control Area constructed before January 1, 2018 must comply with the requirements of Section XII.G. beginning January 1, 2019. (State Only: Existing natural gas processing plants within any new Ozone Nonattainment or Attainment/Maintenance Area shall comply with this regulation within three years after the nonattainment designation.) 59. Point 059: The flare shall be air -assisted and shall be designed and operated in accordance 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: • §60.18(b) Flares. Paragraphs (c) through (f) apply to flares. • 560.18(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. • 560.18(c)(2) Flares shall be operated with a flame present at all times, as determined by the methods specified in paragraph (f). COLORADO it Pollution Control Division Lv -v. aru..wP ; kr FAVIorTer Page 28 of 57 /ope for has the choice of adhering to either the heat cif k . t' in p aph (c)(3)(ii) of this section and the maximum tip ve ocity speci ications in paragraph (c)(4) of this section, or adhering to the requirements in paragraph (c)(3)(i) of this section. (3) $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). (4) $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. (5) $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 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 paragraph (f)(3) of this section. • §60.18(c)(5) Air -assisted flares shall be designed and operated with an exit velocity less than the velocity, Vmax, as determined by the method specified in paragraph (f)(6). • §60.18(c)(6) Flares used to comply with this section shall be steam -assisted, air - assisted, or nonassisted. • §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. • §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. • $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. • §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. COLORADO Air Pollution Control Division nc Ralbr ec §t vx n cnc Page 29 of 57 value of the gas being combusted in a flare shall ng equation: n H K C1H 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; f( = Constant I g mole NJ 1.740 x i0-7(per} ( scm �kca7 ' were the standard temperature for (q note} is20cC; 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. • §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. • $60.18(f)(5) The maximum permitted velocity, Vmax, for flares complying with paragraph (c)(4)(iii) shall be determined by the following equation. Loglo (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). • §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). 60. This source is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of COLORADO Air Pollution. Control Division Page 30 of 57 . The following requirements were determined to 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: Recycle to inlet via VRU and secondary control is route to open flare during VRU downtime Still Vent: Regenerative Thermal Oxidizer and back-up Thermal Oxidizer D-01 048 VOC Flash Tank: Recycle to inlet via VRU and secondary control is route to open flare during VRU downtime Still Vent: Condenser and recycle to inlet via VRU and secondary control is route to open flare during VRU downtime TANKS 050 VOC Enclosed combustor LOAD 051 VOC Submerged fill, vapor balance service, enclosed combustor FUG 052 VOC LDAR UL 056 VOC Unloading using pressurized vessels and vapor balance PW TANK 057 VOC Enclosed combustor F-1 059 VOC Installing flare and operating according to 40 CFR 60.18 OPERATING Et MAINTENANCE REQUIREMENTS 61. Points 047, 048, 050, 051, and 057: Upon startup of these points, the owner or operator shall follow the most recent operating and maintenance (O8M) 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 O8M plan are subject to Division approval prior to implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.) COLORADO Air Pollution Control Division Murtment at Futext a3hk ErisedalMere Page 31 of 57 62.E d 0'-'"`t al i es d ing normal operation, the owner or operator shall NOx m •e. On a daily basis, the owner or operator shall monitor and record the status of t e oLoNOx mode, including records of when the unit is not operating in SoLoNOx mode. These records shall be made available to the Division upon request. Normal operation shall be defined as all periods of operation except for startup, shutdown, or malfunction events. 63. Point 047: For Process 01, the combustion chamber 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, on a daily average basis. The approved daily average minimum operating temperature shall be achieved 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. The combustion chamber temperature shall be measured and recorded at least once every hour. If the combustion chamber temperature value is measured more frequently than once per hour, the source shall record either each measured data value or each block average value for each 1 -hour period calculated from all measured data values during each period. 64. Point 047: For Process 01, the regenerative thermal oxidizer shall not operate in supplemental fuel injection (SFI) mode. On a daily basis, the owner or operator shall monitor and record the status of the RTO mode, including records of when the unit is operating in SFI mode. These records shall be made available to the Division upon request. 65. Point 047: For Process 01, 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. 66. Point 047: For Process 02, the combustion chamber temperature of the 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, on a daily average basis. The approved daily average minimum operating temperature shall be achieved at all times that any amine unit emissions are routed to the thermal oxidizer in order to meet the emission limits in this permit. The combustion chamber temperature shall be measured and recorded at least once every hour. If the combustion chamber temperature value is measured more frequently than once per hour, the source shall record either each measured data value or each block average value for each 1 -hour period calculated from all measured data values during each period. 67. Point 051: The owner or operator of a loadout at which vapor balancing is used to control emissions shall: • Install and operate the vapor collection and return equipment to collect vapors during loading of tank compartments of outbound transport trucks and return these vapors to the stationary source storage tanks. • Include devices to prevent the release of vapor from vapor recovery hoses not in use. • Use operating procedures to ensure that hydrocarbon liquid cannot be transferred unless the vapor collection equipment is in use. COLORADO Air Pollution Control Division nen: Env;rrh'rte:r t Page 32 of 57 osal equipment at a back pressure less than the f transport vehicles. Inspect thief hatch seals annually for integrity and replace as necessary. Thief hatch covers shall be weighted and properly seated. Inspect pressure relief devices (PRD) annually for proper operation and replace as necessary. PRDs shall be set to release at a pressure that will ensure flashing, working and breathing losses are routed to the control device under normal operating conditions. • Document annual inspections of thief hatch seals and PRD with an indication of status, a description of any problems found, and their resolution. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 68. Points 044 and 045: Each turbine is subject to the initial testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. Points 044 and 045: The operator shall conduct an initial compliance test to measure the emission rate(s) from each turbine for Process 01 - Turbine Emissions 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. 69. Points 044 and 045: The owner or operator shall complete the initial sampling for net heating value of the fuel used in the turbines 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.) 70. Point 047: For Process 01 and 02, the owner or operator shall complete the initial sampling for net heating value of the supplemental fuel used in the RTO and TO 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.) 71. Point 059: The owner or operator shall complete the initial extended gas analyses of the gases routed via the cold header and warm header to the plant flare 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.) Periodic Testing Requirements COLORADO Air Pollution Control Division s�tr. r�: b rnc,3hrac Page 33 of 57 72. d `: ' ep ent of these units completed as Alternative Operating l testing requirements as specified in Attachment 73. 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. 74. 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 for Process 01 - Turbine Emissions. The source may perform a stack test per Condition 74 in lieu of portable analyzer testing. 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 operating hours for that averaging time. (Reference: Regulation No. 3, Part B., Section III.G.3) 75. Points 044 and 045: The operator shall measure the emission rate(s) from each unit for Process 01 - Turbine Emissions for the pollutants listed below at least once every 12 month in order to demonstrate compliance with the emissions limits contained in this permit. Periodic testing shall be conducted within 12 months of the prior test with a minimum period of at least one hundred and eighty (180) days apart. In the event it is not feasible to conduct a test at a minimum of at least one hundred and eighty (180) days apart, a written explanation shall be submitted with the test protocol describing the reasons the testing could not be conducted one hundred and eighty (180) days apart. 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. 76. Points 044 and 045: The net heating value of the fuel used in the turbines shall be sampled and analyzed, at a minimum, once per every three months with consecutive samples taken at least two months apart using EPA approved methods. If sampling is performed more often, the quarterly average results of all valid fuel analyses shall be used in the emission calculations. 77. Point 047: The operator shall measure the emission rate(s) for Process 01 - Still Vent Routed to RTO 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 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. COLORADO Air Pollution Control Division Page 34 of 57 ance with the requirements of the Air Pollution Test nual and shall be submitted to the Division for review an • approval at eas thirty ) 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 78. Point 047: For Process 01, 02 and 03, at a minimum frequency of once every three months, the owner or operator shall sample and complete an extended gas analysis of the acid gas stream from the still vent. Each sample shall be analyzed for heat content and total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 2,2,4- trimethylpentane and H2S content. The sample shall be collected prior to the inlet of the control device and prior to being combined with any other stream. The sampled data will be used to calculate emissions as specified in this permit. 79. Point 047: For Process 01 and 02, the net heating value of the supplemental fuel used in the RTO and TO shall be sampled and analyzed, at a minimum, once per every three months with consecutive samples taken at least two months apart using EPA approved methods. If sampling is performed more often, the quarterly average results of all valid fuel analyses shall be used in the emission calculations. 80. Point 047: For Process 04, at a minimum frequency of once every three months, the owner or operator shall sample and complete an extended gas analysis of the flash tank stream during VRU downtime. Each sample shall be analyzed for heat content and total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 2,2,4-trimethylpentane and H2S content. The sample shall be collected prior to the inlet of the control device and prior to being combined with any other stream. The sampled data will be used to calculate emissions as specified in this permit. 81. 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 (S60.5365(g)(3)). 82. 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. 83. 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. 