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Home My WebLink About20174108.tiffCOLORADO Department of Public Health Er Environment Dedicated to protecting and improving the health and environment of the people of Colorado Weld County - Clerk to the Board 1150 0 St PO Box 758 Greeley, CO 80632 November 28, 2017 Dear Sir or Madam: RECEIVED DEC -1 2017 WELD COUNTY COMMISSIONERS On November 30, 2017, the Air Pollution Control Division will begin a 30 -day public notice period for Discovery DJ Services LLC - Discovery Fort Lupton Plant. A copy of this public notice and the public comment packet are enclosed. Thank you for assisting the Division by posting a copy of this public comment packet in your office. Public copies of these documents are required by Colorado Air Quality Control Commission regulations. The packet must be available for public inspection for a period of thirty (30) days from the beginning of the public notice period. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health Et Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Clara Gonzales Regards, Clara Gonzales Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure 4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.govfcdphe John W. Hickenlooper, Governor bIic V ec� � 9 / Co ( t �l I Larry Wolk, MD, MSPH, Executive Director and Chief Medical Officer CC. PL.CIMM/TP).MLCZT) Pwt EAR/CHUM /ey) ID/L-1/l7 2017-4108 Air Pollution Control Division Notice of a Proposed Project or Activity Warranting Public Comment Website Title: Discovery DJ Services LLC - Discovery Fort Lupton Plant - Weld County Notice Period Begins: November 30, 2017 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: Discovery DJ Services LLC Facility: Discovery Fort Lupton Plant Natural Gas Processing Plant Section 11, Township 1N, Range 66W Weld County The proposed project or activity is as follows: Discovery DJ Services, LLC (Discovery) is requesting to add a new 250 MMscf/day natural gas processing train to the Discovery Fort Lupton Plant. Discovery is requesting permit coverage for the following equipment associated with the new gas processing train: (i) Amine unit, (ii) TEG Dehydrator, (iii) Two (2) hot oil heaters, (iv) Regeneration Heater, (v) Four (4) 1,000 barrel fixed roof condensate storage vessels, (vi) Two (2) 400 barrel fixed roof condensate storage vessels, (vii) Amine unit thermal oxidizer, (viii) TEG dehydrator thermal oxidizer, and (x) hydrocarbon loadout. 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 16WE0773 have been filed with the Weld County Clerk's office. A copy of the draft permit and the Division's analysis are available on the Division's website at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices The Division hereby solicits submission of public comment from any interested person concerning the ability of the proposed project or activity to comply with the applicable standards and regulations of the Commission. The Division will receive and consider written public comments for thirty calendar days after the date of this Notice. Any such comment must be submitted in writing to the following addressee: Harrison Slaughter Colorado Department of Public Health and Environment 4300 Cherry Creek Drive South, APCD-SS-B1 Denver, Colorado 80246-1530 cdphe.commentsapcd@state.co.us cAa0 1 Colorado Air Permitting Project Project Details Review Engineer: Package #: Received Date: Review Start Date: Section 01- Facility Information Company Name: Discovery al Services LLC County AIRS ID: 123 Plant AIRS ID: 9E59 Facility Name: DiscoveryFort Lupton Plant Physical Address/Location: Section 11, Township 1N, Range 66W, in Weld County, Colorado Type of Facility: Natural Gas Processing Plant What industry segment? Oil & Natural Gas Production & Processing Is this facility located in a NAAQS non -attainment area? Yes If yes, for what pollutant? Parton Monoxide (CO) [articulate Matter (PM) ozone (NOx a VOC( Weld Quadrant Section Township Range iN 6 Section 02 - Emissions Units In Permit Application AIRs Point # Emissions Source. Type Equipment Name Emissions Control? Permit # Issuance # Self Cart Required? Action Engineering Remarks 001 , . .... ..„ , - - Natural Gas RICE El Yes 16W60773 -2 _ - Yes : Cancellation Cancellation :. will be submitted within 30 days of start-up of phase II gas processing train. 002 Natural Gas RICE E2 Yes 16W607773 2 Yes Cancellation See note. for Point 001 above - 003 NaturalGasRICE Es ,. Yes - 16WE0773 2 - - Yes Cancellation See note for Point 001 above 004 Natural Gas RICE E4 Yes 16WE0773 2 Yes" - Cancellation See note for Point 001 above 005 - MalntertanceRlowdowns CB - No 17WE1156 2 - - - Na> _ APEN Required I Permit Exempt Compressor Blowdowns. Point removed from permit because emissions are below permit thresholds 006 Other (Explain) RP No 16WE0773 2 Yes Permit Modification Compressor Rod Packing (Fugitive) 007 EG Dehydrator D1 Yes 16WE0773 2 Yes- No Action Requested 008 EG Dehydrator I D2 Yes 16W£0773 2 Yes.: No Action Requested 009 Fugitive Component Leaks FUG No 16W607732 Yes Permit Modification 010 - Condensate Tank CT Yes 16WE0773:.. 2 Yes No Action Requested 011 Natural Gas RICE E5 - Yes 16W60773 2 Yes No Action Requested 012 Natural Gas RICE E6 Yes 16W60773 2 Yes No Action Requested 013 Process flare Plant Flare No 16W60773 2 ', Yes No action Requested 014 Hydrocarbon liquid Loading LT No 16WE0773 2 Yes No Action Requested 015 Amine Sweetening Unit Al Yes 16WE6773 2 Yes Permit Modification NewSource (Phase II) 016 TEG Dehydrator D3 : Yes 16WE0773 2 Yes Permit Modification New Source (Phase II) 017 Boiler or Process Heater Hl & H2 No 16WE0773 2 ,... .. Yes. ,. Permit. --. Modification- New Source (Phase II) 018 Boiler or Process Heater H3 : No 16WE0773 2 Yes. Permit Modification New Source (Phase Il)' 019 Condensate Tank CT2 Yes 16WE0773 2 Yes----- Permit Modification New Source (Phase II) 020 Condensate Tank ST Yes 16WE0773 2 Yes Permit Modification New Source (Phase II) Colorado Air Permitting Project 021 Other (Explain) CS No 16WE0773 2 ;'; Yes Permit. Modification " Thermal Oxidizer (New Source - Phase; Ii) 022 Other (Explain)' -- - C2 No , -16W60773 2 - Yes Permit. Modification - " Thermal Oxidizer (New Source - Phase II) (Explain) ... C3 - No , 16W£0773 2 --:. No Cancellation -'- Cancelled on 11/13/2017 024 _ " Hydrocarbon Liquid Loading , ,,:._ LT Yes - 16WE0773 2 . ' . Yes Permit - Modification ' New Source (Phase II) Section 03 - Description of Project Discovery Di Services, LLC (Discovery) submitted a construction permit application requesting the modification of an existing synthetic minor natural gas processing facility located in the ozone non -attainment area. With this modification, Discovery is requestingto add a new 250 MMscf/day natural gas processing train to the Discovery Fort Lupton Plant (Phase II). As part of this modification, Discovery is requesting the removal of existing sources, modifications sources. Details of these modifications are as follow: to existing sources and addition of new sou 1. Removal of Sources: Discovery is requesting to cancel and permanently remove four (4) natural gas fired reciprocatiiisginternal combustion engines covered under AIRs Points 001-004. These sources will be cancelled within 30 days after commencement of operation of -Phase II of the Discovery Fort Lupton Plant. Even though these engines are intended to be permanently removed, they were included in the evaluation of total facility emissions to assess the facility classification with the engines in operation. Based on this assessment, the facility would remain synthetic minor with theengines in operation during start up of phase II of the gas processing facility. 2. Discovery is requesting to modify -the following existing point$: "(a) Compressor J3lowdowns (Point 005) - Remove.point from permit as emissions' have fallen below permit thresholds due to the "' removal of four existing inlet compression'engine's.Four (4).electriciesidue" compressors willbeadded. Emissions are calculated based onlyonresidue gas r composition asthe plant will not longer require inlet gas compression. (b) Venting from compressor rod packing (Point 00&):Decrease the permitted process and emission lira its due to the removal of four 'existing inlet compression engines. Four (4) electric residue compressors will be added. Emissions are calculated based only on residue gas composition as the plant will not longer require inlet gas compression. (c) Fugitives (Point 009): Increase in component count and emissions to account for the installation of the second natural gas processing train at this facility. S. New Sources: Discovery is requestingtis'acid the following equipment for the new 250 MMscffday natural gas processing train (Phase II): (i) Amine unit (Point.. 15,), (li) TEG'Dehydrator (Point 016), (iit)ITwo '(2) hot oil heaters (Point 017), (iv) Regeneration Heater (Point 018), (v) four (4) 1,000 barrel fixed_toof condensate storage vessels (Point 019), (vi) Two (2) 400 bbl fixed roof condensate storage vessels (Point020j. (vii) Amine unit thermal oxidizer (Point 021), (viii) TEG dehydrator thermal oxidizer (Point 022), and (x) hydrocarbon loadout (Point 024). 4. The operator initially submitted an APEN for the combustor (point 023) used to control emissions from the new storage vessels (points 019-020) and loadout from these storage vessels (point 024). During review, it was determined emissions from this source are below AP EN reporting thresholds. Asa result, the operator submitted a cancellation for the: source on 11/13/2017. This permit will ire public comment because new synthetic minor limits are being established to avoid other ir.ernents. The operator was provided with a draft permit to review prior to public comment. The operator provided the following comment: 'The amine thermal oxidizer emission faMor for n -Hexane (on Page 37) is from AP -42 Chapter 1 Table S.4-3.' This change was made to the permit as, requested. The operator expressed they had no further comments. Section 04 - Public Comment Requirements Is Public Comment Required? If yes, why? ;Requesting Synthetic Minor Permit Yen Section 05 - Ambient Air Impact Analysis Requirements Was a quantitative modeling analysis required? 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 (P5O) 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. here: S02 NOx CO VOC PM2.5 PM10 TSP HAPs Prevention of Significant Deterioration (PSD) ❑ El ❑ ❑ El ❑ Title V Operating Permits (OP) ❑ ❑ ❑ ❑ El ❑ ❑ ❑ Non -Attainment New Source Review (NANSR) ❑ O Nu SO2 NOx CO VOC PM2.5 PM10 TSP HAPs ❑ ❑ ❑ ❑ El ❑ ❑ ❑ ❑ E El ❑ ❑ O El fl Rod Packing Emissions Inventory Section 01- Adminstrative Information Facility AIRs ID: 123 9E99 _ County Plant Point Section 02- Equipment Description Details Detailed Emissions Unit Description: Emission Control Device , et6i006*(Htiti6640ilt.Ce4'rtE Description: Requested Overall VOC & HAP Control Efficiency %: Section 03- Processing Rate Information for Emissions Estimates Compressor and packing vent rate= v ?'sif: scf/hr Number of compressors= Electric compressor rod packing vent rate= Number of electric compressors= Actual rod packing vent rate= Actual Gas Vent Rate = Requested Permit Limit Throughput = Potential to Emit (PTE) Throughput = scf/hr scf/hr 0 MMscf per year 3.399 MMscf per year 3.399 MMscf per year Actual Gas Throughput While Emissions Controls Operating = Section 04- Emissions Factors & Methodologies Emission Calculation Method EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10- Displacement Equation (10.4-3) Ex=Q*MW*Xx/C Ex = emissions of pollutant x Q. Volumetric flow rate/volume of gas processed MW = Molecular weight of gas = SG of gas * MW of air Xx = mass fraction of x in gas C. molar volume of ideal gas (379 scf/lb-mol) at 60F and 1 atm Throughput (Q) MW 3.40E+00 MMscf/yr Ib/Ib-mol 16.5 3.88Ei02 scf/yr 0.009312[MMscf/d mass fraction lb/hr lb/yr tpy non Helium CO2 N2 methane ethane 0:oi 4 i© 0.00 0.03 0.00 240.75 0.00 0.12 0.00 0.00 0:335 15.74 137896.35 68.95 1.04 9136.04 4.57 propane isobutane n -butane isopentane n -pentane cyclopentane n -Hexane cyclohexane Other hexanes heptanes methylcyclohexane 224-TMP Benzene Toluene Ethylbenzene Xylenes C8+ Heavies VOC mass fration: 0102::-. .:• 0.03 245.60 0.12 0.00 0.00 2.08 0.00 3.13 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.22 1919.01 0.96 0.00 0.000: 0.00 0.00 .. 0.00 0.00 0.00 0.00 0.00 0.00 0.000:V. 0.00 0.00 0.00 . ................. 0.00 1.52 0.00 0.02 134.94 0.07 0.002 0.000 0.03 0.01 0.01 229.55 031 0.03 55.17 125.16 0.06 0 0.00 0.00 0.00 0.018412 Total VOC (Uncontrolled) 1.36 Notes HAP mass fractions are based on the inlet gas composition which is based on an average of five representative samples. The remaining composition of the residue gas is based on an engineering estimate. Emissions are based on a total of 6 compressors. Two compressors (phase I) have an assumed vent rate of 50 scf/hr. The remaining four (4) electric compressors (phase II) have an assumed vent rate of 72 sct/hr. Section 05 - Emissions Inventory Emissions Summary Table Pollutant Uncontrolled Emission Factor Controlled Emission Factor Uncontrolled Emissions Controlled Emissions Source VOC 799.13 lb/MMscf 799.13 lb/MMscf 1.36 tpy 1.36 tpy Gas Analysis Benzene 39.701 lb/MMscf 39.701 lb/MMscf 134.94 lb/yr 134.94 lb/yr Mass Balance Toluene 67.536 lb/MMscf 67.536 lb/MMscf 229.55 lb/yr 229.55 lb/yr Mass Balance Ethylbenzene 16.233 lb/MMscf 16.233 lb/MMscf 55.17 lb/yr 55.17 lb/yr Mass Balance Xylenes 36.824 Ib/MMscf 36.824 lb/MMscf 125.16 lb/yr 125.16 lb/yr Mass Balance n -Hexane 564.600 lb/MMscf 564.600 lb/MMscf 1919.01 lb/yr 1919.01 lb/yr Mass Balance 2,2,4-TMP 0.447 lb/MMscf 0.447 Ib/MMscf 1.52 lb/yr 1.52 lb/yr Mass Balance Section 06- Regulatory Summary Analysis 16WE0773.CP2.xlsm Rod.Packing Emissions Inventory AQCC Regulation 1 Section II.A.1 - Except as provided in paragraphs 2through 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 ll. A and B of this regulation. AQCC Regulation 2 Section I.A applies to all emission sources. "No person, wherever located, shall cause or allow the emission of odorous air contaminants from any single source such as to result in detectable odors which are measured in excess of the following limits: For areas used predominantly for residentialor commercial purposes it is a violation if odorsaredetected after the odorous air has been diluted with seven (7) or more volumes of odor free air." , AQCC Regulation 3 - - PartA-ADEN Requireme'hts - - Criteria Pollutants: For criteria pollutants, Air Pollutant Emission Notices are required for: eachindividualemission 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 Ji Section 11.D.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 modifiedminor sources located in nonattainment or attainment/maintenance areas. This source is located in the 8 -hour ozone nonattainmentarea. - The date of interest for determining whether the source is new or modified is therefore November20, 2007'(the date of the 8 -hour ozone NA area designation). Since the fugitives will be -in service after the date above, this source is considered "new or modified." This source is subject to thereciprocating compressor requirements of NSPS 0000a , which requires replacement of compressor rod packing at specified intervals. These requirements satisfy the RACT requirements under Regulation 3. Regulation 6 - Is this source at an onshore "natural gas processing plant" as defined in 40 CFR, Part 60.631? Yes Did this source commence construction,reconstruction, or modification after January 20,1984, and on or before August 23, 2011? No This source is notsubject to NSPS KKK because the facility will commence construction after August 23, 2011. Did this source commences construction, reconstruction, or modification after August 23, 2011 andon or before September 18, 2015? No Source is not subject to NSPS 0000 because this is a new that facility will commence construction after September 18,.2015. Regulation 7: Section XII: - Is this source located in an ozone non -attainment area or attainment maintenance area? Yes Is this source at an onshore "natural gas processing plant" as defined in 40 CFR, Part 60.631? Yes Facility is located in the non -attainment area and classified as a natural gas processing plant. Therefore, this source is subject to Regulation 7 Section XII.G. Section XVII: - Is the reciprocating compressor located at a natural gas compressor station? No The reciprocating compressors are located at a natural gas processing plant and are therefore not subject to Regulation 7 Section XVII.8.3.c. Regulation 8 - - - - Is this source at a "natural gas processing plant" as defined in 40 CFR, Part 63.761? Yes - Is this facility considered a "major source" of HAP as specifically defined in 40 CFR,Part 63.761 for sites that are not prodcution field facilities? No Source is not subject to MAR lilt because the facility is classified as a synthetic minor source of HAPs. NSPS 0000a Did this source commence construction, reconstruction, or modification after September18, 2015?Yes - Is this source at a well site, compressor station or onshore"natural gas processing plant" as defined in 40 CFR, Part 60.5430a? Yes This facility meets the definition of onshore "natural gas processing plant" as defined by 40 CFR, Part 60.5430a. Therefore, the emissions of this source are subject to the reciprocating compressor affected facility requirements under §60.5385a of NSPS 0000a. Since NSPS 00008 has not been adopted by the State of Colorado, therequirements will be referenced in the notes to permit holder. Section 07 - Technical Analysis Notes i i le .. - - - ,Tnr G 1� ¢ "1€i�rg fpiram �_'Wirh tons moc}Ifaafipn,the-JSPeratar is removing the`our inter compressors at this fasity an siition four ele:c₹Ftcresdue 4�mpfes5otsf5r€he3emn �as,prace55J,: ₹here wiif,tie a total of "six (6) "residue compressors at this facilityfee-Ili:pit two there is no longer inlet compression tfre operator based VOC emissions to a residue gas compostine to t Is based on 'illi anengineeringestimate.The VOCcantent in ,the residuegasestimated.by: the operator, is1.84%.This is mob ble value since residue gas intypica y,verylowmVOGconcel Addfi�nalt ,theOperator y estimated HAP compositlnn based anthe_inlef gas composiu'oawhich is 6a$ed o,�r q`dveFageoffpre Y7preseh'tetlW4^��iat'�T`his Is I becausethe residue gas typically has- lower HAP cuecentrationnwhen compared tot he islet gas 2,.- According to the a pplication.the"compressor rod packing seals leak a small amount of gas boost continuously at very tow pressures making this type =of°emission source very difficult to apply any type of emission earshot_ The NSPS 0000 background- technical support document reviewed the following control techniques for limit mg the leaking of natural gas pastthe -_ piston rod packing: Ii) Replacement of compressor rod packing, 0) Replacement o€ the piston rod, and (iii) Refitting orrealignment of the piston rod. This supports the operators claim that the emissions from this source would be difficult to route to an add-on control device (ie combustor, VRU, etc). Based on this information, along with the definition of fugitive emissionsin. the Colorado Common idetermined-this emission_ source would be classified as fugitive emissions. Asa result, the a ppOceble NSPS 0000a requirements to replace the reciprocating compressor rod packing every .20,000 hours or 35"months was determined: to bean acceptable mechanism for minimizing the emissions from this source. 3. According to the Natural'gasSTAR lessons learned docunreht'Reducing Methane Emissions from Compressor Rod PackingSystems; " leakage typrealip occurs from four areas: (ij ground ,,,the packing case through the sosegosket- (ti) Between the po king lip which are typically mounted metaito-metal against each other. (iii) -Around he riog ions slight movement in the cup groove as the rod moves back end forth. (iv) Between the ( rugs and shaft.' This document also indicates that a new packing system, properly aligned iand -fitted may lose approximately 11'to 12 standard cubic feet per hour (scfh)." Based on this information, the operator estimatedwines of 50 scf/hr (phase -I compressors) and 72 scf/'nr (phase II electric compressors) are likely con treatIse Ornate - - 4. Typically rod packing emissions associated with compressors are accounted for with the 'other" caregory under the fugitive emission source at a 'facility. This is supported by note "C" under Table 2-4 of theSPA Protocol for Equipment Leak Emission Estimates . (EPA -453/R -SS -017) w, hich states .'The 'other` equipment .type was derivedfrom compressors, diaphragms, draioo damparms,.hatches Instrurgents, meters, presser relief valves, polished rods, rehefvalves, and vents. "Ifthis method were used on ins tn rod packing emissions an emission factor'oL6.0088kg/hr-soueceltvottl kbautilized ,U cupthisvalue along with six (6) compressors . and aVOC weight fractionof03'357(Inlet gas 'VOC content -used asaconservatote.estimate), the V¢TGiemissransw�reestna#edtobe,0.17.₹py.:Assucfi,theope[a€orestlmatedvatueof136�tpy oVOC fisac stimateofem';,sions.;, ... ,... ,,,,... ir onsarvative eis 5. As discussed above); thisfa -.. .., . ,.. ---1,0.,,,O,01,,,g,(,,HpWever,regulation -,adopted-into: Colorado inthe notes to permit holder etermined above;-th operator confirmed that eacf mpl lanes testingwdl be )Rp ptlsni0n5 to demonstrates q e requirements in NSPS 0000a to se mpressors. e operator to obtai;ri anextended residue Qas�analysis This gas analysis wdt be used Co hi Dint is conservative. - - ments of Regulation 7 Settiort X!LG. 16WE0773.CP2.xlsm Rod Packing Emissions Inventory Section 08 - Inventory SCC Coding and Emissions Factors AIRS Point # 006 Process # 01 SCC Code �jYGs5 ,;, Uncontrolled Emissions Pollutant Factor Control % Units VOC 799.133 0 Ib/MMscf Benzene 39.701 0 Ib/MMscf Toluene 67.536 0 Ib/MMscf Ethylbenzene 16.233 0 Ib/MMscf Xylenes 36.824 0 Ib/MMscf n -Hexane 564.600 0 ib/MMscf 2,2,4-TMP 0.447 0 Ib/MMscf 16WE0773.CP2.xlsm Fugitives Emissions Inventory Section 01- Adminstretive.lnformation 'Facility AIRS ID: CUM Plant - Pain Section 02 - Equipment Description Details Detailed Emissions. Unit Description: Emission Control Device Eminent s - Description: frgr Requested Overall VOC & HAP Control Efficiency iency 131( p - rs nn0e spiion5le to fia&ru .,,, , , ...I..L: Section 04- Emissions Factors & Methodologies Regulation 7 Information Operating Hours: Emission Factor Source Control Efficiency Source: Calculations 0 0 hours/year Service Component. Type Count Emission Factor (kg/hr- source) Table 2-4 Table 2-8 Control (%) Pollutant Mass Fraction Uncontrolled Emissions (tpy) Controlled Emissions (tpy). Gas Connectors Flanges Open -Ended Lines Pump Seals Valves Other 2.00E-04 1.00E-05 0.0% 3.90E-04 5.70E-06 0.0% 2.00E-03. 1.50E-05 0.0% 2.40E-03 3.50E-04 0.0% 4.50E-03 2.50E-05 88.0% 8.60E-03 1.20E-04 0.0% VOC Benzene Toluene Ethylbenzen Xylenes n -Hexane 2.2,4TMP VOC Benzene Toluene Ethyl bonze Xylenes n -Hexane 2,2,47MP VOC Benzene Toluene . Ethylbenzene: Xylenes n -Hexane 2,2,4-TMP VOC Benzene Toluene Ethylbenzen Xylenes n -Hexane 2,2,4-TMP VOC Ben2one Toluene Ethylbenzene Xylenes n-Hesane 2,2,4- MP Heavy Oil Connectors Flanges Open -Ended Lines Pump Seals Valves Other 7.50E-06 7,50E-06. 0.0% 3.90E-07 3,90E-07 0.0% 1.40E-04 7.20E-06 0.0% 0.00E+00. 0.00E+00 0.0% 8.40E-06 8.40E-06 0.0%. 3.20E-05 3.20E-05: 0.0% Condensate (Light Oil) Connectors Flanges Open -Ended Lines Pump Seals Valves Other 2.10E-04 1.10E-04 1.40E-03 1.30E-02 2.50E-03 7.50E-03 9.70E-06 2.40E-06 1.40E-05 5.10E-04 1.90E-05. 1.10E-09- 0.0% 0.0% 0.0% 68.0% 76.0% 0.0% Water/Oil Connectors Flanges Open -Ended Lines Pump Seals Valves Other 1.10E-04 1.00E-05 0.0% 2.90E-06 2.90E-06 0.0% 2.50E-04 3.50E-06 0.0%'. 2.40E-05 2-..40E-05 0:0%. 9.50E-05. 9.70E-06 0.0% 1.40E-02 5.90E-05 0.0% NGL (Light Oil) Connectors Ranges Open -Ended Lines Pump Seals. Valves Other 2.10E-04 ' 9.70E-06' 0:0% 1.10E-04 2.40E-06. 0;0%. 1.40E-03 1.40E-05 0:0% 1.30E-02 - 0..10E-04 68.0%- 2.50E-03 1.90E-05 76.0% 7.50E-03 1.10E-04 0.0% 28.65647382 0.077806125 0,13282536 0.03192589 0.072422259 1.110414886 0.000879242 0.234493278 11_08315092 0.030092224 0:051371411 0.012347627 0.028008965 0.429463019 0.000340055 0.234493278 0 0 0 0 0 0 0 11.77702430 0.16644704 0.32897351 0.08540227 0.193278635 2.352100236 0.001612275 0.036299392 0 0 0 0 4,233255283 0:059829444 0.118249636 0.030697874 0.069474069 0.845463205 0.000579533 0.036299392 0 0 0 0 0 27.37987073 0.119675618 .0.580861406 0.021029945 0.054947065 0321938892 0.115696363 59.24329269 0.252457284 0.174964154 0.045503617 0.118891907 0,696596423 0:250338416 Section 05 —Emissions Inventory Pollutant Uncontrolled Emissions Controlled Emissions - Source VOC 99.95 tpy 42.97 tpy Standard EF Benzene 993.42 lbyr 413.19 lb/yr Standard EF Toluene 1273.53 Ib/yr 500.96 lb/yr Standard EFF' Ethylbenzene. 325.66 lb/yr 128.15 lb/yr Standard EF: Xylenes 769.19 Ib/yr 304.86 lb/yr Standard EF: n -Hexane 8318.22 lb/yr 3193.73 Ibyr Standard EF: 2,2,4-TMP 505.66 lb/yr 233.23 lb/yr Standard EF. - ERA -453/R-95-017 Table 2-4 - EPA -453/R-95-017 Table 2-4 .FAA -453/R-95-017 Table 2-4 - EPA -453/R-95-017 Table 2-4 EFA-453/R-95-017 Table 2-4 - ERA -453/R-95-017 Table 2-4 - EPA -453/R-95-017 Table 2-4 Review Regulation 3, Part B, Section III.D.2 to determine is RACT is required? _ Review 40 CFR, Part 60, Subpart KKK to determine if applicable to this source? Review 40 CFR, Part 60, Subpart 0000 to determine 080.5380 and/or 60.5385 is applicable? Review Section.XVII.F to determine is LDAR is applicable? itieeeI Reoulatory Considerations Regulation 1 Section ll.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 atmosphereof any air pollutant which isinPorn of 20./ opacity. This standard is based on 24 consecutive opacity readings takon at 15 -second intervals for six minutes. The approved reference test method for visible emissions meaurementis 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 commercialpurposes 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. Part A-APEN Requirements Criteria Pollutants: For criteria pollutants,. Air Pollutant Emission Notices are required fob sac h' individual emission point ina non -attainment area with uncontrolled actual emissions of onaton 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 en APEN since emissions exceed 1 ton per year VOC TPY Uncontrolled Controlled 0.496710449 0.2065973 0.636763024 0.2504825 0.162831777 0.0640754 0.384592801 0.1524311 4.159111544 1.5968651 0.252829933 0.116616 Fugitives Emissions Inventory Regulation.3 Part B —Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled VOC emissions from this facility are greater than the 20 WY threshold (Reg. 3, Part B, Section 11:0.20) Is this source located in an ozone non -attainment area or attainment maintenance area? If yes, Is this source subject to leak detection and repair (LIAR) requirements. per. Regulation 7, Section XVII.F or XI IG'or 40 CFR, Part 60, Subparts KKK,. 0000, or 00000? 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 °Zone NA area designation). Since the fugitives will be in service after the date above, this source is considered "new or modified." This facility is subject to NSPS 0000a. Following the leak detection and repair program pet NSPS 0000a satisifies the RACT requirements of Reguletien3. The permit will contain a condition reflecting this. determination.. a' g 31)7b Regulation - Is this source at an onshore "natural gas processing pant" as defined in 40 CFR, Part 60.631? Did this source commences construction, reconstruction, ormodification after January20, 1984, and on or before August23, 2011? This source is not subject to NSPS KKK becausethe facility will commence construction after August 23, 2011. Did this source commences construction, reconstruction, or modification after August 23, 2011 and on or before September 18,: 2015? Source is not subject to NSPS 0000 because this is a new thatfacility will commence construction after September 18, 2010. `Yes: i�• , Regulation 7 Is this source located in an ozone non -attainment area or attainment maintenance area? Is this sourceat an onshore 'natural gas processingpanf' as defined in 40 CFR, Part 60.631.o Facility is classified as a natural gas.processing plant Therefore,this source is subject to Regulation 7 Section XII.0. Is the facility classified as a well pmduc4'on facility or natural gas compressor station? Since this facility is not classified as a well production facility or natural gas compressor station, it Is not subject to Regulation 7 Section XVII.F, ' " Yes;, . Regulation 8 Is this source at a 'natural gas processing plant" as defined in 40 CFR, Part 63.761? Is this facility considered. a "major source" of HAP as specifically defined In 40 CFR. Part 63.761 for sites that are not produution field facilities? If you repond 'yes" to both questions above, further review ifthe provisions of 40 CFR, Part 63.769 "Equipment Leak Standards" apply? Source is not subject to MACT HH because the facility is classifiedas a synthetic minor source of HAPs. tit II lI ii Yes- l( (? 91 NSPS 00000 Did this source commence construction, reconstruction. or modification after September 18, 2015? Is this source eta well she, compressor station or onshore "natural gas processing pant' as defined in 40 CFR, Part 80:54300? This facility meets the definition of onshore "natural gas processing plant" as defined by 40 CFR, Part 60.5430a. Therefore, the fugitive emissions at this facility subject to NSPS 0000a. �"; ..• Yes Section 07 - Technical Analysis Notes Add8tone(pfnFes: 1. With this opphcatithe operator s modifying the fugitives source toincrease thecomp vent count: and emisvionsto account for the installation of Sun second natural gas pr°mssbrgdraio at this facility. 2, The operator calculated VOC emission.ssocratedwith the mndeneatelight atservice;,;water/all servlceand heavy oilsn rebound:cootocweightcorit & cethis lathe most censervativeestimatefor voc,IdCtRtmined it was uhnecessaFYfot theopel'ator to obtain an nital-s ample forthese servicesto ver'Fyt 3.Thegas serulca eompanition isbased ort [epfesentat�lveinle£ges samples. Since the`entire gassarvic s based -on ial tgas, the emisslonscalrsltafedare fiknly conservative:H wever,'the op atonsassuming innsthen 500%VOC andthe sample is not deespeeifie::Asaresulf, mtteltesting will be.incktdedin-thepermitrequmng sample he obtained from this service todemoostrate compliance with the limits contaiiredln the permit. Annual testing will also be required, 4. The NGi ti h€nil service HAP compos nobs based en informatron providedvntfi thefirst ssuance ofttpermhGVOCdalue used in thin eppiiatton issb�xlymorn ervatioollwnthiervice HAP in the or%irral appiiration,.Sinec the:opneot r ming:loss than 100%VOClorthisserylee. intaltestingwdfbe included in the Fermin u regmnng a samplebeobtained from this rnesrneta demonstrate compliance wish the liml�m the permit.: Annual tooting,will. also be required for th ssery ce 3, Asdlvcuooed above; this facility ssublect'to NSPS 00000, However ih s federal regulapon has not been adopted into Colora do state- egulation- As such, this regular on will be adarassed in the.hotesto permit holder 6. Colorado Regulation 75eit on Xll G. 1 requires the foliowmg Forfugitice VOCerrissions &4m leaking equipment, the Leak detect °n and repo r ([UAR] program as ' provided at 40 CFR part 60„Subpart tiff (tvly 5, 2016) shell opply, regardless of the date on construction afi,the afferzed fa'aiity, voless'suptectto appfica61eiDAR program as provlded:at 40LFH. Part60, Subparts 0000, or 00000 (July 1, 2016)."As discussedobova, this soerceissubiect to NSPS 00000. Following the rend€rements of NSPS 00000 sat stles the requirements under Co)omdoOegulatien / Section XIi:G. 7. According to Colorado'Regulator 3 PartASeehon i.B 25:6, Fuglt ve emissions shot notbe considerediiin h,ourre is the a oJarsource forthe purposes of this Section h8.25.b., unless the soorcebelongsto one of the followingwtegnr'es nfstationary Sources:"ThiskdRy isnot ncudedtnthe lrscedsour<esand therefore furtive emissions are not Included whendetermie ng whether or riot this fatilityrs a maj rsource. 8. The opereterdid net provide OAF cnnopos@ran foethe heavy o tar weterInilservices.Thmwas deemed eeeeptabiefer_the loll owing reasons (j This facility is not close to the individual ortotal HAP major source thresholds. (")These two srevices contribute less than l tpy ofVOC tethe total emissions fromthis source. As such, the HAPs thatwov Id resoltfrom:these s 9. The operator submitted' an O&M plan for fugitives with this application. According to the second paragraph on the first page o f the fugitve O&M plan, 'If she flocilitphoo NSPS or MACT requirements for Leak Dete[LanandRepair(e.g., NSPS KKKan-Oot 0000 and/or 0000a and/orother( Menthe operator snailbliowthe federal ". requirements and this O&M Plandoestmt need to be submitted. This sourceissubject _tcnllP4 Q000a asindcated above. As'a result, the operator agreed toremovethe O&M plarttram the a pplication as they win fWiowLOAR:requirements per NSp5cow, Section 08 - Inventory 5CC Coding and Emissions Factors AIRS Point # Process # 5CC Code 009 01 Uncontrolled Pollutant Emissions Factor Control % Units Varies by Varies by component type component type Standard EFs - EPA -453/R-05-017 Table 2-4 VOC Varies by Varies by Benzene component type-. component type Standard EFs - EPA -459/8-95-017 Table 2-4 Fugitives Emissions Inventory Varies by Varies by Toluene component type component type Standard EFs - EPA -453/R-95-017 Table 2-4 Varies by Varies by Ethylbenzene component type component type Standard EFs -EPA-453/R-95-017Table 2-4 Varies by Varies by Xylene component type component type Standard EFs - EPA -453/3-95-017 Table 2-4 Varies by Varies by n -Hexane component type component type Standard EFs - EPA453/R-95-017 Table 2-4 Varies by Varies by 224 TMP component type component type Standard EFs - EPA453/3-95-017 Table 2-4 Amine Unit Emissions Inventory IN.,. ID: Arena p5 Information Am Inaiy Make Model: Owlan Panty: reelmulaten Pump Menetbn NUmber Pump Pumps Make Destlgn/Maseeerelet4n Pat ...Equipment flash l'ank amgerBurner StrkeIng Gas 4mee enoXdpmemoeerkelon Emission Cntrol02Wae 5M4,p4Xn: ro and flab eamer. Ono(1)M6mymiethenolanew IMDEgl neural kes weeenegunit Make:Teo, M4521,1e0,sad5Trvanber. TVD)whhedaRn5Pedty ota0 MMad Pere, -MEG ambelona unit l2 epulppe4whh 3(Mehe Tan,Modal:Ten) eleereareenamine sumdal kWh 0452104 erwIty5rCOS Belem Par m,nmo. Thaemwwwie q ippedwubaaill Imre,. tank and rebil5ihawk Embal5m lam thertlhwm aremmedtoan er-cwmd condenser, mm then tothe Th5rmdrneWr. Cmlssemiromtbetlaabtankammuted directly twee Vapor e, ry Unit IVSDI.A.a sewn ry control device flan tank emissions are mural tot, Thad Oxidizer. 20'marv47211em-ame148202lvennend nklnp�=aml kequ.74: rm71-W7 brwghput le,rs.4MMccrt is yeear Potentelm[me(PTELTbreughput= a1,ssD MMsdceryear Sean ry Emissions- embus -ten uwIcofefornir. Pollution Cont. SW! Vont Caere Parra, control device Secondary control del,. Secontlarkwontroldekeeperadoe it'll Vent eas Hon.', Value elll Vent Weste Cos Vent Pate kramml Primary controWawke Secondary control device Reek Tank Ws Heade; Valet PlestitenkWeee Wee,. welontp Emssmm Netors&MHM1oddoe. !wen Unit ineteas Input Pressure MI. Gas InlautkeePewets Requested Flash Tank ie5mpenare n Amine ulam Pate Flee Tank Pressure Lean svmneweitln% See VENT Pelment nw pal ke Ibmn l ...wed 1041 VOCToluene MOMS ..r 3 .1Wee ,;.0.0598.6 0 keyeeaen5 000510218 Wenm ¢1aiTss.,'.t.1333i3,m??:.': . 4 106246-06 H25 0.0741604 0 Coneol Scene, nwl saenatio Pollutant uncontrolled (Ilk/el Conoolled(ib/hll m5krol&d 0/5rl VOL ........ .® 0 ;..,_ 130,302 1.3mgee Benzen 0.00e0-072 0.00446.1 Tow tie Earobenaene 0 0.0002007S 0.0002.978 *lanes •000044 ..� 0.00008002 0.000460342 ',Hexaner3=�✓ uzEa0.00506084 EBa1adW n .: S524005O§.11 0110E14 0..50018343 xu 040 //l///$k�`,FG.:'''.' 3 r„'3ei009LT)g333333333317++' ' o.00b6e51s0 0.00018310.3 Doyle, rolled ro lb u) Mesta Heat Combueedl lib/Mead) IWakteee an bun m al ampWU Vent PrIrtrawContr, 04,2304 554 MM./yr 5[111 VentSecondary Ikee0fA0 Waste Gas .ROI Vent k 0.00 ..Wee still Vent kmnaary Controle auwD MMerie Sour Plash Tank PrIrnary [ant. Gas 8,14,0 AWISW/yr Flesh ienkVetondey 8,1450 MMUT/yr azt5i0SCorndeee Hash1ank Primary Coneol:0.0 INMscf/yr Flee TwfWeendery Conan, 500 Wed/yr EmIssion factor Source 0.0000 .000 6000 Pollutant co trel wiled atu) (Waste Heat mmhu 5d) tem el /525200 Cornbusted1 Emisven ewer Source o. 0.0000 0 NCO Prl kw, Una. re Ib/MMeel tem el 01 00 (W0l 418 (Waste Haw,. Emission Fedor Saume 0.0000 0.0e1 0 CO (lb/ de rol PS/v 5224 Emission Factor Soul, 2.B6,.02 1_307E-03 >yene3164.0 2396366 e,x 1216E.. 2.734e02. 27.0 .67307 4406.6 Amine Unit Emissions Inventory Section 03 - EmissFons Invent, Old operator std WSW? RequestedBuffer(%): cnmaaeolwnun ItonaryealUncontrolled Uncontrolled Controlled Imns/yarl Imns/yearl UncontroOed Conewiled (tons/year) (mn5Naad PAR10 NOFt CO 303 000 0.00 0.00 .00 0500 0.00 0.00 0.00 .00 Mao 000 0.00 .0 PAO 10.75 30.73 3.75 341.73 Hazardous nnPollutant Potential to Emit Uncontrolle(tons/War) Actual Emisslons Uncontrolled (Wns/Vearl Petruested Permit WI. Uncontrolled (466/4554 Requested Permittlmil3 Uncontrolled(5/4/ Controlled leryn Benzene Toluene Ethylbenrano %yleo n-llexerre .47IFFIP 2030 30.30 0.41 2030 .1 .599.09 .1.00 15,9 1639 023 13,9 P31 2138170 .171 137 1.74542 127 ¢03 1735.19 54.76 142 1,42 2.84,02 L92 2.64602 .92.61 2.11,04 E.31,04 4.23,00 2.11,04 4.29E-06 0.42 Regulation • aclonllwl- Eceptas provided In paragraphs 2througi 6b ere of any air pollutant which is in city. This standard Is based 24Consecutive taken at 1ssecondl peratls for six mi.... The approved reference testme mfor eem572475 measuremen75EPA Memod3(40CFR, part 50. Append12*(2I,, 1491414 ansubsecmnso(4 n an o rseul on. S4ction II.A.3. Flare or ustIon of ar oMer flare for. of was. ge.sex 20(5)la 46 cauekemhslom into PMe atmosphere ofany eft poll uatontwhlrn kin excess ofsv%opaciry bra purled or periodsaggegeting more 71565067)626516567 W., co secut4e mmue, Paeuielon2 SectWn LA- No on. w4areverloated, shall cause or allow the emissionofodorous.P conteminants from anysinglesource such arm result In detectable odors which ere measured in exces of We following limb: For nanlytor rwldendm al ormnernalpuryoses 5th a violafonlfoaon are detected a5er Me odorous an has been 0nured WWM seven mar more volumes areas otndorralee alr. Ragulatlnn3 Pert PP2N Requlmmams Criteria PollWants, rerke.. pollutann,nir Pollutant Emission Notices are requred for: eachi..Wel emlsslon poWtin a nowaeainmentarea with uncontrolled actual arnIsslons of one ton per year or moreefany indleldual criteria pollutantipolluWn. are notsurmmd) for WWII the area is norearelnment Appliont la remdradto file en APEX since emissions exceed 1ton per war VOL Part 0 —Construction Permit Weln1Wforn Applkent is required m abdna permit since uncontroad V06 emissions from., Weill,. are graterMan me 2aivymreshdd(Reguladan 3.1.. e,5ectian n.0.xa) NSPstu According to465.5ag2)'The apply m aellMldo mm ph(al of this motion which or modfficationaftaWanuarylp, WS, and an Or be.. August 23, 2011,1M10 ntemrthee.dxn.,ssa result, the amiosw..r.mn6anrc lsnor subject coma subpart. 73PS0000 05750000 appiea io amine sweetening unit mrm/25/11and on orherorem (a /44/15e§60.49601/fi)amine after 05/23/1uw aerewit, NPs 0000 bent apeableo this source. 73Ps oa00a mo.� madmen, or reconswcwo araermyu/u. I nu amine emewmcommence con:truaon duet ®/2a/ssu uamWes m ammo sweetening ono amisappgone mar were According. 