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Home My WebLink About20190722.tiffOperating Permit Application LV1VitL1.Pirr . •-_ __-_ - Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Air Pollution Control Division FOR DETERMINING COMPLIANCE Rev 06-95 f.� All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: Flare 4. Unit identification code: Flare 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). El Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): ❑ Periodic Emission Monitoring Using Portable Monitors - Form 2000-502 Pollutant(s): ® Monitoring Control System Parameters or Operating Parameters of a Process - Form 2000-503 Pollutant(s): Pilot Flame Monitoring ❑ Monitoring Maintenance Procedures - Form 2000-504 Pollutant(s): ❑ Stack Testing - Form 2000-505 Pollutant(s): ❑ Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): ® Recordkeeping - Form 2000-507 Pollutant(s): Nitrogen Oxide, Carbon Monoxide, and Volatile Organic Compounds ® Other (please describe) - Form 2000-508 Pollutant(s): Opacity, Wet Gas Composition 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: February 1, 2018 and every 12 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: February 1, 2018 and every 6 months thereafter. (6 month maximum interval) NOTE: APPLICABLE BLE REQUIREMENT ITEM IR M ON FORM 2000-604 NEEDS TO BE SPE5 2019-0722 Operating rermu tppu,nuv.. Colorado Department of Public Health and Environment MONITORING CONTROL Air Pollution Control Division OPERATING PARAMETERS OF A PROCESS ;1� The monitoring of a control system parameter or a a ue and theemission rate of a partiess may be cular pollutantable as a t is establishedpliance in the formon ofac urveprovlof em ss on a a rate versuson between the paraea v rate versus parameter values. Ideally stack test data that bracket the emission limit, if possible, could be used to define the emission curve. This correlation shall constitute the certification of the system. It should be attached for Division approval. If it is not attached, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: Flare 4. Unit identification code: Flare 5. Pollutant(s) being monitored: 6. Name of manufacturer: John Zink 7. Model number: Kaldair P-684 8. Is this an existing system? ® Yes ❑ No 10. Describe the method of monitoring: The pilot light is visually checked daily. A flame detector continuously monitors the pilot light. In case a flame is not detected, the pilot is automatically relit with an auto -igniter. 9. Reserved for future use 11. Backup system: None 12. Quality Assurance/Quality Control: Any monitoring system used with the record keeping shall be subject to appropriate performance specifications, calibration requirements and quality assurance procedures. ❑ A quality assurance/quality control plan for the monitoring system is attached for Division review. ❑ The plan is not attached, but will be submitted to the Division by icular er of continuous for e ose of e. The applicanteem sio propose aDivision appropriate move theproposedl.e., a aver averaging period, or other period which othe)Division determines defining excess emissions. The may pp to be appropriate. Provide the proposed averaging period(s) below. Averaging Period Parameter ***** ***** Operating Permit Application BY �CORDEPING Key �O-7� ' e, Colorado Department of Public Health and Environment , Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value D recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be"J attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing 2. Facility identification code: CO 123-0049 Plant 4. Unit identification code: Flare 3. Stack identification code: Flare • 5. Pollutant(s) being monitored: NOW, CO, & VOC 6. Material or parameter being monitored and recorded: Waste gas volume 7. Method of monitoring and recording (see information on back of this page): A flare meter will be used to determine total amount of waste gas to the flare. 8. List any EPA methods used: None 9. Is this an existing method of demonstrating compliance? ❑Yes ®No 11. Backup system: NA 10. Start date: 12 a. Data collection frequency: ❑ Daily ❑ Weekly ® Monthly ❑ Batch (not to exceed monthly) ® Other — Annually The volume of waste gas flared is metered and monitored monthly. An extended gas analysis will be pulled annually. 12 b. Compliance shall be demonstrated: ® Daily D Weekly ® Other — specify ❑ Batch (not to exceed monthly) ❑ P fy The pilot light is visually checked daily. Opacity is visually checked daily. Emission calculations will be updated monthly. 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ❑ A quality assurance/quality control plan for the recordkeeping system is attached for Division review. ❑ The plan is not attached, but will be submitted to the Division by DCP currently conducts recordkeeping associated with this facility. DCP uses an internal data base to ensure the recordkeeping is being conducted on the proper frequency and that the correct information is being gathered. 14. ❑ A proposed format for the compliance certification report and excess emission report is attached. DCP currently submits compliance certification reports and excess emission reports to the Colorado Air Pollution Control Division as required. The format for these submittals can be found in the previous submittals from DCP. The compliance records shall be available for Division inspection. The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Colorado Department of Public Health and Environment BY OTHER METHODS Rev U6-9 Air Pollution Control Division 1. Facility Name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: Flare 4. Unit Identification code: Flare 5. Pollutant(s) or Parameter(s) being monitored: Opacity of effluent 6. Description of the method of monitoring: Opacity is visually checked daily. A Method 22 reading is completed consistent with 40 CFR 60.18. An initial extended wet gas analysis (EGA) will be conducted, and emission factors for criteria and HAP pollutants will be determined 7. Compliance shall be demonstrated: (Specify the frequency with which compliance will be demonstrated) Opacity — Initial EPA Method 22 test, Daily visual checks EGA — Annual EGA's of the waste gas to this flare will be conducted, with emission factors verified against the permit limits. Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 09-94 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: Flare 4. Unit identification code: Flare 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached ® - Please see Attachment D Air pollutant Actual Potential to emit Maximum allowable Quantity U TPY Quantity U TPY Quantity U TPY Particulates (TSP) PM -10 Nitrogen oxides 0.068 2 1.55 Volatile organic compounds 531.06 7 9.50 Carbon monoxide 0.31 2 6.84 Lead 0.6 7 0.01 Sulfur dioxide Total reduced sulfur Reduced sulfur compounds Hydrogen sulfide Sulfuric Acid Mist Fluorides Units (U) should be entered as follows: 1 = lb/hr 2 = lb/mmBTU 3 = grains/dscf 4 = lb/ gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other (specify) 9 = other (specify) 10 = other (specify) Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE STATUS OF EMISSION UNIT 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: Flare 4. Unit identification code: Flare 5. Pollutant 6. Colorado Air Quality Regulations or Construction Permit Number 7. State Only 8. Limitation 9. Compliance Status IN OUT 10. Other requirements (e.g., malfunction reporting, special operating conditions from an existing permit such as material usage, hours of operation, etc.) State Only Compliance Status IN OUT A construction permit has not yet been issued for this source. Please refer to Attachment E for a list of suggested permit conditions, and proposed compliance methods. These are based on conditions in Construction Permit 15WE0939.CP1, issued 5/16/2016 for DCP's Greeley Gas Plant facility. *Unit has not yet operated for twelve months following modification. **** USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** Rev 06-95 3 rII uperaung rermit Application JUr'r'LCIVIGV I AL IIV r tJruviH I IUIV Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE r'VrUVI LUUU-1 VU 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. This form supplements Form 2000 - 604 for Emission Unit (e.g. B001, P001, etc.) Flare Permit Limitation Compliance Methods A construction permit has not yet been issued for this source. Please refer to Attachment E for a list of suggested permit conditions, and proposed compliance methods. These are based on conditions in Construction Permit 15WE0939.CP1, issued 5/16/2016 for DCP's Greeley Gas Plant facility. Operating Permit Application Colorado Department of Public Health and Environment Air Pollution Control Division STACK IDENTIFICATION FORM 2000-200 Rev 06-95 SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: P025 3a. Construction Permit Number: 10WE1659.CP5 4. Exhausting Unit(s), use Unit identification code from appropriate Form(s) 2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 2000-301 2000-304 2000-305 2000-302 2000-306 P025 2000-303 2000-307 5. Stack identified on the plot plan required on Form 2000-101 ❑ 6. Indicate by checking: ❑ This stack has an actual exhaust point. The parameters are entered in Items 7-13. ® This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. D When stack height Good Engineering Practice (GEP) exceeds 65 meters (Colorado Air Quality Reg 3.A.VIII.D) data entry is required for Item 7. Discharge height above ground level: _`(feet) 8. Inside dimensions at outlet (check one and complete): ❑ Circular _(feet) ❑ Rectangular Exhaust flow rate: length (feet) width (feet) Normal (ACFM) 11. Does process modify ambient air moisture content? IDYes If "Yes", exhaust gas moisture content: Normal w percent 12. Exhaust gas discharge direction: C:IUp Down 13. Is this stack equipped with a rainhat or any obstruction to the free flow of the exhaust gases from the stack? ❑ Yes ❑ No 10.Exhaust gas temperature (normal): "Ambient (°F Horizontal *****Complete the appropriate Air Permit Application Forms(s) 2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. Operating Permit Application MISCELLANEOUS PROCESSES Colorado Department of Public Health and Environment Air Pollution Control Division FORM 2000-306 Rev 06-95 SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 3.Stack identification code: P025 2. Facility identification code: CO 123-0049 4. Process (Unit) code: Fugitive Leak Emissions 5. Unit description: Fugitive component leaks from Roggen gas plant 6. Indicate the control technology status. ❑ Uncontrolled l Controlled (Using LDAR Controls) If the process is controlled, enter the control device code(s) from the appropriate form(s): 2000-400 LDAR 2000-401 2000-402 2000-403 2000-404 2000-405 2000-406 2000-407 Actual annual process rates 8. Date first placed in service: 1990 Date of last modification: Process Units RC modified Q2 2013, RP modified Q1 2015, RTF modified Q1 2015 9. Normal operating schedule: 24 hrs/day 7 days/wk. 8760 hours/yr. 10. Describe this process (please attach a flow diagram of the process). Attached? ❑ Fugitive emissions are from equipment leaks during normal operations, including leaks from flanges, connectors, valves, seals, and other equipment. 11. List the types and amounts of raw materials used in this process: _ Material N/A Storage/material handling process N/A Actual usage Units Maximum usage N/A Units N/A Clean-up solvents Other (specify) 12. List the types and amounts of finished products: Material Storage/material handling process Actual amount produced < Units Maximum amount produced Units N/A 13. Process fuel usage: Type of fuel Maximum heat input to process million BTU/hr. Actual usage Units Maximum usage Units N/A 14. Describe any fugitive emissions associated with this process, such as outdoor storage piles, unpave roads, open conveyors, etc.: Fugitive emissions are from equipment leaks during normal operations, including leaks from flanges, connectors, valves, seals, and other equipment. ***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 2000- 500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 and its attachment(s) to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. ***** Operating Permit Application Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE CONTROL EQUIPMENT - MISCELLANEOUS FORM 2000-400 Rev 06-95 1. Facility name: Roggen Natural Gas Processing Plants 3. Stack identification code: P025 2. Facility identification code: CO 123-0049 4. Unit identification code: Fugitive Leak Emissions 5. Control device code: LDAR Monitoring 6. Manufacturer and model number: N/A 7. Date placed in service: 1990 modified QI 2015, RTF modified Q1 2015 8. Describe the device being used. Attach a diagram of the system. For Process Units RC, RP, and RTF LDAR monitoring being implemented per 40 CFR 60, Subpart OOOO. Date of last modification: Process Units RC modified Q2 2013, RP All other Process Units subject to LDAR monitoring under 40 CFR 60, Subpart KKK. 9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below. 0 Documentation attached EITHER the outlet pollutant concentration OR the control efficiency must be provided. Pollutant Inlet pollutant concentration gr/acf Outlet pollutant concentration gr/acf ppmv Control Efficiency (%) VOC — Connectors 30% VOC — Flanges 30% VOC - Pump Seals 75% VOC — Valves 75% VOC — Other 75% 10. Discuss how the collected material will be handled for reuse or disposal. 11. Prepare a malfunction prevention and abatement plan for this pollution control system. The plan does not have to be submitted with the application. It is suggested the plan include, but not be limited to the following: Identification of the individual(s), by title, responsible for inspecting, maintaining and repairing this device. b. Operation variables such as temperature that will be monitored in order to detect a malfunction or breakthrough, the correct operating range of these variables, and a detailed description of monitoring or surveillance procedures that will be used to show compliance. c. What type of monitoring equipment will be provided (temperature sensors, pressure sensors, CEMs). d. An inspection schedule and items or conditions that will be inspected. f. Where is this plan available for review? NOTE: COMPLETION OF INFORMATION IN SHADED AREA OF THIS FORM IS OPTIONAL i5 9 ray Operating Permit Application COMPLIANCE CERTIFICATION - MONITORING AND REPORTING FORM 2000-500 Colorado Department of DESCRIPTION OF METHODS USED Rev 06-95 Public Health and Environment FOR DETERMINING COMPLIANCE Air Pollution Control Division All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Roggen Natural Gas Processing Plant 3. Stack identification code: P025 2. Facility identification code: CO 123-0049 4. Unit identification code: Fugitive Leak Emissions 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). ❑ Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): El Periodic Emission Monitoring Using Portable Monitors - Form 2000-502 Pollutant(s): VOC ❑ Monitoring Control System Parameters or Operating Parameters of a Process - Form 2000-503 Pollutant(s): Q Monitoring Maintenance Procedures - Form 2000-504 Pollutant(s): VOC ❑ Stack Testing - Form 2000-505 Pollutant(s): ❑ Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): Q Recordkeeping - Form 2000-507 Pollutant(s): VOC and HAPs ❑ Other (please describe) - Form 2000-508 Pollutant(s): 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: February 1, 2018 and every 12 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: February 1, 2018 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE DEMONSTRATION BY PERIODIC EMISSION FORM 2000-502 Colorado Department of MONITORING USING PORTABLE MONITORS Rev 06-95 Public Health and Environment Air Pollution Control Division The use of a portable continuous emission monitor (CEM) may be acceptable as a compliance demonstration method. A monitoring plan shall contain the following information: the name and address of the source; the source facility identification code; a general description of the process and the control equipment; the pollutant or diluent being monitored; the manufacturer, model number, and serial number of each portable monitor; the operating principles of each portable monitor; and a schematic of the CEM system showing the sample acquisition point and the location of the monitors while sampling. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2, Facility identification code: CO 123-0049 3. Stack identification code: P025 4. Unit identification code: Fugitive Leak Emissions 5. Pollutant(s) or diluent(s) being monitored: VOCs 6. Name of manufacturer: N/A Is this an existing system? Q Yes ❑ No 7.Model & serial number: N/A Q Other (specify) — Portable VOC detector 10. Type: ❑ In situ ❑ Extractive ❑ Dilution (using photoionization) 11. Very briefly explain the measurement design concept of the monitor: The applicable components at the Roggen Natural Gas Processing Plant will follow the leak detection and repair (LDAR) program as specified by NSPS OOOO. The monitoring required for all components subject to NSPS OOOO must be performed in accordance with 40 CFR 60, Appendix A, Method 21. Method 21 involves the use of a portable instrument to detect leaks of VOC. These instruments generally use the photoionization or flame ionization detection method. All other components will continue to be subject to the LDAR program specified by NSPS KKK. 12. Backup system: N/A 13. Compliance shall be demonstrated: ❑ Daily ❑ Weekly ❑ Monthly Q Other — specify: As mandated by NSPS OOOO and NSPS KKK 14. Quality Assurance/Quality Control: ❑ A quality assurance/quality control plan for the portable monitor is attached for Division review. ❑ The plan is not attached, but will be submitted to the Division by The instrument monitoring is done per Method 21 guidelines for calibration precision tests, response time tests, daily calibrations, and equipment and supply requirements. Any test value over the emission limit shall be reported as an excess emission. ***** Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-504 Colorado Department of Public Health and Environment MONITORING MAINTENANCE PROCEDURES Rev 06-95 Air Pollution Control Division The monitoring of a maintenance procedure may be acceptable as a compliance demonstration method provided a correlation between the procedure and the emission rate of a particular pollutant is established. VOC leak detection programs or fugitive dust control programs are examples of procedures that could be monitored. The correlation shall be established using test data. This correlation shall constitute the certification of the monitoring system. It should be attached for Division approval. If it is not attached, please submit it within 60 days of the startup of the monitoring program. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: P025 4. Unit identification code: Fugitive Leak Emissions 5. Pollutant(s) being monitored: VOCs and HAPs 6. Procedure being monitored: For Process units RF, RP, and RTF procedures outlined in NSPS Subpart OOOO 7. Is this an existing maintenance procedure? XYes ON 8. Implementation date: 8/18/2017 9. Describe the method of monitoring: For Process units RF, RP, and RTF LDAR monitoring program as outlined in NSPS Subpart OOOO. For all other Process Units, LDAR monitoring program as outlined in NSPS Subpart KICK. 10. Compliance shall be demonstrated: ❑ Daily ❑ Weekly 0 Monthly X Other — As required by NSPS OOOO and NSPS KKK. 11. Quality Assurance/Quality Control: The monitoring program shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ❑ A quality assurance/quality control plan for the monitoring program is attached for Division review. ❑ The plan is not attached, but will be submitted to the Division by ***** Any failure to fulfill a maintenance requirement shall be reported as an excess emission. ***** 1 3 . rn Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of BY RECORDKEEPING Rev 06-95 Public Health and Environment Air Pollution Control Division r Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: P025 4. Unit identification code: Fugitive Leak Emissions 5. Pollutant(s) being monitored: VOCs and HAPs 6. Material or parameter being monitored and recorded: Monthly and Annual Emissions (rolling 12 month total) Component Count Recordkeeping as specified under NSPS OOOO and KKK 7. Method of monitoring and recording (see information on back of this page): A record of all components is maintained. A plant inlet gas analysis is performed according to appropriate ASTM or EPA approved methods annually. The records of the component counts and gas analysis are recorded with the dates that these events took place. VOC and HAP emissions are calculated by multiplying the component count, the VOC/HAP percentages, the EPA emission factors, approved control efficiencies and operating hours per year. Recordkeeping information required by NSPS OOOO will be maintained on an internal LDAR Database and will updated frequently. Recordkeeping information required by NSPS KKK will continue to be maintained on DCP's internal database. 8. List any EPA methods used: Protocol for Equipment Leak Emission Estimates, EPA, November 1995, EPA - 453/R -95-017 9. Is this an existing method of demonstrating compliance? ❑ No X Yes 10. Start date: 8/18/2017 11. Backup system: N/A 12 a. Data collection frequency: ❑ Daily ❑ Weekly RI Monthly 12 b. Compliance shall be demonstrated: ❑ Daily ❑ Weekly B Monthly ❑ Batch (not to exceed monthly) ❑ Other — specify ❑ Batch (not to exceed monthly) ❑ Other — specify 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ❑ A quality assurance/quality control plan for the monitoring program is attached for Division review. ❑ The plan is not attached, but will be submitted to the Division by DCP Midstream currently conducts recordkeeping for the Roggen Natural Gas Processing Plant. DCP Midstream uses an internal database spreadsheet to record monitoring data, calculate emissions and maintain a 12 -month rolling total of pollutant emissions. 14. A proposed format for the compliance certification report and excess emission report is attached. DCP Midstream currently submits compliance certification reports and excess emissions reports to the Colorado Air Pollution Control for this facility as required. The format for these submittals can be found on previous submittals from DCP Midstream. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 3. Stack identification code: P025 FORM 2000-601 09-94 2. Facility identification code: CO 123-0049 4. Unit identification code: Fugitive Leak Emissions 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached l Air pollutant Actual Potential to emit Maximum allowable Quantity , U TPY U TPY U TPY Particulates (TSP) PM -10 Nitrogen oxides Volatile organic compounds Carbon monoxide Lead Sulfur dioxide Total reduced sulfur Reduced sulfur compounds Hydrogen sulfide Sulfuric Acid Mist Fluorides Valves Gas: 0.00992 Valves LL: 0.00551 Relief Valves Gas: 0.019401 Relief Valves LL: 0.016535 Compressor Seals: 0.019401 Pump Seals LL: 0.02866 Connectors Gas: 0.00044 Connectors LL: 0.016535 Flanges Gas: 0.00086 Flanges LL: 0.000243 1 33.5 Units (U) should be entered as follows: 1= lb/hr 2 = lb/mmBTU 3 = grains/dscf 4 = lb/ gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other (lb/month) 9 = other (specify) 10 = other (specify) Operating Permit Application Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE APPLICABLE REQUIREMENTS AND STATUS OF EMISSION UNIT FORM 2000-604, Rev 06-95 ii 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: P025 4. Unit identification code: Fugitive Leak Emissions 5. Pollutant 6. Colorado Air Quality Regulations or Construction Permit Number 7. State Only 8. Limitation 9. Compliance Status IN OUT Volatile Organic Compounds (VOC) 10WE1659.CP5 33.5 TPY X 10. Other requirements (e.g., malfunction reporting, special operating conditions from an existing permit such as material usage, hours of operation, etc.) State Only Compliance Status IN OUT Requirements of NSPS Subpart OOOO (Monitoring, Recordkeeping and Reporting) X Recordkeeping requirements (Emission calculations, component counts) X Complete an extended gas analysis annually and use for 12 month rolling emissions calculations X Requirements of NSPS Subpart KKK (Monitoring, Recordkeeping and Reporting) X **** USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** Operating Permit Application EMISSION UNIT COMPLIANCE PLAN Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE FORM 2000-606 09-94 1.Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: P025 4.Unit identification code: Fugitive Leak Emissions 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ❑ We will continue to operate and maintain this Unit in compliance with all applicable requirements. Q Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline 1. 2. 3. Progress reports will be submitted: Start date: and every six (6) months thereafter operating rermit Application Colorado Department of Public Health and Environment Air Pollution Control Division 09-94 r5 SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. This form supplements Form 2000 - 604 for Emission Unit (e.g. B001, P001, etc.) P025 Permit Limitation Compliance Methods Requirements of NSPS Subpart OOOO (Monitoring, Recordkeeping and Reporting) — Applicable Sources Recordkeeping requirements (Emission calculations, component counts) Complete an extended gas analysis annually and use for 12 month rolling emissions calculations Requirements of NSPS Subpart KICK (Monitoring, Recordkeeping and Reporting) — Applicable Sources VOC Emission Limitation Records and calculations in DCP compliance database Records and calculations in DCP compliance database Records and calculations in DCP compliance database, Initial extended wet gas analysis (EGA), Annual EGA Records and calculations in DCP compliance database Records and calculations in DCP compliance database, Initial extended wet gas analysis (EGA), Annual EGA Operating Permit Application YLANV1-WIDE riALAKUUUS AIK YULLu I An 13 Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE r v�ctvi cuuu-u;' Rev 06-95 l `uidl 1. Facility name: Roggen Gas Plant 2. Facility identification code: CO 123-0049 3. Complete the following emissions summary for all hazardous air emissions at this facility. Calculations attached. Attach a copy of all calculations to this form. X Attached — See Attachment D Pollutant CAS Common or Generic Pollutant Name Quantity Units Actual emissions Allowable Potential to e OR mit Quantity Units Total HAPs <25 TPY Individual HAP <10 TPY NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. 4 �ka Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Gas Plant 2. Facility identification code: CO 123-0049 09-94 3. Complete the following emissions summary for the listed emissions at this facility. Air pollutant Actual Potential to emit Maximum allowable TPY. TPY TPY Particulates (TSP) PM -10 10.6 10.6 Nitrogen oxides 217.6 217.6 Volatile organic compounds 246.8 246.8 Carbon monoxide 301.0 301.0 Lead Sulfur dioxide 30.4 30.4 Total reduced sulfur Reduced sulfur compounds Hydrogen sulfide Sulfuric acid mist Fluorides 5 Operating Permit Application Colorado Department of Health Air Pollution Control Division Facility Name: Roggen Gas Plant I. ADMINISTRATION TABULATION OF PERMIT APPLICATION FORMS FORM 2000-800 09-94 Facility Identification Code: CO 1230'(49 This application contains the following forms: X Form 2000-100, Facility Identification ❑ Form 2000-101, Facility Plot Plan X Forms 2000-102, -102A, Source and Site Descriptions II. EMISSIONS SOURCE DESCRIPTION Total Number of This Form This application contains the following forms (one form for each facility boiler, printing X Form 2000-200, Stack Identification 2 ❑ Form 2000-300, Boiler or Furnace Operation ❑ Form 2000-301, Storage Tanks ❑ Form 2000-302, Internal Combustion Engine ❑ Form 2000-303, Incineration ❑ Form 2000-304, Printing Operations ❑ Form 2000-305, Painting and Coating Operations X Form 2000-306, Miscellaneous Processes 2 ❑ Form 2000-307, Glycol Dehydration Unit III. AIR POLLUTION CONTROL SYSTEM Total Number of This Form This application contains the following forms: X Form 2000-400, Miscellaneous 2 ❑ Form 2000-401, Condensers ❑ Form 2000-402, Adsorbers ❑ Form 2000-403, Catalytic or Thermal Oxidation ❑ Form 2000-404, Cyclones/Settling Chambers ❑ Form 2000-405, Electrostatic Precipitators ❑ Form 2000-406, Wet Collection Systems ❑ Form 2000-407, Baghouses/Fabric Filters IV. COMPLIANCE Total Number DEMONSTRATION of This Form This application contains the following forms (one for each facility boiler, printing operation, X Form 2000-500, Compliance Certification - Monitoring and 2 Reporting ❑ Form 2000-501, Continuous Emission Monitoring X Form 2000-502, Periodic Emission Monitoring Using 1 Portable Monitors X Form 2000-503, Control System Parameters or Operation 1 Parameters of a Process X Form 2000-504, Monitoring Maintenance Procedures 1 ❑ Form 2000-505, Stack Testing ❑ Form 2000-506, Fuel Sampling and Analysis X Form 2000-507, Recordkeeping 2 X Form 2000-508, Other Methods 1 6 COMPLIANCE CERTIFICATION v of This Form This application contains the following forms quantifying emissions, certifying compliance with applicable requirements, and developing a compliance plan 0 Form 2000-600, Emission Unit Hazardous Air Pollutants X Form 2000-601, Emission Unit Criteria Air Pollutants 1 X Form 2000-602, Facility Hazardous Air Pollutants 1 X Form 2000-603, Facility Criteria Air Pollutants 1 X Form 2000-604, Applicable Requirements and Status of Emission Unit 2 0 Form 2000-605, Permit Shield Protection Identification X Form 2000-606, Emission Unit Compliance Plan - Commitments and Schedule 1 ❑ Form 2000-607, Plant -Wide Applicable Requirements ❑ Form 2000-608, Plant -Wide Compliance Plan - Commitments and Schedule 7 Attachment D Emission Calculations and Supporting Documentation Roggen Gas Plant J)I Roggen Emergency Flare Roggen Natural Gas Processing Plant DCP Operating Company, LP Source ID Description Manufacturer Model Serial* Manufacture Date Fuel Heat Value Pilot Flow Rate Heat Input Hours of Operation Potential Fuel Usage Destruction Efficiency Emissions from Pilot Pollutant CAS Number Emission Factor (Ib/MMscf) (lb/hr) (lb/yr) (ton/yr) Source of Emission Factor NOx 100 0.02 131.40 0,07 AP -42' CO 84 0.01 110.38 0.06 AP -42' VOC 5.5 8.25E-04 7.23 3.61E-03 AP -425 SO2 0.6 9.00E-05 0.79 3.94E-04 AP -42' PM 7.6 1.14E-03 9.99 0.00 AP -42` Total HAPs 7.36E-04 6.45 0.003 EPA AP -42, Volume I, Fifth Edition, July 1998, Table 1.4-1 o EPA AP -42, Volume I, Fifth Edition, July 1998, Table 1.4-2 3 EPA AP -42, Volume I, Fifth Edition, July 1998, Table 1.4-3 Emergency Flare Flare John Zink Kaldair P-684 NIA 1141 Btu/scf 150 scf/hr 0.17 MMBtu/hr 8760 hrtyr 1.31 MMscf/yr 95 % 3.150109589 Vents to Combustion Device Vent Stream Flow Rate (scf/hr) Operation (hr/yr) Flow Rate (MMscf/yr)' Heat Value (BIn/scf)3 Heat Rate (MMBtu/yr) Slowdowns to Flare (residue gas) 1922.10 8760 16.84 1141 19,206 Slowdowns to Flare (inlet gas) 1922.10 8760 16.84 1318 22,194 Purge Gas` 240.00 8760 2.10 1141 2,398 Total Waste/Purge Gas Flow Rate 4084.19 35.78 43,798 Flow rate volumes to flare for residue gas and inlet gas were estimated from total volume at FlowCal Meter Number 217111. Half was assumed to be residue gas and half was assumed to be inlet gas. Purge gas flow rate obtained from manufacturer specifications. 3 Heat value of purge gas is equal to residue gas heat value. Combustion Emissions Waste Gas Combustion Pilot Combustion' Total Emissions Emission Factor' Emissions Emissions Pollutant (lb/MMBtu) (lb/hr) (tpy) (Ib/hr) (tpy) . (tpy) NOx 0.068 0.32 1.49 0.02 0.07 1.55 CO 0.310 1.44 6.79 0.01 0.06 6.84 (Ib/MMscf) (lb/hr) (tpy) (lb/hr) (tpy) (roy) SO2 0.6 0.00 0.01 9.00E-05 3.94E-04 0.01 NOx and CO emission factor obtained from EPA AP -42 Section 13.5. Table 13.5-1 and 13.5-2 (April 2015). Fuel gas emissions reflect pilot gas combustion. 3 SO2 emission factor from EPA AP -42, Volume I, Fifth Edition, July 1998, Table 1.4-2. Roggen Residue Analysis - 91112017 N2 Carbon Dioxide Mol%a 0.247953 2.734480 MW 28 44 Component Mass 2 6.94 120.32 tat%. 