84. Point 052: On an annual basis, the permittee shall complete an extended gas analysis of gas samples that are representative of volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. This extended COLORADO Air Pollution Control Division Page 35 of 57 t e coF pliance demonstration as required in the Emission f this • mit. 85. Point 059: For Process 01, the owner or operator shall complete an extended gas analysis of the gas in each header routed to the plant flare including, but not limited to, the cold flare header and warm flare header. The owner or operator shall collect a sample from each header routed to the plant flare on a weekly basis. Each sample shall be analyzed for heat content and stream composition including VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 2,2,4-trimethylpentane, and H2S content using EPA approved methods. The weekly heat content and stream composition results shall be averaged on a monthly basis to calculate emission as specified in this permit. ALTERNATE OPERATING SCENARIOS 86. Point 048: The electric glycol pump may be replaced with another electric glycol pump in accordance with the requirements of Regulation 3, Part A, Section IV.A and without applying for a revision to this permit or obtaining a new construction permit. The maximum glycol recirculation rate of a replacement pump shall not exceed the glycol recirculation rate as authorized in this permit. 87. Point 048: The owner or operator shall maintain a log on -site or at a local field office to contemporaneously record the start and stop dates of any pump replacement, the manufacturer, model number, serial number and capacity of the replacement pump. 88. Point 048: All pump replacements installed and operated per the alternate operating scenarios authorized by this permit must comply with all terms and conditions of this construction permit. ADDITIONAL REQUIREMENTS 89. All previous versions of this permit are cancelled upon issuance of this permit except as provided by Condition 90 in this permit. 90. The owner or operator shall operate AIRS Points 048 as authorized by permit 12WE2024 Issuance 3 (dated September 28, 2016) until the startup of the vapor recovery units (VRUs) that will be utilized to recycle the still vent emissions from AIRS point 048 (as authorized by this issuance of permit 12WE2024, Issuance 4). The startup of the electric powered vapor recovery units shall occur no later than June 30, 2019. 91. The owner or operator shall maintain the following records for a period of 5 years: • Operating hours for all emission sources. • 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. • Quarterly waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) sampling. • Fuel gas sampling. • Leak detection and repair (LDAR) program monitoring results, as well as the repair and maintenance records. • All records required by this Permit shall be retained for not less than 5 years following the date of such measurements; maintenance, and reports. COLORADO Air Pollution Control Division Page 36 of 57 92. (' a Pol E sn N• ce (APEN) shall be filed: (Reference: Regulation • 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 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. • Whenever there is a change in the owner or operator of any facility, process, or activity; or • Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; or • Whenever a permit limitation must be modified; or • No later than 30 days before the existing APEN expires. • 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 owner or operator is exercising an alternative -operating scenario and is installing a permanent replacement turbine. Submittal of an updated APEN is also required for replacement of components if such replacement results in a change of serial number. 93. 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. 94. 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) COLORADO Air Pollution Control Division trams hatewtf .1t1--pmf,rnw?t Page 37 of 57 95.DD P:..- National Emission Standards for Hazardous Air s: Ind trial, Commercial, and Institutional Boilers and rocess eaters requirements shal 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) 96. 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 97. 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 Number 3, Part B, Section II.B. upon a request for transfer of ownership and the submittal of a revised APEN and the required fee. 98. 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 Number 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. 99. 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. 100. 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. 101. 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 COLORADO Air Pollution Control Division Page 38 of 57 t, the • ner or operator of a source may request a hearing of the r ision's action. 102. 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. 103. 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: Carissa Money Permit Engineer Permit Histo Issuance Date Description Issuance 4 This Issuance Replace Points 044 and 045 with new turbines at a lower NOx emission rate of 10 ppm. Account for supplemental fuel used at the RTO for Point 047. For Point 048, revise control strategy so still vent its now recycled to plant inlet with 3% downtime to plant flare. Add Point 056, pressurized condensate unloading, Point 057 (one 400 bbl produced water storage tank),. and Point 058 (one 300 - bbl methanol storage tank). These points are existing and previously considered insignificant activities. Add Point 059 for the plant flare. This flare is existing. Issuance 3 September 28, 2016 Remove GHG conditions and requirements. For Point 047, modify control scenarios to increase VRU downtime from 1% to 3% and include a thermal oxidizer as a back-up control device for the RTO. Also, include downtime for both RTO and TO. For Point 048, modify operational parameters of flash tank which changes emissions from flash tank. Increased VRU downtime from 1% COLORADO Air Pollution Control Division 5.artovn4. 4 Ftotctar t b urs t Page 39 of 57 to 3%. For Points 050 and 051, increase condensate throughput from 456,250 bbl/yr to 730,000 bbl/yr and increase emissions limits. For Point 052, increase component count and emissions limits. Issuance 2 September 4, 2014 Revision to equipment description nomenclature for Point 046. No changes to emissions or throughput limits. Issuance 1 January 13, 2014 Issued to DCP Midstream. Addition of eight (8) permitted sources at a natural gas processing plant. Sources located at a major facility. COLORADO Air Pollution Control Division Page 40 of 57 Notes Pe . i `. per . tim o this -rmit issuance: 1) T i q •ay f , or 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 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. AIRS Point Pollutant CAS # Uncontrolled Emission Rate (lb/yr) Are the emissions reportable? Controlled Emission Rate (lb/yr) 044 Formaldehyde 50000 410 Yes 410 045 Formaldehyde 50000 410 Yes 410 046 n -Hexane 110543 567 Yes 567 047 Benzene 71432 139,810 Yes 7,507 Toluene 108883 65,700 Yes 3,564 Ethylbenzene 100414 2,400 Yes 130 Xylenes 1330207 4,911 Yes 270 n -Hexane 110543 18,256 Yes 114 048 Benzene 71432 187,095 Yes 327 Toluene 108883 94,794 Yes 166 Ethylbenzene 100414 3,280 Yes 6 Xylenes 1330207 17,851 Yes 31 n -Hexane 110543 29,328 Yes 51 050 Benzene 71432 1,505 Yes 75 Toluene 108883 4,173 Yes 209 COLORADO Air Pollution Control Division Lk: ,,arY' tii CA PUtt3f. ?aka n £r FpAron em Page 41 of 57 lb 0.414 310 Yes 15 '-s 041 3,155 Yes 158 n -Hexane 110543 8,102 Yes 405 051 Benzene 71432 2,011 Yes 101 Toluene 108883 5,572 Yes 279 Ethylbenzene 100414 415 Yes 21 Xylenes 1330207 4,212 Yes 211 n -Hexane 110543 10,819 Yes 541 052 Benzene 71432 400 Yes 65 Toluene 108883 267 Yes 43 n -Hexane 110543 8,062 Yes 1,314 056 Benzene 71432 30 No 30 Toluene 108883 30 No 30 Ethylbenzene 100414 2 No 2 Xylenes 1330207 9 No 9 n -Hexane 110543 250 Yes 250 057 Benzene 71432 210 Yes 11 n -Hexane 110543 660 No 33 058 Methanol 67561 461 Yes 461 059 Benzene 71432 246 No 12 Toluene 108883 86 No 4 Ethylbenzene 100414 4 No 0 Xylenes 1330207 15 No 1 n -Hexane 110543 1,378 Yes 73 5) The emission levels contained in this permit are based on the following emission factors: Points 044 and 045: Process 01 (Turbine Emission Factors) Actual emissions shall be based on the following emission factors, the most recent quarterly fuel heat content and the most recent monthly metered fuel gas volume. CAS Pollutant Emission Factors lb/MMBtu - Uncontrolled Source N0x 0.0399 Solar Manufacturer, 10 ppm N0x outlet CO 0.0608 Solar Manufacturer, 25 ppm CO outlet V0C 0.0021 AP -42, Chapter 3.1-2a COLORADO Paz Pollutorn Control Division Page 42 of 57 S llut Emission Factors lb/MMBtu - Uncontrolled Source SO2 0.0034 AP -42, Chapter 3.1-2a PM2.5 0.0066 AP -42, Chapter 3.1-2a 50000 Formaldehyde 0.0007 AP -42, Chapter 3.1 Process 02 (Turbine Startup Emission Factors) CAS Pollutant Emission Factors lb/event - Uncontrolled Source NOx 1 Manufacturer CO 88 Manufacturer VOC 18 Manufacturer Process 03 (Turbine Shutdown Emission Factors) CAS Pollutant Emission Factors lb/event - Uncontrolled Source NOx 1 Manufacturer CO 62 Manufacturer VOC • 8 Manufacturer 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 5.0 Manufacturer SO2 0.6 AP -42, Chapter 1.4 110543 n -Hexane 1.8 AP -42, Chapter 1.4 Emission factors are based on a rated heat input of 53.6 MMBtu/hr, a higher heating value of 999 Btu/scf, and a limited use scenario of 315 MMscf/yr or the equivalent of 67% of operating capacity. Point 047: Process 01 (Still Vent Routed to RTO) Emissions for Process 01 include venting of acid gas (amine unit still vent overhead), combustion of acid gas (amine unit still vent overhead) and combustion of supplemental fuel utilized in the RTO burners. For controlled still vent acid gas emissions: Actual VOC, HAP and H2S emissions from venting of still vent acid gas shall be calculated based on most recent waste gas sampling of the still vent acid gas stream and most recent monthly waste gas flow volume of the still vent acid gas stream to the RTO. Controlled VOC, HAP and H2S emissions are based on an RTO control efficiency of 96%. COLORADO r Pollution Control Division 'ffrnauxPiz t tc &fr rar Page 43 of 57 scf ll nce ion (wt %) = 100 x Still Vent Waste Gas (lb scf month) x Gas Molecular Weight (lbmol) 379 (lbmol)x (1 — 96% control) *V0C/ HAP concentration and Gas Molecular Weight are based on actual sampled values of the amine unit still vent waste gas stream. *Still Vent Waste Gas is the actual measured monthly flow volume of the amine unit still vent to the RTO. For RTO combustion of acid gas: Combustion emissions from combusting the acid gas (still vent acid gas stream) are calculated using the following emission factors, the most recent quarterly acid gas stream heat content and actual monthly volume of total acid gas (still vent acid gas stream) routed to the RTO. CAS Pollutant Uncontrolled Emission Factors lb/MMBtu Uncontrolled EF Source NOx 0.068 AP -42, Table 13.5-1 CO 0.31 AP -42, Table 13.5-1 Permitted emissions are based on a heat content of 12.5 btu/scf. SO2 emissions resulting from the combustion of H2S emissions in the still vent acid gas stream are based on mass balance and assuming 64.06 lb SO2/lb-mol and 34.08 lb H25/lb- mol. SO2 emissions are also based on assuming 96% of the H2S is converted to SO2 when routed to the RTO. For RTO combustion of supplemental fuel: Combustion emissions from combusting the supplemental fuel utilized in the RTO burners are calculated using the following emission factors, the most recent quarterly supplemental fuel heat content and actual monthly volume of fuel routed to the RTO. CAS Pollutant Emission Factors - Uncontrolled lb/MMBtu Source NOx 0.0980 AP -42, Table 1.4-1 CO 0.0824 AP -42, Table 1.4-1 VOC 0.0054 AP -42, Table 1.4-2 PM2.5/PM10 0.0075 AP -42, Table 1.4-2 SO2 0.0006 AP -42, Table 1.4-2 Total actual emissions for Process 01 are then based on the sum of controlled still vent acid gas emissions plus RTO combustion of acid gas plus RTO combustion of supplemental fuel. Process 02 (Still Vent Routed to TO) Emissions for Process 02 include venting of acid gas (amine unit still vent overhead) to the TO, combustion of acid gas (amine unit still vent overhead) in the TO and combustion of supplemental fuel utilized in the burners for the TO. For controlled still vent acid gas emissions: COLORADO Air Pollution Control Division Page 44 of 57 is s fr•. venting of still vent acid gas to the TO shall be c. a !W ci •, se = •n, os ec• ' t wast cas sampling of the still vent acid gas stream and mos recen mon y waste gas flow vo ume of the still vent acid gas stream to the TO. Controlled VOC, HAP and H2S emissions are based on a TO control efficiency of 96%. VOC/HAPwaste Gas scf = VOC/HAP concentration (wt %) _ 100 x Still Vent Waste Gas (month) sc r month x Gas Molecular Weight (lbmlb ol) 379 \lbmol) x (1 — 96% control) *VOC/HAP concentration and Gas Molecular Weight are based on actual sampled values of the amine unit still vent waste gas stream. *Still Vent Waste Gas is the actual measured monthly flow volume of the amine unit still vent to the TO. For TO combustion of acid gas: Combustion