460.5365e(gl(3F "Facilities mathave a designopanry leas man 2 longmu per day (y/o)ofhydme de(HA in gasleepesse0 as sulfur) are required to comply with g)kee p 6 , grequlremenn p tad m 4605ax3a(c)bu arena q mcomplywim556a59nathroupi60.E9maand §45o591W(gl end 50.5415a( This source well haves design opacity less man 2long tons/day H2s in we acid gas based on the Infamaoon submitted In theappnation.Tnb source5411 be required Ay aa(clm keep elite of the eq wrentan y emonstratingWattle facnlrys desipi capacity is less than 3LT/Oof H2sexpressed as 50141.Noo4er requirement ply for Hamden We process on In me application, mesas processed 5y the amine unit will poWntleW 7a.9aef on5is concentration the Proems ne e n mm Ha emissions of 1..3.75tons/yar n me flesh tank and me vent weste.2streams. The fomwin6 nstrateameconversionofmoyamem lens toper day: (18.5 tons H25/year) • (20001bs/544)•11long ton/2042125(92755r/265 den)e 0.0459 long mm Ha/day The calculation WoVeaermnstarn me amine unitwni have a dnlgn.Pacdvless than 2l 6ma/eel,Ha. Section n]-Initel and Pe.iodieamollne naietting Wquiremerrts Was the extended sour gas wmpe used In Me Process models...specific and wetted wimin a year ofeppbadon submittal, ktr _'! _ notes In Section aefor additional Information. If no, [Ae pennlewlllcon.n "InWal Compilance"g requIrementto demonstrate compliance Does Me company uesta device ater Man 95% far a Owe or combustlon If yes, mepermltvNlescontain not niitlal omplianle14515onalt0n to demonstrate We6esaunbn 55251iq of the combustion device hued on inlet and outlet concentration sampling Fe 09 Section 09 -Inventory Srsmdirrc and Eminion Pawn 0,5 fitfle.7.20ntwWWWse 105 sed*FA2n pp S42j � 16B5F wwW AXi8 '!MN 11n,rigpre5'69, [54.16 vumedme5aeon2ntotthe :. Uncontrolled (roll ControlledW.18366035 1.113376332 0.3.673 0.0.310 SIM Uncontrolled PolloWnt Units 5 XOIV/0lcto m b/MMscf 0IV/0I a/0001 NO5 0.0%/1.04s51 VOC 0/WlMscl CC 5000 0.0%b/MM f Fiemene 0.445 38.0%e/MNlscf Toluene Oa. 56.0%b/0004 Emyltenaene 0050 98.0145/0041 xylene 0.084 .0% /040107 n.Hewne arm 53.0%b/00201 224 4632E-06 90.0,2b/MMscf 722 0.911 35.0% /MMscf Glycol Dehydrator Emissions Inventory Section 01 -Administrative Information 'Facility AIRS ID: County Plant 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 Reboller Burner Stripping Gas Dehydrator Equipment Description MMscf/dry flash tank, and reboiler burner One (1) Triethylene glycol (TEG) natural gas dehydration unit (Make: THO, Mudek TBD, Serial Number. TBD) with a design capacity of 250 MMscf per day. This emissions unit is equipped with one (1) (Make_TBD, Model: TBD) electric driven glycol pump with a design capacity of 20 gallons per minute. Iris dehydration unit is equipped with a still vent, flash tank, and reboiler burner. Emissions from the still vent are routed to an air-coaledccndenser, and then tothe Thermal Oxidker. Emissions from the Emission Control Device Description: flash tank are routed directly to the Thermal Oxidizer. Section 03- Processing Rata Information for Emissions Estimates Primary Emissions- Dehydrator Still Vent and Flash Tank (if present) Requested PermiE LimiC Thfoughput= `_'_______S3c..2SO...e4�MMsct peryear Pmentialto EmR{PfE)Throughput= 91,250 MMscf per year Secondary Emissions -Combustion Devke(sl for Air Pollution Central Still Vent Control Condenser: Condenser emission reduction claimed: Primary control deuice: Primary control device operation: Secondary contra device: Secondary control device operation: Still Vent Gas Heating Value: Soil Vent Waste Gas Vent Rate: Flash tank Control Primary control device: Primary control device operation: Secondary contra device: Secondary control device operation: Flash Tank Gas Heating Value Hash Tank WasteGas Vent Rate: /yr /sof set 50 hr/}}yry iilryi?li hr/yr Btu/scf scih Control Efficiency% Control Efficiency% Control Efficiency % Control Efficiency % Wet Gas Processed: Still Vent Primary Control: 91,250.3 MMscf/yr Still Vent Secondary Control: 3.0 MMscf/yr Waete Gas Combusted: Still Vent Primary Control: 0.0 MMscf/yr Still Vent Secondary Control: 0.0 MMscf/yr Wet Gas Processed: Flash Tank Primary Control: 91,250.0 MMscf/yr Flash Tank Secondary Control: 0.0 MMscf/yr Waste Gas Combusted: Flash Tank Primary Control: 0.0 MMscf/yr Flash Tank Secondary Control: 0.0 MMscf/yr Glycol Dehydrator Emissions Inventory Section 04- Emissions Factors & Methndoloeies Input Parameters Inlet Gas Pressure Inlet Gas Temperature Requested Glycol Recirculate Rate Hash Tank Pressure Flash Tank Temperature Dry Gas Water Content ILL VENT Control Scenario Primary Secondary Pollutant Uncontrolledllb/hrl Controlled(Ib/hr) Controlled (lb/hr) VOC Vr- 45.6081 0.912162 0 Benzene B.,.'' 43492 0.096984 0 Toluene 5.3043 0.106086 0 Ethylbenzene 0.7523 0.015046 0 Xylenea 2.0278 0.040556 0 ',Hexane ' _ ., 5.1520 0.023056 0 224-TMP -'- 90004 8E-06 0 Hydrogen Sulfide (H20) ,,,, „'0.0001,. .. 0.000002 0 FLASH TANK Control Scenario Primary Secondary Pollutant Uncontrolled (lb/hr) Controlled (lb/hr) Controlled (lb/hr) VOC 30:6457, , %,, 0.613914 0 Benzene 0.0334-. ",f. 0.090668 0 Toluene ;-9.0225 - ':''' 0.000446 0 Ethylbenzene 0.0017 0.000034 0 Xylenes 0.0031 6.2E-05 0 n -Hexane 0.2723 0.005446 0 224-TMP 0.0001 i0.0000020 Hydrogen Sulfide (H2S) ...0.0001......... 0.000002 0 mission Facto VOC Pollutant Glycol Dehydrate Uncontrolled (Ib/MMscf) (Wet Gas Throughput) Controlled (Ib/MMscf) (Wet Gas Throughput) 8.424 Benzene 5.3904E-01 Tolu 5.8806E-0 078 761E-02 Ethylbenzene 8.3242E-02 Xylene 22421E-0 n -Hexane 1.5733E-0 224 TMP 5,5200E.03 2E-0 1040E-06 Hydrogen Sulfide (H25) 2.2000E-05 Still Vets Primary Control Device 4.4160E-07 Emission Factor Source Uncontrolled Uncontrolled Pollutant (Ib/MMBtu) (lb/MMscf) Emiasion Factor Source PM10 PM25 Non CO (Waste Gas Combusted) 0.0000 0.0000 0.0000 0.0000 Still Vane Secondary Control Device Uncontrolled Uncontrolled Pollutant (lb/MMBt (Waste Heat Combusted) (Ib/MMscf) Emission Factor Source (Waste Gas Combusted) Flash Tank Primary Control De Uncontrolled Uncontrolled Pollutant ilb/NIMBtu) (Ib/MMscf) Emission Factor Source PM10 CO Section 05 - Emissions Inventory Did operator request a buffer? Requested Buffer (%). Pollutant PM10 NO CO (Waste Heat Combusted) (Waste Gas Combusted) 0.0000 0.0000 Flash Tank Secondary Control Oevk:e Uncontrolled Uncontrolled (Ib/MMBtu) (Ib/MMscf) Emission Factor Source (Waste Heat Combusted) (Waste Gas Combusted) 00000 0.0000 0.0000 Criteria Pollutanss Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) PM10 PM25 Nox CO VOC 0.00 0.00 0.00' 0.00 0.00 0,00 0,00 0.00 0.00 0.00 0,00 0,00 0,00 0.00 0.00 0,W 0.00 0.00 0.00 0,00 384,34 38434 7.69 384.34 7.69 Hazardous Air Pollutants Potential to Emit Uncontrolled Ms/year) Actual Emissions Uncontrolled Controlled (Ibs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (ibs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 TMP - Hydrogen Sulfide (H29) 49187,31 49187.31 983.75 49187.31 983.75 24.5937 0.4919 53660.17 53660.17 1073.20 55660.17 1073.20 26.8301 0,5366 7595.80 7595.80 151.92 7595.89 151.32 3.7979 0.0760 20459.29 20459.29 409,19 20459.79 409.19 10.2296 0.2046 14356,46 14356.46 287.13 14356.96 287,13 7.1782 0.1496 5.04 5.04 0,10 5,04 0,10 0.0025 0.0001 201 201 0.04 201 0.04 0.0010 0.0000 Glycol Dehydrator Emissions Inventory Section 06- Regaleeonn Summary Analysis Regulation 3, Pass A, B Regulation 7, Section XVII.5,0 Regulation 7, Section XVII.8.2.e Regulation 7, Section XI I.H Regulation 8, Part E, MACT Subpart HH (Area) Regulation e, Part E, MACF Subpart HH (Major) Regulation 8, Part E, MACF Subpart HHH (See regulatory applicability worksheet for detailed analysis) Source requires a permit Dehydrator is subject to Regulation 1, Section XVII, 8, 0.3 The control device for this dehydrator is nor subjectto Regulation 7, Section XVIL B,i Dehydrator is subject to Regulation 7, Section XII,H The dehy unit meets the benzene exemption You have indicated that this facility is not subject to Major Source requirements of It, You have indicated that this facihty is not subject to MACT HHH. Section 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 Parer application submittal? If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limn Does the company request a control device efficiency greater than 95%for a flare or combustion device? con. If yes, the permitwill contain and initial compliance test condition to demonstrate the destruction efficiency of thecombustiondevice based on inlet and outlet concentration sampling Section 08 - Technkal Analysts Notes F. As dfneusiedabuve,thewet gas compeaiflon is based on sweet gas from amine unit as presided by they ProMax'medalosedtwestimete amine umt eec se eeoeuThe wet gasstreem w the"Treated: Gaaoutlet' stream inthe ProMeo model. Since the input for the GlyCatc modeiisnotbased on a site speeMesempie,.the- operator will here-quit-ed.. obtain a site specific be usedin the tlyCoc modelto demonstrate: ntnal'compliance with the emisaion 2- Theoperatoc4s requesting a 98%controler'fcciencyfortbettiermatoxidlzer thaele Used to control oheStillvent andttushtant.oinen t lis control -value kgteater rianthestandard95%aontcolgraStr initial testit wit€be.iegmred todemonstfatettietbermatnxn010er. is capable of achieving a 4495 destruction efficI ou'y when corrtralfitigstll€ventand flash tankroici ans'from the, dehydration unit. A backup control deviceisnot^ listed for thetherriatoxidl£erthat is used.content bothstRtventAndflash tank ernIssi one Accac ingtc the operator, the Owl hydrator unit shnt down irrthe ever[ therun 1714 1 eeasnot in operation When ehetnetmal?xid ier is back in operation„the defiydraion hint will aontinue'eperanup asweil,Since theglymlidohvd atl nong Shuts down when the titerrini bergs 4, Intheonginetappliation, the operator requested em'sstons reductions assoclatedwiththe use ota condenser. Tnis was dent onstrated bytising the "Controlled 000 nertnot Em issionsTerealn IR the Glycele s{mufatlon,wince takes into account both thetonderoerand the combustor -5.0e LReoperator isalreacty',questinga 98%contYAlefij<1enty eoac Iatedwen the t0ermalolitgter 001,InitaltestingWill be mouledui the permit to=aasessthe ebilly ofthe'E0 eleettliarequested-etficency-Additfonatvcngrtexity would Wadded to the Initial testing requirement due to thecontrolteque3tasssariatedwithtbe condenser.. ordenSe sitriph.the-comgAente demonstration for thitunn, ttwasioggested that a'control efficiency only be claimed for the To end not Rhetgndenser. Ths. "s done by using ahe nMCoctrollod RegeneratorEm ssloM"# gent the G1Catbsimulton nob implyapplyingthe regoesfed98%contmleffidency-The rainedem emissions resulting -from this calculation strategy did not shaegothe€atility efassifiaeyton or theregulato appbtabdrtytor the dehydrator,Further, this remavestherequirement to moo nor outlet-condenser-tenperatute and does not reso0m a limit On maximum condensertemperature. liad on this information, the operator.. agceedtoanlyreques000uncrole/Sicontrol effimenva*€urtheTO:: 4. The 'npuokatie fan coop recureaadpressurej85Fand925psg) of the wet gas stream inthe.GlyCalcslmwon ulaton do not match ltetemperaeureand pressme(94.tr and 985 psig) oftbe PreMaxstream usadOo eat mate west p00 nmcoStion,/3teated 6aS ea However devalues usedby the operator mthe GlyCSIc simulation r molt fo a cgnsefvebve estimete Of emissionsand ere therefore BooeytaAle, Itshould'tie{rher tedthat,the},vetges temperature a nd presavrewill betnomtared and recnrdedbyt€re,opersconcea weekly bas s: Tlt eeage o€drege vaiueswll be used on a monthly basis idthe stcnol lnnestimatee?nissioos and .. 6,According₹d the APEN; the rebotier burner assotietedwph thisd Isydratien unit is rated at l-OMMBm/hrTins reboilerburnerrs APEil excmptper Colorado Regulaioc3 fooawmrgAPENtexemption .'Each individual piece off etturningequipment, other thou smokehouse: genera;ars and internal combos[wnengmes, thncuses gnse0us fr .l eon (ve melli00Brnlsh therm) units per hour. [See defidran FJ:elhurmng egUrpmeOt,--.. rommnwdrovisionS'Aegvbebnnl:^ 7. Secondary emissions noted with the combosraagbf stilt -vent andfiash tank wastegas ace.edeounted'for with point 0221sa resuR, Section 03 of this worksheet onlypmvdcs.information concerning, devices used'. for she stiltvent andflash tank :dot -Tenth theassocated ontrolefftesencies Tbeactual combustion calculations are availableinthe worksheet ass tit€atedwithpoint022inthaworkbook- B. The operator specufeda leangly of wMer stooetoo4T2gc m -the GiyCale simulation. Accommgtta.the.GRw-GiyCalse smanval,'Typl ai water contentsior lean T€o:ace l wt%ta 2 wr%8 .r units withoutr gag-" (Page 111,TAsa result, the specified glycelwaten cannon' acceptable since is. wnhin₹peo pectedraage. - AIRS Point 5 016 Process 0 01 ecA-Sett. ll,D 1 k_which asdesignratelessa Section 09 - Inventory 5CC Coding and Emissions Factors Uncontrolled Pollutant Emissions Factor Control% Units PM10 0OIV/01 0.0 b/MMscf PM2.5 tSIV/01 0,0 b/MMscf NOx 0.000 0.0 b/MMscf VOC 8.42 98.0 b/MMscf CO 0,000 0.0 b/MMscf Benzene 5,390E-01 98.0 b/MMscf Toluene 5.881E-01 98.0 b/MMscf Ethylbenzene 8.324E-02 98.0 b/MMscf Xylene 2.242E-01 98.0 b/MMscf n -Hexane 1.573E-01 90.0 b/MMscf 224 TMP 5,520E-05 98.0 b/MMscf H2S 2.208E-05 98.0 b/MMscf Oehydntor Regulatory Analysis Worksheet 54Hpggg=ylT74 a -/P 3Pm. A and EN and Permit Raouinmmr6 You ha.indica. that...Is In the...tea.. Amo ATTAINMENT actual emissions from anydaripoluana from this Intl..source greater W 2 than IPegWad3,ASe onn cdon 2 ..alll.D.Ll..al Nally vmmmllal WCemiss4. ae 74atertlan5 IP,, NDagaatar Man 10.2.CD emiss,°4. maW ter Man to 11. Weguad.m 3, Patter Semen IID3)2 IyauhgveMdkaredMamma. b'744 N mAa6mm Arm NON-AUAINMEN? I Ara urmntmllad aWsslons from any Mt. Pdl.ana from MbiMMdual source *ream than than l TPy (Pegulati7m3, Paa0.5e.Mm II.O.1a12 total • Are tal facility uncontrolled MX...scions,. the greater Nan 2.2, ND3greaterthan 5 m'or. emlvlons greater Mon 5 WY(RegulatIon 3, Pan3...0n IfD2)i I.erammuires a pm. Cobnda 477447 4 7.Sa44 NII.H 1. Is W.Wy4S 4.tual gas dehydratorlpmled In Mebhrom on7d ar any man enr/ma ma(Peg 2, S4N and 2)1 Is...ye°, natural gas dehydrator looted at ell and *...radon and production natural gas compressor natural gas �rc(Reg 3. la the um°factual umbeedled em7dms of WC firm 74271le dehydator...44d7*It77, t a single sationary...egualto. greatr+lun 1.5vylgeg],Setion XllN3 h)7 m 4. Are actual ...Haden.losofVDc from. iMtddual glycol nerunl gas dehyeamequal[°. greater than 1. O.7. Section Xll.H.3.a] Sedan 1(.11— Emission fledlvlms ham glycol nanaal grid sour® Requires an APEN.Gom Mere.[quasdo7 Source RalWres P Na velndlca1d the analnmentsatus on the Project Sha t Co ntinue -You have Indicated the f4dllrytypemtM1e PropawmmaryS cto nest subject n Go the Dehydrator 5 subjem Regdatn 7, Salon MIN MAST All a12514 L 1stt.44770,t«m®adat an dl and natural gas prducdonramity that meets either of Me foll°wingcdte75, Ives lCwndnue-source is subjectto MAQHH requirements.yeuhay. Indlcatd the source category ontlre Pra)e¢5ummary Sheet a. Aradl.W that p.a., upgadmorNor.hYdree.Mcwlquld5' (6G.750(all2lli65 Ah6llty MM...., Upgrade or sturesnarmal gas pdor to the Om at whi5 natural gas enters Me natural was Innunl.. and storage source ragcry or is dm.. ma irmIpnd b. user' 263.2631.1131)2 2. Is Me dehydrator looted at a 7dlity that is a=Sorsa.. f. IMP., tM6CTHH245546 a appliobilitvsecdo. I., toNIARNxAre. Source Peoubemeateeadan to determine MARHN P ahgM x °nand GasRdua6o Feceh7s • M. dehydrator a niethylere glycol (TED) dohydrad...nit I43.756(b)mn cop.. 7.26 Is the actual annual average nava. of natural gas... glycol .h(25dehydration udt less then 3.001]4] MMs7fper day 163.264(e)(1)(02 26. .dual annual average emiaims ofbemenakorn the ghml dehydadm unl[pr000s went to. atm.phereles than 19o-t21b/yr (63.T6alelµ150, 3. Istleunit amed ITh deMunkmeatstlhebenene,.m.Ionboundary area, Iva on alma- ounavelndlatd Me dehydrator ape on Me dehydatr lone .y t pan A. General prvn6ors per 463264 (a) Table 2 363.755 - 4,174 2 Cmtrd Sad a ids 0o 1 144417 563333 - Mmltdng Standards Oo Not Apply 453.764-Pemrd4*SISg 563.715- Reporting Standards W Noe Apply MelarSoOrm Reaulremer, 1 7711rydvea76114µ5122 actual annual avenge MM natural gas lem Wnad5 ad/day AND a 154114? ide we. annual average hydmaN rboo lewd man ughomIessm249.7 ,Small a,aaa Da. ....IMO tl. glycol 22747 don witless than 3D01747 MMadpred.y(632617 24. Are actual nge annual avesmack.of...eft.the &WO, dehydration unit proms Yens to atmosphere the aosphere Imo Man 3,36521b/7(63.75D2 sm.fl 4.M Raguimeams 418 cals.; of theism.glycol 44l 413655 rmitcommence on . before August, 2011(53.7441 )7)1)2)ad (E)? a, Tar Mzsmall EeM.lzmne2dedbe required m meet the BM emission Unlit *Yen try the eppllmbleeguauml Iyoo ...kat. ihiafidilry 1 no642474,7 to 7ajorWmm tombs.. of MAR AU. Subpart A. General provisions per 463.364 (al Table 2 563265-Emisslas Control Standards 463.773-Mmit.lrg 463.7]6-Pemudkeeping 583'32]5 -Report. 40 C44 Port63.5ubaart415! 1, *44 G.s Tng Ifl,Voad Stn. Foal.7.3442 H the7mlry wide acnall annual avenge mural az throu6hpm less then 0.66g4as1MMsa% ay and glycol dehydamathe,nly HAP.... sour. (63.12]010)] 1 5mall or lams Ess. DatorminN4k 1e, Is thetacuala...I average tlowrateof natural gm to Me glycoll447454on unitIs...5.994051MMzcf per day (63.1.220(4)(202 26 Are nual avenge emlsslom of bemene from the glycol dehydration unit process vent[°..a...ph. less than 1yg42 MAT (6337014112142' 2. RPM P.u62mlem3 roll glycol dehydrzaonu. ..me.e on or before August 23, 2011163.122004(2) and (3))2 a. For. small dory, Is a mind device req to meat der 6TEXemizsm ump(sardaM]) given by the apol®ba �uetlm] YouMv3 sMkaW that thkfadlM k not say.. PACT PM, en A. General Ammons per 363.1274 (a)Taae2 463.3.73 -Emissions Control Standards 463.381 -Coned Equipment 5adards. 463.1283-Impeal°n and M.Itdng 463.1266- IlemnikeepIng 463.1285-Pep,Nng robndo Resulxbn> Saebn573 D • he dehydrator mbject man embdoa control requirement under MAR SIN or HMI Ilea-dadon ], Sdon.5..5)] 2. Is MN ...tor loos. at a ...Ion/storage 7°giry] 3. IS M4 dehydrator Ioatd at an and gm emloabm and product. operation, natural gas compressor Nation or gas..esa'ne Nam (Peg ],Section X'ID3)2 4. Was. giycdatual gas dabydat.mnsnucted before May 12015 (Peg 75ecdon 1'21DA.b(7 If cons.cted por t m May 1.2015, are umntr0Ild equal emissmmfroma single glycol newrel gas dehydrator. ge tor equal toatr Man 6 tors perya. WIf Me C.2 toy VOC 4e. dehydrat. N lotated NO.,1,320Net or a Wilding unitor designated outride advlry area lleg>, Scd°n %MI.D.A412 5. If. ..led on or after May 1. 2013. are uncont.led actual emfaloafrom a single glycol naturals dehydrator up. to or Taal Meng tpy4M(Re5ulad2n2 Section X2l.0.4.a] IENINdamr Nsubeat. Mmulation3,5action XVII. B. D3 6act4on.0.6-Genial Pr midoafce Nr Pdluda Control EquiPmen[ad Prevent fFmisslos ANemttlm 4544744....I f6Pebnal5.5Wnl 6, ends dyedr.wal gas dehydrator controller, Mabad-uporaitematecombus4on device (I.mt Me pdmary metro, der.) delis not enclo., rrneal I..mmold.. Mr OM 4.hyamorenat m5j3.223 flag 2)37 n 1, 53¢65144.&2.. Satin XVR.e2.e-Nmradveemis4kns.m. epernment D)sclelmer • mis tledumentassists 2742477 with determining nppgca5AlN ofcertain requIrernsnfs ante Clean Air Act, lb Implem2THrg regulation, a7d A701184yy Corr. Commission rep/a.m. This document.57775 rulec regndagm, and the analysis 1176712444 mayrctappy foe particular sib aticn.448'epm the Indvid.H fads awl c4usnstance4T]vs document does not clangea8ub0ll4Ae@- arybw. r4Waion,cr y4Marlegalry tin.g requin.artam) k rot legally°a as12#44 event .27cm 74374ean*alaguage doors dxunent and n4a largrra2eatle Veen Air Act I5lmpimrahbg r44larims, 4 IA, Qa2ry Catntl Commission regulations. 477474lagea 0esan4eerreg.,im will card. Tneumaronmarv7lorykrgt.gesaenas'ra.n641*•1237..s...erd'cary'I22rge.6dAPC7 INerpmmtatbncand recamr5.dayiar¢7a1aa`1041 lean/nabb., such as'mu5Ymd'Inguired" are Wended ar8sc724 contrarrg',trireme= under tomsa544l®n Air Adored Air Duality Control Commission modems, but this document cfes red establish Daly 214877 refbrema2ts1nadaibag go to am The deny cant metadtd benzene ere.. • -you More pmia2dy Id7aed this in rte MAR... CartInue- previously Indcatd Mg Int. hegnnI gof the MARseam • -You have previously Indicated Mz in the Peg 2, Sedan XIl detamdrad,n Go to nues.5 Source is subject Hot Oil Heater Emissions Inventory Section 01- Administrative Information Facility AIRS ID: County Plant Poin Section 02- Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP Control Efficiency %: Low NOx combustion system is considered an integral control device. Section 03 - Processing Rate Information for Emissions Estimates Number of Heaters: Heat Input Rate = .,,,,.;1,3,....,,7;58` MMBtu/hr Heat content of waste gas= , , 31f,31 Btu/scf Actual Hours of Operation = Requested Hours of Operation = Actual heat input rate = Requested heat input rate= Potential to Emit (PTE) heat input rate = Actual Fuel Consumption= Requested Fuel Consumption= Potential to Emit (PTE) Fuel Consmption = Section 04- Emissions Factors & Methodologies rs/year hrs/year New Source - not yet installed 0.00 MMBTU per year 876,000.00 MMBTU per year 876,000.00 MMBTU per year 0.00 MMscf/year 775.22 MMscf/year 775.22 MMscf/year 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) VOC PM10 PM2.5 500 NOx CO 2.36 3.26 3.26 0.26 13.14 26.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 2-36 3.26 3.26 0.26 13.14 26.20 2.36 3.26 3.26 0.26 13-14 26,28 Hazardous Air 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 Permit Limits Uncontrolled Controlled (Ibs/year) .-(Ibs/year) Formaldehyde 3.229E-02 9.018E-04 1.460E-03 7.729E-01 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 3.229E-02 9.018E-04 1.460E-03 7.729E-01 3.229E-02 9.018E-04 1-460E-03 7.729E-01 643835 1.8035 2.9200 64.5535 1.8035 2.9200 Benzene Toluene n -Hexane 1545.8824 1545.8824 Section 06- Regulatory Summary Analysis 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, 19921) in all subsections of Section II. A and B of this regulation. 15 of 38 K:\PA\2016\16 W E0773.CP2.xism Hot Oil Heater Emissions Inventory Regulation:1 Section III.A. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following: III.A.1.b. For fuel burning equipment with designed heat inputs greater than 1x10uBTU per hour, but less than or equal to500x10s BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)'' Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. The hot oil heaters covered under point 017 each have a design heat input rate of 50 MMBtu/hr. As a result, the heater is subject to this portion of the regulation. Using the above equation, the allowable particulate emission limitation is 0.1808 lb/MMBtu. The AP -42 emission factor of 7.6 lb/MMscf (7.45x10' lb/MMBtu) used in the calculations above is below this particulate emission threshold. Section VI.B.5..Any new source of sulfur dioxide not specifically regulated above shall: VI.B.5.a. Limit: emissions to not more than two (2) tons per day ofsulfur dioxide. Based on the calculations above, this source will emit 0:13 tons per year of sulfur. diode. This is below the requirement of 2 tons per day and therefore the source is in compliance with the above 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 odorswhich 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) ormore volumes of odor free air. Regulation 3 Part A-APEN Requirements Criteria Pollutants: Forcriteria pollutants, Air Pollutant Emission Notices are required for: each individual emission point in a non- attainment area with uncontrolled actual emissions of one tonper 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 NOx. Part B —Construction Permit Exemptions - Applicant is required to obtain a permit since uncontrolled NOx emissions from this facility are greater than the 2.0 TPY threshold (Reg, 3, Part B, Section B.D.2.a) - Regulation 6 - Part B Section IL:.Standards of Performance for New Fuel earning Equipment: II.C..Standard for Particulate Matter:. On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or causethe 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 heatinput, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-0.26- Where: PE is the allowable particulate emission in pounds per million Btuheat input. Fl is the fuel input in million Btu per hour. If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates. II.C.3. Greater than 20 percent opacity. - The hot oil heaters covered under point 017 each have a design heat input rate of SO MMBtu/hr. As a result, the heater is subject to this portion of the regulation. Using the above equation,the allowable particulate emission limitation is 0.1808 lb/MMBtu. The AP -42 emission factor of 7.6 lb/MMscf (7.45x10-3 lb/MMBtu) used in the calculations above is below this particulate emission threshold. NSPS Dr: Except as provided in paragraphs (d), (el, (f), and (g) of this section, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is. commencedafter June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100million British thermal units per hour (MMBtu/h)) or less,but greater than or equal to 2.9 MW(10MMBtu/h): The design heat input rate for each hot oil heater is 50 MMBtu/hr which is greater than 10 MMBtu/hr. Additionally, the heaters will be constructed after 06/09/89.. According to NSPS Dc, a steam generating unit is defined as "a device thatcombusts any fuel and. produces steam or heats water or heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term doesnot include process heaters as defined in this subpart." Since these hot oil heaters are used to heat a heat transfer medium (hot oil in this instance), the heaters meet the definition of a steam generating unit. As a result, the hot oil heater is subject to.. NSPS Dc. Please see section 07 for the discussion of specific requirements. Regulation. 7 Section XVI.D. Combustion Process Adjustment XVI.D.1. As of January 1,2017, this Section XVI.D. applies to the following combustion equipment with uncontrolled actual emissions of NOx equal to or greater than five (5) tons per year, and that are located at existingmajor sources. of NO5, as listed. in Section XIX.A. This facility is not an existing major source of NOx listed in Section XIX.A. As a result, this section of the regulation does not apply to this facility. - MALT MACT DDDDD: This subpart: establishes national mission limitations and work practice .standards . for hazardous: air pollutants (HAP) emitted from industrial, commercial, and institutional boilers and process heaters located at major sources of HAP. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and work practice standards The hot oil heaters covered under point 017 are not subject to MACT DDDDD becausethis facility is classified as an area source of HAP. Section 07- Technical Analysis Notes 16 of 38 K:\PA\2016\16 W E0773.CP2.xlsm Hot Oil Heater Emissions Inventory with the following requirements of §60.43c, (i) §60.48c(a) "The owner or operator of each affected futility shall submit notification of the date of construction or reconstruct' ottoodo dual startup, as provided by §60.7 of this part" (ii) §60.48c(g)(2) "As an alternative to meeting the requirements of paragraph fellofthis section, the owner oroperator of an affected faciity that combusts only natural gas, wood,fuelsosingfuelcertification in §50.48c(f) to demonstrate compliance with the SO, standard, fuels not subject to art emissions s€undard. (excluding opacity), or a mixture of these fuels -' may elect to record and maintain records of the amount of each fuel combusted during each calendar month. RI §60.48c(I) 'All records required under this section shall be maintained by the owner or. operator of the affectedfacility for a period of two years following the date of such record.' Discovery has expressed they will comply with the above mentioned requirements. 2. Al -Hexane is the only HAP for which an etsusion factor will be included in the permit since it Is the only HAP that is above reporting thresholds (250 lb/year). 3. The emissions factors from AP -42 Chapter 1.4 used to calculate emissions from this source are based on an average natural gas higher heating vafue of 1,020 Btu/scf. The operator based their calculations on a heating rolue of 1,130 Btu/scf. As re,uit, the emissions factors wereconverted to this heating value by multiplying the emission factors by a ratio of 1130/1020 1.1078 as prescribed by footnote "a" under tables 1.4-1, 2, and 3, 4, Based on the sourcegroupingcriteriaoutlined in Regulation 3 Part A Section 11,8.4., it was determined the grouping of thetwo heaters reported ort this APES would be allowed. The heaters meet the following criteria outlined in this section of the regulation: (i) 9.B 4.o. Alt of the aggregated sources have fden₹Calsotrrce classification codes and -emission factors for criteria nollutan is - The two engines have the same heat input rating, both heat hot oil and emissions are calculated using identical emissions factors from AP -42. (ii)t1.0.44. Each of the aggregated sources share a similar location within thefacil'ffy-- Based on the facility wide diagram provided, the heaters appetite be located ata simBar location, (ill)IL B,4.c. Similar sources regulated under the New Source Performance > '. Standards (Regulation- Number B) and non -New Source Performance Standard source s should not be grouped -Bath-of these heaters are subject to: NBPS.Ds, (iv)11.B.4.d, None of the individual sources in required to monitor emissions through the use of continruous emission monitors - Emissions will be calculated using monitored throughput and emissions factors provided in the notes to permit holder. (v) ;LB.4.e, Each of the ednoPvidual emission points has fuel usage, production, and a consumption level, which are indistinguishable from the other points, which have been grouped on the Air Pollutant Emission Notice - Each heater will be equipped with.a fuel meter to track natural gas combusted as fuel. This information will be used to demonstrate compliance with the permitted throughput limit which includes total maximum throughput for both units combined. (vi) lt.B.4.f. None of the individual sources grasped on the. Air Pollutant Emission Notice has previously been issued its awn separate emissions permit, - These heaters are new units that are part of the phase II construction of this gas processingfaciliity. 5. Initial testing will be required to assess the emissionNOx and CO emitted by these heaters. This test will be used to confirm the heaters capable. of meeting theemission,evelsspecified by the manufacturer in actual operation. It was determined VOC does not need to be tested for because the operator. usingthe AP -42 emission factorto estimate VOC emissions. 6. The operator did not provide a manufacturer specification sheet in order to support the manufacturer specified emissions facers for NOx and CO. The operator indicated thatthe hot oilheater specification was outfor bid duringtime of review and the vendor rnformanon would not be evaluated until the bidswere ass essed.The operator did provide the specifications . requested for the heaters., This. information alongw th initial compliance testing was deemed acceptabtefor permitting purposes. AIRS Point it 017 Process # SCC Code 01 Section 08- Inventory 5CC Coding and Emissions Factors Uncontrolled Emissions Pollutant Factor Control % Units PM10 8.42 0 lb/MMscf Burned PM2.5 . 8.42 0 lb/MMscf Burned NOx 33.90 0 lb/MMsd Burned VOC 6.09 - 0 lb/MMscf Burned CO 67.80 0 lb/MMsd Burned SOx 0.66 - 0 lb/MMscf Burned Formaldehyde 8.33E-02 0 Ib/MMsd Burned Benzene 2.33E-03- 0 Ib/MMsd Burned Toluene 3.77E-03 0 lb/MMscf Burned n -Hexane 2.0 0 lb/MMscf Burned 17 of 38 K:\PA\2016\16 W E0773.CP2.xlsm Regenerator Heater Emissions Inventory MMBtu/hr Btu/scf hrs/year hrs/year New Source - not yet installed 0.00 MMBTU per year 131,400.00 MMBTU per year 131,400.00 MMBTU per year 0.00 MMscf/year 116.28 MMscf/year 116.28 MMscf/year Section 01- Administrative Information Facility AIRs ID: County Plant EMMA Point Section 02- Equipment Description Details Detailed Emissions Unit Description: One (1) natural gas fired regeneratorlteater aMMBtu/hr. The heater provide heat Emission Control Device 'Equipped. ml0 a low NI0x combustion system for 3T#lidmizfng emissions off Description: System consldered(igtearal to the processand snstatn add on control,dg Requested Overall VOC & HAP Control Efficiency %: Low NOx combustion system is considered an integral control device. Section 03 - Processing Rate Information for Emissions Estimates Number of Heaters: Heat Input Rate= Heat content of waste gas= Actual Hours of Operation = Requested Hours of Operation = Actual heat input rate = Requested heat input rate= Potential to Emit (PTE) heat input rate= Actual Fuel Consumption = Requested Fuel Consumption = Potential to Emit (PTE) Fuel Consmption = Section 04- Emissions Factors & Methodologies Section 05- Emissions Inventory Formaldehyde maw 1 Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) VOC PM10 PM2.5 SOx NOx CO 1.25 0.85 0.85 0.04 2.63 2.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.25 0.85 0.85 0.04 2.63 2.63 1.25 0.85 0.85 0.04 2.63 2.63 Hazardous Air 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 Permit Limits Uncontrolled Controlled (Ibs/year) (lbs/year) Formaldehyde 4.844E-03 1.353E-04 2.190E-04 1.159E-01 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 4.844E-03 1.353E-04 2.190E-04 1.159E-01 4.844E-03 1.353E-04 2.190E-04 1.159E-01 9.6875 0.2705 0.4380 9.6875 0,2705 0.4380 Benzene Toluene n -Hexane 231.8824 231.8824 Section 06- Regulatory Summary Analysis Section 11.4.1 - 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 readingstaken 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. 18 of 38 K:\PA\2016\16WE0773.CP2.xlsm Regenerator Heater Emissions Inventory Regulation 1 - — Section III.A. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -homing equipment, particulate matter in the flue gases which exceeds the following: III.A.1.b. For fuel burning equipment with designed heat inputs greater than 1x106 BTU per hour, but less than or equal to 5000106 BTU per hour, the following equation will be used to determine the allowable particulate emission limitation. PE=0.5(FI)-e2s Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. The regeneration heater covered under point 018 has a design heat input rate of 15 MMBtu/hr. As a result, the heater is subject to this portion of the regulation. Using the above equation, the allowable particulate emission limitation is 0.2473 Ib/MMBtu. The manufacturer provided emission factor of 1.3010' Ib/MMBtu used in the calculations above is below this particulate emission threshold. Section VI.B.S, Any new source of sulfur dioxide not specifically regulated above shall: VI.B.5.a. Limit emissions to not more than two (2) tons per day of sulfur dioxide. Based on the calculations above, this source will emit 0.04 tons per year of sulfur dioxide. This is below the requirement of 2 tons per day and therefore the source is in compliance with the above 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 NOx. Part B — Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled NOx emissions from this facility are greater than the 2.0TPY threshold (Reg. 3, Part B, Section II.D.2.a) Regulation 6 Part B Section II: Standards of Performance for New Fuel Burning Equipment: LC. 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: s.C.2. For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI)-0.26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates. II.C.3. Greater than 20 percent opacity. The regeneration heater covered under point 018 has a design heat input rate of 15 MMBtu/hr. As a result, the heater is subject to this portion of the regulation. Using the above equation, the allowable particulate emission limitation is 0.2473 lb/MMBtu. The manufacturer provided emission factor of 1.3x10'2 lb/MMBtu used in the calculations above is below this particulate emission threshold. NSPS Sc: Except as provided in paragraphs (d), (e), (0), and (g) of this section, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 9,1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/h)) or less, but greater than or equal 4r 2.9 MW (10 MMBtu/h). The design heat input rate for the regenerator heater is 15 MMBtu'hr which is greaterthan 10 MMBtu/hr. Additionally, the heater will be constructed after 06/09/89. According to NSPS Sc, a steam generating unit is defined as "a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in this subpart." Since this regenerator heater is used to heat a heat transfer medium (natural gas), the heater meets the definition of a steam generating unit. As a result, the regenerator heater is subject to NSPS Dc. Please see section 07 for the discussion of specific requirements. Regulation 7 Section XVI.D. Combustion Process Adjustment XVI.D.1. As of January 1, 2017, this Section XVI.D. applies to the followingcambustion equipment with uncontrolled actual emissions of NOx equal to or greater than five (5) tons per year, and that are located at existing major sources of NOx, as listed in Section XIX.A. This facility is not an existing major source of NOx listed in Section XIX.A. As a result, this section of the regulation does not apply to this facility. MACE a MACT DDDDD: This subpart establishes national emission limitations and work practice standards for hazardous air pollutants (HAP) emitted from industrial, commercial, and institutional boilers and process heaters located at major sources of HAP. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and work practice standards The regeneration heater covered under point 018 is not subject to MACT DDDDD because this facility is classified as an area source of HAP. Section 07 - Technical Analysis Notes 19 of 38 K:\PA\2016\16 W E0773. CP2.xism Regenerator Heater Emissions Inventory nlpieGlFta`!`Siev2 unttwttlbe designedro tuYYl42tZt7'ePIf2i'9a5 aRreVeilt'#pltnanon Oflytii'a₹e5 b!!i(,COlikni ireetrmolG sik, i%, ydtdl itbedtsvrll iSa,vsed As one hells odsarhtng bne will he in theregenetatlonprocess and the other •bed tali be oh.4 .. .�3atuaafed inlet Os..i+?,7R �pA/ YMo4,gCi-rhe arfsoChtng bed foe asr(inedtytle;.adsorbkrq wrtter�r`eseatmt6mgas.FFnce:_evater has been sfrippetl a` i`etsave anysnolesievedustp rota entenhgthe ctya:unit..:a regenetatlon proceAs;tegen gas- floors dpwnste sot, of the t uSafl(teA'? will beeliea€ed-ntr9F,1'rX'b'iYkE l' ii fegerierstlon gas heater' Ringers gas will flow through thPWotersot -,. sorbed waterfrvrp the maleculac sieve. Itegen gas will then betaped," and:FJquru' wd1 Tje se�iara#efilh tPieragenerationgas scrrzbberr,Fhc gas wi# be wrnRressedaadresydedu osier/noolesrer'.Cot»pressiss will be electric-rrmtoeha,uen. Fine liigaid wilt be root ti e"toe tin ed'Uref,s system; ,4n optaon u tb selmsidue rsjia tegeriar rnpp;is Isis regenervtion earnpieseoi• tsarist redim&an T3ia oar further expressed m that the fieat ro.the,combustian gases istra>nfertedfiashe €egeoera direct Contact or intermixing AccordfrngtothegeratEPAApphcabrirtydetermmation tndex doepment ctetre-t„neeterwS36j, devicesrcvhfch contustfvedand transfer heat rthat.prevents mbustion gasest, heattraesfer medmmlacross a physigai barrierwhich.preventsldirect'cpntect.orinteraixing of the combustion gases and the heat hransfeymedUam are.consrdered steam:geneiating,units under 3ubparts'Db and,l7c.":This determxnationas rerEerated in she£PAAppi[cabdny determination index dacumentCoritrbRnubxtier 0800027 7{ns;tl'ifurmatian suppprnsxhe detetminatwn that 2bhS;,. 