0.350 6.072 Pure Component Heat Value (Btu/sof) 0 0 Component Fraction Heat Value (Btu/scf) 0.00 0.00 Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Hexane 80.477710 12.505624 3.392355 0228956 0.369930 0.023995 0.014997 0.002000 16 30 44 58 58 72 72 86 1287.64 375.17 149.26 13.28 21.46 1.73 1.08 0.17 65.147 18.974 7.548 0.671 1.085 0.087 0.055 0.008 1010.0 1769.6 2516.1 3251.9 3262.3 4000.9 4008.9 4755.9 812.82 221.30 85.36 7.45 12.07 0.9600 0.6012 0.0951 Total 1977.1 100.0 1140.6 MW of Gas a VOC Wt% 19.8 10.4 Mol%s for Residue gas values based on representative gas analysis performed on September 1st, 2017 'Component mass = Mol %x MW. a MW of Gas = Total Mass / 100 ° VOC Wt % calculated as sum of individual VOC components. Includes added buffer of 10% Waste Gas Flaring Emissions Specific Volume of Air Residue Waste Gas Uncontrolled' Residue Waste Gas Controlled' Inlet Waste Gas Uncontrolled' Inlet Waste Gas Controlled' Purge Gas Uncontrolled' Purge Gas Controlled' Pilot Combustion Total Controlled' Pollutant IVY) (tPY) (tPY) (tPY) (1Py) (tPY) (tPY) (tPYI VOC 45.67 2.28 138.63 6.93 5.70 0.29 3.61E-03 9.50 (Iblyr) (Iblyr) (Ib/yr) (Iblyr) (Ib/yr) (lb/yr) (Ib/yr) (lb/yr) n -Hexane 70.27 3.51 1948.54 97.43 8.77 0.44 6.15 101.38 Benzene — — 405.95 20.30 — — 0.00 20.30 Toluene — — 216.86 10.84 - - 0.00 10.84 Uncontrolled VOC (tpy) = Flared Volume IMMscf/vrl x MW oas lib/lb-mot x 1105 scf/MMscfl x VOC wt% Air Specific Volume [scf/lb-mog x 2000 lb/ton] Controlled emissions calculated using F-3 DRE of 95%: Controlled VOC (tpy) = Uncontrolled VOC (tpy) a (100-95)% ' Total emissions are the sum of controlled emissions from a) Slowdowns with residue gas composition b) Slowdowns with inlet gas composition c) Purge gas combustion and d) pilot combustion 379 scf/Ib-mol Roggen Gas Plant Inlet - 12 /312014 Constituent MW Helium 0.01 4 h12 0.4900 28 CO2 2.3900 44 H2s 0.0000 34 MeSH 0.0000 48 C1 70.4871 16 C2 14.3020 30 C3 7.6386 44 iC4 1.0162 58 nC4 2.6214 58 iC5 0.3917 72 nC5 0.3893 72 Cyclopentane 0.0180 70 nC6 0.0510 86 Cyclohexane 0.0119 84 nC7 0.0987 86 nC8 0.0318 114 Methylcyclohexane 0.0000 98 2,2,4-Trimethylpentan 0.0000 114 MeOH 0.0000 32 Benzene 0.0117 78 Toluene 0.0053 92 Ethylbenzene 0.0001 106 Xylenes 0.0006 106 CB+Heavies 0.0046 114 Component Mass° weinht % 0.04 13.72 105.16 0.00 0.00 1127.79 429.06 336.10 58.94 152.04 28.20 28.03 1.26 4.39 1.00 8.49 3.63 0.00 0.00 0.00 0.91 0.49 0.01 0.06 0.53 0.00174 0.5966 4.5725 0.0000 0.0000 49.0377 18.6560 14.6139 2.5628 6.6109 1.2263 1.2188 0.0549 0.1907 0.0435 0.3691 0.1576 0.0000 0.0000 0.0000 0.0397 0.0212 0.0005 0.0028 0.0228 Comoone nt Fraction Pure Component Heat Heat Value Value Bi twepn Btu/sc 0.00 0.00 0.00 0.00 0.00 10 0.0 711.92 17 9.6 253.09 25 6.1 192.19 32 1.9 33.05 32 2.3 85.52 40 0.9 15.67 40 8.9 15,61 37 3.9 0.68 47 5.9 2.43 44 1.5 0.53 47 5.9 4.69 55 2.5 1.75 52 5.7 0.00 62 1.7 0.00 0.00 37 1.8 0.44 44 5.0 0.24 5222.2 0.01 5208.8 0.03 6248.9 0.29 Total 100 2299,85 100 1318.12 MW of Gas' 23.00 VOC wt%` 27.14 Mol%s for Inlet gas values based on conservative gas analysis performed on 12/3/2014. 2 Component mass = Mol %x MW. ' MW of Gas = Total Mass / 100. ° VOC Wt % calculated as sum of individual VOC components. 303-637-0150 365 S. MAIN ST. BRIGHTON, CO 80601 EXTENDED NATURAL GAS ANALYSIS (*DHA) GLYCALC INFORMATION PROJECT NO. : 201412030 COMPANY NAME : DCP MIDSTREAM ACCOUNT NO. : BILLING CODE: G031 PRODUCER : LEASE NO. : NAME/DESCRIP : ROGGEN INLET 09:45 ***FIELD DATA*** SAMPLE PRES.: 874 VAPOR PRES. : COMMENTS : SPOT; NO PROBE Componet Helium Hydrogen Carbon Dioxide Nitrogen Methane Ethane Propane Isobutane n -Butane Isopentane n -Pentane Cyclopentane n -Hexane Cyclohexane Other Hexanes Heptanes Methycyclohexane 2,2,4 Trimethylpentane Benzene Toluene Ethylbenzene Xylenes C8+ Heavies Subtotal Oxygen/Argon Total ANALYSIS NO.: 03 ANALYSIS DATE: DECEMBER 5, 2014 SAMPLE DATE : DECEMBER 3, 2014 CYLINDER NO.: 0652 SAMPLED BY : SAM WOOD SAMPLE TEMP.: 76 AMBIENT TEMP.: GRAVITY . Mole % Wt 0.01 0.00 0.00 0.00 2.39 4.56 0.49 0.60 70.48710 49.04450 14.3020 18.6522 7.6386 14.6091 1.0162 2.5617 2.6214 6.6083 0.3917 1.2258 0.3893 1.2182 0.0180 0.0547 0.0510 0.1906 0.0119 0.0435 0.0987 0.3672 0.0318 0.1370 0.0000 0.0000 0.0000 0.0000 0.0117 0.0396 0.0053 0.0212 0.0001 0.0005 0.0006 0.0028 0.0046 0.0231 99.97000 99.96000 0.03 0.04 100.00000 100.00000 THE DATA PRESENTED HEREIN HAS BEEN ACQUIRED THROUGH JUDICIOUS APPLICATION OF CURRENT STATE -OF -THE ART ANALYTICAL TECHNIQUES. THE APPLICATIONS OF THIS INFORMATION IS THE RESPONSIBILITY OF THE USER. EMPACT ANALYTICAL SYSTEMS, INC. ASSUMES NO RESPONSIBILITY FOR ACCURACY OF THE REPORTED INFORMATION NOR ANY CONSEQUENCES OF ITS APPLICATION. SFL Matt Pickett DCP Midstream 3026 4th Avenue Greeley, CO 80631 Certificate of Analysis Number: 2500-17090001-001A Station Name: Roggen G.P. Sample Point: Fuel Gas Cylinder No: 1030-08310 Analyzed: 09/01/2017 12:38:25 by Andy Hartman Sampled By: Sample Of: Sample Date: Sample Conditions: Method: Analytical Data `71 Windsor Laboratory ,3 208 Main Street — Unit A li Windsor, CO 80550 m, ,ryll Sep. 01, 2017 Matt Pickett Gas Spot 09/01/2017 08:20 98 psig, @ 40 °F GPA 2286 Components Mol. % Wt. % GPM at 14.73 psia Oxygen 0.002000 0.003 Nitrogen 0.247953 0.350 Carbon Dioxide 2.734480 6.072 Methane 80.477710 65.147 Ethane 12.505624 18.974 Propane 3.392355 7.548 Iso-butane 0.228956 0.671 n -Butane 0.369930 1.085 Iso-pentane 0.023995 0.087 n -Pentane 0.014997 0.055 Hexanes Plus 0.002000 0.008 100.000000 100.000 3.354 0.937 0.075 0.117 0.009 0.005 0.001 4.498 GPM TOTAL C2+ GPM TOTAL C3+ GPM TOTAL iC5+ 4.498 1.144 0.015 Calculated Physical Properties Total Relative Density Real Gas 0.6861 Calculated Molecular Weight 19.82 Compressibility Factor 0.9970 GPA 2172-09 Calculation: Calculated Gross BTU per ft @ 14.73 psia & 60°F Real Gas Dry BTU 1147 Water Sat. Gas Base BTU 1127 As Delivered BTU 1145 Quality Assurance: C6+ 2.8820 83.47 4559 4479 NIL Hydrocarbon Laboratory Manager The above analyses are performed in accordance with ASTM, UOP, GPA guidelines for quality assurance, unless otherwise stated. Page 1 of 5 DCP Midstream, LP Roggen Natural Gas Processing Plant Fugitive VOC's Detail Sheet Source ID Number Equipment ID Source Description Source Usage Permit Status Potential Emissions P025 Fugitives N/A SCC Source Location Zone: Horizontal: Vertical: Potential operation 8760 hr/yr Pollutant Hrs of Operation (hrs/yr) Estimated Emissions Controlled Uncontrolled (Ib/hr) (tpy) (tpy) VOC 8760 7.659 33.54 114.07 Benzene Toluene Ethylbenzene Xylenes n -Hexane 8760 8760 8760 8760 8760 0.031 0.007 0.003 0.005 0.060 0.13 0.03 0.01 0.02 0.26 0.46 0.11 0.04 0,08 0.89 VOC Calculation Methodolo Equipment Type Emission Factor' (lb/hr/source) Source Count Percent VOC Hours of Operation Control Factor (Percent) Total HC Emission Rate (lb/hr) Total HC Emission Rate (tpy) Total VOC Emission Rate (tpy) Valves-GasNapor 0.009920 2706 29.85% 8760 75.00% 6.7109 29.39 8.77 Valves -Light Liquids 0.005510 2383 100.00% 8760 75,00% 3.2829 14.38 14.38 Relief Valves- Gas 0.019401 130 29.85% 8760 75.00% 0.6286 2.75 0.82 Relief Valves -Liquid 0.016535 40 100.00% 8760 75.00% 0.1637 0.72 0.72 Compressor Seals 0.019401 8 29.85% 8760 75.00% 0.0407 0.18 0.05 Pump Seals -Light Liquids 0.028660 31 100.00% 8760 75.00% 0.2235 0.98 0.98 Other - GasNapor 0.019401 0 29.85% 8760 75,00% 0.0000 0.00 0.00 Other - Light Liquids 0.016535 0 100.00% 8760 75.00% 0.0000 0.00 0.00 Open -Ended Lines 0.004410 0 29.85% 8760 75.00% , 0.0000 0.00 0.00 Connectors-GasNapor 0.000440 3610 29.85% 8760 30.00% 1.1118 4.87 1.45 Connectors -Light Liquids 0.000463 2987 100.00% 8760 30.00% 0.9680 4.24 4.24 Flanges-GasNapor 0.000860 1716 29.85% 8760 30.00% 1.0328 4.52 1.35 Flanges -Light Liquids 0.000243 1044 100.00% 8760 30.00% 0.1776 0.78 0.78 Totals 14.34 62.81 33.54 ' Emission Factors from EPA -453-R-95-017, Tablet -4 DCP Midstream, LP 5/712014 DCP Midstream, LP Roggen Natural Gas Processing Plant Fugitive VOC's Detail Sheet December 4, 2012 Gas Analysis Pollutant Molecular Weight (Ib/Ib-mol) Percentage of Volume (%) 70.3115% 14.3183% 84.6298% Gas Weight (lb%/1b-mol) Weight Corrected11) Percent Wt. Percent (%) (%) Methane Ethane Total NC (Non-VOC) Propane i-Butane n -Butane i-Pentane n -Pentane Hexane +12) Benzene Toluene Ethylbenzene Xylenes n -Hexane Glycols Alcohols Total NMNE VOC Carbon Dioxide Nitrogen H2S Total other sulfurs Helium 16.01 30.02 44.03 58.04 58.04 72.05 • 72.05 86.06 78.11 92.14 106.17 318.50 86.18 150.17 46.07 7.2169% 0.9864% 2.5319% 0.6438% 0.6626% 0.3400% 0.0605% 0.0121% 0.0040% 0.0025% 0.1074% 0.0010% 0.0001% 12.5692% 11.2569 48.25% 50.77% 4.2984 18.43% 19.39% 66.68% 70.15% 3.1776 13.62% 14.33% 0.5725 2.45% 2.58% 1.4695 6.30% 6.63% 0.4639 1.99% 2.09% 0.4774 2.05% 2.15% 0.2926 1.25% 1.32% 0.0473 0.20% 0.21% 0.0111 0.05% 0.05% 0.0042 0.02% 0.02% 0.0080 0.03% 0.04% 0.0926 0.40% 0.42% 0.0015 0.01% 0.01% O.0000 0.00% 0.00% 28.37% 29.85% 43.99 2.3900% 1.0514 4.51% N/A 28.02 0.3700% 0.1037 0.44% N/A 34.1 0.0000% 0.0000 0.00% N/A 34.1 0.0001% 0.0000 0.00% N/A 4.00 0.0100% 0.0004 0.00% N/A Totals 100.0% 23.3289 100.00% 100.00% 1'! Weight Fraction corrected to remove non -organic content. R! = C6 minus HAPs Total Component Count Actual Source Equipment Type I Count + 20% a Valves - Inlet Gas Valves - Liquid Relief Valves- Gas Relief Valves -Liquid Pump Seals - Liquid j. Connectors - Inlet Gas Connectors - Liquid 2987 Flanges - Inlet Gas j 1716 Flanges - Liquid € 1044 Other - Inlet Gas ; 0 (Other- Liquid l 0 Open -Ended Lines 0 Compressor Seals 4 8 T 2706 2383 130 40 31 3610 --- a December 2011 Component Count + 20% DCP Midstream, LP 4/16/2014 Attachment E Suggested Permit Requirements for Flare, including proposed compliance methods Roggen Gas Plant Suggested Conditions —Taken from Construction Permit 15WE0939.CP1, issued 5/16/2016 for DCP's Greeley Gas Plan facility Proposed Compliance Methods 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. DCP will submit a Notice of Startup Within one hundred and eighty days (180) of the latter of commencement of operation or issuance of this permit, compliance with the conditions contained in this permit shall be demonstrated to the Division. It is the owner or operator's responsibility to self -certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. DCP will submit a self -certification The operator shall complete all initial compliance testing and sampling as required in this permit and submit the results to the Division as part of the self - certification process. (Reference: Regulation No. 3, Part B, Section III.E.) DCP will submit a self -certification Emissions shall not exceed the following limitations for Flare Point TBD; 1.55 tpy NOx, 9.50 VOC, 6.84 CO. Records and calculations in DCP compliance database, Initial extended wet gas analysis (EGA), Annual EGA During the first twelve months of operation, compliance with both the monthly and annual limitations is required. After the first twelve months of operation, compliance with only the annual limitation is required. Records and calculations in DCP compliance database The Flare AIRS Point TBD shall be limited to 37.09 MMscf/yr and 3.15 MMscf/month natural gas volume. Records and calculations in DCP compliance database Compliance with the annual limits shall be determined on a twelve month rolling total. Records and calculations, in DCP compliance database The permit number and AIRS ID point number shall be marked on the subject equipment for ease of identification. Visual Inspection Visible emissions shall not exceed twenty percent opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed thirty percent opacity for more than 6 minutes in any sixty consecutive minutes. Emission control devices subject to Regulation 7, Sections XII.C.1.d or XVII.B.2.b shall have no visible emissions. Visual Inspection This flare shall comply with the New Source Performance Standards requirements of Subpart A Section 60.18, General Control Device and Work Practice Requirements. Recordkeeping, flare design specifications Upon issuance of this permit, the owner or operator shall follow the most recent operating and maintenance (O&M) plan and record keeping format approved by the Division, in order to demonstrate compliance on an ongoing basis with the requirements of this permit. Revisions to your O&M plan are subject to Division approval prior to implementation. Recordkeeping Point TBD: The operator shall complete an initial site specific extended gas analysis within one hundred and eighty days after commencement of operation or issuance of this permit, whichever comes later, of the natural gas vented from this emissions unit in order to verify the VOC, benzene, toluene, ethylbenzene, xylenes, n -hexane, and 2,2,4-trimethylpentane content (weight fraction) of this emission stream and using volume from the flare meter along with a 95% DRE to demonstrate compliance with emission limits. Results of testing shall be sued to calculate site -specific emission factors for the pollutants referenced above using Division approved methods. Results of site - specific sampling and emission factor analysis shall be submitted to the Division as part of the self - certification and demonstrate the emissions factors established in the permit application "Notes to Permit Records and calculations in DCP compliance database Holder" for this emissions point. If any site specific emissions factor developed through this sampling and analysis is greater than the emissions factor developed through this sampling and analysis is greater than the emissions factors established in the permit application and "Notes to Permit Holder" the operator shall submit to the Division withing 60 days, a request for permit modification to update emissions factors and emissions limits specified in this permit. Point TBD: The owner or operator shall demonstrate compliance with opacity standards using EPA Method Records in DCP compliance database 9 to measure opacity from the flare. �NI Attachment F Flare O&M Plan Roggen Gas Plant -P Midstream 01, Operating and Maintenance Plan DCP Midstream, LP Flare or Combustion Control Device This Operating and Maintenance Plan (O&M Plan) is developed for operating a flare or other combustion control device in the State of Colorado to satisfy the O&M Plan requirements of the Colorado Department of Public Health and Environment (CDPHE).Air Pollution Control District (APCD) construction permit application. Submittal Date: September 2017 Section 1— Source Identification Company Name: DCP Midstream, LP Facility Name: Roggen Natural Gas Processing Plant Manufacturer: John Zink (Kaldair P-684) Serial Number: Facility Location: Weld County Facility AIRS ID: 123/0049 Units Covered by this O&M Form Facility Equipment ID Flare Permit Number 95OPWE055 AIRS Point ID TBD Section 2 —Maintenance Schedule Facility shall follow individually developed maintenance practices and schedules for operation and maintenance of the equipment and control devices. These schedules and practices, as well as any maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Section 3 — Calculations The source will initially calculate emissions based on the methods and emission factors provided in the permit application and approved by the Division. The facility shall comply with the permitted emission limits. Section 4 — General Monitoring Requirements DCP will monitor and document proper operation of the control device. DCP will monitor the control device according to the parameters below: Pilot Light Monitoring The pilot light is visually checked daily. A flame detector continuously monitors the pilot light. In case a flame is not detected, the pilot is automatically relit with an auto -igniter. Opacity Monitoring Opacity is visually checked daily. A Method 22 reading is completed consistent with 40 CFR 60.18. Flare Gas Volume Monitoring The volume of waste gas flared is metered and is monitored monthly for compliance against permit limits. Section 5 — Recordkeeping Requirements Sources are required to maintain maintenance, monitoring and emission records for the requirements listed in Sections 