emissions from combusting the acid gas (still vent acid gas stream) are calculated using the following emission factors, the most recent quarterly acid gas stream heat content, and most recent monthly volume of total acid gas (still vent acid gas stream) routed to the TO. CAS Pollutant Uncontrolled Emission Factors lb/MMBtu • Uncontrolled EF Source NOx 0.138 TCEQ CO 0.31 AP -42, Table 13.5-1 Permitted emissions are based on a heat content of 12.5 btu/scf. SO2 emissions resulting from the combustion of H2S emissions in the still vent acid gas stream are based on mass balance and assuming 64.06 lb SO2/lb-mol and 34.08 lb H2S/lb- mol. SO2 emissions are also based on assuming 96% of the H2S is converted to SO2 when routed to the TO. For TO combustion of supplemental fuel: Combustion emissions from combusting supplemental fuel and TO pilot light are calculated using the following emission factors, the most recent quarterly supplemental fuel heat content, most recent monthly volume of supplemental fuel volume routed to the TO, and most recent monthly volume of fuel to the TO pilot lights. The TO pilot gas throughput shall be assumed to have a constant value of 0.1 MMBtu/hr. Monthly pilot gas throughput shall be determined by multiplying this hourly pilot gas throughput by the TO monthly hours of operation. CAS Pollutant Uncontrolled Emission Factors lb/MMBtu Uncontrolled EF Source NOx 0.138 TCEQ CO 0.31 AP -42, Table 13.5-1 Permitted emissions are based on a heat content for supplemental fuel and pilot light of 1,098 btu/scf. Process 03 (Still Vent Routed to atmosphere) COLORADO Pollution Control Division t rkr fnk:Ynr:^roan Page 45 of 57 om direct venting of still vent acid gas to the a based most recent waste gas sampling of the still vent aci • gas stream an • most recent mon y waste gas flow volume of the still vent acid gas stream to the atmosphere. VOC/HAPWaste Gas scf = VOC/HAP concentration (wt %) _ 100 x Still Vent Waste Gas (month) x Gas Molecular Weight (lbmol) : 379 (lbmol) *V0C/HAP concentration and Gas Molecular Weight are based on actual sampled values of the amine unit still vent waste gas stream. *Still Vent Waste Gas is the actual measured monthly flow volume of the amine unit still vent to atmosphere. Process 04 (Flash tank Routed to Plant Flare (Point 059) during VRU downtime) Emissions for Process 04 include venting of flash tank emissions during VRU downtime and combustion of waste gas (flash tank emissions during VRU downtime). For controlled flash tank emissions during VRU downtime: Actual VOC, HAP and H2S emissions from venting of flash tank emissions during VRU downtime shall be calculated based on most recent waste gas sampling of the flash tank emissions during VRU downtime and most recent monthly waste gas flow volume of the flash tank emissions stream to the plant flare. Controlled VOC, HAP and Hz5 emissions are based on a flare control efficiency of 95%. VOC/HAPwaste Gas VOC scf HAP concentration (wt %) - 100 x Flash Tank Waste Gas (month) x Gas Molecular Weight (lbmol) 379 (scf ) x (1 — 95% control) lbmol *VOC/HAP concentration and Gas Molecular Weight are based on actual sampled values of the flash tank waste gas stream. *Flash Tank Waste Gas is the actual measured monthly flow volume of the flash tank gas during VRU downtime to the plant flare. For Plant Flare combustion of waste gas: Combustion emissions from combusting the waste gas (flash tank emissions during VRU downtime) are calculated using the following emission factors, the most recent quarterly flash tank heat content, and volume of total waste gas (flash tank emissions during VRU downtime) combusted. CAS Pollutant Uncontrolled Emission Factors lb/MMBtu Uncontrolled EF Source NOx 0.068 AP -42, Table 13.5-1 CO 0.31 AP -42, Table 13.5-1 Permitted emissions are based on a heat content of 937.96 btu/scf. SO2 emissions resulting from the combustion of H25 emissions in the flash gas stream are based on mass balance and assuming 64.06 lb 5O2/lb-mol and 34.08 lb H2S/lb-mol. SO2 COLORADO Air Pollution Control Division LV* , rAri.Af PflMYur t -r: Lr ts,?vr�rmr�r: t Page 46 of 57 of the H2S is converted to S02 when routed to the Point 048: The V0C and HAP emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Actual V0C and HAP controlled emissions are based on a 100% control efficiency when emissions are routed to the VRU and a 95% control efficiency when emissions are routed to an open flare during VRU downtime (max 3.5% annually). To determine actual emissions during VRU downtime, the operator will multiply lb/hr emission results from the monthly GlyCalc model (based on the total actual gas throughput during the month) by the total hours of VRU downtime. A 95% control efficiency will be applied to this calculation based on the destruction efficiency of the flare. The operator will determine the actual monthly gas throughput during VRU downtime using the following equation: Total Gas Throughput, MMscfl (VRU Downtime,hrsl (Total Monthly Hours, hrsl Gas Throughputtaw Downtime = ( Month ) * l Month ) / \ Month / For Plant Flare combustion emissions: Actual N0x and CO emissions from combusting the waste gas (still vent emissions during VRU downtime plus flash tank emissions during VRU downtime) shall be calculated using the following emission factors, volume of total waste gas combusted (still vent flow rate during VRU downtime plus flash tank flow rate during VRU downtime) as reported in the most recent monthly Glycalc report and the heat content of each waste gas stream obtained from the most recent monthly GlyCalc report. Actual volume shall be based on the streams labeled "Condenser vent gas stream" and "Flash tank off gas stream" in the monthly Glycalc report in conjunction with the amount of VRU downtime. Actual heat content shall be calculated based on the stream compositions for the streams labeled "Condenser vent gas stream" and "Flash tank off gas stream" in the most recent monthly Glycalc report. CAS Pollutant Uncontrolled Emission Factors Uncontrolled EF Source N0x 0.068 lb/MMBtu AP -42, Table 13.5-1 CO 0.31 lb/MMBtu AP -42, Table 13.5-1 Point 050: CAS Pollutant Emission Factors Uncontrolled Emission Factors Controlled Source N0x 0.0004 lb/bbl 0.0004 lb/bbl AP -42, Chapter 1.4 and Chapter 13.5 CO 0.0013 lb/bbl 0.0013 lb/bbl AP -42, Chapter 1.4 and Chapter 13.5 V0C 0.1516 lb/bbl 0.0076 lb/bbl EPA Tanks 4.09d 71432 Benzene 0.0021 lb/bbl 0.0001 lb/bbl EPA Tanks 4.09d 108883 Toluene 0.0057 lb/bbl 0.0003 lb/bbl Engineering Calculation Ethylbenzene 0.0004 lb/bbl 0.00002 lb/bbl Engineering Calculation 1330207 Xylenes 0.0043 lb/bbl 0.0002 lb/bbl Engineering Calculation 110543 n -Hexane 0.0111 lb/bbl 0.0006 lb/bbl Engineering Calculation COLORADO Air Pollution Control Division (Xptleur,Ant i*u tc iii: Eri,`"1xonme?c Page 47 of 57 T con"• l M iss' ""�"" ct•,. _ r po t 050 are based on the enclosed combustor control rs are sed on the condensate tank battery as a combined unit, not per tan . " Ix, , an• PM emissions are based on a waste gas heat content of 3,677 btu/scf, waste gas volume of 1.0423 scf/bbl and pilot rating of 0.16 MMBtu/hr with a fuel heat content of 1,098 btu/scf. Point 051: CAS Pollutant Emission Factors Uncontrolled Emission Factors Controlled Source NOx 0.0003 lb/bbl 0.0003 lb/bbl AP -42, Chapter 13.5 CO 0.0016 lb/bbl 0.0016 lb/bbl AP -42, Chapter 13.5 VOC 0.2023 lb/bbl 0.0101 lb/bbl AP -42, Chapter 5.2 71432 Benzene 0.0028 lb/bbl 0.0001 lb/bbl Engineering Calculation 108883 Toluene 0.00761b/bbl 0.00041b/bbl Engineering Calculation Ethylbenzene 0.0006 lb/bbl 0.00003 lb/bbl Engineering Calculation 1330207 Xylenes 0.0058 lb/bbl 0.0003 lb/bbl Engineering Calculation 110543 n -Hexane 0.0148 lb/bbl 0.0007 lb/bbl 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 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 condensate for a similar site by the VOC emission factor. Controlled emission factors are based on an enclosed combustor efficiency of 95%. NOx, CO and PM emissions are based on a waste gas heat content of 3,677 btu/scf and waste gas volume of 1.015 MMscf/yr. Point 052: Equipment Type Gas Gas Control % Light Liquid Light Liquid Control % Connectors 15,258 30 2,524 30 Flanges 1,031 30 494 30 Open -Ended Lines --- --- --- --- Pump Seals --- --- 36 88 COLORADO it Pollution Control Division Page 48 of 57 alve . 2 95 1,224 95 .• 1 75 14 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% --- "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 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 extended gas analysis. Point 056: Emissions associated with the pressurized unloading of condensate result from gasses that are released from hoses during disconnect. Emission factors in the table below are based on vapor and liquid line volumes and specific gravity of the liquid unloaded. CAS Pollutant Emission Factors (lb/loadout event) - Uncontrolled Source VOC 1.29 Engineering Calculation 110543 n -Hexane 0.1039 Emission factors are based on liquid and vapor line volumes of 0.0327 ft /hose. Point 057: CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source NOx 0.0005 0.0005 AP-42,Table 13.5-1 CO 0.0021 0.0021 AP -42, Table 13.5-2 VOC 0.262 0.0131 CDPHE 71432 Benzene 0.007 0.0004 CDPHE 110543 n -Hexane 0.022 0.0011 CDPHE COLORADO .Air Pollution Control Division 6x.;urtm.at fd P,laC s4e.ith kt F.Tw:rs rsrent Page 49 of 57 a vo ume of .: 1 1 sc • bl Point 058: an enclosed combustor efficiency of 95%. NOx, CO as heat content of 3,677 btu/scf and waste gas CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source VOC 0.127 0.127 EPA Tanks 4.0.9d 67561 Methanol 0.127 0.127 EPA Tanks 4.0.9d Point 059 Process 01 (Purge gas and gas routed to flare due to routine maintenance activities) Combustion emissions are calculated using the following emission factors, the most recent monthly flare gas heat content, and volume of total gas combusted including, but not limited to, volume of cold header plus volume of warm header. CAS Pollutant Uncontrolled Emission Factors lb/MMBtu Uncontrolled EF Source NOx O.068 AP -42, Table 13.5-1 CO 0.31 AP -42, Table 13.5-2 Actual VOC and HAP emissions shall be calculated based on most recent gas sampling (including gas samples of cold header and warm header routed to the plant flare) and most recent monthly gas flow volume (including volume of cold header gas and warm header gas routed to the plant flare). Controlled emissions are based on 95% control for VOC and HAP. EcLuation for Actual VOC Emissions Calculations: lb VOCTotal (month) = VOCCoId Heater + VOCWarm Header V OCCoId or Warm Header (month) scf l = VOC concentration (wt %) - 100 x Purge/Process Gas month) x Gas Molecular Weight (lbmol) : 379 scf (lb al) x (1 — 95% control) *VOC concentration and Gas Molecular Weight are based on actual monthly sampled values of the gas streams routed to flare. COLORADO Air Pollution Control Division Page 50 of 57 l measured monthly flow volume of the gas routed to Equation for Actual HAP Emissions Calculations: lb l HAProcai (month) = HAP Cold Heater + HAP Warm Header lb / HAP Cold or Warm Header (month scf HAP concentration (wt %) - 100 x Purge/Process Gas ( ll month) x Gas Molecular Weight (lbmol) : 379 (lbtn ll x (1 — 95% control) *HAP concentration and Gas Molecular Weight are based on actual monthly sampled values of the gas streams routed to flare. *Purge/Process Gas is the actual measured monthly flow volume of the gas routed to flare in each header. Process 02 (Pilot light) The flare pilot light flow rate shall be assumed to have a constant flow rate of 78 scf/hr and a total of three pilot lights in the flare for a total pilot flow rate of 234 scf/hr. Monthly pilot gas throughput shall be determined by multiplying this total hourly pilot gas throughput by the flare monthly hours of operation. CAS Pollutant Emission Factors - Uncontrolled lb/MMscf Source NOx 107.65 AP -42, Table 1.4-1 CO 90.424 AP -42, Table 1.4-1 VOC 5.9206 AP -42, Table 1.4-2 PM2.5/PM10 8.1812 AP -42, Table 1.4-2 110543 n -Hexane 1.9376 AP -42, Table 1.4-3 Permitted emissions are based on a heat content of 1,098 btu/scf. 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 Major Source of CO NANSR Major Source of NOx and VOC COLORADO .Air Pollution Control Division L4:�bP✓Yi^:4.r,S ^,f w:rni Keur ₹ £i Envi? * Page 51 of 57 http: //ecfr.gpoaccess.gov/ vironment Electronic Code of Federal Regulations 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 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 COLORADO Air Pollution Control Division LY ae`t^ n =3t µNoe xra r li Fnrr -rrnrt Page 52 of 57 HMENT A: RATING 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 modificationfor 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 (COLORADO I Air Pollution Control Division DepartMerlt.AtK .tC °:.