'regeneration heater is sublecttoihl5PS :.: Z. The sulfur diaxide,1SC1yrequtsemePRsarf §604 pl faarties that combust coal, oil, woody a illixtvreafthese fuels rrrs mlxturepi=tbeso fsel ;subigez`xo the sulfurdtoxide, ar particulate maueranrissiantimits ofi�5?S;Dc�As'suc,, with tfie following requ7rements:of; §;60 48tz (1§60:48gtaj, "'#hagwrrer or opera₹er of each Provided by§6113`ofth'is part."'fEf-§60484(g)l2I °As an he nstive#e5 meetmg.the require ✓r. nat0raJ,'gas wood, fuels sstngfuet ierG$cation id§6A8c(fl4to ilemonshate.comptiaoce sot may elecbto reoardesd:meintalsrecordsattheamnuntofeach-fuetcombustedduringeachacz opera€or`of they,af`eon' rflCilityl/via'periodhoftwis-years-fntlowing the date si sueh'regord:'=p1' cau, r 3, The perm it wlfl nwt §j3rrt?Ih emissions factors for the HAPS associated wiih this'sburee bese; oa6 oil: or soul/oil witt€otharfilets -The, parttculate.giatter{PM/:requirerredts o f §:6Dt43c apply, to aflecte; any•atherfaelc, Sines thi;regeneration heater wilt, only combustion nateral gas to produce heat, it* tin only $objectimthe'repdrting:and recordkeeping,requirernents o₹ §60.48c.,Theheater wilt campiy &cfiity she supmR notification oft he date, of writ+ action or recnhstruct op,a"nd,a stoat startup,nr paragraph g/1) of this. section, the owner or apeiatar of an affected faciitythat combusts only 5tandardf rs.00tubjecttean emissions standard (excluding npacityj, niioiureafthesefue/s' m §,60.4sc(ij. kll'recerds re§tilted underthisseaian shall; bemaistanned byline owner or" . :ley will, comply,with the•above mentioned requirements_ epee lungt iesho5ls1 5°Ib/year). ->t Euen thoughthe.PM,(10 and 2F 5)emiss ongf tots are based anrnanufactirrer data, the requimmenf;WHE not require'testtngfvf 9tYtrp orPMy. ., Manufacturer prauid'ed'emrssintts(aG₹arsale maPefConserva#ive than the vetoes typica(Cy,used hrn o00-42chapter�.4._(iF)T#ieerr[issions are3xelay.!,A;P6N SE >: "rn, servative manufacturer'provii%d.zmrss7aayFac�a"ns,are used to calcalate'eritiissions �ni}T,hrs E�eahzr usz2s nawratgasas€ ue3--As a resss� theai�bun₹ aP A • process'isless.ofa concern.(iu)-PM ern issions'are:notcioseto amode inga .nst th; sanr #fifties d,-„ - 6. Theemissions factersfra`AP-42Clrapter1.4 used to•calculate 5Ox and HAP eedxalora•s ll'soe lb acsgdroe ae used arean aV rag;-naturalgaslagher hsating:value of 1,020 015/s of. Tire sperator based th realcufations on a heating value of 1}130 Btu/sot,. Asa resait, the i sien'sjacteu'svtareK:onvette„d touolli hea6ng4al ae by mulitplying-tfreami'ssioo factors by a ratio of 1130/1020'=1:1078as prescribed b0botnote 7a"under tables l:4-1, 2, and:3: ' . 6..lo tial:#'estmg wll be„ inquired for this he inanufaciurenhaetua. Section 08 - Inventory SCC Coding and Emissions Factors AIRS Point # 018 Process # 01 SCC Code emuTsians of VOC .hi ThIs-te eff 'rth f Ilawrng reasonS,(i)The,. iresholdn (/toy) Coen when the worn it₹edia'sra result'of:the:-oombesbon m edIar i"s`capable of meesrrwa the ern issiorulevels specified by the Uncontrolled Emissions Pollutant Factor Control % Units PM10 14.7 0 lb/MMscf Burned PM2.5 14.7 0 lb/MMscf Burned IVOx 45.2 0 lb/MMscf Burned VOC 21.5 0 lb/MMscf Burned CO 45.2 0 lb/MMscf Burned 500 0.7 0 lb/MMscf Burned Formaldehyde 8.33E-02 0 lb/MMscf Burned Benzene 2.33E-03 0 lb/MMscf Burned Toluene 3.77E-03 0 lb/MMscf Burned n -Hexane 2.0 0 lb/MMscf Burned 20 of 38 K:\PA\2016\16W E0773.CP2.xlsm Condensate Storage Tank(s) Emissions Inventory Section 01- Administrative Information Facility AIRs ID: County Plan Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device •a3.;. s Emisstonsfrom t(ii Description: Requested Overall VOC & HAP Control Efficiency %: Section 03`- Processing Rate Information for Emissions Estimates Primary Emissions - Storage Tank(s) Actual Condensate Throughput = Requested Permit UmitThroughput= Potential to Emit (PTE) Condensate Throughput = ed tia liquid maanffbt¢ Barrels (bbl) per year Actual Condensate Throughput While Emissions Controls Operating = Barrels (bbl) per year Barrels (bbl) per year Secondary Emissions - Combustion Device(s) Heat content of waste gas= : Btu/scf Volume of waste gas emitted per BBL of liquids produced = "�•�'g .s _ <scf/bbl Actual heat content of waste gas routed to combustion device Requested heat content of waste gas routed to combustion device= 0 MMBTU per year U MMBTU per year Potential to Emit (PTE) heat content of waste gas routed to combustion device = 0 MMBTU per year Section 04- Emissions Factors & Methodologies Will this storage tank emit flash emissions? Pollutant MIEEZEI Pollutant ' 0 Uncontrolled Controlled (lb/bbl) (1b/bbl) (Condensate Throughput) 6.196E-01 .4,079E-03; 03 r1,827E-0Arat q3:653E-04;'', .3.044E -0S __z, (Condensate Throughput) Control Device Uncontrolled Uncontrolled (Ib/MMBtu) (waste heat combusted) (16/bbl) (Condensate Throughput) 0.0000 0.0000 0.0000 0.0000 Emission Factor Source Emission Factor Source Section 05 - Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled. Controlled (tons/year) (tons/year) Requested Permit Umits Uncontrolled Controlled (tons/year) (tons/year) VOC PM10 PM2.5 NOx CO 20.3550 0.0000 0.0000 20.3550 0.4071 0.0000 0.0000 . • 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 ' 0:0000 • 0.0000 0.0000 0.0000 0.0000 Hazardous Air Pollutants Potential to Emit Uncontrolled (lbs/year) Actual Emissions Uncontrolled Controlled (lbs/year) (lbs/year) Requested Permit Umits Uncontrolled Controlled (lbs/year) .(Ibs/year) -. Requested Permit Umits Uncontrolled Controlled (tons/year) (tons/year) Benzene Toluene Ethylbenzene Xylene n -Hexane 224 IMP 267.99 • 0.00 0.00 267.99 5.36 0.1340 2.68E-03 145.99 0.00 0.00 145.99 2.92 - 0.0730 1.46E-03 12.00 • 0.00 0.00 12.00 0.24 0.0060 1.20E-04 24.00 0.00 0.00 24.00 0.48 0.0120 2.40E-04 4386.00 0.00 0.00 4386.00 87.72 2.1930 4.39E-02 2.00 0.00 0.00 2.00 0.04 0.0010 2.00E-05 Section 06- Regulatory Summary Analysis Regulation.3, Parts A, B Regulation 7, Section VI Regulation 7, Section XILC, D, E, F Regulation 7, Section XII.G, C Regulation 7, Section XVII.% C.1, C.3 Regulation 7, Section XVII.C2 Regulation 6, Part A, NSPS Subpart Kb Regulation 6, Part A, NSPS Subpart 0000 NSPS 0000a Regulation 8, Part E, MACi Subpart HH (See regulatory applicability worksheet for detailed analysis) Source requires a permit Storage tank is subject to Regulation 7, Section VI.B.2.a&b Storage Tank is not subject to Regulation 7, Section 011.C -F Storage Tank is not subject to Regulation 7, Section XII.G Storage tank is subject to Regulation 7, Section XVII, B, C.1 & C.3 Storage Tank is not subject to Regulation 7, Section XVII.C.2 Storage tank is subject to NSPS Kb Storage Tank is not subject to NSPS 0000 Storage Tank is not subject to NSPS 0000a Storage Tank is not subject to MAR HH w ,3331? jl Barrels (bbl) per year 21 Of 38 K:\PA\2016\ 16WE0773.CP2.xlsm Condensate Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions? If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? If yes, the permit will contain an "Initial Compliance" testing requirement to develop a she specific emissions factor based on guidelines in PS Memo 05-01. Does the company use a site specific emissions factor to estimate emissions? If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted?This sample should be considered representative which generally means: she -specific and collected within: one year of the application received date. However, if the facility has not been modified (e.g., no. new wells brought on-line), then it maybe appropriate to use an older site -specific sample. If no, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions.factor based on guidelines in PS Memo 05-01. N/A - the operator developed site -specific emissions factors to estimate. 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 thedestruction efficiency of the combustion device based' on inlet and outlet concentration sampling Section n8 - Technical Analysis Notes 1- Based on the process description,"Siquids from the slug catchers will be routed to a three phase soparator and stabilizer w nth the stabilized condensate and RO L directed straight to the sales pipeline. To account for safes line outages (estimated at 5%of the year), the operator has assumed a maximum of 3,600bbl/day and 45,700 bhl/year of stabilized condensate will be sent to the four (4)1,000 barrel condensatetanks." The stabilizer is essentially a separation device that removes the remaining lighter hydrocarbonsfrom the liquid- As a result, the condensate is stablzed Ng. no flash emission) vice it is routed to the condensate storage vessels. 2. Typically, emissions from stabilized storage vessels are estimated • using EPA Tanks 4.09d. However, the operator estimated emssions from these stamp vessels using E&P Tanks versine 3.0 and a condensate compe tine based one PrnMax simulation of the stabiliser area of the gas plant. This methodology estimatingemissrons was deemed acceptable for the following reasons, (j Since EPA Tanks 4.09d is typically used, a test simulation was run assuming 1/40f the requested throughput passed through each of the four tanks Additionally, the characteristics of the tank specified in the E&P tank simulation were maintained in the test EPA Tankssimulation. Finally, gasoline with RVP 11 was used as the liquid in the EPA Tanks test simulsnon since the operator specified a sales oil RVP of 10.84 in lire E&P Tank simulation. This test snmlaton resultedin emisstonsof12,678.451b/year per vessel.To determine total emissions, this mmit was scaled by a factor affect. This resulted in tribal uncontrolled VOC emissions of 25.4tpy (12673,4.5 lb/year `4 x-1 ton/20001bsb, This Simulation resulted in a slightly more conservative value compared to the valuepredicted by the E&P Tank simulation (20355 tpy) However, itwasassumed that EPA Tanks. would result in al more conservativee5.titnate since the liquid was assumed to he gasoline with RVP 11 whereas an actual liquid oomposi lives used in the E&PTank simulation, Additionally, the operator assumed an ambient pmsearn of 12.3psiawhile the EPA Tanks simulation uses an ambient pressure of 12,1 psia. It should be further noted that the storage vessels are controlled and the difference in controlled emissions between the two simulations is 0.1 rye hi) Both the EPA Tanks and E&P Tanks simulations use AP -42 equations to calculate working and breathing losses, ttn) The difference in emissions between the test EPA Tanks simulation and the operator provided E&P Tank simulation does oat change the regulatory applicability for the storage 3_ According to the E&P Tanks 03.Posers manual, "if you select the Stable Oil flowsheet the program will calculate only the working and standing lasses from the storagetank for stable oil. In the mutation provided with the application, the operator selected the Tank with Separator" flowskteet, which alsocaleufates flash ermseanghonor an How v p. the simulation provided by the operator did not result in flash emissions, Additionally, the operator selected the AP -42 calculation method for determining working and breathing emssions. Svice thestable oil flawsheet would typigally be selected for these types of storagevessels, atestSimulatlon was ran using the stable oil flowsheet se1ectIvy wHit the stable oil composition provided by the operator. This test simulation resultedin total uncontrolled VOC emissions of 20.351 tpy. The coral uncontrolled 0t0Cem ssion predicted by the model provided by the operator am 20.355 tpy. The difference between these two values is negligible: As a result, the operator estimated emissions were determined to be acceptable. S. These smrage ?assetsare subject to NSPS Kh In order to comply with this requirement, the operator has indicated the storag vessels will be camrolled with a dosed vent system and an enclosed-,-"' information pertaining to the determination efthe maximum tnieva o p q {dt at equine monitoring result, his er meter-, equippedd nor pressutlesf undditr 460,1 66(e)since paragraphs.. (c) and d�arerthe aonly sectrons that require'monitoring of this parameter. 6, The NOx and CO emissions associated with the combustion of storage vessetemissions are accountedfor under point 023. As a r esu It, combustion emissions are not calculated in this worksheet. 7. These storage vessels are proposed new sources at this facility. As a result, the actual throughput Is: listed as o bbl/yearn nthis analysis because the -storage vessels have not been Installed or operated 8. According to "Fundamentals of Natural Gas Processing, Second Edition' by Kidney, Parrish and McCartney"[Reid Vapor Pressurejvaiues range . m10 to 34 psi, but the common range is 9 to 12 psi when the liquid is trucked offsite." Duets this, assuming RVP10.84 for use in E&P Tanks v3.0 appears to be a reasonable estimate ,or the stablizedcondensateRVP. 9. It was determined that att initial compliance test requiring the operator toabtefn a site specific stable oil sample would not be required for the following reasens_: (i) As discussed In above, the e&P Tanks simulation results In emissions similar tothose predicted by the EPA Tanks test simulation tfs,fig gasotine-wfth RVP:11.AS indicated in is a common range at gas plants, sa the results of the test simulation demonstrate the E&PTanks simulation results are within the expected range. (3i}:lire Division does not typically require site open samples be obtained for statiilrzedcondensate storage vessels. (iii) The facility VOC emissions are not within 10% of major source thresholds. 10. The operator is requesting a 98% control efficiency for the enclosed flare that is used to control the stahilized leadoul. Since this control value is greater than the standard 95% control granted by the Division, initial testing will be requ rrd.L destruction efficiencywhen controlling the above listed sources. Section 09 - Inventory SCC Coding and Emissions Factors - AIRS Point # 019 Process # SCC Code 01 n RVP of9Id12 tab Leed slap tanks and stabilized condensate and slot the eaclased flare is Papa ble of achieving 90% Uncontrolled Emissions Pollutant Factor Control % Units PM10 - 0.00 0 lb/1,000 gallons condensate throughput. PM2.5 0.00 - 0 lb/1,000 gallons condensate throughput NOx - 0.00 0 lb/1,000 gallons condensate throughput - - VOC 148 98 lb/1,000'gallons condensatethroughput CO 0'.00 0 lb/1,000 gallonscondensate throughput Benzene 0.10 98 lb/1,000 gallons condensate. throughput: '- Toluene 0,05 98 lb/1,000 gallons condensate throughput ' Ethylhenzene 0.00 98 Ili/1,000 gallons condensate throughput r . %ylene 0.01 98 lb/1,000 gallons condensate throughput n -Hexane 1.59 98- lb/1,000 gallons condensate throughput 224 TMP 0.00 98 lb/1,000 gallons condensate throughput 22 of 38 K:\PA\2016\16 W E0773.CP2.xlsm Condensate Tank Regulatory Analysis Worksheet Colorado naeslatlon 3 P r A nd... Dd,RgrnlltfjgoBkemeete You hone indicated the:source is in the NonAtta€nment Area ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this Individual source greater than 2 TRY (Regulation 3, PartA, Section Il.D.1.e)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than 5 TPY, NOx greater than 10 TPY or CO emissions greater than 10 TPY (Regulation 3, Part 0, Section 11.0.3)1 IYou hove indicated thatsourco is in the felon.Atadnment Area NON -ATTAINMENT• 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. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions from the greater than 2TPY, NOx greater than 5 TPY or CO emissions greater than 5 TPY (Regulation3, Part B, Section 11.0.2)? ISoarce requires a permit Colorado Regulation 7, Section VI 1. Does this storage tank store' petroleum liquid" as defined by Regulation 7 Section VI,A.2.g? 2, Does this storage tank meet any of the exemptions listed In Regulation 7 Section V1.6.1? 3. Does the tank have a storage capacity greater than 40,000 gallons (952 barrels)? 4. Does the storage tank have afixed roof? 5. Is the fixed roof tank used for the storage of petroleum liquids which have a true vapor pressure between 065 psia and 1133 psia at 20°C (66"F)? 6. Is the fixed roof tank equipped with an Internal floating roof? 5tcragc tank. It ovi/act to Regulation 7,Section VIJ1.2,u€nb lotion 7, fxtrlioe Vi (r) Storage Tank i i not subject iv Regulation 7, Section V .6.2,a.(0).(ill) Colorado Regulation 7, Section XII.C.f 1. Is this storage tank located In the 8 -hr ozone control area or any ozone non-attalnmentarea or attainment/maintenance area? 2. Is this storage tank located at an oil and gas exploration and production operation', natural gas compressor station or natural gas drip station? 3. Is this storage tank located upstream o/ a natural gas processing plant} Intovago Teak's notvub)cult Regulation 7, Section Xll.t-P Section XII.C.1 —General Requirements for Air Pollution Control Equipment —Prevention of Leakage Section XII.C.2—Emission Estimation Procedures Section XII.D-Emissions Control Requirements Section XII.E—Monitoring Section XII.F —Recordkeeping and Reporting Colorado Regulation 7, Section 011.0 1. Is this storage tank located in the 8 -hr ozone control area or any ozone non -attainment area orattalnment/malntenence area? 2. Is this storage tank located ata natural gas processing plant? 3. Does this storage tank exhibit "Flash" (e.g. storing non -stabilized liquids) emissions and have uncontrolled actual emissions greater than or equal to 2 tons per year VOC? Ym§f�y.{. YnCYMY Y23a _ AMU Yes Storage Tank is net.ssibbecl to Regulation 7, 6ect:an XIE.G Section X11.6.2 - Emissions Control Requirements Section XII.C.1 —General Requirements for Air Pollution Control Equipment —Prevention of Leakage Section XII.C.2— Emission Estimation Procedures Colorado Regulation 7, Section XVII 1. Is this tank located ate transmission/storage facility? 2. Is this condensate storage tank° located at an ail and gas exploration and production operation, well production facility', natural gas compressor station' or natural gas processing plant? 3. Is this condensate storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions° of this storage tank equal to or greater than 6 tons per year VOC? 'Storage bon& is atb),tct to Argo€aticn'0, Gentian XVII,Tf, C.18: C.3 Section XVII. B —General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1 - Emissions Control and Monitoring Provisions Section XVII.C.3 - Recordkeeping Requirements 5. Does the condensate storage tank contain onN"stabilized"liquids? ISfr.mt',, Tar€r is not sub)uce to Regulation 7, Section XVII.C.2 Section XVII.e.2-Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CFR, Part 60, Subpart Kb. Standards of Performance for Volatile Organic Liquid Storage Vessels 1. Is the Individual storage vessel capacity greaterthan or equal to 75 cubic meters (m') (-472 Bets)? 2. Does the storage vessel meet the following exemption In 60.111b(d)(4)? a. Does the vessel has a design capacity less than or equal to 1,589,874 ma( -10,000 BBL) used for petroleum' or ondensate stored,processed, or treated prior to custody transfer' as defined In 60,1111? 3. Was this condensatestorage tank constructed,reconstructed, or modified (see definitions 40 CFR, 60.2) afterluly 23, 19B4? 4. Does the tank meet the definition of "storage vessel"' In 60.1116? 5. Does the storage vessel store a"volatile organic liquid (VOL)"s as defined in 60,111b? 6. Does the storage vessel meet any one of the following additional exemptions: a. Is the storage vessel a pressure vessel designed to operate In excess of 204.9 kPa )^29.7 psi) and wlthoutemisslons to the atmosphere (60.110b(d)(2))?; or b. The design capacity is greater than or equal to 151 m51-950 BBL) and stores a liquid with a maximum true vapor pressure` less than 3.5 kPa (60.110b(b))?; or c, The design capacity Is greater -than or equal to 75 Ms ("472 BBL) but lass than 151 ms ["960 BBL) and stores a liquid with a maximum true vapor pressures less than 10,0 kPa(60,lltb)b)1? I6torage tank is cubists Vu NIPS Kb Subpart A, General Provisions. §60.112b- Emissions Control Standards for VOC §60.1136 -Testing and Procedures §60.1151- Reporting and Recordkeeping Requirements §60.116b - Monitoring'of Operations 40 CFR, Part 60, SubpartOO00. Standards of Performance for Crude Oil and Natural Gas Production Transmission and Distribution No Yk`e is Source Requires an OPEN. Go to the next question Go to next question Source Requires a permit Go to the next question Go to the next question Source Is subjectto Regulation 7 Section 01.0.21.; Go to the next question Source Is sub)ectto Regulation 7 Section VI.B.2.a.; Go to the next question Source is subject to Regulation 7 Section VI.B.2 a.(i); Go to the next question Storage Tank is not sublectto Regulation 7, Section VI.B.2.a.(ii)-(lli) Continue- You have indicated the site attainment status on the project summary sheet Storage Tank is not subject to Regulation 7, Section 011 -You have indicated the facility type on the protect summary sheet. Storage Tank is not subject to Regulation 7, Section 011 Continue - You have determined facility attainment status on the Project Summary sheet. Go to the next question - You have Indicated facility type on project summary sheet, Storage Tank Is not subject to Regulation 7, Section 011.0 Continue - You have indicated the source category on the Project Summary sheet Go to the next question -You have Indicated facility type on project summarysheet. Go to the next question Source Is subjectto parts of Regulation 7, Sections 0011.11K. Go to the next question Yag 'Storage Tank is not subject to Regulation 7, Section XVll.C.2 Go to the next question Go to the next question Go to the next question Go to the next question Go to the next question Source is s blestto NSPS Kb 1. Is this condensate storage vessel located at a facility in the onshore oil and natural gas production segment, naturalgas processing segment. natural gastransmission and storage segment of thelndustry?' 2. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) between August 23, 2011 and September 18,.2015? 3. Are paternal VOC emissions' from the individual storage vessel greater than or equal to 6tons per year? 4. Does this condensate storage vessel meet the definition of "storage vessel"' per 60.5430? 5. Is storage 1 subject to d controlled in accordance with requlrements for store a vessels in 40 CFR Part 60 Sub art Kb or 40 CFR Pare 63' Sub art RH? ISi S Tank is not 4b at to SOPS 0000 SubpartA, General Provisions per 460.5425 Table 3 460.5395 - Emissions Control Standards for VOC §60.5413- Testing and Procedures • 460.5395(g) - Notification, Reporting and Recondkeeping Requirements .460.5416(c) - Cover and Closet Vert System Monitoring Requirements. - 060.5417- Control Device Monitoring Requirements [Note: If a storage vessels previously determined to be subject to NSPS0000 due to emissions above 6 tons per year VOC on the applicability determination date, it should remain subject to NSPS 0000 per 60.5365(e)(2) even if potential VOC emissions drop. below 6 tons per year) 40 CFR, Part 60. Subpart 0000a Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction. Modification, or Reconstruction Commenced After September 18. 2015 1. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) after September 10, 2015? 2. Does this condensate storage vessel meet the definition of "storage Vessel"' per 60.5430a? 3 Is this condensate storage vessel located at a facility in the crude oil andnatural gasproduction segment, natural gas processing segment onatural gee transmission and storage segment of the industry? 4. .Are potential VOCemissions' f the individual storage vessel grater than or equal to 6 tons per year? 5. Is the storage vessel subject to and controlled In accordance with requirements for storage vessels In 40CFR Part: 60 Sub Kb or 40 CFR Pan 63 Subpart HH? SG niruc'ruvk is not subject to NOP? 00000 40 CFR, Part 63. Subpart MACE HH Offend Gas Production Facilities 1. Is the storage tank located at an oil and natural gas production facility that meets either of the following criteria: a. A facility that processes, upgrades or stores hydrocarbon liquids' (63.760(a )12)); OR b. A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end user' 163.760(a)(3))? 2. Is the tank located at a facility that s major' for HAPs? 3. Does the tank meet the definition of"storage vessel"" in 63.761? 4. Does the lank meet the definition of "storage vessel with the potential for flash emissions"' per 63.761? 5. Is the tank subject to controlrequirements under 40 CFR Part 60, Subpart Kb or Subpart 0000? - ISrorage'Tank is not subject to MACI`HH Subpart A, General provisions per 063.764 (a) Table 2 §63.766 - Emissions Control Standards 463.773- Monitoring §63.774- Recordkeeping.. §63.775 - Reporting RACT Review RACT review Is required if Regulation 7 does not apply AND if the tank It in the non -attainment area. If the tank meets both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the Clean Air Acl, its implementing regulations, and Air Quality Control Commission regulations. This document is not a rule or regulation, and the analysis it contains may not apply to a particularsiluation based upon the indlvidual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act, its implementing reguI tions, and Air Quality Control Commission regulations, the language of the statute or regulation al control. The use of non mandaloip language such as "recommend,""may," "should," and "can,"is intended to describe APCD InterpretatldnS and retornmendatlons. mandatory te11111nolog'y suEl es 'must" and ?dqulred"are Intended to de5CNbe Cdnfra111ng 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 of itself. MA`•' '141f`"`'%ir ontlnue - you have indicated the source category on the Project Summary sheet. forage Tank Is not subject NSPS 0000 -Tills tank was constructed prior to or after the applicability date... Go tothe next question Go to the next question Go to the next question Storage Tank is not subject NSPS 0000a. ontinue.-you have indicated the source category on the Project Summary sheet Storage Tank is not subject MACT NH- There are no MALT HH requirements fortanks at area Condensate Storage Tank(s) Emissions Inventory Section 01 Administrative Information Facility AIRS ID: Plant Point Section 02 - Equipment Description Details Detailed Emissions Unit Description: Emission Control Device Description: Requested Overall VOC & HAP•Cantrol Efficiency %: Section 03 - Processing Rate Information for Emissions Estimates Primary Emissions -Storage Tank(s) Actual Condensate Throughput = Requested Permit Limit Throughput= Potential to Emit (PTE) Condensate Throughput= Barrels (bbl) per year Actual Condensate Throughput While Emissions Controls Operating = Barrels (bbl) per year Barrels (hbl) per year Secondary Emissions - Combustion Device(s) Heat content of waste gas = ; Btu/scf Volume of waste gas emitted per BBL of liquid produced= cscf/bbl Actual heat content of waste gusrouted to combustion device = Requested heat content of waste gas routed to combustion device= 0 MMBTU per year 0 MMBTU per year Potential to Emit (PTE) heat cm -tent of waste gas routed to combustion device = 0 MMBTU per year Section 04- Emissions Factors& Methodologies Will this storage tank emit flash emissions? Emission -Factors Condensate Tank Pollutant. Uncontrolled Controlled (lb/bbl) (lb/bbl) (Condensate Throughput) (Condensate Throughput) Emission Factor Source VOC 2.14E-03 1.40E-05 7.71E-06 6.09E-07 1,22E-06 2.30E-04 0.00E+00 Benzene Toluene 104E+0 Ethylbenzene xylene n -Hexane 224 IMP Pollutant Control Device Emission Factor Source Uncontrolled Uncontrolled (Ib/MMBtu) (lb/bbl) (waste heat combusted) PM10 PM2.5 (Condensate Throughput) 0.0000 0.0000 0.0000 0.0000 NOx CO 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) - VOC PM10 PM2.5 NOx CO 5.27 0.00 0.00 5.27 0.1054 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 ' 0.00 0.00 0.90 - 0.00 0.00 0.00 0.00 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) Requested Permit Limits Uncontrolled Controlled (lbs/year) (lbs/year) Benzene Toluene Ethylbenzene Xylene - n -Hexane 224 TMP 68.99 0.00 0.00 68.99 1:36 3.449E-02 6.899E-04 38.00 0.00 0.00 38.00' 0.76 1.900E-02 3.800E-04 3.00 0.00 0.00 3.00 0.06 1.500E-03 3.000E-05 6.00 0,00 0.00 6.00 0.12 3.000E-03 6.000E -0S 1133.00 0.00 0.00 1133.00 22.66 5.665E-01 1133E-02 0.00 0.00 0.00 0.00 0.00 0.000E+00 0.000E+00 Section 06 - Regulatory Summary Analysis Regulation 3, Parts A, B Regulation 7, Section VI Regulation 7, Section XII.C, 0, 0. F Regulation 7, Section XII.G, C Regulation 7, Section XVII.B, Cl,.CO.' Regulation 7, Section XVII.C.2 Regulation 6, Part A, NSPS Subpart Kb Regulation 6, Part A, NSPS Subpart 0000 MOPS 0000a Regulation 8, Part E, MACT Subpart HH (See regulatory applicability worksheet for detailed analysis) Source requires a permit Facility is not subject to Regulation 7, Section VI Storage Tank is not subject to Regulation 7, Section 01.C -F Storage Tank is not subject to Regulation 7, Section 81.0 Storage Tank is not subject to Regulation 7, Section XVII Storage Tank is not subject to Regulation 7, Section XVII.C.2 Storage Tank is not subject to NIPS Kb Storage Tank is not subject to NSPS 0000 Storage Tank is not subject to MOPS 00000 Storage Tank is not subject to MAC+ FIB 25 of 38 K:\PA\2016\16 W E0773.CP2.xlsm Condensate Storage Tank(s) Emissions Inventory Section 07 - Initial and Periodic Sampling and Testing Requirements Does the company use the state default emissions factors to estimate emissions? If yes, are the uncontrolled actual or requested emissions estimated to be greater than or equal to 80 tons VOC per year? If yes, the permit will contain an "Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05-01. Does the company use a site specific emissions factor to estimate emissions? If yes and if there are flash emissions, are the emissions factors based on a pressurized liquid sample drawn at the facility being permitted? This sample should be considered representative which generally means site -specific and collected within one year of the application received date. However, if the facility has not been modified (e.g., no new wells brought on-line), then it may be appropriate to use an older site -specific sample. If no, the permit will contain an 'Initial Compliance" testing requirement to develop a site specific emissions factor based on guidelines in PS Memo 05 -Si. aN/A - the operator developed site -specific emissions factors to estimate Does the company request a control device efficiency greater than 95% for a flare or combustion device? Ifyes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Section 08 -Technical Analysis Notes it.Acsn�pg,toPSMemo 05-4laslootenkis•de5ned as follows"A tankiocatediata.non"E&Pfacilitythat usedto store,ondensate, urtersoriereondenseYen or misgeoaneous IubnrcaeY gilit rainage) - products:Ingenera€ it is used' star .dr age'matertalsfronivadues•tanks TheO consrde lop tanktobe a non=E&peondensatetartir 'Based°on Lk sm#errmaitors, these storage vessels,: : yyekeevaluatedtodeterrnine potentfai:regulatoryrequiremenCs:umfet Reguiatmmi:Sec[ionaXlUandXVil,P,leasa see sect on 06 a(fav_:fnr a'summary of4heana(ys :yvada6le iii the "Slop' TavhS gA'nalgsfs"iab. - : , a. , ,. , - - AEmissivosfromthissoure wereestimatedusingf&PTatihz version 3_0 a mid e fend sate cgpf,05lt nn tiased:un aProMax simulation of thestabrli`zereroae? egasplant;Tbe esoSc ofthesicoo lation Were thendwideil4'6iv siiid litie•dperaten is a„iumi'ngthe slap tanks irtaip:.amixtude afl50%walarand 50% condensate_ Typically, EPA.Tank 4V09du,used:tnesi5mateersi35sions iroms mirage:vesse!a:' mntainingsiabiil4aditd Asa•eesniti.astet,EPAtanks simulationwasma Eb,wmpa rth,thesmvlation,provided by the operatcr.(n order tonnthe EP tankeekentOkion;.waterwas addedto the. `¢ kiklenkschemica€it tubasoi(WVdatcr:APoperlieyl IIe0suty, 8'.3454•Rr/gat tfgozd/Vapof MW- 18.01520 lb/tb-mot Antoine's Equation Constants A'. H,) 9., 2. 1543 C;- 23.'420), The simu#ation•was 0,W -till the tank propertics.Suedidifthe Operator pcovidett.Siimalatron o'idditure ef5U%wateraed54%gasoline SOP Si and the assump5pntttat 'Zofthe regoafndtliiavgh;gt passes through each. . ,- of the two tanks. This simalatiea resulted•Ihtii*Ok0, Cemis saris ofP.4&,83 I /,year (Gasolioe emissions only). This result Wassoated by.a fact4irr2 taaCtauntfarthe twus{oaagevessels; idle$ resulteE)n- .. _tiitaLVO£ emissions of.'1.25 toy, This fssigpificafftfg lessthan tkevafue esbmated:ny ttie operator using E&P Tanks {5,27tpyj;-As a sesandsomtrari�n,xnatiiec EPAtanksislmulaxion.was run With tfie .same parametars:ins. esnd beonceisCepiOhe 011010 awas•updateifte representl0%water. and 90%canderuate(gaso(inel2VP11(, This simulaffionr*Wltert Is batal unconti,ouoilvOG,em'sssions of 5.15_ , tpy:i He re again, the value pr nided'byt eapeiator is:more conservative, 8ased,on this information it was.deternined the operatorestfmate•of missiOrtsur slit ly on orvats`v0 and the ref or s0p A enthe inaeE&P-Tanirs was!psed to egtitnete mis, sran,the" table aH flowsheer,":wotilE have beep ti(.Ye expeetedsetting for vistahilizedstnr eves el ratliep; .... dr,..... tank..rep ....„ ows6ee, ,Oh fifmPTanks v3.0 user manual expres mthaE""Ifyod select tieStablckrifflowshee@ tinn;to g wfl"cakulate only the myrkisgaod standingbssnonfom'€he utorag t k rstabie oil,"However, peratprdni aelectthe AP-42•method for.esdmatng workmganil'hreathingenilaghnsl thestmoltronrwhrohi th method a red in thtable dflowsh et,ltshouldb f ethernotedbratthe- ts tj Imrrlt n provided bytha nperatords eat ult flash emissievirki A' oo0 ESP iau89 mu»n yeas nushg the stable ni€ifowsheetaridtheltanSparameters prevfdedgbyth perator to •parative,purpasas. Tine ter 's�unpiati$t1"resulted (p Ot 2misslensu t.Etpy:p10 fl49 tp}lslivided b4 • ):Thedlfferenca between this noise and the.da.ue predicted usiogstlieoiltanh;in+ith,: , fl eek)S'3yy is-rieg}igpfie Therefoee.ihe o(remtpii pfovided0elue was deemed acdep fhr permitting purposes. NO,_and C di mxa ricked'.. table bdiated *adth the�cainbusti np,6%itrragc verse[-enirssionsae.accounted'3dr under point &Asa result, combvstinrs' d-newsau (alt oil tho ctrrai throughput is fisted as 066�eari n this analysis Penance th as ,5eaoncf: ditkfh" h, in ga Sr SO,B4f rosy 7 itwas detenemned tha mina( cofnphanr2 test tor g, apnea er tc obtain a ite spoor I;IigkdekkieirikdiiiitCzaideve; the AS T nkv eimulattoa eeomahv In rveHve estimate i}f RVP1x: Thuwater (50/50 or 90/10 maturr)A hod) atotiih 6alSove aR RVP"of9 to 12is S050ap arnljl)nl eons rvatn' :, - a Ili)The5 atisiondoestin Syplcaltyrequire itspeufmsam(lles he obternei forsiabil�dvo itai ions are not withmib%'ofmajor.sourcethresholds- re E,P rrish.an&McCatfney"(nett Vapocpressurelvafles'rsttge fp5rit2141k4 40si,;bl%t Tanksv30 appears to be a.reasonabr-estimate₹ rithestebihzeif roedensate flip: iced far'he follewing real n arts eomparedtgltimterpredated by the SP! T nIcs testsimolatine usrnga mix dgeat galsiitahts scabhenesaits a`thatzstsimd�tiondempastrate she g&P Ta n tie mirage uess the ontrdfrequiremen oftegutation"y, However, this soyeels.cotteslfedby en?etosedRam: This comrel$e etthe he'control devicetyprcallyl ofuired fo7oftereeevesel'cv anendosei (Iane_ 0,.,'A jndicst d Sagj n06 b ,firs source.ls pot s bl cttv.thg'co teal red ets of Regulation„.7);howexer, the contra fdevice. u.gedto treemiss ,Frorrilthi : omissions from 0.M:tanks cdvered under point 0'19- The storara ge vessels co"vet q sinter poijtt'013aeesuigactto RegulatmnZSeaion 3011 andtheYePi beer eettheaequireme i fthi Jegulation. vice HACT YBgifirementtO re in this'urorkshe t er. tentacled or operated. on range, 9'o l2 psl._ sr,%ofga rsis hnewith 0n res0(ts :l egulatli?R:S used tcontrol do ntrofdevice; ' 1p„The aperatoir fs requesdnga'9$°Io�comroV"efficiency far. tlta encfosedflore that ss tired°ia control the sm6,liied condanisafestoiagevassels stabllfx4d,slop tanksand'stab lfzed eondensat-e andsirar ;,"&5edout.Since this igreater tharothestandard 95°6eontroi granted bythe.Dfvisibn,�ielfaltestingwdiberagairedt o demonstiatahe eaciesedflare iscapatifeof chi singa 98.,4 destructioh of itievcywhen ControllinglheaboveIi5ted sourcesi'_ 'i i •" _ - ... - Section 09 - Inventory SCC Coding and Emissions Factors AIRS Point # Process # SCC Code 020 01 Uncontrolled Emissions Pollutant Factor PM10 0.00 PM2.5. 0.00 0 NOx 0.00 0 VOC 2.55E+00 98 CO 0.00 0 Benzene 1.67E-02 98 Toluene 9.18€-03 98 Ethylbenzene 7.25E-04 98 Xylene 1.45€-03 98 n -Hexane 2.74E-01 98 224 IMP 0.00E+00 98 Control % Units 0 lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput 16/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput lb/1,000 gallons condensate throughput 26 of 38 K:\PA\2016\16 W E0773.CP2.xism Condensate Tank Regulatory Analysis Worksheet C=1 do�Re Vi Lion 3 Parts Band 0 -OPEN and Permit RequiremTen�ts you hate indicated Lino; source is in :he'dnn-Attainment Bonn ATTAINMENT 1. Are uncontrolled actual emissions from any criteria pollutants from this individual source greater than 2 TPY (Regulation 3, Part A, Section ll.D.l.e)? 2. Isthe construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See PS Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions greater than TPY, 600 greater than 10 TPY or CO emissions greater than to WY (Regulation 3, Part B, Section 0.0,3)7 'you hove indicated ihassouece is in the Nnn.Attaimment Area NON -ATTAINMENT 1. Are uncontrolled emissions from any criteria pollutants from this individual source greater than l TPY (Regulation 3, Part A, Section ll.D.1.a)? 2. Is the construction date (service date) prior to 12/30/2002 and not modified after 12/31/2002 (See P5 Memo 05-01 Definitions 1.12 and1.14 and Section 2 for additional guidance on grandfather applicability)? 3. Are total facility uncontrolled VOC emissions from the greater than 2TPY, NOx greater than 5 TPY or CO emissions greaterthan 5TPY (Regulation 3, Part R, Section 11.0.2)? 'Source requires a pannit Colorado Regulation 7. Section V( 1, Does this storage tank store "petroleum liquid" as defined by Regulation 7 Section VIA.2.g? 2. Does this storage tank meet any of the exemptions listed In Regulation 7 Section VI.B.1? 3. Does the tank have a storage apacitygreater than 40,000 gallon. (952 barrels)? 4. Does the storage tank have a fixed roof? 5. Is the fixed roof tank used for the storage of petroleum liquids which have a true vapor pressure between 0.65 psis and 11.0 psia at 20.C (68°F)? 6. Is the fixed roof tank equipped with en internal floating roof? Storage' Tank i5 nut sOLiect to Regulation 7, Section 10,0.2 Storage nonk:n. not sirbjnrt to Regulation 7, Section Vi,8.2.e.(i) Storage Tonic is not subject to Regulation 7, Section )11.9.2.e,(3) -(iii) 7. Is the tank equipped with an external floating roof AND Is larger than 952bbl AND stores petroleum liquid AND Is located in ozone nonattalnment area? 8. Does the tank meet any of the exemptions of Section Vl.B.2.c.(l)(B)(1)? 9. Does the tank meet any of the exemptions of Section Vl.B.2.c.(I)(B)(2)? )R, P9esthet aka Li gilt? Mstere Bank is u Buds with true vapor 7,Secti In VI,B.gdl enge 'lank is not s,ibiect to Regotet on'1. Section Vl.R.2.c 11. Does the storage tank have a storage capacity less than 40,000 gallons (952 barrels)? 12. Does the storage tank store liquids with a true vapor pressure between 1.5 psia and 11.0 psla at 20'C? 13. Is the storage tank at a facility that receives and stores petroleum that Is not addressed by Regulation 7 Sections VI.C2 orVl.C.3? Storage Teak is not sullied to Regulation 7, Section Vl.B.3 Facility it not subinnnyn Royalatian 7, Section Vi Colorado Regulation 7. Section XII.C-F 1. Is this storage tank located In the 8 -hr ozone control area or any ozone non -attainment area or attainment/maintenance area? 2. Is thls storage tank located at an oil and gas exploration and production operation`, natural gas compressor station or natural gas drip station? 3. Is this storage tank located upstream of a natural gas processing plant? ISteragoTank is not citbject to Regulation 7, Section XII.C-F Section XIt.C.1 —General Requirements for Air Pollution Control Equipment —Prevention of Leakage Section XII.C.2—Emisslon Estimation Procedures Section %II.D—Emissions Control Requirements Section XII.E—Monitoring Section %II.F— Recordkeeping and Reporting Colorado Regulation 7. Section 011.0 1. Is this storage tank located in the Et -hr ozone control area or any ozone non-attalnment area or attalnment/maintenance area? 2. Is this storage tank located at a natural gas processing plant? 3. Does this storage tank exhibit"Flash" (e.g. storing non-stablllzed liquids) emissions and have uncontrolled actual emissions greater than or equal to 2 tons per year VOC? I Storage Tank is not subject to Regulation 7, Section XILG Section 000.6.0 -Emissions Control Requirements Section XII.C.1 —General Requirements for Air Pollution Control Equipment —Prevention of Leakage Section XII.C.2—Emission Estimation Procedures Colorado Reg4latlnn 7, Section XVII 1. Is this tank located at a transmission/storage facility? 