2, 3 and 4 for a period of 5 years. �h� 1 i11 Attachment G Updated Facility Wide Emissions Inventory Form 102 Roggen Gas Plant Form APCD-102 Company Name: DCP Operating Company, LP Source Name: Roggen Gas Plant Source AIRS ID: 123/0049 Colorado Department of Public Health and Environment Air Pollution Control Division Facility Wide Emissions Inventory Form Ver. April, 2015 Uncontrolled Potential to Emit (PTE) Controlled Potential to Emit (PTE) Criteria (TPY) I HAPs (lbs/yr) •, Criteria (TPY) , • e , : , HAPs (Ibs/yr) . ' '3 •t` It t 0.61 t 0.61 0.02 84.98 t 02 85 61 11 6762.26 rMi 1.21 1.293176 t �� 166 100 35 14 227 t t t t t 21.24 365 t t Equipment Descri tion P 23/0049/101 Engine C-154/P001/S001 12 0 93t t t t 0.02 16.34 310 88 83 50 18 1 6 0 97 0 123/0049/102 t 123/0049/103 Engine C-155/P002/S002 Engine C-159/P003/S003 0.61 0.94 0.94 t 94 t 117.32 1.992t 1 t .. t •' t •' t t t t' 2738 478 tt t ' 16.34 310t tt ttt0: t. t t t t62.26 1.293 t Engine C-157/P007/S007 t t t 26.07 478 t• • t Engine C-161/P008/S008 Engine C-158/P010/S010 t t .. t • • t • • 104.29 t70.76 1,992t 1401 :t t •18.57 336 t0t t 193 t t. t. t t16.34 310 t t�•• t Engine C-160/P013/S013 t,t t t 62.26 1.293 t t 61 0.61 t 15.57 310 t 18 1 6 t 97 t En,' eC-156/P014/S014 t . KallEENIMEEMMUM t • t t 62.26 MERE 101.02 1.293 1.113 ®-MEIMMIENI-EMM t0 0 t 227 • 0 53 t tt t t1545 14.60 6.95 14.60 267 t 83 t 123/0049/115 En_ne C-223/P015/S015 61.64 276t t123/0049/119 Engine C t t t.54 • t , 10.04 104.28 1.149 . - was =mom' 0 267t123/0049/122 t tt 0123/0049/125 123/0049/117 -225/P017/5017 Engine C-227/P019/S019 t t t t t 0' ' ' 100.81 1.113 t1460 P025/FUGITIVES t t t t t t tit t t t t tt ' t0.00 0 t t t 0 t t t0.00 0 t 0 t t t t o t 0.00 0 t0:0 t t123/0049/126 P039. Stablized Condensate Tanks ttt t t t t ttt000 0 0 t 000 0•tt •c' t t123/0049/129 F029. Condensate Truck Loadout t tt t tt t tt t tt t tt000 0 t a , t El" t t t t t t t t t t t tt t• 2.90 5 t t t t t •t t123/0049/130 H037. Hot Oil Heater t t tt t t 2.90 5 t'. t t t t t ttt tt. t 0.17 0 t't t123/0049/133 P-033.RegenDeht' t tt t tt ttt ttt t t. t 0.17 0 t ttt3 0t t tt t t tt ; t F031. Pressurized Liquids Loadout t tl t tt ttt t t t t t t t 0.00 0 t ' • t• 1 t t 14 27 854 4970 0 155 t123/0049/134 Enl'ne C-181 t • : t • : t : t t 114.18 2.070t•t 0 0 0 5.298 5.153 254 1.066 5.997 0 0 995.54 0.00 0 0 0 78.042 75377 3 699 15.547 106.192 0 0 0.00 0.00 0.00 0.00 2.63 49.79 11.97 123/0049/136 123/0049/137 P-136. Inlet TEG Deh}' P-137. Amine Unit 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 282.96 0.00 0 0 0 50.789 33.225 1.074 287 6509 0 0 0.00 0.00 0.00 30.04 0.85 3.83 3.86 0 0 0 2.364 1564 51 287 34 0 0 0 0 505 0 0 1.07 1 07 1.07 0.08 7:02 0.65 11.79 0 0 0 0 0 0 0 505 0 0 123/0049/138 Hot Oil Heater 1.07 1.07 1.07 0.08 7.02 0.65 11.79 0 0 0 0 0 0.98 0.98 0.98 0.03 14.27 9.99 28.54 1 038 141 133 80 28 1 10 0 155 0 123/0049/140 Engine C-192 0.98 0.98 0.98 0.03 156.99 21.41 114.18 2.076 282 266 160 56 3 20 0 310 0 9.50 6.84 0 0 0 20 11 0 0 101 0 0 0.00 0.00 0.00 0.01 1.55 190.00 6.84 0 0 0 406 217 0 0 2.034 0 0 0.00 0.00 0.00 0.01 1.55 TBD APEN Only - Permit Flare Permitted Sources Subtotal = Exempt Sources - 10.60 10.60 10.60 0.40 1425.08 1891.02 1182.57 19,604 2,667 2,514 136,727 118,650 5,523 21,420 130,013 2,986 0 10.60 10.60 10.60 30.44 216.07 245.56 297.14 5,249 1,334 1,283 9,904 10,192 665 3,809 13,720 1,463 0 I I I I I I I I I I I f APEN Exempt / Insignificant APEN Only Subtotal = sources 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I 0 0 0 0 0 0 0 0 0 0 0.0 _ 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0 0 0 D 0 0 0 0 3.8 139 157 176 1.5 1.3 3.8 I 139 157 176 APEN Exempt / Insignificant sources 1.5 1.3 1 I -------- ----MOM_--_------ I I I I I 0 Insignificant Subtotal = Total, All Sources = 0.0 0.0 0.0 0.0 1.5 1.3. 3.8 I 0 0 0 139 0 0 0 157 176 0 0.0 0.0 0.0 0.0 1.5 1.3 3.8 . 0 0 0 139 0 0 0 157 176 3,809 13,877 1,638 0 0.4 1426.6 1892.3 1186.4 1 19,604 2,667 2,514 136,866 118,650 5,523 21,420 130,170 3,162 0 I 10.6 10.6 10.6 30.4 217.6 246.8 301.0 1 5,249 1,334 1,283 10,043 10,192 665 I 10.6 10.6 10.6 Uncontrolled HAPs Summary (TPY) Controlled Controlled HAPs Total, Summary (TPY) All HAPs (TPY) =I 2.6 I 0.7 I 0.6 I 5.0 I 5.1 I 0.3 I 1.9 I 6.9 I 0.8 I 0.0 =I 9.8 I 1.3 I 1.3 I 68.4 I 59.3 I 2.8 I 10.7 I 65.1 I 1.6 I 0.0 I = 24.0 ncontralled Total, All HAPs (TPY) Footnotes: 1. This form should be completed to include both existing sources and all proposed new or modifications to existing emissions sources 2. If the emissions source is new then enter "proposed" under the Permit No. and AIRS ID data columns 3. HAP abbreviations include: BZ = Benzene 224-TMP = 2,2,4-Trimethylpentane Tol = Toluene Acetal = Acetaldehyde EB = Ethylbenzene Acro = Acrolein Xyl = Xylene n -Hex = n -Hexane HCHO = Formaldehyde Meth = Methanol 4. APEN Exempt/Insignificant Sources should be included when warranted. 9/8/2017 Company Name Page 1 of 1 do Midstream September 21, 2017 Colorado Department of Public Health and Environment Air Pollution Control Division ATTN: Elie Shuchardt 4300 Cherry Creek Drive South Denver, CO 80246 RE: Roggen Natural Gas Processing Plant Operating Permit 95OPWE055 Updated APENs: 123/0049/130,123/0049/136, and 123/0049/137 DCP Operating Company, LP 370 17th Street, Suite 2500 Denver, CO 80202 (303) 605-2039 UPS: 1Z F46 915 02 9428 0798 Dear Ms. Shuchardt: Please find enclosed the requested updates for the following Roggen Natural Gas Processing Plant APENs: • Dehy P-033, AIRS ID: 123/0049/130 • Dehy P-136, AIRS ID: 123/0049/136 • Amine P-137, AIRS ID: 123/0049/137 These APENs capture the latest changes and current information for these units. If you have any questions or comments, please contact me at (303) 605-2039, or by email at rshankaran@dcpmidstream.com. Sincerely, DCP Opera g Company, LP Roshini Shankaran Environmental Engineer Enclosure /rmm 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 all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www Colorado aov/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 ayPSee Regulation No reportable ulat is ode 3, (significant Part A,IC eI.mSforrevisedAPEN requirements ions increase, increase production, new equipment, change in fuel type, etc). g Permit Number: 01WE0208 _ [Leave blank unless APCD has already assigned a permit # and AIRS ID] AIRS ID Number: 123 / 0049 / 130 Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Roggen Natural Gas Processing Plant Site Location: Section 24, R63W, T2N Mailing Address: 370 17th Street, Suite 2500 (Include Zip Code) Denver, CO 80202 E -Mail Address2: rshankaran@dcpmidstream.com Site Location County: Weld NAICS or SIC Code: 1311 Permit Contact: Roshini Shankaran Phone Number: 303-605-2039 1Please 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 9/2016 COLORADO ANNIIh6ffirt�o'vnenl Permit Number: 01WE0208 AIRS ID Number: 123 / 0049 / 130 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ❑ NEW permit OR newly -reported emission source - OR - Q MODIFICATION to existing permit (check each box below that applies) O Change fuel or equipment ❑ Change company name O Add point to existing permit 0 Change permit limit O 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: incorporate 2% enclosed combustor downtime 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: dehydration unit to regenerate the moleseive beds Facility equipment Identification: P-033 For existing sources, operation began on: For new or reconstructed sources, the projected / / start-up date is: 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day days/week weeks/year Will this equipment be operated in any NAAQS nonattainment 0 Yes O No area Is this unit located at a stationary source that is considered a ❑ Yes 0 No Major Source of (HAP) Emissions 1 /1 / 1976 Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 pg COLORADO 2 I m =�' H4NN 6 FawlrohmaN Permit Number: 01WE0208 AIRS ID Number: 123 10049 / 130 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Model Number: Manufacturer: Dehydrator Serial Number: Ethylene Glycol - Di Ethylene Glycol ❑✓ - TriEthylene Glycol Glycol Used: ❑ (EG) ❑ (DEG) (TEG) Glycol Pump Drive: ❑ Electric ❑✓ Gas If Gas, injection pump ratio: 0.08 Acfm/gpm # of pumps: 1 CuStoM Custom Reboiler Rating: n/a Custom Pump Make and Model: Custom MMBTU/hr Glycol Recirculation rate (gal/min): Lean Glycol Water Content: Max: 3.5 1.5 Wt.% Requested: 3.5 Dehydrator Gas Throughput: Design Capacity: 4.0 MMSCF/day Requested: 1,460 MMSCF/year Actual: 0 MMSCF/year Inlet Gas: Pressure: 850 Water Content: Wet Gas: Flash Tank: Pressure: 125 Cold Separator: Pressure: Stripping Gas: (check one) El None 0 Flash Gas 0 Dry Gas 0 Nitrogen Flow Rate: scfm psig lb/MMSCF psig psig Temperature: 0 Saturated Temperature: Temperature: 80 Dry gas: 90 °F 7.0 lb/MMSCF °F 0 NA °F NA Additional Required Information: ❑ Attach a Process Flow Diagram ❑ Attach GRI-GLYCaIc 4.0 Input Report Et Aggregate Report (or equivalent simulation report/test results) ❑ Attach the extended gas analysis (including BTEX Et n -Hexane, temperature, and pressure) Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 :COLORADO i==.N Permit Number: 01WE0208 [Leave blank unless APCD has already assigned a permit it and AIRS ID] AIRS ID Number: 123 /00491 130 Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.1177 / -104.3883 P-033 Indicate the direction of the stack outlet: (check one) Downward ❑ Other (describe): 0 Upward ❑ Horizontal Indicate the stack opening and size: (check one) Circular Interior stack diameter (inches): Square/rectangle Interior stack width (inches): Other (describe): elocf Us 0 Upward with obstructing raincap Interior stack depth (inches): Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 /f 07COLORADO , p�pypemedhiitie 4 I cj�. H..u„b�.�.n� Permit Number: 01WE0208 AIRS ID Number: 123 [0049/130 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information 0 Condenser: Used for control of: Type: Make/Model: Maximum Temp Average Temp Requested Control Efficiency % O VRU: Used for control of: Size: Make/Model: Requested Control Efficiency % VRU Downtime or Bypassed ❑ Combustion Device: Used for control of: Still vent stream* Rating: MMBtu / hr Make/Model: Type: enclosed combustor Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: 95 98 % John Zink Waste Gas Heat Content 569 Btu/scf Constant Pilot Light: 0 Yes 0 No Pilot burner Rating 0.05 MMBtu/hr Closed 0 Loop System: Used for control of: flash tank vent stream Description: stream routed to low pressure inlet System Downtime 0 % 0 Other: Used for control of: Description: Control Efficiency Requested 0/0 *ECD used for still vent control has 2% (175.2 hours) of annual downtime for maintenance and repairs. Still vent emissions will be vented to atmosphere during ECD downtime. Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 © COLORADO 5 AV= FUW 6f�1VIm91MR� Permit Number: 01WE0208 AIRS ID Number: 123 10049/130 [Leave blank unless APCD has already assigned a permit # and AIRS ID] PM PM 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? ✓� I Yes ❑ No If yes, please describe the control equipment AND state the overall control efficiency (% reduction): Overall Requested Control Efficiency (% reduction in emissions) Control Equipment Description SOX NO), CO VOC Enclosed Combustor 95% HAPs Other: Enclosed Combustor 95% From what year is the following reported actual annual emissions data? 2016 Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Emission Factor, Source (AP, -42, .. Mfg: 'etc) Uncontrolled Emission =_ Factor Emission Factor. Units . Uncontrolled • (Tons/year) _ U_ ncontrolled (Tons/year) Control) cI: (Tons/year) Controlled (Tonslyear)`, SOX NOx CO 0.068 b/M M Btu AP -42 0 0 0.06 0.06/0.0/0.06 VOC 0.31 134.5302 lb/MMBtu Ib/MMscf AP -42 GlyCalc 0 0 0 0 0.17 49.10 0.17/0.0/0.17 0/6/030/1.05 Benzene 4.6278 Ib/MMscf GlyCalc 0 0 1.69 0.11 Toluene 5.1516 lb/MMscf GlyCalc 0 0 1.88 Ethylbenzene Xylenes n -Hexane 0.1896 1.7076 1.5762 lb/MMscf Ib/MMscf Ib/MMscf GlyCalc GlyCalc GlyCalc 0 0 0 0 0 0 0.07 0.62 0.58 0.13 0.005 0.04 0.02 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. * Scenario 1 / Scenario 2 / Requested Permit Limit Scenario 1 Emissions = 100% still vent control via ECD Scenario 2 Emissions = Still vent to atmosphere limit during 2% ECD downtime Requested Permit Limits = 98% still vent control via ECD, 2% still vent to atmosphere Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 COLORADO 6I AV�,� Hg11FBLwlmnmW Permit Number: 01WE0208 AIRS ID Number: 123 / 0049/ 130 [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. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran crl2tw--4-- Date Environmental Engineer Name (please print) Title Check the appropriate box to request a copy of the: Q Engineer's Preliminary Analysis conducted El 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 $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 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 9/2016 7 I COLORADO Dcpummtd public Heath& E+vlmnment 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 all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.Rov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 10WE1659 AIRS ID Number: 123 / 0049 /136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 1 - Administrative Information Company Name': Site Name: Site Location: DCP Operating Company, LP Roggen Natural Gas Processing Plant Site Location Section 24, R63W, T2N County: Weld lu Address: p Code370 17th Street, Suite 2500 (Include Zip Code) Denver, CO 80202 E -Mail Address'-: rshankaran@dcpmidstream.com NAICS or SIC Code: 1311 Permit Contact: Roshini Shankaran Phone Number: 303-605-2039 '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 9/2016 COLORADO 1 I AT-fl.d�� N.eaq�E£nNwnn�N Permit Number: 10WE1659 AIRS ID Number: 123 / 0049 / 136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2- Requested Action ❑ NEW permit OR newly -reported emission source -OR - ,r❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment ❑ Change company name 0 Add point to existing permit • Change permit limit 0 Transfer of ownership3 ✓❑ Other (describe below) OR ❑ APEN submittal for update only (Please note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: incorporate 2% enclosed combustor downtime and 2% RTO downtime j 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: dehydration unit for water removal at the plant inlet Facility equipment Identification: P-136 For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: 7 /1 / 2011 / / 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 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 9/2016 0 0 days/week Yes Yes 0 0 weeks/year No No COLORADO AV 2 I `-" - Hw1eh 6 Ems * fl ni Permit Number: 10WE 1659 AIRS ID Number: 123 / 0049 / 136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Dehydrator Serial Number: Glycol Used: Evco Fabracation 2090 Ethylene Glycol (EG) Model Number: T-901 Reboiler Rating: n/a ❑ DiEthylene Glycol (DEG) Glycol Pump Drive:❑ Electric O Gas If Gas, injection pump ratio: Pump Make and Model: Glycol Recirculation rate (gal/min): Max: Lean Glycol Water Content: 1.5 MMBTU /hr ❑ TriEthylene Glycol s (TEG) # of pumps: Wt.