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Home My WebLink About20193767.tiffa COLORADO Department of Public Health b Environment Weld County - Clerk to the Board 11500 St PO Box 758 Greeley, CO 80632 July 30, 2019 Dear Sir or Madam: RECEIVED AUG 0 2 2019 WELD COUNTY COMMISSIONERS On August 1, 2019, the Air Pollution Control Division will begin a 30 -day public notice period for DCP Operating Company, LP - Libsack Compressor Station. 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 Public ;e,u_) 4300 Cherry Creek Drive S., Denver, Co 80246-1530 P 303-692-2000 www.colorado.gov/cdphe Jared Polis, Governor I Jill Hunsaker Ryan, MPH, Executive Director O -c =(t_C re), t t(3T), OCDC3M). (wC TM /CH / E /CK) cI/z I/19 2019-3767 Air Pollution Control Division Notice of a Proposed Project or Activity Warranting Public Comment Website Title: DCP Operating Company, LP - Libsack Compressor Station - Weld County Notice Period Begins: August 1, 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, LP Facility: Libsack Compressor Station Natural Gas Compressor Station Section 36, Township 6N, Range 65W Weld County The proposed project or activity is as follows: The operator is requesting to modify an existing natural gas compressor station located in the ozone non -attainment area. The operator is requesting to modify an existing TEG dehydration unit to include VOC emissions associated with assist/pilot fuel combustion. The operator is also requesting to add the following new sources to the facility: (i) One (1) Solar Titan 250-319005 turbine, (ii) Turbine compressor blowdowns, (iii) One (1) 231 MMSCD TEG dehydration unit, and (iv) Natural gas venting resulting from the blowdown of pig receivers and pig launchers. 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 11WE1475 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: Harrison Slaughter Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 1 I litel COLORADO Department •t PubUC Health 6 tnvinrnment Colorado Air Permitting Project PRELIMINARY ANALYSIS - PROJECT SUMMARY Project Details Review Engineer: Harrison Slaughter Package #: 398590 Received Date: 5/3/2019 Review Start Date: 5/28/2019 Section 01 - Facility Information Company Name: DCP Operating Company, LP County AIRS ID: 123 Quadrant Section Township Range 36 6N 65 Plant AIRS ID: Facility Name: Physical Address/Location: County: Type of Facility: 9008 Libsack Compressor Station Section 36, Township 6N, Range 65W Weld County Natural Gas Compressor Station What industry segment? Oil & Natural Gas Production & Processing Is this facility located in a NAAQS non -attainment area? CCarbon Monoxide (CO) If yes, for what pollutant? Section 02 - Emissions Units In Permit Application Yes Particulate Matter (PM) Ozone (NOx & VOC) AIRs Point # Emissions Source Type Equipment Name Emissions Control? Permit # Issuance # Self Cert Required? Action Engineering Remarks 001 Natural Gas RICE C-185 Yes 11WE1475 4 No No Action Requested 002 Natural Gas RICE C-186 Yes 11WE1475 4 No Cancellation 003 Natural Gas RICE C-187 Yes 11WE1475 4 No Cancellation 004 Natural Gas RICE C-188 Yes 11WE1475 4 No No Action Requested 005 Dehydrator D-1 Yes 11WE1475 4 Yes Permit Modification 007 Natural Gas RICE C-167 Yes 11WE1475 4 Yes No Action Requested 008 Turbine TURB-1 No 11WE1475 4 Yes Permit Initial Issuance 009 Maintenance Blowdowns TURB-BD _ No 11WE1475 4 Yes Permit Initial Issuance Turbine Blowdowns 010 Dehydrator D-2 Yes 11WE1475 4 Yes Permit Initial Issuance 011 Maintenance Blowdowns PIG No 11WE1475 4 Yes Permit Initial Issuance Pigging emissions 012 Produced Water Tank PW-1 & PW-2 No 19WE0618 1 No APEN Required / Permit Section 03 - Description of Project DCP Operating Company, LP (DCP) is requesting to modify the permit for an existing natural gas compressor station located in the ozone non -attainment area. With this modification the operator is requesting to remove existing sources, modify existing sources and add new sources to the facility. The requested changes to this facility are as follows: 1. Removal of Sources: The operator is requesting to remove two engines (Points 002 & 003) from service upon commencement of operation of the new turbine compressor. 2. Modification: The operator is requesting to modify the TEG dehydration unit covered under point 005. With this modification, the operator is requesting to permit VOC emissions associated with the combustion of assist gas by the enclosed combustor used to control emissions from the dehydration unit. 3. New Sources: The operator is requesting to add the following new sources to the facility as part of the request to increase the compression capacity of the facility: (i) One (1) Solar Titan 250-31900S turbine, (ii) Turbine compressor blowdowns, (iii) One (1) 231 MMscf/day TEG dehydration unit, (iv) Blowdown of pigging operations, and (v) Two (2) 300 bbl fixed roof produced water storage vessels. The produced water storage vessels are addressed with the preliminary analysis and exemption letter under #19WE0618.XP1 since the operator is requesting a permit exemption. Self -certification is required for all the points being modified with this application. Additionally, the engine permitted under point 007 has not yet been installed. As a result, self -certification is still required for this source. Public comment is required because the operator is requesting new synthetic minor limits in order to avoid other requirements. Additionally, this modification results in the facility Plainer rlaccifiord ac a nn**, mainr cniirro of \i-1r /Titlo \/ Q. nMANICR1 arid rn /Titlo 1/1 Ac a roc' tit tha nnoratnr will ha ranidirorl to ciihmit an annliratinn to nhtain an nnoratinar normit Colorado Air Permitting Project IdLlllly UCII % LIdJJI11CU dJ d new IIIdjul JUL.!' LC UI V ill, i I tile V Of IVNIVJrt) dllU LL/ % I ILtC vi. t\J d f CJUIL, 111C VpCI d1Uf will UCt CqUtt CU LU JUU11111 dl I IV VU1d111 dl l Upet dllllg penult within one year of commencement of operation of any piece of equipment covered by this permit. Since the change in VOC emissions associated with this project are less than 100 tpy, the facility is not subject to NANSR review. However, the facility is classified as a major source of VOC with regards to NANSR going forward. As a result, future modifications will need to be evaluated with regards to the major modification thresholds. Additionally, the change in CO emissions are less than 250 tpy. As a result, the facility is not subject to PSD review. As shown below, the facility is still classified as synthetic minor for PSD. The operator reviewed the draft permit and provided general comments that are not associated with any specific point included in this review. As a result, the comments and responses provided are addressed here. The comments and responses are as follow: (i) Comment: Permit Language: Facility -wide emissions of total hazardous air pollutants shall not exceed 3,414 pounds per month. DCP Comment: Value calculated comes out to 3639 lbs/month. Note that when this condition says "facility wide" our assumption is that it is also inclusive of PW emissions (APEN only) and insignificant activities. See Attached APCD-102 (Appendix A) provided with the responses to the second round of questions. This value is also inclusive of the 1,3 Butadiene emissions which are not captured on the APCD-102 form. Response: The next statement in the permit states "The facility -wide emission limitations for hazardous air pollutants shall apply to all permitted emission units at this facility." As a result, it is my understanding that these limits are intended to be based on only the permitted points at this facility (20.1 tpy). If you want this to apply to all points at the facility, the language referenced above will need to be changed. Let me know if you agree with my assessment and the condition will remain as it currently stands. (ii) Comment: Permit Language: Facility -wide emissions of total hazardous air pollutants shall not exceed 20.1 tons per year DCP Comment: Value calculated per the APCD- 102 is 21.3 tpy. See Attached APCD-102 (Appendix A) provided with the responses to the second round of questions. Response: The next statement in the permit states "The facility -wide emission limitations for hazardous air pollutants shall apply to all permitted emission units at this facility." Here again,it is my understanding that these limits are intended to be based on only the permitted points at this facility. If you would like these limits to include APEN and permit exempt activities, youwill be required to maintain rolling twelve month totals of the emissions from these sources. Are you willing to maintain rolling twelve month emission totals for APEN and permit exempt sources? If so, the condition may be updated. Let me know how you would like to proceed. If you agree with my assessment the condition will remain as it currently stands. (iii) Comment: Permit Language: Condition 71 DCP Comment: DCP would like to update the current permit limit for APEN exempt sources to conservatively account for the potential addition of a pressurized condensate Ioadout point. Appendix A provided with the second round of responses has the updated emission calculations and insignificant activity list and an updated APCD-102. The updated "Current Permit Limit (tpy)" would be as follows: 3.6 tpy. Response: This change has been made as requested. (iv) Comment: DCP Comment: Although fugitive emissions are not a permitted point (emissions below permitting thresholds), DCP would like to request that we add conditions to the permit to indicate that they are subject to the LDAR requirements under Section XII and Section XVII. Response: If you would like these conditions added to the permit, the fugitive emission source at this facility will need to be added to the permit. In order to do this, an APEN, APEN fees and calculations would need to be submitted for the fugitives. Since that is not currently the case, the requested requirements will not be added to the permit The comments and responses are also available with the email chain that has been uploaded to Records Manager. • Section 04 - Public Comment Requirements Is Public Comment Required? Yes If yes, why? Requesting Synthetic Minor Permit Section 05 - Ambient Air Impact Analysis Requirement: Was a quantitative modeling analysis required? 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, indicate programs and which pollutants: Prevention of Significant Deterioration (PSD) Title V Operating Permits (OP) Non -Attainment New Source Review (NANSR) Is this stationary source a major source? If yes, explain what programs and which pollutants her SO2 Prevention of Significant Deterioration (PSD) Title V Operating Permits (OP) Non -Attainment New Source Review (NANSR) No Yes SO2 NOx J NOx CO VOC PM2.5 PM10 TSP HAPs CO VOC J J PM2.5 PM10 TSP HAPs Glycol Dehydrator Emissions Inventory 005 Dehydrator cacility A!Rs ID. 123 County 9008 Plant 005 Point Section 02 - Equipment Description Details Dehydrator Information Dehydrator Type: Make: Model: Serial Number Design Capacity: Recirculation Pump Information Number of Pumps Pump Type Make: Model: Design/Max Recirculation Rate: Dehydrator Equipment Flash Tank Reboiter Burner Stripping Gas Dehydrator Equipment Description Emission Control Device Description Triethylene glycol (TEG) 08 Johnson Custom Glycol Contactor 642012 64 one(1) electric Best Pump Works ..... NA :;•.aril: i5_ 24 MMscf/day gallons/minute , flash tank, and reboder burner One (1) Triethyleno glycol (TES) natural gas dehydration unit (Male CO Johnson. Modal. Custom Glycol Contactor, Serial Number. 642012) with a design capacity of 64 MMsd par day. This omissions unit is equipped with one (1) (Make: Bast Pump Works, Model: NA) electric driven glycol pump with a design capacity of 24 gallons per minute. This dehydration unit is equipped with a still vent, flash tank, and rebciler burner. Emissions from the still vent are routed to an air -cooed condenser, and then to the Enclosed Flare. Emisions from the flash tank are routed directly to the Vapor Recovery Unit (VRU). As a secondary control device, flash tank emissions are routed to the Enclosed Flare . Section 03 - Processing. Rate Information for Emissions Estimates Primary Emissions - Dehydrator Still Vont and Flash Tank (if present) Requested Permit Limit Throughput = Potential to Emit (PTE) Throughput = 23,360 MMscf per year Requested Monthly Throughput= 1,984 MMscf per month 23.360 Secondary Emissions -Combustion Device(s) for Air Pollution Control Still Vent Control Condenser. Condenser emission reduction claimed: Primary control device: Primer/ control device operation: Secondary control device: Secondary control oevke operation Still Vent Gas Heating Value: Still Vent Waste Gas Vont Rate: Flash tank Control Primary control device. Primary control device operation: Secondary control device. Secondary control device operation: Rash Tank Gas Heating Value Flash Tank Waste Gas Vent Rate: Enclosed Flare Pilot fuel rate: Assist gas rate: Heat Content Enclosed Flan Fuel Gas Composition Yes:: N0_' Enclosed Flare 84972 hr/yr Ka canto! 262.8 hr/yr 1526 Btu/scf 7.56E+02 scfh Vapor Recovery Unit (VRU) Enclosed Flare 8322 hr/yr MMscf per year '> Requested Condenser Outlet Temporal rare: 95% Control Efficiency % Requested TO Temp 0% Control Efficiency % 100% Control Efficiency % 96%' Control Efficiency % 438 hr/yr 1457 gill/scf 1.83E+03 sdh 50 sd/hr 3000 scf/hr 1085.48 Btu/scf MoezuCdr Wmeht 13 37 lb/lb-mol 160 Degrees F Degrees F Moe % Comconent MW lex/lb-mol Mass Fraction Mass Fraction (100% HC) Helium 1.000E-02 4.00 0.00 218E-05 0 C02 1.180E+00 43.99 0.52 2.83E-02 0 N2 3.800E-01 28.02 0.11 5 80E-03 0 Hydrogen Sulfide 4.f t P--05 34.10 000 7.43E-07 0 methane 8.686E+01 16 01 13.91 7 57E-01 7.84E-01 ethane 9.537E+00 30.02 286 1.56E-01 0.161367906 propane 1.599E+00 44.03 0.70 3.83E-02 0.03967854 Isobu Lane 1 041E-01 58.04 0.06 3 29E-03 0.003405366 n -butane 2.321E-01 58.04 0.13 7.33E-03 0.00759256 isopentane 3.950E-02 72.05 0.03 1.55E-03 0.001604046 n -pentane 3800E-02 72.05 0.03 1.49E-03 0.001543133 cyclopentane 0.000E+00 70.13 0.00 0.00E+00 0 n -Hexane 0.000E+00 86.18 0.00 0.00E+00 0 cyclohexane 0.000E+00 84.16 0.00 0.00E+00 0 Other hexanes 1.980E-02 86.06 002 9.28E-04 0.0009604 heptanes 0-000E+00 100.21 0.00 0.00E+00 0 methylcyc1Ohexane 0.000E+00 98.19 0.00 0.00E+00 0 724-TMP 0.000E+00 114.23 0.00 0.00E+00 0 Benzene 1.100E.03 78.10 0.00 4.68E-05 4.84205E-05 Toluene 5.000E-04 92.10 0.00 251E -OS 2.59547E-5 Ethylbenzene 0.000E+00 106.10 0.00 0.00E+00 0 Xylenes 0.000E+00 106.10 0.00 0.00E+00 0 C8+ Heavies 0.000E+00 116.00 0.00 0.00E+00 0 Total (Uncontrolled) Total VOC (Uncontrolle 1.00 1 0.0530 0.05485842 Section 04 - Emissions Factors & Methodologies Dehydrator The operator used GRI GLYCaIc 4.0 to estimate emissions. Wet gas composition is based on a site specific extended wet gas analysis collected from the l`bsack facility TEG Inlet on 12/22/15. Input Parameters I n!et Gas Pressure Inlet Gas Temperature Req,esteo Glycol Rec rcu ate Rate Flash Tank Temp: Flash Tank Pressure: Dry Gas Water Content 5TILL VENT Control Scenano Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 53.1277 2.656385 53.1277 Benzene 11.2079 0.560395 11.2079 Toluene 8.9172 0.44586 8.9172 Ethylbenzene 0.1366 0.00683 0.1366 Xylenes 2.1525 0.107625 :.1525 n -Hexane 1.1804 0.05902 1.1804 224 -IMP 0.0025 0.00012.5 0.0025 Methanol 0.009400226 3.000470011 0.009400226 FLASH TANK Control Scenario Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 53.2583 0 2.662915 Benzene 0.3190 0 0.01595 Toluene 0.1668 0 0.00834 Ethylbenzene 0.0015 0 75E -QS Xylenes 0.0167 0 0.000835 n -Hexane 0.8941 0 0.044705 224-TMP 0.0018 0 9E -0S Methanol 0.0071193 0 0.000355965 r 140 'F 46 psig 6.7 lb/MMscf Dry Gas Throughput: Still Vent Primary Control: 22,659.2_ MMscf/yr Still Vent Secondary Control: 7002 MMscf/yr Waste Gas Combusted: Still Vent Primary Control: 6.623 MMscf/yr Still Vent Secondary Control: 0.00 MMscf/yr Dry Gas Throttehout: Flash Tank Primary Control: 22,192.0 MMscf/yr Flash Tank Secondary Control: 1,168.0 MMscf/yr Waste Gas Combuste4: Flash Tank Primary Control: 0.0 MMscf/yr Flash Tank Secondary Controt 0.802 MMscf/yr Lean Glycol Water Content Pilot fuel/Assist Gas Combusted Pilot Fuel: Assist Fuel: Total: 1 wt%H20 0.438 MMscf/year 26.28 MMscf/year 26.718 MMscf/year 1.9245 MMscf/month 0.56 MMscf/month Glycol Dehydrator Emissions Inventory Emission Factors Glycol Dehydrator Pollutant Uncontrolled Controlled Emission Fact or Source (lb/MMsd) (Ib/MMsd) (Dry Gas Throughput) (Dry Gas Throughput) VOC 47.57 2.09 GlyCalc 4.0 Benzene 5.137105 0.396412146 GIyCalc4.0 Toluene 4.0879 0.315:59677 GiyCalc4.0 G?Y'alc4.0 Ethylbenrene 0.062145 0.004&7083 Xylene 0.97614 0.07605585 GiyCalc 4.0 n -Hexane 0.933525 0.042703493 GlyCaic 4.0 GlyCalc 4.0 GlyCalc 4.0 224 TMP 0.001935 9.03375E -CS Methanol 0.007433737 0.000340072 Pollutant Still Vent Primary Control Device Emission Factor Source Uncontrolled Uncontrolled (Ib/MMBtu) (Ib/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0075 113736 AP -42 Table 1A-2 (PM10/PM2S) AP -42 Table 1A-2 (PM10/PM2.5) AP -42 Table 1A-2 (Sox) AP -42 Chapter 13.5 Industrial Flares(NOx} AP -42 Chapter 13.5 Industrial Flares (CO) PM23 0.0075 113736 SOx 0.0006 02979 NOx 0.0680 103.7939 CO 0.3100 473.20CN Pollutant Still Vent Secondary Control Device Erission Factor Source Uncontrolled Uncontrolled (ib/MMBtu) (Ib/MMsd) ( Waste Heat Combusted) (Waste Gas Combusted) PM10 0.2W. PM2.5 0.0000 Sox 0.0000 NOx 0.0000 CO 0 020 Pollutant Flash Tank Primary Control Device Emission Factor S;u':e Uncontrolled Uncontrolled (lb/MMBtu) (Ib/MMsd) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0000 PM2.5 0.0000 SOX 0.0000 NOx 0.0000 CO 0 0000 Flash Tank Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/MMscf) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0075 103595 AP -42 Table 1A-2 (PM30/PM2S) AP -42 Table 1,4-2 (PM10/PM251 AP -42 Table 1.4-2 (Sox) AP -42 Chapter 13.5Industrial Flares (NOx) AP -42 Chapter 133 Industrial F•laresiCO) PM2.5 0.0075 10.5595 SOx 0.0006 0.3573 NOx 0.0680 99.1076 CO 0.3100 451.3135 Pilot/Assist Gas Combustion Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (Ib/MMsd) (Waste Heat Combusted) (Waste Gas Combusted) PM10 0.0075 3.0879 AP -42 Table 1.4-2 (PM10/PM2S) AP -42 Table 1A-2 (PM10/PM2.5) AP -42 Table 1.4-2 (50x) AP42 Chapter 13.5 Industrial Flares (N0x) AP -42 Chapter 133 industrial Flares (CO) PM2.5 0.0075 3.0879 SOx 0.0006 0.6385 NOx 0.0680 73.8126 CO 0.3100 336.4988 \ilot/Assist Gas Combustion (Primary Emission Emission Factor Source Pollutant Uncontrolled Controlled lb/MMsd lb/MMscf VOC 2658.7446 132.5372 MasfBalance Mass Balance Mass Balance Mass Balance Mass Balance Mass Balance Mass Balance Benzene 2.3467 0.1173 Toluene 11579 0.0629 Ethylbenzare 0.0000 0.0000 Xylene 0.0000 0.0000 n -Hexane 0.0000 0.0000 224 IMP 0.0000 0.0000 ;action 05 - Emissions Inventory Did operator request a buffer) Requested Buffer (9t): Yes ... 20% Criteria Pollutants Potential to Emit Uncontrolled (tons/yar) Actual Emissions Uncontrolled Controlled (ton year) (tons,/year) Requested Permit Units Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Umits Controlled Albs/month) PM10 PM2S SOx NOx CO VOC 0.15 0.1.5 . . . : - 25.49 0.15 0.15 ... .. :5.49 0.01 0.01 -. -. ... _ ... 2.01 1.37 1.37 232.63 6.24 624 _ ... . _ .. 1060.50 560.94 560.94 ;.I .;:) 55.:::: i.: 4.4) 03 Hazardous Air Pollutants Potential to Emit Uncontrolled (bs/year) Actual Emissions Uncontrolled Controlled (bs/year) (bs/year) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Benzene Toluene Ethylbenzeno Xylene n -Hexane 121/7391 1`1173.91 9260.19 121173.91 9260.1877 50,59 4.63 95492.69 95492.69 7364.47 95492.69 7364.47 47.75 3.68 1451.71 1451.71 112.76 1451.71 112.76 3.73 0.06 22802.63 22802.63 1776.66 22302.63 1776.66 11.40 0.89 21507.14 2130714 99755 2180714 997.55 10.90 0.50 224 IMP 45.20 45.20 2.11 4520 2.11 3.32 0.001 Methanol 173.65 173.65 7.94 17165 7.944 3.09 0.004 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XVII.B4O Dehydrator is subject to Regulation 7, Section XVII. 3, D.3 Regulation 7, Section XVII.81.e The control device for this dehydrator is not subject to Regulation 7. Section XVll.3'-a Regulation 7, Section XII.H Dehydrator is subject to Regulation 7. Section XILH Regulation 8, Part E. MAR Subpart HH (Area) Deny is subject to area source MACE HH, per the requirements in 63.764(dj(2) Regulation 8, Part E, MACT Subpart HH (Major) You have Indicated that this facility Is not subject to Major Source requirements at MACT1.H. Regulation 8, Part E. MACT Subpart HHH You have indicated that this facility Is not subject to MAR HHH. (Soo regulatory applicability worksheet for detailed analysis) Bert ion 07 - Initial and Periodic Sampling and Testing Requirements Was the extended wet gas sample used in the GlyCalc model/Process model site -specific and collected within a year of application submittal) If no, the permit will contain an "Initial Compliance' testing requirement to demonstrate compliance with emission limits 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 <z ria'z� �wa�>- _ roe• r If the company has requested a control device efficiency greater than 95%, is a thermal oxidizer or regenerative thermal oxidizer being used to achieve it? If yes, the permit will contain a condition specifying the minimum combustion chamber temperature for the thermal oxidizer Is the company using a thermal oxidizer AND requesting a minimum combustion chamber temperature lower than 1,400 degrees F? if yes, the permit will contain an "Initial Compliance" testing requirement AND a permit condition specifying the minimum combustion chamber temperature for the thermal oxidizer. No __..1 tai" ;;N:":H•- r':-:yacta•,,. •, f..: F.'.. _.. . --TS }.4.:. C' 637 . 1.30 05011 ..ewer Peaunq Value o, Sac 1331.23:_93 Btu/ ad H.ether Heating Value of 3,n 1457.43.36 Btu/scf page ?3 4. i i9,arx; 3-2 t •Atyc to Gan 71.7 .3r.a,:e .. . .r..ia.- ... ... .. h.f.}its. • . , _. _.,r flit.. Glycol Dehydrator Emissions Inventory Section 08 -Technical Analysis Notes 1. As indicated in the regulatory analysis for this source, the glycol dehydration unit is subject to Regulation 7 Section XVII. D. This portion of tee regulation requires "stir/ rents and rents 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 part subject to control requirements pursuant to Section XVII 0.4.. shall reduce uncontrolled actual emissions of hydrocarbons by at least 95 percent on a rotting twelve-month basis through the use of a corrfen.ser or air pollution control equipment. ' Since the operator is requesting to permit downtime for the still vent primary control device during which emissions veal be routed to the atmosphere (i.e. 0% control), the permit will contain conditions that limit the downtime of the VRU and enclosed flare to ensure the overall control otfkiaecy remains greater than or equal to 95%as required by the regulation. These permit conditions are required In the permit to ensure a minimum of 95% overall control is met in the event the total gas processed by the dehydration unit is less than the permitted limit It should be noted that the calculated control efficiencies for benzene, toluene, ethylbenzene and xylene (HAPs) (see Section 09) are less than 95%. However, the overall calculated control efficiency for VOC Is 95.95%. Since the VOC control efficiency is greater than 95% and HAPs are a subset of VOC, it appears this dehydration unit meets the control requirement of Colorado Regulation 7 Section XVIL03. 2. The emissions from the still vent are routed to a condenser prior to being routed to the enclosed flare. However, the operat or is not taking credit for any control achieved by the condenser. This Is demonstrated In the calculations by using the "uncontrolled regenerator emissions" stream from the GlyCalc model to calculate uncontrolled emissions and using a 95% control associated with the flare to calculate controlled emissions. As a result neither the permit nor the O&M plan will set a maximum outlet condenser temperature. However, the operator Is taking account for the condenser In the combustion calculations as described below. As a result, the permit will require the operator to monitor the condenser outlet temperature for use in the monthly GlyCalc simulation. 3. In order to talcutate still vent combustion emissions, the operator used the composition and throughput associated with the " Condenser Vent Stream' in the GlyCak simulation. While the operator is not taking credit for the condenser as a control devise, the use of the condense vent stream to calculate still vent combustion emissions is acceptable as it is likely a better representation of actual emissions. The other option for calculating still vent combustion emissions would have been to use the 'Regenerator Overheads Stream: If this stream had been used, NOx and CO emissions would have been calculated as 035 tpy and 139 tpy respectively (Heat Content • 1983437 Btu/scf, flaw Rare = 5,900 softer). Comparaevely, the 'Condenser Vent Stream' properties results in NOx and CO emissions of 034 tpy and 1.57 tpy respectively. This minor difference in emissions does not result in a facaity classification change. As such, it was determined the use of due composition end flow rate associated with the 'Condenser Vent Stream' was acceptable for estimatirg still vent combustion emissions. 4. Tile temperature and pressure of the inlet wet gas specified in the simulation do not match with the temperature and pressure on the site spedflc sample provided with the application. As a result a test GlyCalc simulation was run to assess the results it the temperature and pressure from the sample were used in the simulation. This test simulation resulted in emissions rates that were slightly more conservative than the emission rates estimated by the operator. However, the operator added a 20% buffer to their emissions estimate to account for variation In the gas analysis and other a ctual parameters. This 20% buffer resulted in emissions that are more conservative than the test GlyCalc simulation. As a result, the operator's estimate of emissions is likely conservative and therefore acceptable for permitting purposes. S. Based on actual benzene emissions reported on the APEN (dated 05/03/2019), the operator meets the area source benzene exempt Ion of MACT HH. As such, the operator is not currenty required to calculate and comply with the optimal glycol circulation rate that would be required based on requested emissions. As a result, the permit will continue to reflect the requirements of MACT NH for this source when actual emissions of benzene are below 1984.2 lb/year (MACT HH Benzene Exemption) and when actual emissions of benzene are greater than 1984 2 lb/year (Area Source Outside UA/UC - Optimal glycol circulation rate). This structure helps to Inform the operator and inspector of the potential MACT HH requirements for this source that will be based on the recorded actual average benzene emissions. In the event the operator is required to comply with the optimal glycol circulation rate, the optimal circulation rate is based on the fallowing parameters from the GlyCak simulation submitted with the application: F = 64 MMscf/day, I a 100.91 lb/MMscf, and 0 = 6.7 lb/MMscf. Using these values and the equation In MACT HH ;63.761(d)(2)(i) the optimal glycol circulation rate would be calculated as follows: Lopt = (1.15)"(3 gal TEG/lb H2O)•(((64 MMscr/day)•(10091 lb/MMscf - 6.7 Ib/MMscf))/(24hr/day)) a 866.732 gallons/hr • lhr/60 min = I&45 gallons/man. This information is contained in the notes to permit holder section of the permit. 6. The operator expressed there are no flow meten for the flash tank or still vent waste gas streams. The operator expressed de waste gas vented from the still vent and flash tank 5 determined from the monthly GlyCalc simulations. 7. The O&M plan submitted by the operator does not contain information on how the dry gas throughput vented from the dehydrator Is monitored. As a result this information is contained in the permit The operator expressed that the dry gas throughput is monitored with a meter at the outlet of the dehydration unit. The operator indicated that the dry gas tnroughput vented from each dehydration unit at this facility (points 005 and 010) will be tracked using separate flow meters. 8. This dehydration unit is equipped with a 2.86 MMBtu/hr reboiler. Since this reboiler has a design rate less than S MMBtu/hr, it is APEN exempt per Colorado Regula bon 3 Part A Section If.0.1.k. 9. The operator indicated that the pilot light fuel and assist fuel used by the combustor flow at a constant rate and are theref ore not metered. Permitted emissions are based on a constant pilot fuel flow rate of 50 scf/hr and a constant assist fuel flow rate of 3,000 scf/hr. The operator did indicate that the assist fuel flow may be changed, but is constant at the rate set by the operator The assist fuel flow rate used in the application Is the highest expected rate for this parameter. Even though these rates are constant a limit on assist gas and plot fuel combusted was included in the permit because it contributes to the overall emission limits on VOC. NOx and CO contained in the permit 10. The operator indicated that the volume of dry gas vented from the glycol dehydrator Is monitored using a flow meter at the ou tlet of the dehydration unit As a result. the process limits in the permit reflect "dry gas throughput" as the metered value. This language accurately reflects the volume of gas the operator is directly measudng at the facility and using to demonstrate compliance with tux process limits. Further, the dry gas flow rate Is the input value for the GlyCak simulation the operator uses to demonstrate compliance with the emission limits in the permit. 11. The sample used in the GlyCak simulation is site specific however, the sample was obtained more than one year prior to the application date. Even though the sample was obtained more than a year prior to the application, it was determined to be acceptable for estimating emission for the following reasons: (i) The operator is not requesting to change the emission cakulation methodology with phis application. 1u) The operator added a 20% buffer ro the emissions calculations to account for variations in the gas analysis and other parameters. (lit) The operator is required to obtain a wet gas sample prior to the TEG inlet on an annual basis. This annual sample is then used for calculating actual emissions. In summary, the sample used to calculate emissions in this application is likely representative and therefore acceptable for estimating emissions. 12. According to the operator, the heat content of the waste gas streams (flash tank and still vent waste gas) will be calculated based on the monthly GlyCak run. By calculating the heat value each month, rather than building the heat value used for permitting into the emission factor, the operator will be able to determine actual emissions more accurately. Three separate tables associated with the combustion processes (flash tank controlled by ECU, still vent controlled by ECD, & Assist/pilot fuel combustion) are contained in the notes to permit holder to clearly demonstrate the methods used to calculate emissions. The notes under each table clearly indicate how the heat content of the still vent and flash tank waste gas streams will be calculated on a monthly basis and used along with the calculated flow rate and monitored hours of operation to determine the combustion emissions. 13. The operator expressed that assist gas was necessary for this enclosed combustor in order to handle the seasonal methanol con tent in the processed wet gas (primarily during winter months). 14. The dehydration unit is equipped with one (1) electric driven glycol pump with a maximum circulation rate of 24 gyn. 15. The operator indicated the values used in the simulation for lean glycol and dry gas water content are vendor design values and remain constant. As a result the permit will riot require the operator to monitor these input parameters. According to the GlyCalc 4.0 users manual, the 'typical water contents for lean TEG are 1 wt % to 2 wt % for units without stripping gas (page 110)e The operator used a value of 1.0 wt% 1120 for the lean glycol input stream. This is within the range indicated by the GlyCak user's manual and is therefore acceptable for permitting purposes. 16. In order to calculate methanol emissions from this source. the operator Includes the mot%of alcohols present in the referent ed gas analysis with the n -Hexane male % specified In the GLYCatc simulation. The n -Hexane emission rates predicted by the GlyCak simulation are then multiplied by the ratio of the inlet alcohol mole%concentration to the inlet n -Hexane mole% concentration. Typically, the weight % values from the inlet gas simulation would be used in the ratio to determine emissions. However, the mole X values provide a conservative estimate of emissions and are acceptable for permitting purposes. The simulation used to estimate methanol emissions a run separately from the simulation used to demonstrate compliance with VOC and other HAP emissions. 17. The calculation of VOC and HAP emissions associated with the combustion of assist gas and pilot light fuel is based on a repr esentative fuel gas sample obtained on September 12, 2018. While this sample was taken within one year prior to this application, it is a representative rather than site specific sample. As a result, the operator will be required to obtain an initial sample. The permit will also require the operator to obtain an annual sample of fuel gas in order to demonstrate ongoing compliance with the emission factors established through this analysis. 18. As discussed above, VOC and HAP emissions associated with the combustion of assist gas and pilot light fuel are calculated using a representative fuel gas sample in conjunction with the EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10 • Displacement Equation (10.43). This information is used to establish Ib/MMscf emission fat tors. In order to calculate actual VOC and HAP emissions, the emission factors established through this analysis are multiplied by the actual assist gas and pilot light fuel use- These emissions are added to the VOC & HAP emissions calculated through the monthly GlyCalc simulations in order to determine total VOC and HAP emissions. It should be noted that only the controlled emission factors are used to estimate VOC and HAP emissions associated with combustion of assist gas and pilot light fuel. This is due to the fact that the fuel gas (i.e. assist and pilot light) Is only combusted when the combustion device is operational There is no scenario in which fuel gas Is vented to atmosphere. In the event the combustion device is not operational, the fuel gas flow is shut down. The controlled VOC and HAP emissions associated with combustion of assist gas and pilot fuel were added to both the uncontrolled and controlled columns above. 