2. Is this condensate storage tank' located at an oil and gas exploration and production operation, well production facility', natural gas compressor stations or natural gas processing plant? 3. Is this condensate storage tank a fixed roof storage tank? 4. Are uncontrolled actual emissions° of this storage tank equal to or greater than 6 tens per year VOC? I Storage Tank is not c,stlet to Regulation 7, Section XVII Section XVII.B— General Provisions for Air Pollution Control Equipment and Prevention of Emissions Section XVII.C.1- Emissions Control and Monitoring Provisions Section XV11.C.3 - Recordkeeping Requirements 5. Does the condensate storage tank contain only "stablllzed" liquids? (Storage Tank fs not ssrljrxt to Regulation 7, Section XVil.C,2 Section XVII.C.2-Capture and Monitoring for Storage Tanks fitted with Air Pollution Control Equipment 40 CPR. Part 60. Subpart Xb, Standards of Performance for Volatile Organic Liquid Storage Vessels 1. Is the individual storage vessel capacity greater than or equal to 75 cubic meters (m) (-472 BBB)? 2. Does the storage vessel meet the following exemption In 6D.111b(d)(4)? _ a. Does the vessel has a design capacity less than or equal to 1,589.874 ms[ 410,000 BRL) used for petroleurri or condergate stored, processed, or treated prior to custody transfer' as defined In 60.1116? 3. Was this condensate storage tank constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) afterluly 23, 1984? 4. Does the tank meet the definition of "storage vessel"' in 60.1111? 5. Does the storage vessel store a "volatile organic liquid (VOW' as defined in 60.1111? 6. Does the storage vessel meet any one of the following additional exemptions: a. Is the storage vessel a pressure vessel designed to operate in excess of 204.9 kPa ("29.7 psi] and without emissions to the atmosphere (60.110b(d)(2)(7; or wavog— WIMM Tiaarn OMB No Yes WOW Source Requires an APEN. Go to the next question Go to next question Source Requires a permit Continue - You have indicated the site attainment status on the project summary sheet. Storage Tank Is not subject to Regulation 7, Sadler XII -you have Indicated the facility type on the project summary sheet. Storage Tank Is not subject to Regulation 7, Section XII Continue - You have determined facility attainment status on the Project Summary sheet. Go to the next question - you have indicated facility type on project summary sheet. Storage Tank Is net subjectte Regulation?, Section 011.6 Continue -you have indicated the source category on the Project Summery sheet. Go to the next question - you have Indicated facility type on project summary sheet. Go to the next question Storage Tank Is not subject to Regulation 7, Section XVII Storage Tank Is not subject MPS Kb - The storage vessel capacity Is below the applicable threshold. b. The design capacity is greater than or equal to 151 ma (-'950 BBL] and stores a liquid with a maximum true vapor pressure less than 3.5 kPa (60.110b(b))?; or c. The design capacity Is greater than or equal to 75 Ma (^472 BBL) but less than 151 ma ]-'950 BBL] and stores a liquid white maximum true vapor pressure° less than 15.0 kPa(60.110b(b))? IStorase Tank is not sublet's nr NSPS Kt; Subpart A, General Provisions 560.1126 -Emissions Control Standards for VOC §60.1136 -Testing and Procedures §60.1]56 -Reporting and Recordkeeping Requirements §60.1166 -Monitoring of Operations 40 CFR, Part 60, Subpart 0000, Standards of Performance for Crude Oil and Natural Gas Productlerb Transmission and Distribution 1. Is this condensate storage vessel located ate facility In the onshore oil and natural gas production segment, natural ges processing segment or natural gas transmission and storage segment of the Industry? 2. Was this condensate storage vessel constructed,reconstructed, or modified (see definitions 40 CFR, 60.2] between August 23, 2011 and September 18, 2015? 3. Are potential VOCemissions' from the Individual storage vessel greater than or equal to 6tons per year? 4. Does this condensate storage vessel meet the definition of"storage vessel.' per 60.5430? 5. Is the storage vessel subject to and controlled In accordance with requirements for storage vessels in 40 CFR Part 60 Subpart Kb or 40 CFR Part 63 Sub art HH? (Storage Tankis not subject Ga NSPS 0000 Subpart A, General Provisions per §60,542STable 3 560.5395 -Emissions Control Standards for AOC §60.5413 -Testing and Procedures 560.5595(g) - Notification, Reporting and Recordkeeping Requirements 560.5415(c) -Cover and Closed Vent System Monitoring Requirements §60.5417 -Control Device Monitoring Requirements [Note: If a storage vessel is previously determined tribe subject to SOPS 0000 due to emissions above 6 tons per year ROC on the applicability determination date, It should remain subject to NSPS 0000 per 60.5365(e)(2) even If potential VDC emissions drop below 6 tans per year] 40 CFR, Part 60. Subpart 0000¢, Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction. Modification. or Reconstruction Commenced After September 18, 2015 1. Was this condensate storage vessel constructed, reconstructed, or modified (see definitions 40 CFR, 60.2) after September 18, 201$? 2. Does this condensate storage vessel meet the definition of "storage vessel"' per 60.54305? 3. Is this condensate storage vessel located at a facility In the crude oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment of the industry? 4. Are potential VOCemissions' from the Individual storage vessel greater than or equal to 6 tons per year? 5. 'stile Nora ge vessel subject to and controlled in accordance with requirements for store a vessels In 40 CFR Part 60 Sub art Kb or 90 CFR Part 63 Sub art HH? (Storage Tank is oat subject's NSPS 00000 90 CFR. Part 63, Subpart MACT HO. Oil and Gas Production Facilities, 1. Is the storage tank located at an oil and natural gas production facility that meets either of the following criteria: a. Afacility that processes, upgrades or stores hydrocarbon liquids' (63.760(0(2)):OR b. A facility that processes, upgrades or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to a final end users (63.760(a)(3))? 2. Is the tank located at a facility that Is major' for HAPs? 3. Does the tank meet the definition of "storage vessel"" in 63.761? 4. Does the tank meet the definition of"storage vessel with the potential for flash emissions"' per 63.761? 5. Is the tank subject to control requirements under 90 CFR Part 60, Subpart Kb orSubpart 00007 IStorag:Tank is not subject to MACT HIi Subpart A, General provisions per §63.764 (a) Table 2 §63.766- Emissions Control Standards §63.773- Monitoring §63.774-Recordkeeping 563.775 Reporting PACT Review RACr review Is required If Regulation 7 does not apply AND If the tank Is In the non -attainment area. If the tank meets both criteria, then review RACT requirements. Disclaimer This document assists operators with determining applicability of certain requirements of the. Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations. This document is note rule or regulation, and the analysis d contains may not apply to a particular situation based upon the individual facts and circumstances. This document does not change or substitute for any law, regulation, or any other legally binding requirement and is not legally enforceable. In the event of any conflict between the language of this document and the language of the Clean Air Act, its implementing regulations, and Air Quality Control Commission regulations, the language ofthe statute or regulation will control. The use of non -mandatory language such es "recommend,""may," "should," and 'cen,"Is intended to describe APCD Interpretations and recommendations. Mandatory terminology such as °must' and "required"ere intended to describe controlling requirements under Me terms of the Clean AlrAct end Air Quality Control Commission regulations, but this document does not establish legally binding requirements in and of Itself No✓ a Continue - You have Indicated the source category on the Project Summary sheet. Storage Tank Is not subject NSPS 0000 _This tank was constructed prior to or after the applicability dater Go to the next question Go to the next question Go to the next question Storage Tank Is not subject NSPS 0000a. Continue - You have indicated the source category on the Project Summary sheet. Storage Tank is not subject MACT HH-There are no MACE HH requirements for tanks at area sources Amine Unit Thermal Oxidizer Emissions Inventory Section 01- Administrative Information 'Facility AIRs ID: Coun Plant Point Section 02- Equipment Description Details One Detailed Emissions Unit the.am Description: gas is only rotated! Emission Control Device Nfon ,. Description: Requested Overall VOC & HAP Control Efficiency %: 0, Model: TOO SNC THD ?. t"015, The thermal oxrdi�i �ddzer.durfng SEA VRU-d1 Section 03- Processing Rate Information for Emissions Estimates TO Burner Rating (Supplemental Fuel)= °.....ZS;MMBtu/hr 193.8053097 MMscf/Year ' alallM 1130; stu/sci MMscf/day 1670.56485 MMscf/year Heat content of Supplemental Fuel= Acid Gas (Still Vent) Flow Rase = Acid Gas (Still Vent) Heat Content = Flash Tank Waste Gas Flow Rate = Flash Tank Waste Gas Heat Content = Pilot Light Rating = Heat Content of Pilot Light Fuel = Actual Hours of Operation = Requested Hours of Operation =- Actual heat input rate = Requested heat input rate= Potential to Emit (PTE) heat iput rate= Total Actual Waste Gas Combusted = Total Requested Waste Gas Combusted = Total Potential to Emit (PTE) Waste Gas Combusted = Section 04- Emissions Factors & Methodologies Toluene n -Hexane Pry ,d flash' tank' waste gas >l ' .... iu ih n 158244' Btu/scf -iMMscf/day 6.1375115 MMscf/year Btu/scf MMBtu/hr 0 MMscf/year Btu/scf . hrs/year New Source - not yet. installed ;hrs/year d ffaS 184.34 MMBTU per year 219,184.34 MMBTU per year 219,184.34 MMBTU per year 1,676.70 MMscf/year 1,870.51 MMscf/year 1,870.51 MMscf/year Amine Unit TO Emission Factor Source Emission Factors Pollutant Uncontrolled Uncontrolled lb/MMBtu lb/MMs (Waste Heat (Waste Gas Combusted) combusted). Emission Factor Source Section 05 - Emissions Inventory. Criteria Pollutants Potential to Emit . Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled. Controlled (tons/year) (tons/year) VOC PM10 0.00 0.00 1 0.00 0.00 0.00 0.00 0.00 I 0.00 0.00 0.00 Average Waste G 13.33562213 29 of 38 K:\PA\2016\ 16WE0773.CP2.xlsm Amine Unit Thermal Oxidizer Emissions Inventory PM2.5 50x NOx CO 0.00 0.00 0.00 0.00 0.00: 0:07 0.07 0.07 0.07 0.07 12.07 12.07 12.07 12.07 1207 12.07 12.07 12.07 12.07 12.07 Hazardous Air 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 Permit Limits Uncontrolled Controlled lbs/year) (Ibs/year)- Formaldehyde' 8.897E-03 8.897E-03 8.897E=03 - 8.897E-03 8.897E-03 I 17.7944 17.7944 Benzene 2.485E-04 2.485E-04 2.485E-04 2.485E-04 2.485E-04 0.4969 0.4969 Toluene 4.023E-04 4.023E-04 4.023E-04 4.023E-04 4.023E-04 0.8045 0.8045 n -Hexane 2.130E-01 2.130E-01 2.130E-01 - 2.130E-01 2.130E-01 425.9292 425.9292 Section 06- Regulatory Summary Analysis Regulation 1 Section II.A.1 - Except as provided inparagraphs2 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 approvedreference test method forvisible emissions measurement is EPA Method -9 (40 CFR,- Part 60, Appendix A (July, 1992)) in all subsections of Section II. A and B of this regulation. _ Section II.A'.5 - Smokeless Flare or Flares for the Combustion of Waste Gases No owneror operator of a smokelessflare or other flare for the combustion of waste gases shall -allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes In any sixty consecutive minutes. Regulation 2 Section I.A - No person, wherever located, shall cause or allow the emission of odorousair 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 far: 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 NOx. Part 8 —Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled NOx emissions from this facility are greater than the 2.0 TPY threshold (Reg. 3, Part B, Section II.D.2.a) Section 07 - Technical Analysis Notes 1. VOC is not included in the calculu e VOC emissions associated 2. AP -42 Chapter 5,3 provides intorsati:onwltst egards'toamine units. In sectmn 5. d.3 paragraph 7, the document stains Most plants employ elevated smokeless flares nrtall gas incinerators for complete combustion of all waste gas consts'tuents, including virtually 100 percent conversion of H25to SO2 .Little particulate, smoke, or hydrocarbons result fromYhesetrevsces.".This Is further supported by table 13.1 which provides emissiontsctors for gas sweetening plants. This table expresses the p rtsulate emission factor for amine units controlled bysmakele ssflares and tail gas i for und. - incinerators is negligible. 'It should be noted that the permit requiresthat daily checks be conducted to determine if the thermal oxidizer is. smoking. If smoke is observed during the daily checa the source is. required to either conduct o formal opacity observation,ormmedlateily shut in the equipment to. Investigate the causeof the smoke and conduct r epairs as necessary, Based onthisrequirement for the thermal oxidizer it can safely be assumed that the thermal oxidizer=willoperate without smoke on a regular basis. Also, if smoke is -observed, the operator will be required toassebthe uroblemand perform necessary maintenanceto prevent the thermal-oxidlzerfrom smoking. As such, I am comfortable assuming the particulate emitted from this source is negligible. The 0&?v# pla rialso sets a minimum combustion chamber temperature for the TO, tymaint ing-this temperature and other good combustion pracnices,the TO isiunlikely to em it significant amounts of particulate -as a result ofthycombustion of still - vent waste gas. -- If the total PM emission factor of 7.6-lb/Mast€- from AP -42 Chapter 1.4 were used, the total PM emissions (for both PM 10 and 2,5 ) associated with the combustors of flash tank and stilt vent waste gas would be 0.9 tpy. This is a very small amount of emissivrsand would not result in permit limits for PM or result in addition al regulatory requirements. - Based on the Information discussed above, it was determinedthatany PM generated from this combustion device is likely negligible and does not need to be calculated. - - 3. During normal operations, the flash tank emissions will mutedto a vapor recovery unit and recycled to the ..rut inlet while still vent emissions am routed to the thermal oxidizer, Based on this set u p, the throughput limit for the com buxtton of waste gas only accounts for flash tank waste gas routed toltbeTO during VRU downtime. The operator has requested a maximum .9:0% VRIJ downtime during which flash tank emissions orb IfSedto,theTO Since the flash tank waste gas is typically recycled, it was deemed u nnecessary to require the operator to routethe flash tang waste gas to the TO . n Further, the flash tank waste gas permitted to be routed to the TO. only accounts for 0.5 tpy of the overall permitted limit, 'during the initial compliance testetfeEdzffrw.'I*s a7 3 4. The operator indicated that there kn)Lao'3ioeter5associated with this thermal oxidizer. One tow meter will measuretotal still vent and flash tank waste gas routed to the TO. The second flow meter will measure total supplemental fun)corrsb bytheTO. Based on this information. there will be two throughput limit s in the permit for this source, One muIlmit the total amount of waste gas combusted and the other will limitthe amount of"supplemental fuel combusted.. Based on the location of the flow- meter forth e waste gas, it was determined that VRti downtime would not .berequired to be recorded, This is because the total flow of wasth gas routed to the thermal oxidizer will be recorded using a tow meter. 5. The operator indicated that the pilot fuel combusted by the thermal oxidizer is accounted for with the supplemental fuel. 6. Typically HAP emissionsare onlysalculatedfor the combustion of the supplemental fuel Perth sources sincethe HAP emiss ions associated with the still vent and 'lash, nb waste gas are calculated with the amine unit. In this instancethe operator chose to calculate HAPs associated with the combustion of the still vent a nd flash tank waste gas. This leads to a conservative estimateand is therefore acceptable for permitting purposes. -7.. The operator is requesting a 98% control efficiency for the thermal oxidizer that is used to control thestill ventand flash tank. Since this control value is greaterthan the standard 95% control granted by the Division, initial testing will be required todemonstratethe thermal oxidizer iscapable of achieving: a -98°a,. destruction efficiency when controlling still vent and flash tank emissions from the amine unit. Since the flash tank is only permitted to routed to the thermal oxidizer 10% of the time emit. is lixeI9 to have the greatest difficulty meeting the requested: destruction efficiency when only the still vent is routed to it (due to low he. content of -waste gas), it was determined the operator would- not be required t o route the flash tank totheTOdur,agthestacktest tademonstrate compliance with this initial compliance test. 8. 502 emissions are elculated with the amine unit (point015) becausetheoperatorused'the 502 emission factor from Table 53 _S of AP -42 chapter 5.3_This emission factor is based- on gas processed Ste as combusted. Please on with the amine unit re ardin lids calculation. by iher�d,F{ifne nta, ((t�vi(i3 g (ease see discussion g g --- Section 08 - Inventory 5CC Coding and Emissions Factors AIRS Point P Process if 5CC Code Uncontrolled Emissions Pollutant Factor Control % Units 30 of 38 K:\PA\2016\16W E0773.CP2.xlsm Amine Unit Thermal Oxidizer Emissions Inventory 021 01 02 The processes above are as follow: (i) 01- Combustion of supplemental fuel, (ii) 02 Combustion of still vent and flash tank waste gas PM10 0.0 0 lb/MMscf Burned PM2.5 0.0 0 lb/MMscf Burned NOx 113.0 0 lb/MMscf Burned VOC 0.0 0 lb/MMscf Burned CO 113.0 0 lb/MMscf Burned SOx 0.7 0 lb/MMscf Burned Formaldehyde 8.33E-02 0 lb/MMscf Burned. Benzene 2.33E-03 0 lb/MMscf Burned Toluene 3.77E-03 0 lb/MMscf Burned n -Hexane 2.0 0 Ib/MMscf Burned PM10 0.0 0 lb/MMscf Burned PM2.5 0.0 0 Ib/MMscf Burned NOx 1.3 0 Ib/MMscf Burned VOC 0.0 0 lb/MMscf Burned CO 1.3 0 lb/MMscf Burned SOx 0.0 0 lb/MMscf Burned Formaldehyde 9.83E-04 0 lb/MMscf Burned Benzene 2.75E-05 0 lb/MMscf Burned Toluene 4.45E-05 0 lb/MMscf Burned n -Hexane 2.35E-02 0 lb/MMscf Burned 31 of 38 K:\PA\2016\16W E0773.CP2.xlsm TEG Dehydrator Thermal Oxidizer Emissions Inventory 0 MMscf/year 105.12 MMscf/year 0.438 MMscf/year New Source - not yet Installed 0.00 MMBTU per year 43,068.54 MMBTU per year 43,068.54 MMBTU per year 0.00 MMscf/year 105,56 MMscf/year 105.56 MMscf/year Section 01 -Administrative Information Facility AIRS ID. County Plan Oxa�i Point Section 02 - Equipment Description Details One (1(thermat n idize7 (Make 2Bi Detailed Emissions Unit the TEG dehydratumtcevared. , d puii Emission Control Device Description gqa th p ntfun tlgnsas2fi Requested Overall VOC & HAP Control Efficiency Si TO Burner Rating (Supplemental Fuel) = 07' - 0 MMBtu/hr Heat content of Supplemental Fuel=k.y 1130-.. Btu/scf Waste Gas (Still Vent & Flash Tank) Flow Rate Waste Gas (Still Vent & Flash Tank) Heat Content = Pilot Light Rating = Heat Content of Pilot Light Fuel = Actual Hours of Operation = Requested Hours of Operation = Actual heat input rate = Requested heat input rate = Potential to Emit (PTE) heat input rate = Total Actual Waste Gas Combusted = Total Requested Waste Gas Combusted = Total Potential to Emit (PTE) Waste Gas Combusted = Section 04- Emissions Factors & Methodologies 405::. Btu/scf SRi scf/hr Btu/scf hrs/year hrs/year enmir�snrm� tEG�tuflti�asY��s�vta"u?svr stews Section 05 - Emissions Inventory ill0113Z0RINIEEI Formaldehyde Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tans/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tans/year) VOC PM10 PM2.5 Sox NOx CO 0.00 0.00 0,00 0.01 2.97 5,93 0.00 0.00 0.00 0.00 0,00 0,00 0,00 0,00 0,00 0.00 0,01 2,97 5.93 0.00 0.00 0.00 0.01 2.97 5.93 0.00 0,00 0.00 0.00 Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tom/year) Requested Permit Limits Uncontrolled Controlled (tons/year) (tons/year) Requested Permit Limits Uncontrolled Controlled (Ras/year( (Ibs/year( Formaldehyde 1,588E-03 4.434E-05 7.178E-05 3.800E-02 0.000E+00 0.000E+00 0,000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 1.588E-03 4.434E-05 7378E-05 3.800E-02 1.588E-03 4.434E-05 7.178E-05 3.800E-02 3.1752 0.0887 0.1436 76.0033 3.1752 0.0887 0.1430 76.0033 Benzene Toluene n -Hexane Section 06 - Regulatory Summary Analysis 32 of 38 KSPA\2016\16WE0773.CP2.xlsm TEG Dehydrator Thermal Oxidizer Emissions inventory Regulation 1 Section II.A.1- Except as provided in paragraphs 2 through B below, no owner or operator of a sourceshall 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, AppendixA (July, 1992)) in all subsections of Section II. A and B of this regulation. Section II.A.5--Smokeless Flare or Flares for the Combustion of Waste Gases No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions Into the atmosphere of any air pollutant which Is In excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. 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 theodorous air has been diluted with seven (7) or more volumes of odor free au. 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 NOx. Part B' —Construction Permit Exemptions Applicant is required to obtain a permit since uncontrolled NOx emissions from this facility are greater than the 2.0 TPYthresheld (Reg. 3, Part B, Section ll.D.2.a( Regulation 7 The TEG dehydrator that this thermal oxidizer controls is subject to Regulation 7 Section XII and XVII. As a result, the thermal oxidizer is subject to the requirements of these sections of Colorado Regulation 7. Section 07 -Technical Analysis Notes 1. VOC not included in the calculations above because the VOC emission mated with the amineunit are accounted forunder point 015. 2 Thewastegas flow mte:used to calculate .:emissions is based on the design capacity of the thermal oxidizer when combustingv apors with a not content of 405 Btu/scf. Typically, the waste gas combated by the cantroldetdce is estimated based on the simulation used to estimateemissmist from the source of emissions, in this case the TEC Dehydrator )point 016) However, the operators estimated waste gas flow rate and heat value results in a conservative estimate when comparedtu ho lnfor notion, obtained from the Glycalc simulation used to estimate TEG dehydrator emissions. For comparative purposes, the waste gas flow ra₹e and beet onions obtained Sum rho Glycalc was deter oreas follow, (I) Flesh Tack: Based on the"Rash TookOtfEnsStream" theifashtankwastegasSowratewnsdeterminedtobe.1,140ccf/brand[heheatcontentoored tit he esUmatedcomposfticnn this stream w n calculated at 1,5648tu/sch(ih Still Vent: There are two stream options iorcalatiatfng the stffivent waste gas flowfrom the GlyC icsimulation These streams are the "Regenerator Overheads Stream or the "Condenser VentStreatn." Based on the'. Regenerator Overheads5tream,' the waste gasfiaw rate is8,610 so₹/brand the heat content was calculated to be 130.5 auocf. Using the 'Condenser Vent Streamx" qre; waste gas flow -=rate Is 367 sef/lrr and the heat content was calculated to be 1150.2 BteJscf. It should be bated the heat content was calculated using the CASA Engineering Data Book, page 23 4, Figure 23-2. Using the values obtained from the "Flash Tank Off Gas Stream" and the "Regenerator Overheads Stream" the Nov and CO emissions were calculated to be 1.76 tpy and 3,51 tpy respectively. rising the values obtained from the"Flash Tank Off GasStream" and the "Condenser VentStream" the 500 end CO eissionswere calculatedto be 158 toy and 3.16 tpy respectively. Finally, thet1Ox and CO sonsealc fated using_tbe operator provided values-of12?000 scf/hr and 405 Btu/scfare 2J4tpy and 5.86 tpy respectively, Since the operators calculation resultsin a conservative estimate of -: emissions, it Is ocoepttble far permtwtig purposes. An examplecalculanon for determining 500 emissions is as follows: NOx(tpy)=)(1140scf/hr)`(87B0hrfyr)'(S MMscf/S,000,050 scfj*(1564 MMBtit(MMs t})+({8616scf/hr)*(8760 hr/yrill1MMscf/1,000,000 set). (130.5 MM Btu/MMscfj)'(0.138Rt/RfM8tu)= 176 tpy.. 3. The operator Indicated. that suppler, fuel will not be required for this thermal oxidizer. This will be confirmed with the initial compliance rest thatwill be required for this source. 4. The operator indicated a flew meter wilt be used to tracktvfol volume ofTEG still vent and flash tank waste gas routed to and combusted by this thermal oxidizer, 'As a result, a condition will be included: in the permit requiring that continuous operational flow meter be used to track this total volume. S. The operator indicatedthe pilot fue(flowrate a constant. As a result, they wiltassume the manufacturer provided pilot tight fuel value, the permit wilt notthclude a aooditloothat requires pilot fuel to be monitored.i • ow rate re determine pilot light 6. Tin npen000l'f requesting a 38% contminfficiencyforthethermalOxidizer Mats usedtacontrol the still vent and flash tank 5incethis control Yalue is greater than the standard 95% control grai by the Division, Initial testing wiil he required to demonstrate. the thermal oxidizeris apable of achieving a 98% destruction efficiency when controlling still vent andfiashtank emissions from the dehydration unit. 7, HAP amissionsfac ersuiill nut he included In the perm it because they are below reporting thresholds (250 lb/year♦.. B. Typically HAP emissioesareanly calculated for the combustion of the pilatfuelfor these sourcessince the FLAP emissions associated with the shil vent and flash tank waste gas are calculated with the dehydration unit In this instance the operator choseta calculate HAPs associated with thecombnstion of the savant and flash tank waste gas. This leads tea conservative estimate and istherefore: acceptablef r permitting purposes. operator yet cat w the eombustionofstill vent and flash tank emisctons that are ro used to . and connotledby.the tbermat ?§diner. The TCECI techmcal 9.Theo dislatcPM emissions associated fti₹ supplement 4: flares was reviewed since the NON and CO emission factors from this document 'Were used tataiculate still vent and flash tank combustion emissions. This document does not provide ;. specific: information with regards to PM emissions. Since there: is not readily available information forcaiculatingPM emission associated with thermal madders, ft lsacceptablethattbose potential issionsarenotcalcufated.. - - - - It should be noted that t€re peemlt requirap;then daily checks becandocted to determine if the thermal oxidizer lbuvnyktog. If smoke x observed during the dolly checkt{tesource is required to either conduct a format opacity o or lmniediately shut in the equipment to investigate the cause of the smokeand conduct repairsas necessary. Based on this requirement for the thermal oxidizer t can safely be assumed that the thermal oxidizer will operate without smoke on a regular basis. Also, If smoke is observed, the operator will be required to assess the problem and perform necessary maintenance to prevent.the tlermaloxidleerfrom smoking=As such, I amcomfortable assummgthe particulate emitted from thisseurce is negfigibia The O&M plan also sets a minimum combustion: chamber temperature for theTO. By maintaining this temperature and other good combustion practices, the TO is unlikely to em€tsignifiant amounts ofparticutarc asa result of the combustron of still vent waste gas. If the total PM emissionfactorof 7,61b/MMscffrom AP)42 Chapter 1.4 were used, thetoteI PM emissions (for both PM_ 10 and 2.S) associated with the combuston of1ash tank and still would be0.2Spy. This is a verysmall amount of em ssionsand would notresuit n permit Iimitsfor PM or result in additional regulatory requiemeens.:: eased on the information discussed above,it was determined that any PM generated from thiscombustion devicels likely negligible and does not need to he calculated. 33 of 38 K:\PA\2016\16W E0773.CP2,xlsm TEG Dehydrator Thermal Oxidizer Emissions inventory • Section 08- InventorySCC Coding and Emissions Factors AIRS Point # 022 Process N SCC Code 01 02 The processes above are as follow: (i) 01 - Combustion of still vent and flash tank waste gas, (ii) 02 - Combustion of pilot fuel. Uncontrolled Emissions Pollutant Factor Control % Units PM10 0.0 0 lb/MMscf Burned PM2.5 0.0 0 Ib/MMscf Burned NOx 55.9 0 lb/MMscf Burned VOC 0.0 0 lb/MMscf Burned. CO 111.6 0 lb/MMscf Burned SOx 0.2 0 lb/MMscf Burned Formaldehyde 2.99E-02 0 lb/MMscf Burned Benzene 8.34E-04 0 lb/MMscf Bumed Toluene 1.35E-03 0 lb/MMscf Burned n-Flexaee 0.7 0 lb/MMscf Burned PM10 0.0 0 lb/MMscf Bumed. PM2.5 0.0 0 lb/MMscf Bumed NOx 155.9 0 lb/MMscf Burned VOC 0.0 0 lb/MMscf Burned CO 311.3 0 lb/MMscf Burned 500 0.7 0 lb/MMscf Burned Formaldehyde 8.33E-02 0 lb/MMscf Burned Benzene 2.33E-03 0 lb/MMscf Burned Toluene 3.77E-03 0 lb/MMscf Burned n -Hexane 1.99E+00 0 lb/MMscf Burned 34 of 38 K:\PA\2016\16W E0773.CP2.xlsm Hydrocarbon Loadout Emissions Inventory Section 05 - Embslons Inventory Section 01 -Administrative Information Facility AIRS ID: County Pla Zr Point Section 02 -Equipment Doscriptors Details Detailed Emissions Unit Description: Emission Control Device Description: Is the loadout controlled? Collection Efficiency: Control Efficiency: 98.00 Requested Overall VOC & HAP Control Efficiency %: Section 03 -Processing Rate Information for Emissions Estimates Primary Emissions- Hydrocarbon Loadout Actual Volume Loaded= Requested Permit Limit Throughput= Potential to Emit (PTE) Volume Loaded = 1250 Barrels (bbl) per year .2503 Barrels (bbl) per year 250 Barrels (bbil per year Secondary Emissions -Combustion Device(s) Heat content of waste gas= Btu/scf Volume of waste gas emitted per year= 226018.1077 scf/year Actual heat content of waste gas routed to combustion device= Requested heat content of waste gas routedto combustion device= Potential to Emit (PTE) heat content of waste gas routed to combustion device= Section 04- Emissions Factor.&Methodologies Does the company use the state default emissions factors to estimate emissions? Does the hydrocarbon liquid loading operation utilize submerged fill? Emission Facto Pollutant Hydrocarbon loadout Uncontrolled Controlled (Ib/bbll (Ib/bbp (Volume Loaded) VOC 2.36E-0 0.80E100 0,00E+00 0.00E+00 3.60E-03 224 IMP 0.00E+00 Control Device (Volume Loaded) 0,00E+00 0.00E+00 7.20E-05 0.00E+00 Uncontrolled Uncontrolled Benzene Toluene Ethyl benzene Xylene n-Henne 4.10E-04 Actual Volume Loaded While Emissions Controls Operating = 0 MMB U per year o MMRTU per year D MMRTU per year The state default emissions factors may be used to estimate emissions, Emission Factor Source Pollutant (Ib/MMBN) (W/bbl) Emission Factor Source (waste heat combusted) (Volume Loaded) 0.00E+0G 0.00E+00 0.00E+00 0.00E+00 Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tom/year) Rom/year) Requested Permit Limits Uncontrolled Controlled +tom/year) (mns/yexr) PM10 PM2.5 505 NOx VOC CO 8.08 8,08 8,88 0,00 0.00 _ 0,00 _ 0,ne 0,00 _ 0,50 0.00 8.00 0.00 0.80 0,00 0.00 0.00 0.00 0,00 0.00 0.00 19.38 19,38 0.39 19.38 0.39 0.00 0.00 0,00 0,00 0.00 Hazardous Air Pollutants Potential to Emit Uncontrolled Ilbs/yearl Actual Emissions Uncontrolled Controlled llbs/year) (Ibs/year) Requested Permit Limits Uncontrolled Controlled (Ihs/yearl llbs/year) Benzene Toluene Ethylbenzene Xyleea n -Henna 224 TMP 67.34 67.34 1.35 _ _ 57.54 1.35 0.00 0,00 0,00 0,00 0.00 _ 0.00 _ 0.05 0.00 __ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 591.50 591.30 11,83 591.30 11.83 0.00 0.00 0.00 0.00 0.00 35 of 38 K:\PA\2016\16W E0773.CP2.xbm Hydrocarbon Loadout Emissions Inventory Section 06 -Re oleo Summary Analysis Regulation 3, Parts A, B RACT- Regulation 3, Part B, Section III.D.2.a (tee regulatory applIntiility worksheet for detailed analysis) Source requires a permit The laadout must be operated with submerged till to satisfy RACT. tendon 07. Initial and Periodic Sampling and Testing Requirements Ooes the company request a control device efficiency greaterthan 95%for a fare or combustion device?.e'.x,,�,,.srx✓% Ifyes, the permit will contain and initial compliance test condftion to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling Secdon 09 -Inventory SCC Coding and Emissions Factors AIRS Point IOadpu[apUYCgneE) hgsed ofthl5 p14ti It cieaff,0104 rain tow n lee h1h Process SCC Code 024 01 4.06-00142 Crude Oil, Submerged Loading Normal Service (5=0.81 Uncontrolled Emissions Pollutant Factor Control % Unit PM10 0.00 b/1,000 gallons transferred PM2.5 0.00 b/1,000 gallons transferred SOS 0.00 b/1,000 gallons transferred NOx 0.00 b/1,000 gallons transferred VOC 5-8 6/1,000 gallons transferred CO 0.00 6/1,000 gallonstansferred Benzene 9.76E-03 9 b/1,000 gallonstansferred Toluene c.00 9 6/1,000 gallons transferred Ethylbenzene 0.00 9 b/1,000 gallons transferred Xylene 0.00 9 b/1,000 gallons transferred n-Nexane 8.57E-02 9g b/1,000 gallons transferred 224TMP 0.00 98 b/3,000 gallons transferred 1 36 of 38 Ki\PA\2016\16OOE0773.CP2.xism Hydrocarbon Loadout Regulatory Analysis Worksheet Colorado Regulation 3 Pena Stand B - OPEN and Permit Requirements i You have inditetadth¢t eons h, in tho NomAtiahnuontAlea ATTAINMENT 1. are uncontrolled actual emissions from any criteria pollulanh from this Irdlrlduai source greaMr than 2TPY (Regulation 3, Part A, Section ll.0.1.a)1 a. Is Me Iwdout loeatedat an exploration and production site tog, well pad) (Regulation 3, Pan e,Sec0on il.D.1.11t 3. Is the loadoutoperztion loading lass Man 10,000 gallons (23.9 0a..a) of crude l per day on an annual average basis, 4. Is Me 100400topera00, loading less than 6,750 bids per year of condensate via splash fill, 5. Is the loadoutoperation 1057176 leo than 16,300 bbls per year of condensate via submerged IN praeduse, 6. are total fecl.Ry uncontrolled VOC .missions greater Man 1077, NOg greater than 10TH or CO emissions greater than 10 TPY(Regulaton 3, Part section ll. 0.317 to:: Wavt Indirnted that seuene ism She Noweiminneni Aren 1. o n IAINMPNT 1. Are uncontrolled emission Romany n solo pollutanh from t.s individual source greater than STPli (Regulation% PartA, 5eNon 2. Is the loadoutlocaoa at an exploration and luau) n 10,000 e.g., weeass taegulacm3,Pan B,SeNo511.0.1.1), Is the loadout oparagon loading less than 10,000 gallons (23g BBIs) of crude oil per dayon anannWl average basis? Is the Madout operation loading less Man 6,750 bbls per year d condensate via splash all, 5. 0 the loadtut operation loading less Man 16,300 Weis gammas of condensate vie submerged all procedure, 6. Are total MOW uncontrolled VOC emission from the greater Man2TPY, NOx greater than 5 TPY or Co emissions greater Nun 5TPy(Regulation 9, Part 5, Section 11.0.21, 5ooe00 raqutraz a permit 7. Ma -are uncontrolled UDC emissl0m from Me loadout operation greater than 20yy(Regulation 3, Part B,Scc5on law -Mt 'hie toe7uot must be 400.02, softit submerged Rii to s:3bm., tea. Dledsimer This daumenl assists operators with delamtnlrg appOnablillydcerteln requirements dfhe Clean Alt Acl. Its Implenentlrg re0ulatlons, and Air Quality Control Commission regulations. This dacungd is not rub or regulation, and the analysis ',contains may not apply toe particular situation based upon to IndNdual tat. and clmumslawes. This dxumant clam rat charge on subalthte Ia0nylaw, mpu/etion, any other legally binding requirement and la no le0agy enforceable. Intone event deny contact between to language of this cbcement and the language of She Clean AlrAct„ as Implementing regulations, and Air Qua(dy Coned Commission regulations, the language dfha statute anregulatm will oontn1 The use ofnen- nadaloy language such as'recommana—may, "shaYd"end tan,'is Wand. to desalt o APCD Inierpretatms ardrecanmsrd0tms. Mandatory tamindogy sash as -must' andlaqubed are Intended todasonba controlling requirements under the lama d the Clean Air Act endAir Quality Control Commission regulations, but this cbcument des not estabbshlegally biairg regWraranta In andorltssi Go ton. ctia. Go to q non6 Ile Madout requires a permit Iwdout must be operated with submerged NI to satisfy RACE. Insignificant Source Summary se thetlare,s notintended to control any, plannedaperations.l Indicated to the operatorthac od Cad It111 �1nple000d 000 0 yfloapexattire%puessedthey understoodttl5 vaLiestiseittrzitie_o(6ilbtlpnriefesiononovided,l expressed to theoperatorthae crUst; By tsingddroinfornatiotravadabltin the E&P tanksimdations (heat content °erica[). erodes These values, It wood appear that this soerc a would notsequir'e. telculat1464 nsedtoesfirrvar€etn-,$*801r0m[h1uu fete may be referensed okaths manutaeturor eoinr0dfor_nascd on e tompl Section 03 -Processing Rate Information for Emissions Estimates Requested Throughput = ::(,$7 bbl/year G08= 9,000 scf/bbl Gas Flow Rate = 214582.77 scf/year Heat Content 3934.3. tO / cf Requested Throughput= GDR= Gas Flow Rate = Heat Content = Gas Flow Rate = Heat Content= Operation Hours = Gas Flow Rate = Heat Content = Actual Hours of Operation = Phase!, d kP perEies.(Palh$OT+7T';' , 226018.1077 sct/year 0.226018108 MMscf/year 1 � 333813: Btu/scf Conservatively assume highest heat content of stahillaed condensate hrs/year New Source- not yet Installed Section 04 -Emissions Factors & Methodologies 0.21458277 MMscf/year Average W 3923.996 0.11118411 MMsef/year 0.438 MMscf/year Process Ul:Combosti0notstarage vesselivastegos MIMIMIlff a.ia. IIMMEMIMITERIE err✓✓ !MrITEM .. i' ProcesO3: Combustion of Phase II Loadoer Waste Gas . :rmgzsis5,7zrmisimans iiimmiscommegnmessmomm NommEml ,r Process O2: Combustion of pilot light fuel Section 05- Emissions Inventory Criteria Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions Uncontrolled Controlled (tons/year) (tons/year) Requested Perm[ Limits Uncontrolled Controlled (tons/year) (tons/year) 80C . PM10 PM2.5 SOS NO0 CO. 0.00 .0.00 0.00 0.00 0.00 0.80 0.00 0.00 0.00 0.00 0.00 0.00 0.00 - 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.18 0.18 0.18 0.18 ' 0.18 0.37 0.37 0.37 0.37 0.37 Hazardous Air Pollutants Potential to Emit Uncontrolled (tons/year) Actual Emissions . Uncontrolled Controlled (tons/year) (tors/year) Requested Permit L'mifs Uncontrolled Controlled (tons/year) (tons/year) tequested Permit Limit Jncontrolle Controlled (lbs/ymr) (lbs/year) Formaldehyde 0.000E+0o 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.0000 0.0000 . Benzene - 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.0011 0.0000 Toluene 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.000E+00 0.0010 0.0000 n -Hexane 0.000E+00 0.000E+00 0.000E+00 0.0001800 0.000E+00 0.00@0 0.0000 Permit number: Date issued: Issued to: COLORADO Air Pollution Control Division Department of Public Health & Environment CONSTRUCTION PERMIT 16WE0773 Facility Name: Plant AIRS ID: Physical Location: County: General Description: Issuance: 2 Discovery DJ Services LLC Discovery Fort Lupton Plant 123/9E99 SEC 11 T1 N R66W Weld County Natural Gas Processing Plant Equipment or activity subject to this permit: Facility Equipment ID AIRS Point Equipment Description Emissions Control Description El 001 One (1) Caterpillar Model: G3516B SN: TBD natural gas fired, turbocharged, 4SLB reciprocating internal combustion engine, site rated ' at 1,380 HP and 1400 RPM. This emission unit is used for natural gas compression. Oxidation Catalyst and Air -Fuel Ratio Controller E2 002 One (1) Caterpillar Model: G3516B SN: TBD natural gas fired, turbocharged, 4SLB reciprocating internal combustion engine, site rated at 1,380 HP and 1400 RPM. This emission unit is used for natural gas compression. Oxidation Catalyst and Air -Fuel Ratio Controller E3 003 One (1) Caterpillar Model: G3516B SN: TBD natural gas fired, turbocharged, 4SLB reciprocating internal combustion engine, site rated at 1,380 HP and 1400 RPM. This emission unit is used for natural gas compression. Oxidation Catalyst and Air -Fuel Ratio Controller . E4 004 One (1) Caterpillar Model: G3516B SN: TBD natural gas fired, turbocharged, 4SLB reciprocating internal combustion engine, site rated at 1,380 HP and 1400 RPM. This Oxidation Catalyst and Air -Fuel Ratio Controller [COLORADO Air Pollution Control Division Del>: mem of Pub*: Heu's'h. 1 eriiro rnent Page 1 of 46 emission unit is used for natural gas compression. RP 006 Natural gas venting from reciprocating compressor rod packing. Emissions from this source are vented to the atmosphere. None D1 007 One (1) Enerflex Ethylene Glycol (EG) natural gas dehydration unit (Model Et Serial Number: TBD) with a design capacity of 20 MMscf per day. This emissions unit is equipped with one (1) gas -glycol pump (Make, Model, SN: TBD) with a design capacity of 7.5 gallons per minute. This unit is equipped with a reboiler, still vent and flash tank. Emissions from the still vent are routed -toe condenser and then to an enclosed flare. Emissions from the flash tank are used as fuel gas for the regenerator reboiler or routed to the enclosed flare. D2 008 One (1) Ethylene Glycol (EG) natural gas dehydration unit (Make, Model Et Serial Number: TBD) with a design capacity of 20 MMscf per day. This emissions unit is equipped with one (1) gas -glycol pump (Make, Model, SN: TBD) with a design capacity of 7.5 gallons per minute. This unit is equipped with a reboiler, still vent and flash tank. Emissions from the still vent are routed to a condenser and then to an enclosed flare. Emissions from the flash tank are used as fuel gas for the regenerator reboiler or routed to the enclosed flare. FUG 009 Equipment leaks (fugitive VOCs) from a natural gas processing facility. None CT 010 Ten (10) 400 barrel fixed roof storage vessels connected via liquid manifold used to store condensate. Emissions from this source are a function of vapor recovery unit (VRU) downtime. 