% Requested: 24 Acfm/gpm 1 Dehydrator Gas Throughput: Design Capacity: 85 MMSCF/day Requested: 31,025 MMSCF/year Actual: 7,727.78 MMSCF/year Inlet Gas: Water Content: Flash Tank: Cold Separator: Pressure: 829.33 psig Temperature: Wet Gas: 97.96 lb/MMSCF O Saturated Pressure: 72.33 psig Temperature: Pressure: psig Temperature: Stripping Gas: (check one) p None O Flash Gas O Dry Gas O Nitrogen Flow Rate: scfm 116 Dry gas: °F 4 lb/MMSCF 128.5 °F O NA °F ❑✓ NA Additional Required Information: ❑ Attach a Process Flow Diagram ❑ Attach GRI-GLYCalc 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 9/2016 AV COLORADO 3 I AV�a N'W1N16 yrvpOMVM1I Permit Number: 10WE1659 AIRS ID Number: 123 /0049/136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.1177 / -104.3883 Ar , Opera'tor�FR a n, �r Stack ID No�� „ , Discha g Height �"�x Above Ground L vel (Feet) ₹� < , Temp fi. � (� ' R Flow _fate F 'c) eloci r P-136 Indicate the direction of the stack outlet: (check one) ❑✓ Upward ❑ Horizontal ❑ Downward O 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-202 -Glycol Dehydration Unit APEN - Revision 9/2016 4 I A© COLORADO ra d= Permit Number: 10WE1659 [Leave blank unless APCD has already assigned a permit # and AIRS ID] AIRS ID Number: 123 /0049/136 Section 6 - Control Device Information O Condenser: Used for control of: Type: Make/Model: Maximum Temp Average Temp Requested Control Efficiency ❑ VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed % ❑ Combustion Device: Used for control of: Still vent stream* Rating: Type: RTO/enclosed combustor Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: 1,450 MMBtu/hr hr Make/Model: 97/95 98 Anguil / John Zink Waste Gas Heat Content Constant Pilot Light: ❑✓ Yes ✓❑ No Pilot burner Rating 697 0.05 Btu/scf MMBtu/hr Closed p Loop System: Used for control of: flash tank vent stream Description: stream routed to low pressure inlet System Downtime 0 0 ❑✓ Other: Used for control of: Still vent stream Description: RTO no constant pilot; ECD has constant pilot Control Efficiency Requested 0/0 *ECD used for still vent control has 2% (175.2 hours) of annual downtime for maintenance and repairs. RTO used for still vent control has 2% (175.2 hours) of annual downtime for maintenance and repairs. Still vent emissions will be vented to atmosphere during ECD/RTO downtime. Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 COLORADO 5 1= 17°""'";„ Fnvlmnnnnl Permit Number: 10WE 1659 [Leave blank unless APCD has already assigned a permit # and AIRS ID] 123 /0049/136 AIRS ID Number: PM 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 O No If yes, please describe the control equipment AND state the overall control efficiency (% reduction):Overall Requested Control Efficiency (% reduction in emissions) SOX NO„ CO VOC HAPs Other: Control Equipment Description RTO / Enclosed Combustor RTO / Enclosed Combustor From what year is the following reported actual annual emissions data? 2016 Use the following table to report the criteria pollutant emissions from source: (Use the data reported in Sections 4 and 6 to calculate these emissions.) Emission Factor Source (AP -42, - Mfg. etc) PM SOx NO„ CO VOC Benzene Toluene Ethylbenzene Xylenes n -Hexane 2,2,4- Trimethylpentane Other: Methanol Uncontrolled Emission Factor 0.068 0.31 64.18 2.52 2.43 0.12 0.50 3.42 0.01 Emission Factor Units_: Ib/MMBtu L/MMBtu Ib/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf lb/MMscf AP -42 AP -42 ProMax ProMax ProMax ProMax ProMax ProMax ProMax . Uncontrolled (Tons/year).. Uncontrolled, (Tons%year) 0.14 0.75 40.90 1.56 0.56 0.00 0.00 1.47 16.40 Controlled5 ((Tons/yea- 0.14 0.75 0.59 0.05 0.02 0.00 0.00 0.04 0.49 97/95 97 / 95 2.6 12.0 995.54 39.02 37.69 1.85 7.77 53.10 0.22 Controlled (Tons/year);:;: 2.6/2.6/0.0/2.6 12.0/12.0/0.0/12.0 3608/21.65!14.43 / 49.79 2.65 2.58 0.13 0.53 3.00 0.02 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. * Scenario 1 / Scenario 2 / Scenario 3 / Requested Permit Limit Scenario 1 Emissions = 100% still vent control via ECD Scenario 2 Emissions = 100% still vent control via RTO Scenario 3 Emissions = Still vent to atmosphere limit during 2% ECD OR RTO downtime Requested Permit Limits = 98% still vent control via ECD, 2% still vent to atmosphere Form APCD-202 -Glycol Dehydration Unit APEN - Revision 9/2016 ANCOLORADO 6 I �N ..O;6E d. 4,uL99f.MIW,11114E1 Permit Number: 10WE1659 AIRS ID Number: 123 / 0049/136 [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. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran 61121120O - Date Environmental Engineer Name (please print) Title Check the appropriate box to request a copy of the: �✓ Engineer's Preliminary Analysis conducted 0 Draft permit prior to issuance Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) 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 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 9/2016 COLORADO 7 I AV n,,mo�rcdr.ati� Hp BEIWIIP tk Amine Sweetening Unit - Form APCD-206 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You maybe charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for Amine Sweetening Units only. If your emission unit does not fall into this category, there may be a more specific APEN 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 all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 10WE1659 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Company equipment Identification: P-137 [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] AIRS ID Number: 123 / 0049 / 137 Section 1 - Administrative Information Company Name': Site Name: Site Location: DCP Operating Company, LP Roggen Natural Gas Processing Plant Site Location Section 24, R63W, T2N County: Weld Mailing (include Address: de) 370 17th Street Suite 2500 (Include Zip Code) Denver, CO 80202 E -Mail Address': rshankaran@dcpmidstream.com NAICS or SIC Code: 1311 Permit Contact: Roshini Shankaran Phone Number: 303-605-2039 '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-206 - Amine Sweetening Unit APEN - Revision 04/2017 n COLORADO 1I • I o 5[m{1�6 EnNIOMarN Permit Number: 10WE1659 AIRS ID Number: 123 / 0049/ 137 [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 0 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 - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info & Notes: incorporate 2% RTO downtime 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: Amine unit for acid gas removal Facility equipment Identification: P-137 For existing sources, operation began on: 7 / 01 / 2011 For new or reconstructed sources, the projected start-up date is: / / El Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day Will this equipment be operated in any NAAQS nonattainment area Does this facility have a design capacity less than 2 long tons/day of H2S in the acid gas? Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 0 ❑✓ days/week Yes Yes 0 0 2IAV weeks/year No No COLORADO Llepseseelat Pub& NanII bEnmenvnvN Permit Number: 1 0WE1659 AIRS ID Number: 123 / 0049/ 137 [Leave blank unless APCD has already assigned a permit #r and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Evco Fabrication Model : Reboiler Rating: N/A Amine Type: Pump Make and Model: 0 MEA T-9002 Serial Number: 2082 MMBtu/hr Absorber Column Stages: 7 ❑ DEA 0 TEA stages ❑ MDEA 0 DGA # of pumps: 1 Sweet Gas Throughput4: Design Capacity: 85 MMSCF/day Requested: 31,025 MMSCF/year Actual: 0.0 MMSCF/year 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth Inlet Gas: Pressure: 847.33 psig Temperature: 86 °F Rich Amine Feed: Pressure: 839.33 psia Flowrate: 376 Gal/min Lean Amine Stream: Pressure: 266 psia Temperature: 131 Temperature: 252 Flowrate: 350 Gal/min Wt. % amine: 50 Mole loading H2S 1.23E-06 Mole Loading co, 0.0099 °F °F Sour Gas Input: Pressure: Flowrate: psia MMSCF/Day Temperature: °F NGL Input: Pressure: Flowrate: psia Gal/min Temperature: °F Flash Tank: 0 No Flash Tank Pressure: 60 psia Temperature: 1 33 °F Additional Required Information: Attach a Process Flow Diagram Attach the simulation model inputs a emission report Attach composition reports for the rich amine feed, sour gas feed, NGL feed, Et outlet stream (emissions) Attach the extended gas analysis (including BTEX Et n -Hexane, H2S, CO2, temperature, and pressure) Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 3j AVICOLORADO =Tr.= Permit Number: 10WE 1659 AIRS ID Number: 123 / 0049 / 137 [Leave blank unless APCD has already assigned a permit A' and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.1174 / -104.3883 Operator Stack ID No. Discharge Height .. Above Ground Level (Feet) Temp. (`F) Flow Rate (ACFM) Velocity (ftlsec) P-137 Indicate the direction of the stack outlet: (check one) 2 Upward 0 Horizontal ❑ Downward ❑ Other (describe): 0 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): 0 Other (describe): Form APCD-206 Amine Sweetening Unit APEN - Revision 04/2017 4iAV COLORADO Nea06tnumaimeN Permit Number: 10WE1659 AIRS ID Number: 123 / 0049/ 137 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information O VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed ❑ Combustion Device: Used for control of: Still Vent Stream* Rating: MMBtu/hr Type: RTO Make/Model: Anguil / Model 150 Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency 97 99 % Minimum Temperature: 1,450 Waste Gas Heat Content 29 Btu/scf Constant Pilot Light: ❑ Yes p No Pilot burner Rating MMBtu/hr ❑✓ Other: Used for control of: flash tank stream Description: closed loop system Control Efficiency 100 Requested % * RTO used for still vent control has 2% (175.2 hours) of annual downtime for maintenance and repairs. Still vent emissions will be vented to atmosphere during RTO downtime. Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 ® (Nu[NCOLORADO 5j b 5nwmiumrt Permit Number: 10WE1659 AIRS ID Number: 123 / 0049 / 137 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 -Emissions Inventory Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? 0 Yes 0 No • ction): AND the ........g.............•.-- • From what year is the following reported actual annual emissions data? 2016 Use the following table to report the criteria pollutant emissions from source: ons. Jse Lira UUIu i cpw LCU 111 .lCa.uvn+ -r u.... v ... --.--.--- ----- Criteria Pollutant Emissions Inventory Emission Requested Annual Permit Uncontrolled Emission Factor Actual Annual Emissions Emission Limit(s)4 Pollutant Emission Factor Factor Units Source (AP -42, Uncontrolled Controlled5 Uncontrolled Controlled Mfg. etc) (Tons/year) (Tons/year) (Tons/year) (Tons/year) PM SOX 1.88 ton SO2/ ton H2S Promax 0.0 0.0 30.0 no/a0/3ao H2S 0.82 lb/MMscf Promax 0.0 0.0 12.79 0.38 / 0.26 / 0.6 NOx 0.068 b/MMBtu AP -42 0.0 0.0 0.8 0.8 /0.0 /0.8 VOC 18.24 lb/MMscf Promax 0.0 0.0 282.96 2.32 / 1.55 / 3.83 CO 0.31 Ib/MMBtu AP -42 0.0 0.0 3.9 3.9 /0.0 /3.9 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth. AAnnual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. * Scenario 1 / Scenario 2 / Requested Permit Limit Scenario 1 Emissions = 100% still vent control via RTO Scenario 2 Emissions = Still vent to atmosphere limit during 2% RTO downtime Requested Permit Limits = 98% still vent control via RTO, 2% still vent to atmosphere * * Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 6I A COLORADO Ueprrtmanv al Albflc NUW. b Enetironmenl Permit Number: 10WE1659 AIRS ID Number: 123 / 0049/ 137 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 (continued) Non -Criteria Reportable Pollutant Emissions Inventory Pollutant Chemical Abstract Service (CAS) Number Uncontrolled Emission Factor Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions Uncontrolled (lbs/year) Controlled5 (lbs/year) Benzene 71432 1.64 Ib/MMscf AP -42 50,789.27 2,363.98 Toluene 108883 1.07 lb/MMscf AP -42 33,225.36 1,563.95 Ethylbenzene 100414 0.03 lb/MMscf AP -42 1,074.43 50.54 Xylenes 1330207 0.19 lb/MMscf AP -42 6,018.75 287.29 n -Hexane 110543 0.21 Ib/MMscf AP -42 6,508.94 33.92 2,2,4- Trimethylpentane 540841 Other: 5 Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true and correct. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Name (please print) °t (211Z01i- Date Environmental Engineer Title Check the appropriate box to request a copy of the: ✓❑ Draft permit prior to. issuance 0 Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) 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 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-206 - Amine Sweetening Unit ADEN - Revision 04/2017 7 I cLO !CORof,ADO teLo ttmmbs,..w.m.m A &Er -a Midstream November 9, 2017 DCP Midstream 370 17`" St., Suite 2500 Denver, CO 80202 (303) 605-2039 www.dcpmidstream.com UPS Tracking No. 1Z F46 915 02 9545 2547 Colorado Department of Public Health and Environment Air Pollution Control Division ATTN: Elie Schuchardt 4300 Cherry Creek Drive South Denver, CO 80246-1530 Re: Roggen Natural Gas Processing Plant Title V Modification: 95OPWE055 AIRS ID 123/0049 Dear Ms. Schuchardt: DCP Operating Company, LP ("DCP") is submitting the attached operating permit modification application for the Roggen Natural Gas Processing Plant ("Facility"), located at Section 24, Range 63W, Township 2N in Weld County, Colorado. This facility currently operates under Title V permit 95OPWE055 originally issued on May 1, 2001 and last revised on August 29, 2005, with an expiration date of May 1, 2006. A timely Title V permit renewal application was submitted in April 2005; however, a revised Title V permit has not yet been issued. Several construction permits have been issued since this date and DCP has subsequently requested that the revisions be rolled into the Title V permit for the facility. DCP received a draft Title V permit in May 2013 that incorporated all of the changes that were requested prior to 2013. The requested language changes and updated compliance assurance monitoring. (CAM) plans included in this modification application use the conditions in the 2013 draft Title V permit as a starting point. This modification application for permit 95OPWE055 requests changes to the control of emissions from inlet TEG natural gas dehydrator P-136, in addition to incorporating pieces of other recently submitted minor modification applications for this facility. The newly requested changes to P-136 are detailed immediately below and a review of recent permit actions, and the pieces of those actions that DCP wants to incorporate into this modification, are detailed in the "Additional Modifications" section below. Modifications to Control Device Downtime — P-136 (AIRS 136) The following is the regulatory history of P-136: Currently authorized under construction permit 10WE1659 Issuance 5 with the following description: P136 — AIRS Point 136 - One (1) TEG dehydration unit with a processing capacity of 85 MMscfd and glycol pump circulation rate of 24 gpm. Still vent emissions routed to an enclosed combustor (ECD) or the regenerative thermal oxidizer (RTO) with 97% control efficiency. • Title V draft permit (May 15, 2013) — Gas processing limit of 31,025 MMscf/yr, glycol pump circulation rate of 24 gpm, still vent control authorized to RTO with 97% destruction efficiency (DRE). • Construction Permit 10WE 1659 Issuance 5 (March 18, 2015) — Gas processing limit of 31,025 MMscf/yr, glycol pump circulation rate of 24 gpm, still vent control authorized to RTO or ECD with 97% DRE. • Title V modification application to roll in CP 10WE1659 Issuance 5 was submitted on March 17, 2016. o This modification requested three distinct operating scenarios for the control of emissions from units P-033, P-136, and P-137. ■ The current modification application requests: o Decrease control efficiency of ECD to 95%, while retaining control efficiency of RTO at 97%; o Update Promax model used to determine revised permit limits o Permit 2% annual downtime for ECD maintenance and malfunctions; o Ensure that P-136 will achieve a minimum of 95% overall system control to meet Regulation 7 Section XVII.D requirements. o Make the ECD the primary control device for still vent emissions. The RTO will serve as a backup control device when the amine unit P-137 is also online. Replace the three operating scenarios proposed in the March 17, 2016 Title V modification with the following: ■ Scenario 1: The amine unit (P-137) is out of service and bypassed while the inlet TEG dehydrator (P-136) and the regen gas TEG dehydrator (P-033) are in service. The emissions from the still vents from both dehydration units are routed to the ECD with a minimum control efficiency of 95% and an annual downtime of 2%. ■ Scenario 2: The amine unit (P-137), inlet dehy (P-136), and regen dehy (P-033) are all in service. Emissions from P-137 will be directed to the existing RTO with control efficiency of 97%. Emissions from P-136 may be directed to either the ECD or the RTO during this scenario. Emissions from P-033 will continue to be directed to only the ECD. o Permit limits and proposed language are included in Appendix E. ■ Permit limits were calculated based on Scenario 1 above, corresponding to full time