19. The combustion emissions calculated for the still vent routed to the enclosed combustor are based on 8760 hrs/year rather than the requested 3% downtime (2628 hrs/year). This calculation method accurately estimates emissions from the combustor in the event the combustor does not have downtime and operates for the entire year. Since combustors typic ally have some downtime during the year, permitting the still vent combustion emissions at 8760 hrs/year results in a conservative estimate. 20. The actual emissions reported on the APEN do not match with the actual emissions listed in the table In Section 05 above. This is due to the tact that the operator Is required to calculate actual emissions using a simulation on a monthly basis rather than through the use of emissions factors. As a result, I do not have all the calculations used to estimate actual emissions. Due to this, the actual emissions for this source should be referenced on the most recent APEN submitted on 05/03/2019. 21. The operator expressed the glycol circulation pump at this facility does not have a model number. As such, only the manufacturer will be provided In the equipment description in the permit. 22. An updated O&M plan was not submitted with this application. This is due to the fact that there are no changes required fort he O&M plan approved with the previous issuance of this permit The operator will continue to use the previously approved O&M plan. This O&M plan may be referenced in Records Manager with Record *123 -9008-82 (page 54). 23. The NOx and CO emissions associated with the combustion of pilot fuel and assist gas are based on a heat content of 1085.43 Btu/scf. While this value does not match with the heat content calculated on the fuel gas analysis (1087.4 Btu/scf), the difference in emissions resulting from the use of the operator provided value rather than the value on the fuel analysis is negligible. As a result the operator provided value was accepted and used for permitting purposes. The operator's explanation for the difference In values Is available in the email chain uploaded to Records Manager. 24. The operator was provided with a draft permit and APEN redline to review prior to puosic comment The operator reviewed the documents and provided comments on the draft permit The comments and responses provided are as follows: (I) Comment: Permit Language: Condition 13. Point 005 & 010: On a weekly basis, the owner or operator shall monitor and record operatfonalvalues including; condenser outlet temperature, flash tank temperature and pressure, wet gas inlet temperature and pressure. These records shall be maintained for a period of five years. DCP Comment: In the previous version of the permit: "condenser outlet temperature" was not included in the above condition. Note that the condenser is not used an emissions control device (no credit was taken during emission estimation for the dehydrators AIRS 005 and 010). DCP requests that 'condenser outlet temperature be removed from the above condition. Response: DCP uses the condenser Outlet temperature in the GlyCalc model on a monthly basis to obtain the heat content of the still vent waste gas stream and thus calculate combustion emissions. Since the condenser temperature is an Input In the model, DCP will be required to track actual values. Since the condenser is not being claimed as emission control a limit on the maximum outlet temperature is not included in permit or 0&M plan for this source. The condition will remain as it currently stands in the permit This topic has teen discussed with DCP in the past and agreed to. (if) Comment: Permit Language: Condition 18. Point 035 & 010: The volume of dry gas throughput shall be measured by gas meter at the outlet of each 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 DCP Comment: The previous permit gave us an option to measure the volume of gas processed by a gas meter or to use the maximum design rate of dehydrator. Therefore, in line with how a recent compressor station permit with a dehydrator (Eaton Compressor Station) was worded for the same condition, DCP requests the addition of the following line to Condition 15. "During flow meter downtime, a dry gas throughput of 64 MMscf/day for 005 and 231 MMscl/day for 010 shall be assumed until the flow meter is reoaired and/or operational" Response: The intention of this condition is to require the use of a flow meter to demonstrate compliance with the process limits. not provide multiple compliance mechanisms. I understand this condition was structured this way in the past, however, the oil and gas team determined the requested structure of the condition is not appropriate and has removed the optional language from our permit templates. it is Imperative that actual Information be used to demonstrate compliance with the limits. The requested language allows for the continued use of an assumed throughput for an indefinite amount of time. I am not certain why the permit you referenced contained the requested language You will notice the most recen t permit I wrote and issued for DCP (Troudt - 13WE1103) no longer contains this language. The language will remain is cuVentry written in the permit (Ili) Comment Permit language: Conditions 44 and 55 DCP Comment With the above conditions (Conditions 44 and 55), DCP would like to point oit that the representative site specific extended fuel gas analysis showed minimal HAP content The HAP emissions from assist gas combustion and pilot light fuel combustion were well below deMinimis thresholds (Benzene and Toluene < 0.01 tpy) as evidenced in the emission calculations provided with the application. Considering the negligible HAP content and negligible HAP emissions from the fuel gas used in assist gas and pilot gas fuel combustion, DCP would like to request that the testing mandated (i.e. site specific extended gas analysis of the assist gas and pilot light fuel) be restricted to a one time, initial requirement and that the periodic testing requirement specified under Condition 55 be removedRasponse: Since the sample used is representative rather than site specific, the initial gas analysis will still require evaluation HAP in addition to VOC. However, tam comfortable updating the annual testing to only include VOC. The annual testing will remain in the permit due to the level of VOC emissions. The operator did not provide any comments on the APEN redline provided. The comments and responses are also available with the email chain that has been iploaded to Records Manager. The operator reviewed the responses provided and expressed they had no further comments. Section 09 - Inventory SCC Codirez and Emissions Factors AIRS Point a cos Process a $CC Code 3-10-002.27: Glycol dehydrator: rebciter stilt stack Uncontrolled Pollutant Emissions Factor Control % Links PMIO 0.013 J.o lb/MMscf PM2.5 0.013 0.0 lb/MMscf SOx 0.001 0.0 lb/MMscf NOx 0.117 0.0 Ib/MMscf VOC 48.0 95.7 lb/MMscf CO 0.535 0.0 lb/MMscf Benzene 5.187 92.4 lb/MMscf Toluene 4.088 92.3 Ib/MMscf Ethylbenrene 0.062 92.2 lb/MMscf Xylene 0.976 92.2 lb/MMscf n -Hexane 0.934 954 lb/MMscf n4 TMP 0.002 953 lb/Mfv'scf Methanol 0.007 95 4 Ib/MMxf Dehydrator Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and 8 - APEN and Permit Requirements (Source a in the Non-Atta;nmsent Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this indM dual source greater than 2 TPY (Regulation 3, Part A, Section 11.0 l.a)' 2. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10TPY or CO emissions greater than 10 TPY (Regulation 3, Pan B, Section Il. D.3)' You hero inc.!cated that source is in the Non -Attainment Area NON-ATTNNMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section II.D.1-a)? 2. Are total facility uncontrolled VOC emissions from the greater than 2 T NOxgreater than 5 TPY or CO emissions seater than 10 TPY (Regulation 3. Part B. Section IID.2)? ro requ;res a porn•t Yes Colorado Regulation 7, Section XILH 1. Is this glycol natural gas dehydrator located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area (Reg 7, Section XII.H.1 and 2)? 2. Is this glycol natural gas dehydrator located at an oil and gas exploration and production operations, natural gas compressor station, natural gas drip station or gas -processing plant (Reg 7 Section 3. is the sum of actual uncontrolled emissions of VOC from any single dehydrator or group of dehydrators at a single stationary source equal to or greater than 15 tpy (Reg 7, Section XII.H.3.b)' 4. Are actual uncontrolled emissions of VOC from the individual col natural as den razor ual to or eater than 1 Re 7 Section XII.H.3.a ' Dehydrator is sub4tt to Regulation 7, Soction x11N Section XII.H — Emission Reductions from glycol natural gas dehydrators MACT Analysis 1. Is the dehydrator 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 A facility that processes, upgrades or stores natural gas prior to the point at which natural ges enters the natural gas transmission and storage source category or is delivered to a final b. end user: (63.760(03)1? 2. Is the dehydrator located at a facility that is a major source for HAPs? ;c.-A•G",./: ,s:.a'a„•c a Pg. rcr+rr sac! -:n to determine MAR Hie aeolicabilty 40 CFR, Part 63, Subpart MACT HH, Oil and Gas Production Focilities Area Source Requirements 1. Is the dehydrator a triethylene glycol (TEG) dehydration unit (63.760(b)(2p? Exemptions 2a. Is the actual annual average (lowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.764(eN 1)(il' 2b. Are actual annual average emissions of benzene from the glycol dehydration unit prods vent to the atmosphere less than 1,984.2 Ib/yr (63.764(e)(1110)' 3. is the unit located inside of a UA plus offset and I.IC boundary area? IDeny is sub Oct to ►-oa sou to MACT H h, ce • the raq uiromen is in 63 764(dg 21 Subpart A, General provisions per §63.764 (a) Table 2 §63.765 - Emissions Control Standards Do Not Apply §63.773 - Monitoring Standards Do Not Apply §63.774 - Recordkeeping §63.775 -Reporting Major Source Requirements Does the facility have a facility -wide actual annual average natural gas throughput Tess than 0.65 MMscf/day AND a facility -wide actual annual average hydrocarbon liquid throughput less than 1. 249.7 bbl/d (63.760(e)(2))' Small or largo Deny Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.761)? 2b. Are actual annual average emissions of benzene from the &col dehydration unit process vent to the ionosphere less than 1,984.2 lb/yr (63.761)? Smell Deity Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 3, 2011 (63.760(b)(1)(i1(B) and (C )? 4. For this small debt', is a control device required to meet the BTEX emission limit given by the applicable equation? (YOU have iroicatod that this facility is not subject to Major Source requirements a' MAC HH Subpart A, General provisions per §63.764 (a) Table 2 §63.765 - Emissions Control Standards §63.773 - Monitoring §63.774 - Recordkeeping §63.773 - Reporting 40 CFR. Part 63, Subpart MACE HHH, Natural Gas Transmission and Storage Facilities 1 Is the facility wide actual annual average natural gas throughput less than 0.9994051 MMscf/day and glycol dehydrators the only HAP emission source (63.12700)? Small or large Deity Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 9.994051 MMscf per day (63.1270(b)(2))? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.1270@1(211? Small Dohs Requirements 3. Did construction of the small glycol dehydration unit corrvnence on or before August 23.2011(631270(b)(2) and (3) )? 4. For this small deny, s a control device required to meet the BTEX emission limmlt (standard?) given by the applicable equation' You have indicated that this facility k not subject tp MACT n net Subpart A, General provisions per §63.1274 (a) Table 2 §63.1275 - Emissions Control Standards §63.1281 -Control Equipment Standards §63.1283 - Inspection and Monitoring §63.1284 - Recordkeepusg §63 1285 - Reporting Colorado Regulation 7, Section XVILD 1. Is the dehydrator subject to an emissions control requirement under MAC HH or HHH (Regulation 7, Section XVII.B.5)' 2. Is this dehydrator located at a transmission/storage facility? 3. Is this dehydrator located at an oil and gas exploration and production operation . natural gas compressor station or gas processing plant (Reg 7, Section XVII.D.3)7 4. Was this glycol natural gas dehydrator constructed before May 1. 2015 (Reg 7 Section XVII.D.4.b)? If constructed prior to May 1, 2015, are uncontrolled actual emissions from a single neat natural gas dehydrator equal to or greater than 6 tons per year VOC or 2 tpy VOC if the aa. dehydrator is located within L320 feet of a building unit or designated outside activity area (Reg 7, Section XVTLD.4b)? 5. If constructed on or after May 1. 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 2 spy VOC (Regulation 7 Section XVII.D.4a)' Dehydrator :s subjoin to Regulat ion 7 Section xvil a. 0.3 Section XVILB —General Provisions for Air Pollution Control Equipment and Prevention of Emissions Sect Ion XVILD3 - Emissions Reduction Provisions Aiternat(vs Emissions Control loptbnal Section!. 6. Is this glycol natural gas dehydrator controlled by a back-up or alternate combustion device (i.e., not the primary control device) that is not enclosed' the control device for the dehydrator is not subject to Regulation 7, Section XVII.B?.e Section XVIL82a - Alternative emissions control equipment Disclaimer Commission regulations This document is not a rule or regulation, and the analysts 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 lawregulation, 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 implementrtg regulations. and Air Quality Control Com'rassvn ,regulations. the language of the statute or regulation will control The use of non-rnendatory language such as 'recommend, "may "shoal - and "can is intended to issrnbe APCD atterprelatons and reco nmendatcns Mandatory termrnlbgy such as "must' and 'required' are intended to describe controlling requrernents under the terms of the Clean Air Act and Air Quality Control Conmsscn regurabans. but this document does not establish legally binding requirements in and of itself Yes Source Requires an APEN, Go to the next question Source Requires a Permit Continue • You have indicated the attainment status on the Project Summary Sheet. Continua • You have indicated the facility type on the Protect Summary Sheet. Go to the next question Yes Dehydrator is subject to Regulation 7, Section XILH Yes 1N° Continue - Source is subject to MACT HH requirements. You have indicated the source category on the Project Summary Sheet IGo to MACT HH Area source applicability section No NO P10 No Yes tgig sa Continue • You have indicated the dehydrator type on the dehydrator inventory sheet eo to the next question go to the next question The dehy is subject to the toot requiren*nts in 63.7641d1(2) Continue - You have previously indicated this in the MAR section Continue - You have previously Indicated this in the beginning of the MACT section Continue - You have previously indicated this in the Reg 7, Section XII determination Go to subquestion 4a. Source is subject Turbine Emissions Inventory Section 01 - Administrative Information Facility AIRs ID: 123 9008 008 County Plant Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: One (1) Solar, Titan 250-319005, natural gas fired combustion turbine (SN: TBD), rated at 175.21 MMBtu/hr heat input (WV) at 40°r ambient temperature and 27,000 horsepower (HP) at 6,615 RPM. This turbine is used for natural gas compression. Emission Control Device Equipped with SoLoNOx combustion system for minimizing omissions of Nitrogen Oxides. The SoioNox combustion Description: system is considered integral to the process and not an add-on control device. Requested Overall VOC & HAP Control Efficiency %: SoLoNOx is considered an integral control device. Section 03 - Processing Rate Information for Emissions Estimates Process 01: Steady State Operation Heat Input Rate = 175.21 MMBtu/hr Heat content of waste gas= 986.8 Btu/scf Actual Hours of Operation = 0 hrs/year 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 = Process 02: Turbine Start-up Events Number of turbine start-up events Time per start-up event Process 03: Turbine Shutdown Events Number of turbine shutdown events Time per shutdown event Section 04 - Emissions Factors & Methodologies Process 01: Steady State Operation 8760 hrs/year 48 events 10 minutes S hours/year 48 events 10 minutes 8 hours/year New Source - not yet installed 0.0-0 MMBTU per year 1,534,839.60 MMBTU per year 1.534.39.60 MMBTU per year D.00 MMscf/year 1,555.3705 MMscf/year 1,555-3705 MMscf/year Emission Factors Turbine Emission Factor Source Pollutant Uncontrolled Uncontrolled (lb/MMBtu) (Ib/MMscf) (Fuel Input) (Fuel Consumption) VOC 2.10E-03 2 372 AP -2 Chapter 3 Table 3.1-2a AP -42 Chapter 3 Table 3.1-2a AP -42 Chapter 3 Table 3.1-2a AP -42 Chapter 3 Table 3.1-2a Manufacturer Manufacturer AP -42 Chapter 3 Table 3.1-3 AP -2 Chapter 3 Table 3.13 AP -42 Chapter 3 Table 3.1-3 AP -42 Chapter 3 Table 3.1.3 AP -42 Chapter 3 Table 3.1.3 AP -42 Chapter 3 Table 3.1-3 AP -42 Chapter 3 Table 3.1-3 AP -42 Chapter 3 Table 3.1.3 AP -42 Chapter 3 Table 3.1-3 PM10 6.60E-03 6.313 PM2.5 6.60E-03 6.513 SOx 3.40E-03 3.355 NOx 4 393E-02 43 347 CO 6.07SE.02 59.973 Formaldehyde 7.10E-04 7.01E-01 Acetaldehyde 4.00E-05 3.95E-02 Acrolein 6.40E-06 6.32E-03 Benzene 1.20E-05 1.18E-02 1,3 -Butadiene 4.30E-07 4.24E-04 Ethylbenzene 3.20E-05 3.16E-02 Toluene 1.30E-04 118E-01 PAH 2.20E-06 2.17E-03 Xylene 6.40E-05 6.32E-02 Process 02: Turbine Start-up Events Emission Factors Turbine Emission Factor Source Pollutant Uncontrolled Uncortrollod (lb/event) (lb/hr) (Start-up event) (Start-up event) VOC 2.00 12 000 Manufacturer Manufacturer Manufacturer NOx 2.00 12 000 CO 32.00 192.000 Process 03: Turbine Shutdown Events Em.ssion •-actor: Turbine Emission Factor Source Pollutant Uncontrolled Uncortrolled (lb/event) (lb/hr) (Start-up event) (Start-up event) VOC 2.00 12 000 Manufacturer Manufacturer Manufacturer NOx 2.00 12.000 CO 20.00 L'C.000 7 of 20 K:\PA\2011\11WE1475.CP4 Turbine Emissions Inventory Section 05 - Emissions Inventory. Process 01: Steady State Operation Criteria Pollutants Potential to Em;: Uncontrolled _(tons/year) Actual Emissions Controlled (tons/year) Requested Permit limits Uncontrolled Controlled (tors/yearj_ (tors/year) Monthly Units Uncontrolled (lbs/month) Uncontrolled (tons/year) VOC PM10 PM2.5 SOx NOx CO 1.61 000 0.00 16116 16116 '73744104 5.06 0 00 0.00 5.0650 5 0650 860.351184 5.06 0.00 0.00 5 0650 5.0650 860.351184 2.61 0.00 0.00 2 6092 2.6092 443 211216 33.71 0 00 0.00 33 7100 33.7100 5726082192 46.64 0.00 0.00 46 6400 46.6400 7922 410962 Fia:a,d,us Air Pollute•-' Potential to Erni: Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (bs/year) Phi/year) Formaldehyde 5.449E-01 0.000E+00 0 000E+00 5 449E-01 5 449E-01 1089.7361 1089.7361 Acetaldehyde 3 070E-02 0.000£+00 0 000E+00 3 070E-02 3 070E-02 61 3936 - 61.3936 Acrobin 4.911E-03 0.000E+00 0.000E+00 -19111-03 4.911E-03 9.8230 9.8230 Benzene 9.209E-03 0.000E+00 0.000E-00 a 209E-03 9209E-03 1841111 184181 1,3 -Butadiene 3.300£-04 0.000E+00 0.000E+00 3.300E-04 3.300E-04 04600 0 6600 Ethylben:ono 2.456E-02 0.000E+00 0.000E+00 2.456E-02 2.456E-02 49.1149 49.1149 Toluene 9.976E-02 0.000E+00 0.000E-00 9.976E-02 9.976E-02 199.5291 199.5291 PAH 1 688E-03 0.000E+00 0.000E+00 1.688E-03 1.688E-03 3.3766 3 3766 Xylone 4.911£-02 0.000E+00 0.000E+00 4 911E-02 4.911E-02 98.2297 58.2297 Process 02: Turbine Start-up Events Criteria Pollutants Potential to Emit Uncontrolled It :r<./,,c•at Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) VOC 0.00 0.00 0,0S 0 c5 NOx 0.00 0.00 0 05 0.05 CO C, 00 000 077 077 Process 03: Turbine Shutdown Events '-"'"'''^'"`• Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit limits Uncontrolled Controlled (torts/Year) (torn/year) VOC NOx CO 0.05 0.00 0.00 0.0. 0.05 0.00 0 00 0-05 0 48 0 00 0.00 0 48 .. Section 06 - Regulatory Summary Analysis Regulation 1 Section I I.A.1 - Except as provided in paragraphs 2 through 6 below, no owner or operator of a sauce shall allow a 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 - intervals for The for is EPA Method 9 CFR, Part 60, second six minutes. approved reference test method visible emissions measurement (40 Appendix A (July, 1992)) in all subsections of Section II. A and B of this regulation. Section IBA No owner a operator shall cause or permit to be emitted into the atmosphere from arty fuel -burning equipment, particulate matter in the flue gases which exceeds the following: IIIA1.b. For fuel burning equipment with designed heat inputs greater than 1x10• BTU per hour, but less than a equal to 500x10+ BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE 3.5(Fl)'.'° Where: PE = Particulate Emission In Pounds per million BTU heat Input. El = Fuel Input in Million BTU per hour. The turbine covered under point 008 has a design heat input rate of 175.21 MMBtu/hr. As a result, the turbine is subject to this portion of the regulation. Using the above equation, the allowable particulate emission limitation is 0.1305 Ib/MMBtu. The AP -42 emission factor of 6.6x10 s b/MMBtu used in the calculations above is below this particulate emission threshold. Section VI.B.4. New sources of sulfur dioxide shall not emit or cause to be emitted sulfur dioxide in excess of the following process -specific Imitations (Heat input rates shall be the manufacturer's guaranteed maximum heat Input rates.) VI.8.4.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 turbine covered under point 008 has a design heat input rate of 175.11 MMBtu/hr. As a result, the turbine is subject to this portion of the regulation. The AP -42 emission factor of 3.4.10 ' lb/MMBtu used in the calculations above is below this sulfur dioxide emission threshold. Regulation 2 Section LA - No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are measured In excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven (7) or more volumes of odor free air. Regulation 3 Part A -ADEN 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) fa which the area is natattainment. Applicant is required to fie an ADEN since emissions exceed 1 ton per year NOt Part 8 —Construction Permit Exemptions Applicant is required to obtain a perm* since uncontrolled NOx emisslc s fran this facility are greater than the Z.0 WY threshold (Reg. 3, Pan B. Section Il.D.2.a1 Regulation 6 Part B Section II: Standards of Performance for New Fuel Burning Equipment ILC 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, a cause the discharge into the atmosphere of any particulate matter which is. II -C2. 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: PE43.5(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 a 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. 11.0 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. 502/mllion Btu The turbine covered under point 008 has a design haat input rate of 175.21 MMBtu/hr and will be constructed after 01/30/19. As a result, the turbine is subject to this portion of the regulation. Using the above equation in ll,C2., the allowable particulate emission limitation is 0.1305 Ib/MMI3tu. The AP -42 omission factor of 6.6x10 ' lb PM/MMBtu used in the calculations above is below this particulate emission threshold. Additionally, the AP -42 emission factor of 3.4.10 ' lb SOx/MMBtu used in the cakulations 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 facilities: All stationary gas turbines with a heat input at peak load equal to a 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 this turbine (point 008) is 175.21 MMBtu/hr which is greater than 10 MMBtu/hr. As a result, the turbine would be subject to this NSPS; however, the turbine is 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 horn 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, Obi and Dc of this part. As • result, NSPS GG does not apply to point 008. 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, Of reconstruction after February 18, 2005. your turbine is subject to this subpart. 7 his turbine (Pont 008) has a heat input at peak load of 175.21 MMBtu/hr (> IOMMBtu/hr) and will commence construction after February 18, 2005. As a result, NSPS KKKK applies to this turbine. The applicable requirements have been included in the permit. Regulation 7 Section XVI.D.6. Combustion Process Adjustment Applicability. Except as provided in Section XVI.D2., 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 omissions of NO: equal to or greater than five (5) tons per year that existed at major sources of NOx as of June 3, 2016. The turbine covered under point 008 is permitted with NO. emissions greater than 5 tpy; howev•r, the turbine will b• installed idler June 3, 2016. As a result, the turbine is not subject to this portion of the regulation. Additionally, the faciity was not classified as a major source of NOx as of June 3, 2016. MACT MACT YYYY: You are subject to this subpart if you own or operate • stationary combustion turbine located et • major source of HAP emissions. This turbine (Point 008) is not subject to MACT YYYY because it is located at an area source of HAP emissions. K:\PA\2011\ 11 WE 1475.CP4 Turbine Emissions Inventory Section 07 - Technical Ar also Notes 1. The Solar Turbine product information Letter (Pit) 168 expresses that 'For natural gas fuel, Solar's customers use 10-20% of the UHC emission rate to represent VOC emission. The estimate of 10- 20% Is based on a ratio of total non -methane hydrocarbons to total organic compounds. The use of 1020% provides a conservative estimate of VOC emissions With this information along with the manufacturer provided UHC emission rate of 0.0348049 lb/MMBtu (6.0981735 lb/hr • hr/175.21MMBtu), the VOC emission factor wasdetermined to be 0.00696 lb/MM Btu (0.2.0.0348049 lb/MMBtu). Using this value. VOC emissions were determined to be 5.34 tpy. While this result is more conservative than the emissions calculated using the AR42 VOC emission factor of 0.0021 lb/MMBtu, it was determined the use of the AP -42 emission factor was acceptable for the following reasons: (I) PIL 168 also states that "In the absence of site -specific or representative source test data. Solar refers customers to a Urited States Environmental Protection Agency (EPA) document titled 'AP -42" or other appropriate reference documents." Also, the Pll end the manufacturer specification sheets express that the VOC emission are not warranted by Solar. (if) On similar applications, the operator expressed the following: "OCP has traditionally used AP -42 factors for estimating all criteria and HAP emissions other than NOx and CO for turbines. CDPHE has historically accepted and permitted turbines using the VOCAP-42 factor. Phrase refer to Lucerne 2 Permit I2WE2024 for consistency." Since the PIL explicitly states the VOC emissions are not warranted and the Division accepts AP -42 emission factors for other pollutants emitted from turbines, the use of AP -42 is acceptable for the VOC emissions as well. (iii) The difference of 3.73 tpy VOC (maximum) does not change the facility classification. As a result, this difference is considered insignificant 2. In terms of PM emissions, Solar Phi 171 suggests the use of the following emission factor with natural gas conbustion:0.015lb/MMBtu. However, the Pit goes on to further express that 'Recent customer source testing has shown that AP -42 (EPA AP -42 "Compilation of Alt Pollutant Emission Factors.") for natural gas are ac hievable in the field." Additionally, It should be noted that the Division has accepted the use of the AP -42 emission factors for PM for the turbines permitted at other similar facilities, Based on the reasons expressed above, the AP -42 emission factors for PM 10 and PM2.S are acceptable for use moving forward. 3. The operator expressed that a flow meter Is used to measure the fuel consumption of the turbine. As a result, the permit willcontain a condition that fuel use for the turbine be tracked based on the flow meter data. 4. According to the operator and the manufacturer specification sheet provided in the application, "Solar's typical SOLoNOx warranty, for ppm values, is available for greater than -20 deg F, and between 40% and 100% load for gas fuel.' If the SoloNOx mode Is not engaged on the turbines, emissions are likely higher thanthe lb/hr values used for permitting. As a result, the permit will contain a condition that requires the turbine be operated in a way that the SoloNOx mode is engaged at ail times during normal operation. In previous applications the operator indicated that information regarding SoloNOx mode Is not provided to the operator continuously. Instead, they are only currently capable of obtaining this data directly from the electronic panel on the turbine Itself. The operator provided the following information as to why continuous monitoring of SotoNOx was not an option at this facility: "DCP requets that the CDPIiE maintain the same language for Condition 43 as provided in the draft permit (Daily monitor and record status of the SoLoNOx mode), to ensure consistency with how other permits have been written which would In turn ensure uniform compliance requirements across facilities. With regards to cerainuous monitoring, Installation of monitors are not in the scope of thisproject. in addition to concerns expressed by DCP earlier on the onerous volume of data that needs to be maintained, and the potential duplication of current recordkeeping requirements tender NSPS KKKK and NSPS Subpart A general provisions.- At this time, there is not data that supports the need for continuous monitoring of SoloNOx. As a result, daily monitoring is considered sufficient at this time. S. Based on CO emissions (>100 tpy) it was determined that portable analyzer testing would be conducted on a quarterly basis. 6. Since the NOx emissions associated with this project are close to the modeling threshold of 40 tpy, it was determined stack tasting would be required in the permit. This stack testing is important for several reasons. First it will demonstrate NOx emissions are indeed below the modeling threshold. Additionally, the NOx testng required by NSPS KKKK only requires the operator to demonstrate compliance with the NSPS KKKK NOx standard of 25 ppm at 15% oxygen. However, the permit limits are based on manufacturer data that shows the turbine is capable of operating at Nee levels of 11 ppm at 15% oxygen. If the stack testing requiring the operator to demonstrate compliance with the emission limits In additionto NSPS KKKK was not included, the operator may demonstrate compliance with NSPS KKKK but woildn't necessarily demonstrate compliance with the permit. Testing for carbon monoxide was also Includedin this stack testing requirement In this instance, testing for VOC was determined to be unnecessary. This is due to the fact that the facility is already classified as a major source of VOC and any small changes in VOC resulting horn the test would not trigger anyadditional requirements. Additionally, the operator is using the AP -47 emission factor to estimate VOC and this factor is typically canticle red to be conservative. 7. Emissions associated with start-up and shutdown events have higher emission rates compared to steady state operations. As a mutt. it was discussed with the operator that planned start-up and shutdown events must de permitted to account for elevated emission rates during these operating scenarios. The operator provided manufacturer data for emissions during start-up and shutdown events and requested to permit a total of 48 start-up events and 48 shutdown events for each turbine at this facility. The manuf acturer provided data included emission rates for NOx, CO and VOC during start-ups and shutdowns. 