10% VRU downtime is assumed. Vapor Recovery Unit (VRU) and Enclosed Flare during VRU downtime. E5 011 One (1) Caterpillar Model: G3508B SN: TBD natural gas fired, turbocharged, 4SLB reciprocating internal combustion engine, site rated at 690 HP and 1400 RPM. This emission unit is used for natural gas compression. Oxidation Catalyst and Air -Fuel Ratio Controller E6 012 One (1) Caterpillar Model: G3508B SN: TBD natural gas fired, turbocharged, 4SLB reciprocating internal combustion engine, site rated at 690 HP and 1400 RPM. This emission unit is used for natural gas compression. Oxidation Catalyst and Air -Fuel Ratio Controller COLORADO Air Pollution Control Division Page 2 of 46 Plant Flare 013 One (1) enclosed flare (Make, Model, SN: TBD) used to control emissions from the ethylene glycol dehydration unit still vent (point 007 and 008). This enclosed flare also controls emissions from the ethylene glycol dehydration unit flash tank (point 007 and 008) when emissions are not routed to the reboiler and from the condensate storage vessels (point 010) when emissions are not routed to the VRU. None LT 014 Truck loadout of condensate. None Al 015 One (1) methyldiethanolamine (MDEA) natural gas sweetening unit (Make: TBD, Model: TBD, Serial Number: TBD) for acid gas removal with a design capacity of 25a MMscf per day. This emission unit is equipped with three (3) (Make: TBD, Model: TBD). electric driven amine recirculation pumps with a total limited capacity of 608 gallons per minute of lean amine. Only two (2) amine recirculation pumps will be operated at any given time. The third amine recirculation pump serves as a back-up only. This amine unit is equipped with a natural gas/amine contactor,- reflux condenser, flash tank, still vent and amine regeneration reboiler covered under point 123/9E99/017. Emissions from the flash tank are routed directly to the vapor recovery unit (VRU) that recycles the emissions back to the plant inlet. During VRU downtime, flash tank emissions are routed to a thermal oxidizer (TO). The acid gas stream from the still vent is routed to a condenser and then to a TO. The TO is covered under point 123/9E99/021 and has a 98% destruction efficiency. During TO downtime, the amine unit shuts down until the TO is back in operation. D3 016 One (1) Triethylene glycol (TEG) natural gas dehydration unit (Make: TBD, Model: TBD, Serial Number: TBD). This emissions unit is equipped with one (1) (Make: TBD, Model: TBD) electric driven glycol pump with a design capacity of 20 gallons per minute. This dehydration unit is equipped with a still vent, flash tank, and a reboiler burner. Emissions from the still vent are routed to a BTEX condenser and then to a thermal oxidizer (TO). Flash tank emissions are routed directly to a TO. The TO is covered under point 123/9E99/022 and has a 98% destruction efficiency. During TO downtime, the dehydration unit shuts down until the TO is back in operation. COLORADO Air Poilution Control Division Czrt?r.e.^.t or Hea,,th v Envimrvent Page 3 of 46 HI and H2 017 Two (2) natural gas fired hot oil heaters (Make: TBD, Model: TBD, Serial Number: TBD). The heaters each have a design rate of 50 MMBtu/hr. Each heater is equipped with a low NOx combustion system for minimizing emissions of nitrogen oxides. The heaters provide heat for hot oil that is circulated throughout the plant as a heat transfer medium. None H3 018 One (1) natural gas fired regenerator heater (Make: TBD, Model: TBD, Serial Number: TBD). The heater has a design rate of 15 MMBtu/hr. This heater is equipped with a low NOx combustion system for minimizing emissions of nitrogen oxides. The heater provides heat for mole sieve regeneration. None CT2 019 Four (4) 1,000 barrel fixed roof stabilized condensate storage vessels connected via liquid manifold. Enclosed Flare ST 020 Two (2) 400 barrel fixed roof storage vessels connected via liquid manifold. These storage vessels are used to store a mixture'°of stabilized water and condensate. Enclosed Flare Cl 021 One (1) thermal oxidizer (Make: TBD, Model: TBD, Serial Number: TBD) used to control still vent and flash tank emissions from the amine unit covered under point015. Amine unit flash tank emissions are routed to this thermal oxidizer during 10% VRU downtime. The thermal oxidizer is design rated at 25 MMBtu/hr None C2 022 One (1) thermal oxidizer (Make: TBD, Model: TBD, Serial Number: TBD) used to control still vent and flash tank emissions from the TEG dehydration unit covered under point 016. None LT 024 Loadout of stabilized condensate and slop (tiixture of stabilized condensate and water) to -tank trucks. Enclosed Flare Points 001-004: These engines may be replaced with another engine in accordance with the temporary engine replacement provision or with another Caterpillar G3516B engine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. Points 011-012: These engines may be replaced with another engine in accordance with the temporary engine replacement provision or with another Caterpillar G3508B engine in accordance with the permanent replacement provision of the Alternate Operating Scenario (AOS), included in this permit as Attachment A. This permit is granted subject to all rules and regulations of the Colorado Air Quality Control Commission and the Colorado Air Pollution Prevention and Control Act (C.R.S. 25-7-101 et seq), to the specific general terms and conditions included in this document and the following specific terms and conditions. REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION COLORADO ( Air Pollution Control Division Publi4Z Health t, Es T,rgnent Page 4 of 46 1. YOU MUST notify the Air Pollution Control Division (the Division) no later than fifteen days of the latter of commencement of operation or issuance of this permit, by 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/pacific/cdphe/other-air-permitting- notices. 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, hall 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/pacific/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.) 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. Points 001-004 and 011-012: 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 • Serial number • Manufacturer • Model Number This information shall. be included with the Notice of Startup submitted for the equipment. (Reference: Regulation Number 3, Part B, III.E.) 6. Points OO7-008, and 016: The following information shall be provided to the Division within fifteen (15) days of the tatter 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. (Reference: Regulation Number 3, Part B, III.E.) 7. Point 013, 017-018, and 021-022: 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 COLORADO 1 Air Pollution Control Division ,,..eparrientof f .tfs¢it Wee3ith & ErNirrorment Page 5 of 46 This information shall be included with the Notice of Startup submitted for the equipment. (Reference: Regulation Number 3, Part B, III.E.) 8. Point 015: 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 amine unit manufacturer name, model number and serial number • The amine circulation pump manufacturer name and model number This information shall be included with the Notice of Startup submitted for the equipment. (Reference: Regulation Number 3, Part B, III.E.) 9. 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 10. Emissions of air pollutants shall not exceed the following limitations. (Regulation Number 3, Part B, Section II.A.4.) .A.4. ) Monthly Limits: t Facility Equipment ID AIRS Point Pounds per Month Emission Type PM2.5 PM10 SOX H25 NOX VOC CO El 001 ---- --- --- --- 1,138 1,087 1,138 Point E2 002 --- --- --- --- ! 1,138 1,087 1,138 Point E3 003 --- --- -- - - 1,138 1,087 1,138 Point E4 004 --- --- --- --- 1,138 1,087 1,138 Point RP 006 --- --- --- --- --- 238 --- Fugitive D1 007 --- --- --- --- --- 68 --- Point D2 008 - --- --- --- --- --- 68 --- Point FUG 009 ---' --- --- --- --- 7,304 --- Fugitive CT 010 --- --- --- --- --- 1,308 --- Point E5 011 --- --- --- --- 578 628 578 Point E6 012 --- --- --- --- 578 628 578 Point Plant Flare 013 --- --- --- --- 781 --- 1,545 Point LT 014 --- --- --- --- --- 832 --- Point Al 015 --- --- 5,232 68 --- 1,410 --- Point D3 ' ' 016 --- --- --- --- --- 1,308 --- Point H1 and H2 017 561 561 --- --- 2,243 408 4,468 Point COLORADO Air Pollution Control Division of Public ti { 13&M Yr 4 Page 6 of 46 N The owner or operator shall calculate monthly emissions based ort"the calendar month. Facility -wide emissions of each individual hazardous air pollutant shall not exceed 1,359 pounds per month. H3 018 --- --- --- --- 459 221 459 Point CT2 019 --- --- --- --- --- 68 --- Point ST 020 --- --- --- --- --- 17 --- Point Cl 021 --- --- --- --- 2,056 --- 2,056 Point C2 022 --- --- --- --- 510 --- 1,019 Point LT 024 --- --- --- --- -- 68 --- Point Facility -wide emissions of total hazardous air pollutants shall not exceed 3,398 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 Tons per Year Emission Type PM2 5 PM10 SO. H2S" NO, V0C CO El 001 --- --- --- --- 6.7 6.4 6.7 Point E2 002 ": --- ---. --- --- 6.7 6.4 6.7 Point E3 003u,-- --- --- --- 6.7 6.4 6.7 Point E4 004 , --- --- --- --- 6.7 6.4 6.7 Point RP 006 ---> --- --- --- --- 1.4 --- Fugitive D1 007 --- --- --- --- --- 0.4 --- Point D2 008 ---. --- --- --- --- 0.4 --- Point FUG,, 009 --- --- --- --- --- 43.0 --- Fugitive CT 010 - --- --- --- --- --- 7.7 --- Point E5 011 --- --- --- --- 3.4 3.7 3.4 Point E6 012 --- --- --- --- 3.4 3.7 3.4 Point Plant Flare 013 --- --- --- --- 4.6 --- 9.1 Point LT 014 --- --- --- --- --- 4.9 --- Point Al 015 --- --- 30.8 0.4 --- 8.3 --- Point 'COLORADO Air Pollution Control Division "hit ,rime ,t Ptiitia 1 i : E,Nir +;:merit Page 7 of 46 D3 016 --- --- --- --- --- 7.7 --- Point H1 and H2 017 3.3 3.3 --- --- 13.2 2.4 26.3 Point H3 018 --- --- --- --- 2.7 1.3 2.7 Point CT2 019 --- --- --- --- --- 0.4 --- Point ST 020 --- --- --- --- --- 0.1 --- Point C1 021 --- --- --- --- 12.1 --- 12.1 Point C2 022 --- --- --- --- 3.0 --- 6.0 Point LT 024 --- --- --- --- --- 0.4 --- Point Note: See "Notes to Permit Holder" for information on emission factors and methods used to calculate limits. 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 shalt not exceed 20.0 tons per year. The facility -wide emissions limitation for hazardous air pollutants shall apply to all permitted emission units at this facility. 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 bothcriteria and hazardous air pollutants, shall be determined on a roiling twelve (12) month total. By the end of each month a new twelve month total is calculated based onthe 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. 11. Points 007-008: Compliance with the emission limits in this permit shall be demonstrated by running the ProMax version 4.0 or higher on a monthly basis using the most recent extended wet gas analysis and recorded operational values, including: gas throughput, lean glycol recirculation rate, chiller temperature and pressure, condenser temperature, wet gas inlet temperature and pressure, and flash tank temperature and pressure. Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into the model and be provided to the Division upon request 12. Point 009: The operator shall calculate actual emissions from this emissions point based on representative component counts for the facility with the most recent gas and liquids analyses, as required in the Compliance Testing and Sampling section of this permit. The operator shall maintain records of the results of component counts and sampling events used to calculate actual emissions and the dates that these counts and events were completed. These records shall be provided to the Division upon request. 13. Point 015: Compliance with the emission limits in this permit shall be demonstrated by running the ProMax model version 4.0.16071.0 or higher on a monthly basis using the most recent amine unit inlet extended sour gas analysis and recorded operational values, including: gas throughput, lean amine circulation rate, MDEA weight concentration in the lean amine stream, flash tank temperature and pressure, sour gas inlet temperature, and sour gas inlet pressure. Recorded operational values, except for gas throughput, shall be averaged on a monthly basis for input into the ProMax model and be provided to the Division upon request. COLORADO Air Pollution Control Division pt<tt x, t 'r riiuo Page 8 of 46 14. Point 016: 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: gas throughput, lean glycol recirculation rate, flash tank temperature and pressure, wet gas inlet temperature, and wet gas inlet pressure. Recorded operational values, except for gas throughput, 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 E1 001 Oxidation Catalyst and Air -Fuel Ratio Controller V0C, CO, and Formaldehyde E2 002 Oxidation Catalyst and Air -Fuel Ratio Controller V0C, CO, and Formaldehyde E3 003 Oxidation Catalyst and Air -Fuel Ratio Controller VOC, CO, and Formaldehyde E4 004 Oxidation Catalyst and Air -Fuel Ratio Controller V0C, CO, and Formaldehyde D1 007 Still Vent: Condenser and Enclosed Flare V0C and HAP Flash Tank: Reboiler or Enclosed Flare D2 008 Still Vent: Condenser and Enclosed Flare V0C and HAP Flash Tank: Reboiler or Enclosed Flare CT ' 010 Vapor Recovery Unit (VRU) V0C and HAP Enclosed Flare during VRU downtime V0C and HAP E5 0 t 1: Oxidation Catalyst and Air -Fuel Ratio Controller V0C, CO, and Formaldehyde E6 0l2 Oxidation Catalyst and Air -Fuel Ratio Controller V0C, CO, and Formaldehyde Al 015 Still Vent: Routed to thermal oxidizer covered under point 123/9E99/021. V0C and HAP Flash Tank: Recycled to the plant inlet via vapor recovery unit (VRU). Routed to thermal oxidizer covered under point 123/9E99/021 during VRU downtime. D3 016 Still Vent: Routed to thermal oxidizer covered under point 123/9E99/022. V0C and HAP Flash Tank: Routed to thermal oxidizer covered under point 123/9E99/022. COLORADO Air Pollution Control Division ±kbtt Nea€;n &E;lnorovnt Page 9 of 46 CT2 019 Enclosed Flare VOC and HAP ST 020 Enclosed Flare VOC and HAP LT 024 Enclosed Flare VOC and HAP PROCESS LIMITATIONS AND RECORDS 16. This source shall be limited to the following maximum processing rates as listed below. Monthly records of the actual processing rates shall be maintained by the owner or operator and made available to the Division for inspection upon request. (Regulation Number 3, Part B, II.A.4.) Process Limits Facility Equipment ID AIRS Point Process Parameter Annual Limit Monthly Limit (31 days) El 001 Consumption of natural gas as fuel 80.3 MMscf 6.8 MMscf E2 002 Consumption of natural gas as fuel 80.3 MMscf 6.8 MMscf E3 003 Consumption of natural gas as fuel 80.3 MMscf 6.8 MMscf E4 004 Consumption of natural gas as fuel 80.3 MMscf 6.8 MMscf RP 006 Natural gas, vented from compressor rod packing 3.4 MMscf 0.29 MMscf D1 007 Natural Gas Throughput 7,300 MMscf 620 MMscf D2 008 Natural Gas Throughput 7,300 MMscf 620 MMscf CT Total Condensate Throughput 41,198 barrels 3,499 barrels 010 Condensate. Throughput while emissions are routed to the enclosed flare 4,120 barrels ' 350 barrels E5 011 Consumption of natural gas as fuel 39.9 MMscf 3.39 MMscf E6 012 Consumption of natural gas as fuel 39.9 MMscf 3.39 MMscf Plant Flare 013 Combustion of waste gas from the ethylene glycol dehydration unit still vent and flash tank (points 007-008) and the condensate storage vessels (point 010) 49.2 MMscf 4.18 MMscf LT 014 Condensate Loading 41,198 barrels 3,499 barrels COLORADO Air Pollution Control Division Page 10 of 46 Al 015 Natural Gas Throughput 91,250 MMscf 7,750 MMscf D3 016 Natural Gas Throughput 91,250 MMscf 7,750 MMscf H1 and H2 017 Consumption of Natural Gas as Fuel 775.3 MMscf 65.85 MMscf H3 018 Consumption of Natural Gas as Fuel 116.3 MMscf 9.88 MMscf CT2 019 Stabilized Condensate Throughput 65,700 barrels 5,580 barrels ST 020 Stabilized condensate and water throughput 98,550 barrels 8,370 barrels Cl 021 Combustion of supplemental fuel 193.8 MMscf 16.46 MMscf Combustion of amine. unit still vent and °" flash tank waste gas 1,676.7 MMscf 142.4 MMscf C2 022 Combustion of TEG dehydrator unit still vent and flash tank waste gas 105.2 MMscf 8.93 MMscf Combustion of pilot light fuel. 0.5 MMscf ., 0.04 MMscf LT 024 Stabilized Condensate and Slop (mixture of stabilized condensate and water) loaded 164)250 barrels 13,950 barrels The owner or operator shall monitor monthly process rates based on the calendar month. Point 015: The owner or operator shall monitor monthly process rates based on the calendar month. The volume of "gasprocessed shall be measured by gas meter or by assuming the maximum design rate of the amine unit of 250 MMscf/d. Point 016: The owner or operator shall monitor monthly process rates based on the calendar month. The volume of gas processed shall be measured by gas meter or by assuming the maximum design rate of the dehydrator unit of 250 MMscf/d. 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. 17. Points 007-008: This unit shall be limited to the maximum lean glycol circulation rate of 7.5 gallons per minute. The lean glycol recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. (Reference: Regulation Number 3, Part B, II.A.4) 18. Point 010: The owner or operator shall continuously monitor and record Vapor Recovery Unit (VRU) downtime while emissions are routed to the enclosed flare. COLORADO Air Pollution Control Division ETwit,nrne t Page 11 of 46 19. Point 010: The owner or operator must use monthly VRU downtime records, monthly condensate throughput records, calculation methods detailed in the O&M Plan, and the emission factors established in the Notes to Permit Holder to demonstrate compliance with the process and emissions limits specified in this permit. 20. Point 015: This unit shall be limited to the maximum lean amine circulation rate of 608 gallons per minute. The lean amine circulation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. Amine circulation rate shall be monitored by one of the following methods: assuming maximum design pump rate, using amine flow meter(s), or recording strokes per minute and converting to circulation rate. (Reference: Regulation Number 3, Part B, II.A.4) 21. Point 015: On a weekly basis, the owner or operator shall monitor and record operational values including: flash tank temperature and pressure, MDEA weight concentration in the lean amine stream, and sour gas inlet temperature and pressure. These records shall be maintained for a period of five years. 22. Point 016: This unit shall be limited to the maximum lean glycol circulation rate of 20 gallons per minute. The lean glycol recirculation rate shall be recorded daily in a log maintained on site and made available to the Division for inspection upon request. Glycol recirculation rate shall be monitored by one of the following methods: assuming maximum design pump rate, using glycol flow meter(s), or recording strokes per minute and converting to circulation rate. This maximum glycol circulation rate does not preclude compliance with the optimal glycol circulation rate (Loft) provisions under MACT HH. (Reference: Regulation Number 3, Part B, II.A.4) 23. Point 016: On a weekly basis, the owner or operator shall monitor and record operational values including: flash tank temperature and pressure and wet gas inlet temperature and pressure. These records shall be maintained for a period of five years. 24. Point 017 and 018: The owner or operator shall continuously monitor and record the volumetric flow rate of natural gas combusted as fuel for each heater using an operational continuous flow meter at the inlet of each heater. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 25. Point 021: The owner or operator shall continuously monitor and record the volumetric flow rate of still vent and flash tank waste gas vented from the amine unit and routed to the thermal oxidizer using an operational continuous flow meter. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 26. Point 021: The owner or operator shall continuously monitor and record the volumetric flow rate of supplemental fuel combusted by the thermal oxidizer using an operational continuous flow meter. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. 27. Point 022: The owner or operator shall continuously monitor and record the volumetric flow rate of still vent and: flash tank waste gas vented from the TEG dehydration unit and routed to the thermal oxidizer using an operational continuous flow meter. The owner or operator shall use monthly throughput records to demonstrate compliance with the process limits contained in this permit and to calculate emissions as described in this permit. STATE AND FEDERAL REGULATORY REQUIREMENTS 28. This source is subject to the odor requirements of Regulation Number 2. (State only enforceable) 29. This source is located in an ozone non -attainment or attainment -maintenance area and subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2. The following requirements were determined to be RACT for this source: COLORADO Air Pollution Control Division _,.er 'x Wr Fu*4�.i 41C Ya p E-rn . J rent Page 12 of 46 Facility Equipment ID AIRS Point RACT Pollutants E1 001 Oxidation Catalyst and Air -Fuel Ratio Controller V0C E2 002 Oxidation Catalyst and Air -Fuel Ratio Controller V0C E3 003 Oxidation Catalyst and Air -Fuel Ratio Controller V0C E4 004 Oxidation Catalyst and Air -Fuel Ratio Controller V0C RP 006 40 CFR Part 60 Subpart 0000a V0C D1 007 Still Vent: Condenser and Enclosed Flare .. Flash Tank: Reboiler or Enclosed Flare V0C D2 008 Still Vent: Condenser and Enclosed Flare VOC Flash Tank: Reboiler or Enclosed Flare FUG 009 LDAR as provided at 40 CFR Part 60 Subpart 0000a V0C CT 010 Vapor Recovery Unit (VRU). Routed to enclosed flare during VRU downtime. V0C E5 011 Oxidation Catalyst and Air -Fuel Ratio, Controller V0C E6 012 Oxidation Catalyst and Air -Fuel Ratio Controller V0C LT 014 Submerged Fill V0C Al Still Vent: Routed to thermal oxidizer covered under point 123/9E99/021. V0C 015 Flash Tank: Recycled to the plant inlet via vapor recovery unit (VRU). Routed to thermal oxidizer covered under point 123/9E99/021 during VRU downtime. D3 016 Still Vent: Routed to thermal oxidizer covered under point 123/9E99/022. VOC Flash Tank: Routed to thermal oxidizer covered under point 123/9E99/022. H1 and H2 . 017 Natural gas as fuel, low N0x burners, good combustion practices N0x, V0C H3 018 Natural gas as fuel, low N0x burners, good combustion practices N0x, V0C CT2 019 Enclosed Flare V0C ST 020 Enclosed Flare V0C LT 024 Submerged Fill and Enclosed Flare V0C COLORADO Air Pollution Control Division si:^ t ,r Gutimef t Page 13 of 46 30. Points 001-004, 007-008, 010-022 and 024: 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) 31. Points 001-004, 006, 009, 011-012, 014, 017, and 018: 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 shalt not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. (Reference: Regulation Number 1, Section II.A.1. Et 4.) 32. Points 001-004 and 011-012: This equipment is subject to the control requirements for stationary and portable engines in the 8 -hour ozone control area under Regulation No. 7, Section XVI.B.2. For lean burn reciprocating internal combustion engines, an oxidation catalyst shall be required. 33. Point 006 and 009: These sources are subject to Regulation Number 7, Section XII.G.1 (State only enforceable). For fugitive V0C emissions from leaking equipment, the leak detection and repair (LDAR) program as provided at 40 CFR Part 60, Subpart KKK (July 1, 2016) shall apply, regardless of the date of construction of the affected facility, unless subject to applicable LDAR program as provided at 40 CFR Part 60, Subparts OOOO or 0000a (July 1, 2016). The operator shall comply with all applicable requirements of Section XII. 34. Points 007-008, and 016: 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 emissionsof 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 XUI.H.1.) 35. Points 007-008,010, 013, 016, 019, and 022: 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.16; 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. Points 007-008, and 016: 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. COLORADO 1 Air Pollution Control Division £-:v lea olle,;,p Page 14 of 46 37. Point 009: This source is subject to Regulation Number 7, Section XII.C General Provisions (State only enforceable). All condensate collection, storage, processing and handling operations, regardless of size, shall be designed, operated and maintained so as to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. The operator shall comply with all applicable requirements of Section XII. 38. Point 010: This source is subject to Regulation Number 7, Section XII.G. The operator shall comply with all applicable requirements of Section XII. 39. Points 010 and 019: The storage tank covered by this permit is subject to the emission control requirements in Regulation Number 7, Section XViI.C.1. The owner or operator shall install and operate air pollution control equipment that achieves an average hydrocarbon control efficiency of 95%. If a combustion device is used, it must have a design destruction efficiency of at least 98% for hydrocarbons except where the combustion device has been authorized by permit prior to May 1, 2014. The source shall follow the inspection requirements of Regulation Number 7, Section XVII.C.1.d. and maintain records of the inspections for a period of two years, made available to the Division upon request. This control requirement must be. met within 90 days of the date that the storage tank commences operation. 40. Point 010: The storage tanks covered by this permit are subject to the venting and Storage Tank Emission Management System ("STEM") requirements of Regulation Number 7, Section XVII.C.2. 41. Points 014 and 024: This source is located in an ozone non-attainmentor attainment - maintenance area and is subject to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3, Part B, III.D.2.a. Condensate loading to truck tanks shall be conducted by submerged fill. (Regulation Number 3, Part B, III.D.2.) 42. Points 014 and 024: The owner or operator shall follow loading procedures that minimize the leakage of V0Cs to the atmosphere including, but not limited to (Regulation Number 3, Part B, III. E. ): a) Hoses, couplings,and valves shall be maintained to prevent dripping, leaking, or other liquid or vapor loss during loading and unloading. b) All compartment hatches at the facility (including thief hatches) shall be closed and latched at all times when loading operations are not active, except for periods of maintenance, gauging, or safety of personnel and equipment. c) The ' owner or operator shall inspect onsite loading equipment during loading operations to monitor compliance with above conditions. The inspections shall occur at least monthly. Each inspection shall be documented in a log available to the Division on request. 43. Points GL4:E and 024: All hydrocarbon liquid loading operations, regardless of size, shall be designed, operated and: maintained so as to minimize leakage of volatile organic compounds to the atmosphere to the maximum extent practicable. 44. Point 015 and 021: No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity for a period or periods aggregating more than six minutes in any sixty consecutive minutes. (Reference: Regulation Number 1, Section II.A.5.) 45. Point 015: The inlet gas stream to the amine unit shall have a total sulfurs concentration, including H2S, of less than or equal to 4.0 ppm. 46. Point 016: The glycol dehydration unit at this facility is subject to National Emissions Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production Facilities, Subpart HH. This facility shall be subject to applicable area source provisions of this regulation, COLORADO Air. Pollution Control Division :pr,;rmnt of3W Hean 6 Page 15 of 46 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 §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration §63.774 - Recordkeeping Requirements §63.764 (e)(1) - The owner or operator is exempt from the requirements of paragraph (d) of this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in §63.774(d)(1). §63.764 (e)(1)(ii) - The actual average emissions of benzene from the glycol dehydration unit process vent to the atmosphere are less than 0.90 megagram per year, as determined by the procedures specified in §63.772(b)(2) of this subpart. §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-GLYCalc TM, Version 3.0 or higher, and the procedures presented in the associated GRI-GLYCaIc TMTechnical 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 art 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 (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit. §63.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per year) as determined in accordance with §63.772(b)(2). 47. Point 017 and 018: This source is subject to the Particulate Matter and Sulfur Dioxide Emission Regulations of Regulation 1 including, but not limited to, the following (Regulation 1, Section III.A.1 and VI. B.5. ): a. No owner or operator shall cause or permit to be emitted into the atmosphere from any fuel -burning equipment, particulate matter in the flue gases which exceeds the following (Regulation 1, Section III.A.1): COLORADO tt Air Pollution Control Division Uaj.:,r.ozent ..f nz€ i._ ..,'+.s Erltr3Ywertt Page 16 of 46 (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 )-o.26 Where: PE = Particulate Emission in Pounds per million BTU heat input. Fl = Fuel Input in Million BTU per hour. b. New sources of sulfur dioxide shall not emit or cause to be emitted sulfur dioxide in excess of the following process -specific limitations: (1) Limit emissions to not more than two (2) tons per day of sulfur dioxide. (Regulation 1 Section VI.B.5.a.) 48. Point 017 and 018: This source is subject to the New Source Performance Standards requirements of Regulation 6, Part B including, but not limited to, the following (Regulation 6, Part B, Section II): a. Standard for Particulate Matter - On and after the date on which the required performance test is completed, no owner or operator subject to the provisions of this regulation may discharge, or cause the discharge into the atmosphere of any particulate matter which is: (i) For fuel burning equipment generating greater than one million but less than 250 million Btu per hour heat input, the following equation will be used to determine the allowable particulate emission limitation: PE=0.5(FI )-0.26 Where: PE is the allowable particulate emission in pounds per million Btu heat input. Fl is the fuel input in million Btu per hour. If two or more units connect to any opening, the maximum allowable emission rate shall be the sum of the individual emission rates. (ii) Greater than 20 percent opacity. 49. Points 017 and 018: This source is subject to the New Source Performance Standards requirements of Regulation Number 6, Part A Subpart Dc, Standards of Performance for Small Industrial -Commercial -Institutional Steam Generating Units including, but not limited to, the following: 40 CFR, Part 60, Subpart A - General Provisions 40 CFR 60.48c(a) The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction and actual startup, as provided by §60.7 of this part. c. 40 CFR Part 60.48c(g) The owner or operator of the facility shall record and maintain records of the amount of fuel combusted during each month. d. 40 CFR Part 60.48c(i) Monthly records of fuel combusted required under the previous condition shall be maintained by the owner or operator of the facility for a period of two years following the date of such record. 50. Point 019: This source is subject to the applicable requirements of Regulation Number 7, Section VI.B.2. 51. Point 019: This source is subject to the New Source Performance Standards requirements of Regulation Number 6, Part A, Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels for which construction, reconstruction or modification commenced after July 23, 1984, including, but not limited to, the following: [COLORADO 1 Air Pollution Control Division of PIA:6z .tetafth Lriimnrrielit Page 17 of 46 • 40 CFR, Part 60, Subpart A - General Provisions • §60.112b - Standard for volatile organic compounds (VOC) o §60.112b(a) The owner or operator of each storage vessel with a....design capacity greater than or equal to 75 m3 but less than 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa but less than 76.6 kPa, shall equip each storage vessel with one of the following: • §60.112b(a)(3) A closed vent system and control device meeting the following specifications: • §60.112b(a)(3)(i) The closed vent system shall be designed to collect all VOC vapors and gases discharged from the storage vessel and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background and visual inspections, as determined in part 60, subpart W, §60.485(b)., • $60.112b(a)(3)(ii) The control device shall be designed and operated to reduce inlet VOC emissions by 95 percent or greater. If a flare is used as the control device, it shall meet the specifications described in the general control device requirements (S60.18) of the General Provisions. o §60.113b - Testing and procedures • The owner or operator of each storage vessel as specified in §60.112b(a) shall meet the requirements of paragraph (a), (b), or (c) of this section. The applicable paragraph for a particular storage vessel depends on the control equipment installed to meet the requirements of §60.112b. • §60.113b(d) The owner or operator of each source that is equipped with a closed vent system and a flare to meet the requirements in §60.112b (a)(3) or (b)(2) shall meet the requirements as specified in the general control device requirements, §60.18 (e) and (f). o §60.115b - Reporting and recordkeeping requirements • The owner or operator of each storage vessel as specified in §60.112b(a) shall keep records and furnish reports as required by paragraphs (a), (b), or (c) of this section depending upon the control equipment installed to meet the requirements of §60.112b. The owner or operator shall keep copies of all reports and records required by this section, except for the record required by (c)(1), for at least 2 years. The record required by (c)(1) will be kept for the life of the control equipment. $60.115b(d) After installing a closed vent system and flare to comply with §60.112b, the owner or operator shall meet the following requirements. §60,115b(d)(1) A report containing the measurements required by $60.18(f) (1), (2), (3), (4), (5), and (6) shall be furnished to the Administrator as required by §60.8 of the General Provisions. This report shall be submitted within 6 months of the initial start-up date. • §60.115b(d)(2) Records shall be kept of all periods of operation during which the flare pilot flame is absent. • $60.115b(d)(3) Semiannual reports of all periods recorded under §60.115b(d)(2) in which the pilot flame was absent shall be furnished to the Administrator. o §60.116b - Monitoring of operations • §60.116b(a) The owner or operator shall keep copies of all records required by this section, except for the record required by paragraph (b) of this section, for COLORADO Air Pollution Control Division Page 18 of 46 at least 2 years. The record required by paragraph (b) of this section wilt be kept for the life of the source. • §60.116b(b) The owner or operator of each storage vessel as specified in $60.110b(a) shall keep readily accessible records showing the dimension of the storage vessel and an analysis showing the capacity of the storage vessel. • §60.116b(g) The owner or operator of each vessel equipped with a closed vent system and control device meeting the specification of $60.112b or with emissions reductions equipment as specified in 40 CFR 65.42(b)(4), (b)(5), (b)(6), or (c) is exempt from the requirements of paragraphs (c) and (d) of this section. 52. Point 024: The owner or operator shall: a. loading of tank compartments of outbound transport trucks. b. Include devices to prevent the release of vapor from vapor recovery hoses not in use. Install and operate the vapor collection and return equipment to collect vapors during c. Use operating procedures to ensure that hydrocarbon liquid cannot be transferred unless the vapor collection equipment is in use. d. Operate all recovery and disposal equipment at a back -pressure less than the pressure relief valve setting of transport vehicles. OPERATING Et MAINTENANCE REQUIREMENTS 53. Points 001-004, 007-008, 010-012, O15-016, 019-020, and 024: Upon startup of these points, the owner or operator shall follow the most recent operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to the OEtM plan are subject to Division approval prior to implementation. (Regulation Number 3, Part B, Section III.G.7.) COMPLIANCE TESTING AND SAMPLING Initial Testing Requirements 54. Points 001-004 and 011-012: A sourceinitial 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 (Reference: Regulation No. 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. Formaldehyde 55. Point 006: The owner or operator shall complete an initial extended residue gas analysis within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit. 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.) COLORADO Air Pollution Control Division ll:J:t'.E TJ f'l Erli�b C JL".`ilY: YYIY$t;( Page 19 of 46 56. Points 007-008, 01O, 013, 016, and 022: The owner or operator shall demonstrate compliance with opacity standards, using EPA Reference Method 22, 40 C.F.R. Part 60, Appendix A, to determine the presence or absence of visible emissions. "Visible Emissions" means observations of smoke for any period or periods of duration greater than or equal to one minute in any fifteen minute period during normal operation. (Regulation Number 7, Sections XII.C, XVII.B.2. and XVII.A.16) 57. Points 007-008: The owner or operator shall complete an initial extended wet gas analysis within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit. 