^.6 Emao=mem Page 53 of 57 pr orporates and shall be considered a Construction P • r b', e o ur a com nent replacement performed in accordance with t is OS, an the owner or operator s a l be allowed to perform such turbine or turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. 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 COLORADO Aiz Patlutioa Control Division Deg::;. en ^,€ F:aiYaC r7f. '*:r? r0fInl rit Page 54 of 57 omp s with the emission limitations and other s a•, ic. le to t - original turbine as well as any new applicable requirements for e 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. 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. COLORADO Aix Pollution Control Division Page 55 of 57 Al c Division's we site. ' esu compliance status of this unit. fired,; y this permit shall be conducted using the most Port le Analyzer Monitoring Protocol as found on the e por a le analyzer tests shall be used to monitor the 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 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., COLORADO Air Pollution Control Division ;r Page 56 of 57 elocated to Colorado becomes equivalent to the roses 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). 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 1COLORADO Mr Pollution Control Division teprtrnel; S Fi:ttd: iti,ie Exmon:'F?am: Page 57 of 57 COFit General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit AU 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. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found 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: 12WE2024 AIRS ID Number: 123 /0107/044 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Namet DCP-Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: 370 17th Street Suite 2500 (Include Zip Code) f Portable Source Home Base: Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address: RShankaran@DCPMidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 7/2018 388593 atBrICOLORADO 1 I m. i ROUT 6EnWa GattT mnmM1 Permit Number: 12WE2024 AIRS ID Number: 123 /0107/044 [Leave blank unless APCD has already assigned a permit tt and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source (check one below) ❑ STATIONARY source O PORTABLE source -OR- ❑✓ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 O Add point to existing permit O Change permit limit O Transfer of ownership4 O Other (describe below) -OR- ❑ APEN submittal for update only (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 Et Notes: Change in NOx emlSSlon factor. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Natural gas compression turbine Manufacturer: Solar Model No.: Taurus T70 Company equipment Identification No. (optional): For existing sources, operation began on: TURB-1 Serial No.: --Q85 " L)1( _6124J-2015- For new or reconstructed sources, the projected start-up date is: 0 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 Seasonal use percentage: Dec -Feb: Mar -May: days/week weeks/year Jun -Aug: Sep -Nov: Form APCD-200 - General APEN - Revision 7/2018 2 I A Y COLORADO ti.p.d HQNUt6uw..IMn1 f' "I'llj`t Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 044 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information 8 Material Use 0 Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limits (Specify Units) Material Consumption: Finished Produc(s) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information 4,478,327.79/528,681.36 ❑ 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. `S�J�`�?u`�`k`z„,. x et Ar O erator � tact IQIo �"`. � Tempelg l 7,*) . ilt Above �.k.,. un +� Fee LeN I r. . ., ...m. ,_mod-. TURB-1 45 941 127,352 169 Indicate the direction of the stack outlet: (check one) Q Upward ❑ Horizontal O Downward ['Other (describe): O Upward with obstructing raincap Indicate the stack opening and size: (check one) 12 Circular Interior stack diameter (inches): 48 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): Other (describe): Form APCD-200 - General APEN - Revision 7/2018 --COLORADO 3 - . n _oe�x,:kl� i:aazmasnwmnmeni Permit Number: 12WE2024 AIRS ID Number: 123 /0107/044 [Leave blank unless APCD has already assigned a permit #t and AIRS ID] Section 6 - Combustion Equipment £t 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 (MMBTU/br) ::: Actual Annual Fuel Use {Specify Units) : : ,. Requested Annual Permit Limits (Specify Units) 72.73 502.4 MMscf/yr ` MMscf/yr From what year is the actual annua fuel use data? Indicate the type of fuel used6: ❑ 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/SCE) ❑ Coal Heating value: BTU/lb Ash content: Sulfur content: 2017 ❑✓ Other (describe): Residue Gas Heating value (give units): 1,098 Btu/scf 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 If fuel heating value is different than the listed assumed value, 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 uioment AND state the overall control efficiency (% reduction): Pollutant Control Equipment . Description . Overall Collection Efficiency; Overall Control Efficiency: (%r ons) ,_ eduction to emissi TSP (PM) PMio PM2.5 SO,, NO), CO VOC Other: Form APCD-200 - General APEN - Revision 7/2018 41 COLORADO iatr,xtic ti u:Ev,mn�unen� TSP (PM) Permit Number: 12W E2024 AIRS 1D Number: 123 /0107/044 [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? 201 7 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.) Uncontrolle d.. Emission Factor (Specify Units)` Emission Factor Source etc ) Uncontrolled (tons%year) __ Control led Uncontrolled (tor s/year) Controlled7: (tons%year). (tons/year) 0.0066 Ib/MMBtu AP -42 1.80 1.80 0- 2:10` PMio 0.0066 Ib/MMBtu AP -42 1.80 1.80 2-40 --27109 PM2.5 0.0066 Ib/MMBtu AP -42 1.80 1.80 2-40 2:-1-p- SOx 0.0034 Ib/MMBtu AP -42 0.93 0.93 4O8 1708-- NOx 0.039 Ib/MMBtu Mfg. 12.87 12.87 4243- 1 -2.43 - Co ...(1-0553 Ib/MMBtu Mfg. 15.08 15.08 X7:61 -17:69" VOC 0.0021 Ib/MMBtu AP -42 0.57 0.57 0:67" Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth.- -- .. - 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. p 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) equal to or greater than 250 lbs/year? �✓ Yes ❑ No towing table to repart the non -criteria pollutant (HAP) emissions from source: CAS e- Chemical : Name .... Overall Control Efficiency ' Uncontrolled . Emission Factor ",:_. (Specify Units) . Emission Factor Source (AP 42; Mfg , etc ) Uncontrolled. Actual Emissions (lbs/year) Controlled ' Actual Emissions 7 • (lbs/year) 50-00-0 maldedehyde Formaldehyde N/A 7.1E-04 AP -42 X87--iMC -3$7-'-lit. 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision. 7/2018 51 -V Eiluircotreletel COLORADO Permit Number: 12WE2024 AIRS ID Number: 123 /0107/044 [Leave blank unless APCD has already assigned a permit # 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. to(5/7ag Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: Draft permit prior to issuance ✓i 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 61; COLORADO Hrt.ocneolPuE:lc ambEnWm3manl RECEIVED OCT - 5 2018 General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and 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. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found 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: 12WE2024 AIRS ID Number: 123 /0107/045 APCD Stationary �jou�oan [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Portable Source Home Base: Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 7/2018 388594 COLORADO 1 I tr,.mecn xauwmmrni Permit Number: 12WE2024 AIRS ID Number: 123 /0107/045 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action O NEW permit OR newly -reported emission source (check one below) ❑ STATIONARY source ❑ PORTABLE source -OR - ❑✓ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 O Add point to existing permit ❑✓ Change permit limit O Transfer of ownership4 O Other (describe below) -OR- ❑ APEN submittal for update only (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: Change in NOx emission factor. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Natural gas compression turbine Manufacturer: Solar Model No.: Taurus T70 Company equipment Identification No. (optional): For existing sources, operation began on: TURB-2 Serial No.: 6124 e1 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: Form APCD-200 - General APEN - Revision 7/2018 Jun -Aug: Sep -Nov: COLORADO 2 �V i6Stdauram smme,snNmnnwni Permit Number: 12WE2024 AIRS ID Number: 123 / 0107/ 045 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information £t Material Use �✓ Check box if this information is not applicable to source or process From what year is the actual annual amount? Material Consumption Finished Product(s) Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit L' .t5 (Specify Units) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information 4,478,327.79/528,681.36 ['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. ..e�+. e-aY.e4Y >.swt. t A dI t^w 4 �� y++ discharge Height 3 ��' ~`r x *1 w Tem ( F� ar �i ;d, .. k+ rr&^at '# -.'✓ xN.uc�k Flow to (ACFM) .. �ufvr .. by €.ax. 127,352 ;.§Xi„'...6-•"*.'"'�__.., �+. Velocity �e(r�t°j . Jtacl��D 170 `3"+ ..:.. s d' -WX 6 Above Ground Level aS- 4M4 i- Y .t 4.(�—./'F a ., -(ft/sec 169 .:_k . TURB-2 45 941 Indicate the direction of the stack outlet: (check one) p✓ Upward 0 Horizontal 0 Downward Other (describe): Indicate the stack opening and size: (check one) Q✓ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): ❑ Other (describe): El Upward with obstructing raincap 48 Interior stack depth (inches): Form APCD-200 - General APEN - Revision 7/2018 3 ICOLOR ADO Health hits haM Permit Number: 12WE2024 AIRS ID Number: 123 /0107/045 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment a Fuel Consumption Information 0 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 (MMBTU/hr) Actual Annual Fuel Use (Specify Units) ! Requested Annual Permit Limits (Specify Units) 72.73 532.0 MMscf/yr --63-79-MMscf/yr From what year is the actual annua fuel use data? 2017 Indicate the type of fuel used6: o Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) o 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: 0 Other (describe): Residue Gas Heating value (give units): 1,098 Btu/scf 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 If fuel heating value is different than the listed assumed value, 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? 0 Yes 0 No ribe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Collection Efficiency', Overall Control Efficiency (96' reduction in emissions) TSP (PM) PMio PM2.5 SOX NOx CO VOC Other: Form APCD-200 - General APEN - Revision 7/2018 41 COLORADO ➢.atm&En tmnnwc iianlh bEnuirannit><1 TSP (PM) Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 045 [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? 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.) 2017 Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled (tons/year) Controlled? (tons/year) nnuarPirmi mission Limits` Uncontrolled (tons/year) Controlled (tons/year) !, 0.0066 Ib/MMBtu AP -42 1.91 1.91 —240— PMto 0.0066 Ib/MMBtu AP -42 1.91 1.91 PM2.5 0.0066 Ib/MMBtu AP -42 1.91 1.91 SOX 0.0034 Ib/MMBtu AP -42 0.98 0.98 -4708 NO. 0.039 Ib/MMBtu Mfg. 13.63 13.63 CO ;, : t, 53-Ib/MMBtu Mfg. 15.96 15.96 ---!M61" VOC 0.0021 lb/MMBtu AP -42 0.61 0.61 Other: 5 Requested values will become permit limitations. Requested timit(s) should consider future process growth. 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. p.LX nn1 :: 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) equal to or greater than 250 lbs/year? 0✓ Yes ❑ No criteria pollutant (HAP) emissions from source: CAS Number Chemical '. Name Overall Control Efficiency. _ Uncontrolled Emission Factor )Specify Units) _ Emission Factor Source (AP -42, M etc .) Mfg--- Uncontrolled Actual Emissions (!bs/year) Controlled Actual Emissions 7 ' (!bs/year) 50-00-0 Formaldehyde N/A 7.1E-04 AP -42 410 410 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 7/2018 COLORADO 5 I L. I tt wumauunAnmon+ Permit Number: 12WE2024 AIRS ID Number: 123 /0107/045 [Leave blank unless APCD has already assigned a permit # 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. Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: 0✓ Draft permit prior to issuance 0✓ 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 COLORADO 6 I AV! naumarnmmamnni OFY Amine Sweetening Unit - Form APCD-206 Air Pollutant Emission Notice (APEN) and 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. This APEN is to be used for amine sweetening units only. If your emission unit does not fall into this category, there may be a more specific APEN available for your source (e.g. glycol dehydration unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.Rov/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: 12WE2024 AIRS ID Number: 123 / 0107 / 047 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section -1 — Administrative Information Company Name': DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 388595 Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 1 I COLORADO tip rueenlNPuttic IiaaLib LlNratumN Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 047 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source -OR - ❑✓ MODIFICATION to existing permit (check each box below that applies) O Change fuel or equipment O Change company name3 O Add point to existing permit ❑✓ Change permit limit O Transfer of ownership4 O Other (describe below) -OR- ❑ APEN submittal for update only (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) Additional Info Et Notes: Operating Scenarios: (1) Acid gas primarily controlled by RTO, (2) backup TO with 96% DRE employed during RTO downtime, (3) during RTO/TO downtime acid gas vents to atm, (4) VRU downtime emissions routed to plant flare with 95% DRE. Adding RTO pilot and changing TO emission factors. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Amine treating unit for CO2 removal, permitted with 4 operating scenarios. See additional notes in Section 2. Company equipment Identification No. (optional): AU -02 For existing sources, operation began on: 6/24/2015 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 hours/day days/week weeks/year Operation: Will this equipment be operated in any NAAQS Yes O No nonattainment area? Does this facility have a design capacity less than 2 long Yes ❑ No tons/day of H2S in the acid gas? Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO 2 Ybegs rtresne RliIPSEnNl Palk Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 047 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Amine Unit Equipment Information Manufacturer: Fabwell Model No.: 108" amine contactor Absorber Column Stages: Amine Type: stages ❑ MEA ❑ DEA ❑ TEA Pump Make and Model: Baker Hughes HPHYMARK Serial Number: 13-1311-1 ❑✓ MDEA ❑ DGA # of pumps: 3 Sour Gas Throughput: Design Capacity: 230 MMSCF/day Requested5: 83,950 MMSCF/year Actual: 80,048 MMSCF/year Sour Gas: Pressure: 900.5 psig Temperature: 78.14 °F Lean Amine Stream: Pressure: 932.3 psia Temperature: 122 Ftowrate: 945 gal/min Wt. % amine: 50 Mole loading HzS: 6.1 E-05 °F Mole Loading 0.396_- COz: NGL Input: Pressure: Ftowrate: psia Gal/min Temperature: °F Flash Tank: O No Flash Tank Pressure: 72.33 psia Temperature: 158 °F Additional Required Information: o Attach a Process Flow Diagram ❑ Attach the simulation model inputs Et emissions report o Attach composition reports for the rich amine feed, sour gas feed, NGL feed, Et outlet stream (emissions) ❑ Attach the extended gas analysis (including BTEX Et n -Hexane, H2S, CO2, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO fililPfr EnhlaMianl Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 047 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/longitude or 11TM), 4,478,327.79, 528,681.36 eJe f q x-IDischar � Operator Stack 1D No re-( =. -<, a Het ht g g Above Ground Level �x (feet) t - Temp f F� „._. r { FI9 Rafe �" 5 * r (ACEN)(ft/ velocity sec AU -02 40 Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Circular O Square/rectangle O Other (describe): Interior stack diameter (inches): O Upward with obstructing raincap Interior stack width (inches): Interior stack depth (inches): Section 6 - Control Device Information O Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. 0 VRU: Used for control of: Amine flash stream Size: Make/Model: Ariel / JGP / 2 Requested Control Efficiency: 100 VRU Downtime or Bypassed: 3 ❑ Combustion Device: Used for control of: Acid Gas Stream Rating: MMBtu/hr Type: RTO/TO Make/Model: Anguil / 150 / 17714 Requested Control Efficiency: 96 % Manufacturer Guaranteed Control Efficiency: 99 % Minimum Temperature: 1,550 °F Waste Gas Heat Content: 12.5 Btu/scf Constant Pilot Light: O Yes 0 No Pilot Burner Rating: 5.5 MMBtu/hr Supplemental Fuel Flow: 9.58 MMscf/year Supplemental Fuel Heat Content: 1,098 Btu/scf Closed ❑ Loop System: Used for control of: Description: System Downtime: ❑✓ Other: Used for control of: See description in Section 2 for the four (4) operating scenarios Description: Requested Control Efficiency: Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 COLORADO 4I ANY I=mtcn�� wssvwn & Benzene Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 047 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Pollutant PM Description of Control Method(s) Overall Requested Control Efficiency (% reduction in`emissions) -' sox H2S NO), CO VOC Still - RTO / TO, Flash - VRU (Plant Flare during VRU DT) Still - 98%, Flash -100% (95% during VRU DT) HAPs Still - RTO / TO, Flash - VRU (Plant Flare during VRU DT) Sti8 - 96%, Flash - 100% (95% during VRU DT) Other: From what year is the following reported actual annual emissions data? 2017 0.03 lb/MMscf Eng. Est. Uncontrolled Basis PM Criteria Pollutant Emissions Inventory Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 ncontrolled' Emissions (tons/year) ?, -Controlled Emissions6 (tons/year) `: Uncontrolled missions bns/ ear 0.04/-/-/- 0.04/—/—/- SOx 21.82 lb/MMscf Eng. Est. --/-/—/ 13.4210.101- /0.00 -/-/--/- 31.3/1.1 /-/-012•<- H25 0.42 lb/MMscf Eng. Est. 7.14/1.39/0.13/0.00 0.29/0.06/0.13/0.00 17.3/0.6/0.3/0.1 0.7/0.02/0.3/0.0 NOx 0.068 lb/MMBtu AP -42 0.39/0.24/-/0.01 0.39/0/4/-40.01 1.7/0.8/—/0.1 1.7/0.8/—/0.1 CO 0.31 Ib/MMBtu AP -42 1.29/0.65/-10.02 1.29/0.65/-/0.02 6.0/1.8/—/0.5 6.0/1.8/--/0.5 VOC 17.25 lb/MMscf Eng. Est. 89.89/19.68/1.33/1.06 3.60/0.79/1.33/0.05 166.9/5.9/2.8/557.2 6.7/0.2/2.8/0.8 Non -Criteria Reportable_Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number 71432 Emission Factor , Uncontrolled Basis 1.67 Ib/MMscf Source (AP -42, Mfg., etc.) Eng. Est... Actual Annual Emissions Uncontrolled Emissions (pounds/year) -262654-87694-575440- Controlled Emissions6 (pounds/year) 1-050-/-351--/-57-54-0,5 Toluene 108883 0.78 lb/MMscf Eng. Est. -16959-/4465 _ / _ 2₹4-1-4- x..58-/-4-7.9-/-274 / 0.2 Ethylbenzene Xylene 100414 0.03 lb/MMscf Eng. Est. 5534 1 67-i-91 0 1- - 22-/-,4-/-9 / 0.005 1330207 0.06 lb/MMscf Eng. Est. 31014-898 / 48 /VL 124-/36+4-8 0 O3- n -Hexane 110543 0.22 lb/MMscf Eng. Est. 1273-/229116116- 1 -/-1-f-16+1 2,2,4- Trimethylpentane Other: 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. NOTE: Uncontrolled Emission Factors for HAPs based on future potential emissions Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 5I 'cOLORAoo 1 D i;Inssu , ualm f nnufmnnwN Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 047 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. io15/zo1a Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance El 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-206 - Amine Sweetening Unit APEN - Revision 7/2018 6I COLORADO �_ Dep. xdrnt& e HBLRb£nvIz.nanI Glycol Dehydration Unit APEN Form APCD-202 Air Pollutant Emission Notice (APEN) and 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. This APEN is to be used for glycol dehydration (dehy) units only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, hydrocarbon liquid loading, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found 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: 12WE2024 to - 5 '1018 station Y sources AIRS ID Number: 123 / 0107 /048 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 388596 1 I AV4COLORADO Permit Number: 12WE2024 AIRS ID Number: 123/01w/048 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source -OR- ✓❑ MODIFICATION to existing permit (check each box below that applies) O Change fuel or equipment O Change company name3 O Add point to existing permit ❑✓ Change permit limit ❑ Transfer of ownership4 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (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) Additional Info Et Notes: Change in operation. Still and flash stream emissions recycled to plant inlet via VRU. VRU downtime (3.5% / yr) emissions routed to plant flare. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-1O6) must be submitted. 4 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: TEG Dehydrator Unit Company equipment Identification No. (optional): D-01 For existing sources, operation began on: 6/24/2015 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 Will this equipment be operated in any NAAQS nonattainment area? Is this unit located at a stationary source that is considered a Major Source of (HAP) Emissions? Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 El Yes Yes weeks/year No No COLORADO 2.1 A17'1 ' xevmarnmmnm1 Permit Number: 12WE2024 AIRS ID Number: 123 /0107 / 048 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Prof Projects Inc. Model Number: T-9600 Dehydrator Serial Number: 5518 Reboiler Rating: Indirect MMBTU/hr hr Glycol Used: O Ethylene Glycol (EG) O DiEthylene Glycol (DEG) 0 TriEthylene Glycol (TEG) Glycol Pump Drive: ❑✓ Electric O Gas If Gas, injection pump ratio: Pump Make and Model: Cat Pumps / 3541.0110 Glycol Recirculation rate (gal/min): Max: 40 Lean Glycol Water Content: 1.5 Wt.% Requested: 40 Acfm/gpm # of pumps: 1 P+1 B Dehydrator Gas Throughput: Design Capacity: 230 MMSCF/day Requested5: 83,950 MMSCF/year Actual: 80,048 MMSCF/year Inlet Gas: Pressure: 920 psig Temperature: 100 °F Water Content: Wet Gas: lb/MMSCF ❑✓ Saturated Dry gas: 5.0 lb/MMSCF Flash Tank: Pressure: 65 psig Temperature: 175 °F O NA Cold Separator: Pressure: - psig Temperature: °F ❑✓ NA Stripping Gas: (check one) ❑✓ None O Flash Gas O Dry Gas O Nitrogen Flow Rate: scfm Additional Required Information: ❑✓ Attach a Process Flow Diagram ❑✓ Attach GRI-GLYCaIc 4.0 Input Report Et Aggregate Report (or equivalent simulation report/test results) ❑,/ Attach the extended gas analysis (including BTEX Et n -Hexane, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 COLORADO 3 I AV D IP FGn1libEnulmnrtuM ❑ Upward o Horizontal Permit Number: 12WE2024 AIRS ID Number: 123/0107/048 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 4,478,327.79 / 528,681.36 .i Operators Stack7D No z k Discharge Height Above Ground Level .. (feet) Temp ( F) _._-... Flow Rate � (ACFhQFn _ .._ .. _ k x Velocity {ft/iec)� D-01 123 (Flare) Indicate the direction of the stack outlet: (check one) ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) o Circular ❑ Square/rectangle ❑ Other (describe): Interior stack diameter (inches): Interior stack width (inches): 0 Upward with obstructing raincap Interior stack depth (inches): Section 6 - Control Device Information 0 Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. ❑ Condenser: Used for control of: Type: Make/Model: Maximum Temp: °F Average Temp: °F Requested Control Efficiency: ❑✓ VRU: Used for control of: VOC and HAPs from still vent and flash tank streams Size: Make/Model: TBD Requested Control Efficiency: 100 % VRU Downtime or Bypassed: 3.5 ❑ Combustion Device: Used for control of: V0C and HAPs from still vent and flash tank streams Rating: MMBtu/hr Type: Plant Flare Make/Model: Zeeco / HSLF Requested Control Efficiency: 95 Manufacturer Guaranteed Control Efficiency: 98 % Minimum Temperature: °F Waste Gas Heat Content: 2,924 / 1,754 Constant Pilot Light: ❑✓ Yes 0 No Pilot Burner Rating: 0.26 Btu/scf MMBtu/hr Closed --- ❑ Loop System: Used for control of: _ Description: _ System Downtime: ❑✓ Other: Used for control of: VOC/HAP from still vent/flash tank (3.5% VRU DT only) Description: Plant Flare Requested Control Efficiency: 95 Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 ICOLORADO 4i'DepartreerrtaiPubtic PM PM Permit Number: 12WE2024 AIRS ID Number: 123/m07/O48 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emission calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can overall (or combined) control efficiency (% reduction): Description of Control Method(s) be used to state the Overall Requested Control Efficiency, O6 reduction in emissions) SOX NO. CO VOC VRIJs to control still vent and flash tank streams 100 (3.5% downtime to plant flare) HAPs VRUs to control still vent and flash tank streams 100 (3.5% downtime to plant flare) Other: From what year is the following reported actual annual emissions data? 2017 Criteria Pollutant Emissions Inventory Actual Annual Emissions t ntro8dd missions (tons/year)r= Requested Annual Permit Emission Limit(s)5__ 0.00 SOX 0 lb/MMscf Mass Balance NOX CO 0.068 lb/MMBtu AP -42 0.36 0.36 0.08 0.08 0.310 Ib/MMBtu AP -42 0.45 0.45 0.37 0.37 VOC 0.7931 Ib/MMscf GlyCalc 721.15 13.30 1.66 Chemical Name Benzene Chemical Abstract Non -Criteria Reportable Pollutant Emissions Inventory Actual Annual Emissions Service (CAS) Number 71432 Emission Factor Uncontrolled - Basis 0.0780 Units lb/MMscf Source (AP -42, Mfg., etc.) GlyCalc Uncontrolled Emissions (pounds/year) iK T 1 7226' Controlled Emissrons6 (pounds/ year) •-2;688- s7 Toluene 108883 0.0395 Ib/MMscf GlyCalc t 85;634 -998 ; u Ethylbenzene Xylene 100414 0.0014 Ib/MMscf GlyCalc 298- 49- 1330207 0.0074 lb/MMscf GlyCalc 11-�5.27;3-3tj- --95— 3 E n -Hexane 110543 0.0122 lb/MMscf GlyCalc >"5' 423-- ; I 2,2,4- Trimethylpentane Other: 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. NOTE: Uncontrolled Emission Factors for HAPs based on future potential emissions laylcoLoRanO Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 Permit Number: 12WE2024 AIRS ID Number: 123/m07/048 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. io/5/2oig Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ▪ Draft permit prior to issuance ▪ 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.Rov/cdphe/apcd Form APCD-202 - Glycol Dehydration Unit APEN - Revision 7/2018 COLORADO 6I AMDV OF', czNO oivS -v31A" Condensate Storage Tank(s) APEN Form APCD-205 Ssp ty Air Pollutant Emission Notice (APEN) and 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. This APEN is to be used for tanks that store condensate associated with oil and gas industry operations. If your emission source does not fall into this category, there may be a more specific APEN available for your source (e.g. crude oil storage tanks, produced water storage tanks, hydrocarbon liquid loading, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms and associated addendum forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/pacific/cdphe/air-permits. 