'The operator indicated the rates are based on 10 minute start -upland 10 minute shutdowns. The hourly emission rabesassodated with start-ups and shutdowns are shown in Section 04 above. The steady state emission rates for NOx. CO and total hydrocarbons provided by the manufacturer ae 7.7 to/fu, 10.65 lb/hr and 6.10 lb/hr. These values are lower than the emission rates during start-up and shutdowns. This supports the need to account for emissions during start -up and shutdown in addition to normal turbine operation. & The operator was provided with a draft permit and ADEN redline to review prior to public comment The operator reviewed bothdocuments and provided comments on the draft permit. The comments and responses provided are as follow: (i) Comment: Permit Language: Condition 22. Point 008: The owner or operator shall continuously monitor and record the volumetric flow rate of natural gas combusted is fuel using an operational continuous flow meter at the inlet of the turbine. The owner or operator hall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described by this permit. DCP Comment: To ensure consitency with how a recent compressor station permit with a turbine (Eaton Compressor Station) was worded for the same condition, DCP requests the addition of the following line to Condition 22: "Ourhg flow meter downtime, the natural gas consumed by the turbine as fuel shall be assumed to be 4.26 MMscf/day until the flow meter is repaired and/or operational"Response: Please see my response to comment #5 above. For the reasons discussed above, the condition will remain es currently written fn the permit (Note - the response to comment e5 Is contained in the preliminary analysis for points 005 and 011) (ii) Comment: DCP Comment: This permit has initial and periodic annual compliance tests (NOX and CO) for the turbine, In addition to the testing requirements mandated by NSPS KKKK (Conditions 47 and 59). This requirement was not found in other permits issued for compressor stations (Eaton/Bernhardt/Milton). DCP would like to request the rationale for the same. DCP urderstands that this condition was found in Lucerne 1, but it must be noted that Lucerne 2 is a majcr NNSR source for VOC and NOX, whereas Libsack is a major NNSR source for VOC and a synthetic minor ource for NOX. Response: You are correct that this facility is currently only major for VOC with regards to NNSR. However, the facility will be classified as an existing major source of NOx with thechange from moderate to serious non -attainment. As a result the annual testing for NOx and CO ncluded in the permit is warranted. Additionally, the testing outside of NSPS KKKK was included been tat NSPS KKKK only requires the testing to demonstrate the turbine meets a NOx standard of 25 ppm at 15%02. The emission limits for this source are based on 11 ppm at 15%02. Therefore, the Includedtesting requirements ensure there are requirements to demonstrate compliance with the emission limits in addition to the NSPS standards. (RI)Comment: This permit has initial and subsequent quarterfysampling for net heating value of the fuel used in the turbine (Condition 48 and 60). These are conditions that are not there in other compressor station permits (Eaton, Bernhardt. Milton) DCP would like to request the rationaie for the same. DCP undersonds that this condition was round in Lucerne 2, but it must be noted that lucerne 2 is a major NNSR source for VOC and NOX, whereas Libsack is a major NNSR source for VOC and a synthetic minor source for NOX- Response: Here again the facility will be classified as an existing major source of NOx with the change from moderate to serious non -attainment Asa result, the periodic testing is warranted. Further, the emission factors for the turbine in me Notes to Permit Holder sre In units of lb/MMBtu As a result, actual he& content is required to be used to calculate actual emissions. (iv) Comment This permit has quarter y portable analyzer testing for NOX and CO under periodic testing requirements (Condition 58). Usualtesting frequency for turbines at compressor station is semiannual with an option to go to annual after two successful tests (Eaton, Milton and Bernhardt). DCP would like to request the rationale forthe same. DCP understands that this condition was found in Lucerne 2, but it must be noted that Lucerne 2 is a major NNSR source for VOC and NOX, whereas Libsack is a major NNSR source for VOC and a syrthetic minor source for NOX. Response: Please see my responses above for comments #1.3 and #14 with regards to the change from moderate to serious non -attainment. For comparison, the O&M plan for engines requires quarterly portable analyzer tests for NOx and CO if permitted lac lity emissions of P40x or CO are greater than 100 tpy. Permitted facility CO emissions are 115.8 tpy. Since this level of emissions requires quarterly porta bit analyzer testing for engines, It is not unreasonable to require the same frequency for a turbine. The O&M plan also does not relax the portable arelyzer testing frequency when emissions are at this level. Based on the discussion quarterly portable analyzer testing is required under our current structure and thus will certainly be required wth the change to serious non -attainment. The operator did not provide arty comments on the APEN redline provided. The comments and responses are also available with the email chain that has been u ploaded to Records Manager. The operator reviewed the responses provided and expressed they had no further comments. Section 0$ - Inventory SCC Cod int and Emissions Factors AIRS Point if 008 Process N 01 02 SCC Code 2.01.002-01 • Turbine Natural Gas Fired'!. Pollutant PM 10 PM25 NOx VOC CO Sox Formaldehyde Acetaldehyde Acrolein Benzene 1,3 -Butadiene Ethylbenzene Toluene PAH Xylene VOC NOx CO vac NOx CO Uncontrolled Emissions Factor 6.60(-03 6 60E-03 4.39E-02 2.10E-03 6 Cif -02 3 40E-03 7 10E-oa 001-05 6 40E•06 1.20f•a5 1.30E-07 3 20E•05 1-30E-04 2.20E-06 6.40E-05 2.00 2.00 3200 2.00 2.00 20.00 Control % Units 0 ib/MMBtu input 0 lb/MMBtu Input 0 lb/MMBtu Input 0 lb/MMBtu Input 0 lb/MMBtu Input 0 lb/MMBtu Input 0 lb/MMBtu Input 0 lb/MMBtu Input O ib/MMBtu input 0 lb/MMBtu Input 0 Ib/MMBtu Input 0 Ib/MMBtu Input 0 lb/MMBtu Input O lb/MMBtu Input 0 lb/MMBtu Input 0 lb/start-up event O Ib/start-up event 0 lb/start-up event O Ib/shutdown event 0 lb/shutdown event O Ib/shutdown event 9 of 20 K:\PA\2011\11WE1475.CP4 Compressor Blowdown Venting Emissions Inventory Section 01 - Administrative Information Facility AIRs ID: 123 9008 009 County Plant Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Natural gas venting from turbine compressor blowdowns. Emission Control Device Description: None Requested Overall VOC & HAP Control Efficiency %: Limited Process Parameter Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions Compressor Blowdown Volume= Requested Compressor Blowdown Events= Actual Compressor Blowdown Events= Actual Throughput = 0.027539 24 0 MMscf events/year events/year 0.0 MMscf per year 0 Requested Permit Limit Throughput = 0.66 MMscf per year Requested Monthly Throughput = 0.0561 MMscf per month Potential to Emit (PTE) Throughput = Process Control (Recycling) Equipped with a VRU Is VRU process equipment: 0.66 MMscf per year Secondary Emissions - Combustion Device(s) for Air Pollution Control Separator Gas Heating Value: Volume of waste gas emitted per BBL of liquids throughput Section 04 - Emissions Factors & Methodologies Description Btu/scf scf/bbl Emissions associated with turbine compressor blowdowns were calculated based on a site specific inlet gas analysis obtained from the Libsack facility inlet on 04/17/2018. This analysis was used along with the displacement equation shown below in order to estimate emission factors and emissions. MW 22.3357721 I b/I b-mo l Displacement Equation Ex = Q • MW *Xx/C Mole % Molecular Weight lb/lb-mole Mass % Corrected Mass % Helium 0.00 4 0 0 - CO2 2.41 43.99 1.060159 4.74646229 - N2 0.24 28.02 0.067248 0.301077571 - methane 72.68 16.01 11.63536356 52.09295433 54.86214286 ethane 14.14 30.02 4.24548844 19.00757413 20.01799017 propane 6.75 44.03 2.97184888 13.30533311 14.01262599 isobutane 0.91 58.04 0.5261326 2.355560388 2.480778681 n -butane 1.98 58.04 1.15197792 5.157546893 5.431714866 isopentane 0.34 72.05 0.24230415 1.084825494 1.142493299 n -pentane 0.34 72.05 0.2432403 1.089018991 1.146909716 cyclopentane 0.01 70.1 0.0097439 0.043624639 0.045943664 n -Hexane 0.05 86.16 0.04015056 0.179758997 0.189314734 cyclohexane 0.01 84.16 0.00908928 0.040693825 0.042857052 Other hexanes 0.09 86.16 0.07332216 0.328272332 0.34572283 heptanes 0.03 100.2 0.0252504 0.113049148 0.119058682 methylcyclohexane 0.01 98.19 0.00706968 0.031651827 0.033334394 224-TMP 0.00 114.23 0 0 0 Benzene 0.01 78.1 0.0073414 0.032868351 0.034615587 Toluene 0.01 92.14 0.00562054 0.025163849 0.026501524 Ethylbenzene 0.00 92.1 0.0001842 0.000824686 0.000868525 Xylenes 0.00 106.17 0.00201723 0.009031387 0.009511483 C8+ Heavies 0.01 114.2 0.0122194 0.054707757 0.057615945 Total VOC Mole % 100.00 10.53 TOC % 94.95 VOC Wt% 25.11986697 Emission Factors Compressor Blowdowns Pollutant Uncontrolled Controlled (Ib/MMscf) (lb/MMscf) Emission Factor Source (Gas Throughput) (Gas Throughput) VOC 11804.0006 14804.0006 Extended gas analysis Benzene 20.4002 20.4002 Extended gas analysis Toluene 15.6183 15.6183 Extended gas analysis Ethylbenzene 0.5119 0.5119 Extended gas analysis Extended gas analysis Extended gas analysis Extended gas analysis Xylene 5.6054 5.6054 n -Hexane 111.5697 111.5697 224 TMP 0.0000 0.0000 Primary Control Device Emission Factor Source Uncontrolled Uncontrolled Pollutant (lb/MMBtu) lb/MMscf (Waste Heat Combusted) (Gas Throughput) PM10 0.000 PM2.5 0.000 SOx 0.000 NOx 0.000 CO 0.000 Emission Factors Compressor Slowdowns Pollutant Uncontrolled Controlled lb/event lb/event (Compressor Slowdown) (Compressor Slowdown) VOC .107.6874 407.6874 Benzene 0.5618 0.5618 Toluene 0.4301 0.4301 Ethylbenzene 0.0141 0.0141 Xylene 0.1544 0.1544 n -Hexane 3.0725 3.0725 224 TMP 0.0000 _x0000 K:\PA\2011\11W E1475.CP4 Compressor Blowdown Venting Emissions Inventory 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) PM10 PM2.5 SOx NOx VOC CO 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 4.89 0.00 0.00 4.89 4.89 6.31.01 0.00 0.00 0.00 0.00 0.00 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 13.48 0.00 0.00 13.48 13.48 10.32 0.00 0.00 10.32 10.32 0.34 0.00 0.00 0.34 0.34 3.70 0.00 0.00 3.70 3.70 n -Hexane 73.74 0.00 0.00 73.74 73.74 224 TMP 0.00 0.00 0.00 0.00 0.00 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. Regulation 2 Section I.A - No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are measured in excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven (7) or more volumes of odor free air. Regulation 3 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 VOC Part B — Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 2.0 TPY threshold (Reg. 3, Part B, Section II.D.2.a) Part B, 111.D.2 - RAG requirements for new or modified minor sources This section of Regulation 3 requires RAG for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. The date of interest for determining whether the source is new or modified is therefore November 20, 2007 (the date of the 8 -hour ozone NA area designation). Since the turbine compressor blowdowns will be in service after the date above, this source is considered "new or modified." The operator indicated RACT is satisfied through good maintenance practices. These include the following: "These include practices such as avoiding "flat" blowdowns or completely blowing down equipment for every single maintenance event. The proposed blowdowns/yr limit takes these practices into account." The operator further explained that "A "flat" blowdown is the removal of all pressure from the system. A sudden "flat" blowdown would be result in a higher emission event, therefore this practice is avoided to the extent possible for turbine blowdowns." Please see additional information regarding RAG in the Technical Analysis notes in Section 08 below. Section 07 - Initial and Periodic Sampling and Testing Requirements Using Gas Throughput to Monitor Compliance Does the company use site specific emission factors based on a gas sample to estimate emissions? This sample should represent the gas outlet of the equipment covered under this AIRs ID, and should have been 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. Yes If no, the permit will contain an "Initial Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application. Are facility -wide permitted emissions of VOC greater than or equal to 90 tons per year? Yes If yes, the permit will contain: -An "Initial Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application. -A "Periodic Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application on an annual basis. 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 You have indicated above that the monitored process parameter is natural gas vented. The following questions do not require an answer. i N/A - source is not controlled. 11 of 20 K:\PA\2011\11WE1475.CP4 Compressor Blowdown Venting Emissions Inventory Section 08 - Technical Analysis Notes 1. The operator used a site specific sample to develop emission factors and estimate emissions for this source. This sample was obtained from the Libsack Compressor Station on April 17, 2018. While this sample is site specific it was obtained more than one year prior this application. Since the facility is being modified to include new equipment and the sample is more than one year old the operator will be required to obtain a site specific sample representative of compressor blowdowns as part of this initial compliance demonstration for this facility. This sample will be used to demonstrate the emission factors established through this analysis are either accurate or conservative. 2. Typically, emissions associated with natural gas venting associated with compressor blowdowns are calculated using the weight % values directly from the sample analysis provided in the application. If the weight % values had been taken directly from the sample, the emissions would have been calculated as follows: (i) VOC: 4.64 tpy, (ii) Benzene: 12.8 lb/year, (iii) Toluene: 9.8 lb/year, ( iv) Ethylbenzene: 0.4 lb/year, (v) Xylene: 3.5 lb/year, and (vi) n -Hexane: 69.8 lb/year. Instead of using the weight % values directly from the sample, the operator chose to use the mole % values and convert to weight %. This methodology lead to a minor difference in weight % valu es. The operator further adjusted the calculated weight % values by assuming the sample was composed entirely of hydrocarbons. That is helium, carbon dioxide and nitrogen content in the sample is assumed to be zero. This methodology leads to a slightly more conservative estimate of emissions since the sample does contain minor fractions of components that are not considered hydrocarbons. This calculation methodology may be reviewed in Section 04 above. As can be seen by the emission results in Section 05, the operator's calcula tions are conservative (except for ethylbenzene) compared to the Division's practice of estimating emissions from compressor blowdowns. As a result, the operator's calculations are acceptable for permitting purposes. 3. In order to calculate actual emissions, the operator will track the number of events and multiply the events by the emissionfactors. The emission factors have been converted to units of lb/event and are available for reference in Section 04 above. .i^.�z �� ..^ce YYk-� •_ �t c.i.. . v•x ,.... <.,.i .. .....r \ • r .e' S: •:•. 4. The operator used a compressor volume of 27,539 cubic feet/blowdown. According to the operator, this volume is based on an engineering estimate from a similar turbine at another DCP compressor station (Rocky Turbine Compressor Station). 5. The operator provided the following information with regards to RACT: 'DCP has recently been evaluating RACT requirements for compressor blowdowns. The common issue is that these blowdowns have a high instantaneous flowrate, but a low overall annual flowrate, which makes sizing combustion equipment difficult. Existing/new combustors at this facility are sized specifically for TEG de by control, and cannot handle the large short-term volumes produced by compressor blowdowns. New add-on controls are expensive and also require significant redesigns to facility layout, which adds to the overall expense. Typically, DCP considers good work practice requirements as RACT for blowdown sources. These include practices such as avoiding "fiat" blowdowns or completely blowing down equipment for every single maintenance event. The proposed blowdowns/yr limit takes these practices into account." It should also be noted that current Colorado regulations do not address RACT for compressor blowdowns. As a result, it is worth assessing RAG for other equipment. For example, RAG for storage vessels is considered to be an enclosed combustion device. However, Regulation 7 Section XVII does not require this control unless uncontrolled emissions from the storage vessels are greater than 6 tpy. In this instance, uncontrolled emissions from this source are less than 6 tpy. As a result, it is reasonable to assume that control would not be required for this source since controls are not required for storage vessels with emissions at these levels. Based on this information, the operator's ass essment that good work practices satisfy RAG was accepted in this instance. However, this source may need to be re-evaluated if uncontrolled emissions increase or Colorado regulations are updated to address control requirements for maintenance blowdowns. 6. The operator provided the following information as to why the new enclosed combustor that will be installed to control emissions from point 010 would not be used to control turbine blowdown emissions: 'The ECD is specifically designed to control the waste gas off the dehydration regeneration system. This system operates at very low pressures to ensure the proper regeneration of the TEG. Add ing additional sources into the waste stream can and more than likely will cause additional upsets at the dehydrator which will bad to increase of the overall emissions coming from the facility. In plants where blowdowns are captured, these systems have been specifically designed for this operation. At the gas processing plants like Lucerne 2 and Mewbourn, these kind of blowdown activities are typically handled by the plant/emergency flare. Therefore, to achieve control of blowdown emissions at Libsack, entirely new system would have to be designed and implemented if the blowdown sources were to be captured in the field, in addition to potentially adding a new co ntrol device like a flare." x.. 7. The operator was provided with a draft permit and APEN redline to review prior to public comment. The operator reviewed bothdocuments and provided comments on the draft permit. The comments and responses provided are as follow: (i) Comment: Permit Language: Page 6 of 59 Permit Language: Monthly Limits table which provides monthly emission limits (lb/month) for facility equipment D CP Comment: DCP requests that the monthly emission limits for Equipment IDs TURB-BD and PIG be removed, as they are not evenly distributed every month and therefore cannot be evenly appropriated across 12 months. This is line with the monthly emission limit tables which have been issued in permits for other DCP compressor stations. Response: The monthly emission limits for point 009 (TURB-BD) and 011 (PIG) have been removed as requested. (ii) Comment: Permit Language: Process Limits table which provides annual and monthly process parameter limits DCP Comment: DCP requests that the monthly process limits (events) for Equipment IDs TURBBD and PIG be removed, as they are not evenly distributed every month and therefore cannot be evenly appropriated across 12 months. This is line with the monthly process limit tables in permits which have been issued for other DCP compressor stations. Response: The monthly process limits for point 009 (TURB-BD) and 011 (PIG) have been removed as requested. (iii) Comment: Permit Language: Note: The emission factors for turbine compressor blowdown events are based on a compressor volume of 0.027539 MMscf, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10 - Displacement Equation (10.4-3). Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of turbine compressor blowdown events DCP Comment: DCP would like the compressor volume represented in the un its of scf, instead of MMscf. Response: This change has been made as requested. The operator did not provide any comments on the APEN redline provided. The comments and responses are also available with the email chain that has been tploaded to Records Manager. The operator reviewed the responses provided and expressed they had no further comments. Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # 009 Process # SCC Code 01 3-10-002-03 Compressors Pollutant PM10 PM2.5 SOx NOx VOC CO Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP .. Uncontrolled Emissions Factor Control % Units 0.00 0 Ib/MMSCF 0.00 0 Ib/MMSCF 0.00 0 lb/MMSCF 0.00 0 Ib/MMSCF 14804.00 0 Ib/MMSCF 0.00 0 Ib/MMSCF 20.40 0 Ib/MMSCF 15.62 0 Ib/MMSCF 0.51 0 Ib/MMSCF 5.61 0 Ib/MMSCF 111.57 0 lb/MMSCF 0.00 0 Ib/MMSCF 12 of 20 K:\PA\2011\11WE1475.CP4 Glycol Dehydrator Emissions Inventory 010 Dehydrator tacit ty AIRS ID: 123 County 9008 Plant 010 Point Section 02 - Equipment Description Details Dehydrator Information Dehydrator Type: Make: Model: Serial Number, Design Capacity: Recirculation Pump Information Number of Pumps Pump Type Make: Model: Design/Max Recirculation Rate. Dehydrator Equipment Flash Tank ReboferBurner Stripping Gas Dehydrator Equipment Description Emission Control Device Description: Tole ir/1gAt dyedice??. TBD T8D TBD 231 two (2) etecttc TBD TB D 40 yes Yes MMscf/day gallons/minute . flash tank, and rebofer burner One (1) Triethylene glycol (TEG) natural gas dehydration unit (Meier. T80, Modet T80, Serial Number TOO) with a design capacity of 231 MMsd pot day. This emissions unit is equipped with two (2) (Make TBD, Model: T80) electric driven glycol pump with a design capacity ce 40 gallons per minute. This dehydration unit is equipped with a still vont, flash tankand reboilor burner. Emissions from the still vent are routed to an air-cooled condenser, end then to the Enclosed Flare. Emitaiom from the flash tank are routed directly to the Vapor Recovery Unit (VRU). Asa secondary control device, Cash tank emissions are routed totha E. -.closed Flare Section 03 - Processing Rate Information for Emissions Estimates (Requested Permit limit Throughput = Primary Emissions - Dehydrator Still Vent and Flash Tank (N present) Potential to Emit (PTE) Throughput = 84,315 MMscf per year Requested Monthly Throughput a MMscf per year 7.161 MMscf per month 54 Secondary Emissions - Combustion Devices) for Air Pollution Control Still Vont Control Condenser Condenser emission reduction claimed: Primary control device Primary control device operation: Secondary control device Secondary control device operation. Still Vent Gas Heating Value: Still Vent Waste Gas Vent Rate: Rash tank Control Primary control device Primary control device operation: Secondary control device Secondary control device operation: Flash Tank Gas Heating Value Flash Tank Waste Gas Vent Rate: Enclosed Flare Pilot fuel rate: Assist gas rate: Heat Content Enclosed Rare Fuel Gas Composition Yes No Enclosed We Not applicable Requested Condenser Outlet Temperature. 95% Control Efficiency % Requested TO Temp Control Effciency % 8760 hr/yr o hr/yr 1450 B^,ascr 1 08E+0.3 ;_.. Vapor Recovery Unit (VRU) 8322 hr/yr 100% Control Efficiency X Enclosed Flare 95% Control Efficiency X 438 hr/yr 1456 Btu/scf 2.98E+03 scfh 65 scf/hr 2000 scf/hr 1085.48 Btu/scf Molecular We ht 13 37 Its/b rnol 160 Degrees F Degrees F Mole % Component MW Ibxfb-mol Mass Fraction Mass Fraction (1OCX HC) Helium 1.000E-02 4.00 0.00 218E-06 0 CO2 1.180E+00 43.99 0.52 283E-02 0 N2 3.800E -C1 28.02 0.11 5.80E-03 0 Hydrogen Sulfide 4.000E-05 34.10 0.00 7.43E-07 0 methane 8.686E+01 16.01 13.91 7.57E-01 0.783773634 ethane 9.537E+00 30.02 2.86 1.58E-01 0.161 36 794 6 propane 1.599E+00 44.03 0.70 3.83E-02 0.03967854 isobutane 1 041E-01 58.04 0.06 3.29E-03 0.001405366 n -butane 2321E-01 58.04 0.13 7.33E-03. 0.00759256 tsoperttane 3.950E-02 72.06 0.03 1.55E-03 0001604646 npentane 3.800E-02 72.00 0.03 1.49E-03 6001543133 cyclopertane 0.000E+00 70.13 000 0.00E+00 0 n -Hexane 0.000E+00 86.18 0.00 0.040E+00 0 0.000E+00 8416 000 0.00E+00 0 cyclohexane Other hexanes 1.990E-02 86.06 0.02 928E-04 0 00C9bC4 heptanes 0.000E+00 100 21 0.00 O.00E+C0 0 methylcycbhexane 0.000E+00 98.19 0.00 0.00E+00 0 24-TMP 0.000E+00 114-23 0.00 0.00E+00 0 Benzene 1.100E-03 78.10 0.00 4 68E-05 4.84205E-05 Toluene 5.000E-04 92.10 0.00 2.51E -OS 1.59547E-05 Ethylbenzene 0.000E+00 106.10 0.00 0.00E+00 0 Xylenes 0.000E+00 106.10 0.00 0.00E+00 0 C8+ Heavies 0 000E+00 116.00 0.00 0.00E+00 0 Total (Uncontrolled) _ 1.00 1 Total VOC (Uncontrolle 0.0530 0.05485842 action 04 - Emission Factors & Methoddostigl Dehydrator The operator used GRI GLYCaIc 4.0 to estimate emissions. Wet gas composition is based on a sit• specriic extended wet gas analysis collected from the Ubsack faciityTEGInlet on 04/17/19 Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Glycol Recirculate Rate 1000 115 40 psig 'F gpm Flash Tank Temp: Flash Tank Pressure: Dry Gas Water Content 150 45 5 STILLVENT Control Scenano Primary Secondary Pollutant Uncontrolled (lb[hr) Controlled (b/hr) Controlled (b/hr) VOC 72.3404 3.6170: 0 Benzene 12 1270 0.60635 0 Toluene 11.7361 0.536935 0 Ethylbenzene 0.5219 7.026095 0 Xylenes 69109 . _40545 0 n -Hexane 0.9574 0.04787 0 224 -IMP 0 0 0 Methanol 0.00620279 0.000310119 0 FLASH TANI( Control Scenario Primary Secondary Pollutant Uncontrolled Ilbihrl Controlled (lb/hr) Controlled (Ib/hr) VOC 88.6044 0 4.43022 Benzene 0A299 0 0.021495 Toluene 0.2846 0 0.01423 Ethylbenzene 0.0077 0 0.00033! xy.enes 0_0703 C 0.0035:5 n!ecant 02749 0 3.04374 224 -IMP 0 C 0 Methanol 0.005667311 2 0.0002$3391 'F psig lb/MMscr 1 Still Vent Primary Still Vent Secondary Still Vent Primary Still Vent Secondary Dry Gas Throughput: Control: ?4,315.0 MMscf/yr Control: 0.0 MMscf/yr Waste Gas Sombusteg: Control: 9.46: MMscf/yr Control: 0.C MMscf/yr Dry Gas Throiaha(: Flash Tank Primary Control: 90 2953 MMscf/yr Flash Tank Secondary Control: 4215 S MMscf/yr Waste Gas Combusted: Flash Tank Primary Control. C.C MMscf/yr Flash Tank Secondary Control: 1.305 MMscf/yr Pilot fuel/Asist Gas Combusted Not Fuel: 3 5 SS4 MMscf/year Assist Fuel: :7 5_ MMscf/year Total: :3 MMscf/year Lean Glycol Water Content 1 wt % H2O 71f-:0 MMscf/month C.SC MMscf/month J J y'-:112: I - . ♦;;; Y. stir ') e - K^an+ 't:oane tibrl'drle - -but-ate Sorel' testa -Lille:7 n•rstir t'r- 4017't.7 C•.:sx - "7d3 6 - - :4316 d7tz Glycol Dehydrator Emissions Inventory Emission Factors Glycol Dehydrator Emission Factor Sot: ': o Pollutant Uncontrolled Controlled (Ib/MMsd) (b/MMsd) (Dry Gas Throughput) (Dry Gas Throughput) VOC 111394 0.467 GlyCalc4.0 Gtytalc4D G1yCalc4.0 GiyCelc4.0 GlyCelt 4.0 G1yCa144,0 Glyt.atc 4 O GlyCalc 4.0 Benzene 1.435074286 0.069445145 Toluene 1373794236 0.067159237 Ethylbenzene 0.060525714 0.002984486 Xylene 0.786422857 0.038939514 n -Hexane 0109394286 0.0057208 224 IMP 0 0 Methanol 0.00135664 3.20639E -CS Pollutant urn Vent Primary Control Device E'r'ss:on Factor Scu'ce Uncontrolled Uncontrolled lb/MMBtu) (Ib/MMsd) (Waste Heat Combusted) (Waste Gas Combusted) PM1C 0.0075 103020 AP -42 Table 1.4-2 (PM16/PM 25) AP 42 Table 14-2 (PM10/PM2S) AP -4'2 Table 1.4-2 (50x) AP-42Chapter 13.5Industrial Flares (NOx) AP•42Chapter 13.5Industrial Flares {CO) PM2.5 0.0075 10.9020 SOx 0.0006 02523 NOx 0.0680 98.5823 CO 0.3100 449.4192 Pollutant Still Vent Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (lb/MM8tu) (Ib/MMsd) (Waste Heat Combusted) (Waste Ga Combusted) PM1C C.:.. PM2.5 0.000( 50x 0 0000 NOx 0.0000 CO 0.0000 Pollutant Flash Tank Primary Control Device Emission Fact or Scarce Uncontrolled Uncontrolled (b/MMBtu) (Ib/MMsd) (Waste Heat Combusted) (Waste Gas Combated) PM1C 0.0000 _ PM2.5 0.0000 SO* 0.0000 NOx 0.0000 CO 0 0000 Pollutant Flash Tank Secondary Control Device Emission Factor Source Uncontrolled Uncontrolled (Ib/MMBtu) (Ib/ia ad) (Waste Heat Combusted) (Waste Gas Combusted) PM1C 0.0075 10.8455 Ap.42 Table 1.4.2 (PM10/PM23) AP -42 Table 1.4-2 (PM 10/PM2 S) AP -42 Table 1.4-2 (SOK) AP -42 Chapter 13.5 Industrial Flares(NOx) AP -42 Chapter 133 Industrial Flares (C01 PM2.5 0.0075 10-9699 SOx 0.0006 0.8566 NO* 0.0680 99.0195 CO 0.3100 4514122 Pollutant Pilot/Assist Gas Combustion Emission Factor Source Uncontrolled Uncontrolled (Ib/MMBtu) (Ib/MMsd) (Waste Heat Combusted) (Waste Gas Combusted) PM1C 0.0075 AP -42 Table 1.4.2 (PM10/PM25) AP -42 Table 1.4-2 (PM10/PM35) AP -42 Table 14-Z (SOx) AP -2 Chapter 135 Ostia rial Flares (NOx) AP 42 Chapter 133 Industrial FtaresjCol PM2.5 0.0075 - 50x 0.0006 .. - - NOx 0.0680 7 CO 0.3100 - , - Pollutant 'hot/Assist Gas Combustion (Primary Emission E•- ss:_,=a^or Source Uncontrolled Controlled Ib/MMsd Ib/MMscf VOC 2658.7446 132 .3T_ Mass Balance Mass Balance Mass Balance Mass Balance Mass Balance Mass Balance Mass Balance Benzene 2.3467 0.1173 Toluene 13579 0.0629 Ethylbenzene 0.0000 0.0000 Xylene 0.0000 0.0000 n -Hexane 0.0000 0.0000 224 IMP 0.0000 1 0000 section 05 - Emissions Inventory Did operator requesta ou'fer) Requested Buffer (%): yes 10% Criteria Pollutants Potential to Emit Unconeoged (tans/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled ibns/year, (tons/year) Requested Monthly Lints Controlled pas/month} PM1C PM2-5 SOx NOx CO VOC 0.13 013 0.13 013 22.31 033 0.13 0.13 : - 0.13 22.31 0.01 0.01 0.01 -: 0.0: L76 1.20 120 110 .. 1.2C 203.59 5.46 5.46 5 46 5.:6 929.14 776.63 ...:' t '0 77ry.ii t ,.;g ..-.... Hazardous Air Pollutants Potential to Emit Uncontrolled Jibs/Year ) Actual E niss,ons Uncontrolled Controlled (bs/yew) (®s/yearl Requested Permit Limits Uncontrolled Controlled (bs/year) (bs/year) Requested Permit Limits Uncontrolled Controlled (tans/year) (tons/year) Benzene Toluene Ethylbenane *VW* n -Hexane 12100341 12100041 535517 121000.41 5855.2674 6030 :.93 115832.60 115832.60 5662.4/ 115812.60 5662.45 57.92 223 5103.23 5103.23 251.64 510313 251.64 235 0.13 66307.24 66307.24 3283.19 6630714 1283.19 33.15 144 17655.08 17655.03 .. :7655.05 482.35 5.83 0.24 224 IMP 0.00 O.00 100 0.00 100 0000 Methanol 11439 114.39 3. :3 :1435 3 I:5 , -5-", 0 302 Sett ion 06 - Regulator,' Summary Analysis Regulation 3, Parts A, B Source requires a permit Regulation 7, Section XVII.B,D Dehydrators subject to Regulation 7, Section XVII, 3, 03 Regulation 7, Section XVII.B.2.e The control davits for this dehydrator is not subject to Regulation 7. Suct.un XV11.8.2.e Regulation 7, Section XII.H Dehydrator is object to Regulation 7, Section XILH Regulation 8, Part E. MACT Subpart MN (Area) Doily is subject to area source MAC? NH, per the requirements in 63.764(d)(2) Regulation 8, Part E. MACT Subpart HH (Major) You have indkated that this facility is not subject to Major Source requirements of MACT NH. Regulation 8, Part E. MACT Subpart HHH You have indicated that this facility Is net subs to MAT HHH. (See regulatory applicability worksheet for detailed analysis) i.-c. :59 124.71.!:- , ii.,-.. (75 P :3C C•?)S lanerMeabnq Vadwo! :,.n 1330.:94377 Btu/r Higher Hooting Value or 3.15 14561695 Btu/scf Source. GPSn EnE(neerins i3 to Brr> . page fl 4. Fjurt: 73-2 Sftl vent Y...r ' nixrz:nt LHv -.:r Cpl f•. 161` 5.521.3 1353.333533 Btu/st -... V. :1 7>na52 Btu/scn Glycol Dehydrator Emissions Inventory Section 07- Initial and Periodic Samoiing and Testing Requirements Was the extended wet gas sample used in the GlyCalc model/Process model site -specific and collected within a year of application submittal' No If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with omission limits 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 if the company has requested a control device efficiency greater than 95%, is a thermal oxidizer cr regenerative thermal oxidizer being used to achieve it? If yes, the permit will contain a condition specifying the minimum combustion chamber temperature for the thermal oxidizer Is the company using a thermal oxidizer AND requesting a minimum combustion chamber temperature lower than 1,400 degrees Fz If yes, the permit will contain an "Initial Compliance" testing requirement AND a permit condition specifying the minimum combustion chamber temperature for the thermal oxidizer. No Section 08 - Technical Analysis Notes 1. The emissions from the still vent are routed to a condenser prior to being routed to the enclosed flare. However, the operabris not taking credit for any control achieved by the condenser. This is demonstrated in the calculations by using the "uncontrolled regenerator emissions" stream from the GlyCalc model to calculate uncontrolled emissions and using a 95% control associated with the flare to calculate controlled emissions. Asa result, neither me permit nor the O&M plan will set a maximum outlet condenser temperature. However, the operator is taking account for the condenser in the combustion calculations as described below. As a result, the permit will require the operator to monitor the condenser outlet temperature for use in the monthly GlyCalc simulation. 2. in order to calculate still vent combustion emissions, the operator used the composition and throughput associated with the " Condenser Vent Stream" in the GlyCalc simulation. While the operator is not taking credit for the condenser as a control device, the use of the condenser vent stream to calculate still vent combustion emissions is acceptable as it Is likely a better representation of actual emissions. The other option for calculating still vent combustion emissions would have been to use the "Regenerator Overheads Stream." If this stream had been used, NOx and CO emissions would have been calculated as 0.48 tpy and 2.1$ tpy respectively (Heat Content = 90.384 Btu/scf, Flow Rate = 17,800 scf/hr). Comparatively, the "Condenser Vent Stream" properties result in NOx and CO emissions of 0.47 tpy and 2.13 tpy respectively. This minor difference In emissions does not result in a facility classification change or other regulatory requirements. As such, it was determined the use of the composition and flow rate associated with the "Condenser Vent Stream" was acceptable for estimating stilt vent combustion emissions. 3. The temperature and pressure of the inlet wet gas specified in the simulation do not match with the temperature and pressure on the representative sample provided with the application. As a result, a test GlyCalc simulation was run to assess the result if the temperature and pressure from the sample were used in the simulation. This test simulation resulted in emissions rates that were slightly more conservative than the emission rates estimated by the operator. However, the operator added a 10% buffer to their emissions estimate to account for variation in the gas analysis and other actual parameters. This 10% buffer resulted In emissions that are more conservative than the testGlyCalc simulation except for toluene, ethyibentene, and event. The values from the test simulation for toluene, ethylbenzerte and xylene are 116,247,8 lb/yr, 5205.2 lb/year and 67,357.4 lb/year respectively. The difference between the operator calculations and test simulation are minimal and thus determined to be negligible for permitting purposes. As a resu k, the operator's estimate of emissions are acceptable for permitting purposes. It should be noted that the operator will be required to obtain an initial sample in order to demonstrate initial compliance with the permitted limits. 4. Based Information in me application, the TEG dehydrator is located at an area source of HAPs. Additionally, the location dat a provided by the operator indicates this source is not located in a UA plus offset and t c boundary. Since the dehydrator also does not meet the benzene exemption or throughput exemption in the MACT based on requested permit limits, the dehydrator must meet the requirements of optimum glycol circulation rate in§63.764(d)(2). Since the dehydrator does not have control requirements specified in the MACT, the dehydrator is subject to the requirements of Regulat ion 7, Section XVII. The optimal circulation rate is based on the following parameters from the GlyCalc simulation submitted with the application: F = 231 MMscf/day, I = 89.52 lb/MMscf, and 0 = 5.0 lb/MMscf. Using these values an d the equation in MACT HH §63.764 (d)(2)(} the optimal glycol circulation rate would be calculated as follows. Lopt = (1.15)'(3 gal TEG/lb H2O)'(((231 MMscf/day)•(89.52!b/MMscf - 5.0 ib/MMscf))/(24hr/day)) = 2806.59225 gallons/hr1hr/60 min= 46.78 gallons/min. The operator has requested a circulation rate of 40 gpm. 5. The operator expressed there are no flow meters for the flash tank or still vent waste gas streams. The operator expressed tie waste gas vented from the still vent and flash tank is determined from the monthly GlyCalc simulations. 6. The O&M plan submitted by the operator does not contain Information on how the dry gas throughput vented from the dehydrator Is monitored. As a result, this information Is contained in the permit The operator expressed that the dry gas throughput is monitored with a meter at the outer of the dehydration unit. The operator expressed the facility is equipped with two outlet meters. There is one meter at the outlet of eacn dehydration unit and used to track dry gas throughput. 7. This dehydration unit is equipped with a. 4.48 MMBtu/hr reboiler. Since this reboiler has a design rate less than 5 MM8tu/hr, it is APEN exempt per Colorado Regulation 3 Part A Section II.D.1.k. 8. The operator indicated that the pilot light fuel and assist fuel used by the combustor flow at a constant rate and are there( ore not metered. Permitted emissions are based on a constant pilot fuel flow rate of 65 scf/hr and a constant assist fuel flow rate of 2,000 scf/hr. The operator did indicate that the assist fuel flow may be changed, but is constant at the rate set by theoperator. The assist fuel flow rate used in the application is the highest expected rate for this parameter. Even though these rates are constant, a limit on assist gas and pilot fuel combusted was included in the permit be cause it contributes to the overall emission limits on VOC, NOx and CO contained in the permit. 