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. (Reference: Regulation Number 3, Part B, Section III.E.) 58. Points 009: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the owner or operator shall complete the initial extended gas analysis of gas samples and extended natural gas liquids analysis of NGL (light oil service) that are representative of volatile organic compound (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. These extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. The operator shall submit the results of the gas and liquids analyses and emission calculations to the Division as part of the self -certification process to ensure compliance with emissions limits. 59. Point 009: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the operator shalt complete a hard count of components at the source and establish the number of components that are operated in "heavy liquid service", "condensate light liquid service", "NGL light liquid service", "beater/oil service" and "gas service". The operator shall submit the results to the Division as part of the self -certification process to ensure compliance with emissions limits. 60. Point 010: The owner or operator shall complete site specific sampling including a compositional analysis of the pre -flash pressurized condensate routed to these storage tanks and a sales oil analysis to determine RVP and API gravity. Testing shall be in accordance with the guidance contained in PS Memo 05-01. Results of testing shall be used to determine a site -specific emissions factor using Division approved methods. Results of site -specific sampling and analysis shall be submitted to the Division as part of the self -certification and used to demonstrate compliance with the emissions factors chosen for this emissions point. 61. Point 015 and 021: The owner or operator shall demonstrate compliance with opacity standards using EPA Method 9 to measure opacity from the thermal oxidizer. (Regulation Number 1, Section II.A.1 and 5) 62. Point 015: The owner or operator shall complete an initial extended sour gas analysis from the inlet to the amine unit within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit. 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. (Reference: Regulation Number 3, Part B, Section III.E.) 63. Point 015: Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, the operator shall complete an initial sample of the inlet gas to the amine unit to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The owner or operator shall use the sample results to calculate actual emissions, as prescribed in the Emission Limitations and Records section of this permit, to verify initial compliance with the emission limits. The sample results shall also be monitored to demonstrate that this amine unit !COLORADO Air Pollution Control Division 3%uiM c Hean s £^rC, rrnenC Page 20 of 46 qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Facilities (S60.5365a(g)(3)) and to demonstrate compliance with the limit for total sulfurs concentration, including H2S. The owner or operator shall submit the analysis and the emission calculation results to the Division as part of the self -certification process. The testing required by the condition above may be used for this demonstration. 64. Point 015 and 021: A source initial compliance test shall be conducted on this emissions point to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits in this permit. The operator shall also demonstrate the thermal oxidizer (TO) achieves a minimum destruction efficiency of 98% for VOC. The operator shall measure and record, using EPA approved methods, VOC mass emission rates at the thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the thermal oxidizer (process models shall not be used to determine the flow rate or composition of waste gas (waste gas stream from the still vent and flash tank) sent to the thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine recirculation rate, MDEA concentration, sulfur content of the sour gas entering the amine unit, and thermal oxidizer combustion chamber temperature shall be monitored and recorded during this test. This test shall be run with the thermal oxidizer operating at the minimum combustion chamber temperature of 1,400°F as indicated in the O&M plan for this point. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation Number 3, Part B., Section III.G.3) Sulfur Dioxide using EPA approved methods. Oxides of Nitrogen using EPA approved methods. Volatile Organic Compounds using EPA approved methods. Carbon Monoxide using EPA approved methods. 65. Point 016: The owner or operator shall complete an initial extended wet gas analysis prior to the inlet the to the TEG dehydration, unit within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit. 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. (Reference Regulation Number 3, Part B, Section TILE.) 66. Point 016 and 022: A source initial compliance test shall be conducted on this emissions point to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits in this permit. The operator shall also demonstrate the thermal oxidizer (TO) achieves a minimum destruction efficiency of 98% for VOC while emissions from the flash tank and still vent are routed to the TO. The operator shall measure and record, using EPA approved methods, VOC mass emission rates at the thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of the thermal oxidizer (process models shall not be used to determine the flow rate or composition of waste gas (waste gas stream from the still vent and flash tank) sent to the thermal oxidizer for the purposes of this test). The natural gas throughput, lean glycol recirculation rate and thermal oxidizer combustion chamber temperature shall be monitored and recorded during this test. This test shall be run with the thermal oxidizer operating at the minimum combustion chamber temperature of 1,400°F as indicated in the OLtM plan for this point. Supplemental fuel shall not be used during this test. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval COLORADO Air Pollution Control Division Page 21 of 46 at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation Number 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Volatile Organic Compounds using EPA approved methods. Carbon Monoxide using EPA approved methods. 67. Point 017: A source initial compliance test shall be conducted on each of the heaters covered by this point to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation Number 3, Part B., Section III.G.3) Oxides of Nitrogen using EPA approved methods. Carbon Monoxide using EPA approved methods. 68. Point 018: A source initial compliance test shall be conducted on this heater to measure the emission rate(s) for the pollutants listed below in order to demonstrate compliance with the emissions limits contained in this permit. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any compliance test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation 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. 69. Points 019, 020 and 024: A source initial compliance test shall be conducted to measure the emission rate for volatile organic compounds (VOC) in order to demonstrate compliance with a minimum destruction efficiency of 98% for VOCs. The test shall determine the mass emission rates of volatile organic compounds at the inlet and outlet of the control device, which shall be used to determine the destruction efficiency during the test. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance Test Manual and shall be submitted to the Division for review and approval at least thirty (30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. (Regulation Number 3, Part B., Section III.G.3) Periodic Testing Requirements 70. Points 001-004 and 011-012: These engines are subject to the periodic testing requirements as specified in the operating and maintenance (O&M) plan as approved by the Division. Revisions to your O.8M 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. 'COLORADO Air Pollution Control Division Page 22 of 46 71. Points 007-008: The owner or operator shall complete an extended wet gas analysis prior to the in of the ethylene glycol dehydration unit on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. 72. Point 009: On an annual basis, the owner or operator shall complete an extended gas analysis of gas samples and an extended natural gas liquids analysis of NGL (light oil service) that are representative of volatile organic compounds (VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions. These extended gas and liquids analyses shall be used in the compliance demonstration as required in the Emission Limits and Records section of this permit. 73. Point 015 and 021: On a daily basis, the owner or operator shall conduct an inspection for presence or absence of smoke, and, if smoke is observed, the operator has the option to (1) immediately conduct repairs and maintain records of the specific repairs completed; (2) shut-in the equipment to investigate the cause of the smoke, conduct any necessary repairs, and maintain records of the specific repairs completed; or (3) conducta formal EPA Method 9 observation to determine the opacity of the visible emissions, and conduct repairs if necessary. 74. Point 015: The owner or operator shall sample the inlet gas to the amine unit on an annual basis to determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall be monitored to demonstrate that this amine unit qualifies for the exemption from the Standards of Performance for Crude Oil and Natural Gas Facilities (o.65The testing required the following condition may be used for this demonstration. 75. Point 015: The owner or operator shall complete an extended sour gas analysis prior to the inlet of the amine unit on an annual basis.. Results of the sour gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit. 76. Point 016 and 022: On a daily basis, the owner on„operator shall conduct an inspection for the presence or absence of smoke (e.g., visible emissions). If smoke is observed during the visible emissions inspection, the operator has the . option ` to either (1) immediately shut-in the equipment to investigate the cause of the smoke, conduct any necessary repairs, and maintain records of the specific repairs completed; of (2) conduct a formal Method 22 observation to determine whether visible emissions (as defined per Regulation No. 7, Section XVII.A.16.) are present. 77. Point 016: The owneror operator shall complete an extended wet gas analysis prior to the inlet of the TEG dehydration unit on an annual basis. Results of the wet gas analysis shall be used to calculate emissions of criteria pollutants and hazardous air pollutants per this permit and be provided to the Division upon request. ADDITIONAL. REQUIREMENTS 78. All previous versions of this permit are cancelled upon issuance of this permit. 79. The operator shall have 30 days after commencement of operation of the associated gas processing train to cancel the following points and permanently remove them from service: Existing Permit Number Existing Emission Point New Emission Point 16WE0773 123/9E99/001 Engine is cancelled upon startup of the phase II natural gas processing train at the Discovery Fort Lupton Plant. 16WE0773 123/9E99/002 Engine is cancelled upon startup of the phase II natural gas processing train at the Discovery Fort Lupton Plant. COLORADO Air Pollution Control Division _ e wttru tot PubHee fr, c E vimnrneflt Page 23 of 46 16WE0773 123/9E99/003 Engine is cancelled upon startup of the phase II natural gas processing train at the Discovery Fort Lupton Plant. 16WE0773 123/9E99/004 Engine is cancelled upon startup of the phase II natural gas processing train at the Discovery Fort Lupton Plant. 80. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Regulation Number 3, Part A, 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 (NOX) in ozone nonattainment areas emitting less than 100 tons of VOC or NOX per year, a change in annual actual emissions of one (1) ton per year or more or five percent, whichever is greater, above the level reported on the last, APEN; or For 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 newcontrol 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. 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 owner or operator is exercising an alternative -operating scenario and is installing a permanent replacement engine. 81. The requirements of Colorado Regulation No. 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 (Reference: Regulation Number 3, Part D, V.A.7.B). 82. MACT Subpart HH - National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities major stationary source requirements shall apply to this stationary source at any such time that this stationary source becomes major solely by virtue of a relaxation !COLORADO Air Pollution Control Division Pub Page 24 of 46 in any permit limitation and shall be subject to all appropriate applicable requirements of Subpart HH. (Reference: Regulation No. 8, Part E) 83. MACT Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines 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 that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation No. 8, Part E) 84. Points 017 and 018: MACT DDDDD - National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters requirements shall apply to this source at any such time that this source becomes a major source of hazardous air pollutants (HAP) solely by virtue of a relaxation in any permit limitation and shall be subject to all appropriate applicable requirements of that Subpart on the date as stated in the rule as published in the Federal Register. (Reference: Regulation Number 8, Part E) GENERAL TERMS AND CONDITIONS 85. 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. 86. If this permit specifically states that final authorization has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit does not provide "final" authority for this activity or operation of this source. Final authorization of the permit must be secured from the APCD in writing in accordance with the provisions of 25-7- 114.5(12)(a) C.R.S. and AQCC Regulation Number 3, Part B, Section III.G. Final authorization cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self -certification of all points has been reviewed and approved by the. Division, it wilt 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. 87. 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. 88. 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. 89. 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. 90. 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. !COLORADO I Air Pollution Control Division kpraitn ent,,f rut€i, Lm,i,6nrne,le - Page 25 of 46 91. 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 December 21, 2016 Issued to Discovery DJ Services LLC Permit for a new natural gas processing facility located in the ozone non -attainment area. Issuance 2 ;COLORADO Air Pollution Control Division This Issuance Cancel points 001-004 upon start-up of Phase II of the Discovery Fort Lupton Plant. Addition of points 015-022 and 024 for Phase II of the Discovery Fort Lupton Plant. Remove Point 005 from the permit as emissions have fallen below permit thresholds. Update emissions and throughput limits for point 006 to account for removal of inlet compressors and addition of four (4) electric residue compressors. Increase component count and emission limit for Point 009 to account for new gas processing train. Page 26 of 46 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 II, Subpart E, Affirmative Defense Provision for Excess Emissions During Malfunctions. The owner or operator shall notify the Division of any malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than noon of the next working day, followed by written notice to the Division addressing alt of the criteria set forth in Part II.E.1 of the Common Provisions Regulation. See: https: //www. colorado.gov/pacific/cdphe/aqcc-regs 4) The following emissions of non -criteria reportable air pollutants are estimated based upon the process limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds emitted if the source(s) operate at the permitted limitations. AIRS Point Pollutant CAS # Uncontrolled Emissions (lb/yr) Controlled Emissions (lb/yr) Formaldehyde 50000 4,664 3,023 Acetaldehyde 75070 739 739 Acrolein 107028 454 454 Methanol 67561 221 221 001 Benzene 71432 39 39 Toluene 108883 36 36 Ethylbenzene 100414 4 4 Xylenes 1330207 17 17 n -Hexane 110543 98 98 2,2,4- Trimethylpentane 540841 22 22 002 Formaldehyde 50000 4,664 3,023 Acetaldehyde 75070 739 739 Acrolein 107028 454 454 Methanol 67561 221 221 Benzene 71432 39 39 COLORADO Air Pollution Control Division Page 27 of 46 Toluene 108883 36 36 Ethylbenzene 100414 4 4 Xylenes 1330207 17 17 n -Hexane 110543 98 98 2,2,4- Trimethylpentane 540841 22 22 003 Formaldehyde 50000 4,664 3,023 Acetaldehyde 75070 739 739 Acrotein 107028 454 454 Methanol 67561 221 Benzene 71432 39 39 Toluene 108883 36 36 Ethylbenzene 100414 4 4 Xylenes 1330207 17 17 n -Hexane 110543 98 98 2,2,4- Trimethylpentane 50000 22 22 Formaldehyde 4,664 3,023 Acetaldehyde 75070 739 739 Acrotein 107028 454 454 Methanol 67561 221 221 Benzene 71432 39 39 Toluene 108883 36 36 Ethylbenzene 100414 4 4 Xylenes 1330207 17 17 n -Hexane 110543 98 98 2,2,4- Trimethylpentane 540841 22 22 006 Benzene 71432 135 135 Toluene 108883 230 230 Ethylbenzene 100414 55 55 Xylenes 1330207 125 125 n -Hexane 110543 1,919 1,919 2,2,4- Trimethylpentane 540841 2 2 COLORADO Air Pollution Control Division Page 28 of 46 007 Benzene 71432 8,153 408 Toluene 108883 2,784 140 Ethylbenzene 100414 328 17 Xylenes 1330207 1,448 73 n -Hexane 110543 5 1 2,2,4- Trimethylpentane 540841 2 1 008 Benzene 71432 8,153, 408 Toluene 108883 2,784 140 Ethylbenzene 100414 17 Xylenes 1330207 1,448 73 n -Hexane 110543 2,2,4- Trimethylpentane 540841 009 Benzene 71432 5 1 1 994 414 Toluene 108883 1,274 501 Ethylbenzene 100414 326 129 Xylenes 1330207 770`` 305 n -Hexane 110543 8;319 3,194 2,2,4- Trimethylpentane 540841 506 234 Benzene 71432 25,975 130 Toluene{ 108883 11,690 59 Ethylbenzene 100414' 1,440 8 Xylenes 1330207 3,152 16 n -Hexane 110543 74,445 373 2,2,4- Trimethylpentane 540841 18,159 91 011 Formaldehyde 50000 2,318 1,502 Acetaldehyde 75070 367 367 Acrolein 107028 226 226 Methanol 67561 110 110 Benzene 71432 20 20 Toluene 108883 18 18 Ethylbenzene 100414 2 2 Xylenes 1330207 8 8 ICOLORADO Air Pollution Control Division FP Page 29 of 46 016 n -Hexane 110543 49 49 2,2,4- Trimethylpentane 540841 11 11 012 Formaldehyde 50000 2,318 1,502 Acetaldehyde 75070 367 367 Acrolein 107028 226 226 Methanol 67561 110 110 Benzene 71432 20 20 Toluene 108883 18 18 Ethylbenzene 100414 2 2 Xylenes 133D207 8 n -Hexane 110543 49 49 ., 2,2,4- Trimethylpentane 540841 11 11 014 Benzene 71432 18 18 n -Hexane 110543 149 149 015 Benzene 71432 40,599 812 Toluene 108883 31,589 632 Ethylbenzene. 100414 2,738 55 Xylene 1330207 7,709 154 n -Hexane 110543 2,843 57 2,2,4-_ Trimethylpentane 540841 1 0.1 Hydrogen Sulfide (H2S) 7783064 37,497 750 Benzene 71432 49,187 984 Toluene 108883 53,660 1,073 Ethylbenzene 100414 7,596 152 Xylene 1330207 20,459 409 n -Hexane 110543 14,356 287 2,2,4- Trimethylpentane 540841 5 0.1 Hydrogen Sulfide (H2S) 7783064 2 0.1 017 Formaldehyde 50000 65 65 Benzene 71432 2 2 Toluene 108883 3 3 !COLORADO Air Pollution Control Division Demt,ner,t Cnvironrrient Page 30 of 46 n -Hexane 110543 1,546 1,546 018 , Formaldehyde 50000 10 10 Benzene 71432 1 1 Toluene 108883 1 1 n -Hexane 110543 232 232 019 Benzene 71432 268 6 Toluene 108883 146 3 Ethylbenzene 100414 1 1 Xylene 1330207 1 n -Hexane 110543 4,386 88 2,2,4- Trimethylpentane 540841 2 0 020 Benzene 71432 69 Toluene 108883 38, 1 Ethylbenzene 100414 3 0 Xylene 1330207 6 1 n -Hexane 110543 1,133`. 23 021 Formaldehyde 50000 18. 18 Benzene 71432 1 1 Toluene 108883 1 1 n -Hexane 110543 426 426 Formaldehyde , 50000 4 4 Toluene 108883 1 1 n -Hexane 110543 76 76 Benzene 71432 68 2 n -Hexane 110543 592 12 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 001-004: CAS Pollutant Emission Uncontrolled lb/MMBtu Factors - g/bhp-hr Emission Factors lb/MMBtu - Controlled g/bhp-hr NOx 1.51x1O1 5.0x10-1 1.51x10-1 5.0x10-1 CO 7.34x10-1 2.43 1.51x10-1 5.0x10-1 VOC 1.45x1O1 4.8x10-1 1.45x10-1 4.8x10-1 50000 Formaldehyde 5.28x10-2 1.75x1O1 3.42x10-2 1.13x10`1 75070 Acetaldehyde 8.36x1O3 2.77x1O2 8.36x10-3 2.77x1O2 COLORADO Air Pollution Control Division Page 31 of 46 CAS Pollutant Emission Uncontrolled lb/MMBtu Factors - g/bhp-hr Emission Factors lb/MMBtu - Controlled g/bhp-hr 107028 Acrolein 5.14x10-3 1.7x10-2 5.14x10-3 1.7x10-2 67561 Methanol 2.5x10-3 8.28x10-3 2.5x10-3 8.28x10-3 Note: Emission factors are based on a Brake -Specific Fuel Consumption Factor of 7,301 Btu/hp-hr, a site - rated horsepower value of 1,380, and a fuel heat value of 1,100 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer - Manufacturer CO Manufacturer Manufacturer VOC Manufacturer Manufacturer 50000 Formaldehyde AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 75070 Acetaldehyde AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 107028 Acrolein AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 67561 Methanol AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 Point 006: CAS # Weight Fraction of Gas Pollutant Uncontrolled Emission Factors (lb/MMscf) Source 0.0184 VOC 799.13 Gas Analysis 110543 0.013 n -Hexane 564.59 Mass Balance Note: The VOC content is based on an engineering estimate of residue gas composition and HAP mass fractions from the inlet gas composition which is based on an average of five representative samples. Emissions are based on a rod packing vent rate of 50 scf/hr for phase I residue compressors and 72 scf/hr for phase II electric residue compressors and the weight fraction of gas indicated in the table above. Point 007-008: The emission levels contained in this permit are based on the information provided in the application and the ProMax 4.0 modeL Component Gas Service Heavy Oil Condensate (Light Oil) NGL (Light Oil) Water/Oil Service Connectors 8,250 2,688 454 9,515 11 Flanges 1,259 725 330 1,537 68 Open-ended Lines 1 -- --- 318 --- Pump Seals --- 48 11 6 --- Valves 1,369 404 360 3,011 24 Other* 61 14 6 69 --- VOC Content (wt. fraction) 0.3357 1 1 0.5715 1 Benzene Content (wt. fraction) 9,115E-4 --- 1.413E-2 2.435E-3 --- Toluene Content (wt. fraction) 1.556E-3 --- 2.793E-2 1.688E-3 --- Ethylbenzene (wt. fraction) 3.74E-4 --- 7.252E-3 4.39E-4 --- =COLORADO Air Pollution Control Division Page 32 of 46 Xylenes Content (wt. fraction) 8,484E-4 --- 1.641E-2 1.147E-3 --- n -Hexane Content (wt. fraction) 1,301E-2 --- 1.997E-1 6.72E-3 --- 2,2,4- Trimethylpentane Content (wt. fraction) 1.03E-5 --- 1.369E-4 2.415E-3 --- *Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms, hatches, instrument meters, polish rods and vents TOC Emission Factors (kg/hr-component): Component Gas Service Heavy Oil Light Oil Water/Oil Service Connectors 2.0E-04 7.5E-06 2.1E-04 1.1E-04 Flanges 3.9E-04 3.9E-07 1.1E-04 2.9E-06 Open-ended Lines 2.0E-03 1.4E-04 1.4E-03 2.5E-04 Pump Seals 2.4E-03 NA 1.3E-02 2.4E-05 Valves 4.5E-03 8.4E-06 2.5E-03 9.8E-05 Other 8.8E-03 3.2E-05 7.5E-03 1.4E-02 Source: EPA -453/R95-017 Table 2-4 Compliance with emissions limits in this permit will be demonstrated by using the TOC emission factors listed in the table above with representative component counts, multiplied by the VOC content from the most recent gas and liquids analyses. Point 010: CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source VOC 74.28 3.71 ProMax 71432 Benzene 6.30x10-1 3.15x10-2 ProMax 108883. Toluene 2.83x10-1 1.42x102 ProMax 100414 Ethylbenzene 3.49x10-2 1.75x10-3 ProMax . 1330207 ! Xylene 7.65x10.2 3.82x10-3 ProMax 110543 n -Hexane 1.80 9.03x1O2 ProMax 540841 2,2,4 Trimethylpentane 4.40x10-1 2.20x10-2 ProMax Note: a) During operations when emissions are routed to the enclosed flare, the controlled emission factors in the table above shall be used to calculate actual emissions. These emission factors are based on the enclosed flare control efficiency of 95%. b) During operations when emissions are routed to the vapor recovery unit (VRU), a control efficiency of 100% may be used to calculate actual controlled emissions. COLORADO I Mr Pollution Control Division Dep,atr. , t jr Pt0e, b nk:tr,. v Er ngrrncent Page 33 of 46 Points 011-012: CAS Pollutant Emission Uncontrolled lb/MMBtu Factors - g/bhp-hr Emission Factors Ib/MMBtu - Controlled g/bhp-hr NOx 1.51x10-1 5.0x10-1 1.51x10-1 5.0x10-1 CO 7.84x10'1 2.58 1.51x10-1 5.0x10-1 VOC 1.67x10-1 5.5x10-1 1.67x10-1 5.5x10-1 50000 Formaldehyde 5.28x10-2 1.74x10-1 3.42x10-2 1.12x10-1 75070 Acetaldehyde 8.36x10-3 2.75x10-2 8.36x10-3 2.75x10-2 107028 Acrolein 5.14x10-3 1.69x1O2 5.14x10-3 1.69x10-2 67561 Methanol 2.5x10-3 8.23x10'3 2.5x10-3 8.23x10-3 Note: Emission factors are based on a Brake -Specific Fuel Consumption Factor of 7,254 Btu/hp-hr, a site - rated horsepower value of 690, and a fuel heat value of 1,100 Btu/scf. Emission Factor Sources: CAS Pollutant Uncontrolled EFSource Controlled EF Source NOx Manufacturer Manufacturer CO Manufacturer Manufacturer VOC Manufacturer Manufacturer 50000 Formaldehyde AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 75070 Acetaldehyde AP -42 Chapter 3 Table 3.2-2 `' AP -42 Chapter 3 Table 3.2-2 107028 Acrolein AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 67561 Methanol AP -42 Chapter 3 Table 3.2-2 AP -42 Chapter 3 Table 3.2-2 Point 013: CAS # Pollutant Uncontrolled Emission Factors lb/MMBtu Source NOx 0.138 TNRCC Flare Emissions Guidance CO 0.2755 TNRCC Flare Emissions Guidance Note: a) The emission levels in this permit for this point are based on the heat content and gas volume from the following process streams: Process. Stream Heat Content (Btu/scf) Gas Volume (MMscf/year) Condensate Storage Vessel Waste Gas 2,474 25.67 Ethylene Glycol Dehydration Unit Still Vent Waste Gas 29 21.69 Ethylene Glycol Dehydration Unit Flash Tank Waste Gas 801 1.76 ;COLORADO Air Pollution Control Division Page 34 of 46 Purge/Pilot Gas 1,023 0.04 Average Heat Content 1,334 Total Gas Volume 49.2 b) Total actual emissions for this point are based on the average heat content and total gas volume of the process streams routed to and controlled by the enclosed combustor. The following equation demonstrates this calculation: /r EF, lb ll (Average Heat Content, MMBtuI# (Gas Vo1me., Combustion Emissionstpy = IMMBtu/ l MMscf l Point 014: outed to Flare, MMscfl r 1 ton l year ) 12000 lb/ CAS # Pollutant Uncontrolled Emission Factors lb/bbl Source VOC 2.36x10' CDPHE PS Memo 14-02 Point 015: The emission levels contained in this permit are based on information provided in the application and the ProMax simulation. The emissions levels fn this permit were buffered by multiplying the simulation results by a factor of 1.15. Controlled flash tank emissions are based on 98% control efficiency when emissions are routed to the VRU and 98% control when emissions are routed to the thermal oxidizer during VRIf downtime. Controlled still vent emissions are based on 98% control efficiency when emissions are routed to the thermal oxidizer. The following table summarizes the control efficiency for each scenario: Control Scenario VOC Control Efficiency Still vent emissions routed to the thermal oxidizer Flash tank emissions routed to the VRU and recycled to the plant inlet. Flash tank emissions routed to the thermal oxidizer during VRU downtime. 98% SO2 emissions resulting from the combustion of H2S in the waste gas (including flash tank stream during VRU downtime and acid gas stream from the still vent) are based on the 502 emission factor presented in table 5.3.1 in AP -42 Chapter 5.3. The SO2 emission factor is as follows: CAS # Pollutant Uncontrolled Emission Factors lb/MMscf gas processed Source 502 0.674 AP -42 Chapter 5.3 Table 5.3.1 COLORADO Air Pollution Control Division .,pot . A A l f let ervir ,nment Page 35 of 46 Note: The SO2 emission factor is based on the amine unit inlet H2S concentration of 4 ppm. Point O16: The emission levels contained in this permit are based on information provided in the application and the GRI GlyCalc 4.0 model. The emissions levels in this permit were buffered by multiplying the simulation results by a factor of 1.15. Controlled flash tank and still vent emissions are based on 98% control efficiency when emissions are routed to the thermal oxidizer. Point O17: Uncontrolled CAS # Pollutant Emission Factors lb/MMscf Source PM,o 8 42 AP -42 Chapter 1 Table 1.4-2 PM2 5 8 42 AP -42 Chapter 1 Table 1.4-2 NO, 33.9 Manufacturer CO 67.8 Manufacturer VOC 6.09 AP -42 Chapter 1 Table 1.4-2 110543 n -Hexane 1.99 AP -42 Chapter 1 Table 1.4-3 Note: Emissions factors are based on a rated heat input of 50 MMBtu/hr, a higher heating value of 1,130 Btu/scf and 8,760 hours of operation per year. Point O18: CAS # Pollutant Uncontrolled Emission Factors lb/MMscf Source NO, 45.2 Manufacturer CO 45.2 Manufacturer VOC 21.5 " Manufacturer Note: Emissions factors are based on a rated heat input of 15 MMBtu/hr, a higher heating value of 1,130 Btu/scf and 8,760 hours of operation per year. Point O19::. CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source VOC 6.19x10-1 1.24x10-2 EttP Tanks v3.0 71432 Benzene 4.08x10-3 8.16x1O5 E£tP Tanks v3.0 110543 n -Hexane 6.67x10-2 1.33x10-3 E£tP Tanks v3.0 Note: The controlled emissions factors for this point are based on the enclosed flare control efficiency of 98%. COLORADO Air Pollution Control Division Page 36 of 46 Point 020: CAS # Pollutant Uncontrolled Emission Factors lb/bbl Controlled Emission Factors Ib/bbl. Source VOC 1.07x10-' 2.14x10-3 EEtP Tanks v3.0 110543 n -Hexane 1.15x10-2 2.3x10-4 EEtP Tanks v3.0 Note: The controlled emissions factors for this point are based on the enclosed flare control efficiency of 98%. Point 021: Total actual combustion emissions are based on the sum of the emissions calculated for the combustion of supplemental fuel (process 01) and the combustion. of amine unit stilt vent and flash tank waste gas (process 02). Process 01: CAS # Pollutant Uncontrolled Emission Factors lb/MMscf Source NOX 113 Manufacturer CO 113 Manufacturer n -Hexane 2.0 AP -42 Chapter 1 Table 1.4-3 Note: The combustion emissions factors are based on a higher heating value of 1,130 Btu/scf. Actual emissions are calculated by multiplying the emission factors in the table above by the total supplemental fuel combusted by the thermal oxidizer as measured by flow meter. Process 02: CAS # Pollutant Uncontrolled Emission Factors lb/MMscf Source NOx 1.33 Manufacturer CO'' 1.33 ' Manufacturer n -Hexane 2.35x10-2 AP 42 Chapter 1 Table 1.4-3 Note: The combustion emissions factors are based on an average higher heating value of 13.34 Btu/scf. Actual emissions are calculated by multiplying the emission factors in the table above by the total amine unit flash tank and still vent waste gas combusted by the thermal oxidizer as measured by flow meter. Point 022: Total actual combustion` emissions are based on the sum of the emissions calculated for the combustion of TEG ;"dehydration unit still vent and flash tank waste gas (process 01) and the combustion of pilot light fuel (process 02). Process 01: CAS # Pollutant Uncontrolled Emission Factors Ib/MMscf Source NOX 55.89 TCEQ CO 111.57 TCEQ ,COLORADO Air Pollution Control Division . sis ,o ; Efwironmet Page 37 of 46 Note: The combustion emissions factors are based on a higher heating value of 405 Btu/scf. Actual emissions are calculated by multiplying the emission factors in the table above by the total TEG dehydration unit flash tank and still vent waste gas combusted by the thermal oxidizer as measured by flow meter. Process 02: CAS # Pollutant Uncontrolled Emission Factors Ib/MMscf Source NO), 155.94 TCEQ CO 311.31 TCEQ Note: The combustion emissions factors are based on an average higher heating value of 1,130 Btu/scf and 8,760 hours of operation per year. The pilot light fuel has a constant rate of 50 scf/hr. Point 024: Pollutant CAS # Uncontrolled Emission Factors lb/bbl Controlled Emission Factors lb/bbl Source V0C 2.36x101 4.72x10 3 CDPHE PS Memo 14-02 n -Hexane 110543 3.6x10-3 7.2x10.5 CDPHE PS Memo 14.02 Note: Controlled emission factors are based on the enclosed flare efficiency of 98% and a collection efficiency of 100%. 6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission Notice (APEN) associated with this permit is valid for a term of five years from the date it was received by the Division. A revised APEN shall be submitted no later than 30 days before the five-year term expires. Please refer to the most recent annual`fee invoice to determine the APEN expiration date for each emissions point associated with this permit. For any questions regarding a specific expiration date call the Division at (303) 692 3150. 7) This permit fulfills the requirement to hold a valid permit reflecting the storage tank and associated control device per the Colorado Oil and Gas Conservation Commission rule 805b(2)(A) when applicable." 8) Points 001-004 and 011-012 These engines are 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.PRotevtiettn/astuwh/Paarreta/fr181a0 9) Points 001-004 and 011-012: These engines are subject to 40 CFR, Part 63, Subpart ZZZZ - National ;Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. (See 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/fr181a08.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) Points 006 and 009: These sources are subject to 40 CFR, Part 60, Subpart. 0000a — Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015 (See June 3, 2016 Federal Register posting - effective August 02, 2016). This rule has not yet been incorporated into Colorado Air Quality Control Commission's Regulation No. 6. A copy of the complete COLORADO Aix Pollution Control Division ktbk3 s ti^air6rmea Page 38 of 46 subpart is available on the EPA website at: https://www.gpo.gov/fdsys/pkg/FR-2016-06- 03/pdf/2016-11971.pdf 11) Point 015: This amine unit is subject to 40 CFR, Part 60, Subpart OOOOa—Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015 (See June 3, 2016 Federal Register posting - effective August 02, 2016). 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: https://www.gpo.gov/fdsys/pkg/FR-2016-06- 03/pdf/2016-11971.pdf 12) This facility is classified as follows: Applicable Requirement Status Operating Permit Synthetic Minor Source of: VOC, Benzene, Toluene, Xytene, n -Hexane, H2S and Total HAPs NANSR Synthetic Minor Source of: VOC PSD True Minor Source MACT HH Major Source Requirements: Not Applicable Area Source Requirements: Applicable Major Source Requirements: Not Applicable Area Source Requirements: Applicable MACT ZZZZ MACT DDDDD Not Applicable NSPS KKK Not Applicable NSPS OOOO Not Applicable NSPS 0000a Applicable to points 006 and 009. Recordkeeping and reporting requirements for point 015. NSPS Dc Applicable to points O17 and 018 NSPS LLL Not Applicable NSPS JJJJ Applicableto points 001-004 and 011-012 NSPS Kb Applicable to point 019 13) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be found at the website listed below: http://ecfr.gpoaccess.gov/ Part 60: Standards of Performance for New Stationary Sources NSPS 60.1 -End Subpart A - Subpart KKKK NSPS Part 60, Appendixes Appendix A - Appendix I Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories COLORADO Air Pollution Control Division pot, -u. ror 1333.3333€3,: 3 is ...1 E;^vrrrorr tort Page 39 of 46 MACT 63.1-63.599 Subpart A - Subpart Z MACT 63.600-63.1199 Subpart AA - Subpart DDD MACT 63.1200-63.1439 Subpart EEE - Subpart PPP MACT 63.1440-63.6175 Subpart QQQ- Subpart YYYY MACT 63.6580-63.8830 Subpart ZZZZ - Subpart MMMMM MACT 63.8980 -End Subpart NNNNN - Subpart XXXXXX COLORADO Air Pollution Control Division 2%J -t•» PcthI iE i1 En.iir rne,,t Page 40 of 46 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 a compressor 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 AO.S 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 MACTrequirements. 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 shalt maintain a copy of all Applicability Reports required under section 2.1.2 and make them available to the Division upon request. 2.1.1 The owner or operator may temporarily replace an existing compressor 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. COLORADO Air Pollution Control Division nent of cubit HeWth i, Envir.ortrrvit Page 41 of 46 2.1.2 The owner or operator may permanently replace the existing compressor 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 http://www.cdphe.state.co.us/ap/oilgaspermitting.html. 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 regardto 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. 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 andmultiplied 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. COLORADO Aix Pollution Control Division Dep.rt,wrnt V15 3! F E :e Page 42 of 46 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 S 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. 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 (5 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). Control 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. !COLORADO Air Pollution Control Division } ,part=.'#.4 i Heoh Page 43 of 46 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: Max Engine HP Construction or Relocation Date Emission Standards in G/hp-hr N0x CO VOC January 1, 2008 2.0 4.0 1.0 100<Hp<500 January 1, 2011 1.0 2.0 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 hp 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 A0S. 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 by the Division, provided that such test is conducted within the time frame specified in Condition 2.2. 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 B, § I.B (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. COLORADO Air Pollution Control Division Page 44 of 46 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. 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. COLORADO Air Pollution Control Division `k .sr •x.�rt ` 7 Ik % l i i En.iro si t Page 45 of 46 ATTACHMENT B: INSIGNIFICANT ACTIVITIES Description NOx (tpy) VOC (tpy) CO (tpy) Produced Water Storage Tanks --- 0.1 --- Two (2) 0.5 MMBtu/hr Dehydrator Regenerator Burners 1.4 0.1 1.2 Two (2) 3.5 MMBtu/hr Stabilizer Burners 1.4 0.1 1.2 One (1) 1.0 MMBtu/hr TEG Dehydrator Reboiler 0.4 --- 0.4 Methanol Tanks --- 0.1 - Emergency Flare 0.3 -- 0.5 NGL Loadout --- 0.7 --- Two (2) Emergency Generators 0.8 0.3 0.7 MSS Blowdowns -- 0.5 --- Tanks and Loadout Combustor 0.2 --- 0.4 'COLORADO Air Pollution Control Division Page 46 of 46 General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of specialty APENs is available on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 16WE0773 AIRS ID Number: 123 / 9E99 / 006 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Discovery DJ Services LLC Site Name: Discovery Fort Lupton Plant Site Location: Section 11, T1 N, R66W Mailing Address: (Include Zip Code) 7859_ Walnut Hill Lane, Suite 335 Dallas, TX 75230 Portable Source P • Home Base: NIA" Site Location Weld County: NAICS or SIC Code: 213112 Permit Contact: Manya Miller Phone Number: (214) 414-1980 E -Mail Address2: manya@discoverymidstream.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 APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 1/2017 361292 COLORADO 1 IAV fa=',:1�� He�IC� b£rvunmm�M� Permit Number: 16WE0773 AIRS ID Number: 123 / 9E99 /006 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ❑ NEW permit OR newly -reported emission source (check one below) ❑ STATIONARY source ❑ PORTABLE source -OR - ❑✓ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name ❑ Add point to existing permit ❑✓ Change permit limit ❑ Transfer of ownership3 ✓❑ Other (describe below) -OR - ❑ APEN submittal for update only (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: Modification to remove four existing inlet compressor engines (001-004) and add four new electric residue compressors. 