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: 12WE2024 AIRS ID Number: 123 /0107/050 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: (include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 388597 ADO 1 .AZ (COLORwams�mronnrni Permit Number: 12WE2024 AIRS ID Number: 123 /0107/050 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action O NEW permit OR newly -reported emission source O Request coverage under traditional construction permit 0 Request coverage under a General Permit O GP01 O GP08 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- O MODIFICATION to existing permit (check each box below that applies) ❑ Change in equipment O Change company name3 El Change permit limit O Transfer of ownership4 O Other (describe below) - OR ▪ APEN submittal for update only ,(Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ▪ APEN submittal for permit exempt/grandfathered source ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: Change to emission factor for NOx and CO and allocation of the enclosed combustor pilot to source. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Stabilized Atmospheric Condensate Tanks Company equipment Identification No. (optional): TANKS For existing sources, operation began on: 06/24/2015 For new or reconstructed sources, the projected start-up date is: Normal Hours of Source Operation: 24 hours/day 7 days/week 52 Storage tanks) located at: 0 Exploration a Production (EEtP) site weeks/year ❑✓ Midstream or Downstream (non E&P) site Will this equipment be operated in any NAAQS nonattainment area? 51 Yes ■ No Are Flash Emissions anticipated from these storage tanks? ■ Yes 51 No Is the actual annual average hydrocarbon liquid throughput ≥ 500 bbl/day? 51 Yes ■ No If "yes", identify the stock tank gas -to -oil ratio: 0.0002 m3/liter Are these storage tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-105. II Yes 151 No Are you requesting ≥ 6 ton/yr VOC emissions (per storage tank), or are uncontrolled actual emissions ≥ 6 ton/yr (per storage tank)? Yes No 19 ■ Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 2 I A. COLORADaO wssmasnw�an�aai Permit Number: 12WE2024 AIRS ID Number: 123 /0107/050 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Storage Tank(s) Information Condensate Throughput:' Actual Annual Amount (bbl/year) 391,188 From what year is the actual annual amount? 2017 Average API gravity of sates oil: 65.35 degrees O Internal floating roof Tank design: 0 Fixed roof Requested Annual Permit Limits (bbl/year) 's 730,000 RVP of sales oil: 10 psi O External floating roof StorageLiquid T ank ID # of Manifold Storage V i in Storage Tank . Total Volume of Storage Tank (bbl) Installation Date of Mott, Recent Storage Vessel in Storage Tank',(month/year) . Date of Firs t Production • (month/year)' TANKS 4 1,000 2014 API Number Wells Serviced by this Storage Tank or Tank Battery6 (EFtP Sites Only) - .• ; Name of Well Newly Reported Well O O ❑ _ . _❑ 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 6 The E&P Storage Tank APEN Addendum (Form APCD-212) should be completed and attached when additional space is needed to report all wells that are serviced by the equipment reported on this APEN form. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) '4,478,327.79 / 528,681.36 Operator Stack ID No. . Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity ., (ft/sec) TANKS 19 (ECD) Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Circular ❑ Square/rectangle ❑ Other (describe): O Upward with obstructing raincap Interior stack diameter (inches): Interior stack width (inches): Interior stack depth (inches): Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 AVOICOLORADO L 3 I `d' i � ' ,` . Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ 050 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information O Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Vapor ❑ Recovery Unit (VRU): Pollutants Controlled: Size: Make/Model: Requested Control Efficiency: % VRU Downtime or Bypassed (emissions vented): ❑ Combustion Device: ❑ Other: Pollutants Controlled: VOC and HAPs Rating: MMBtu/hr Type: Enclosed Combustor Make/Model: Ab utec Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98 Waste Gas Heat Content: Constant Pilot Light: ❑✓ Yes ❑ No Pilot Burner Rating: Minimum Temperature: Description of the closed loop system: Pollutants Controlled: Description: Control Efficiency Requested: 3,677 0.16 Btu/scf MMBtu /hr Section 7 - Gas/Liquids Separation Technology Information (EELP Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? psig Describe the separation process between the well and the storage tanks: Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 6 4 IiCOLORAD4 Benzene VOC Permit Number: 12WE2024 AIRS ID Number: 123 10107/050 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form7. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Description of Control Method(s) Enclosed Combustor Overall Requested Control Efficiency (% reduction in emissions) 't 95 NOx CO HAPs Enclosed Combustor 95 Other: From what year is the following reported actual annual emissions data? 2017 riteria Pollutant Emissions Inventory - Pollutant VOC Emission Factor' Source (AP -42,' Mfg.; etc) Actual Annual Emissions Requested Annual Permit.': Emission Linit(s)5 , Uncontrolled Basis 0.1516 Units ,. lb/bbl Tanks 4.09d Uncontrolled Emissions (Tons/year) 29.7 Controlled Emissions8 (Tons/year) 1.5 Uncontrolled Emissions (Tons/year) `. 55.34 Controlled Emissions (Tons/year) 2.77 NOx 0.0004 lb/bbl AP -42 0.1 0.1 '0:12 CO 0.0013 lb/bbl AP -42 0.04 0.04 on Criteria Reportable Pollutant Emissions 1nvento Chemical Abstract Service (CAS) Number Emission Factor' Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg. etc) Uncontrolled Emissions (Pounds/year) Controlled, Emissionsg' pod/lilt/oat) 71432 0.0021 lb/bbl Eng. Est. 821 41 Toluene 108883 0.0057 lb/bbl Eng. Est. 2230 111 Ethylbenzene Xylene 100414 0.0004 lb/bbl Eng. Est. 1330207 0.0043 lb/bbl Eng. Est. 1682 84 n -Hexane 110543 0.011 lb/bbl Eng. Est. 4342 217 2,2,4- Trimethylpentane 540841 0.00001 lb/bbl Eng. Est. 5 Requested values will become permit Limitations. Requested limit(s) should consider future growth. 7 Attach condensate liquid laboratory analysis, stack test results, and associated emissions calculations if you are requesting site specific emissions factors according to the guidance in PS Memo 14-03. g Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 5I A® I COLORADO Cepinma telPulLc Permit Number: 12WE2024 AIRS ID Number: 123 /0107/050 [Leave blank unless APCD has already assigned a permit # 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. If this is a registration for coverage under General Permit GP01 or GP08, I further certify that this source is and will be operated in full compliance with each condition of the applicable General Permit. f, io I5/20iR Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ❑ 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.Rov/cdphe/apcd Form APCD-205 - Condensate Storage Tank(s) APEN - Revision 7/2018 COLORADO 6I l . RauNbEnWI? Lk copy�p18 „co\rop act CPC Hydrocarbon Liquid Loading APEN stiff ?;2 Form APCD-208 Air Pollutant Emission Notice (APEN) and 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. This APEN is to be used for hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found 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: 12WE2024 AIRS ID Number: 123 / 0107 / 051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location:. 31495 Weld County Road 43 Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Phone Number: E -Mail Address2: Roshini Shankaran 303-605-2039 RShankaran@DCPMidstream.com 1 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 388598 COLORADO 1 1 it=r,,,,,tf. Permit Number: 12WE2024 AIRS ID Number: 123 /0107/051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source O Request coverage under construction permit O Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR - ❑✓ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name3 ❑✓ Change permit limit O Transfer of ownership4 O Other (describe below) - OR • APEN submittal for update only (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) Additional Info a Notes: Change in NOx and CO emission factors and allocation of the enclosed combustor pilot emissions to controlled sources. No change in throughput is being requested. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Loadout of stabilized condensate Company equipment Identification No. (optional): LOAD For existing sources, operation began on: 6/24/2015 For new or reconstructed sources, the projected start-up date is: Will this equipment be operated in any NAAQS nonattainment area? p Yes • No Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • p Does this source load gasoline into transport vehicles? ■ Yes IN No Is this source located at an oil and gas exploration and production site? ■ Yes NI No If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average? • Yes ■ No Does this source splash fill less than 6750 bbl of condensate per year? ■ Yes • No Does this source submerge fill less than 16308 bbl of condensate per year? ■ Yes ■ No Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLOR A DO 2 I � v AariO�£EfuNwan�snl Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / 051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: ❑✓ Condensate O Crude Oil O Other: If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: 730,000 bbl/year This product is loaded from tanks at this facility into: (e.g. "rail tank cars" or "tank trucks") Actual Volume Loaded: Tank Trucks 391,188 bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: 0.6 Average temperature of bulk liquid loading: �� . ^ 5° `t F True Vapor Pressure:Psia 5.0032 @ 60 °F Molecular weight of displaced vapors: 66 lb/lb-mol If this APEN is being filed for vapors displaced from pressurized loading lines, complete the following: Requested Volume Loaded5: bbl/year Actual Volume Loaded: bbl/year Product Density: lb/ft3 Load Line Volume: ft3/truckload Vapor Recovery Line Volume: ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 ®ICOIORADO HauMbEnNmnumnl Permit Number: 12WE2024 AIRS ID Number: 123 /0107/051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 4,478,327.79 / 528,681.36 sK p?,v �' Y Operator �. Stak ID Nom ac t DtscharRe Hetght Above Ground Leve[ � "" Temp � FloVi► Rafe {AC M) ' ,t Yeloctty fis /sec)�� LOAD 19 Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Circular ❑ Other (describe): Interior stack diameter (inches): ❑ Upward with obstructing raincap Section 6 - Control Device Information Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. ❑ Loading occurs using a vapor balance system: Requested Control Efficiency: % O Combustion Device: Used for control of: VOC and HAPs Rating: Type: Enclosed Combustor MMBtu/hr Make/Model: Abutec Requested Control Efficiency: 95 Manufacturer Guaranteed Control Efficiency: 98 Minimum Temperature: °F Waste Gas Heat Content: 3,677 Btu/scf Constant Pilot Light: El Yes ❑ No Pilot Burner Rating: 0.16 MMBtu/hr ❑ Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 4 I AY I FNfA bFnW,°auwnl PM Permit Number: 12WE2024 AIRS ID Number: 123 /0107/051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Description of Control Methods) Overall Requested Control Efficiency (% reduction in emissions) SO. NOx CO VOC Enclosed Combustor 95 HAPs Enclosed Combustor 95 Other: ❑ Using State Emission Factors (Required for GP07) ❑ Condensate ❑ Crude VOC 0.236 Lbs/BBL 0.104 Lbs/BBL Benzene 0.00041 Lbs/BBL 0.00018 Lbs/BBL n -Hexane 0.0036 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? 