9. The operator indicated that the volume of dry gas vented from the glycol dehydrator is monitored using a flow meter at the ouiet of the dehydration unit. As a result the process limits in the permit reflect 'dry gas throughput" as the metered value. This language accurately reflects the volume of gas the operator is directly measuring at the facility and using to demonstrate compliance with the process limits. Further, the dry gas flow rate is the input value for the GlyCalc simulation the operator uses to demonstrate compliance with the emission limits In the permit. 10. As indicated in Section 07 above, the sample used in the GlyCalc simulation is site specific. However, this dehydrator is int ended to be part of a new separate compression train at the facility. Asa result the gas composition may be slightly different. Since this is a new unit that has not operated and the site specific sample used is more than one year old, the permit wilt contain an initial compliance test requiring the operator to obtain an inlet wet gas sample that will be used in the GlyCalc simulation to demonstrate the permitted emissions are either accurate or conservative. 11. According to the operator, the heat content of the waste gas streams (flash tank and still vent waste gas) will be calculated based on the monthly Glycak run. By calculating the heat value each month, rather than building the heat value used for permitting into the emission factor, the operator will be able to determine actual emissions more accurately. Three separate tables associated with the combustion processes (flash tank controlled by ECD, still vent controlled by ECD, & Assiet/pilot fuel combustion) are contained in the notes to permit holder to clearly demonstrate the methods used to calculate emissions. The notes under each table clearly indicate how the heat content of thesdll vent and flash tank waste gas streams will be calculated on a monthly basis and used along with the calculated flow rate and monitored hours of operation to determine the combustion emissions. 12. The operator expressed that assist gas was necessary for this enclosed combustor in order to handle the seasonal methanol con tent In the processed wet gas (primarily during winter months). 13. The dehydration unit is equipped with two (2) electric driven glycol pumps, each with a maximum circulation rate of 40 gpm. A ccording to the application, only one pump is active at any given time. The second glycol pump serves as a back-up only. 14. The operator indicated the values used in the simulation for lean glycol and dry gas water content are vendor design values a nd remain constant. As a result the permit will not require the operator to monitor these input parameters. According to the GlyCalc 4.0 user's manual, the "typical water contents for lean TEG are 1 wt % to 2 wt % for units without s tripping gas (page 110)' The operator used a value of 1.Owt% H2O for the lean glycol input stream. This Is within the range indicated by the GlyCalc user's manual and is therefore acceptable for permitting purposes. 15. in order to calculate methanol emissions from this source, the operator Includes the mot% of alcohols present in the referent ed gas analysis with the n -Hexane mole % specified in the GLYCaIc simulation. T he n -Hexane emission rates predicted by the Glycalc simulation are then multiplied by the ratio of the inlet alcohol mole%concentration to the inlet n -Hexane mole%concentration. Typically, the weight % values from the inlet gas simulation would be used in the ratio to determine emissions. However, me mole % values provide a conservative estimate of emissions and are acceptable for permitting purposes. The simulation used to estimate methanol emissions is run separately from the simulation used to demonstrate compliance with VOC and other HAP emissions. 16. The calculation of VCC and HAP emissions associated with the combustion of assist gas and plot light fuel is based on a repr esentative fuel gas sample obtained on. September 12, 2018. While this sample was taken within one year prior to this application, it is a representative rather than site specific sample. As a result, the operator will be required to obtain an initial sample. The permit will also require the operator to obtain an annual sample of fuel gas in order to demonstrate ongoing compliance with the emission factors established through this analysis. 17. As discussed above, VOC and HAP emissions associated with the combustion of assist gas and pilot light fuel are calculated using a representative fuel gas sample in conjunction with the EPA Emission Inventory Improvement Program Publication: Volume Ii, Chapter 10 • Displacement Equation (10.4.3). This information is used to establish lb/MMscf emission fac tors. In order to calculate actual VOC and HAP emissions, the emission factors established through this analysis are multiplied by the actual assist gas and pilot light fuel use. These emissions are added to the VOC & HAP emissions calculated through the monthly GlyCalc simulations in order to determine total VOC and HAP emissions. It should be noted that only the controlled emission factors are used to estimate VOC and HAP emissions associated with combustion of assist gas and pilot light fuel. This is due to the fact that the fuel gas (i.e. assist and pilot light) is only combusted when the combustion device is operational. There is no scenario in which fuel gas is vented to atmosphere. In the event the combustion device is not operational, the fuel gas flow Is shut down. The controlled VOC and HAP emissions associated with combustion of assist gas and pilot fuel were added to both the uncontrolled and controlled columns above. 18. The enclosed combustor specification sheet provided indicates it is capable of handling an emergency heat release rate of 36. 7 MMBtu/hr. The dehydrator Is permitted to send a total of 4.03 MMBtu/hr to me enclosed flare annually. As a result, the flare should be able to handle the volume of gas sent to it during normal operations, 19. This dehydration unit does not have a back•up control device for the still vent. The operator indicated that the dehydration wit shuts down in the event the enclosed combustor is down. Asa result, it is acceptable that there is not a back-up control for the still vent. 20. The NOx and CO emissions assocated with the combustion of pilot fuel and assist gas are based on a heat content of 1065.48 Btu/scf. While this value does not match with the heat content calculated on the fuel gas analysis (1087.4 Btu/scf), the difference in emissions resulting from the use of the operator provided value rather than the value on the fuel analysis is negligible. As a result. the operator provided value was accepted and used for permitting purposes. The operator's explanation for the difference in values is available in the email chain uploaded to Records Manager. 21. The operator was provided with a draft permit and ADEN redline to review prior to public comment The operator reviewed the d ocuments and provided comments on the draft permit The comments and responses provided are as follows: (i) Comment: Permit Language: ConditIon 13. Point 005 & 010: On a weekly basis, the owrer or operator shall monitor and record operationalvalues including condenser outlet temperature, flash tank temperature and pressure, wet gas inlet temperature and pressure, These records shall be maintained fora period of five years. OCP Comment: In the previous version of the permit "condenser outlet temperature" was not included in the above condition. Note that the condenser is not used art emissions control device (no credit was taken during emission estimation for the dehydrators AIRS 005 and 010) DCP requests that 'condenser outlet temperature' be removed from the above condition. Response: DCP uses the condenser outlet temperature In the GlyCalc model one monthly basis to obtain the heat content of the still vert waste gas stream and thus calculate combustion emissions. Since the condenser temperature is an input in the model, OCP will be required to track actual values. Since the condenser is not being claimed as emission control a limit on the maximum outlet temperature is not Included in permit or O&M plan for this source. The condition will remain as it currently stands in the permit. This topic has been discussed with DCP in the past and agreed to. (ii) Comment: Permit Language: Condition 18. Point005 & 010: The volume of dry gas throughput shall be measured by gas meter at the outlet of each 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. OCP Comment: The previous permit gave us an option to measure the volume of gas processed by a gas meter or to use the maximum design rate of dehydrator. Therefore- in line with how a recent compressor station permit with a dehydrator (Eaton Compressor Station) was worded for the same condition, DCP requests the addition of the following line to Condition 18. "During flow meter downtime, a dry gas throughput of 64 MMscf/day for 005 and 231 MMscf;day for 010 shall be assumed until the flow meter is repaired and/or operational.' Response: The intention of this condition is to require the use of a flow meter to demonstrate compliance with the process limits, not provide multiple compliance mechanisms.I understand this condition was structured this way in the past: however, the oil and gas team determined the requested structure of the condition is not appropriate and has removed the optional language from our permit templates. It is imperative that actual information be used to demonstrate compliance with the limits. The requested language allows for the continued use of an assumed throughput for an indefinite amount of time. I am not certain why the permit you referenced contained the requested language. You will notice the most recen t permit) wrote and issued for DCP (Troudt - 13WE1108) no longer contains this language. The language will remain is currently written in the permit flit) Comment: Permit Language: Conditions 44 and 55 OCP Comment: With the above conditions (Conditions 44 and 55), DCP would like to point ott that the representadve site specific extended fuel gas analysis showed minimal HAP content. The HAP emissions from assist gas combustion and pilot light fuel combustion were well below deMinimis thresholds (Benzene and Toluene < 0.01 tpy) as evidenced in the emission calculations provided with the application. Considering the negligible HAP content and negligible HAP emissions from the fuel gas used in assist gas and pilot gas fuel combustion, 0CP would like to request that the testing mandated (i.e. site specific extended gas analysis of the assist gas and pilot light fuel) be restricted to a one time. initial requirement and that the periodic testing requirement specified under Condition 55 be removed.Rosponse: Since the sample used is representative rather than site specific, the initial gas analysis will still require evaluation HAP in addition to VOC. However, I am comfortable updating the annual testing to only include VOC. The annual testing will remain in the permit due to the level of VOC emissions. The operator did not provide any comment on the APEN redline provided. The comments and responses are also available with the email chain that has been uploaded to Records Manager. The operator reviewed the responses provided and expressed they had no further comments. E�tz"?rr "p�� ::Ite on, t'...ma( e: rip Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point N 010 Process N 01 SCC Code 8.10.002-27: Glycol Uncontrolled Pollutant Emissions Factor Control 14 Units PM10 10 Ib/MMscf PM2.5 0.003 0.0 Ib/MMscf SOx 0.000 0.0 Ib/MMscf NOx 0.028 0.0 Ib/MMscf VOC 18.4 97.5 lb/MMscf CO 0.130 0.0 Ib/MMscf Benzene 1.435 95.2 lb/MMscf Toluene 1374 95 1 lb/MMscf Ethylbenzene 0.061 95.1 lb/MMscf Xylene 0.786 95.0 Ib/MMscf n -Hexane 0.209 97.3 Ib/MMscf 224 TMP 0.000 NON/o! lb/MMscf Methanol 0.001 97.3 lb/MMscf Dehydrator Regulatory Analysis Worksheet Colorado Regulation 3 Parts A and B • APEN and Permit Requirements 'Source is in the Non -Attainment A, ATTNNMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TRY (Regulation 3. Part A, Section II.D.1.a)? 2. 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)? You have indicated that source is in the Non -Attainment Area NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than 1 TPY (Regulation 3, Part A, Section ILD.1a)? 2. 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 11.0.21? Source requires a permit Colorado Regulation 7, Section XILH 1. Is this glycol natural gas dehydrator located in the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area (Reg 7, Section XII.H.1 and 2)) 2. Is this glycol natural gas dehydrator located at an oil and gas exploration and production operation', natural gas compressor station, natural gas drip station or gas -processing plant (Reg 7 Section 3. Is the sum of actual uncontrolled emissions of VOC from any single dehydrator or group of dehydrators at a single stationary source equal to or greater than 15 tpy (Reg 7, Section XII.H.3.b)? 4. Are actual uncontrolled emissions of VOC from the Individual glycol natural gas dehydrator equal to or greater than 1 tpy (Reg 7, Section XII.H.3a)? Dehydrator is subject to Regulation 7, Section X3!.H Section XR.H — Emission Reductions from glycol natural gas dehydrators MACT Analysis 1. Is the dehydrator 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 &quids' (63.760(a)(2)); OR 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 b. end user' (63.760(aX311? 2. Is the dehydrator located eta facility that is a major source for HAPs? Go to MAR HH Area Source Requirement section to determine MAR HH applicability 40 CFR, Part 63, Subpart MAC! HH, Oil and Gas Production Facilities Area Source Requirements 1. Is the dehydrator a triethylene glycol (TEG) dehydration unit (63.160(b)(2))? Exemptions 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.764(e)11Xi)? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.764(e)(1)(6)? 3. Is the unit located inside of a UA plus offset and UC boundary area? Dehy is subject to area source MAC HH, per the requirements in 63.764i J1121 Subpart A. General provisions per §63.764 (a) Table 2 §63.765 - Emissions Control Standards Do Not AM* §63.773 - Monitoring Standards Do Not Apply §63.774 - Recordkeeping §63.775 - Reporting Major Source Requirements Does the facility have a facility -wide actual annual average natural gas throughput less than 0.65 MMscf/day AND a facility -wide actual annual average hydrocarbon liquid throughput less than 1. 249.7 bbl/d (63.760(e)(2))? Small or Large Dehy Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 3.001747 MMscf per day (63.761)7 2b. Are actual annual average emissions of benzene from the *col dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.761)? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (63.760(b)(1)(iX8) and (C )? 4. For this small dehy. Is a control device required to meet the BTEX emission limit elven by the applicable equation? i You have indicated :hat this facility is not subject to Major Source requirements of MAR HH. Subpart A, General provisions per §63.764 (a) Table 2 463.765 - Emissions Control Standards 463273 - Monitoring §63.774 - Recordkeeping §63.775 - Reporting 40 CFR. Part 63, Subpart MAC HHH, Natural Gas Transmission and Storage Facilities 1 Is the facility wide actual annual average natural gas throughput less than 0.9994051 MMscf/day and glycol dehydrators the only HAP emission source (63.1270pi) Small or Large Dehy Determination 2a. Is the actual annual average flowrate of natural gas to the glycol dehydration unit less than 9.994051 MMscf per day (63.1270(b)1211? 2b. Are actual annual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere less than 1,984.2 lb/yr (63.1270(b)(2)l? Small Dehy Requirements 3. Did construction of the small glycol dehydration unit commence on or before August 23, 2011 (631270(6)(2) and (3)P 4. For this small deity, is a control device required to meet the BTEX emission limit (standard?) given by the applicable equation' Yo_ Yes Yes Yet 1 You have indicated that this facility is not subject to MAR HH Subpart A. General provisions per §63.1274 (a) Table 2 463.1275 - Emissions Control Standards 463.1281 -Control Equipment Standards §63.1283 - Inspection and Monitoring 463.1284 • Recordkeeping §63.1285 Reporting H. Colorado Regulation 7, Section XVILD 1. Is the dehydrator subject to an emissions control requirement under MACT HH or HHH (Regulation 7, Section XVII.B.5)? 2. Is this dehydrator located ata transmission/storage facility? 3. Is this dehydrator located at an oil and gas exploration and production operation , natural gas compressor station or gas processing plant (Reg 7, Section XVll.0.3)? 4. Was this glycol natural gas dehydrator constructed before May 1, 2015 (Reg 7 Section XVII.D.4.b)? If constructed prior to May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 6 tons per year VOC or 2 toy VOC 8 the 4a. dehydrator is located within 1,320 feet of a building unit or designated outside activity area (Reg 7, Section XVII.D.4.b)? 5. If constructed on or after May 1, 2015, are uncontrolled actual emissions from a single glycol natural gas dehydrator equal to or greater than 2 tpy VOC (Regulation 7, Section XVI1.0.4a)? Gohydrater 's subject to Regulation 7, Section XVII, 8. 0.3 Section XVILB —General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.D.3 - Emissions Reduction Provisions Alternative Emissions Control (Optional Section) 6. Is this glycol natural gas dehydrator controlled by a back-up or alternate combustion device tie., not the primary control device) that fs not enclosed? The control dents for this dehydrator is not subject to Regulation 7, Section %VILB2.e Section XVIL82.e —Alternative emissions control equipment Disclaimer 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. megulatan. or any other lagafy 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 anplementa ig 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 ' as intended to descnbe APCD interpretations and .recommendations Mandatory tenrunology such as 'must" and 'required' are intended to descnbe 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 No No Yes No .Yes. :.. Source Requires an APEN. Go to the next question Source Requires a Permit Continue • You have indicated the attainment status on the Project Summary Sheet Continue - You have indicated the facility type on the Project Summary Sheet. Go to the next question Dehydrator is subject to Regulation 7, Section XILH Continue • Source is subject to MACT NH requirements. You have indicated the source category on the Project Summary Sheet Go to MACT HH Area source applicability section Continue • You have indicated the dehydrator type on the dehydrator inventory sheet go to the next question go to the next question The dehy is subject to the Loot requirements in 63.764(d)(2) Continue • You have previously indicated this in the MAC section Continue - You have previously indicated this in the beginning of the MACT section Continue -You have previously indicated this in the Reg 7, Section XII determination Go to question 5 Source is subject Blowdown Emissions Inventory Section 01- Administrative Information I Facility AIRS ID: 123 County 9008 Plant 011 Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Natural gas venting resulting from the blowdown of pig receivers and pig launchers. Emission Control Device Description: None Requested Overall VOC & HAP Control Efficiency %: Limited Process Parameter NIWAffilaratattel Section 03 - Processing Rate Information for Emissions Estimates Constants: R (Ideal Gas Law Constant) = Atmospheric Pressure = Temperature = Primary Emissions Receiver 10" (Low Pressure) Number of receivers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Slowdown Events= Total Moles Vented (n) = Total Mass Vented = Receiver 20" (Low Pressure) Number of receivers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Slowdown Events= Total Moles Vented (n) = Total Mass Vented = Receiver 12" (Low Pressure) Number of receivers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Blowdown Events= Total Moles Vented (n) = Total Mass Vented = Receiver 24" (Low Pressure) Number of receivers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Slowdown Events= Total Moles Vented (n) = Total Mass Vented = Actual Throughput = 10.7316 ftA3*psia/•R'Ibmol 12.2 psia 550 •R 1 19.926 scf 400 psig 52 events/year O events/year 1.39155683 lb-mol 31.08150918 lbs 2 68.839 scf 400 psig 156 events/year O events/year 4.807456619 lb-mol 107.3783002 lbs 2 25.815 scf 400 psig 156 0 1.802822421 4026744753 events/year events/year Ib-mol lbs 0 123.344 scf 400 psig O events/year O events/year 8.613880638 lb-mol 1923977551 lbs 0.0 MMscf per year Ideal Gas Law = PV=nRT Receiver 6" (High Pressure Fuel) Number of receivers = Receiver Volume= Receiver Pressure = Requested Blowdown Events= Actual Slowdown Total Moles Vented (n) = Total Mass Vented = 1 3.576 scf 1150 psig 1 0 0.704127352 15.72723463 Receiver 12" (High Pressure) Number of receivers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Slowdown events/year events/year Ib-mol lbs 2 25.815 scf 1150 psig 16 events/year O events/year Total Moles Vented (n) = 5.083067 lb-mol Total Mass Vented = 113.5342735 lbs Launcher 16" (High Pressure] Number of launchers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Slowdown Total Moles Vented (n) = Total Mass Vented = Number of launchers = Receiver Volume= Receiver Pressure = Requested Slowdown Events= Actual Slowdown Total Moles Vented (n) = Total Mass Vented = 1 35.487 scf 1150 psig 16 events/year 0 events/year 6.987518831 lb-mol 155.9859238 lbs 1 68.839 scf 1150 psig 16 events/year O events/year 13.55464843 lb-mol 302.5872857 lbs Requested Permit Limit Throughput = Potential to Emit (PTE) Throughput = Total Requested Slowdown Events = Total Actual Slowdown Events = Process Control (Recycling) Equipped with a VRU: Is VRU process equipment: 0.0331 MMscf per year 0.03 MMsd per year 741.00 events/year 0.00 events/year Secondary Emissions - Combustion Device(s) for Air Pollution Control Separator Gas Heating Value: Volume of waste gas emitted per BBL of liquids throughput: Section 04 - Emissions Factors & Methodologies Btu/scf scf/bbl Requested Monthly Throughput = 0.0028 MMscf per month 1 Description The operator used two separate gas analyses to determine emissions. According to the application, the pigging receivers handle inlet gas and the pigging launchers handle post dehydrator dry gas. As a result, the operator used a site specific inlet gas sample from the Libsack facility inlet on 04/17/18 to estimate emissions from blowdowns of pigging receivers and the dry gas predicted by the GlyCaic simulation to estimate emissions from blowdowns of pigging launchers. The GlyCalc simualtion is based on the inlet gas sample obtained on 04/17/18. Inlet Gas Composition: MW 2233578142 Ib/Ib-mol Displacement Equation Ex=Q• MW* Xx/C Mole % Molecular Weight lb/lb-mole Mass % Corrected Mass % Helium 0.00 4 0 0 - CO2 2.41 43.99 1.060159 4.74646031 -- N2 0.24 28.02 0.067248 0.301077445 - methane 72.68 16.01 11.63536356 52.0929326 54.86211875 ethane 14.14 30.02 4.24548844 19.0075662 20.01798137 propane 6.75 44.03 2.97184888 13.30532756 14.01261983 isobutane 0.91 58.04 0.5261326 2.355559405 2.480777591 n -butane 1.98 58.04 1.15197792 5.157544741 5.431712479 isopentane 0.34 72.05 0.24230415 1.084825041 1.1424927% n -pentane 0.34 72.05 0.2432408 1.089018 537 1.146909212 cyclopentane 0.01 70.1 0.0097439 0.043624621 0.045943644 n -Hexane 0.05 86.18 0.04015988 0.179800649 0.189358596 cyclohexane 0.01 84.16 0.00908928 0.040693308 0.042857033 Other hexanes 0.09 86.16 0.Q7332216 0.328272195 0.345722678 heptanes 0.03 100.2 0.0252504 0.113049101 0.11905863 methylcyclohexane 0.01 98.19 0.00706968 0.031651814 0.033334379 224-TMP 0.00 114.23 0 0 0 Benzene 0.01 78.1 0.0073414 0.032868337 0.034615571 Toluene 0.01 92.14 0.00562054 0.025163839 0.026501513 Ethylbenzene 0.00 92.1 0.0001842 0.000824686 0.000868525 Xylenes 0.00 106.17 0.00201723 0.009031383 0.009511479 C8+ Heavies 0.01 114.2 0.0122194 0.054707735 0.05761592 iota, VOC Mole % TOC % 94.95 VOC Wt% 25.11989988 Emission Factors Total Pigging Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (Blowdown event) (B lowdown event) VOC 19.8S75 19.8875 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 0.0272 0.0272 Toluene 0.020E 0.0208 Ethylbenzene 0.0c1, ' 0.0007 Xylene 0.007-1 0.0074 n -Hexane 0.1499 0.1499 224 TMP 0.0000 0.0000 Dry MW Gas Composition: 22.32350675 Ib/Ib-mol Displacement Equation Ex = Q MW • Xx / C Mole % Molecular Weight lb/lb-mole Mass % Corrected Mass % Water 0.01 18.02 0.0018921 0.008476 --- 0O2 2.41 43.99 1.060159 4.74907 - N2 0.24 28.02 0.067248 0.301243 -- methane 72.70 16.01 11.63927 52.13908 54.91722 ethane 14.10 30.02 4.23282 18.96127 19.97159 propane 6.75 44.03 2.972025 13.31343 14.02282 isobutane 0.91 58.04 0.5258424 2.355555 2.481067 n -butane 1.98 58.04 1.149192 5.147901 5.422198 isopentane 0.34 72.05 0.242088 1.084453 1.142237 n -pentane 0.34 72.05 0.2428085 1.087681 1.145636 cyclopentane 0.01 70.1 0.0096738 0.043335 0.045644 n -Hexane 0.05 86.18 0.0400737 0.179513 0.189079 cyclohexane 0.01 84.16 0.00900512 0.040339 0.042489 Other hexanes 0.09 86.16 0.073236 0.328067 0.345547 heptanes 0.03 100.2 0.0251502 0.112662 0.118665 methylcyclohexane 0.01 98.19 0.007010766 0.031405 0.033079 224-TMP 0.00 114.23 0 0 0 Benzene 0.01 78.1 0.00684937 0.030682 0.032317 Toluene 0.01 92.14 0.005150626 0.023073 0.024302 Ethylbenzene 0.00 92.1 0.00016578 0.000743 0.000782 Xylenes 0.00 106.17 0.001741138 0.0078 0.008215 C8+ Heavies 0.01 114.2 .. _. 0.0121052 0.054226 0.057116 Total VOC Mole % TOC% 94.94 VOC Wt% 25.11119 K:\PA\2O11\11 WE1475.CP4 Blowdown Emissions Inventory Pollutant Primary Control Device Uncontrolled Uncontrolled (ib/MMStu) Ib/MMscf Emission Factor Source (Waste Heat Combusted) (Gas Throughput) PM10 0.000 PM2.5 0.000 SOx 0.000 NOx 0.000 Co 0.0.. Emission Factors Receiver 10" (Low Pressure) Emission Factors Pollutant Uncontrolled Controlled Emission Factor Source lb/event lb/event (10" Slowdown) (10" Slowdown) VOC 1.8076 7.8016 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 1.08E-02 1.08E-02 Toluene 8.24E-03 8.24E-03 Ethylbenzene 2.70E-04 2.70E•04 Xylene 2.96E-03 2.96E-03 n -Hexane 5.89E-02 5.89E-02 224 TMP 0.00E+00 Emission Factors Receiver 20" (Low Pressure) Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (20" Blowdown) (20" Slowdown) VOC 2-.t i s; 26.9733 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 3.72E-02 3.72E-02 Toluene 2.85E-02 2.85E-02 Ethylbenzene 9.33E-04 9.33E-04 Xylene 1.02E-02 1.02E-02 n -Hexane 2.03E-01 2.03E-01 224 TMP O.Ocr.on CC:.30r to," Emission Factors Receiver 12" (Low Pressure) Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (12" Slowdown) (12" Blowdown) VOC 10.1151 10.1151 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 1.39E-02 1.39E-02 Toluene 1.07E-02 1.07E-02 Ethylbenzene 3.50E-04 3.50E-04 Xylene 3.83E-03 3.83E-03 n -Hexane 7.62E-02 7.62E-02 224 TMP 0.OOE.O0 0.00E +00 Emission Factors Receiver 24" (Low Pressure) Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (24" Slowdown) (24" Blowdown) VOC 0-0000 0.0000 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 0.0000 0.0000 Toluene 0.0000 0.0000 Ethylbenzene 0.0000 0.0000 Xylene 0.0000 0.0000 n -Hexane 0.0000 0.0000 224 TMP 0.0000 0.0000 Emission Factors Receiver 6" (High Pressure Fuel) Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (6" Slowdown) (6" Blowdown) VOC 3.9507 3.9507 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 5.44E-03 5.44E-03 Toluene 4.17E-03 4.17E-03 Ethylbenzene 1.37E-04 1.37E-04 Xylene 1.50E-03 1.50E-03 n -Hexane 2.98E-02 2.98E-02 224 TMP 0.00E+00 0.00E+0b Emission Factors Receiver 12" (High Pressure) Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (12" Slowdown) (12" Slowdown) VOC 2.: , '6.5: _ ; Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 3.92._ 3.93E-02 Toluene 3.01E-02 3.01E-02 Ethylbenzene 9.86E-04 9.86E-04 Xylene 1.08E-02 1.08E-02 n -Hexane 2.15E-01 2.15E-01 224 IMP 0.00E ..'" GOOF " ' Emission Factors IlIattr 16" (High Pressuti hltision Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (16" Slowdown) (16" Slowdown) VOC 39.1699 39.1699 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 5.04E-02 5.04E-02 Toluene 3.79E-02 3.79E-02 Ethylbenzene 1.22E-03 1.22E-03 Xylene 1.28E-02 1.28E-02 n -Hexane 2.95E-01 2.95E-01 224 TMP 0.00F +00 o.nnr.an Emission Factors Launcher20" (High Pressure) Emission Factors Emission Factor Source Pollutant Uncontrolled Controlled lb/event lb/event (20" Slowdown) (20" Slowdown) VOC 75.9833 75.9833 Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Engineering Analysis Benzene 9.78E-02 9.78E-02 Toluene 7.35E-02 7.35E-02 Ethylbenzene 2.37E-03 2.37E-03 Xylene 2.49E-02 2.49E-02 n -Hexane 5.72E-01 5.72E-01 224 TMP 0.00E+00 0.00E+00 Section 05 - Emissions Inventory Total Emissions 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) PM10 PM2.5 SOx NOx VOC CO 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 0.00 0.00 0.00 0.00 0.00 0 7.37 0.00 0.00 7.37 7.37 1251.60 0.00 0.00 0.00 0.00 0.00 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 20.14 0.00 0.00 20.14 20.14 Toluene 15.39 0.00 0.00 1539 15.39 Ethylbenzene 0.50 0.00 0.00 0.50 0.50 Xylene 5.49 0.00 0.00 5.49 5.49 n -Hexane 111.07 0.00 0.00 111.07 111.07 224 TMP 0.00 0.00 0.00 0.00 0.00 18 of 20 K:\PA\2011\11W E1475.CP4 Blowdown Emissions Inventory Receiver 10" (Low Pressure) Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.S SOx NOx VOC 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.20 0.20 34 CO 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 0.56 0.56 Toluene 0.43 0.43 Ethylbenzene 0.01 0.01 Xylene 0.15 0.15 n -Hexane 3.06 3.06 224 TMP 0.00 0.00 Receiver 20" (Low Pressure Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 VOC CO 4.21 4.21 715 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 11.60 11.60 Toluene 8.88 8.88 Ethylbenzene 0.29 0.29 Xylene 3.19 3.19 n -Hexane 63.44 63.44 224 IMP 0.00 0.00 Receiver 12" (Low Pressure Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx VOC 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 1.58 1.58 268 CO 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 4.35 4.35 Toluene 3.33 3.33 Ethylbenzene 0.11 0.11 Xylene 1.19 1.19 n -Hexane 23.79 23.79 224 IMP 0.00 0.00 Receiver 24" (Low Pressure) Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx VOC 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 CO 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 0.00 0.00 Toluene 0.00 0.00 Ethylbenzene 0.00 0.00 Xylene 0.00 0.00 n -Hexane 0.00 0.00 224 IMP 0.00 0.00 Section 06 - Regulatory Summary Analysis Receiver 6" (HIgh Pressure Fuel Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx VOC CO 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.0020 0.0020 0 0.00 0.00 U Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (bs/year) Benzene 0.01 0.01 Toluene 0.00 0.00 Ethylbenzene 0.00 0.00 Xylene 0.00 0.00 n -Hexane 0.03 0.03 224 IMP 0.00 0.00 Receiver 12" (High Pressure Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx VOC CO 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.46 0.46 78 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 IMP 1.26 1.26 0.96 0.96 0.03 0.03 0.35 0.35 6.88 6.88 0.00 0.00 Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 PM2.5 SOx NOx 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 0.00 0.00 0 VOC 0.3134 0.3134 53 CO 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled abs/year) (lbs/year) Benzene 0.81 0.81 Toluene 0.61 0.61 Ethylbenzene 0.02 0.02 Xylene 0.21 0.21 n -Hexane 4.72 4.72 224 TMP 0.00 0.00 Criteria Pollutants Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Monthly Limits Controlled (lbs/month) PM10 0.00 0.00 0 PM2.5 0.00 0.00 0 SOx 0.00 0.00 0 NOx 0.00 0.00 0 VOC 0.6079 0.6079 103 CO 0.00 0.00 0 Hazardous Air Pollutants Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene 1.56 1.56 Toluene 1.18 1.18 Ethylbenzene 0.04 0.04 Xylene 0.40 0.40 n -Hexane 9.15 9.15 224 IMP 0.00 0.00 Regulation 1 Section IIAi - 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 8 of this regulation. Regulation 2 Section IA - No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are measured in excess of the following limits: For areas used predominantly for residential or commercial purposes it is a violation if odors are detected after the odorous air has been diluted with seven (7) or more volumes of odor free air. Regulation 3 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 VOC Part B — Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 2.0 TPY threshold (Reg. 3, Part B, Section II.0.2.a) Part B, III.D.2 - RACT requirements for new or modified minor sources This section of Regulation 3 requires RACT for new or modified minor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainment area. The date of interest for determining whether the source is new or modified is therefore November 20, 2007 (the date of the 8 -hour ozone NA area designation). Since the pigging blowdowns will be in service after the date above, this source is considered "new or modified." The operator indicated RACT is satisfied through good maintenance practices. These include the following: "Best Management Practices include proper piping design, adequate depressurization of the vessels in a safe manner prior to pig removal and appropriate recordkeeping of pigging blowdown events." Please see additional information regarding RACE in the Technical Analysis notes in Section 08 below. Section 07 - Initial and Periodic Sampling and Testing Requirements Using Gas Throughput to Monitor Compliance Does the company use site specific emission factors based on a gas sample to estimate emissions? This sample should represent the gas outlet of the equipment covered under this AIRS ID, and should have been 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 Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application. Are facility -wide permitted emissions of VOC greater than or equal to 90 tons per year? ..m 19 of 20 K:\PA\2O11\11 W E1475.CP4 Blowdown Emissions Inventory If yes, the permit will contain: -An "Initial Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application. -A "Periodic Testing Requirement" to collect a site -specific gas sample from the equipment being permitted and conduct an emission factor analysis to demonstrate that the emission factors are less than or equal to the emissions factors established with this application on an annual basis. 