3 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: Compressor Rod Packing (Total for 6 compressors) Manufacturer: N/A Model No.: Company equipment Identification No. (optional): For existing sources, operation began on: N/A Serial No.: N/A For new or reconstructed sources, the projected start-up date is: 01-01-2018 ❑ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: 24 hours/day 7 days/week Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 1/2017 52 weeks/year Jun -Aug: Sep -Nov: COLORADO }yq{ 2 I Li1� nca a,�ot u� y:��c, sF .v_.onrti,m Permit Number: 16WE0773 AIRS ID Number: 123 /9E99/ 006 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information a Material Use ❑ Check box if this information is not applicable to source or process From what year is the actual annual amount? Description Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limit (Specify Units) Material Consumption Natural Gas 50scf/compressor (Plant #1) 0.88 MMSCFY 72 5cf / compressor (Plant #2) 2.52 MMSCFY Total 3.40 MMSCFY Finished Product(s): 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) UTM E: 521844 UTM N: 4434730 0 Check box if the following information is not applicable to the source because emissions will not be emitted from a stack. If this is the case, the rest of this section may remain blank. ¢"` Stack ID No, p• Discharge Height A; Above Ground Level (Feet) Temp--_ (•F) _ Flow Rate (ACFM) Velocity (ft/sec) , e Indicate the direction of tlistack outlet: (check one) ;r ❑ Downward ❑ Upward ❑ Horizontal ❑ Other (describe): ❑ Upward with obstructing raincap Indicate the stack opening and size: (check one) ❑ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-200 - General APEN - Revision 1/2017 AV COLORADO 3 I a`s„��r�e. YiSEftv:[unmu. Permit Number: 16W E0773 AIRS ID Number: 123 / 9E99/ 006 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment Ft Fuel Consumption Information 0 Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated with this emission source) Design Input Rate (MMBTU/hr) Actual Annual Fuel Use (Specify Units) 4 Requested Annual Permit Limit (Specify Units) From what year is the actual annual fuel use data? Indicate the type of fuel used5: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) O Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) O 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): a Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes ❑✓ No a 'eauioment AND state the overall control efficiency (% reduction): Pollutant Control Equipment r. Description C7 Overall Collection Efficiency ' Overall Control Efficiency (% reduction in emissions ) TSP (PM) PM, 0 PM2.5 Sax NO. CO VOC Other: Form APCD-200 - General APEN - Revision 1/2017 p COLORADO AV 4 I =I,oiw,auc TSP (PM) Permit Number: 16WE0773 AIRS ID Number: 123 /9E99/006 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 (continued) From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg. etc) Controlled6 (Tons/year) Actual Annual Emissions Requested Annual Permit Emission Limit(s)4 Uncontrolled (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) PM10 PM2.5 SOX NO), CO VOC 799.14 Ib/MMSCF, Eng. Estimate 1.36 • 1.36 . Other: a Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 lbs/year? E Yes ❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: CAS Numbers Chemical'. Name f C ,1 s Oll veraControl Efficiency Uncontrolled . Emission Factor (specify units) Emission Factor Source (AP -42, Mfg. etc) Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions6 (113s/year) 110543 n-Hexaner 0 564.601b/MMSCF• Engineering Estimate 1,919.02. 1,919.02 • f 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 1/2017 5I :COLORADO Haalin EEnv:ianmaxi Permit Number: 16WE0773 AIRS ID Number: 123 /9E99 / 006 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Signature of Lally Authofized Person (not a vendor or consultant) Date Cory G. Jordan EVP Operations Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ❑✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with' $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 ' 4300 Cherry Creek Drive South Denver, CO 80246-1530 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: Make check payable to: https://www.colorado.gov/cdphe/apcd Colorado Department of Public Health and Environment Telephone: (303) 692-3150 Form APCD-200 - General APEN - Revision 1/2017 �Y COLORADO ,==, POLLUTANT EMISSION NOTICE (APEN) & Applicatit Jr Construction Permit — Fugitive Component Leak Emiss, Permit Number: 16WE0773 Facility Equipment ID: FUG [Leave blank unless APCD has already assigned a permit # & AIRS ID] Emission Source AIRS ID: 123 Section 01— Administrative Information Company Name: Discovery DJ Services LLC [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Source Name: Discovery Fort Lupton Plant Source Location: Section 11, T1 N, R66W Mailing Address: 7859 Walnut Hill Lane, Suite 335 NAICS, or SIC Code: / 9E99 / 009 Section 02 — Requested Action (Check applicable request boxes) ❑ Request for NEW permit or newly reported emission source 213112 0 Request MODIFICATION to existing permit (check each box below that applies) County: Weld Elevation: 5,135 ZIP Code: 75230 ❑ Change process or equipment ❑ Change company name Feet Q Change permit limit ❑ Transfer of ownership ❑ Other Person To Contact: Manya Miller Phone Number: (214) 414-1980 E-mail Address: manya@discoverymidstream.com Fax Number: (214) 414-1980 Section 03 — General Information For existing sources, operation began on: Normal Hours of Source Operation: Facility Type: ❑ Request to limit HAPs with a Federally enforceable limit on PTE ❑ APEN Submittal for update only (Please note blank APENs will not be accepted) Additional Info. & Notes: 24 hours/day 7 days/week 52 weeks/year ❑Well Production ❑ Natural Gas Facility Compressor Station Will this equipment be operated in any NAAQS nonattainment area? (http://www.colorado.gov/cdphe/state-implementation-plans-sips) Section 04 — Regulatory Information Is this equipment subject to Regulation 7, Section XVII.F? Is this equipment subject to NSPS 40 CFR Part 60, subpart KKK? Is this equipment subject to NSPS 40 CFR Part 60, subpart 0000? Is this equipment subject to NESHAP 40 CFR Part 63, Subpart HH? Section 05 — Stream Constituents Identify the VOC & HAP weight % content of each applicable stream. Natural Gas Processing Plant Yes Yes ❑ No Yes ✓❑ No Yes ❑ No Yes 0 No No E 0 For new or reconstructed sources, the projected startup date is: 01 ❑ Other (Describe): Don't know Don't know Don't know Don't know Don't know Stream I VOC (wt. %) Benzene (wt. %) Toluene (wt. %) Ethylbenzene (wt. %) Xylene (wt. ) n -Hexane (wt. %) _J Gas 33.57 0.09 0.16 0.04 0.08 t30 Heavy Oil (or Heavy Liquid) 100 0 0 0 0 0 Light Oil (or Light Liquid) 100 1.41 2.79 0.73 1.64 19.97 Water/Oil 100 0 0 0 0 0 ❑✓ Submit a representative gas and liquid extended analysis (including BTEX) to support data above / 01 / 2018 Colorado Department of Public Health and Environment Air Pollution Control Division (APCD) This notice is valid for five (5) years. Submit a revised APEN prior to expiration of five-year term, or when a significant change is made (increase production, new equipment, change in fuel type, etc). Mail this form along with a check for $152.90 to:1 Colorado Department of Public Health & lEhvironmet, APCD-SS-B1 tin ! 1 ' 4300 Cherry Creek Drive South Denver, CO 80246-1530 For guidance on how to complete this APEN form;.; , Air Pollution Control Division: (303) 692-3150 Small Business Assistance Program (SBAP): (303) 692-3148 or (303) 692-3175 APEN forms: http://www.colorado.gov/cdphe/APENforms Application status: http://www.colorado.gov/cdphe/permitstatus ❑✓ Check box to request copy of draft permit prior to public notice or issuance. FORM APCD-203 361300 Page 1 of 2 FormAPCD-203-FugitiveComponentLeaksAPEN-Ver.11-13-2014 POLLUTANT EMISSION NOTICE (APEN) & Applicati, Permit Number: 16WE0773 Section 06 — Location Information (Provide Datum and either Lat/Long or UTM) br Construction Permit — Fugitive Component Leak Emiss Emission Source AIRS ID: 123 / 9E99 / 009 Section 07 —Leak Detection & Repair (LDAR) & Control Information Horizontal Datum - (NAD27, NAD83, UTM Zone UTM Easting or Longitude UTM Northing or Latitude Method of Collection for Location Data (e.g. map, GPS, WGS84) (12 or 13) (meters or degrees) (meters or degrees) GoogleEarth) NAD83 13 520961 4432473 Digitized Plot Plan Check appropriate boxes to identify LDAR program conducted at this site: ✓❑ LDAR per NSPS KKK / OOOO ❑ LDAR Per Reg. 7, Section XVII.F ❑ No LDAR program 0 Other: If LDAR per NSPS KKK / OOOO: O Monthly monitoring. Control: 88% gas valve, 76% It. liq. valve, 68% It. liq. pump ❑ Quarterly monitoring. Control: 70% gas valve, 61% It. liq. valve, 45% It. liq. pump Section 08 — Emission Factor Information Identify the emission factor used to estimate emissionsunde�r•y' E:F.'aalon with,the u,0its relating to the emission factor (e.g. lb/hr/component). ❑✓ Table 2-4* was used to estimate emissions. Lw T. , lJ : Table 240.(410i000 ppm) was used to estimate emissions. *Tables 2-4 and 2-8 are found in U.S. EPA's 1995 Protocol for Equipment Leak Emission Estimates Equipment Type Service Gas Heavy Oil (or Heavy Liquid) Light Oil (or Light Liquid) Water/Oil Count2 E.F. Units Count2 E.F. Units Count2 E.F. Units Count2 E.F. Units Connectors Flanges Appen Open -Ended Lines Please see Table 17 of the emission calculations in ix B Pump Seals Valves Other3 2 Count shall be the actual or estimated number of components in each type of service used to calculate the "Actual Calendar Year Emissions" below. 'The "Other" equipment type should be applied for any equipment type other than connectors, flanges, open-ended lines, pumps, or valves. Section 09 — Emissions Inventory Information & Emission Control Information Emission Factor Documentation attached Estimated Count Data year for actual calendar year emissions below (e.g. 2007): Actual Count conducted on the following date: Pollutant Control Device Description Control Efficiency (% Reduction) Emission Factor Actual Calendar Year Emissions4 Requested Permitted Emissions5 Estimation Method or Emission Factor Source Primary Secondary Uncontrolled Basis Units Uncontrolled (Tons/Year) Controlled (Tons/Year) Uncontrolled (Tons/Year) Controlled (Tons/Year) VOC Identify in Section 07 Identify in Section 08 99.95 . 42.97 , Table 2-4 Benzene 0.50 • 0.21 • Table 2-4 Toluene 0.64 . 0.25• Table 2-4 Ethylbenzene 0.16 . 0.06 Table 2-4 Xylene X28 O.10,$ ' 0.. tcj Table 2-4 n -Hexane 3.58- €4.‘c. 4-34- tAz, Table 2-4 Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. You may be charged an additional APEN fee if APEN is filled out incorrectly or missing information and requires re -submittal. 4Annual emission fees will be based on actual emissions reported here. 5 You may request permitted emissions in excess of actual emissions to account for component count and gas composition variability. Section 10 —Any cant Certi on f I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Signature of Person C)*,egally authorized to Supply Data —17-)7 Date Cory G. Jordan '-9.��thcs ?or Cw o,.'t• �1DS 1\10-4.11} EVP Operations Name of Legally Authorized Person (Please print) Title FORM APCD-203 Page 2 of 2 FonnAPCD-203-FugitiveComponentLeaksAPEN-Ver.11-13-2014 4cW NON -CRITERIA REPORTABLE AIR POLL) TANT EMISSION NOTICE ADDENDUM (See reverse side for guidance on completing this form) Permit Number: Company Name: Plant Location: Person to Contact: E-mail Address: 16WE0773 Discovery DJ Services LLC Section 11, T1 N, R66W Manya Miller manya@discoverymidstream.com AIRS ID Number: County: Weld , Phone Number: (214) 414-1980 IZ319E:9 I i Zip Code: 75230 Fax Number: (214) 414-1980 Chemical Abstract Service (CAS) Number Chemical Name Control Equipment / Reduction (%) Emission Factor (Include Units) Emission Factor Source Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions (lbs/year) 540841 2,2,4-Trimethylpentane 88% gas valve See Table 13 in Table 2-4 505.68 233.24 76% It. liq. valve emission calculations 68% It. liq. pump Calendar Year for which Actual Data Applies: N/A, these are requested permitted emissions Digitally signed by Manya Miller Date: 2017.11.06 09:40:11 -07'00' Signature of Person Legally Authorized to Supply Data Manya Miller Name of Person Legally Authorized to Supply Data (Please print) 11/06/2017 Date Manager of Engineering Title of Person Legally Authorized to Supply Data Form Revision Date: April 14, 2014 t_11010111• \1I).7 2I'O SZ'0 09'1 91'0 ST 0 600 LB'006 . 0Z 691 08'60T'q> ,,,,.08190 a0, 90'O 90'0 SZ'0 86'005 Y 95110T <`,T9T ,m ....88,669: TWO 05'0 TS'0T 05'00 TES TES OT'S9 OT'59 00'0 109T LEST 60'85 65'560 •pawsse sem smog Ogee loc wwow.O°snonuNu6J; 1,,,,n4,166146.1114.89 606,0PIn61N9611%911.01.0.65 %99 ila11u6J( 0.18.03 9901 60000 /1199 9096 a918uIu6w9dwlAmid t.964 plowmen 266.,666s 15010*], '(16611agwanoN 'LI0-568/660 VaJ'l.awn000039) 0ewlls3001111w6 O,I1 nuawdlnb31001010lwd.to 0-6 5194 0009 01151 015 500063) '(0-606-9000 6.1660,911.6k1 ,Iunco 19eki se91/6mau01S(NIIPW03]5010001e8wis a wort pau111gosema6I1>as se91.1006001 ad/1 wawdlnba Tinto alewOsa uV, 0100 aunt poem oaonlldaanpolad>Nuoianllsuo,woq 0.616190, 99'0 TZ'0 05'0 bZ Ea ✓ 89 SOS Ob T9fw.d>;c 9T'T 09'6 91'00 91'00 68'L 601 61'66 61'66 000 00'02 90'08 00'0 001,0 00'TSE 64000'0 SC 66TE e 90- 9066,. 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V/N 000 000 00'0 00'0 000 00'0 00'0 000 V/N 00'0 000 000 00'0 64000'0 V/N 00'0 00'0 00"0 00'0 000 00'a 00'0 v/N _ 000 00'0 000 000 00'0 %00'0 Pour 3-:k VIAL,9a v/N 00'0 000 00'0 00'0 000 000 00'0 V/N 00'0 000 000 000 00'0 %00'0 V/N 00'0 000 00'0 00'0 00'0 00'0 00'0 V/N 00'0 00'0 000 000 00'0 %400'0 i'y�llb/.107¢M�?8?eMla9lae( ; N k.Oa0.mX :333,010133 V/N 00'0 00'0 00'0 00'0 00'0 00'0 00'0 00'0 00'0 00'0 000 6400'0 0/6 000 000 00'0 00'0 00'0 000 00'0 V/N 00'0 00'0 00'0 000 00'0 %000 PP, v/N 00'0 00'0 000 000 00'0 00'0 oaDIA 9/N 000 00'0 00'0 000 00'0 %001 706905.`. 640 v/N 6 0 step5310nd ' %0 00-3606 0 0 seuE Papu141130 640 10909'9 000 0 6.806)3 NO 10-359'1 ST 0 91065x660] NO 50-350'L 0 0 111410 %0 10-310'1 0 0 (.9301) °A8d 640 SO -359'I TT 0 V/N 00'0 000 000 00'0 00'0 00'0 00'0 000 V/N 00'0 00'0 00'0 00'O %4000'0 V/N 00'0 00-0 00'0 00'0 00'0 00'0 V/N 00'0 00'0 00'0 00'0 00'0 %00'0 .na ,5;905'>S V/N 000 00'0 00'0 V/N 00'0 00'0 000 00'0 00'0 00'0 00'0 00'0 %000 V/N V/N 00'0 00'0 000 00'0 000 00'0 000 00'0 00'0 00'0 00'0 00'0 %00'0 ,.1. (PINbll MeaH) 931.:. 0°'0'. OTTO V/N V%N 00'0 00'0 00'0 000 000 00'0 00'0 000 00'0 00'0 00'0 00'0 94000 0 tl/N 00'0 00'0 00'0 00'0 00'0 00'0 000 00'0 VN 00'0 00'0 00'0 00'0 %000 V/N 00'0 00'0 TT'0 TT'0 00'0 00'0 00'0 V/N 00'0 00'0 00'0 00'0 000 %COT %0 640 640 640 %0 60 %0 V/N l9D0196911E1 0 0 0 60 0 061 005'0 616.5 3004 60-360'E 10-3066 10-319'0 10-360'1 S0-310'1 10-3501 6..011 papua-u8d0 618.0613 u0n5a000] 0 0 0 0T x1.460 (0199 0111084 980 9916A Plnbn M¢aH) D3 . 34: 9a/M V/N v/N 00'0 00'0 00'0 000 00'0 00'0 00'0 00'0 00'0 00'0 00'0 000 %000'0 V/N 00'0 00'0 00'0 000 00'0 00'0 000 00'0 V/N 00'0 00'0 00'0 00'0 9600'0 iM300:0 v/N 000 000 00'0 00'0 00'0 00'0 000 V/N 00'0 00'0 00'0 00'0 00'0 9'00'0 .. S0a.9. +g 7 v/N V/N, 00'0 000 000 000 000 00'0 9/9 000 000 0011 OT 0 00 0 00'0 00'0 00'0 000 00'0 VIN V/N COO 00'0 000 000 000 00'0 00'0 000 TITO TTO 111115.1 9E111111'1111 NO 10-30913 . OR SET seluelj NO 10-3191 ST 911'T popsuuo9 NO SO -31O1 0 0 .9910 NO SO -3001 0 0 (90913 011 EAU 10-3181 TT 96 saNTA 000 OTO TEO 00'0 SWO 5W1) STO 901) oao 907 LEO 95115 'MOST TTOVE 61.196 EC196 ZWEES 1061160 OEPT ova ZESI oao TETT WWI oao BO'S 90'5 STET STET STE EWE 10.6 DELL 000 00'0 61'61 SE 61 0011 ITS t1W0I 1,0.00 Sec ECT 66 61,01 00'0 000 6.6 TE6 00.90 ZTSZ 01.9 61,0 ETV EEO ZVO 607 11999 doOld xo NO xo 00-301,0 COT OS 006 619410 SET (N6.111O11) sientapuop 00 000 000 000 EEO EWO SCTO IVO SWO DOTI SET 0113 SEEZT 10.10T 09 6 ZELVST TLEBT ST0 1013 ET10 60'1Z 99.0 TES TES WWI 000 TTO SEE SEE 0610 061S LEI LWI of 3 Lk walk auozuaqihm .50 OTO oao 90'0 8600 85'60 DirOT VITOT ZWSEIS auaniaL 000 000 1611 900 191, TEE 9010 01 0; ftlf tomes LEO 101 001 101 JOA xo 60-301010 00-30911 VCISTIV 00-3061 NO NO 000 051 118.19 006'l OZ NO SZ (60.13 00/104 60-9006 VtLeT 2065/1 0919w) weld uorloi 5.'04 ALanoa510 AIR POLLUTANT EMISSION NOTICE (APEN) & API Permit Number: 16WE0773 Facility Equipment ID: Al [Leave blank unless APCD has already assigned a permit # & AIRS ID] Section 01— Administrative Information Company Name: Discovery DJ Services LLC bon for Construction Permit — Amine Sweetening Units - Emission Source AIRS ID: I'3 t q c. () I S" [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Section 02 — Requested Action (Check applicable request boxes) Source Name: Discovery Fort Lupton Plant NAICS, or SIC Code: 213112 Source Location: Section 11, TIN, R66W County: Weld Elevation: 5,135 Feet Mailing Address: 7859 Walnut Hill Lane, Suite 335 ZIP Code: 75230 Dallas, TX Person To Contact: Manya Miller "Phone Number: (214) 414-1980 E-mail Address: Manya@discoverymidstream.com Fax Number: (214) 414-1980 Section 03 — General Information For existing sources, operation began on: Normal Hours of Source Operation: General description of equipment and purpose: / / Request for NEW permit or newly reported emission source ® Request MODIFICATION to existing permit (check each box below that applies) ❑ Change process or equipment ❑ Change company name ❑ Change permit limit ❑ Transfer of ownership ® Other ❑ Request to limit HAPs with a Federally enforceable limit on PTE ❑ Request APEN update only (check the box below that applies) ❑ Revision to actual calendar year emissions for emission inventory CI Addl. Info. & Notes: Update 5 -Year APEN term without change to permit limits or previously reported emissions New Emission Source Amine Treater For new or reconstructed sources, the projected startup date is: 01 / 01 / 2018 24 hours/day 7 days/week 52 weeks/year 250 MMSCFD AmineTreater ► Will this equipment be operated in any NAAQS nonattainment area? (www.colorado.gov/cdphe/attainment) D. Does this facility have a design capacity less than 2 long tons/day of H2S in the acid gas? Provide documentation. Section 04 — Amine Sweetening Unit Equipment Information Manufacturer: TBD Reboiler Rating: N/A MMBtu/hr Amine Type: ❑ MEA ❑ DEA Amine Pump Make & Model: TBD Model: TBD Absorber Column Stages: ❑ TEA Serial No.: TBD 20 stages MDEA # of Pumps: Sweet Gas Throughput: Design Capacity: 245.254 MMSCF/day Requested2: • Inlet Gas: Rich Amine Feed: . Lean Amine Stream: l tv0O Pressure: 910 psia psig Pressure: 946 1_071_3 psia Pressure: -950, Ico1..'ypsia Calendar year actual: Temperature: 4-19 (D1D °F Temperature: 120 °F Temperature: 120 °F wt. % amine: 50 Mole loading H2S: Sour Gas Input: Pressure: -940 1piZ � psia Temperature: NGL Input: Pressure: psia Temperature: Flash Tank: Pressure: 93 1Z.. 3 psia Temperature: 'You will be charged an additional APEN fee if APEN is filled out incorrectly or information is missing and requires re -submittal. 'Requested values will become permit limitations. ❑ DGA / 250— °1112'50 MMSCF/yr. MMSCF/yr. Flowrate: gal/min Flowrate: 8001,00 gal/min 0.0004 Mole loading CO2: 0:005 L7.0%.%llo 1-h0- lo(o 5{ °F Flowrate: 250 MMSCF/day °F Flowrate: -He 11,1.4 °F ❑ None gal/min Additional Information Required: ® Attach a process flow diagram ® Attach the simulation model inputs & emission report ® Attach composition reports for the rich amine feed, sour gas feed, NGL feed, & outlet stream (emissions) ® Attach the extended gas analysis (including BTEX & n -Hexane, H2S, CO2, 2,2,4 Trimethylpentane) FORM APCD-206 Rcdli�cs a ckd iof 2c 361294 Page ® Yes ❑ No ❑ Don't know ® Yes ❑ No ❑ Don't know Colorado Department of Public Health and Environment Air Pollution Control Division (APCD) This notice is valid for five (5) years. Submit a revised APEN prior to expiration of five-year term, or when a significant change is made (increase production, new equipment, change in fuel type, etc). Mail this form along with a check for $152.90 to: Colorado Department of Public Health & Environment APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 APR 18 ail For guidance on how to complete this APEN form: Air Pollution Control Division: (303) 692-3150 Small Business Assistance Program (SBAP): (303) 692-3148 or (303) 692-3175 APEN forms: www.Colorado.gov/cdphe/oilaaspermits Application status: www.colorado.aov/cdphe/pernitstatus ❑ Check box to request copy of draft permit prior to issuance. ® Check box to request copy of draft permit prior to public notice. 6 - AP Form-APCD-206-Amine-Unit-APEN AIR POLLUTANT EMISSION NOTICE (APEN) & App Lion for Construction Permit — Amine Sweetening Unit' - Permit Number: 16WE0773 Emission Source AIRS ID: 1�,3 / .c1 E9" / 015 Section 05 — Stack Information (Combustion stacks must be listed here) Operator Stack S No. Stack Base Elevation (feet) Stack Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Moisture (%) Cl 5,115 TBD TBD TBD TBD TBD Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) Horizontal Datum (NAD27, NAD83, WGS84) UTM Zone (12 or 13) - UTM Easting or Longitude (meters or degrees) UTM Northing or Latitude (meters or degrees) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) l l Direction of stack outlet (check one): ® Vertical ❑ Vertical with obstructing raincap Exhaust Opening Shape & Size (check one): ® Circular: Inner Diameter (inches) = ❑ Horizontal ❑ Down ❑ Other: Length (inches) _ Section 07 — Control Device Information (Indicate if a control device controls the flash tank and/or regenerator emissions ./ VRU used for control of: Flash;Gaa=< _<z- F=- ;,,-;=,;•;• •• - --== /1 Combustion Device used for control of: Flash (secondary) + Acid Gas Rating: 20 MMBtu/hr Size: TBD Make/Model: TBD Type: Oxidizer Make/Model/Serial #: TBD Requested VOC & HAP Control Efficiency: 98 % VOC & HAP Control Efficiency: Requested: 98 % Manufacturer Guaranteed: 98 % Annual time that VRU is bypassed (emissions vented): 10 % Minimum temp. to achieve requested control: IiNO0 °F Waste gas heat content: Btu/scf Constant pilot light? ■ Yes /1 No Pilot burner rating: MMBtu/hr ■ Describe Any Other: ❑ Other (Describe): Width (inches) = Section 08 — Emissions Inventory Information & Emission Control Information ❑ Emission Factor Documentation attached Pollutant Control Device Description Primary Secondary Data year for actual calendar yr. emissions below & gas throughput above (e.g. 2007): Control Efficiency (% Reduction) Emission Factor Actual Calendar Year Emissions' Requested Permitted Emissions' Uncontrolled Basis Units Uncontrolled (Tons/Year) Controlled (Tons/Year) Uncontrolled (Tons/Year) Controlled (Tons/Year) Estimation Method or Emission Factor Source VOC N0x CO SO2 HzS Benzene Toluene Ethylbenzene Xylene n -Hexane 9.57, O lb/MMSCF y�6.ti `6.31 IPro x. I1,1 `INmak 6.36 0,4t Ib/MMSCF 159. 0, Ib/MMSCF 0474.0.7� Ib/11MSCF 0:56 °AA' lb/MMSCF 3O.% 0.31- tPfo v✓tAx 2a3 15.19 1.3�• 0.41 0.32. 0.03 P‘ro Marc \)✓oW'4X N O Max 0.3.2 ,o9 lb/MMSCF 9:30- 0 .OS lb/MMSCF 3.33 0.0c, 1.42 0.p3 -Pfofl' aX Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. 'You will be charged an additional APEN fee if APEN is filled out incorrectly or information is missing and requires re -submittal. 7 ►_. _ n1 .. 1..CiA/.: 2Annual emission fees will be based on actual emissions reported here. If left blank, annual emission fees will be based on requested emissions. Section 09 —Applicant Certifican - I hereby certify that all information contained herein and information submitted with this application is complete, true and correctW�� tul e4 -' 17 —17 Cory G. Jordan EVP Operations Signature of Person egal y thorized to Supply Data Date Name of Legally Authorized Person (Please print) Title Page 2 of 2 6 - AP Form-APCD-206-Amine-Unit-APEN Glycol Dehydration Unit APEN - Form APCD-202 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for Glycol Dehydration (Dehy) Units only. If your emission unit does not fall into this category, there may be a more specific APEN for your source. In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of alt 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: 16WE0773 AIRS ID Number: 12. i' E cmi 6 (, [Leave blank unless APCD has already assigned a permit # and AIRS ID] Company equipment Identification: D3 [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': Site Name: Discovery DJ Services LLC Discovery Fort Lupton Plant Site Location: Section 11, T1 N, R66W Mailing Address: 2 (Include Zip code) 7859Walnut Hill Lane, Suite 335 Dallas, TX 75230 E -Mail Address2: Many a@discoverymidstream.com —,a Site Location County: Weld NAICS or SIC Code: 213112 Permit Contact: Manya Miller Phone Number: (214) 414-1980 'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. Form APCD-202 - Glycol Dehydration Unit APEN - Revision 02/2017 361295 COLORADO ASAM -i n Fr ennin.+main Permit Number: 16WE0773 AIRS ID Number: / le19/ Olla [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 name ❑✓ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: 3 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. TEG dehydrator for the removal of water from Facility equipment Identification: For existing sources, operation began on: D3 / / For new or reconstructed sources, the projected start-up date is: 01 /01 /2018 ❑✓ 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 unit located at a stationary source that is considered a Major Source of (HAP) Emissions Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 O days/week Yes Yes ❑✓ weeks/year No No :COLORADO 2 I Hai:YS&:vennmvm Permit Number: 16WE0773 AIRS ID Number: 123 / 9E`r/ p Ib [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Dehydrator Serial Number: Glycol Used: TBD TBD Ethylene Glycol (EG) Model Number: TBD Reboiler Rating: 1.0 DiEthylene Glycol (DEG) Glycol Pump Drive: ✓❑ Electric ❑ Gas If Gas, injection pump ratio: Pump Make and Model: TBD MMBTU/hr ❑ TriEthylene Glycol (TEG) # of pumps: Glycol Recirculation rate (gal/min): Max: 20 Lean Glycol Water Content: 1.2 Wt.% Requested: 20 Acfm/gpm 1O Dehydrator Gas Throughput: Design Capacity: 250 MMSCF/day Requested: 91tZ5° MMSCF/year Actual: MMSCF/year Inlet Gas: Pressure: 925 Water Content: Wet Gas: 7.0 Flash Tank: Pressure: 75 Cold Separator: Pressure: Stripping Gas: (check one) ❑✓ None ❑ Flash Gas ❑ Dry Gas ❑ Nitrogen Flow Rate: scfm psig Temperature: lb/MMSCF 0 Saturated Dry gas: psig Temperature: psig Temperature: 85 100 °F °F °F lb/MMSCF ✓❑ NA NA Additional Required Information: Attach a Process Flow Diagram Attach GRI-GLYClc 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) Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 yip') l0(10[11 - COLORADO 3 I H.vlb`� SEnve[°nm°M Permit Number: 16WE0773 AIRS ID Number: 2.3 /o'Gc9/ O1ko [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) N 1266987.86 E3211856.99 Operator Stack ID No. Discharge Height Above Ground, Level, (Feet) Temp. ('F) Flow Rate (ACFM) Velocity (ft/sec)" C2 TBD TBD TBD . TBD Indicate the direction of the stack outlet: (check one) ❑� Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap ❑✓ Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 4 I Av COLORADO Hwl6i 6E �vaonrnnrti Permit Number: 16WE0773 AIRS ID Number: l /9CQe�/ Orb [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information Used for control of: Regenerator ❑✓ Condenser: Type: BTEX Maximum Temp 160 Requested Control Efficiency Make/Model: TBD Average Temp 65 ❑ VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed % ❑ Combustion Device: Used for control of: Regenerator Vent & Flash Gas Rating: 4.86 MMBtu/hr Type: Thermal Oxidizer Make/Model: TBD Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: 1,400 98 99 % % Waste Gas Heat Content 405 Btu/scf Constant Pilot Light: ❑✓ Yes ❑ No Pilot burner Rating 0.057 MMBtu/hr Closed ❑ Loop System: Used for control of: Description: System Downtime ❑ Other: Used for control of: Description: Control Efficiency Requested 0 Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 p .COLORADO 5 I m�;n, m, II 1 alt,fThU.ath,i. U Permit Number: 16WE0773 AIRS ID Number: its /90 / O4to [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑✓ Yes ❑ No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Requested Control Efficiency (% ;eduction in emissions) PM S0x NOx CO VOC DTEX-Ceadcnacr Combustor(-hcr 98% otid . 4 ot;d; zc> HAPs Combustor(re ..„1 ()yak, r..) 98% Other: From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Pollutant Uncontrolled Emission Factor Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions Requested Annual Permit Emission Limit(s)4 Uncontrolled (Tons/year) ', Controlled5 (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) PM SOx NOx CO VOC %.47., Ib/MMSCF GRI-GLYCaIc .$'i. 3`( ,(1,C1 Benzene ; 5,39 xat0't Ib/MMSCF GRI-GLYCaIc Iri.5`j 0.41 Toluene a 5,S$xrol Ib/MMSCF GRI-GLYCaIc 2.Ln.$3 0.5`I Ethylbenzene r -t.u. Kto 7• Ib/MMSCF GRI-GLYCaIc 3• �o 0.o'S Xylenes • °7 j -1 y, tt I •Ib/MMSCF GRI-GLYCaIc 10. ZZ 0.2. n -Hexane 1.5-f-xID t Ib/MMSCF GRI-GLYCaIc �. Ig 0. I`{ 2,2,4- Trimethylpentane .r. F Other: jkeckklwcs O. D&)4w cwta'I I. future process growth. %4DS 101lOl1�- 4 Requested values will become permit limitations. Requested limit(s) should consider 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 6 I A Haal[b &ThWteonmanfl Permit Number: 16WE0773 AIRS ID Number: its /1Es,1,9 / Quo [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. q_I7-17 Signature of Le • ly Author ed Person (not a vendor or consultant) Date Cory G. Jordan EVP Operations Name (please print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ❑✓ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) Send this form along with.] 52.90 to: Colorado Department of Public Health and Environment -i 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 Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https://www.colorado.gov/cdphe/apcd Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 AV COLORADO m 7 I � Haa1��bFnu_�o.unox� Boiler APEN - Form APCD-220 Air Pollutant Emission Notice (APEN) and Application for Construction Permit .1 t'YVk "Vi All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, 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. Do not complete this form for the following source categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: / /www.colorado. goy/ pacific/cdphe/apen-or-air-permit-exemptions. 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: 16WE0773 Spur`', AIRS ID Number: 3 /4 99/ © 4 T [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Discovery DJ Services LLC Discovery Fort Lupton Plant Site Location: Sec{ton 11, T1 N, R66W Mailing Address: c . (Include Zip code) 7859 Walnut Hill Lane, Suite 335 ..a Dallas, TX 75230 E -Mail Address2: Manya@discoverymidstream.com Site Location County: Weld NAICS or SIC Code: 213112 Permit Contact: Manya Miller Phone Number: (214) 414-1980 'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. el nag 2Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. 3 Permit Number: 16WE0773 AIRS ID Number: 123 / qt -`j9 / O11 - [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action El NEW permit OR newly -reported emission source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment El Change company name ❑ Change permit limit ❑ Transfer of ownership3 - OR APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info Et Notes: ✓❑ Add point to existing permit ❑ Other (describe below) 3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: the Hot Oil Heating System System includes 2 x 50 MMBtu/hr heaters for Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): For existing sources, opp,(ation began on: H1 and H2 For new, modified, or reconstructed sources, the projected start-up date is: 01-01-2018 ❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: Seasonal use percentage: y Dec -Feb: hours/day Mar -May: days/week weeks/year June -Aug: Sept -Nov: Are you reporting multiple identical boilers on this APEN? ❑✓ Yes ❑ No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers or separate meters for each unit): Separate fuel usage meters for each unit. Form APCD-220 - Boiler APEN - Revision 7/2016 2 I ,COLORADO bcp,cm d o-suk MN�t06Fff4Zl0nmi91 Permit Number: 16WE0773 AIRS ID Number: 12.3 196111 on - [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) N 1267294.44 E 3212491.55 Stack ID No. Discharge Height Operator Temp. Above Ground Level (Feet) ('F) Flow Rate . (ACFM) Velocity (ftrsec)_ H1/H2 70 480 18,000 22 Indicate the direction of the stack outlet: (check one) E Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): ❑ Upward with obstructing raincap 50" Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use4 (Specify Units) Requested Annual Permit Limits (Specify Units) 50 MMBtu/hr (each) 387.61 MMSCF/year/unit From what year is the actual annual fuel use data? Fuel consumption values entered above are for: E Each Boiler ❑ All Boilers ❑ N/A Indicate the type(s) of fuel used6: ❑ Pipeline Natural Gasc ❑ Field Natural Gas ❑ Ultra Low Sulfur Diesel ❑ Propane ❑ Coal ❑✓ Other (describe): (assumed fuel heating value of 1,020 BTU/SCF) Heating value: BTU/SCF (assumed fuel heating value of 138,000 BTU/gallon) (assumed fuel heating value of 2,300 BTU/SCF) Heating value: BTU/lb Ash Content: Sulfur Content: Residue Natural Gas Heating value (give units): 1,130 Btu/scf if you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers. 5Requested values will become permit limitations. Requested limit(s) should consider future process growth. 61f fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2016 'COLORADO 3 I AY iat 64 HNitri�*EevittnM;61 Permit Number: 16WE0773 AIRS ID Number: 123 /9E941 / O I� [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6- 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? nYes 0✓ No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Control Efficiency (% reduction in emissions) TSP (PM) PM10 PM2.5 SOX NO), CO VOC Other: From what year is the following reported actual annual emissions data? Use the follesving tables to report the criteria pollutant emissions from source: (Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type (natural gas, #2 diesel, ".'.etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission FactorEmission Source (AP_42, Mfg etc ) Actual Annual Emissions Requested Annual Permit Ltmtt(s) s Uncontrolled Tons/ ear (Tons/year) ) Controlled' (Tons/year) R Y ) Uncontrolled Tons/ ear(Tons/year) (Tons/year) ) _Controlled Residue Natural Gas TSP (PM) $.4Z 1,^nmsej AP -42 3.62.3,2.to 2.633,24 PM10 g! -It IblwivA5C- AP -42 3.2b X3:114 PM2.5 <6.`i,i %K+v15Ct AP -42 3.02 3.2b 131 SOX 43.(d1/401,11w).54. AP -42 0-39 O.'ito $z9 0,212 NOx 33.1 1 c i Mfg. 13.►' I I3, 14 C_O (ol-. % Iww,sGP Mfg. 26.28 26.28 Vot (D,oe1 "3I,,,,4m5 I AP -42 2:62 z .3b 2- Z.3 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 'Annual emission fees will be;based on actual controlled emissions reported. If source has not yet started operating, leave blank. i% igze4 Form APCD-220 - Boiler APEN - Revision 7/2016 4 I 'COLORADO Department 3r rv:u< H��1� 5F�•.ultanmPnl Permit Number: 16WE0773 AIRS ID Number: l2?� i9E9`1 / ply [Leave blank unless APCD has already assigned a permit # and AIRS ID] Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions Requested Annual Permit., Emission Limit(s)5r, Uncontrolled (Tons/year) Controlled? (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) TSP (PM) PM10 PM7.s SOX NO), CO VOC Other: If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: Actual Annual Emissions. Requested Annual Permit Emission Limit(s)5, Uncontrolled (Tons/year) Controlled' (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) TSP (PM) 3-62' 3.62 PM10 .3762 4:e2- 3:62 -2.02 SOX 07-2 9- 9 NOX 4371 -4 -- CO �6 6- VOC X762-- OtI r: 1-145 1o/v-t/ 1- 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2016 COLORADO 5I�',�bn�ro� Yfiir[r $Ef5�lennmPnl Permit Number: 16WE0773 AIRS ID Number: 113 /1Ei9 / of q - [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - 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? D 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) 110543 Hexane N/A l,`f1 t1m•++5d.-{ AP -42 ISLIb t5tllo 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, eave blank. Section 8 - Applicant Certification NOS (011 /r I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. 4--1 7 % -7 lly horized Person (not a vendor or consultant) Date Signature Le g / Cory G. Jordan EVP Operations Name (please print) Title Check the appropriate'box if you want: ❑ Copy of the Preliminary Analysis conducted by the Division ❑ Draft permit prior to public notice ❑ Draft of the permit prior to issuance 14 (Checking any of these boxes may result in an increased fee and/or processing time) R,{ This notice is valid for fNe (5) years unless a significant change is made, such as an increased production, new equipment, changed to fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the expiration date of this APEN form. Send this form along with $152.90 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Telephone: (303) 692-3150 Form APCD-220 - Boiler APEN - Revision 7/2016 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd COLORADO 6 I AV , ,r,tn, Patilc nit�sFrvironrnnm Boiler APEN - Form APCD-220 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, 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. Do not complete this form for the following source categories: - Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by natural gas or liquid petroleum gas (LPG). Heaters or boilers with a design capacity less than or equal to 10 MM6tu/hour used solely for heating buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG). More information can be found in the APEN exempt/permit exempt checklist: https: //www.colorado.gov/ pacific /cdphe /apen-or-air-permit-exemptions. 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: 16WE0773 AIRS ID Number: [ 13 /ct-Eye/ G g [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Site Name: Discovery DJ Services LLC d Discovery Fort Lupton Plant Site Location: Section 11, Ti N, R66W Mailing Address: (Include Zip Code) 7859 Walnut Hill Lane, Suite 335 Dallas, TX 75230 E -Mail Address2: Manya@discoverymidstream.com Site Location County: Weld NAICS or SIC Code: 213112 Permit Contact: Manya Miller Phone Number: (214) 414-1980 'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. 36129? Permit Number: 16WE0773 AIRS ID Number: l j, / 9611 / Of [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 name ❑✓ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership; ❑ Other (describe below) - OR ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info a Notes: For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Boiler Information General description of equipment and purpose: for the Mole Sieve Dehydration System Natural Gas -Fired Regenerator Heater Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identification No. (optional): H3 For existing sources, operation began on: For new, modified, or reconstructed sources, the projected start-up date is: 01-01-2018 lgi Check this box if operging hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source 'Op'eration: Seasonal use percentage:, Dec -Feb: hours/day Mar -May: days/week weeks/year June -Aug: Sept -Nov: Are you reporting multiple identical boilers on this APEN? EYes 0✓ No If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers 'or separate meters for each unit): Form APCD-220 - Boiler APEN - Revision 7/2016 2 I COLORADO DOM 4Velrontn4N Permit Number: 16WE0773 AIRS ID Number: I2,s/"E19 / O1? [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) N 1266777.00 E 3212466.00 _' Operator '_ Stack ID No: - Discharge Height . Above Ground Level Temp. F) „ (' • Flow Rate(Feet) ' (ACFM) Velocity (ft/sec) H3 30 480 11,000 15 Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): 9 Square/rectangle Interior stack width (inches): 9 Other (describe): ❑ Upward with obstructing raincap 24" Interior stack depth (inches): Section 5 - Fuel Consumption Information Design Input Rate (MMBTU/hr) Actual Annual Fuel Use4 (Specify Units) Requested Annual Permit Limits (Specify Units) 15.0 MMBtu/hr 116.28 MMSCF/year From what year is the actual annua fuel use data? Fuel consumption values=entered above are for: ❑r Each Boiler 9 All Boilers 9 N/A Indicate the type(s) of fuel used6: A ,1 9 Pipeline Natural Gas; c (assumed fuel heating value of 1,020 BTU/SCF) 9 Field Natural Gas ;• Heating value: BTU/SCF 9 Ultra Low Sulfur Diesel •,I 9 Propane (assumed fuel heating value of 2,300 BTU/SCF) (assumed fuel heating value of 138,000 BTU/gallon) 9 Coal Heating value: ❑✓ Other (describe): BTU/lb Ash Content: Sulfur Content: Residue Natural Gas Heating value (give units): 1,130 Btu/sal 4If you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual boiler basis, or if the values represent total fuel usage for multiple boilers. 