operation of the ECD, with associated 2% annual downtime. This operating scenario gives the most conservative emissions estimate, due to the lower control efficiency of the ECD versus the RTO, in addition to the requested ECD downtime. As the RTO can only be used as a control device for P-136 when the amine unit P-137 is also online, DCP determined that emission limits based on full time use of the ECD were most conservative for this facility. o Revised O&M plan for P-136 / P-033 is included reflecting the proposed ECD changes o Revised CAM plans are included reflecting the proposed changes. DCP is requesting that the combined CAM plan for P-136 and the amine unit P-137 present in the 2013 draft Title V permit be split, with individual CAM plans for each unit. A redlined CAM plan for P-137 and a proposed CAM plan for P-136 have been included in Attachment G. Additional Modifications As a part of this modification application, DCP is requesting the indicated portions of the following previously submitted modifications be incorporated into the Title V permit: ■ 7/07/2017 - Title V Minor Modification Application: o Please proceed with this minor modification application for engines C-154, C-159, C- 161, C-156, C-225, C-227, and C-181 as submitted on 7/7/17 o Please proceed with the modifications requested for the regen dehy P-033 (AIRS 130). An updated Operating and Maintenance (O&M) plan for units P-136 and P-033 has been included in Attachment B of this application but there are no changes requested for P- 033. o Please cancel any request in this application for the TEG dehydrator P-136 (AIRS 136) and replace with this modification application. o The final part of this minor modification application included changes to the amine unit P-137 (AIRS 137) as well as proposed RTO downtime. DCP requests that these proposed changes be cancelled. The RTO will continue to operate with no annual downtime and unit P-137 will continue to operate as authorized under construction permit 1OWE1659 Issuance 5. ■ 7/28/2017 — Title V Minor Modification Application Addendum: o F029: Please proceed with this correction request for the condensate truck loadout. o P -137/P-136 & RTO: Please cancel this modification request. • 9/08/2017 — Title V Modification Addendum: o P025: Please proceed with processing this modification request. o FLARE: Please proceed with processing this modification request. • 9/21/2017 - Title V Minor Modification Application Correction: o Please cancel this modification request for P-033, P-136, and P-137. Regulatory Analysis Please see Attachment E for a regulatory analysis specific to the changes requested for unit P-136. The regulatory applicability for the changes incorporated from other minor modifications and addendum applications are discussed in those individual applications. The following is an analysis of the overall regulatory applicability pertaining to this project with regards to NA-NSR and PSD. Nonattainment New Source Review & Prevention of Significant Deterioration The federal New Source Review program applies to new or modified sources in both attainment and nonattainment areas that result in emission increases in excess of specified thresholds. Weld County is designated as nonattainment for ozone, so new sources in this area are potentially subject to NA-NSR if emissions of nitrogen oxides (NOx) or volatile organic compounds (VOCs) are in excess of 100 tons per year (tpy). The Roggen Natural Gas Processing Plant is a major source (potential emissions > 100 tpy) of both NOx and VOC and NA-NSR would be required if a proposed modification would result in both a project and net emissions increase of 40 tpy or more of either pollutant. Table 1— New Source Review Applicability Determination Baseline Actual Emissionsa'' Project Emission Changes AIRS ID Equipment Description NOx (tpy) VOC (tpy) CO (tpy) PM (tpy) NOx (tpy) VOC (tpy) CO (tpy) PM (tpy) 123/0049/130 P-033, Regen Dehy 0.00 0.51 0.00 - 0.06 0.54 9.17 - 123/0049/136 P-136, Inlet TEG Dehy 1.91 6.98 10.42 - 0.71 16.75 1.56 - TBD Emergency Flare - - - - 1.55 9.50 6.84 - Total Roggen Project Increases' 1.61 26.80 7.02 0.00 New Source Review Thresholds 40 40 100 10 Trigger New Source Review? X11 s `MOM Highest Individual HAP 5.61 tpy Total HAP 22.82 tpy Baseline actuals calculated in accordance with Colorado Regulation 3, Part D. The twenty-four month period selected for determining baseline actual emissions for all regulated NSR pollutants was September 2011 through August 2013. Only increases caused by this proposed project were considered when determining the Total Roggen Project Increases. The decreased NOx and CO combustion emissions for unit P-136 were not considered in this analysis, in accordance with Colorado Regulation 3, Part D. Th,e current proposed permitting action does not increase emissions of either pollutant by 40 tpy or more as indicated above in Table 1. This analysis was conducted by subtracting the baseline actual emissions calculated for each modified unit from their proposed respective potentials to emit in accordance with Part D of Colorado Regulation 3. Please see below for details on how the baseline actual emissions for these two units were determined. As the project emission increases are less than the significance levels of either NOx or VOCs, no netting analysis has been performed. Roggen is also an existing major source for PSD purposes due to emissions of NOx and CO exceeding 250 tpy. The emission increases in Table 1 indicate that the project does not trigger PSD review. The actions proposed in this Title V modification application are therefore considered a "minor modification," for PSD purposes, as defined in Part D of Colorado Regulation 3. Baseline Actual Emissions Baseline actual emissions were determined for all three units with proposed emission increases in this modification application. Both dehys, P-033 and P-136, are considered existing units and the following definition of "Baseline Actual Emissions" from Part D, Section II.A.4, of Colorado Regulation 3 applies: For an existing emissions unit (other than an electric utility steam generating unit), baseline actual emissions means the average rate, in tons per year, at which the emissions unit actually emitted the pollutant during any consecutive twenty-four month period selected by the owner or operator within the ten year period immediately preceding either the date the owner or operator begins actual construction of the project, or the date a complete permit application is received by the Division for a permit required under this Part D, except that the ten year period shall not include any period earlier than November 15, 1990. It is expected that the proposed changes in this modification application will be conducted in 2018, making 2008 the start of the 10- year period preceding this project. However, unit P-136 was not installed on site until July 2011. Because this project involves multiple emission units, analysis of the same consecutive 24 -month period is required for both P-033 and P-136. Because of this, the start of the normally 10 -year contemporaneous period is the startup date for P-136 for this project. A full table of actual emissions from both units, from July 2011 to the present, has been included in Attachment C of this application. As shown in this table, the 24 -month contemporaneous period chosen for analysis was September 2011 through August 2013 and was selected for both P-033 and P-136. DCP believes this 24 -month period gives the most representative baseline actual emissions for unit P-136. This same period was chosen for P-033, as required by Part D, Section II.A.4. of Colorado Regulation 3. There were emissions limit exceedances for either unit during this 24 -month period, which would require the actuals to be adjusted downwards. The final calculated baseline actual emission values for units P-033 and P-136 can be seen above in Table 1. The emergency flare is considered a new emission unit and the following definition of "Baseline Actual Emissions" from Part D, Section II.A.4. of Colorado Regulation 3 applies: For a new emissions unit, the baseline actual emissions for purposes of determining the emissions increase that will result from the initial construction and operation of such unit shall equal zero; and thereafter, for all other purposes, shall equal the unit's potential to emit (as defined in Section 13.37. of Part A of this regulation). Based on this definition, the full potential to emit for the emergency flare, as proposed in the modification application submitted 9/08/2017, was considered alongside the baseline actual emission values determined for units P-033 and P-136. In addition to the New Source Review applicability test discussed above, Condition 45 of construction permit 10WE1659 Issuance 5 states in part: Any relaxation that increases the potential to emit above the applicable NSR threshold will require a full NSR review of the source as though construction had not yet commenced on the source. As a result of this condition and at the request of CDPHE, the proposed permit limits for all pieces of equipment included in the construction permit after the requested modifications have been made were compared to New Source Review thresholds. The only piece of equipment whose permit limits will change due to this modification application that is authorized under construction permit l0WE1659 Issuance 5 is the inlet TEG dehy P-136. As shown below in Table 2, the emission increases proposed in this modification application, combined with the existing permit limitations already authorized under this construction permit, all remain below the applicable NSR thresholds. Therefore, the changes proposed in this modification application do not require further NSR review of the sources in construction permit 10WE1659 Issuance 5. Table 2 — Current and Proposed Construction Permit 10WE1659 Limitations Existing PermitLimits-Issuance 5' Proposed Permit Limitsb AIRS ID Equipment Description NOx (tpy) VOC (tpy) CO (tpy) PM (tpy) NOx (tpy) VOC (tpy) CO (tpy) PM (tpy) 123/0049/136 P-136, Inlet TEG Dehy 2.60 21.60 14.30 0.89 23,74 4.04 - 123/0049/137 P-137, Amine Unit 0.80 2.30 4.60 - 0.80 2.30 4.60 - 123/0049/138 30.7 MMBtu/hr Hot Oil Heater 7.00 0.70 11.80 - 7.00 0.70 11.80 - Total Roggen Project Increases 8.69 26.74 20.44 0.00 New Source Review Thresholds 40 40 100 10 Trigger New Source Review? O ;. wa _"; 0, Highest Individual HAP 5.61 tpy Total HAP 22.82 tpy Existing limits are from construction permit 10WE1659 Issuance 5 Issued March 18, 2015. °The proposed emission limits for P-136 include the reduction in ECD control efficiency, as well as the addition of a 2% annual downtime for the ECD used for periods of maitenance and malfunction. There are no changes proposed to the emission limits for either unit P-137 or the Hot Oil Heater in this modification application. Attachments The following attachments needed to make the requested changes to operating permit 95OPWE055 have been included: • Attachment A: Updated APENs for inlet TEG dehy P-136 and amine unit P-137 • Attachment B: Updated Operating and Maintenance (O&M) Plans for inlet TEG dehy P-136 / regen dehy P-033 and amine unit P-137 • Attachment C: Emission Calculation and Supporting Documentation for unit P-136 • Attachment D: Form APCD-102: Facility Emissions Inventory • Attachment E: Regulatory Analysis for changes to P-136 • Attachment F: RACT Requirements • Attachment G: Redlined Title V Compliance Assurance Monitoring (CAM) Plans If you have any questions or require any additional information about this submittal, please contact me at (303) 605-2039 or RShankaran@dcpmidstream.com. Sincerely, DCP Operating Company, LP Roshini Shankaran Environmental Engineer Attachment A: Updated APENs P-136 Inlet TEG Dehy, AIRS ID: 123/0049/136 P-137 Amine Unit, AIRS ID: 123/0049/137 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 all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 9gbss AIRS ID Number: 123 / 0049 / 136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Company equipment Identification: Inlet TEG Dehydration Unit (P-136) [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Roggen Natural Gas Processing Plant Site Location: Section 24, R63W, T2N Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 E -Mail Address2: RShankaran@DCPMidstream.com Site Location County: Weld NAICS or SIC Code: 1311 Permit Contact: Roshini Shankaran Phone Number: 303-605-2039 1Please 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 3'71400 COLORADO 1I AV aP HwY66F.nvuo= Permit Number: 10WE1659.CP5 AIRS ID Number: 123 /0049/ 136 [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 - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: incorporate 2% enclosed combustor downtime and reduce ECD control efficiency from 97% to 95% 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: dehydration unit for water removal at the plant inlet Facility equipment Identification: For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: P-136 7 /01 /2011 / / El Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: 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 ll days/week Yes Yes O ll weeks/year No No //��\ COLORADO Permit Number: 10WE1659.CP5 AIRS ID Number: 123 /0049/ 136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Dehydration Unit Equipment Information Manufacturer: Evco Fabrication Model Number: T-901 Dehydrator Serial 2090 Reboiler Rating: N/A Number: Ethylene Glycol DiEthylene Glycol Glycol Used: ❑ (EG) ❑ (DEG) Glycol Pump Drive: Li Electric O Gas If Gas, injection pump ratio: Pump Make and Model: Glycol Recirculation rate (gal/min): Lean Glycol Water Content: 1.5 Max: 24.0 Wt.% 0 MMBTU / hr TriEthylene Glycol (TEG) Requested: 24.0 # of pumps: Acfm/gpm 1 Dehydrator Gas Throughput: Design Capacity: 85 MMSCF/day Requested: 31,025 MMSCF/year Actual: 7,727.78 MMSCF/year Inlet Gas: Pressure: 840 Water Content: Wet Gas: psig lb/MMSCF Flash Tank: Pressure: 51 .3 psig psig Cold Separator: Pressure: Stripping Gas: (check one) 0 None ❑ Flash Gas O Dry Gas ❑ Nitrogen Flow Rate: scfm Temperature: ❑✓ Saturated Dry gas: 11.4 lb/MMSCF Temperature: 111.4 °F Temperature: °F 0 NA 120 °F O NA Additional Required Information: Cl Attach a Process Flow Diagram Attach GRI-GLYCaIc 4.0 Input Report Et Aggregate Report (or equivalent simulation report/test results) Attach the extended gas analysis (including BTEX Et n -Hexane, temperature, and pressure) wag COLORADO Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017�> Permit Number: 10WE1659.CP5 AIRS ID Number: 123 /0049/ 136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.1177 / -104.3883 O erator r p Stack ID No Discharge Height Above, Ground Level (Feet) Temp (F) Flow Rate (ACFM) Velocity, (ftlsec) P-136 Indicate the direction of the stack outlet: (check one) ❑ Downward ❑ Other (describe): ❑✓ Upward ❑ Horizontal ❑ 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-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO' 4 IPR�,°, itnJih a4'hMn3 ' Permit Number: 10WE1659.CP5 AIRS ID Number: 123 /0049/ 136 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information O Condenser: Used for control of: Type: Make/Model: Maximum Temp Average Temp Requested Control Efficiency ❑ VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed % ❑ Combustion Device: Used for control of: Still Vent Stream Rating: MMBtu/hr Type: Enclosed Combustor / RTO Make/Model: John Zink / Anguil Requested Control Efficiency: 95.0 / 97.0 % Manufacturer Guaranteed Control Efficiency 98.0 / 99.0 % Minimum Temperature: Waste Gas Heat Content Btu/scf Constant Pilot Light: ❑ Yes O No Pilot burner Rating 0.05 MMBtu/hr Closed ✓❑ Loop System: Used for control of: flash tank vent stream Description: stream routed to low pressure inlet System Downtime 0 ✓❑ Other: Used for control of: Description: Control Efficiency Requested still vent stream ECD has constant pilot; RTO no constant pilot O/O * ECD combustion device used for still vent control has a 2.0% annual downtime for maintenance and repairs. Still vent emissions will vent to atmosphere during periods of ECD downtime. The listed RT0 acts as a backup control device. The RT0 is only online when the amine unit P-137 is operating. During these periods, the P-136 still vent may vent to the RT0 instead of to the ECD. Form APCD-202 -Glycol Dehydration Unit APEN - Revision 02/2017 COLORADO 5 I46S6VWI V, Ei* w Je5,mMsS Permit Number: 10WE1659.CP5 AIRS ID Number: 123 / 0049' 136 [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 es lease describe the control equipment AND state the overall control efficiency (% reduction): y ,P Pollutant Control Equipment Description Overall Requested Control Efficiency (% reduction in emissions) PM SOX NO„ CO VOC Enclosed Combustor / RTO 95% / 97% HAPs Enclosed Combustor / RTO 95% / 97% Other: From what year is the following reported actual annual emissions data? 2016 Use the following table to report the criteria pollutant emissions from source: Pollutant Uncontrolled Emission Factor Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions; Requested Annual Permier t m1 4 Emission L�t(s) Uncontrolled (Tons/year) Controlled5 (Tons/year) Uncontrolled (Tons/year) ` Controlled (Tons/year) PM SOX p Vt. NOX 0.068 Ib/MMBtu AP -42 0.14 0.14 +� s'�� 0. CO 0.31 Ib/MMBtu AP -42 0.75 0.75 1' 'Z4 Q4 4. VOC 41.8 lb/MMscf Promax 40.90 0.59 663.37 23.74 Benzene 3.2 lb/MMscf Promax 1.56 0.05 49.58 3.37 Toluene 2.5 lb/MMscf Promax 0.56 0.02 39.28 2.69 Ethylbenzene 0.1 lb/MMscf Promax 0.00 0.00 0.98 0.07 Xylenes 0.5 lb/MMscf Promax 0.00 0.00 8.03 0.55 n -Hexane 2.1 lb/MMscf Promax 1.47 0.04 3237 1.68 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-202 -Glycol Dehydration Unit APEN - Revision 02/2017 Permit Number: 10WE1659.CP5 AIRS ID Number: 123 /0049/ 136 [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. Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran 0/201 Date Environmental Engineer Name (please print) Title Check the appropriate box to request a copy of the: 0 Draft permit prior to issuance ❑� Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) 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 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 ccLaaavo 7 I m frN �r..iewa[awa.�.,i Amine Sweetening Unit - Form APCD-206 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for Amine Sweetening Units only. If your emission unit does not fall into this category, there may be a more specific APEN 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 all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 9 5 61"141E O≤ AIRS ID Number: 123 / 0049 / 137 [Leave blank unless APCD has already assigned a permit ft and AIRS ID] Company equipment Identification: P-137 [Provide Facility Equipment ID to identify how this equipment is referenced within your organization] Section 1 - Administrative Information Company Name': Site Name: Site Location: DCP Operating Company, LP Roggen Natural Gas Processing Plant Site Location Section 24, R63W, T2N County: Weld Mailing Address: (Include Zip Code) 370 17th Street Suite 2500 Denver, CO 80202 E -Mail Address2: rshankaran@dcpmidstream.com NAICS or SIC Code: 1311 Permit Contact: Roshini Shankaran Phone Number: 303-605-2039 '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. 371401 i COLORA DO Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 Permit Number: 10WE1659 AIRS ID Number: 123 / 08/ 137 [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 0 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) 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: Amine unit for acid gas removal Facility equipment Identification: For existing sources, operation began on: For new or reconstructed sources, the projected start-up date is: P-137 7 /01 /2011 / / 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 Will this equipment be operated in any NAAQS nonattainment area Does this facility have a design capacity less than 2 long tons/day of H25 in the acid gas? Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 El 0 days/week Yes Yes 0 2,AY weeks/year No No COLORADO Oepannwrd of VuWc Ne41.6 FnmentneN Permit Number: 10WE1659 AIRS ID Number: 123 / 0a 137 [Leave blank unless APCD has already assigned a permit # and AIRS ID] a Section 4 - Dehydration Unit Equipment Information Manufacturer: Evco Fabrication Model : T-9002 Serial Number: 2082 Reboiler Rating: N/A Amine Type: Pump Make and Model: ❑ MEA MMBtu/hr Absorber Column Stages: 7 0 DEA 0 TEA stages ❑✓ MDEA 0 DGA # of pumps: Sweet Gas Throughput4: Design Capacity: 85 MMSCF/day Requested: 31,025 MMSCF/year Actual: 0.0 MMSCF/year 4 Requested values will become permit limitations. Requested limit(s) should consider future process growth Inlet Gas: Pressure: 847.33 psig Temperature: 86 °F Rich Amine Feed: Pressure: 839.33 psia Flowrate: 376 Gal/min Temperature: 131 °F Lean Amine Stream: Pressure: 266 psia Temperature: 252 Flowrate: 350 Gal/min Wt. % amine: 50 Mote loading H2S 1.23E-06 Mole Loading co2 0.0099 °F Sour Gas Input: Pressure: Flowrate: psia MMSCF/Day Temperature: °F NGL Input: Pressure: Flowrate: psia Gal/min Temperature: °F Flash Tank: ❑ No Flash Tank Pressure: 60 psia Temperature: 133 °F Additional Required Information: ❑ Attach a Process Flow Diagram ❑ Attach the simulation model inputs Et emission report ❑ Attach composition reports for the rich amine feed, sour gas feed, NGL feed, Et outlet stream (emissions) ❑ Attach the extended gas analysis (including BTEX Et n -Hexane, H2S, CO2, temperature, and pressure) Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 it' ICOLORADO 3 I �SVV77 o.wn�mdwsu� x�ma�,..�.m Permit Number: 10WE1659 AIRS ID Number: 123 / 0a/ 137 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.1174 / -104.3883 Operator Stack ID NO.. Discharge Height - Above Ground Level (Feet) Temp. (°F) Flow Rate (ACFM) Velocity (ft/sec) P-137 Indicate the direction of the stack outlet: (check one) O Downward El Other (describe): ❑✓ Upward El Horizontal O Upward with obstructing raincap Indicate the stack opening and size: (check one) El Circular Interior stack diameter (inches): O Square/rectangle Interior stack width (inches): Interior stack depth (inches): El Other (describe): Form APCD-206 - Amine Sweetening Unit APED - Revision 04/2017 COLOR ADO 4I •V =6 uwmb�.= Permit Number: 10WE1659 AIRS ID Number: 123 / Oa/ 137 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Control Device Information ❑ VRU: Used for control of: Size: Make/Model: Requested Control Efficiency VRU Downtime or Bypassed ❑ Combustion Device: Used for control of: Still Vent Stream Rating: MMBtu/hr Type: RTO Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency Minimum Temperature: 1,450 Make/Model: Anguil / Model 150 97 99 Waste Gas Heat Content Constant Pilot Light: ❑ Yes p No Pilot burner Rating 29 5 Btu/scf MMBtu/hr r❑ Other: Used for control of: flash tank stream closed loop system Description: Control Efficiency 100 Requested Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 (COLORADO 5 I N � w 6 tA6nweNnen+ E.3S per exiicLi real Permit Number: 10WE1659 AIRS ID Number: 123 I Oat 137 [Leave blank unless APCD has already assigned a permit ft and MRS ID] Section 7 -Emissions Inventory 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 es lease describe the control equipment AND state the overall control efficiency (% reduction): Y ,P Pollutant Control Equipment Description Overall Requested Control Efficiency (% reduction in emissions) PM SO. H25 NO. VOC RTO 97% CO HAPs RTO 97% Other: From what year is the following reported actual annual emissions data? 2016 Use the following table to report the criteria pollutant emissions from source: Criteria Pollutant Emissions Inventory 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 O.110 0.10 SO, 1.88 ton SO2 / ton H25 PROMAX 0.00 0.00 -- HZS 0.00 0.00 NO. 0.068 lb/MMBtu AP -42 0.00 0.00 ' 2.93 VOC 18.24 Ib/MMscf PROMAX 0.00 0.00 282.X .toq, "2)2‘ CO 0.31 Ib/MMBtu AP -42 0.00 0.00 '6.l01 30.05 z.a3 Z.43 5.t�► ernal ce.c,clt 2J 1I 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-206 Amine Sweetening Unit APEN - Revision 04/2017 6 I AV COLORADO lieatax b6ewenmmt In Permit Number: 10WE1659 AIRS ID Number: 123 /08/ 137 [Leave blank unless APCD has already assigned a permit if and AIRS ID] ail Section 7 (continued) Non -Criteria Reportable Pollutant Emissions Inventory Pollutant Chemical Abstract Service (CAS) Number Uncontrolled Emission Factor Emission Factor Units Emission Factor Source (AP -42, Mfg. etc) Actual Annual Emissions Uncontrolled Ohs/year) Controlleds (lbs/year) Benzene 71432 1.64 lb/MMscf PROMAX 0.00 0.00 Toluene 108883 1.07 Ib/MMscf PROMAX 0.00 0.00 Ethylbenzene 100414 Xylenes 1330207 0.19 Ib/MMscf PROMAX 0.00 0.00 n -Hexane 110543 0.21 Ib/MMscf PROMAX 0.00 0.00 2,2,4- Trimethylpentane 540841 Other: 5Annual 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. klla(z0r-- Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Environmental Engineer Name (please print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance O 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 $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 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-206 - Amine Sweetening Unit APEN - Revision 04/2017 AV iCOLORADO 7I AV1 N Attachment B: Updated Operating and Maintenance Plans P-136 Inlet TEG Dehy, AIRS ID: 123/0049/136 P-033 Regen Dehy, AIRS ID: 123/0049/130 *These two units share an O&M Plan P-137 Amine Unit, AIRS ID: 123/0049/137 COLORADO Air Pollution Control Division Department of Public He Ith b Environment Form APCD-302 ,ti Air Pollution Control Division Operating and Maintenance Plan Template for Glycol Dehydration Systems Ver. December 22, 2016 The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (OEM Plan) for glycol dehydration systems that use emissions controls, permitted at synthetic minor and major oil and gas facilities in the State of Colorado. An O&M Plan shall be submitted with the permit application when required. One O&M Plan may be used for multiple dehydrators at one facility if each are controlled and monitored in the same manner. If the OFtM Plan template is completed correctly, the Division will approve the O&M Plan and a construction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly, the Division will work with the operator to make corrections. Once a construction permit is issued, the facility operator must comply with the requirements of the O&M Plan upon commencement of operation. An existing approved O&M Plan may be modified without a permit modification or permit reissuance, but the operator must adhere to the requirements of the existing approved O&M Plan until an approval letter is issued for the new O&M Plan. The operator is required to use the Division -developed O&M Plan template forms in order to meet minimum expectations within a standard, organized format. Do not modify the structure and/or content of this template. If the facility or equipment is subject to other state or federal regulations with duplicative requirements, the operator shall follow the most stringent regulatory requirement. For sources that are subject to the Title V Operating Permits program: in accordance with Colorado Regulation No. 3, Part C, Section V.C.5., some or all of the monitoring specified in this O&M plan will be incorporated as specific conditions in the source's Operating Permit, and in some cases permit limits will be established for certain operational parameters. Submittal Date: November 2017 Section 1 - Source Identification For new permits, some of this information (i.e., Facility AIRS ID, Permit Number, and AIRS Point ID) may not be known at the time of application. Please only fill in the fields that are known and leave the others blank. Company Name: Facility Name: DCP Operating Company, LP Roggen Gas Plant Facility Location: Weld County Facility AIRS ID (for existing facilities) 123 - 0049 Emission Units Covered by this O&M Form Facility Equipment ID P-136 P-033 Permit Number (if known) 10WE1659 01WE0208 AIRS Point ID (if known) 136 130 Glycol Type Used a TEG TEG Equipped with Flash Tank? (Y/N) Y Y a Glycol types are Ethylene Glycol (EG), Diethylene Glycol (DEG), or Triethylene Glycol (TEG). APCD Internal Use Only Approved? EZ Initial EY5 Date 11 51 Page 1 of 5 COLORADO Air Pollution Control Division Department of Public Health 5 Environment Section 2 - Maintenance Schedules Check one of the following: Facility shall follow manufacturer recommendations for the operation and maintenance of the emissions unit and control devices. These schedules and practices, as well as all maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices, as well as alt maintenance records showing adherence to these practices, shall be made available to the Division upon request and shall be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. rsi Section 3 - Recordkeeping Requirements The following box must be checked for the O&M Plan to be considered complete: Synthetic minor and major sources are required to maintain maintenance and monitoring records for the requirements of this OaM Plan for a period of five (5) years. If applicable state requirements or any Federal NSPS, NESHAP, or MACT require a longer record retention period, the operator must comply with the longest record retention requirement. Section 4 - Monitoring Requirements Control Equipment Information Table I below details the monitoring parameters and frequency for control equipment depending on the type of control equipment and the requested permitted emissions at the facility. Indicate the emissions control type(s) by checking the appropriate boxes. In addition, check the appropriate box for "Monitoring Frequency" based on the faclury-w►ae pefnn«eu rvt. ciiimovu..7. Table 1 Emissions Control or Recycling Method Flash Still Tank Vent (if present) Parameter Monitoring Frequency Permitted ❑ Permitted Facility Emissions < 80 tpy VOC Facility Emissions ≥ 80 tpy VOC Condenser b ❑ ❑ Condenser Outlet Tempe rature Weekly Monthly Enclosed Flare or Combustor ❑ Pilot Light and Auto- igniter Monitoring d Daily Weekly � Visible Emissions Observation e Daily Weekly Elevated Open Flare C ❑ ❑ Pilot Light and Auto- igniter Monitoring Daily Weekly Visible Emissions Observation e Daily Weekly Thermal Oxidizer* ❑ Chamber Temperature f Daily Weekly •Combustion // * Unit P-136 may vent to the RTO as a backup control device. Unit P-033 may only vent to the enclosed combustor. Page 2 of 5 COLORADO Air Pollution Control Division Department of Public Health 5 Environment Table 1 Emissions Control or Recycling Method Flash Still Tank Vent (if present) Parameter Monitoring Frequency // Permitted ❑ Permitted Facility Emissions < 80 tpy VOC Facility Emissions ≥ 80 tpy VOC Vapor Recovery Unit (VRU) or Recycled or Closed Loop System g ❑ Monitoring requirements, including parameters and frequency, to be determined by the operator and listed below, and approved by the Division I/ Routed to Reboiler Burner as Fuel h ❑ ❑ Monitoring requirements, including parameters and frequency, to be determined by the operator and listed below, and approved by the Division Other ❑ ❑ Monitoring requirements including specific parameters and frequency to be determined by the operator and described in Section 5 below, and approved by the Division b Condenser Maximum Outlet Temperature If the equipment is controlled with a secondary control device and no control efficiency is being claimed for the condenser, then the condenser outlet temperature does not need to be monitored and there will be no maximum condenser outlet temperature. For all other equipment, the maximum condenser outlet temperature • Table 2: Condenser Maximum Outlet Temperature ❑ 160 °F ❑ °F A maximum temperature greater than 160 °F requires approval from the Division. Supporting documentation must be submitted with the permit application and made available to the Division upon request. Elevated Open Flare An open flare permitted after May 1, 2014 and used to comply with Regulation No. 7 Section XVII must be approved by the Division as an alternate emission control device prior to operation, in accordance with Regulation No. 7 Section XVII.B.2.e.; see PS Memo 