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 inn have indicated above that the monitored nrncess narameter is natural eas vented. The following questions do not reouire an answer. Section 08 - Technical Analysis Notes N/A - source is not controlled. 1. The operator used two separate gas analyses to determine emissions. According to the application, the pigging receivers handle inlet gas and the egging launchers handle post dehydrator dry gas. As a result, the operator used a site specific inlet gas sample from the Libsa& facility inlet on 04/17/18 to estimate emissions from blowdowns of pigging receivers and the dry gas predicted by the GlyCalc simulation to estmate emissions from blowdownsof pigging launchers. The GlyCalc simulation is based on the inlet gas sample obtained on 04/17/18. While this sample is site specific, it was taken more than one year prior to the application and the operators adding new equipment to the facility Which could ead to a change in gas composition. As a result, the permit will require the operator to obtain initial samples of gis that is representative of inlet gas and dry gas. 2. In order to calculate actual emissions, the operator will track the number of blowdown events associated with each pig receiver/launcher and multiply the events by the emission factors developed for each receiver/launcher size. The emission factors have been converted to units of lb/event and are available for reference in Section 04 above. This specificity is necessary because the blowdown volume assoiated with each size of pig receiver/launcher is different and thus the lb/event emission factors are different depending on which specific piece of equipment is blown down. There are receivers and launchers that have the same size (i.e. 20" & 12") however, the VOC composition of the gas blows down from these separate sources or the operating pressure is different. As a result, the emission factors are again differentdespite having the same volume of gas. 3. The operator expressed the pig launcher and pig receiver volumes were estimated using engineering estimates and calculationsfrorr similar pig launchers and receivers installed at other DCP facilities. 4. The operator provided the following information with regards to RACT: "Pigging operations deal with instantaneous spikes in flow and pressure which pose problems in routing those emissions to the existing and new combustors at the facility. In addition, installation of an exclusive control device for pigging would necessitate layout changes at the facility which would prove to be expensive and beyond the scope ofRACT level control. Best Management Practices include proper piping design, adequate depressurization of the vessels in a safe manner prior to pig removal and appropriate recordkeeping of pigging blowdown events." it should also be noted that current Colorado regulations do not address RACT for blowdownsof pigging receivers and launchers. Additionally, pig launchers and receivers are often located at different places within a facility and do not vent to a common stack. As a result, it is common that each pig launcher or receiver is considered an individual point sourceand evaluated separately with regards to APEN and permit applicability. If this had been done, only the 20" receivers would have exceeded APEN and permitting thresholds (` 2 tpy each). Further it is worth assessing RACT for other equipment. For example, RACT for storage vessels is considered to be an enclosed combustion device. However, Regulation 7 Section XVII does not require this control unless uncontrolled emissions from the storage vessels are greater than 6 tpy. In this instance, uncontrolled emissions from all the launchers and receivers combined are geater than E tpy; however, they are all below this threshold if evaluated individually. The operators methodology of grouping t hese sources is conservative witt regards to standard permitting practices. As a result, it is reasonable to assume that control would not be required for this source. Based on this information, the operator's assessment that good work practices satisfy RACT was accepted in this instance. Howe ver, this source may need to be re- evaluated if uncontrolled emissions increase or Colorado regulations are updated to address control requirements for maintenaice blowdowns. 5. The operator provided the following information as to why the new enclosed combustor that will be installed to control emissions from point 010 would not be used to control pigging blowdown emissions: "The ECD is specifically designed to control the waste gas off the dehydration regeneration system. This system operates at very low pressures to ensure the proper regeneration of the TEG. Adding additioral sources into the waste stream can and more than likely will cause additional upsets at the dehydrator which will lead to incr ease of the overall emissions coming from the facility. In plants where blowdowns are captured, these systems have been specifically designed for this operationAt the gas processing plants like Lucerne 2 and Mewbourn, these kind of blowdown activities are typically handled by the plant/emergency flare. Therefore, to achieve control of blowdown emissions at Libsack, entirely new system would have to be designed and implemented if the blowdown soures were to be captured in the field, in addition to potentially adding a new control device like a flare." 6. The operator was provided with a draft permit and APEN redline to review prior to public comment. The operator reviewed both documents and provided comments on the draft permit. The comments and responses provided are as follow: (i)Comment: Permit Language: Page 6 of 59 Permit Language: Monthly Limits table which provides monthly emission limits (lb/month) for facility equipment DCP Comment: CEP requests that the monthly emission limits for Equipment IQs TURK -BD and PIG be removed, as they are not evenly distributed every month and therefore cannot be evenly appropriated across 12 months. This is line with the monthly emission limit tables which have been issued inpermits for other DCP compressor stations. Response: The monthly emission limits for point 009 (TURB-BD) and 011 (PIG) have been removed as requested. (ii) Comment: Permit Language: Process Limits table which provides annual and monthly process parameter limits DCP Comment: DCP requests th at the monthly process limits (events) for Equipment IDs TURBBD and PIG be removed, as they are not evenly distributed every month and therefore cannot be evenly appropriated across 12 months. This is line with the monthly process limit tables in permits which have beenissued fc r other DCP compressor stations. Response: The monthly process limits for point 009 (TURB-BO) and 011 (PIG) have been removed as requested.(ii:) Comment: Permit Language: Notes to Permit Holder Condition 5 Point 011: DCP Comment: DCP would like to correct the uncontrolled lb/blowdown event values as follows: Process 02: 26.99 lb/blowdown event, Process 05: 28-54 lb/blowdown event, Process 06: 39.22 ib/bbwdown event, Process 07: 76.07 lb/blowdown event. Response: This change has been made as requested. The operator did not provide any comments on the APEN redline provided. The comments and responses are also available with the email chain that has been uploaded to Records Manager. The operator reviewed the responses provided and expressed they had no further comments. 7. As discussed above, the operator requested to use the following emission factors: Process 02: 26.99 lb/blowdown event, Process 05: 2854 lb/blowdown event, Process 06: 39.22 Ib/blowdown event: Process 07: 76.07 lb/blowdown event. These values do not match with the values calculated above. The differences in values is small and likely due to rounding in calculations. Since the difference in emisions calculated using the operator requested values is negligible and the operator requested values are conservative, they are acceptable for permitting purposes. t �C .S Y..... _ .F.IX 1 � Y, .� ... .L-��:: Y::9::3::a: [".�^Yfi'. bPi.}LyIY-aa�l ".Y11(t 'YII4: IG.L{I Lr.Ir N.. Y.' %4:.dli%.I:a%< %..6A....,C Iv.l�%L�-i:. i:: L:: %::".""1 %�k %(:."..Y.'4. ..""ni"LYS "r k. }t •{t4LWL" ^I�"'''''•'"""14‘v++‘"'"`"..""'"-.'• 1.-. ..,r... -.n �.^" 1Y-:. .papa aav wr-�Aa". .. , .�,....�...e �rti�n..rti i.rvr}..vii` .� r x:me�S.•:ml�•.•r!'Ymrn.—�•..e.w^rzr—....-rvr�.�.�r•--w .""1"r -+v n.er.r.r-.e-"rfrrunLlU n...rll Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point ti 011 Process e 01 SCC Code 3-10-002-11 Pfpeiige Pigging {releases sittiiiii ptg removal) `::, Pollutant PM10 PM2.5 SOx NOx VOC CO Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP Uncontrolled Emissions Factor Control % Units 0.00 0 lb/MMSCF 0.00 0 lb/MMSCF 0.00 0 Ib/MMSCF 0.00 0 lb/MMSCF 445658.76 0 lb/MMSCF 0.00 0 Ib/MMSCF 609.05 0 lb/MMSCF 465.31 0 lb/MMSCF 15.22 0 Ib/MMSCF 165.88 0 I b/MMSCF 3358.98 0 Ib/MMSCF 0.00 0 Ib/MMSCF 20 of 20 K:\PA\2011\11WE1475.CP4 COLORADO Air Pollution Control Division Department of Public Health b Environment Dedicated to protecting and improving the health and environment of the people of Colorado Permit number: Date issued: Issued to: CONSTRUCTION PERMIT I1 WE 1475 Issuance: 4 DCP Operating Company, LP Facility Name: Plant AIRS ID: Physical Location: County: Description: Libsack Compressor Station 123/9008 SEC 36 T6N R65W Weld County Natural Gas Compressor Station Equipment or activity subject to this permit: Facility Equipment ID AIRS Point Equipment Description Emissions Control Description C-185 001 One (1) Waukesha, Model L7044GSI, Serial Number 5283701797, natural gas -fired, turbo -charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This emission unit is used for natural gas compression. Non -selective catalytic reduction (NSCR) system and air -fuel ratio control C-186 002 One (1) Waukesha, Model L7044GSI, Serial Number 5283701843, natural gas -fired, turbo -charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This emission unit is used for natural gas compression. Non -selective catalytic reduction (NSCR) system and air -fuel ratio control C-187 003 One (1) Waukesha, Model L7044GSI, Serial Number 5283701844, natural gas -fired, turbo -charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This emission unit is used for natural gas compression. Non -selective catalytic reduction (NSCR) system and air -fuel ratio control Page 1 of 59 COLORADO Air Pollution Control Division Department of Public Health El Environment Dedicated to protecting and improving the health and environment of the people of Colorado C-188 004 One (1) Waukesha, Model L7044GSI, Serial Number 5283701845, natural gas -fired, turbo -charged, 4SRB reciprocating internal combustion engine, site rated at 1680 horsepower at 1200 RPM. This emission unit is used for natural gas compression. Non -selective catalytic reduction (NSCR) system and air -fuel ratio control D-1 005 One gas Model: Number: 64 MMscf equipped glycol Model: gallons is equipped flash (1) Triethylene glycol (TEG) natural dehydration unit (Make: QB Johnson, Custom Glycol Contactor,, Serial 642012) with a design ? capacity of '' per day. This emissions unit is with one (1) electric driven pump (Make: Best Works Pump, N/A) with a design capacity of 24 per minute. This dehydration unit with a reboiler, condenser, tank, and still vent. Emissions from the still vent are routed to a condenser and then to an enclosed combustor. During enclosed combustor downtime, emissions from the still vent are vented to the atmosphere. The enclosed combustor has a maximum of 3% annual downtime. Emissions from the flash tank are routed directly to a vapor recovery unit (VRU) that recycles emissions back to the compressor station inlet. During VRU downtime, flash tank emissions are routed to the enclosed combustor. The VRU has a maximum 5% annual downtime. C-167 007 One (1) Waukesha Model: L7044 GSI SN: C- 14610/1 natural gas fired, turbocharged, 4SRB reciprocating internal combustion engine, site rated at 1,680 HP. This emission unit is used for natural gas compression. Non -selective catalytic reduction (NSCR) system and air -fuel ratio control TURB-1 008 One (1) Solar Titan 250-31900S, Serial Number: TBD, natural gas fired turbine rated at 175.21 MMBtu/hr (LHV) heat input at 40°F ambient temperature and 27,000 None Page 2 of 59 COLORADO Air Pollution Control Division Department of Public Health b Environment Dedicated to protecting and improving the health and environment of the people of Colorado horsepower at 6,615 RPM. This turbine is used for natural gas compression. This source is equipped with SoLoNOx technology for minizing emissions of Nitrogen Oxides. TURB-BD 009 Natural gas venting from turbine compressor blowdowns. None D-2 One (1) Triethylene glycol (TEG) natural gas dehydration unit (Make: TBD, Model: TBD, Serial Number: TBD) with a design capacity of 231 MMscf per day. This emissions unit is equipped with two (2) (Make: TBD, Model: TBD) electric driven glycol pumps each with a design capacity of 40 gallons per minute. Only one glycol pump will be operated at any given time. The second glycol pump serves asa back- up only. This dehydration unit is equipped with a still vent, flash tank, and reboiler burner. Emissions from the still vent are routed to an air-cooled condenser, and then to the enclosed combustor. Emissions from the flash tank are routed directly to a vapor recovery unit (VRU) that recycles emissions back to the compressor station inlet. During VRU downtime, flash tank emissions are routed to the enclosed combustor. The VRU has a maximum of 5% annual downtime. PIG 011 Natural gas venting resulting from the blowdown of pig receivers and pig launchers. This source includes the following equipment: • One (1) 10" low pressure pig receiver, • Two (2) 20" low pressure pig receivers, • Two (2) 12" low pressure pig receivers, • One (1) 6" high pressure fuel pig receiver, • Two (2) 12" high pressure pig receivers, • One (1) 16" high pressure pig launcher, and None Page 3 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado • One (1) 20" high pressure pig launcher. Points 001-004, and 007: These engines may be replaced with another engine in accordance with the temporary engine replacement provision or with another Waukesha L7044G51 engine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. Point 005 £t 010: The glycol pump may be replaced with another glycol pump in accordance with the provisions of the Alternate Operating Scenario (AOS) in this permit. Point 008: This turbine may be replaced with another Solar Titan 250-31900S turbine rated at 27,000 HP in accordance with the temporary turbine replacement provision or with another Solar Titan 250-31900S turbine rated at 27,000 HP in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment B. This permit is granted subject to all rules and regulations of the Colorado Air Quality Control Commission and the Colorado Air Pollution Prevention and Control Act (C.R.S. 25-7-101 et seq), to the specific general terms and conditions included in this document and the following specific terms and conditions. REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION 1. Point 007-011: 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, submitting a Notice of Startup form to the Division for the equipment covered by this permit. 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! Number 3, Part B, Section III.G.1. and can result in the revocation of the permit. 2. Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, compliance with the conditions contained in this permit shall be demonstrated to the Division. It is the owner or operator's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. A self certification form and guidance on how to self -certify compliance as required by this permit may be obtained online at www.colorado.gov/cdphe/air- permit-self-certification. (Regulation Number 3, Part B, Section III.G.2.) 3. This permit shall expire if the owner or operator of the source for which this permit was issued: (i) does not commence construction/modification or operation of this source within 18 months after either, the date of issuance of this construction permit or the date on which such construction or activity was scheduled to commence as set forth in the permit application associated with this permit; (ii) discontinues construction for a period of eighteen months or more; (iii) does not complete construction within a reasonable time of the estimated completion date. The Division may grant extensions of the deadline. (Regulation Number 3, Part B, Section III.F.4.) Page 4 of 59 COLORADO Air Pollution Control Division Department of Public Health E. Environment Dedicated to protecting and improving the health and environment of the people of Colorado 4. The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self -certification process. (Regulation Number 3, Part B, Section III.E.) 5. Point 007: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. • manufacture date • construction date • order date • date of relocation into Colorado • manufacturer • model number • serial number This information shall be included with the Notice of Startup submitted for the equipment. (Regulation Number 3, Part B, Section III.E.) 6. Point 008: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. manufacturer model number serial number This information shalt be included with the Notice of Startup submitted for the equipment. (Regulation Number 3, Part B, Section III.E.) 7. Point 010: The following information shall be provided to the Division within fifteen (15) days of the latter of commencement of operation or issuance of this permit. • The dehydrator manufacturer name, model number and serial number • The glycol circulation pump manufacturer name and model number This information shall be included with the Notice of Startup submitted for the equipment. (Regulation Number 3, Part B, Section III.E.) 8. 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 9. Emissions of air pollutants shall not exceed the following limitations. (Regulation Number 3, Part B, Section II.A.4.) ) Monthly Limits: Facility Equipment ID AIRS Point Process Pounds per Month Emission Type PM10 PM2.5 SOX NOX VOC CO Page 5 of 59 COLORADO Air Pollution Control Division Department of Pubiic Health 8 Environment Dedicated to protecting and improving the health and environment of the people of Colorado C-167 007 01 204 204 --- 4,145 2,073 4,145 Point TURB-1 008 01 861 861 443 5,726 274 7,923 Point D-2 010 01 --- --- --- 204 3,346 928 Point Note: Monthly limits are based on a 31 -day month. For Point 008 the following process designation applies: o Process 01: Steady-state Turbine Emissions The owner or operator shall calculate monthly emissions based on the calendar month. Facility -wide emissions of each individual hazardous air pollutant shall not exceed 1,359 pounds per month. Facility -wide emissions of total hazardous air pollutants shall not exceed 3,414 pounds per month. The facility -wide emissions limitation for hazardous air pollutants shall apply to all permitted emission units at this facility. Annual Limits: Facility Equipment ID AIRS Point Process Tons per Year Emission Type PMio PMz.s SOX NOX VOC CO C-185 001 01 1.2 1.2 --- 8.1 11.4 16.2 Point C-186 002 01 1.2 1.2 --- 8.1 11.4 16.2 Point C-187 003 01 1.2 1.2 --- 8.1 11.4 16.2 Point C-188 004 01 1.2 1.2 --- 8.1 11.4 16.2 Point D-1 005 01 --- --- --- 1.4 24.4 6.3 Point C-167 007 01 1.2 1.2 --- 24.4 12.2 24A Point TURB-1 008 01 5.1 5.1 2.6 33.8 1.7 46.7 Point 02 --- --- --- 0.1 0.1 0.8 03 --- --- --- 0.1 0.1 0.5 TURB-BD 009 01 --- --- --- --- 4.9 --- Point D-2 010 01 --- --- --- 1.2 19.7 5.5 Point 01 --- --- --- --- 7.4 --- Point Page 6 of 59 COLORADO Air Pollution Control Division Department of Public Hearth & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 02 03 04 PIG 011 05 06 07 Note: • See "Notes to Permit Holder" for information on emission factors and methods used to calculate limits. • Process 01, 02 and 03 for point 008 are as follows: Process 01: Steady-state Turbine Emissions Process 02: Start-up Turbine Emissions Process 03: Shutdown Turbine Emissions For Point 011 the following process designations apply: o Process 01: Blowdown of 10" low pressure pig receiver o Process 02: Blowdown of 20" low pressure pig receiver o Process 03: Blowdown of 12" low pressure pig receiver Process 04: Blowdown of 6" high pressure fuel pig receiver Process 05: Blowdown of 12" high pressure pig receiver Process 06: Blowdown of. 16" high pressure pig launcher Process 07: Blowdown of 20" high pressure pig launcher Facility -wide emissions of each individual hazardous air pollutant shall not exceed 8.0 tons per year. Facility -wide emissions of total hazardous air pollutants shall not exceed 20.1 tons per year. The facility -wide emissions limitation for hazardous air pollutants shall apply to all permitted emission units at this facility. Points 007-011: During the first twelve (12) months of operation, compliance with both the monthly and annual emission limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is required. Compliance with the annual limits, for both criteria and hazardous air pollutants, 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 actual emissions each month and keep a compliance record on site or at a local field office with site responsibility for Division review. 10. The owner or operator must use the emission calculation methods and emission factors found in the Notes to Permit Holder to calculate emissions and show compliance with the limits Page 7 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado contained in this permit. The owner or operator must submit an Air Pollutant Emission Notice (APEN) and receive a modified permit prior to the use of any other method of calculating emissions. 11. The owner or operator shall track emissions from all insignificant activities at the facility on an annual basis to demonstrate compliance with the facility potential emission limitations as indicated below. An inventory of each insignificant activity and associated emission calculations shall be made available to the Division for inspection upon request. For the purposes of this condition, insignificant activities are defined as any activity or equipment, which emits any amount but does not require an Air Pollution Emission Notice (APEN) or is permit exempt. (Regulation Number 3, Part C. II.E.) Total emissions from the facility, including all permitted emissions and potential to emit from all insignificant activities, shall be less than: • 25 tons per year of total hazardous air pollutants (HAP). 12. Point 005: 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: dry gas throughput (measured at the outlet of the dehydrator), lean glycol recirculation rate, vapor recovery unit (VRU) downtime, ECD downtime, condenser outlet temperature, flash tank temperature and pressure, wet gas inlet temperature and wet gas inlet pressure. Recorded operational values, except for dry gas throughput, VRU downtime, and ECD downtime, shall be averaged on a monthly basis for input into GRI GlyCalc and be provided to the Division upon request. 13. Point 005 Et 010: On a weekly basis, the owner or operator shall monitor and record operational values including: condenser outlet temperature, flash tank temperature and pressure, wet gas inlet temperature and pressure. These records shall be maintained for a period of five years. 14. Point 010: 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: dry gas throughput (measured at the outlet of the dehydrator), lean glycol recirculation rate, vapor recovery unit (VRU) downtime, condenser outlet temperature, flash tank temperature and pressure, wet gas inlet temperature, and wet gas inlet pressure. Recorded operational values, except for dry gas throughput and VRU downtime, shall be averaged on a monthly basis for input into the model and be provided to the Division upon request. 15. 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 Control Device Pollutants Controlled C-185 001 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO Page 8 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado C-186 002 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO C-187 003 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO C-188 004 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO D-1 005 Still Vent: Enclosed Combustor VOC and HAP Flash Tank: Recycled to plant inlet via VRU. Routed to enclosed combustor during 5% VRU downtime. C-167 007 Non -selective catalytic reduction system and air/fuel ratio controller NOx, VOC, and CO D-2 010 Still Vent: Enclosed Combustor VOC and HAP Flash Tank: Recycled to plant inlet via VRU. Routed to enclosed combustor during 5% VRU downtime. 16. Point 005 £t 010: Except during VRU downtime, 100% of emissions that result from the flash tank associated with each dehydrator shall be recycled to the compressor station inlet and recompressed in a closed loop system. During VRU downtime, 100% of emissions that result from the flash tank associated with each dehydrator shall be routed to an enclosed combustor. PROCESS LIMITATIONS AND RECORDS 17. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rates shall be maintained by the owner or operator and made available to the Division for inspection upon request. (Regulation Number 3, Part B, Section I I .A.4. ) Process Limits Facility Equipment ID AIRS Point Process Process Parameter Annual Limit Monthly Limit (31 days) C-185 001 01 Consumption of natural gas as a fuel 128.8 MMSCF C-186 002 01 Consumption of natural gas as a fuel 128.8 MMSCF --- C-187 003 01 Consumption of natural gas as a fuel 128.8 MMSCF -- C-188 004 01 Consumption of natural gas as a fuel 128.8 MMSCF --- Page 9 of 59 D-2 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado D-1 005 01 Total Dry Gas Throughput 23,360 MMSCF Total still vent waste gas throughput 6.7 MMSCF Still vent waste gas routed to the atmosphere 0.2 MMSCF Flash tank waste gas routed to and combusted by the ECD 0.8 MMSCF Combustion of assist gas and pilot fuel by the enclosed combustor Consumption of natural gas as a fuel Consumption of natural gas as a fuel Ten minute turbine start-up event Ten minute turbine shutdown event Turbine compressor blowdown events 128.8 MMSCF C-167 007 01 10.94 MMSCF TURB-1 008 03 01 1,555.4 MMSCF 132.1 MMSCF 48 events 48 events TURB-BD 009 01 24 events 010 01 Total Dry Gas Throughput 84,315 MMSCF 7,161 MMSCF Still vent waste gas routed to and combusted by the ECD 9.5 MMSCF 0.8 MMSCF Flash tank waste gas routed to and combusted by the ECD 1.3 MMSCF Combustion of assist gas and pilot fuel by the enclosed combustor 18.1 MMSCF 1.54 MMSCF PIG 011 01 10" low pressure pig receiver blowdown event 52 Page 10 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 02 20" low pressure pig receiver blowdown event 312 03 12" low pressure pig receiver blowdown event 312 04 6" high pressure fuel pig receiver blowdown event 1 05 12" high pressure pig receiver blowdown event 32 06 16" high pressure pig launcher blowdown event 20" high pressure pig launcher blowdown event 16 The owner or operator shall monitor monthly process rates based on the calendar month. Points 007-011: During the first twelve (12) months of operation, compliance with both the monthly and annual throughput limitations is required. After the first twelve (12) months of operation, compliance with only the annual limitation is required. Compliance with the annual throughput limits shall be determined on a rolling twelve (12) month total. By the end of each month a new twelve-month total is calculated based on the previous twelve months' data. The permit holder shall calculate throughput each month and keep a compliance record on site or at a local field office with site responsibility, for Division review. Points 001-004 Et 007: Fuel consumption shall be measured by one of the following methods: individual engine fuel meter; facility -wide fuel meter attributed to fuel consumption rating and hours of operation; or manufacturer -provided fuel consumption rate. 18. Point 005 £t 010: The volume of dry gas throughput shall be measured by gas meter at the outlet of each 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. 19. Point 005: This unit shall be limited to the maximum lean glycol circulation rate of 24 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 (Lopt) provisions under MACT HH. (Regulation Number 3, Part B, Section II.A.4) Page 11 of 59 COLORADO Air Pollution Control Division apartment of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 20. Point 005 £t 010: The owner or operator shall monitor and record flash tank vapor recovery unit (VRU) downtime on a daily basis. Flash tank VRU downtime shall be defined as times when the waste gas vented from the dehydrator flash tank is routed to the enclosed combustor rather than the VRU. The total hours of flash tank VRU downtime, total flash tank waste gas volume, and total volume of flash tank waste gas routed to the ECD shall be recorded on a monthly basis. The owner or operator shall use monthly VRU downtime records, monthly gas volume 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. 21. Point 005: The owner or operator shall monitor and record enclosed combustor (ECD) downtime on a daily basis. ECD downtime shall be defined as times when the waste gas vented from the dehydrator still vent is routed to the atmosphere rather than the ECD. The total hours of ECD downtime, total still vent waste gas volume and total volume of still vent waste gas routed to atmosphere during ECD downtime shall be recorded on a monthly basis. The owner or operator shall use monthly ECD downtime records, monthly gas volume 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. 22. Point 008: The owner or operator shall continuously monitor and record the volumetric flow rate of natural', gas combusted as fuel using an operational continuous flow meter at the inlet of the turbine. 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 008: On a monthly basis, the owner or operator shall monitor and record the total number of turbine startup and shutdown events. 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. 24. Point 009: On a monthly basis, the owner or operator shall monitor and record the total number of turbine compressor blowdown events. By the end of each month, the total number of turbine compressor blowdown 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. 25. Point 010: 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. (Regulation Number 3, Part B, Section II.A.4) 26. Point 011: On a monthly basis, the owner or operator shall monitor and record the total number of blowdown events associated with each pig receiver and pig launcher. By the end of each month, the total number of events associated with each pig receiver and pig launcher for the Page 12 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 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. STATE AND FEDERAL REGULATORY REQUIREMENTS 27. The permit number and ten digit AIRS ID number assigned by the Division (e.g. 123/4567/001) shall be marked on the subject equipment for ease of identification. (Regulation Number 3, Part B, Section III.E.) (State only enforceable) 28. 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. (Regulation Number 1, Section II.A.1. £t 4.) 29. This source is subject to the odor requirements of Regulation Number 2. (State only enforceable) 30. This source is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, Section III.D.2. The following requirements were determined to be RACT for this source. Facility Equipment ID AIRS Point Pollutant RACT C-185 001 NON, VOC Air -Fuel Ratio Controller and NSCR C-186 002 NON, VOC Air -Fuel Ratio Controller and NSCR C-187 003 NOR, VOC Air -Fuel Ratio Controller and NSCR C-188 004 NOR, VOC Air -Fuel Ratio Controller and NSCR D-1 005 VOC Still Vent: Enclosed Combustor Flash Tank: Recycled to plant inlet via VRU. Routed to enclosed combustor during 5% VRU downtime. C-167 007 NON, VOC Air -Fuel Ratio Controller and NSCR TURB-1 008combustion NOx, VOC Natural gas as fuel, low NOx burners, good practices TURB-BD 009 VOC Good Maintenance Practices D-2 010 VOC Still Vent: Enclosed Combustor Flash Tank: Recycled to plant inlet via VRU. Routed to enclosed combustor during 5% VRU downtime. Page 13 of 59 COLORADO Air Pollution Control Division Department of Public Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado PIG 011 V0C Good Maintenance Practices Waukesha Engines (Points 001-004 at 007) 31. This equipment is subject to the control requirements for stationary and portable engines in the 8 -hour ozone control area under Regulation Number 7, Section XVI.B.1. For rich burn reciprocating internal combustion engines, a non -selective catalyst reduction system and an air fuel controller shall be required. 32. Points 001-004: This equipment is subject to the control requirements for natural gas -fired reciprocating internal combustion engines under Regulation No. 7, Section XVII.E (State only enforceable). The owner or operator of any natural gas -fired reciprocating internal combustion engine that is either constructed or relocated to the state of Colorado from another state after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Maximum Engine HP Construction or Relocation Date Emission Standard in g/hp-hr N0x CO V0C <100HP N/A 4.0 N/A ≥100HP and <500HP January 1, 2008 January 1, 2011 2.0 1.0 2.0 1.0 0.7 July 1, 2007 July 1,2010 2.0 1.0 4.0 2.0 1.0 0.7 Note: Per Regulation No. 7, Section XVII.B.4, internal combustion engines that are subject to an emissions control requirement in a federal maximum achievable control technology ("MACT") standard under 40 CFR Part 63, a Best Available Control Technology ("BACT") limit, or a New Source Performance Standard under 40 CFR Part 60 are not subject to this Section XVII. 33. Point 007: This equipment is subject to the requirements for natural gas -fired reciprocating internal combustion engines under Regulation Number 7, Section XVII.E.3 (State only enforceable). Any rich burn reciprocating internal combustion engine constructed or modified before February 1, 2009 with a manufacturer's name plate design rate greater than 500 horsepower shall install and operate both a non -selective catalyst reduction and an air fuel controller by July 1, 2010. The operator shall operate and maintain the air pollution control equipment to manufacturer specifications or equivalent to the extent practicable and shall keep manufacturer specifications or equivalent on file. Records of maintenance shall be kept on site or at a local field office with site responsibility, for Division review. Please note that replacements of this engine in accordance with the A0S in Attachment A may be subject to this or other requirements in Regulation 7, Section XVII.E. TEG Dehydrator (AIRS Point 005 Et 010) Page 14 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 34. Point 005 a 010: 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 recordkeeping, monitoring, reporting and emission control requirements for glycol natural gas dehydrators; 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.) 