5Requested values will become permit limitations. Requested limit(s) should consider future process growth. 61f fuel heating value is different than the listed assumed value, please provide this information in the "Other" field. Form APCD-220 - Boiler APEN - Revision 7/2016 COLORADO 3 I A'^ t,enILic yaal!Y s ,w,mMXun1 Permit Number: 16WE0773 AIRS ID Number: l23 '9 H ' Ol`6 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6- 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 0✓ No If yes. Tease describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Control Efficiency (% reduction in emissions) TSP (PM) PM,o PM2.5 SO, NO„ CO VOC Other: From what year is the following reported actual annual emissions data? Use the following tables to report the criteria pollutant emissions from source: Use the data reported in Section 5 to calculate these emissions.) Primary Fuel Type- (natural gas, #2etc.) diesel, Pollutant Uncontrolled Uncontrolled Emission Factor (Specify Units) Factor Source (AP-42,etc) Mfg . - - Actual Annual Emissions_ Requested Annual Permit .; Emission Limit(s)s Uncontrolled. Controlled' Uncontrolled (Tons/year) Control(Tons/velar) Residue Natural Gas TSP (PM) 14.1- Ns(4 v'Elf�. 0.54-0.$5 .0754-6,e, PMio t4l-Ibw,r„ .f W1c. 8,-54 0.%S .40c PM2.s t(-1.1i4wwilsc- i mC5. 3. zt 0.85 0.54412,a SO, O•-71M„Asdi AP -42 0.04 0.04 NO `IS,ZIrrim5c•F Mfg' 7.14/,(4,3 4 Z. b` Co: 45.2- lown5c4 Mfg. X 2.(03 6-.-99.2.(.0:, vQ:4 2i.SIbinnta 040, (3.-3,9 I:7_5 0.39 t.2.5 other: r { 1;'&cs P� at cksd cal • 14OS I 5 Requested values will becorrte permit limitations. Requested limit(s) should consider future process growth. l Zt{ l L� 'Annual emission fees will be;based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2016 - C oDL.0RADO 4 I Av o . .ywl<9 SF Vtll TSP (PM) Permit Number: 16WE0773 AIRS ID Number: (1.6 / 9 91 / Oi S [Leave blank unless APCD has already assigned a permit # and AIRS ID] XCheck this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7. If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria emissions table below: Secondary Fuel Type (#2 diesel, waste oil, etc.) Pollutant Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg. etc) • AdtUat Annual Emissions Requested Annual Permit. Emission Limit(s)s .." Uncontrolled (Tons/year) Controlled' (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year), TSP (PM) PMio PM2.5 SOX NO,, CO VOC Other: If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary fuels' emissions tables in this Section 6: Actual Annual Emissions Requested Annual Permit Emission Limit(s)5` Uncontrolled (Tons/year) Controlled' (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) PM10 .0.54 -0754 2. 0.54- 0 .54- SOX 9-94 0.04 NOX 7.14 - CO 5.00 - 5.00, VOC 0.39 O,t j'Or: ADS 5Requested values will become permit limitations. Requested limit(s) should consider future process growth. 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-220 - Boiler APEN - Revision 7/2016 5 I COLORADO Department d Pat nr.$kn fr W;ranm?m Permit Number: 16WE0773 AIRS ID Number: tis / Te ► t / ova [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - 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 -41 Mfg. etc) Uncontrolled Actual Emissions (/bs/year) Controlled Actual 7 Emissions (lbs/year) 'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. -17-)7 Signature of !gall` A.thorized Person (not a vendor or consultant) Date Cory G. Jordan EVP Operations Name (please print) Title Check the appropriate box if you want: ❑ Copy of the Prel4minary Analysis conducted by the Division ❑✓ Draft permit ptor to public notice ❑ Draft of the permit prior to issuance (Checking any of these IJOxes may result in an increased fee and/or processing time) This notice is valid for fiuc (5) years unless a significant change is made, such as an increased production, new equipment, change"i!n fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the expiration date of this APEN form. Send this form along with $152.90 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 Telephone: (303) 692-3150 Form APCD-220 - Boiler APEN - Revision 7/2016 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https: / /www.colorado. gov/cdphe/apcd COLORADO 6 .� Depa triF'Itk Hr]IthS $%VUQ,V,W! SIR POLLUTANT EMISSION NOTICE (APEN) & Appli on for Construction Permit — Condensate Storage Tank(s)' Permit Number: 16WE0773 Facility Equipment ID: CT2 Section 01— Administrative Information Company Name: Discovery DJ Services LLC [Leave blank unless APCD has already assigned a permit # & AIRS ID] Emission Source AIRS ID: )2. iC / O 1 9' [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Source Name: Discovery Fort Lupton Plant Source Location: Section 11, T1N, R66W Mailing Address: 7859 Walnut Hill Lane, Sprtitg;3,3. _; „_ ri ZIP Code: Dallas, TX Person To Contact: Manya Miller E-mail Address: Manya@discoverymidstream.com Section 03 — General Information For existing sources, operation began on: This Storage Tank is ❑ Exploration & Production Located at: (E&P) Site Will this equipment be operated in any NAAQS nonattainment area? Is actual annual average hydrocarbon liquid throughput ≥ 500 bbl/day? ► Are these condensate tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-105. ► Are you requesting ≥ 6 ton/yr VOC emissions, or are uncontrolled actual emissions ≥ 6 ton/yr? General description of equipment purpose: Storage of stabilized produced liquids from field natural gas separation [NOT liquids extractions] Section 04 — Storage Tank(s) Information Condensate Requested Permit Limit: 65,700 bbl/year Throughput: Actual: bbl/year Actual While Controls Operational: Phone Number: Fax Number: / / NAICS, or 213112 SIC Code: County: Weld Elevation: 5,135 Feet 75230 Section 02 — Requested Action (Check applicable request boxes) El Request for NEW INDIVIDUAL permit El Request for coverage under GENERAL PERMIT ❑ GP01 ❑ GP08 ® Request MODIFICATION to existing INDIVIDUAL permit (check boxes below) ❑ Change process or equipment ❑ Change company name ❑ Change permit limit ❑ Transfer of ownership ® Other [l (214) 414-1980 ❑ Addl. Info. & Notes: (214) 414-1980 Midstream or Downstream (Non-E&P) Site Yes ❑ No Yes ® No APEN Submittal for Permit Exempt/Grandfathered source APEN Submittal for update only (Please note blank APEN's will not be accepted) New Emission Source (4 x 1,000BBL Stabilized Condensate Storage Tanks) For new or reconstructed sources, the projected startup date is: 01 / 01 / 2018 Normal Hours of Source Operation: 24 hours/ day Are Flash Emissions anticipated at these tanks If "yes", identify the stock tank gas -to -oil ratio: Average API Gravity of Sales Oil: Tank Design: Fixed Roof: degrees Internal Floating Roof: ❑ RVP of Sales Oil External Floating Roof: bbl/year Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of most recent storage vessel in storage tank (Month/Year) Date Of First Production (Month/Year) CT2 4 4,000 NA NA Wells Serviced by this Storage Tank or Tank Battery (E&P Sites Only) API Number Name of Well Newly Reported Well - - ❑ - - ■ - - ■ - - ❑ - - ■ FORM APCD-205 361298 - Page 1 of 2 7 days/ 52 weeks/ week year Yes ® No m3/liter Yes ® No Yes ® No Colorado Department of Public Health and Environment Air Pollution Control Division (APCD)This notice is valid for five (5) years. Submit a revised APEN prior to expiration of five-year term, or when a significant change is made (increase production, new equipment, change in fuel type, etc). Mail this form along with a check for $152.90 per APEN for non- E&P, midstream and downstream sources or $152.90 for up to five (5) APENs for E&P sources and $250 for each general permit registration to: Colorado Department of Public Health &,Environment APCD-SS-B1 4300 Cherry Creek Drive South AP�f J 8 ^oi Denver, CO 80246-1530 For guidance on how to complete this APEN form: Air Pollution Control Division: °f303) 692-3150 Small Business Assistance Program (SBAP): (303) 692-3148 or (303) 692-3175 APEN forms: http://www.colorado.gov/cdphe/oilgasAPENS Application status: http://www.colorado.gov/cdphe/permitstatus 10 - AP Form-APCD-205-Condensate-Tanks-APEN CT2 SIR POLLUTANT EMISSION NOTICE (APEN) & Appli Permit Number: 16WE0773 Section 05 — Stack Information (For Midstream sites only) Operator Stack ID No. Stack Base Elevation (feet) Stack Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Moisture (%) C3 5,111 TBD TBD J 0 0 TBD Direction of stack outlet (check one): ® Vertical O Vertical with obstructing raincap Exhaust Opening Shape & Size (check one): D Circular: Inner Diameter (inches) = TBD on for Construction Permit — Condensate Storage Tank(s)1 Emission Source AIRS ID: 11,1 / Ect`] / 019 Section U6 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM) Horizontal Datum (NAD27, NAD83, WGS84) UTM Zone (12 or 13) UTM Fasting or Longitude (meters or degrees) UTM Northing or Latitude (meters or degrees) Method of Collection for Location Data (e.g. map, GPS, GoogleEarth) NAD83 13 3212435.86 1267432.67 Digitized Plot Plan ❑ Horizontal ❑ Down 0 Other: Length (inches) = O Other (Describe): Width (inches) = Section 07 — Control Device Information • Vapor Recovery Unit (VRU) used for cpntirpJ of dle,Storage Tlk(s).. Size: Make7Mi3del: "-;'' '- '�.-' -' ' .1 Combustion Device used for control of the Storage Tank(s) Type: Combustor Make/Model Rating: 10.0 MMBtu/hr TBD Requested VOC & HAP Control Efficiency: % VOC & HAP Control Efficiency: Requested: 98 % Manufacturer Guaranteed: Waste gas heat content: 1,030 98 % Annual time that VRU is bypassed (emissions vented): % Minimum temp. to achieve requested control: 1,400 °F Btu/scf • Closed loop system used for control of the storage tank(s) Description: Constant pilot light? /1 Yes ■ No Pilot burner rating: 0.057 MMBtu/hr • Describe Any Other: Section 08 — Gas/Liquids Separation Technology Information (E&P Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? Please describe the separation process between the well and the storage tanks: psig Section 09 — Emissions Inventory Information & Emission Control Information ❑ Emission Factor Documentation attached Data year for actual calendar yr. emissions below & throughput in Sec. 04 (e.g. 2007): G3:k.ck.C'%M \ OM-. W \1I t 3 Pollutant Emission Factor Actual Calendar Year Emission Requested Permitted Emissions Emission Factor Data Source Uncontrolled Basis Units Uncontrolled (Tons/Year) Controlled (Tons/Year) Uncontrolled (Tons/Year) Controlled (Tons/Year) NOx VOC 0.62 lb/BBL 20.36 0.41 E&P Tanks CO Benzene 4.O1)C---(D lb/BBL 0.13 ' 2.%9$ l: -03 E&P Tanks Toluene 1.1.1..g- 01 lb/BBL 0.07 . 1.L1b E. -o3 E&P Tanks Ethylbenzene O:'Sr -oli lb/BBL b. (.Zo E -G-1 E&P Tanks Xylenes 3.tovE-aK lb/BBL 0.01 ' 2.,40 E-oN E&P Tanks n -Hexane ( 1-6-2. lb/BBL 348 Z,Ic'\ +.tVI C-02, E&P Tanks 2,2,4-Trimethylpentane 3.04 €-°S lb/BBL .61-14-E-04' O.c d S 1.0 L -O`, E&P Tanks 1 Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. Section 10 —Applicant Certification - I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. If this is a registration for coverage under#neral per it C3P(i7 or ( P08, I further certify that this source is and will be operated in full compliance with each, condition of the applicable general permit. -17-17 Cory G. Jordan Signature of Person gally Autlt rized to Supply Data Date Name of Legally Authorized Person (Please print) I You may be charged an additional APEN fee for APEN re -submittal due to incorrectly filled -out APEN or missing information. 2 Annual emissions fees will be based on actual emissions reported here. Additional Information Required: FORM APCD-205 0 0 Attach a pressurized pre -flash condensate extended liquids analysis, RVP & API analysis of the post -flash oil Attach E&P Tanks input & emission estimate documentation (or equivalent simulation report/test results) Attach EPA TANKS emission analysis if emission estimates do not contain working/breathing losses Page 2 of 2 0 EVP Operations Title Check box to request copy of draft permit prior to issuance. Check box to request copy of draft permit prior to public notice. 10 - AP_Fonn-APCD-205-Condensate-Tanks-APEN CT2 AIR POLLUTANT EMISSION NOTICE (APEN) & Appl; on for Construction Permit — Condensate Storage Tank(s) Permit Number: 16WE0773 Facility Equipment ID: ST Section 01— Administrative Information Company Name: Discovery DJ Services LLC [Leave blank unless APCD has already assigned a permit # & AIRS ID] Emission Source AIRS ID: I Z " I `1 G cq [Provide Facility Equipment ID to identify how this equipment is referenced within your organization.] Source Name: Discovery Fort Lupton Plant Source Location: Section 11, TIN, R66W Mailing Address: 7859 Walnut Hill Lane, Suite 335. Dallas, TX Person To Contact: Manya Miller E-mail Address: Manya@discoverymidstream.com NAICS, or 213112 SIC Code: County: Weld Elevation: 5,135 Feet ZIP Code: 85230 Phone Number: (214) 414-1980 Fax Number: (214) 414-1980 Section 02 — Requested Action (Check applicable request boxes) 'd20 Request for NEW INDIVIDUAL permit Request for coverage under GENERAL PERMIT O GP01 ❑ GP08 Request MODIFICATION to existing INDIVIDUAL permit (check boxes below) ❑ Change process or equipment ❑ Change company name ❑ Change permit limit ❑ Transfer of ownership ® Other APEN Submittal for Permit Exempt/Grandfathered source APEN Submittal for update only (Please note blank APEN's will not be accepted) Addl. Info. New Emission Source (2 x 400BBL Slop Storage Tanks) & Notes: Section 03 — General Information For existing sources, operation began on: / / For new or reconstructed sources, the projected startup date is: 01 / 01 / 2018 This Storage Tank is Exploration & Production Midstream or Downstream hours/ days/ weeks/ Located at: ❑ (E&P) Site ® (Non-E&P) Site Normal Hours of Source Operation: 24 day 7 week 52 year Will this equipment be operated in any NAAQS nonattainment area? ® Yes ❑ No Are Flash Emissions anticipated at these tanks ❑ Yes ® No Is actual annual average hydrocarbon liquid throughput≥ 500 bbl/day? ❑ Yes ® No If "yes", identify the stock tank gas -to -oil ratio: m3/liter ► Are these condensate tanks subject to Colorado Oil and Gas Conservation Commission (COGCC) 805 series rules? If so, submit Form APCD-105. ❑ Yes ® No ► Are you requesting ≥ 6 ton/yr VOC emissions, or are uncontrolled actual emissions ≥ 6 ton/yr? ❑ Yes ® No General description of equipment purpose: Storage of stabilized produced liquids from field natural gas separation [NOT liquids extractions] Section 04 — Storage Tank(s) Information Requested Permit Limit: Actual: Average API Gravity of Sales Oil: Tank Design: Fixed Roof: Condensate Throughput: 98,550 bbl/year bbl/year degrees Internal Floating Roof: Actual While Controls Operational: RVP of Sales Oil External Floating Roof: bbl/year Storage Tank ID # of Liquid Manifold Storage Vessels in Storage Tank Total Volume of Storage Tank (bbl) Installation Date of most recent storage vessel in storage tank (Month/Year) Date Of First Production (Month/Year) ST 2 800 NA NA Wells Serviced by this Storage Tank or Tank Battery (E&P Sites Only) API Number Name of Well Newly Reported Well - - ■ - - • - - ■ - - ❑ - - ■ FORM APCD-205 361299 Page 1 of 2 Colorado Department of Public Health and Environment Air Pollution Control Division (APCD)This notice is valid for five (5) years. Submit a revised APEN prior to expiration of five-year term, or when a significant change is made (increase production, new equipment, change in fuel type, etc). Mail this form along with a check for $152.90 per APEN for non- E&P, midstream and downstream sources or $152.90 for up to five (5) APENs for E&P sources and $250 for each general permit registration to: Colorado Department of Public Health & Envirdnment APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 For guidance on how to complete this APEN form: Air Pollution Control Division: (303) 692-3150 Small Business Assistance Program (SBAP): (303) 692-3148 or (303) 692-3175 APEN forms: http://www.colorado.gov/cdphe/oilgasAPENS Application status: http://www.colorado.gov/cdphe/permitstatus APR 11 - AP_ Form-APCD-205-Condensate-Tanks-APEN ST Permit SIR POLLUTANT EMISSION NOTICE (APEN) & Appli in for Construction Permit — Condensate Storage Tank(s)1 Number: 16WE0773 Emission Source AIRS ID: Li. 0,619 Information For Midstream sites only) Section 06 —Stack (Source, if no combustion) Location (Datum & either Lat/Long or UTM Section 05 — Stack Operator Stack ID No. Stack Base Elevation (feet) Stack Discharge Height Above Ground Level (feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) Moisture (%) C3 5,111 TBD TBD 0 0 TBD Direction of stack outlet (check one): ® Vertical D Vertical with obstructing raincap Exhaust Opening Shape & Size (check one): ® Circular: Inner Diameter (inches) = TBD Section 07 — Control Device Information • Vapor Recovery Unit (VRU) used for control -of -the Storage Tank(s) Size: MakeilVfedni: u.0 ' - ''_— ' ' ` ` " // Combustion Device used for control of the Storage Type: Combustor Tank(s) Make/Model 98 % Rating: 10.0 MMBtu/hr TBD Requested VOC & HAP Control Efficiency: % % VOC & HAP Control Efficiency: Requested: Minimum temp. to achieve requested control: Constant pilot light? 0Yes IIINo Manufacturer Guaranteed: Waste gas heat content: 1,030 98 % Annual time that VRU is bypassed (emissions vented): 1,400 °F Btu/scf • Closed loop system used for control of the storage tank(s) Description: Pilot burner rating: 0.057 MMBtu/hr • Describe Any Other: Horizontal Datum (NAD27, NAD83, UTM Zone UTM Easting or Longitude UTM Northing or Latitude Method of Collection for Location Data (e.g. map, WGS84) (12 or 13) (meters or degrees) (meters or degrees) GPS, GoogleEarth) NAD83 13 3212435.86 1267432.67 Digitized Plot Plan ❑ Horizontal ❑ Down ❑ Other: Length (inches) = El Other (Describe): Width (inches) = Section 08 — Gas/Liquids Separation Technology Information (E&P Sites Only) What is the pressure of the final separator vessel prior to discharge to the storage tank(s)? Please describe the separation process between the well and the storage tanks: psig Section 09 — Emissions Inventory Information & Emission Control Information ❑ Emission Factor Documentation attached Data year for actual calendar yr. emissions below & throughput in Sec. 04 (e.g. 2007): Pollutant Emission Factor Actual Calendar Year Emission Requested Permitted Emissions Emission Factor Data Source Uncontrolled Basis Units Uncontrolled (Tons/Year) Controlled (Tons/Year) Uncontrolled (Tons/Year) Controlled (Tons/Year) NOx VOC 0.11 lb/BBL 5.27 0.1 E&P Tanks CO Benzene 7.00E-04 lb/BBL 3.45E-02 6.90E-04 E&P Tanks Toluene 3.$lu r-o't lb/BBL I. aOE-Ot 3.$ E -G E&P Tanks Ethylbenzene 3.ot-I C -c2S lb/BBL I .S E-0 3. o G- OS E&P Tanks Xylenes lo.Oci e - oS lb/BBL 3.0 e- o3 ti, .o e -oS E&P Tanks n -Hexane 1.15E- 0Z„ lb/BBL 0:56- O.51- 1.l31 =O't_ E&P Tanks 2,2,4-Trimethylpentane _ Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above. (d1iK%6 1. 1-IQ5 Section 10 —Applicant Certification - I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. If this is a registration for coverage under gepral per it G O'1 or CyP08, I further certify that this source is and will be operated in full compliance with each condition of the applicable general permit. 41-1 7 - % 7 Cory G. Jordan Signature of Person Lally Authorized to Supply Data Date Name of Legally Authorized Person (Please print) 1 You may be charged an additional APEN fee for APEN re -submittal due to incorrectly filled -out APEN or missing information. 2 Annual emissions fees will be based on actual emissions reported here. Additional Information Required: FORM APCD-205 Attach a pressurized pre -flash condensate extended liquids analysis, RVP & API analysis of the post -flash oil Attach E&P Tanks input & emission estimate documentation (or equivalent simulation report/test results) Attach EPA TANKS emission analysis if emission estimates do not contain working/breathing losses Page 2 of 2 EVP Operations Title Check box to request copy of draft permit prior to issuance. Check box to request copy of draft permit prior to public notice. 11 - AP_Form-APCD-205-Condensate-Tanks-APEN ST i tee General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of specialty APENs is available 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: 16WE0773 AIRS ID Number: (2'3 '(9'/ 02_,1 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Site Name: Site Location: Discovery DJ Services LLC Discovery Fort Lupton Plant Section 11, T1 N, R66W Mailing Address: 7859 Walnut hill Lane, Suite 335 (include Zip Code) Portable Source 4 Dallas, TX 75230 Home Base: NA I „f Site Location WeIA ld County: NAICS or SIC Code: 213112 Permit Contact: Phone Number: Manya Miller (214) 414-1980 E -Mail Address2: manya@discoverymidstream.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 APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 1/2017 361301 COLORADO 1 Av CcP Rot4a N.Wt &Enxuonmott Permit Number: 16WE0773 AIRS ID Number: 2_3 / Cit ctl / 024 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ❑ NEW permit OR newly -reported emission source (check one below) ❑ STATIONARY source ❑ PORTABLE source - OR - ❑✓ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name ❑✓ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (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 a Notes: Acid Gas Oxidizer 3 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: Acid Gas Oxidizer to control VOC and HAPs for Amine Treater (Primary control for Acid Gas and Secondary control for Flash Gas) Manufacturer: TBD Model No.: TBD Serial No.: TBD ?sl Company equipment Identification No. (optional): Cl For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: 01-01-2018 E Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Seasonal use percentage: Dec -Feb: Mar -May: Jun -Aug: Sep -Nov: Form APCD-200 - General APEN - Revision 1/2017 2 I ' 7 COLORADO a,a=m.m. of a�wr Permit Number: 16WE0773 AIRS ID Number: /� / oLl [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Processing/Manufacturing Information £t Material Use ❑ Check box if this information is not applicable to source or process From what year is the actual annual amount? Description Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limit4 (Specify Units) Material Consumption: Assist Natural Gas 2.5 MMBtu/hr ici .8 MMSCF/yr AwiVit.Vht'k. Skin vCAt, * l4S� k,ouN.K. �0.SEe. p ,r / tb.� W1►yc�j�� Finished Product(s): 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. DS 101151q - Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) N 1266564.45 E 3211976.42 ❑ 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. Operator • tack ID No. $'3 '_ 2- � Discharge Height AboveGround Level: (Feet) Temp. (SF) Flow Rate - (ACFM) ' Velocity (ft/sec) Cl .TBD TBD TBD TBD r Is Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal El Downward O Other (describe): O Upward with obstructing raincap Indicate the stack opening and size: (check one) ❑✓ Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): O Other (describe): Interior stack depth (inches): Form APCD-200 - General APEN - Revision 1/2017 AVC060RADO H.ivl t bEn�i.nnmuni Permit Number: 16WE0773 AIRS ID Number: iLS /9011 OZ1 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment It 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 Limit4 (Specify Units) 1-9-.0 25 n'.8 MMSCF/yr From what year is the actual annual fuel use data? Indicate the type of fuel used5: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content: te' . wvsCf iv ❑✓ Other (describe): Residue Natural Gas Heating value (give units): 1,130 Btu/scf a Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes Q No a If yes, describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Cont-ol Equipment d. Description yy Overall Collection Efficiency `, Overall Control Efficiency (96 reduction in emissions) TSP (PM) e;. PM10 s PM2.5 - ," SOx NOx CO VOC Other: Form APCD-200 - General APEN - Revision 1/2017 41 "Ds 05114 - COLORADO h.-»miFshilc HriiN 6Ettusonmum TSP (PM) Permit Number: 16WE0773 AIRS ID Number: (2� / / OZ -1 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 (continued) From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions Requested Annual Perm ii Emission Limit(s)4 Uncontrolled (Tons/year) Controlled6 (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year) Nu) PM2.5 Sox D.C74 Ib/MMSCF AP=42 30.14 30.1-4 NOx CO VOC t 1.Sttl wrisc4' 1.33\binAmscE' R3 brky,r45c,f PA onrw5c Mfg. Mfg. 15.26 (Lk 9512.1 15.2612,` 9.35 12..1 Other: 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 lbs/year? I] Yes ❑ No If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source: CAS Number t .i Chemical t ;t Name - . F „r g;. Overall Control Efficiency Uncontrolled Emission Factor ' (specify units) Emission Factor Source (AP -42, Mfg. etc) Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions e (Ws/year) 110543 n -Hexane;;':{ 0 2'° ii"" 2.35�uci �wrY�c� AP -42 .844 L{ 2l0 344 yU T,J 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 1/2017 - 1DS IO�LS'►� COLORADO 5 I Hoak new o mn. Permit Number: 16WE 0773 AIRS ID Number: 123 / 9E9' /p2' [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. 4-17 -1") Signature of Lally Authorized Person (not a vendor or consultant) Date Cory G. Jordan EVP Operations Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ❑� Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with$152.90 to: Colorado Department of Public Health and Environment ! ° Air Pollution Cordrol Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: Make check payable to: https://www.colorado.gov/cdphe/apcd Colorado Department of Public Health and Environment Telephone: (303) 692-3150 Form APCD-200 - General APEN - Revision 1/2017 6 I COLORADO 9cpu..mcm ai Pahuc Fivlc>i bF .vaamnaM General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of specialty APENs is available on the Air Pollution Control Division (APCD) website at: www.colorado. gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 16WE0773 AIRS ID Number: IeZ.J /i£ / 622_ [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Discovery DJ Services LLC Site Name: Discovery Fort Lupton Plant Site Location: Section 11, Ti N, R66W Mailing Address: i a 7859 Walnut hill Lane, Suite 335 (Include Zip Code) S'3 Dallas, TX 75230 Portable Source Home Base: NI ;! Site Location County: Weld NAICS or SIC Code: 213112 Permit Contact: Manya Miller Phone Number: (214) 414-1980 E -Mail Address2: manya@discoverymidstream.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 APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 1/2017 38 COLORADO 1 I AV Hrill��bErev:.enmuni Permit Number: 16WE0773 AIRS ID Number: tL3 /9E99 / oil - [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ❑ NEW permit OR newly -reported emission source (check one below) ❑ STATIONARY source ❑ PORTABLE source -OR - ❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name ❑✓ Add point to existing permit ❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below) -OR - ❑ APEN submittal for update only (Blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) ❑ APEN submittal for permit exempt/grandfathered source Additional Info £t Notes: TEG Dehydrator Oxidizer 3 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 Oxidizer to control VOC and HAPs for TEG Dehydrator(Primary control for Regenerator Gas and Flash Gas) Manufacturer: TBD Model No.: TBD Serial No.: TBD Company equipment Identrication No. (optional): C2 p .L For existing sources, oper`a'tion began on: For new or reconstructed sources, the projected start-up date is: 01-01-2018 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 1/2017 days/week weeks/year Jun -Aug: Sep -Nov: RP', COLORADO 2 I ===„ Permit Number: 16WE0773 AIRS ID Number: [Leave blank unless APCD has already assigned a permit 11 and AIRS ID] as 11611 I Du_ Section 4 - Processing/Manufacturing Information Et Material Use 0 Check box if this information is not applicable to source or process From what year is the actual annual amount? Description Design Process Rate (Specify Units) Actual Annual Amount (Specify Units) Requested Annual Permit Limit4 (Specify Units) Material Consumption: Finished Product(s): 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) N 1266987.86 E 3211856.99. ❑ 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. Operator Stack ID No Discharge Height : Above Ground Level _ (Feety Temp. r F) ` Flow Rate (ACFM) Velocity (ft/sec) C2 ..,TBD TBD TBD TBD ti Indicate the direction of tf.i stack outlet: (check one) 0 Upward s ❑ Downward 0 Horizontal ❑ Other (describe): Indicate the stack opening and size: (check one) ❑ Upward with obstructing raincap 0 Circular Interior stack diameter (inches): TBD ❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches): ❑ Other (describe): Form APCD-200 - General APEN - Revision 1/2017 N COLORADO 3 m bepartna..ofPuaa Rg,at Y b£r:w.toeunertn Permit Number: 16WE0773 AIRS ID Number: 123 19O11 DZL [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment Et Fuel Consumption Information 2 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 Limit4 (Specify Units) 4.86 From what year is the actual annual fuel use data? \A-2, v -"Scq ✓ 11/ Indicate the type of fuel used5: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content: E Other (describe): TEG Vapors Heating value (give units): 405 Btu/scf 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ❑ Yes ❑✓ No ti:. If yes, describe the contrcit:equipment AND state the overall control efficiency (% reduction): Pollutant Contliol Equipment Description c,; Overall Collection Efficiency Overall Control Efficiency (96 reduction in emissions) TSP (PM) F;y PM10 c: r�7 PM2.s a SOX NOx CO VOC Other: Form APCD-200 - General APEN - Revision 1/2017 4 I AVCOLORADO vaiIth Erty o ' TSP (PM) Permit Number: 1 6WEQ773 AIRS ID Number: ( /1E91/ OZZ [Leave blank unless APCD has already assigned a permit / and AIRS ID] Section 7 (continued) From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions Requested Annual Permit Emission Limit(s)4 Uncontrolled (Tons/year) Controlled (Tons/year) Uncontrolled (Tons/year) Controlled (Tons/year), PM10 PM2.5 SOX NOX CO VOC 55.'if 9 i` 41,,iycf tSS•gy"��msc� TNRCC 3l,gaLmxf TNRCC 2.97 5.93 2.97 5.93 Other: a Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. '91041 cs a c c c.. c �. t -F S li f 1* -f, Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 lbs/year? as If yes, use the following :table to report the non -criteria pollutant (HAP) emissions from source: ❑ Yes ❑✓ No CAS Number 8 I.'.i Chemical( s Name ,: ,i ` Overall Control Efficiency Uncontrolled ` Emission Factor (specify units) Emission Factor Source (AP -42 , Mfg. etc) Uncontrolled Actual Emissions (lbs/year) Controlled Actual Emissions 6 (lbs/year) Gtr 4..4 6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-200 - General APEN - Revision 1/2017 �,l ,COLORADO 5 I Haut EFnvnonman� Permit Number: 16WE0773 AIRS ID Number: [Leave blank unless APCD has already assigned a permit # and AIRS ID] 12.3 /9E-11/ 022 - Section 9 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. 9741- Y Le ill ��YYYY a -17-17 Signature of g y Authorized Person (not a vendor or consultant) Date Cory G. Jordan EVP Operations Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ❑� Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $152.90 to: 4. .1 u iti Colorado Depa'rtnent of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: Make check payable to: https://www.colorado.gov/cdphe/apcd Colorado Department of Public Health and Environment Telephone: (303) 692-3150 Form APCD-200 - General APEN - Revision 1/2017 'COLORADO 6 I bear L.u-. cf glLUc HaNN 6Envlonmun� iCcavic). 1O 1 tic[►1 Hydrocarbon Liquid Loading APEN - Form APCD-208 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out. incorrectly or is missing information and requires re -submittal. This APEN is to be used for Hydrocarbon Liquid Loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source. In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of alt available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/aped. 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: 16WE0773 AIRS ID Number: in / I ec19 f o2� (Leave blank unless APCD has already assigneda permit # and AIRS ID] Company equipment Identification: LT [Provide -Facility Equipment ID to identify how this equipment is referenced within your Organization] Section 1 - Administrative Information Company Name': Discovery DJ Services LLC Site Name: Discovery Fort Lupton Plant Site Location: Section 11, T1 N, R66W Mailing Address: (include Zip Code) 7859 Walnut Hill Lane, Suite 335 Dallas, TX 75230 E -Mail Address2: manya@discoverymidstream.com Site Location County: Weld NAICS or SIC Code: 213112 Permit Contact: Manye Miller Phone Number: (214) 414-1980 'Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issuedby the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Rev 02/2017 3(01X1 COLORADO xtyic i7ik Permit Number: 16W E0773 AIRS ID Number; X7 /9c1 / d2�{ [Leave blank unless APCD has already assigned a permit = and AIRS ID? l Section 2- Requested Action DI NEW permit OR newly -reported emission source O Request coverage under construction permit O Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $250 must be submitted along with the APEN Filing fee. -OR- El MODIFICATION. to existing permit (check each box below that applies) O Change fuel or equipment O Change company name O Change permit limit O Transfer of ownership3 0 Other (describe below) - OR • APEN submittal for update only (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: Plant #2. Loadout of stabilized condensate and slop associated with 3 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: pipeline outages from Plant #2. Loadout of stabilized condensate and slop during For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: 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? Does this source load gasoline into transport vehicles? / / 08/ 01 /201.8 is this sourcelocated at an oil and gas exploration and production site? If yes:. Does this source load less than 10,000 gallons of crude oil per day on an annual average? Does this source splash fill less than. 6750 BBL of condensate per year? Does this source submerge fill less than 16308 BBL of condensate per year? Form APCD-.203 -Hydrocarbon Liquid Loading APEN - Rev 0212017 O Yes ❑ No ❑ Yes O No ❑ Yes 0 No ❑ Yes ❑Q No ❑ Yes ❑ No ❑ Yes O No ❑ Yes O No COLORADO 2 I AV „`.'.u„".t,ir,c N Zagemmnem Permit Number: 1.6WE0773 AIRS ID Number: 11.3 19591/ p2,,' -I [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: El Condensate ❑ Crude Oil I] Other: slop (50% condensate/50% water) and NGL if this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded4: 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth Condeneale{65,)00);SI p(98,$0) Bbl/yr Actual Volume Loaded: Bbl/yr This product is loaded from tanks at this facility into: (eg, "rail tank cars" or "tank trucks") tank trucks If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor Average temperature of bulk liquid loading: ,F. True Vapor Pressure Psia @ 60 °F Molecular weight of displaced vapors Lb/lb mol If this APEN is being filed for vapors displaced from pressurized loading tines, complete the following: Requested Volume Loadeds: Bbl/yr Actual Volume Loaded: B.bl/yr 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth Product Density: Load Line Volume: Lb/ft3 ft3/truckload Vapor Recovery Line Volume ft3/truckload Form APCD-208 -Hydrocarbon Liquid Loading APEN - Rev 02/2017 co 1.0 ADO 3I .. • r mP�.n: Permit Number: 16WE0773 AIRS ID Number: 'TM 52-9 [Leave Plank unless,ApCD has already assigned a permit ,And AIRS ID] Section 5 - Geographical Information Geographical Coordinates (Latitude/Longitude or UM) N 1267471.25 E3212342.92 Operator Slack ID No Discharge Height Above Ground Level {Feet) Temp ( • F} Flow Rate (ACFM) Velocity (ftfsec) Tanks Combustor Indicate the direction of the stack outlet: (check one) Upward ❑ Horizontal ❑ Downward ❑ Other (describe): Indicate the stack opening and size: (check one) ❑Q Circular Interior stack diameter (inches): O Other (describe): O Upward with obstructing raincap Section 6 - Control Device Information ❑ Loading occurs using a vapor balance system: Requested Control Efficiency ❑ Combustion Device: Pollutants Controlled: VOC and HAPs from Loading Operations (Plant #2) Rating: 10.0 Type: Combustor Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: MMBtu/hr Make/Model: TBD 98 98 Waste Gas Heat Content Constant Pilot Light: 0 Yes ❑ No Pilot burner Rating Btu/scf 0.06 MMBtu/hr Other: Pollutants Controlled: Description: Control Efficiency Requested 0 0. Form APCD-208 -Hydrocarbon Liquid Loading APEN - ,Rev 02/2017 -COLORADO 4 1 Ay uV...F...,,. N�_� 6 Cn'a:��neimi PM Permit Number: 16WE0773 AIRS ID Number: 173 /7E91 1 02.4 [Leave blank unless APCD has already assigned a permitµ and AIRS ID] Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? 0 Yes 0 No If yes, describe the control equipment AND state the overall control efficiency (% reduction): Pollutant Control Equipment Description Overall Requested Control Efficiency (% reduction in emissions) PM SOx NOx CO VOC Tanks Combustor to control VOC emissions during condensate and slop loadout from Plant #2 98 HAPs Tanks Combustor to control HAP emissions during condensate and slop loadout from Plant #2 98 Other: 1=1 Using State Emission Factors (Required for GP07) V0C ® Condensate ❑ Crude 0.236 Lbs/BBL 0.104 Lbs/BBL Benzene n -Hexane 0.00041 Lbs/BBL 0.0036 Lbs/BBL 0.00018 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Uncontrolled Emission Factor:! Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Uncontrolled (Tons/year) Controlleds (Tons/year) Uncontrolled (Tonsyear) • Controlled (Tons/year) Sax NO,, VOC 0.236 .lb/BBL CDPHE 19.42 0.39 CO Benzene 0.00041 lb/BBL CDPHE 0.034 0.001 Toluene Ethylbenzene Xylenes n -Hexane 0.0036 lb/BBL DCPHE 0.30 0.006 2,2,4- Trimethylpentane Other: 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 -Hydrocarbon Liquid. Loading APEN - Rev 02/2017 COLORADO 5 1 kiloDeanrur�at::ue 1 Ncs._�&[nrnrnun� Permit Number: 16WE0773 AIRS ID Number: III /elf I pyLl [Leave blank unless APCD has already assigned a permit r and AIRS 'Dl Section 8 Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will beoperated in full compliance with each condition of the applicable General Permit. Signature of Lddally Authized Person (not a vendor or consultant) Date Cory G. Jordan EVP Operations Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ['Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing, time) Thisemission 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 inci ease, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, ILC. for revised APEN requirements. Send this form along with $152.90 and the General Permit registration fee of $250 as applicable to: Colorado Department of Public Health and Environment Ai: Pollution Control Division APCD-SS-a 1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment Telephone: (303) 692-3150 For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 Or visit the APCD website at: https: //www.colorado.gov/cdphe/apcd Form APCD 208 -Hydrocarbon Liquid Loading APEN - Rev 02/2017 61 AY COLORADO WAN +Fs+" .. .t Hello