2017 Pollutant-= Uncontrolled -.: Basis PM -nteria Pollutant=Emissions"Inventory ------------ - Source Uncontrolled - (AP=42, Emissions Mfg., etc.); (tons/year) Controlled Uncontrolled Emissions ` " (tons/year) Emissions6 (tons/year) Controlled Emissions _" (tons%year). SOX �;. a:� NOx CO -A:96tis Ib/bbl AP -42 0.06 0.06 Ib/bbl AP -42 0.04 0.04 0.61 0.61 VOC 0.2023 Ib/bbl AP -42 39.6 2.0 73.85 3.69 Chemical Name Benzene Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number 71432 Emission Factor Uncontrolled Basis 0.0028 Ib/bbl Source (AP -42, Mfg., etc.) Eng. Est Actual Annual Emissions Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Toluene 108883 0.0076 Ib/bbl Eng. Est Ethylbenzene Xylene n -Hexane - 100414 1330207 110543 0.0006 0.0058 0.0148 Ib/bbl Ib/bbl Ib/bbl Eng. Est Eng. Est Eng. Est 2,2,4- Trimethylpentane Other: 540841 0.00001 Ib/bbl Eng. Est 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 5 I ��I14.1.1.61114106.7.1 d 4 41 Permit Number: 12WE2024 AIRS ID Number: 123 /0107/051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑✓ Draft permit prior to issuance El 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 I COLORADO 6I AVI,=� IiaJlAbTnMpCmmi Hydrocarbon Liquid Loading APEN Form APCD-208 Air Pollutant Emission Notice (APEN) and 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. This APEN is to be used for hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found 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: 12WE2024 AIRS ID Number: 123 / 0107 / 05ip [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com i 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 388599 COLORADO 1 awecm ®'� i xaaimaewn.onm�n� Permit Number: 12WE2024 _ [Leave blank unless APCD has already assigned a permit # and AIRS ID] AIRS ID Number: 123 / 0107/ Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source ❑✓ Request coverage under construction permit 0 Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR- ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name3 0 Change permit limit ❑ Transfer of ownership4 ❑ Other (describe below) - OR ▪ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info 8 Notes: Previously classified as an insignificant activity. Please add to Permit. Pressurized unloading of raw condensate. Each condensate tank truck has a capacity of 7,000 gallons per load. DCP would like to limit the number of loads per year to 2,409 (401,500 bbl/yr). See Section 5. * 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Pressurized unloading of raw condensate. Previously classified as an insignificant activity. Company equipment Identification No. (optional): UL For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD Will this equipment be operated in any NAAQS nonattainment area? 4 Yes • No Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • IS Does this source load gasoline into transport vehicles? ■ Yes l7 No Is this source located at an oil and gas exploration and production site? ■ Yes SI No If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average? Yes No • ■ Does this source splash fill less than 6750 bbl of condensate per year? ■ Yes ■ No Does this source submerge fill less than 16308 bbl of condensate per year? ■ Yes ■ No Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 //y�� 1COLOR ADO A 2 I - I nera,e n<�� a wbuc Mwfibbbealmnmenl Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: ❑✓ Condensate ❑ Crude Oil O Other: If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: bbl/year This product is loaded from tanks at this facility into: (e.g. "rail tank cars" or "tank trucks") Actual Volume Loaded: bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: Average temperature of bulk liquid loading: eF True Vapor Pressure: Psia 60 °F Molecular weight of displaced vapors: lb/lb mol If this APEN is being filed for vapors displaced from pressurized loading lines, complete the following: Requested Volume Loaded5: 401,500 bbl/year - Actual Volume Loaded: 219,825 bbl/year— Product Density: 38.46 lb/ft3 Load Line Volume: 0.0327 ft3/truckload Vapor Recovery Line Volume: 0.0327 ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Note: Requested Volume Loaded: 2,409 Loads/yr Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 3 1 . AV COLORADO DeparunalitaPitbliC Hwi,Tb 6uN.ommeR Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 4,478,327.79 / 528,681.36 Operator a $t ac lD No; . . ; Discharge Height Above Ground Level eel lf, !. Temp ( F) FlowRate jA M) R . s Velocity h (fUsec) ... UL Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal O Downward O Other (describe): Indicate the stack opening and size: (check one) ❑ Circular ❑ Other (describe): Interior stack diameter (inches): O Upward with obstructing raincap Section 6 - Control Device Information Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. ❑✓ Loading occurs using a vapor balance system: Requested Control Efficiency: 100 ❑ Combustion Device: Used for control of: Rating: MMBtu/hr hr Type: Make/Model: Requested Control Efficiency: % Manufacturer Guaranteed Control Efficiency: Minimum Temperature: °F Waste Gas Heat Content: Btu/scf Constant Pilot Light: O Yes O No Pilot Burner Rating: MMBtu/hr O Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 WV COLORADO 4i•V XNXT6EnNennmant Benzene PM Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) SOX NO. CO VOC HAPs Other: ❑ Using State Emission Factors (Required for GP07) ❑ Condensate ❑ Crude VOC 0.236 Lbs/BBL 0.104 Lbs/BBL Benzene 0.00041 Lbs/BBL 0.00018 Lbs/BBL n -Hexane 0.0036 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? N/A Pollutant' Criteria Pollutant Emissions Inventory Emission Factor Actual Annual Emissions Requested Annual Permit Emission Ltmt(s)5 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled- Emissions6 (tons/year) Uncontrolled - Emissions (tons/year)' • Controlled Emissions' (tons/year) PM SOX NO. CO VOC 1.29 lb/load Eng. Estimate 0.89 0.89 1.55 1.55 Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number 71432 Emission Factor Actual Annual Emissions Uncontrolled Basis lb/load Source (AP -42, Mfg-, etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Toluene 108883 Ethylbenzene Xylene n -Hexane 100414 1330207 110543 0.1039 Eng. Estimate 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 5i VI = XtaM1b b =arm.. Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran O 15 /2 Uf Date Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: �✓ Draft permit prior to issuance �✓ 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 © COLORADO 6 I f➢►f 11== Produced Water Storage Tank(s) APEN - Form APCD-207 Air Pollutant Emission Notice (APEN) and 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. This APEN is to be used for tanks that store produced water associated with oil and gas industry operations. If your emission source does not fall into this category, there may be a more specific APEN available for your source (e.g. crude oil storage tanks, condensate storage tanks, hydrocarbon liquid loading, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms and associated addendum forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.Qov/pacific/cdphe/air-permits. 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: 2WE2024 AIRS ID Number: 123 /0107/051 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: DCP Operating Company, LP Site Name: Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran©DCPMidstream.com I 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 388600 COLORADO 1 I A- s °`a, o.nb� Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source ❑✓ Request coverage under traditional construction permit O Request coverage under a General Permit O GP05 O GP08 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. - OR ❑ MODIFICATION to existing permit (check each box below that applies) O Change in equipment ❑ Change company name3 O Change permit limit O Transfer of ownership' O Other (describe below) - OR ▪ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - • APEN submittal for permit exempt/grandfathered source EI Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: Note that this is a "permit exempt" but "APEN subject" source. DCP chooses to permit this produced water tank to obtain a federally enforceable permit limit. This produced water tank is controlled by the enclosed combustor. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: Company equipment Identification No. (optional): For existing sources, operation began on: One (1) 400 bbl Produced Water Tank PW TANK 6/24/2015 For new or reconstructed sources, the projected start-up date is: Normal Hours of Source Operation: 24 Storage tank(s) located at: hours/day 7 days/week 52 ❑ Exploration & Production (EEtP) site weeks/year ❑✓ Midstream or Downstream (non EEtP) site Will this equipment be operated in any NAAQS nonattainment area? ✓ Yes ❑ No Are Flash Emissions anticipated from these storage tanks? ❑ Yes ✓ No Are these storage tanks located at a commercial facility that accepts oil production wastewater for processing? ❑ Yes No / Do these storage tanks contain less than 1% by volume crude oil on an annual average basis? ✓ Yes ❑ No Are these storage tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-105. ❑ Yes No ✓ Are you requesting ≥ 6 ton/yr VOC emissions (per storage tank), or are uncontrolled actual emissions a 6 ton/yr (per storage tank)? ❑ Yes No ✓ Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 'COLORADO 2jr ray a« ❑ Upward ❑ Horizontal Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Storage Tank(s) Information Produced Water Throughput: Actual Annual Amount (bbl/year) 18,468 Requested Annual Permit Limits (bbl/year) 30,000 From what year is the actual annual amount? Tank design: ❑✓ Fixed roof 2017 O Internal floating roof O External floating roof Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of Most Recent Storage Vessel in Storage Tank (month/year) Date of First Production (month/year). PW TANK 1 400 Wells Serviced by this Storage Tank or Tank Batter? (E8fP Sites Only) API Number Name`of Well Newly Reported Well 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 6 The E&P Storage Tank APEN Addendum (Form APCD-212) should be completed and attached when additional space is needed to report all wells that are serviced by the equipment reported on this APEN form. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 4,478,327.79 / 528,681.36 Operator Stack ID No. : Discharge Height Above Ground Level (feet) Temp., (°F) Flow Rate (ACFM) ; Velocity (ft/sec) Ambient Indicate the direction of the stack outlet: (check one) O Downward ❑ Other (describe): O Upward with obstructing raincap Indicate the stack opening and size: (check one) ❑ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ['Other (describe): Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 3 A�COLORADO I fHa10i frFn i Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information ❑ Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. Vapor ❑ Recovery Unit (VRU): Pollutants Controlled: Size: Make/Model: Requested Control Efficiency: VRU Downtime or Bypassed (emissions vented): % ❑ Combustion Device: Pollutants Controlled: VOC and HAPs Rating: MMBtu/hr Type: Enclosed Combustor Make/Model: AbU } Iec Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98 Minimum Temperature: Waste Gas Heat Content: 3,677 Btu/scf Constant Pilot Light: ❑✓ Yes ❑ No Pilot Burner Rating: 0.16 MMBtu/hr ❑ Closed Loop System Description of the closed loop system: ❑ Other: Pollutants Controlled: Description: Control Efficiency Requested: Section 7 - Gas/Liquids Separation Technology Information (E&tP Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? psig Describe the separation process between the well and the storage tanks: Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 COLORADO q I N? it HaaIm tnWnannlwI Benzene VOC Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Description of Control Method(s) Overall Requested Control:; Efficiency %reduction in emissions Enclosed Combustor 95 NOx CO HAPs Enclosed Combustor 95 Other: From what year is the following reported actual annual emissions data? 2017 Pollutant VOC 0.262 rrteria Pollutant Emissions lnvento Emission Factor7 Actual Annual Emissions Uncontrolled Emissions (tons/year) Uncontrolled Basis lb/bbl Source (AP -42, Mfg., etc.) Uncontrolled Emissions (tons/year) Controlled Emissions8 (tons/year) Controlled Emissions (tons/year) CDPHE 2.42 0.12 3.93 0.20 NOx 0.0005 lb/bbl AP -42 3.74E-03 3.74E-03 0.01 0.01 CO 0.0021 lb/bbl AP -42 3.14E-03 3.14E-03 0.03 0.03 Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number Emission Factor7 Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Actual Annual Emissions Uncontrolled Emissions (pounds/year) Controlled Emissions8 (pounds/year) 71432 Toluene 108883 Ethylbenzene Xylene 100414 1330207 n -Hexane 110543 0.022 lb/bbl CDPHE 406 20 2,2,4- Trimethylpentane 540841 5 Requested values will become permit limitations. Requested limit(s) should consider future growth. 