35. Point 005 a 010: The combustion device covered by this permit is subject to Regulation Number 7, Section XVII.B.2 General Provisions (State only enforceable). If a flare or other combustion device is used to control emissions of volatile organic compounds to comply with Section XVII, it shall be enclosed; have no visible emissions during normal operations, as defined under Regulation Number 7, XVII.A.17; 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. This flare must be equipped with an operational auto -igniter according to the following schedule: • All combustion devices installed on or after May 1, 2014, must be equipped with an operational auto -igniter upon installation of the combustion device; • 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. 36. Point 005 a 010: The glycol dehydration unit covered by this permit is subject to the emission control requirements in Regulation Number 7, Section 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% on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. 37. Point 005 Et 010: The glycol dehydration units at this facility are subject to the National Emissions Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities, Subpart HH. If actual average emissions of benzene from the glycol dehydration unit process vent to atmosphere are greater than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart, the glycol dehydration units 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 Outside UA/UC boundary Page 15 of 59 COLORADO Air Pollution Control Division. Department of Public Health Er Environment Dedicated to protecting and improving the health and environment of the people of Colorado §63.760 - §63.760 (f) - The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(1) and (f)(2) of this section. The owner or operator of an affected area source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs (f)(3) through (f)(6) of this section. Applicability and designation of §63.760 (f)(6) - The owner or operator of an affected area source that is affected source not located in an Urban -1 county, as defined in §63.761, the construction or reconstruction of which commences on or after July 8, 2005, shall achieve compliance with the provisions of this subpart immediately upon initial startup or January 3, 2007, whichever date is later. §63.764 (d)(2) -Each owner or operator of an area source not located in a UA plus offset, and UC boundary (as defined in §63.761) shall comply with the provisions specified in paragraphs (d)(2)(i) through (iii) of this section. §63.764 (d)(2)(i) - Determine the optimum glycol circulation rate using the following equation: gal TEG (F*(I—O)\ Lon —1.15 *3.0 *1bH2O 24hr/day) Where: LOPT = Optimal circulation rate, gal/hr. F = Gas flowrate (MMSCF/D) I = Inlet water content (lb/MMSCF) O = Outlet water content (lb/MMSCF) §63.764 - 3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal General TEG/lbH2O) Standards 1.15 = Adjustment factor included for a margin of safety. §63.764 (d)(2)(ii) - Operate the TEG dehydration unit such that the actual glycol circulation rate does not exceed the optimum glycol circulation rate determined in accordance with paragraph (d)(2)(i) of this section. If the TEG dehydration unit is unable to meet the sales gas specification for moisture content using the glycol circulation rate determined in accordance with paragraph (d)(2)(i), the owner or operator must calculate an alternate circulation rate using GRI-GLYCalcTM, Version 3.0 or higher. The owner or operator must document why the TEG dehydration unit must be operated using the alternate circulation rate and submit this documentation with the initial notification in accordance with §63.775(c)(7). §63.764 (d)(2)(iii) - Maintain a record of the determination specified in paragraph (d)(2)(ii) in accordance with the requirements in §63.774(f) and Page 16 of 59 COLORADO Air Pollution Control Division Department of Public Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado submit the Initial Notification in accordance with the requirements in §63.775(c)(7). If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph (d)(2)(i) or (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v). §63.774 (b) - Except as specified in paragraphs (c), (d), and (f) of this section, each owner or operator of a facility subject to this subpart shall maintain the records specified in paragraphs (b)(1) through (11) of this section: §63.774 (b)(1) - The owner or operator of an affected source subject to the provisions of this subpart shall maintain files of all information (including all reports and notifications) required by this subpart. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report or period. §63.774 (b)(1)(i) - All applicable records shall be maintained in such a manner that they can be readily accessed. §63.774 - Recordkeeping §63.774 (b)(1)(ii) - The most recent 12 months of records shall be Requirements r retained on site or shall be accessible from a central location by computer or other means that provides access within 2 hours after a request. §63.774 (b)(1)(iii) - The remaining 4 years of records may be retained offsite. §63.774 (b)(1)(iv) - Records may be maintained in hard copy or computer -readable form including, but not limited to, on paper, microfilm, computer, floppy disk, magnetic tape, or microfiche. §63.774 (f) - The owner or operator of an area source not located within a UA plus offset and UC boundary must keep a record of the calculation used to determine the optimum glycol circulation rate in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. §63.775 - §63.775 (a) - The reporting provisions of subpart A of this part, that apply Reporting and those that do not apply to owners and operators of sources subject to Requirements this subpart are listed in Table 2 of this subpart. Page 17 of 59 COLORADO Air Pollution Control Division Department of Public Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 563.775 (c) - Except as provided in paragraph (c)(8), each owner or operator of an area source subject to this subpart shall submit the information listed in paragraph (c)(1) of this section. If the source is located within a UA plus offset and UC boundary, the owner or operator shall also submit the information listed in paragraphs (c)(2) through (6) of this section. If the source is not located within any UA plus offset and UC boundaries, the owner or operator shall also submit the information listed within paragraph (c)(7). §63.775 (c)(1) - The initial notifications required under §63.9(b)(2) not later than January 3, 2008. In addition to submitting your initial notification to the addressees specified under 563.9(a), you must also submit a copy of the initial notification to the EPA's Office of Air Quality Planning and Standards. Send your notification via email to Oil and Gas Sector@epa.gov or via U.S. mail or other mail delivery service to U.S. EPA, Sector Policies and Programs Division/Fuels and Incineration Group (E143-01), Attn: Oil and Gas Project Leader, Research Triangle Park, NC 27711. 563.775 (c)(7) The information listed in paragraphs (c)(1)(i) through (v) of this section. This information shall be submitted with the initial notification.' §63.775 (c)(7)(i) - Documentation of the source's location relative to the nearest UA plus offset and UC boundaries. This information shallinclude the latitude and longitude of the affected source; whether the source is located in an urban cluster with 10,000 people or more; the distance in miles to the nearest urbanized area boundary if the source is not located in an urban cluster with 10,000 people or more; and the names of the nearest urban cluster with 10,000 people or more and nearest urbanized area. §63.775 (c)(7)(ii) - Calculation of the optimum glycol circulation rate determined in accordance with §63.764(d)(2)(i). §63.775 (c)(7)(iii) - If applicable, documentation of the alternate glycol circulation rate calculated using GRI-GLYCalcTA°, Version 3.0 or higher and documentation stating why the TEG dehydration unit must operate using the alternate glycol circulation rate. §63.775 (c)(7)(iv) - The name of the manufacturer and the model number of the glycol circulation pump(s) in operation. Page 18 of 59 COLORADO Air Pollution Control Division Department of Public Health & Envirerunent Dedicated to protecting and improving the health and environment of the people of Colorado 563.775 (c)(7)(v) - Statement by a responsible official, with that official's name, title, and signature, certifying that the facility will always operate the glycol dehydration unit using the optimum circulation rate determined in accordance with §63.764(d)(2)(i) or §63.764(d)(2)(ii), as applicable. 563.775 (f) - Notification of process change. Whenever a process change is made, or a change in any of the information submitted in the Notification of Compliance Status Report, the owner or operator shall submit a report within 180 days after the process change is made or as a part of the next Periodic Report as required under paragraph (e) of this section, whichever is sooner. The report shall include: §63.775 (f)(1) - A brief description of the process change; §63.775 (f)(2) - A description of any modification to standard procedures or quality assurance procedures References from Table 2 to Subpart HH of Part 63 General Provisions Reference Applicable to subpart HH Explanation §63.9(h)(1) through (h)(3) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit notifications of compliance status. §63.10(d)(2) Yes Area sources located outside UA plus offset and UC boundaries do not have to submit performance test reports. §63.10(e)(1) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit reports. §63.10(e)(2) Yes Area sources located outside UA plus offset and UC boundaries are not required to submit reports. §63.10(e)(3)(i) Yes Subpart HH requires major sources to submit Periodic Reports semi- annually. Area sources are required to submit Periodic Reports annually. Area sources located outside UA plus offset and UC boundaries are not required to submit reports. Page 19 of 59 COLORADO Air Pollution Control Division Department of Public Health Er Environment Dedicated to protecting and improving the health and environment of the people of Colorado 38. Points 005 &t 010: The glycol dehydration units at this facility are subject to the National Emissions Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities, Subpart HH. If actual average emissions of benzene from the glycol dehydration unit process vent to atmosphere are less than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart, the glycol dehydration units 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 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)(11) - The actual average emissions of benzene from glycol dehydration unit process vent to the atmosphere are less than megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart. (e)(1)(i) the 0.90 §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration §63.772(b) - Determination of glycol dehydration unit flowrate or benzene emissions. The procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas flowrate or benzene emissions to meet the criteria for an exemption from control requirements under §63.764(e)(1). §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 Page 20 of 59 COLORADO Air Pollution Control Division Department of Public Health 8 Environment Dedicated to protecting and improving the health and environment of the people of Colorado 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 (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 §63.774 - (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit. Recordkeeping Requirements §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). Turbine (Point 008): 39. Point 008: This source is subject to the Particulate Matter and Sulfur Dioxide Emission Regulations of Regulation Number 1 including, but not limited to, the following (Regulation Number 1, Section III A 1 a VI B )• No owner or operator shall cause or permit tobe emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section III.A.1.): (i) For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 500x106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)-0.26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. b. Sources of sulfur dioxide shall not emit sulfur dioxide in excess of the following combustion turbine limitations. (Heat input rates shall be the manufacturer's guaranteed maximum heat input rates). (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. (Regulation 1, Section VI.B.4.c.(i).) 40. Point 008: This source is subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation Number 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 (Regulation Number 6, Part B, Section II.C.): Page 21 of 59 COLORADO Air Pollution Control Division Department of Public Health 6 Environment Dedicated to protecting and improving the health and environment of the people of Colorado (1) 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)-o.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) Greater than 20 percent opacity. b. Standard for Sulfur Dioxide - On and after the date on which the required performance test is competed, 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 (Regulation Number 6, Part B, Section H.D, ): (i) Sources with a heat input of less than 250 million Btu per hour: 08 lbs. 5O2/million Btu. 41. Point 008: The combustion turbine is subject to the New Source Performance Standards requirements of Regulation Number 6, Part A, Subpart KKKK, Standards of Performance for Stationary Combustion Turbines including, but not limited to, the following. 40 CFR, Part 60, Subpart A - General Provisions §60.4320 - Nitrogen Oxide Emissions Limits o §60.4320 (a) - NOx emissions shall not exceed 25 ppm at 15% O2 or 1.2 lb/MW-hr; §6O.4330' - Sulfur Dioxide Emissions Limits o §60.4330 (a)(1) - SO2 emissions shall not exceed 0.9 lb/MW-hr gross output; or o §60.4330 (a)(2) - Operator shall not burn any fuel that contains total potential sulfur emissions in excess of 0.060 lb S02/MMBtu heat input. • §60.4333 - General Requirements o §60.4333 (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 §60.4340 (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 Page 22 of 59 COLORADO Air Pollution Control Division Department of Pubic Health 5 Environment Dedicated to protecting and improving the health and environment of the people of Colorado exceed 75 percent of the NOx emission limit for the turbine, you must resume annual performance tests. • §60.4365 (or §§60.4360 and 60.4370) - SO2 Monitoring o The operator shall comply with §60.4365 or with both 5§60.4360 and 60.4370 to demonstrate compliance with SO2 emissions limits. • §60.4375 - Reporting o §60.4375 (b) - For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test. • §§60.4400 and 60.4415 - Performance Tests o Annual tests must be conducted in accordance with 560.4400(a) and (b). 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. OPERATING a MAINTENANCE REQUIREMENTS 42. Points 001-005, 007 a 010: Upon startup of these points, the owner or operator shall follow the most recent operating and maintenance (OEtM) 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 the OEtM plan are subject to Division approval prior to implementation. (Regulation Number 3, Part B, Section III.G.7.) 43. Point 008: At all times during normal operation, the owner or operator shall operate the turbine in SoLoNOx mode. On a daily basis, the owner or operator shall monitor and record the status of the SoLoNOx 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. COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 44. Point 005 a 010: The owner/operator shall complete an initial site specific extended gas analysis ("Analysis") of the assist gas and pilot light fuel routed to this enclosed combustor. The initial sample shall be analyzed for stream composition including VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 2,2,4-trimethylpentane, and methanol content using EPA approved methods. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/MMSCF) using Division approved methods. Results of the Analysis shall be submitted to the Division as part of the self - certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the Page 23 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 45. Point 007: A source initial compliance test shall be conducted to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emission limits in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Regulation Number 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Volatile Organic Compounds using EPA approved methods. 46. Point 008: This turbine is subject to the initial testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 47. Point 008: A source initial compliance test shall be conducted on the combustion turbine to measure the emission rate(s) for Process 01 - Steady-state 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 (Regulation Number 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. This test may be conducted concurrently with the initial testing required by 40 C.F.R. Part 60, Subpart KKKK. 48. Point 008: The owner or operator shall complete the initial sampling for net heating value of the fuel used in the turbine as required by this permit and submit the results to the Division as part of the self -certification process to demonstrate compliance with emissions limits. (Regulation Number 3, Part B, Section III.E.) 49. Point 009: The owner or operator shall complete an initial site specific extended gas analysis ("Analysis") within one hundred and eighty days (180) after commencement of operation or issuance of this permit, whichever comes later, of the natural gas vented during turbine compressor blowdowns in order to verify the VOC, benzene, toluene, ethylbenzene, xylene, n - Hexane, 2,2,4-trimethylpentane content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis shall be submitted to the Division as part of the self - Page 24 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 50. Point 010: The owner or operator shall complete the initial extended wet gas analysis prior to the inlet of the TEG dehydration unit within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit. The wet gas analysis shall be analyzed for total VOC, benzene, toluene, ethylbenzene, xylene, n -Hexane, 2,2,4-trimethylpentane and methanol content. The owner or operator shall use this analysis to calculate actual emissions, as prescribed in the Emission Limitation and Records section of this permit, to verify initial compliance with the emission limits. The owner or operator shall submit the analysis and the emission calculation results to the Division as part of the self -certification process. (Regulation Number 3, Part B, Section III.E.) 51. Point 011: The owner or operator shall complete an initial site specific extended gas analysis ("Analysis') within one hundred and eighty days (180) after commencement of operation or issuance of this permit, whichever comes later, of the inlet gas vented during pig receiver blowdown events in order to verify the VOC, benzene, toluene, ethylbenzene, xylene, n - Hexane, 2,2,4-trimethylpentane content (weight fraction) of this emission stream. Results of the Analysis shall be used to, calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis shall be submitted to the Division as part of the self - certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 52. Point 011: The owner or operator shall complete an initial site specific extended gas analysis ("Analysis") within one hundred and eighty days (180) after commencement o operation or issuance of this permit, whichever comes later, of the outlet dry gas vented during pig launcher blowdown events in order to verify the VOC, benzene, toluene, ethylbenzene, xylene, n - Hexane, 2,2,4-trimethylpentane content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis shall be submitted to the Division as part of the self - certification and must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall Page 25 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). Periodic Testing Requirements 53. Points 001-004 Et 007: Each engine is subject to the periodic testing requirements as specified in the operating and maintenance (OEM) plan as approved by the Division. Revisions to your O&M plan are subject to Division approval. Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment A. 54. Point 005 Et 010: The owner or operator shall complete an extended wet gas analysis prior to the inlet of each TEG dehydration unit on an annual basis. The wet gas analysis shall be analyzed for total VOC, benzene, toluene, ethylbenzene, xylene, n -Hexane, 2,2,4- trimethylpentane and methanol content. 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. 55. Point 005 Et 010: On an annual basis, the owner/operator shall complete a site specific extended gas analysis (''Analysis") of the assist gas and pilot light fuel routed to this enclosed combustor. Each sample shall be analyzed for stream composition including VOC content using EPA approved methods. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/MMSCF) using Division approved methods. Results of the Analysis must demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 56. Point 008: The turbine is subject to the periodic testing requirements of 40 C.F.R. Part 60, Subpart KKKK, as referenced in this permit. 57. Point 008: Replacements of this unit completed as Alternative Operating Scenarios may be subject to additional testing requirements as specified in Attachment B. 58. Point 008: The owner or operator shall conduct, at a minimum, quarterly portable analyzer monitoring of the turbine exhaust outlet emissions of nitrogen oxides (NO,) and carbon monoxide (CO) to monitor compliance with the emissions limits for Process 01 - Steady-state Turbine emissions. The source may perform a stack test per the following condition 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. 59. Point 008: The owner or operator shall measure the emission rate(s) from the turbine for Process 01 - Steady-state Turbine Emissions for the pollutants listed below at least once every Page 26 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 12 months 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 (Regulation Number 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods Carbon Monoxide using EPA approved methods. 60. Point 008: The net heating value of the fuel used in the turbine 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. 61. Point 009: On an annual basis, the owner or operator shall complete a site specific extended gas analysis ("Analysis") of the natural gas vented during turbine compressor blowdowns in order to verify the VOC, benzene, toluene, ethylbenzene, xylene, n -Hexane, 2,2,4-trimethylpentane content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis must be used to demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors- submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 62. Point 011: On an annual basis, the owner or operator shall complete a site specific extended gas analysis ("Analysis") of the inlet gas vented during pig receiver blowdown events in order to verify the VOC, benzene, toluene, ethylbenzene, xylene, n -Hexane, 2,2,4-trimethylpentane content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis must be used to demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within Page 27 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). 63. Point 011: On an annual basis, the owner or operator shall complete a site specific extended gas analysis ("Analysis") of the outlet dry gas vented during pig launcher blowdown events in order to verify the VOC, benzene, toluene, ethylbenzene, xylene, n -Hexane, 2,2,4- trimethylpentane content (weight fraction) of this emission stream. Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants referenced in this permit (in units of lb/blowdown event) using Division approved methods. Results of the Analysis must be used to demonstrate the emissions factors established through the Analysis are less than or equal to, the emissions factors submitted with the permit application and established herein in the "Notes to Permit Holder" for this emissions point. If any site specific emissions factor developed through this Analysis is greater than the emissions factors submitted with the permit application and established in the "Notes to Permit Holder" the operator shall submit to the Division within 60 days, or in a timeframe as agreed to by the Division, a request for permit modification to address this/these inaccuracy(ies). ALTERNATE OPERATING SCENARIOS 64. Point 005 Et 010: The electric glycol pump may be, replaced with another electric glycol pump in accordance with the requirements of Regulation Number 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. 65. Point 005 a 010: 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. 66. Point 005 a 010: 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 67. All previous versions of this permit are cancelled upon issuance of this permit. 68. This permit replaces the following permits and/or points, which are cancelled upon startup of the natural gas fired turbine covered under point 008 in this permit. The owner or operator must submit a cancellation notice for the following equipment with the Notice of Startup for the natural gas fired turbine covered under point 008 in this permit. Existing Permit Number Existing Emission Point New Emission Point 11WE1475 123/9008/002 Operator must cancel and permanently remove this engine from service upon startup of natural gas fired turbine covered under point 008. Page 28 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 11WE1475 123/9008/003 Operator must cancel and permanently remove this engine from service upon startup of natural gas fired turbine covered under point 008. 69. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Regulation Number 3, Part A, Section II.C.) • 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 N0,t 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 001-004 £t 007: Within 14 calendar days of commencing operation of a permanent replacement engine 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 engine, the appropriate APEN filing fee and a cover letter explaining that the permittee is exercising an alternative -operating scenario and is installing a permanent replacement engine. • Point 008: Within 14 calendar days of commencing operation of a permanent replacement turbine under the alternative operating scenario outlined in this permit as Page 29 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Attachment B. 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. 70. This source is subject to the provisions of Regulation Number 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The application for the Operating Permit is due within one year of the earliest commencement of operation of any piece of equipment covered by this permit. 71. The requirements of Colorado Regulation Number 3, Part D shall apply at such time that any stationary source or modification becomes a major stationary source or 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, (Regulation Number 3, Part D, With respect to this Condition, Part D requirements may apply to future modifications if emission limits are modified to equal or exceed the following threshold levels: Facility Equipment ID AIRS Point Equipment Description Emissions - tons per year Pollutant Threshold (tPY) Current Permit Limit (tPY) D-1 005 64 MMSCFD TEG Dehydrator VOC 100 24.4 TURB-1 008 Solar Titan 250-31900S Turbine 1.9 TURB-BD 009 Turbine Compressor Blowdowns 4.9 D-2 010 231 MMSCFD TEG Dehydrator 19.7 PIG 011 Pig Launcher and Receiver Blowdowns 7.4 Page 30 of 59 COLORADO Air Pollution Control Division Department of Public Health ft Environment Dedicated to protecting and improving the health and environment of the people of Colorado PW-1 and PW-2* 012 Produced Water Storage Vessels 8.2 * APEN Exempt Sources 3.6 Notes: • The produced water storage vessels (permit exempt source) and APEN exempt sources do not have permit limits. However, the PTE of these sources is still considered in the project increase when evaluating PSD and NANSR. • Fugitives are not included in this evaluation because the facility is not a listed source. 72. Points 001-004 £t 007: MACT Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines requirements shallapply to this source at any such time that this source becomes major 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. (Regulation Number 8, Part E) 73. Point 005 Et 010: 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 source at any such time that this 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. (Regulation Number 8, Part E) 74. Point 008: 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. (Regulation Number 8, Part E) GENERAL TERMS AND CONDITIONS 75. 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. 76. 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 Page 31 of 59 COLORADO Air Pollution Control Division Department of Public Health ft Environment Dedicated to protecting and improving the health and environment of the people of Colorado 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. 77. 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. 78. 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. 79. Each and every condition of this permit is a material part hereof and is not severable. Any challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked at any time prior to self -certification and final authorization by the Air Pollution Control Division (APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission (AQCC), including failure to meet any express term or condition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the owner or operator, or the Division revokes a permit, the owner or operator of a source may request a hearing before the AQCC for review of the Division's action. 80. 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. 81. 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: Harrison Slaughter Permit Engineer Permit History Issuance Date Description Issuance 1 November 21, 2011 Issued to DCP Midstream, LP Page 32 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Issuance 2 August 14, 2014 Issued to DCP Midstream, LP. Increase in VOC emission limit for Point 006. Change the control device for Point 005 to an enclosed combustor. Issued permit as final. Source at a synthetic minor facility. Issuance 3 January 22, 2018 Issued to DCP Operating Company, LP Point 005: Modification to increase permitted throughput from 18,250 MMscf/year to 23,360 MMscf/year. Add 5% annual VRU downtime during which flash tank emissions will be routed to the ECD. Add 3% annual downtime for ECD controlling the still vent. Point 007: Addition of new compression engine. Cancel point 006. Cancellation request received 05/01/15. Issuance 4 This Issuance Issued to DCP Operating Company, LP • Point 005: Modify to include VOC emissions associated with combustion of assist gas. Update process limits and emission limits. • Add one (1) Solar Titan 250-31900S natural gas fired compression turbine to the facility (point 008). • Add turbine compressor blowdowns (point 009) to the permit. • Add one (1) 231 MMscf/day TEG dehydration unit (point 010) • Add pig receiver and pig launcher blowdowns (point 011) to the permit. Page 33 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Notes to Permit Holder at the time of this permit issuance: 1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of receipt of the invoice. Failure to pay the invoice will result in revocation of this permit. (Regulation Number 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 11, 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 11.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 Emissions (lb/yr) Controlled Emissions (lb/yr) Formaldehyde 50000 1,623 390 001 Methanol 67561 355 178 Acetaldehyde 75070 324 162 Acrolein 107028 305 153 Benzene 71432 184 92 1,3 -Butadiene 106990 77 39 Toluene 108883 65 33 Xylenes 1330207 23 12 Ethylbenzene 100414 3 2 002 Formaldehyde 50000 1,623 390 Methanol 67561 355 178 Acetaldehyde 75070 324 162 Acrolein 107028 305 153 Page 34 of 59 COLORADO Air Pollution Control Division Department of Public Health S Environment Dedicated to protecting and improving the health and environment of the people of Colorado Benzene 71432 184 92 1,3 -Butadiene 106990 77 39 Toluene 108883 65 33 Xylenes 1330207 23 12 Ethylbenzene 100414 3 2 003 Formaldehyde 50000 1,623 390 Methanol 67561 355 178 Acetaldehyde 75070 324 162 Acrolein 107028 305 153 Benzene 71432 184 92 1,3 -Butadiene 106990 77 3 Toluene 108883 65 33 Xylenes 1330207 23 12 Ethylbenzene 100414 3 2 004 Formaldehyde 50000 1,623 390 Methanol 67561 178 Acetaldehyde 75070 162 Acrolein 107028 305 153 Benzene 71432 184 92 1,3 -Butadiene 106990' 77 39 Toluene 108883 65 33 Xylenes 1330207 23 12 Ethylbenzene 100414 3 2 005 Benzene 71432 121,174 9,261 Toluene 108883 95,493 7,365 Ethylbenzene 100414 1,452 113 Xylenes 1330207 22,803 1,777 n -Hexane 110543 21,808 998 2,2,4- Trimethylpentane 540841 46 3 Methanol 67561 174 8 007 Formaldehyde 50000 1,623 390 Page 35 of 59 COLORADO Air Pollution Control Division Department of Public Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Methanol 67561 355 178 Acetaldehyde 75070 324 162 Acrolein 107028 305 153 Benzene 71432 184 92 1,3 -Butadiene 106990 77 39 Toluene 108883 65 33 Xylenes 1330207 23 12 Ethylbenzene 100414 3 2 008 Formaldehyde 50000 1,090 1,090 Acetaldehyde 75070 62 62 Acrolein 107028 10 10 Benzene 71432 19 19 1,3 -Butadiene 106990 1 1 Ethylbenzene 100414 50 50 Toluene 108883 200 200 Xylene 1330207 99 99 009 Benzene 71432 14 14 Toluene 108883 11 11 Ethylbenzene 100414 1 1 Xylenes 1330207 4 4 n -Hexane 110543 74 74 010 Benzene 71432 121,001 5,856 Toluene 108883 115,833 5,663 Ethylbenzene 100414 5,104 252 Xylenes 1330207 66,308 3,284 n -Hexane 110543 17,655 483 Methanol 67561 115 4 011 Benzene 71432 21 21 Toluene 108883 16 16 Ethylbenzene 100414 1 1 Xylenes 1330207 6 6 n -Hexane 110543 111 111 Page 36 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Note: All non -criteria reportable pollutants in the table above with uncontrolled emission rates above 250 pounds per year (lb/yr) are reportable and may result in annual emission fees based on the most recent Air Pollution Emission Notice. 5) The emission levels contained in this permit are based on the following emission factors: Points 001 through 004: CAS Pollutant Emission Factors lb/MMBtu - Uncontrolled g/bhp-hr Emission Controlled lb/MMBtu Factors - g/bhp-hr N0x 3.6669 13.1000 0.1400 0.5000 CO 3.2750 11.7000 0.2799 1.0000 V0C 0.4199 1.5000 0.1959 0.7000 PM2.5 1.94x10-2 6.93x10"2 1.94x10"2 6.93x10-2 PMK() 1.94x10"2 6.93x10-2 1.94x10-2 6.93x10-2 50000 Formaldehyde 0.0140 0.0500 0.0034 0.0120 67561 Methanol 0.0031 0.0109 0.0015 0.0055 75070 Acetaldehyde 0.0028 0.0100 0.0014 " 0.0050 107028 Acrolein 0.0026 0.0094 0.0013 0.0047 71432 Benzene 0.0016 0.0056 0.0008 0.0028 106990 1,3 -Butadiene 0.0007 0.0024 0.0003 0.0012 108883 Toluene 0.0006 0.0020 0.0003 0.0010 Emission factors are based on a Brake -Specific Fuel Consumption Factor of 7876 Btu/hp-hr, a site -rated horsepower value of 1680, and a fuel heat value of 900 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EF Source . Controlled EF Source NOx Manufacturer's specifications Manufacturer's specifications CO Manufacturer's specifications Manufacturer's specifications V0C Manufacturer's specifications Manufacturer's specifications PM2.5 AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 PM,() AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 50000 Formaldehyde Manufacturer's specifications Manufacturer's specifications 67561 Methanol AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 75070 Acetaldehyde AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 107028 Acrolein AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 71432 Benzene AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 106990 1,3 -Butadiene AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications 108883 Toluene AP -42; Table 3.2-3 (7/2000); Natural Gas Manufacturer's specifications Page 37 of 59 COLORADO Air Pollution Control Division Department of Pubic Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Point 005: The VOC and HAP emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Actual controlled VOC and HAP flash tank emissions are based on 100% control efficiency when emissions are routed to the VRU and 95% control efficiency when emissions are routed to the ECD during VRU downtimeThe VRU has a maximum of 5% annual downtime. To determine actual flash tank emissions during VRU downtime, the operator will multiply the lb/hr emission rates from the "Flash Tank Off Gas" stream in the GlyCalc model (based on total actual gas throughput during the month) by the total hours of VRU downtime. A 95% control efficiency is applied to this calculation based on the destruction efficiency of the ECD. Actual controlled VOC and HAP still vent emissions are based on a 95% ECD control efficiency when emissions are routed to the ECD and 0% control efficiency when emissions are routed to atmosphere during ECD downtime. The ECD has a maximum of 3% annual downtime. To determine actual still vent emissions while emissions are routed to the ECD, the operator will multiply the lb/hr emission rates from the "Uncontrolled Regenerator Emissions" stream in the GlyCalc model by the total hours of ECD operation. A 95% control efficiency is applied to this calculation based on the destruction efficiency of the ECD. To determine actual still vent emissions during ECD downtime, the operator will multiply the lb/hr emission rates from the "Uncontrolled Regenerator Emissions" stream in the GlyCalc model by the total hours of ECD downtime. A 0% control efficiency is applied to this calculation. Total actual still vent emissions are the sum of still vent emissions routed to the ECD and still vent emissions routed to atmosphere during ECD downtime. The following table summarizes the control efficiency for each scenario: Control Scenario VOC Control Efficiency Still vent emissions routed to the ECD. 95% Still vent emissions routed to atmosphere during ECD downtime 0% Flash tank emissions routed to the VRU and recycled to the plant inlet. 100% Flash tank emissions routed to the ECD during VRU downtime. 95% Methanol emissions from this source are based on a mass balance. The methanol/alcohol mole from the periodic inlet wet gas analysis is specified with the n -Hexane mole % in the GlyCalc Wet Gas input stream. Uncontrolled actual methanol emission rates are calculated by multiplying the sum of the n -hexane lb/hour rate from the "Uncontrolled Regenerator Emissions" and "Flash Tank Off Gas" streams in the GlyCalc model by the ratio of the methanol/alcohol mole % in the inlet gas to the n -Hexane mole % in the inlet gas. Actual controlled methanol emissions are calculated using the methodologies described above for VOC and HAP. lb Flash Tank n — Hexane rate, lb) + ( Still Vent n — Hexane rate, lb methanol moleo/a Uncontrolled Methanol ( hr ) _ [( �] * ( hr hr n — Hexane mole ) Optimal recirculation rate per MACT HH (63.764(d)(2)(i)) is based on the following information submitted with the application: F = 64 MMscf/d; I = 100.91 lb/MMscf; and O = 6.7 lb/MMscf. Page 38 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Combustion Emissions: Total actual NOx and CO emissions are based on the sum of the emissions for the still vent and flash tank controlled by the ECD and the combustion of ECD pilot and assist fuel. Actual volume of waste gas combusted shall be based on the monthly GlyCalc report streams described in the notes beneath each table. Actual heat content of the waste gas stream shall be calculated monthly based on the GlyCalc report streams described in the notes beneath each table. Total combustion emissions are based on the following emission factors: Still Vent Controlled by the ECD: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu Source NOx 0.068 AP -42 Chapter 13.5 Industrial Flares CO 0.31 lote: The permitted combustion emissions are based on a still vent waste gas heating value of 1_52 Btu/scf. Actual emissions are calculated based on the heat content and waste gas flow rate from the "Condenser Vent Stream" in the most recent monthly GlyCalc report and the hours per month the still vent waste gas is routed to the ECD. The heat content is calculated on a monthly basis using the composition of the "Condenser Vent Stream" in the most recent monthly GlyCalc report and the higher heating value of each component. Flash Tank Controlled by the ECD: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu Source NOx 0.068 AP -42 Chapter 13.5 Industrial Flares CO 0.31 Note: The permitted combustion emissions are based on a flash tank waste gas heating value of 1,457.5 Btu/scf. Actual emissions are calculated based on the heat content and waste gas flow rate from the "Flash Tank Off Gas Stream" in the most recent monthly GlyCalc report and the hours per month the flash tank waste gas is routed to the ECD. The heat content is calculated on a monthly basis using the composition of the "Flash Tank Off Gas Stream" in the most recent monthly GlyCalc report and the higher heating value of each component. Combustion of ECD Pilot/Assist Fuel: CAS # Weight Fraction of Gas (%) Pollutant Emission Factors lb/MMscf Source --- NOx 73.81 AP -42 Chapter 13.5 Industrial Flares --- CO 336.5 5.49 VOC 132.94 Gas Analysis 71432 4.84x10-3 Benzene 1.17x10-1 108883 2.6x10-3 Toluene 6.29x10-2 Note: The VOC and HAP emissions were ca culated using a representative fuel gas samp e obtained on September 12, 2018 and an enclosed combustor control efficiency of 95%. The NOx and CO emission factors Page 39 of 59 COLORADO Air Pollution Control Division Department of Public Health t Environment Dedicated to protecting and improving the health and environment of the people of Colorado from AP -42 Chapter 13.5 (0.068 lb/MMBtu and 0.31 lb/MMBtu respectively) were converted to units of lb/MMscf using a heating value of 1,085.5 Btu/scf. The pilot fuel and assist gas flow rates are constant. Actual emissions are calculated by multiplying the emissions factors in the table above by the total fuel flow of the pilot gas and assist gas routed to the ECD. Permitted emissions are based on a constant pilot fuel flow rate of 50 scf/hr and a constant assist fuel flow rate of 3,000 scf/hr. Total V0C and HAP emissions for this source are based on the sum of emissions calculated using the monthly GlyCalc model and the combustion of ECD pilot and assist fuel. Point 007: CAS Pollutant Emission Uncontrolled lb/MMBtu Factors - g/bhp-hr Emission Controlled lb/MMBtu Factors - g/bhp-hr N0x 3.67 13.10 0.42 1.50 CO 3.28 11.70 0.42 1.50 V0C 0.42 1.50 0.21 0.75 PM2.s' 1.94x10 2 6.93x10 2 1.94x102 6. paw 6.93x10-2 I.94x10 2 6.93x10 2 50000 Formaldehyde 1.40x10-2 0.05 3.36x10 3 1'.20x10"2 67561 Methanol 3.06x10"3 1.09x10 2 1.53x10 3 5.47x10 3 75070 Acetaldehyde 2.79x10 3 9.97x10 3 1.40x10"3 4.98x103 107028 Acrolein 2.63x10 3 9.40x10-3 1.32x10 3 70x1093x1'0`2 4. 3 71432 Benzene 1.58x10`3 5.65x10 3 7.90x10-4 2.82x10 3 106990 1,3 -Butadiene 6.63x10-4 2.37x10-3 3.32x10-4 1.18x10"3 108883 Toluene 5.58x10"4 1.99x10-3 2.79x10"4 9.97x10-4 1330207, Xylenes 1.95x10-4 ` 6.97x10-4 9.75x10-5 !3.48x10-4 100414 Ethylbenzene 2.48x10"5 8.86x10"5 1.24x10-5 4.43x10"5 Emission factors are based on a Brake -Specific Fuel Consumption Factor of 7,876 Btu/hp-hr,_a site -rated horsepower value of 1680, and a fuel heat value of 900 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source N0x Manufacturer Manufacturer CO Manufacturer Manufacturer V0C Manufacturer Manufacturer PM2.5 AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 PMio AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 50000 Formaldehyde Manufacturer Manufacturer 67561 Methanol AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 75070 Acetaldehyde AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 107028 Acrolein AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 71432 Benzene AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 106990 1,3 -Butadiene AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 108883 Toluene AP -42 Chapter 3 Table 3.2-3 AP -42 Chapter 3 Table 3.2-3 Page 40 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Point 008: Process O1: Turbine emissions during steady state operations: CAS Pollutant Emission Factors - Uncontrolled Source lb/MMBtu PPM at 15% 02 PM2.5 6.6x10-3 --- AP -42 Chapter 3 Table 3.1-2a PMio 6.6x10-3 --- AP -42 Chapter 3 Table 3.1-2a SOX 3.4x10-3 --- AP -42 Chapter 3 Table 3.1-2a NOx 4.39x10"2 11 Manufacturer CO 6.08x10-2 25 Manufacturer VOC 2.1x10-3 --- AP -42 Chapter 3 Table 3.1-2a 50000 Formaldehyde 7.1x10"4 --- AP -42 Chapter 3 Table 3.1-3 Note: Emission factors are based on a heat input rate of 175.21 MMBtu/hr, a lower fuel heat value of 986.8 Btu/scf and 8,760 hours of operation a year. Actual emissions shall be calculated by multiplying the lb/MMBtu emission factors in the table above by the actual net (lower) heat value from the most recent quarterly heat content sample and the most recent monthly metered fuel gas volume. Process 02: Turbine start-up emissions CAS Pollutant Emission Factors - Uncontrolled lb/event Source NOx 2.0 Manufacturer Manufacturer Manufacturer C0 32.0 VOC 2.0 Note: The manufacturer provided emission factors for turbine start-ups are based on 10 minute start-up events. Actual emissions shall be calculated by multiplying the emission factor in the table above by the recorded number of turbine start-up events. Process 03: Turbine shutdown emissions CAS Pollutant Emission Factors - Uncontrolled Source lb/event NOx 2.0 Manufacturer CO 20.0 Manufacturer VOC 2.0 Manufacturer Page 41 of 59 COLORADO Air Pollution Control Division Department of Pubic Health b Environment Dedicated to protecting and improving the health and environment of the people of Colorado Note: The manufacturer provided emission factors for turbine shutdowns are based on 10 minute shutdown events. Actual emissions shall be calculated by multiplying the emission factor in the table above by the recorded number of turbine shutdown events. Point 009: CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.12 VOC 407.69 Mass Balance Note: The emission factors for turbine compressor blowdown events are based on a compressor volume of 27,539 scf, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10 - Displacement Equation (10.4-3). Actual emissions are calculated by _multiplying the emission factor in the table above by the recorded number of turbine compressor blowdown events. Point 010: The VOC and HAP emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. Actual controlled VOC. and HAP flash tank emissions are based on 100% control efficiency when emissions are routed to the VRU and 95% control efficiency when emissions are ' routed to the ECD during VRU downtime. The VRU has a maximum of 5% annual downtime. To determine actual flash tank emissions during VRU downtime, the operator will multiply the lb/hr emissionrates from the "Flash Tank Off Gas" stream in the GlyCalc model (based on total actual gas throughput during the month) by the total hours of VRU downtime. A 95% control efficiency is applied to this calculation based on the destruction efficiency of the ECD. Actual controlled VOC and HAP still vent emissions are based on a 95% ECD control efficiency. To determine actual still vent emissions, the operator will multiply the lb/hr emission rates from the "Uncontrolled Regenerator Emissions" stream in the GlyCalc model by the total hours of operation. A 95% control efficiency is applied to this calculation based on the destruction efficiency of the ECD. The following table summarizes the control efficiency for each scenario: Control Scenario VOC Control Efficiency Still vent emissions routed to the ECD. 95% Flash tank emissions routed to the VRU and recycled to the plant inlet. 100% Flash tank emissions routed to the ECD during VRU downtime. 95% Methanol emissions from this source are based on a mass balance. The methanol/alcohol mole % from the periodic inlet wet gas analysis is specified with the n -Hexane mole % in the GlyCalc Wet Gas input stream. Uncontrolled actual methanol emission rates are calculated by multiplying the sum of the n -hexane lb/hour rate from the "Uncontrolled Regenerator Emissions" and "Flash Tank Page 42 of 59 COLORADO Air Pollution Control Division Department of Public Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Off Gas" streams in the GlyCalc model by the ratio of the methanol/alcohol mole % in the inlet gas to the n -Hexane mole % in the inlet gas. Actual controlled methanol emissions are calculated using the methodologies described above for VOC and HAP. lb Flash Tank n — Hexane rate, lb Still Vent n — Hexane rate, lb methanol mole% Uncontrolled Methanol ( ) = [( } + ( }] ( ) hr hr hr n — Hexane mole Optimal recirculation rate per MACT HH (63.764(d)(2)(i)) is based on the following information submitted with the application: F = 231 MMscf/d; I = 89.52 lb/MMscf; and O = 5.0 lb/MMscf. Combustion Emissions: Total actual NOx and CO emissions are based on the sum of the emissions for the still vent and flash tank controlled by the ECD and the combustion of ECD pilot and assist fuel. Actual volume of waste gas combusted shall be based on the monthly GlyCalc report streams described in the notes beneath each table. Actual heat content of the waste gas stream shall be calculated monthly based on the GlyCalc report streams described in the notes beneath each table. Total combustion emissions are based on the following emission factors: Still Vent Controlled by the ECD: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu NOx 0.068 CO 0.31 AP -42 Chapter 13.5 Industrial Flares Note: The permitted combustion emissions are based on a still vent waste gas heating value of 1,450 Btu/scf. Actual emissions are calculated based on the heat content and waste gas flow rate from the "Condenser Vent Stream" in the most recent monthly GlyCalc report and the hours, per month the still vent waste gas is routed to the ECD. The heat content is calculated, on a monthly basis using the composition of the "Condenser Vent Stream" in the most recent monthly GlyCalc report and the higher heating value of each component. Flash Tank Controlled by the ECD: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu Source NOx 0.068 AP -42 Chapter 13.5 Industrial Flares CO 0.31 Note: The permitted combustion emissions are based on a flash tank waste gas heating value of 1,456 Btu/scf. Actual emissions are calculated based on the heat content and waste gas flow rate from the "Flash Tank Off Gas Stream" in the most recent monthly GlyCalc report and the hours per month the flash tank waste gas is routed to the ECD. The heat content is calculated on a monthly basis using the composition of the "Flash Tank Off Gas Stream" in the most recent monthly GlyCalc report and the higher heating value of each component. Page 43 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Combustion of ECD Pilot/Assist Fuel: CAS # Weight Fraction of Gas (%) Pollutant Emission Factors lb/MMscf Source --- NOx 73.81 AP -42 Chapter 13.5 Industrial Flares --- CO 336.5 5.49 VOC 132.94 Gas Analysis 71432 4.84x10-3 Benzene 1.17x10"1 108883 2.6x10-3 Toluene 6.29x10-2 Note: The VOC and HAP emissions were calculated using a representative fuel gas samp e obtained on September 12, 2018 and an enclosed combustor control efficiency of 95%. The NOx and CO emission factors from AP -42 Chapter 13.5 (0.068 lb/MMBtu and 0.31 lb/MMBtu respectively) were converted to units of lb/MMscf using a heating value of 1,085.5 Btu/scf. The pilot fuel and assist gas flow rates are constant. Actual emissions are calculated by multiplying the emissions factors in the table above by the total fuel flow of the pilot gas and assist gas routed to the ECD. Permitted emissions are based on a constant pilot fuel flow rate of 65 scf/hr and a constant assist fuel flow rate of 2,000 scf/hr. Total VOC and HAP emissions are based on the sum of emissions calculated using the monthly GlyCalc model and the combustion of ECD pilot and assist fuel Point 011: Total; actual VOC emissions are based on the sum of emissions calculated for processes 01-07. Process 01: Blowdown of 10" low pressureig receiver p CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.12 VOC 7.81 Mass Balance Note: The emission factors for 10" low pressure nig receiver hlowdown events are hased on a volume of 19.926 scf, an absolute pressure of 412.2 psia, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the ideal gas law. The ideal gas law is based on the following parameters: (i) Temperature: 550° R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/ ° R*lbmol. Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of 10" low pressure pig receiver blowdown events. Process 02: Blowdown of 20" low pressure pig receivers CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.12 VOC 26.99 Mass Balance Page 44 of 59 COLORADO Air Pollution Control Division Department of Public Health ti Environment Dedicated to protecting and improving the health and environment of the people of Colorado Note: The emission factors for 20" low pressure pig receiver blowdown events are based on a volume of 68.839 scf, an absolute pressure of 412.2 psia, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the ideal gas law. The ideal gas law is based on the following parameters: (i) Temperature: 550°R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/ ° R*lbmol. Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of 20" low pressure pig receiver blowdown events. Process 03: Blowdown of 12" low pressure pig receivers CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.12 V0C 10.12 Mass Balance Note: The emission factors for 12" tow pressure pig receiver blowdown events are based on a volume of 25.815 scf, an absolute pressure'. of 412.2 psia, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the ideal gas law.The ideal gas law is based on the following parameters: (i) Temperature: 550°R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/ ° R*lbmol. Actual emissions, are calculated by multiplying the emission factor in the table above by the recorded number of 12" low pressure pig receiver blowdown events. Process 04: Blowdown of 6" high pressure fuel, pig receiver CAS Weight % of Gas VOC Emission Factors - Uncontrolled lb/blowdown event 25.12 3.95 Mass Balance Note The emission factors for 6" high pressure pig receiver blowdown events are based on a volume of 3.576 scf, an absolute pressure of 1,162.2 psia, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the ideal gas law. The ideal gas law is based on the following parameters: (i) Temperature: 550° R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/ ° R*lbmol. Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of 6" high pressure pig receiver blowdown events. Process 05: Blowdown of 12" high pressure pig receivers CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.12 V0C 28.54 Mass Balance Note: The emission factors for 12" high pressure pig receiver blowdown events are based on a volume of 25.815 scf, an absolute pressure of 1,162.2 psia, a representative inlet gas analysis obtained from the Libsack Compressor Station inlet on 04/17/18 and the ideal gas law. The ideal gas law is based on the following parameters: (i) Temperature: 550°R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/ ° R*lbmol. Page 45 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of 12" high pressure pig receiver blowdown events. Process 06: Blowdown of 16" high pressure pig launcher CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.11 VOC 39.22 Mass Balance Note: The emission factors for 16" high pressure pig launcher blowdown events are based on a volume of 35.487 scf, an absolute pressure of 1,162.2 psia, a representative outlet dry gas analysis obtained from the GlyCalc simulation provided for point 010 in the application received on 05/03/19, and the ideal gas law. The ideal gas law is based on the following parameters: (i) Temperature: 550°R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/ ° R*lbmol. Actual emissions are calculated by multiplying the emission factor in the table above by therecorded number of 16" high pressure pig launcher blowdown events. Process 07: Blowdown of 20" high pressure pig launcher CAS Weight % of Gas Pollutant Emission Factors - Uncontrolled Source lb/blowdown event 25.11 VOC 76.07 Mass Balance Note: The emission factors for 20" high pressure pig launcher blowdown events are based on a volume of 68.839 scf, an absolute pressure of 1,162.2 psia, a representative outlet dry gas analysis obtained from the GlyCalc simulation provided for point 010 in the application received on 05/03/19, and the ideal gas aw. The ideal gas law is based on the following parameters: (i) Temperature: 550°R and (ii) Ideal Gas Law Constant: 10.7316 ft3*psia/°R*lbmol. Actual emissions are calculated by multiplying the emission factor in the table above by the recorded number of 20" high pressure pig launcher blowdown events. 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) Points 001-004: Each engine is subject to 40 CFR, Part 60, Subpart JJJJ—Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (See January 18, 2008 Federal Register posting - effective March 18, 2008). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available on the EPA website at: http://www.epa.gov/ttn/atw/area/fr18ia08.pdf 8) Points 001-004: Each engine is subject to 40 CFR, Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. (See Page 46 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado January 18, 2008 Federal Register posting - effective March 18, 2008). The January 18, 2008 amendments to include requirements for area sources and engines < 500 hp located at major sources have not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 8. A copy of the complete subpart is available on the EPA website at: http://www.epa.gov/ttn/atw/area/fr18ia08.pdf Additional information regarding area source standards can be found on the EPA website at: http://www.epa.gov/ttn/atw/area/arearules.html 9) Point 007: This engine is subject to 40 CFR, Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines (See August 20, 2010 Federal Register posting - effective October 19, 2010). The August 20, 2010 amendments to include requirements for existing engines located at area sources and existing engines < 500 hp located at major sources have not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 8. A copy of the complete subpart is available on the EPA website at: http://www.epa.gov/ttn/atw/rice/fr20au10.pdf Additional information regarding area source standards can be found on the EPA website at: http://www.epa.gov/ttn/atw/area/arearules.html 10) This facility is classified as follows: Applicable Requirement Status Operating Permit Major Source of: VOC and CO Synthetic Minor Source of: NOx, benzene, toluene, xylene, n - Hexane and Total HAPs. NANSR Major Source of: VOC Synthetic Minor Source of: NOx PSD Synthetic Minor Source of: CO, NOx and VOC MACT HH Major Source Requirements: Not Applicable Area Source Requirements: Applicable MACT ZZZZ Area Source Requirements NSPS JJJJ Applicable to points 001-004 MACT YYYY Not Applicable NSPS GG Not Applicable NSPS KKKK Applicable to point 008 11) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources Page 47 of 59 COLORADO Air Pollution Control Division Department of Public Health b Environment Dedicated to protecting and improving the health and environment of the people of Colorado 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 Page 48 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado ATTACHMENT A: ALTERNATIVE OPERATING SCENARIOS RECIPROCATING INTERNAL COMBUSTION ENGINES October 12, 2012 2. Alternative Operating Scenarios The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of natural gas fired reciprocating internal combustion engines has been reviewed in accordance with the requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility -Alternative Operating Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such engine replacement without applying for a revision to this permit or obtaining a new Construction Permit. 2.1 Engine Replacement The following AOS is incorporated into this permit in order to deal with an engine breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent replacement engine. "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 engine is in operation. If the engine 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. All replacement engines 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 NSPS or MACT 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 engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the replacement engine. In addition to the log, the owner or operator shall maintain a copy of all Applicability Reports required under section 2.1.2 and make them available to the Division upon request. Page 49 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 2.1.1 The owner or operator may temporarily replace an existing engine that is subject to the emission limits set forth in this permit with an engine that is of the same manufacturer, model, and horsepower or a different manufacturer, model, or horsepower as the existing engine without modifying this permit, so long as the temporary replacement engine complies with all permit limitations and other requirements applicable to the existing engine. Measurement of emissions from the temporary replacement engine shall be made as set forth in section 2.2. 2.1.2 The owner or operator may permanently replace the existing engine with another engine with the same manufacturer, model, and horsepower engines without modifying this permit so long as the permanent replacement engine complies with all permit limitations and other requirements applicable to the existing engine as well as any new applicable requirements for the replacement engine. Measurement of emissions from the permanent replacement engine and compliance with the applicable emission limitations shall be made as set forth in section 2.2. An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement engine shall be filed with the Division for the permanent replacement engine within 14 calendar days of commencing operation of the replacement engine. 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 engine, and a copy of the relevant Applicability Reports for the replacement engine. Example Applicability Reports can be found at https://www.colorado.gov/pacific/cdphe/alternate-operating-scenario-aos- reporting-forms. This submittal shall be accompanied by a certification from the Responsible Official indicating that "based on the information and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurate and complete". This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt engine or an engine 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 engine replacement. 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. Page 50 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement engine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement engine. All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's web site at: https: / /www.colorado.gov/pacific/sites/default/files/AP_Portable-Analyzer-Monitoring-Protocol. pdf Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or concentration based (ppmvd ® 15% O2) that the existing unit is currently subject to or the replacement engine 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 engine 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 engine 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 engine is taken offline. 2.3 Applicable Regulations for Permanent Engine Replacements 2.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § II.D.2 All permanent replacement engines that are located in an area that is classified as attainment/maintenance or nonattainment must apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note that both VOC and NOX are precursors for ozone. RACT shall be applied for any level of emissions of the pollutant for which the area is in attainment/maintenance or nonattainment, except as follows: In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PM10 at any level of emissions and to NOX and SO2, as precursors to PM10, if the potential to emit of NOX or SO2 exceeds 40 tons/yr. Page 51 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado For purposes of this AOS, the following shall be considered RACT for natural gas fired reciprocating internal combustion engines: VOC: The emission limitations in NSPS JJJJ CO: The emission limitations in NSPS JJJJ NOX: The emission limitations in NSPS JJJJ 5O2: Use of natural gas as fuel PM10: Use of natural gas as fuel As defined in 40 CFR Part 60 Subparts GG (S 60.331) and 40 CFR Part 72 (S 72.2), natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. 2.3.2 Control Requirements and Emission Standards: Regulation No. 7, Sections XVI. and XVII.E (State - Only conditions). Contro( Requirements: Section XVI Any permanent replacement engine located within the boundaries of an ozone nonattainment area is subject to the applicable control requirements specified in Regulation No. 7, section XVI, as specified below: Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non- selective catalyst and air fuel controller to reduce emission. Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation catalyst to reduce emissions. The above emission control equipment shall be appropriately sized for the engine and shall be operated and maintained according to manufacturer specifications. The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. Emission Standards: Section XVII.E - State -only requirements Any permanent engine that is either constructed or relocated to the state of Colorado from another state, after the date listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance practices over the entire life of the engine so that it achieves the emission standards required in the table below: Page 52 of 59 COLORADO Air Pollution Control Division Department of Public Health &Environment Dedicated to protecting and improving the health and environment of the people of Colorado Max Engine HP Construction or Relocation Date Emission Standards in G/hp-hr NOx CO VOC 100<Hp<500 January 1, 2008 January 1, 2011 2.0 1.0 4.0 2.0 1.0 0.7 500≤Hp July 1, 2007 July 1, 2010 2.0 1.0 ,4.0 2.0 1.0 0.7 The source shall submit copies of the relevant Applicability Reports required under Condition 2.1.2. 2.3.3 NSPS for stationary spark ignition internal combustion engines: 40 CFR Part 60, Subpart JJJJ A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines greater than 25 hp, 7/1 /2008 for engines less than 500 hp, 7/1/2007 for engines greater than or equal to 500 hp except for lean burn engines greater than or equal to 500 on and less than 1,350 hp, and 1/1/2008 for lean 'burn engines' greater than or equal to 500 hp and less than 1,350 hp are subject to the requirements of 40 CFR Part 60, Subpart JJJJ. An analysis of applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the NSPS is in addition to that required by this AOS. Note that the initial test required by NSPS Subpart JJJJ can'serve as the testing required by this • AOS under Condition 2.2, if,approved in advance such test ' is conduct d h' h f' d ' Condition ' 2 ante by the Division, provided that e wit in t e time frame specified in on ition 2. 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 manufacture date for purposes of determining the applicability of NSPS JJJJ requirements). • However, as of October 1, 2011 the Division has not yet adopted NSPS JJJJ. Until such time as it does, any engine subject to NSPS will be subject only under Federal law. Once the Division adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS. Under the provisions of Regulation No. 6, Part 8, § 1.8 (which is referenced in Part A), any engine relocated from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of NSPS JJJJ. 2.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ A permanent replacement engine located at either an area or major source is subject to the requirements in 40 CFR Part 63, Subpart ZZZZ. An analysis of the applicable monitoring, recordkeeping, and reporting requirements for the permanent engine replacement shall be included in the Applicability Reports required under Condition 2.1.2. Any testing required by the MACT is in addition to that required by this AOS. Note that the initial test required by the MACT can serve as the testing required by this AOS under Condition 2.2, if approved in advance by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. Page 53 of 59 COLORADO Air Pollution Control Division Department of Pubtc Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 2.4 Additional Sources The replacement of an existing engine with a new engine 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; an engine that is being installed as an entirely new emission point and not as part of an AOS-approved replacement of an existing onsite engine has to go through the appropriate Construction/Operating permitting process prior to installation. Page 54 of 59 COLORADO Air Pollution Control Division Department of Pubzc Health &Environment Dedicated to protecting and improving the health and environment of the people of Colorado ATTACHMENT B: ALTERNATIVE OPERATING SCENARIOS TURBINES WITHOUT CONTINUOUS EMISSIONS MONITORING August 16, 2011 1. Routine Turbine Component Replacements The following physical or operational changes to the turbines in this permit are not considered a modification for purposes of NSPS GG, major stationary source NSR/PSD, or Regulation No. 3, Part B. Note that the component replacement provisions apply ONLY to those turbines subject to NSPS GG. Neither pre-GG turbines nor post GG turbines (i.e. KKKK turbines) can use those provisions. 1) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seats, 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, Page 55 of 59 COLORADO Air Pollution Control Division Department of Public Heath & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Major Stationary Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit incorporates and shall be considered a Construction Permit for any turbine or turbine component replacement performed in accordance with this AOS, and the owner or operator shall be allowed to perform such turbine or turbine component replacement without applying for a revision to this permit or obtaining a new Construction Permit. 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. Page 56 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado 2.1.2 The owner or operator may permanently replace the existing turbine that is covered by this permit with a turbine that is the exact same make and model as the existing turbine without modifying this permit so long as the permanent replacement turbine complies with the emission limitations and other requirements applicable to the original turbine as well as any new applicable requirements for the replacement turbine. Measurement of emissions from the temporary replacement turbine shall be made as set forth in section 2.2. 2.1.3 An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and horsepower of the permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar days of commencing operation of the replacement turbine. The APEN shall be accompanied by the appropriate APEN filing fee, a cover letter explaining that the owner or operator is exercising an alternative operating scenario and is installing a permanent replacement turbine. This AOS cannot be used for permanent turbine replacement of a grandfathered or permit exempt turbine or a turbine that is not subject to emission limits. The owner or operator shall agree to pay fees based on the normal permit processing rate for review of information submitted to the Division in regard to any permanent turbine replacement. 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.44. 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. Page 57 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado The owner or operator shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust from the replacement turbine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the replacement turbine. All portable analyzer testing required by this permit shall be conducted using the most current version of the Division's Portable Analyzer Monitoring Protocol as found on the Division's website. Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year (8760), whichever applies. For comparison with a short-term limit that is either input based (lb/MMBtu), output based (g/hp- hr) or concentration based (ppmvd ® 15% O2) that the existing unit is currently subject to or the replacement turbine will be subject to, the results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer Monitoring Protocol document. If the portable analyzer results indicate compliance with both the NOX and CO emission limitations, in the absence of credible evidence to the contrary, the source may certify that the turbine is in compliance with both the NOX and CO emission limitations for the relevant time period. Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable analyzer results fail to demonstrate compliance with either the NOX or CO 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 Page 58 of 59 COLORADO Air Pollution Control Division Department of Public Health & Environment Dedicated to protecting and improving the health and environment of the people of Colorado Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS GG requirements). 2.3.2 NSPS for Stationary Combustion Turbines: 40 CFR 60, Subpart KKKK §60.4305 Does this subpart apply to my stationary combustion turbine? (a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part.Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part. A Subpart KKKK applicability determination as well as an analysis of applicable Subpart KKKK monitoring, recordkeeping, and reporting requirements for the permanent turbine replacement shall be included in any request for a permanent turbine replacement Note that under the provisions of Regulation No. 6. Part B, Section I.B. that Relocation of a source from outside of the State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the commence construction date for purposes of determining the applicability of NSPS KKKK requirements). 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. Page 59 of 59 RECEIVED 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. Incomplete APENs will be rejected and will require re -submittal. Your APEN will be rejected if it is , filled out incorrectly, is missing information, or lacks payment for the filing fee. The re -submittal will require payment for a new filing fee. 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.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. NAY -32019 Permit Number: 1 WE1475 ,,fario PeD q' nary AIRS ID Number: 123 / 9008 / 005 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Site Name: DCP Operating Company, LP Libsack Compressor Station Site Location: Section 36, T6N, Range 65W Mailing Address: (Include Zip code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Phone Number: Marie Cameron (303) 605-2029 E -Mail Address': mecameron@dcpmidstream.com ' 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. 3:`28582 Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 COLORADO 1 I 1 YLO lr�E riBiiula ElfVimMW:1 Permit Number: 11 WE1475 AIRS ID Number: 123/9°m/005 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source -OR - Q 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) Additional Info £t Notes: Update to VOC limit to include the assist gas VOC emissions 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: TEG Dehydrator Unit Company equipment Identification No. (optional): For existing sources, operation began on: D-1 6/7/2013 For new or reconstructed sources, the projected start-up date is: El Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Will this equipment be operated in any NAAQS noriattainment area? Is this unit located at a stationary source that is considered a Major Source of (HAP) Emissions? hours/day days/week Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 O Yes ❑ Yes weeks/year No No 2IAVCOLORADO HGaIITb&tY4vfuMRl Permit Number: 11WE1475 AIRS ID Number: 123/9°m/005 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: QB Dehydrator Serial Number: 642012 Model Number: 9i O1T 6,)SU t (•icoI (,B )1 Reboiler Rating: 2.86 MMBTU/hr Glycol Used: O Ethylene Glycol (EG) O DiEthylene Glycol (DEG) ❑✓ TriEthylene Glycol (TEG) Glycol Pump Drive: ❑✓ Electric O Gas If Gas, injection pump ratio: / Acfm/gpm Pump Make and Model: Best Pump Works, SN: 6123355002 # of pumps: 1 Glycol Recirculation rate (gal/min): Max: 24.0 Requested: 24.0 Lean Glycol Water Content: 1.0 Wt.% Dehydrator Gas Throughput: Design Capacity: 64 MMSCF/day Requested5: 23,360 MMSCF/year Actual: MMSCF/year Inlet Gas: Pressure: 1020 psig Water Content: Wet Gas: lb/MMSCF Flash Tank: Pressure: 46 psig Cold Separator: Pressure: psig Stripping Gas: (check one) ❑✓ None ❑ Flash Gas ❑ Dry Gas ❑ Nitrogen Flow Rate: scfm Temperature: 120 0Saturated Dry gas: 6.7 lb/MMSCF Temperature: 140 °F O NA Temperature: °F ❑✓ NA °F 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. �l.cr%�:wtb I OprontF . \D5 Oli10`1C‘ Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 COLORADO 3 I ��M� ,Sa.SITt£nW.°fuf�Ml Permit Number: 11 WE1475 AIRS ID Number: 123/90w/005 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.446123 / -104.604122 Operator_ Stack ID No _ - - Discharge Height Above Gro and Level (feet)' - �( Temp F) �� Flow Rates (ACFM ) - Velocity t/sec ff ) D-1 30 Indicate the direction of the stack outlet: (check one) D Upward 0 Horizontal 0 Downward ❑ Other (describe): 0 Upward with obstructing raincap Indicate the stack opening and size: (check one) Circular Interior stack diameter (inches): 48 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): 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. Condenser: Used for control of: Type: Make/Model: Maximum Temp: °F Average Temp: Requested Control Efficiency: VRU: Used for control of: VOC and HAPs from flash tank stream Size: Make/Model: Requested Control Efficiency: 100 VRU Downtime or Bypassed: 5 % ❑ Combustion Device: Used for control of: VOC and HAPs from flash tank stream during VRU downtime and still vent stream Rating: MMBtu/hr Type: ECD-1 Make/Model: Leed Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 98 % Minimum Temperature: °F Waste Gas Heat Content: >1450 Btu/scf Constant Pilot Light: ✓❑ Yes 0 No Pilot Burner Rating: 0.05 MMBtu/hr Closed ❑ Loop System: Used for control of: Description: System Downtime: ❑ Other: Used for control of: Description: Requested Control Efficiency: Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 AV COL11„: ODO 4, - He4Q l Benzene Permit Number: 11WE1475 AIRS ID Number: 123/90m/OO5 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach alt emission 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 Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX NO), CO VOC Still Vent ECD-1, Flash: VRU (ECD-1 during VRU DT) Still: 95%, Flash: 100% (95% VRU DT) HAPs Still Vent ECD-1, Flash: VRU (ECD-1 during VRU DT) Still: 95%, Flash: 100% (95% VRU DT) Other: From what year is the following reported actual annual emissions data? 2018 Criteria Pollutant Emissions Inventory Pollutant PM Source (AP -42, Mfg., etc.) Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) SOX NO. 0.068 lb/MMBtu AP -42 0.1 0.1 a- 2. 4,3} CO 0.31 • lb/MMBtu AP -42 0.3 0.3 (P4M 5.5 (o;L'-( VOC 47.87 / 13't,9y GlyCalc / Mass Balance 127.8 3.1 559.2V 1.8 22.67 1.8 • Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis lb/MMscf Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Toluene Ethylbenzene 71432 108883 100414 ,.tct/ 1.\14%•5-1 "Lin I b.1,1Tio t 6.21 E-02 • lb/MMscf lb/MMscf (PM( -0-\c" WtA. 5 &-ko-CL <00 cote! GlyCalc 27,065 23,807 828 1,349 1,186 41 Xylene 1330207 9.76E-01 • lb/MMscf GlyCalc 8,993 447 n -Hexane 110543 9.34E-01 Ib/MMscf GlyCalc 2,005 100 2,2,4- Trimethylpentane 540841 Other: �tv�(S pca( apple&o.. 5 Requested values will become permit limitations. Requested limit(s) should cohsider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. �S C�4icl Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 5 � COLORADO a,sEn al� Permit Number: 11 WE1475 AIRS ID Number: 123/90m/005 [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. .71; 2:p Signature of Legally Authorized Person (not a vendor or consultant) Date tit/ac/a Marie Cameron Senior Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑✓ 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-202 - Glycol Dehydration Unit APEN - Revision 3/2019 -VIORADO 6 I HeaUh Enuironm ml •.69 6 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. Incomplete APENs wilt be rejected and will require re -submittal. Your APEN will be rejected if it is filled out incorrectly, is missing information, or lacks payment for the filing fee. The re -submittal will require payment for a new filing fee. 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: 11 WE 1475 AIRS ID Number: 123 /9008/00g [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Namet: Site Name: DCP Operating Company, LP Libsack Compressor Station Site Location: Section 36, T6N, Range 65W Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Portable Source Home Base: Denver, CO 80202 Site Location Weld County: NAICS or SIC Code: 1311 Contact Person: Marie Cameron Phone Number: (303) 605-2029 E -Mail Address2: mecameron@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. 4. 318533 Form APCD-200 - General APEN - Revision 3/2019 �j�\ {fCOLORADO 1 I �V i C mcantal Pubic FfSNITb FnW,tWlflI Permit Number: 11WE1475 AIRS ID Number: 123 /9008/ cull [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) ❑ 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: 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.: Titan 250-31900S Company equipment Identification No. (optional): For existing sources, operation began on: TURB-1 Serial No.: TBD For new or reconstructed sources, the projected start-up date is: TBD O 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 3/2019 days/week weeks/year Jun -Aug: Sep -Nov: p COLORADO 21 .JDepartroantafPuthe } aNaF EnWmeuemaN Permit Number: 11 WE 1475 AIRS ID Number: 123 / 9008/ op% [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information Et 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) Actual Annual Amount (Specify Units) Requested Annual Permit Limits (Specify Units) Material Consumption: Finished Product(s): 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.446123 / -104.604122 ❑ 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. , O erator� c Stack ID Noy r s Discharge Height 'we rain Level G (Feet) Temp P O� Flow Rate � : (ACFM) Vei°S�t)r �jfr secs z l TURB-1 44 872 Indicate the direction of the stack outlet: (check one) ❑✓ Upward D Horizontal ❑ Downward O Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): ❑ Upward with obstructing raincap O Square/rectangle Interior stack width (inches): Interior stack depth (inches): O Other (describe): Form APCD-200 - General APEN - Revision 3/2019 COLORADO 3I W oL {{ailbbfry M,t wtl Permit Number: 11 WE 1475 AIRS ID Number: 123 /9008 / Cos [Leave blank unless APCD has already assigned a permit # 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/hr) Actual Annual Fuel Use (Specify Units) Requested Annual Permit Limits (Specify Units) 175.21 k, S5•`+ MMscf/yr From what year is the actual annual fuel use data? N/A Indicate the type of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑✓ Field Natural Gas Heating value: c(1%3 BTU/SCF O 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. tM(.A, cpy jlrC-1. as . i-kS psi -m.11 Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes ✓❑ No If yes, describe the control equipment AND state the overall control efficiency (% reduction): 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 3/2019 COLORADO rtam,au,wbmnea Permit Number: 11 WE 14755 AIRS ID Number: 123 /9008 / cepTh [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. Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg., etc.) Actual Annual Emissions .,. . ��w.<<_., Requested Annual Permit Emission Ltmit(s)5 x..., --,f-,-.. _ Uncontrolled (tons/year) Controlled7 (tons/year) Uncontrolled (tons/year) Controlled (tons/year) TSP (PM) 6.60E-3 Ib/MMBtu • AP -42 .675-7.5.03.- 5.575.o PM10 6.60E-3 Ib/MMBtu • AP -42 5.575.01, 5.57 c.t PM2.5 6.60E-3 Ib/MMBtu . AP -42 5.57 &57 S. s v; SOx 3.40E-3 Ib/MMBtu • AP -42 2278-7Z•v% 2.87 Z.t. NOx Ll.vw..10•z-14,v st i c 511u-e�.E i Manufacturer 33.71 /0.05/0.05 33.71 /0.05/0.05 CO Si. t tc..X.� t 7 es Uri L.-e-K1c Manufacturer 46.6410.77 / 0.48 46.64 /0.77 / 0.48 L.O to-"Stb7 VOC fyo t51...k. � AP -42 I . to l / 0.05 / 0.05 t. o/ 0.05 / 0.05 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. Note that the requested permit limits for NOx, CO, and VOC include three scenarios: normal operation, startup, and shutdown emissions 0"} 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 (lbs/year) Controlled Actual Emissions? (lbs/year) 50-00-0 Formaldehyde -- 7.10E-4 Ib/MMBtu AP -42 1199 101O 11991octO 7 Amual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Note that the values above are Potential -to -emit (PTE) emissions for non -criteria pollutants. Please include these PTE emissions in the Notes to Permit Holder section of the permit. Form APCD-200 - General APEN - Revision 3/2019 5I AvCOLORAD7:zO x•.emacnW�on:suri V,ct).G+nts ,,( vvva.,Akccu.bAwci Ja • l-lD5 05 fret ill Permit Number: 11WE1475 AIRS ID Number: 123 /9008/ o OZ [Leave blank unless APCD has already assigned a permit k 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) Marie Cameron Date Senior Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑✓ 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-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.Rov/cdphe/apcd Form APCD-200 - General APEN - Revision 3/2019 61 COLORADO Nm'rntvl PAEflc atllRS Enfircwimerd Gas Venting APEN - Form APCD-211 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. Incomplete APENs will be rejected and will require re -submittal. Your APEN will be rejected if it is filled out incorrectly, is missing information, or lacks payment for the filing fee. The re -submittal will require payment for a new filing fee. This APEN is to be used for gas venting only. Gas venting includes emissions from gas/liquid separators, well head casing, pneumatic pumps, blowdown events, among other events. 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.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: 11WE1475 AIRS ID Number: 123 /9008 /00 01 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: Site Name: Site Location: DCP Operating Company, LP Libsack Compressor Station Section 36, T6N, Range 65W Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Phone Number: Marie Cameron (303) 605-2029 E -Mail Address2: mecameron@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-211 - Gas Venting APEN - Revision 3/2019 • 3'185184 COLORADO 1 I Av rig.ofP.rj ReL1At EnW.a.u'wnl Permit Number: 11WE1475 AIRS ID Number: 123 /9008 / per( [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) ❑ Change fuel or equipment ❑ Change company name3 ❑ Add point to existing permit O 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 & Notes: 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: TURB-1 compressor blowdown emissions. Company equipment Identification No. (optional): TU RB-BD For existing sources, operation began on: For new, modified, 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 Will this equipment be operated in any NAAQS nonattainment area? Is this equipment located at a stationary source that is considered a Major Source of (HAP) Emissions? Is this equipment subject to Colorado Regulation No. 7, Section XVII.G? Form APCD-211 - Gas Venting APEN - Revision 3/2019 days/week weeks/year Yes Yes Yes No No No 2 I AvICOLORADO FiUl�h Enubvmm,,l Permit Number: 11 WE1475 AIRS ID Number: 123 /9008 / Ocfj [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information ❑ Gas/Liquid Separator ❑ Well Head Casing ❑ Pneumatic Pump Make: Model: Compressor Rod Packing Make: ❑✓ Blowdown Events # of Events/year: ❑ Other Description: Serial #: Model: # of Pistons: 24 Capacity: gal/min Leak Rate: Scf/hr/pist Volume per event: 0.028 MMscf/event If you are requesting uncontrolled VOC emissions greater than 100 tpy for a gas/liquid separator, you must use Gas Venting as a process parameter. Are requested uncontrolled VOC emissions greater than 100 tpy? Gas Venting Process Parameters5: Liquid Throughput Process Parameters5: Vented Gas Properties: ❑ Yes ❑✓ No Vent Gas Heating Value: LtP S'L& BTU/SCF Requested: 0.66 MMSCF/year Actual: MMSCF/year -OR- NoS O1-11ti111 Requested: bbl/year Actual: bbl/year Molecular Weight: 22.3 VOC (Weight %) 25.12 • Benzene (Weight %) 0.03 ' Toluene (Weight %) 0.03. Ethylbenzene (Weight %) 0.001• Xylene (Weight %) 0.01 • n -Hexane (Weight %) 0.19 2,2,4-Trimethylpentane (Weight %) 0 Additional Required Information: ❑✓ Attach a representative gas analysis (including BTEX It n -Hexane, temperature, and pressure) Attach a representative pressurized extended liquids analysis (including BTEX Et n -Hexane, temperature, and pressure) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. COLORADO Form APCD-211 - Gas Venting APEN - Revision 3/2019 Permit Number: 11 WE1475 AIRS ID Number: 123 / 9008 / cool [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.446123 / -104.604122 Operator { Stack ID No * Discharge Heigh Above Ground Level (Feet) H Temp . r ( F1 Flow Raie (ACFM) .. i fVeloctty (jt/secj . TURB-BD NIA ta'A calA NiA Indicate the direction of the stack outlet: (check one) Upward Horizontal Downward ® Ether (describe):]-tjve S Indicate the stack opening and size: (check one) Circular Interior stack diameter (inches): © Other (describe): El Upward with obstructing raincap ?wk, .c> v -o . 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. VRU: Pollutants Controlled: Size: Make/Model: Requested Control Efficiency: % VRU Downtime or Bypassed: 0/0 Combustion Device: Pollutants Controlled: Rating: Type: Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency: Minimum Temperature: MMBtu/hr Make/Model: % Waste Gas Heat Content: Btu/scf Constant Pilot Light: Yes No Pilot burner Rating: MMBtu/hr Other: Pollutants Controlled: Description: Requested Control Efficiency: yoggiCOLORADO Form APCD-211 - Gas Venting APEN - Revision 3/2019 Benzene Permit Number: 11 WE1475 AIRS ID Number: 123 /9008 / a'9 [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 Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX NO. CO VOC HAPs Other: From what year is the following reported actual annual emissions data? N/A Criteria Pollutant Emissions Inventory Pollutant PM Emission Factor Source (AP -42, Mfg., etc.) Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Ib/blowdown Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tans/year) SOX NO„ CO VOC 407.7 • Eng. Estimate 4.89 . 4.89 ' Non -Criteria Reportable, Pollutant, Emissions Inventory Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) 71432 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 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-211 - Gas Venting APEN - Revision 3/2019 5I.VCOLORADO i,17.4=d �c Permit Number: 11 WE1475 AIRS ID Number: 123 /9008/ '( [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. L1/261/ 9 Signature of Legally Authorized Person (not a vendor or consultant) Date Marie Cameron Senior Environmental Engineer Name (please 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-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 websiteat: https://www.colorado.Rov/cdphe/apcd Form APCD-211 - Gas Venting APEN - Revision 3/2019 iCOLORADQ 6 to R �di_ �Hodhb EM1�tem�m,ri;l 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. Incomplete APENs will be rejected and will require re -submittal. Your APEN will be rejected if it is filled out incorrectly, is missing information, or lacks payment for the filing fee. The re -submittal will require payment for a new filing fee. 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.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: 11 WE1475 AIRS ID Number: 123 / 9008 / 0 0 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name1: DCP Operating Company, LP Site Name: Libsack Compressor Station Site Location: Section 36, T6N, Range 65W Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Site Location County: Weld NAICS or SIC Code: 1311 Denver, CO 80202 Contact Person: Marie Cameron Phone Number: (303) 605-2029 E -Mail Address2: mecameron@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-202 - Glycol Dehydration Unit APEN - Revision 3/2019 - 345S5 COLORADO AV mob. Permit Number: 11 WE1475 AIRS ID Number: 123/9008/ OO [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) D Change fuel or equipment ❑ Change company name3 ❑ 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 - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info & Notes: 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: TEG Dehydrator Unit Company equipment Identification No. (optional): D-2 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: Will this equipment be operated in any NAAQS nonattainment area? hours/day days/week 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 3/2019 ❑✓ Yes Yes weeks/year No No COLORADO R lth EnUUPfumnl Permit Number: 11 WE1475 AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 123190061 0 t Section 4 - Dehydration Unit Equipment Information Manufacturer: TBD • Dehydrator Serial Number: TBD Model Number: TBD Reboiler Rating: 4.48 MMBTU/hr Glycol Used: ❑ Ethylene Glycol (EG) O DiEthylene Glycol (DEG) ❑✓ TriEthylene Glycol (TEG) • Glycol Pump Drive: ❑✓ Electric O Gas If Gas, injection pump ratio: / Acfm/gpm Pump Make and Model: TBD Glycol Recirculation rate (gal/min): Max: 40 . Lean Glycol Water Content: 1.0 • Wt.% Requested: 40 #of pumps: 1P + 1B • Dehydrator Gas Throughput: Design Capacity: 231 • MMSCF/day Requested5: 84,315 • MMSCF/year Actual: N/A MMSCF/year Inlet Gas: Pressure: 1000 • psig Temperature: 115 ° F Water Content: Wet Gas: lb/MMSCF ❑✓ Saturated Dry gas: 5.0 tb/MMSCF Flash Tank: Pressure: 45 , psig Temperature: 150 °F O NA Cold Separator: Pressure: psig Temperature: °F ❑✓ NA Stripping Gas: (check one) ✓❑ None ❑ 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) 0 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 3/2019 3 I AI` tflnl Permit Number: 11 WE1475 AIRS ID Number: 123/9008/ O1O [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.446123 / -104.604122 Operator T Stack 1D No Discharge Height , 4..6 , h Above Ground Level Temp ( F) Flow Rate (ACFM) 1/eloci a �jtisec). ask r D-2 40 Indicate the direction of the stack outlet: (check one) 0 Upward ❑ Horizontal 9 Downward O Other (describe): ❑ Upward with obstructing raincap Indicate the stack opening and size: (check one) ❑� Circular Interior stack diameter (inches): 84 ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): 9 Other (describe): 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. O Condenser: Used for control of: Type: Make /Model: Maximum Temp: °F Average Temp: Requested Control Efficiency: % °F ❑✓ VRU: Used for control of: VOC and HAPs from flash tank stream Size: Make/Model: TBD Requested Control Efficiency: 100 VRU Downtime or Bypassed: 5 % ✓❑ Combustion Device: Used for control of: VOC and HAPs from flash tank stream during VRU downtime and still vent stream Rating: MMBtu/hr Type: ECD-2 Make/Model: Zeeco / EGF-7-40 Requested Control Efficiency: 95 % Manufacturer Guaranteed Control Efficiency: 99 % Minimum Temperature: T Waste Gas Heat Content: >1450 Btu/scf Constant Pilot Light: 0 Yes O No Pilot Burner Rating: 0.071 MMBtu/hr Closed ❑ Loop System: Used for control of: Description: System Downtime: 0 O Other: Used for control of: Description: Requested Control Efficiency: % Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 4 I ACOLLOORAbO ° «Pu Permit Number: 11 WE1475 AIRS ID Number: 12319°081 O1O [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 be used to state the overall (or combined) control efficiency (% reduction): Pollutant Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOX NO. , CO VOC Still Vent: ECD-2, Flash: VRU (ECD-2 during VRU DT) Still: 95%, Flash: 100% (95% VRU DT) HAPs Still Vent: ECD-2, Flash: VRU (ECD-2 during VRU DT) Still: 95%, Flash: 100% (95% VRU DT) Other: From what year is the following reported actual annual emissions data? N/A Criteria Pollutant! Emissions Inventory Pollutant PM Source (AP -42, Mfg., etc.) Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) SOX NO. 0.068 • lb/MMBtu AP -42 1.20 1.20 . CO 0.31 lb/MMBtu AP -42 5.46 . 5.46 VOC 18.3941 12.M IIrwwScf GIyCaIW Mass Balance 775.43•/ 1.20 18.49/ 1.20. Chemical Name Benzene Toluene Ethylbenzene Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number 71432 108883 100414 Emission Factor Actual Annual Emissions Uncontrolled Basis 1;13s1�1.r.xlo 1 0.0605 Units Ib/MMscf Ib/MMscf Ib/MMscf Source (AP -42, Mfg., etc.) �,lycaic,f �tyCuc 1'10.S� salow-C. GlyCalc Uncontrolled Emissions (pounds/year) ILI,dc7J tS, b'.3 5,103 Controlled Emissions6 (pounds/year); S',155 S,totD7- 252 • Xylene 1330207 0.7864• Ib/MMscf GlyCalc 66,308 • 3,283 • n -Hexane 110543 0.2094 lb/MMscf GlyCalc 17,655 - 482 • 2,2,4- Trimethylpentane 540841 Other: callkt'> ?eAr a oak w- • 5 Requested values will become permit limitations. Requested limit(s) should consider future process groh. Ht , oll it/ri 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Note that the values above are Potential -to -emit (PTE) emissions for non -criteria pollutants. Please include these PTE emissions in the Notes to Permit Holder section of the permit. COLORADO 5 I �,,.�P:b& Health Eru4nt Permit Number: 11WE1475 AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 123/9008/ o'T Section 8 - 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) Z -02g ,//1' Date Marie Cameron Senior Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ✓O 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.gov/cdphe/apcd Form APCD-202 - Glycol Dehydration Unit APEN - Revision 3/2019 COLOR ADO at r�n� 6 =V= E,= RECEIVED MAY - 3 7019 APCD Stationary Sources Gas Venting APEN - Form APCD-211 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. Incomplete APENs will be rejected and will require re -submittal. Your APEN will be rejected if it is filled out incorrectly, is missing information, or lacks payment for the filing fee. The re -submittal will require payment for a new filing fee. This APEN is to be used for gas venting only. Gas venting includes emissions from gas/liquid separators, well head casing, pneumatic pumps, blowdown events, among other events. 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: 11 WE1475 AIRS ID Number: 123 / 9008 / 0 l I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Libsack Compressor Station Site Location: Section 36, T6N, Range 65W Mailing Address: 370 17th Street, Suite 2500 (include Zip Code) Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1311 Contact Person: Marie Cameron Phone Number: (303) 605-2029 E -Mail Address2: mecameron@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. 3`18556 COLORADO Form APCD-211 - Gas Venting APEN - Revision 3/2019 Permit Number: 11 WE 1475 AIRS ID Number: 123 /9008/ oil, [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) ❑ 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) Additional Info a Notes: 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: Pigging - five (5) low pressure receivers (one 10", two 12", two 20"); three (3) high pressure receivers (one 6", two 12"); two (2) high pressure launchers (one 16", one 20") Company equipment Identification No. (optional): P I G For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: TBD 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: Will this equipment be operated in any NAAQS nonattainment area? hours/day Is this equipment located at a stationary source that is considered a Major Source of (HAP) Emissions? Is this equipment subject to Colorado Regulation No. 7, Section XVII.G? Form APCD-211 - Gas Venting APEN - Revision 3/2019 days/week weeks/year Yes Yes Yes ❑ No No ❑✓ No hrCOLORADO 2 1ik m..ap kaNfTb L,,ka!uwnl Permit Number: I1 WE 1475 AIRS ID Number: 123 /9008 / [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information ❑ Gas/Liquid Separator ❑ Well Head Casing ❑ Pneumatic Pump Make: Model: ❑ Compressor Rod Packing Make: Model: ❑✓ Blowdown Events # of Events/year: ❑ Other Description: 741 ' Serial #: # of Pistons: Volume per event: Capacity: gal/min Leak Rate: 6" - 3.6 scf; 10"-19.9 scf; 12" - 25.8 scf; 16" - 35.5 scf; 20"-68.8scf Scf/hr/pist MMscf/event If you are requesting uncontrolled VOC emissions greater than 100 tpy for a gas/liquid separator, you must use Gas Venting as a process parameter. Are requested uncontrolled VOC emissions greater than 100 tpy? Gas Venting Process Parameters5: * Requested limit is 741 total pigging events/ year Liquid Throughput Process Parameters5: Vented Gas Properties: ❑ Yes ❑✓ No Vent Gas Heating Value: IZ�3 `l BTU/SCF Requested: 0.033 * MMSCF/year Actual: MMSCF/year -OR- Requested: bbl/year Actual: bbl/year etc '0bl ') 1 Molecular Weight: 22.3 / 22.3 - VOC (Weight %) 25.12/25.11 ' Benzene (Weight %) 0.03 / 0.03' Toluene (Weight %) 0.03 / 0.02 • Ethylbenzene (Weight %) 0.001 / 0.001 . Xylene (Weight %) 0.01 / 0.01 ' n -Hexane (Weight %) 0.19 /0.19' 2,2,4-Trimethylpentane (Weight %) 0 / 0 ' Note the receivers will handle inlet gas and the launchers will handle post -dehydrator dry gas Additional Required Information: ❑✓ Attach a representative gas analysis (including BTEX Et n -Hexane, temperature, and pressure) Attach a representative pressurized extended liquids analysis (including BTEX Et n -Hexane, temperature, and pressure) (7% lih(5 ctpc;iita 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Form APCD-211 - Gas Venting APEN - Revision 3/2019 mpricoLORADO 3 I Aoi bw,oj 14,y, Permit Number: 11WE1475 AIRS ID Number: 123 /9008 / o t [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.446123 / -104.604122 Operator Stack ID No Discharge Height Above Ground Level (Feet) Temp �F 4 (�)s Flow Rate (ACFM.) Velocity (ft/sec). .." ... PIG N/A N/A N/A N/A 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): 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. ❑ VRU: Pollutants Controlled: Size: Make/Model: Requested Control Efficiency: % VRU Downtime or Bypassed: % ❑ Combustion Device: Pollutants Controlled: Rating: Type: Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency: Minimum Temperature: MMBtu/hr Make/Model: % Waste Gas Heat Content: Btu/scf Constant Pilot Light: ❑ Yes ❑ No Pilot burner Rating: MMBtu/hr Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-211 - Gas Venting APEN - Revision 3/2019 COLORADO 4 wxmarnwm;uncni Chemical Name Permit Number: 11 WE 1475 AIRS ID Number: 123 / 9008 / O1\ [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 Description. of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) PM SOx NO. CO VOC HAPs Other: From what year is the following reported actual annual emissions data? N/A Criteria Pollutant Emissions Inventory PM Uncontrolled Basis Ib/blowdown Source (AP -42, Mfg., etc.) Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Emissions (tons/year) Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled Emissions (tons/year) SOx NOx CO VOC Eng. Estimate 7.18, .134. X137- ROdNiN..C- To( t- f- CQlc0Ea-* . t}�S (Pit td Non -Criteria Reportable Pollutant Emissions Inventory Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Source (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions6 (pounds/year) Benzene 71432 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 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-211 - Gas Venting APEN - Revision 3/2019 5 COLORADO xammaenut,�unna Permit Number: 11 WE1475 AIRS ID Number: 123 / 9008 / O I [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. ,v 71 1 — Signature of Legally Authorized Person (not a vendor or consultant) ' Date Marie Cameron Senior Environmental Engineer Name (please print) Title Check the appropriate box to request a copy of the: ❑✓ 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-211 - Gas Venting APEN - Revision 3/2019 COLOR ADO 6 I AV Hello