7 Attach produced water laboratory analysis, stack test results, and associated emissions calculations if you are requesting site specific emissions factors according to the guidance in PS Memo 14-03. 8 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 COLORADO 5 7 I. xeemesnv,Mw. ni Permit Number: 12WE2024 AIRS ID Number: 123 / 0107 / [Leave blank unless APCD has already assigned a permit # 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. If this is a registration for coverage under General Permit GP05 or GP08, I further certify that this source is and will be operated in full compliance with each condition of the applicable General Permit. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran lo/5/201 Date Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: 0 Draft permit prior to issuance 0 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 $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division __ APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-207 - Produced Water Storage Tank(s) APEN - Revision 7/2018 6 I COLORADO Department ofPubiic H¢at@SEnuimnnwnl • F General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and 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. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found 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: 12WE2024 AIRS ID Number: 123 /0107/ dsg [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: DCP Operating Company, LP Site Name:- Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Portable Source Home Base: Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com t 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. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 338601 I_._ COLORADO Form APCD-200 - General APEN - Revision 7/2018 Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source (check one below) ❑✓ STATIONARY source O PORTABLE source -OR- ❑ MODIFICATION to existing permit (check each box below that applies) o Change fuel or equipment O Change company name3 O Add point to existing permit o Change permit limit O Transfer of ownership4 O Other (describe below) - OR - APEN submittal for update only (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 & Notes: APEN being submitted since emissions of NCRP (methanol) are > 250 lb/yr. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: One (1) 300 bbl methanol storage tank PTE throughput = 3,626 bbl/yr Manufacturer: TBD Model No.: TBD Serial No.: T B D Company equipment Identification No. METHANOL (optional): For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: TBD ❑✓ 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 Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 7/2018 days/week weeks/year Jun -Aug: Sep -Nov: ,COLORADO 2 I ////&�L\ I� �3:a� i xeumaEnwmimnn+ Methanol Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information a Material Use O Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process Rate -' (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limits (Specify Units) Material Consumption: 3,626 bbl/yr 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information eographical_Coordinates Latitude/Longitude OrT117:49-'- 4,478,327.79 / 528,681.36 0 ❑✓ 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. rnE` « - i -.. «14 aT.. Discharge Height' - .k �Y�3"�5�i T` Veloocit F /sec, ''x vc'� (J C . °p0 erator ac ,Stack lD NO q }.: nz � Above Ground Level t ',•44,", (Feet) 7em p x F)� '. �t x Flow Rate Fs fA)r , METHANOL Indicate the direction of the stack outlet: (check one) ❑ Upward ❑ Horizontal ❑ Downward o Other (describe): Indicate the stack opening and size: (check one) 0 Circular Interior stack diameter (inches): ❑ Upward with obstructing raincap ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-200 - General APEN - Revision 7/2018 3 I AVCOLORADO ≥ b Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [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 (MMBTU/hr) Actual Annual Fuel Use (Specify Units) '' Requested Annual Permit Limits (Specify Units) From what year is the actual annua fuel use data? Indicate the type of fuel used6: ❑ 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): Heating value (give units): 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 If fuel heating value is different than the listed assumed value, 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? O Yes No If es describe the control equipment AND state the overall control efficiency (% reduction): Y Pollutant Control Equipment • Description Overall Collection Efficiency, Overall Control Efficiency (% reduction in emissions) '. TSP (PM) PM10 PM2.5 SOX NO. CO VOC Other: Form APCD-200 - General APEN - Revision 7/2018 4 I iCORADO OLEnt TSP (PM) Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] 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.) Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Controlled) (tons/year) Uncontrolled, (tons/year) Controlled (tons/year) Uncontrolled (tons/year) PM10 PM2.5 SOX' NO,, CO VOC 0.13 lb/bbl TANKS 4.09d 0.14 0.14 0.23 0.23 Other: 5 Requested values will become permit limitations. Requested limit(s) shou d consider future process growth. 7 Annual emissions fees wilt 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) equal to or greater than 250 lbs/year? ❑✓ Yes ❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: CAS Number Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (Specify, Units) Emission Factor Source (AP -42, Mfg., etc.) Uncontrolled Actual Emissions (ibs/year) Controlled Actual Emissions) (lbs/year) 67-56-1 Methanol 0.13 lb/bbl TANKS 4.09d 281 281 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Note that Potential to emit (PTE) emissions for methanol is as follows (actual emissions have been reported above): Uncontrolled Emissions (Ib/yr): 461. Controlled Emissions (Ib/yr): 461 Please include these PTE methanol emissions in the Notes to Permit Holder section of the permit. Form APCD-200 - General APEN - Revision 7/2018 COLORApo 5 I Helm &tiwfrnm,nl Permit Number: 12WE2024 AIRS ID Number: 123 / 0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran lo /51?o'' Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: 0✓ Draft permit prior to issuance E✓ 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 6I COLORADO Dean oent of?utac FifMIT S EnNTannuAl 0� General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and 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. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found 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: 12 W E2024 AIRS ID Number: 123 /0107/05 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1-- Administrative Information Company Name: Site Name: DCP Operating Company, LP Lucerne 2 Natural Gas Processing Plant Site Location: 31495 Weld County Road 43 Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Portable Source Home Base: Denver, CO 80202 Site Location Weld County: NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I 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 wilt require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 7/2018 388602 COLORADO 1 I gr I= Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑✓ NEW permit OR newly -reported emission source (check one below) ✓❑ STATIONARY source ❑ PORTABLE source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name3 ❑ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership4 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (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 Et Notes: Flare used as backup control device and during maintenance and emergency situations. Previously classified as an insignificant activity. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 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: ZEECO E C O Model No.: HSLF L F Serial No.: N/A Company equipment Identification No. (optional): For existing sources, operation began on: F-1 6/24/2015 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 Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 7/2018 days/week weeks/year Jun -Aug: Sep -Nov: COLORADO • 2 I AV;w�du�� tlaaNnb E�MroM1menk Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information E Material Use ❑✓ Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process Rate (Specify Units) ctual Annua Amount (Specify Units) equested Annual Permit Limits' Specify Units) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information 4,478,327.79 / 528,681.36 ❑ 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. i#t '. .,..�..[� : . y $ pe.. was D No.y t� Stag © M� YF3fdE aT�-�� '_ .t'. .. �S1. �2 .-.. .J.•..„. .,. A,bovei Ground -,e el �l { i 1 rr9(J4`f ��M4 J, y sir' _ yam PE.L r�, i` Q#' u C %mp �t tYi{�f S �'+r�� `'t rL�J2.'�R'S` tE.. "' - ` Y x�.�: h ,� 'i 2- Ifi. s i flow tatef k ,Y ai}r� -� L �' Ct1 "r'kv ��j WAN . �'ry'� xis g VetPP rG � t/ fl c)}5�'J �f �e i i i ( c. �w__ �. F-1 123 1200 Indicate the direction of the stack outlet: (check one) ✓❑ Upward O Horizontal ❑ Downward O Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): 50 o Square/rectangle Interior stack width (inches): Interior stack depth (inches): O Other (describe): Form APCD-200 - General APEN - Revision 7/2018 COLORADO 3 I A Enu*e. a. �. HNHTbEnWrenmanl TSP (PM) Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment a 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 (MMBTU/hr): Actual Annual Fuel Use , (Specify Units) Requested Annual Permit Limits (Specify Units) -' 0.26 (Pilot Only) 32.88 MMscf/yr (Purge + Waste) From what year is the actual annual fuel use data? Indicate the type of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF o Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) o Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash content: Sulfur content: ❑✓ Other (describe): Residue gas/Inlet gas/Propane Heating value (give units): 1,098 / 1,311 / 2,516 Btu/scf 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 If fuel heating value is different than the listed assumed value, 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 O No If yes, describe the control equipment AND state the overall control efficiency (% reduction): Overall Control Efficient (% reduction ►n emissions)'? PM10 PM2.5 SOX NO. CO VOC Flare 100% 95% Other: HAPs - Flare 100% 95% Form APCD-200 - General APEN - Revision 7/2018 COLORADO 4I A. I H,a@In b EnvIM..MPnI. 110-54-3 n -Hexane TSP (PM) Permit Number: 12 W E2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? 2017 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.) Uncontrolled Emission Factor (Specify Units)`. :mission Factor', Source (AP -42, Mfg. ei Uncontrolled, (tons/year), Controlled (tons/year) issiors Umit Uncontrolled:' (tons%year) , Controlled:: (tons/year) 7.6 Ib/MMscf AP -42 0.01 0.01 PMio 7.6 lb/MMscf AP -42 0.01 0.01 PM2.s 7.6 Ib/MMscf AP -42 0.01 0.01 SOx 0.6 Ib/MMscf AP -42 0.01 0.01 NOx 0.068 lb/MMBtu AP -42 1.53 1.53 CO 0.310 Ib/MMBtu AP -42 6.61 6.61 VOC 15,593 Ib/MMscf Site -specific -25673e- -12.32 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. t' 3 ,Gs. i 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) equal to or greater than 250 lbs/year? 0✓ Yes ❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: Overall: Control Efficiency Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg et Uncontrolled Actual Emissions (lbs/year) ontrolled Actual missions? (lbs/year); 95% 42 Ib/MMscf Site -specific 7-1-375 -69 2 Note: PTE Emissions shown above. Only NCRP > 250 lb/yr reported. 7 Annual emissions tees wilt be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-20D - General APEN - Revision 7/2018 COLORADO 5 I u�,L.O D HUMhbc,.w.enmenS Permit Number: 12WE2024 AIRS ID Number: 123 /0107/ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. io►512oi$ Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: 0✓ Draft permit prior to issuance ❑✓ 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 $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 6 I ��COLORADO °fRAU< Hello