15-03. d Pilot Light Monitoring Options If emissions are controlled by flare or combustor, then the operator must indicate in Table 3 the method by which the presence of a pilot light will be monitored. One primary method for Pilot Light Monitoring must be checked and, optionally, up to two backup methods may be checked. Table 3: Pilot Light Monitoring Primary Back-up Monitoring Method ❑ ►1 Visual Inspection ❑ ❑ Optical Sensor ❑ ❑ Auto -Igniter Signal r ❑ Thermocouple e Visible Emissions Observation and Method 22 Options At the frequency specified in Table 1, the operator is required to conduct an inspection of the subject combustion device 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 Page 3 of 5 COLORADO Air Pollution Control Division Department of Public Health ET Environment to investigate the cause of the smoke, conduct any necessary repairs, and maintain records of the specific repairs completed; or (2) conduct a formal Method 22 observation to determine whether visible emissions (as defined per Regulation No. 7, Section XVII.A.16.) are present. If a Method 22 is conducted, the record of the observations shall be maintained as required in Section 3 of this O&M Plan. If visible emissions are observed by Method 22, the operator shall immediately conduct any necessary repairs and maintain records of the specific repairs completed; if repair cannot be immediately completed, the operator shall shut-in the equipment, conduct any necessary repairs, and maintain records of the specific repairs completed. The Division has historically approved a "check box" to satisfy the Method 22 documentation procedures. The Division will continue to accept the "check box" recordkeeping format in instances where no visible emissions are observed in order to demonstrate compliance with the Method 22 requirement. If a flare is not subject to Regulation No. 7 requirements (as described in the permit), a similar approach may be employed where the operator may 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) conduct a formal Method 9 observation to determine the opacity of the visible emissions, and conduct repairs if necessary. Thermal Oxidizer: Minimum Combustion Chamber Temperature If emissions are controlled by thermal oxidizer, the minimum combustion chamber temperature shall be: Table 4: Thermal Oxidizer Minimum Combustion Chamber Temperature 1400 °F 1,450 °F Based on manufacturer specifications. Specifications must be submitted with the permit application and made available to the Division upon request. �� Based on Division -approved testing. Test data shall be submitted with and attached to O&M Plan. g Vapor Recovery Unit (VRU) or Recycled or Closed Loop System In the space provided below, please provide a description of the emission control system, including an explanation of parameters monitored, monitoring frequency, and how the system design ensures that emissions are being routed to the appropriate system at all times, or during all permitted runtime. Also, provide a description of how downtime is tracked and recorded. Attach additional pages if necessary. The flash gas emissions from these TEG Dehy units are piped directly to the low pressure inlet line. The TEG flash gas is routed to the low pressure inlet without a VRU or supplemental suction because the higher pressure of the flash tank allows the vapors to flow to the lower pressure inlet system without assistance. This system design ensures the flash gas vapors are recycled as a closed loop system. Page 4 of 5 COLORADO Air Pollution Control Division Department of Public Health & Environment h Routed to Reboiler Burner as Fuel In the space provided below, please provide a brief description of the emission control system, including an explanation of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Describe the cycling frequency of the burner. Describe the other parameters and frequency for monitoring of this emissions control approach. Attach additional pages if necessary. Section 5 - Additional Notes and OM Activities Please use this section to describe any additional notes or operation and maintenance activities, or if additional space is needed from a previous section. Attach additional pages if necessary. The Inlet Dehy P-136 still vent emissions will be controlled by either the enclosed combustor (ECD) or the regenerative thermal oxidizer (RTO). The RTO serves as a backup control device, and can only be used when the Amine Unit P-137 is online. There is no annual downtime associated with the RTO. The Regen Dehy P-033 still vent emissions will be controlled by the ECD only. The enclosed combustor (ECD) used for still vent control has a 2.0% annual downtime for maintenance and malfunctions, during which time, still vent emissions will be vented to atmosphere. ECD Runtime Status will be tracked on at least a daily basis to determine ECD downtime. ECD downtime is defined as periods when emissions from either still vent are routed to the atmosphere instead of to the ECD. If unit P-136 and unit P- 033 are both down in addition to the ECD, this does not constitute downtime as no emissions are being produced. Page 5 of 5 COLORADO Air Pollution Control Division Department of Public Health & Environment Form APCD-306 • Air Pollution Control Division Operating and Maintenance Plan Template for Amine Sweetening Systems Ver. December 22, 2016 The Air Pollution Control Division (Division) developed this Operating and Maintenance Plan (00M Plan) for amine sweetening systems that use emissions controls, permitted at synthetic minor and major oil and gas facilities in the State of Colorado. An OEN Plan shall be submitted with the permit application when required. One OEtM Plan may be used for multiple amine sweetening systems at one facility if each are controlled and monitored in the same manner. If the O0M Plan template is completed correctly, the Division will approve the OEtM Plan and a construction permit will be issued with the requirement to follow the O&M Plan as submitted. If the template is not completed correctly, the Division will work with the operator to make corrections. Once a construction permit is issued, the facility operator must comply with the requirements of the OEtM Plan upon commencement of operation. An existing approved O&M Plan may be modified without a permit modification or permit reissuance, but the operator must adhere to the requirements of the existing approved OEtM Plan until an approval letter is issued for the new O&M Plan. The operator is required to use the Division -developed OEtM Plan template forms in order to meet minimum expectations within a standard, organized format. Do not modify the structure and/or content of this template. If the facility or equipment is subject to other state or federal regulations with duplicative requirements, the operator shall follow the most stringent regulatory requirement. For sources that are subject to the Title V Operating Permits program: in accordance with Colorado Regulation No. 3, Part C, Section V.C.5., some or all of the monitoring specified in this OEtM plan will be incorporated as specific conditions in the source's Operating Permit, and in some cases permit limits will be established for certain operational parameters. Submittal Date: November 2017 Section 1 - Source Identification For new permits, some of this information (i.e., Facility AIRS ID, Permit Number, and AIRS Point ID) may not be known at the time of application. Please only fill in the fields that are known and leave the others blank. Company Name: DCP Operating Company, LP Facility Location: Weld Facility Name: Roggen Gas Plant Facility AIRS ID (for existing facilities) 123 - 0049 Emission Units Covered by this O&M Form Facility Equipment ID P-137 Permit Number (if known) 10WE1659 AIRS Point ID (if known) 137 Amine Type Used a MDEA Equipped with Flash Tank? (Y/N) Y Equipped with Surge Tank? (Y/N) N a Amine types are MEA, DEA, TEA, MDEA, and DGA. APCD Internal Use Only Approved? [ Initial EZ'5 Date i I?1 f �� Page 1 of 5 COLORADO Air Pollution Control Division Department of Public Health Er Environment Section 2 - Maintenance Schedules Check one of the following: Facility shall follow manufacturer recommendations for the operation and maintenance of the emissions unit and control devices. These schedules and practices, as well as all maintenance records showing compliance with these recommendations, shall be made available to the Division upon request. Facility shall follow individually developed maintenance practices and schedules for the operation and maintenance of equipment and control devices. These schedules and practices, as well as all maintenance records showing adherence to these practices, shall be made available to the Division upon request and shall be consistent with good air pollution control practices for minimizing emissions as defined in the New Source Performance Standard (NSPS) general conditions. Section 3 - Recordkeeping Requirements The following box must be checked for the O&M Plan to be considered complete: Synthetic minor and major sources are required to maintain maintenance and monitoring records for the requirements of this O&M Plan for a period of five (5) years. If applicable state requirements or any Federal NSPS, NESHAP, or MACT require a longer record retention period, the operator must comply with the longest record retention requirement. Section 4 - Monitoring Requirements Control Equipment Information Table 1 below details the monitoring parameters and frequency for control equipment depending on the type of control equipment and the requested permitted emissions at the facility. Indicate the emissions control type(s) by checking the appropriate boxes. In addition, check the appropriate box for "Monitoring Frequency" based on the facility -wide permitted VOC emissions. Emissions Control or Recycling Method Flash Still Tank Vent (if present) Condenser b Enclosed Flare or Combustor Table 1 Parameter Condenser Outlet Temperature Pilot Light and Auto - igniter Monitoring d Visible Emissions Observation e Pilot Light and Auto - igniter Monitoring d Visible Emissions Observation e Elevated Open Flare Thermal Oxidizer Combustion Chamber Temperature Page 2 of 5 Monitoring Frequency ® Permitted Facility Emissions ≥ 80 tpy VOC Weekly Daily Daily Daily Daily Daily ❑ Permitted Facility Emissions < 80 tpy VOC Monthly Weekly Weekly Weekly Weekly Weekly COLORADO Air Pollution Control Division Department of Public Health & Environment Table 1 Emissions Control or Recycling Method Flash Still Tank Vent (if present) Parameter Monitoring Frequency r1 Permitted ❑ Permitted Facility Emissions < 80 tpy VOC Facility Emissions ≥ 80 tpy VOC Vapor Recovery c (VRU) or Recycled or Closed Loop System g ❑ Monitoring requirements, including parameters and frequency, to be determined by the operator and listed below, and approved by the Division pp �� Routed to Reboiler Burner as Fuel h ❑ ❑ Monitoring requirements, including parameters and frequency, to be determined by the operator and listed below, and approved by the Division Other ❑ ❑ Monitoring requirements including specific parameters and frequency to be determined by the operator and described in Section 5 below, and approved by the Division b Condenser Maximum Outlet Temperature If emissions are controlled with a secondary control device and no control efficiency is being claimed for the condenser, then the condenser outlet temperature does not need to be monitored and there will be no maximum condenser outlet temperature. For all other equipment, the maximum condenser outlet temperature • u y� Table 2: Condenser Maximum Outlet Temperature ❑ 160 °F ❑ °F A maximum temperature greater than 160 °F requires approval from the Division. Supporting documentation must be submitted with the permit application and made available to the Division upon request. ` Elevated Open Flare An open flare permitted after May 1, 2014 and used to comply with Regulation No. 7 Section XVII must be approved by the Division as an alternate emission control device prior to operation, in accordance with Regulation No. 7 Section XVII.B.2.e.; see PS Memo 15-03. d Pilot Light Monitoring Options If emissions are controlled by flare or combustor, then the operator must indicate in Table 3 the method by which the presence of a pilot light will be monitored. One primary method for Pilot Light Monitoring must be checked and, optionally, up to two backup methods may be checked. Table 3: Pilot Light Monitoring Primary Back-up Monitoring Method ❑ ❑ Visual Inspection ❑ ❑ Optical Sensor ❑ ❑ Auto -Igniter Signal ❑ ❑ Thermocouple Page 3 of 5 COLORADO Air Pollution Control Division Department of Public Health £r Environment e Visible Emissions Observation and Method 22 Options At the frequency specified in Table 1, the operator is required to conduct an inspection of the subject combustion device 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; or (2) conduct a formal Method 22 observation to determine whether visible emissions (as defined per Regulation No. 7, Section XVII.A.16.) are present. If a Method 22 is conducted, the record of the observations shall be maintained as required in Section 3 of this O&M Plan. If visible emissions are observed by Method 22, the operator shall immediately conduct any necessary repairs and maintain records of the specific repairs completed; if repair cannot be immediately completed, the operator shall shut-in the equipment, conduct any necessary repairs, and maintain records of the specific repairs completed. The Division has historically approved a "check box" to satisfy the Method 22 documentation procedures. The Division will continue to accept the "check box" recordkeeping format in instances where no visible emissions are observed in order to demonstrate compliance with the Method 22 requirement. If a flare is not subject to Regulation No. 7 requirements (as described in the permit), a similar approach may be employed where the operator may 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) conduct a formal Method 9 observation to determine the opacity of the visible emissions, and conduct repairs if necessary. f Thermal Oxidizer: Minimum Combustion Chamber Temperature If emissions are controlled by thermal oxidizer, the minimum combustion chamber temperature shall be: Table 4: Thermal Oxidizer Minimum Combustion Chamber Temperature 1400 °F 1,450 °F Based on manufacturer specifications. Specifications must be submitted with the permit application and made available to the Division upon request. ►_ Based on Division -approved testing. Test data shall be submitted with and attached to OItM Plan. g Vapor Recovery Unit (VRU) or Recycled or Closed Loop System In the space provided below, please provide a description of the emission control system, including an explanation of parameters monitored, monitoring frequency, and how the system design ensures that emissions are being routed to the appropriate system at all times, or during all permitted runtime. Also, provide a description of how downtime is tracked and recorded. Attach additional pages if necessary. The flash gas emissions from the amine unit are piped directly to the low pressure inlet line. The amine flash gas is routed to the low pressure inlet without a VRU or supplemental suction because the higher pressure of the flash tank allows the vapors to flow to the lower pressure inlet system without assistance. This system design ensures the flash gas vapors are recycled as a closed loop system. Page 4 of 5 COLORADO Air Pollution Control Division Department of Public Health & Environment h Routed to Reboiler Burner as Fuel In the space provided below, please provide a brief description of the emission control system, including an explanation of how the system design ensures that emissions are being held or rerouted when the reboiler is not firing. Describe the cycling frequency of the burner. Describe the other parameters and frequency for monitoring of this emissions control approach. Attach additional pages if necessary. Section 5 - Additional Notes and OltM Activities Please use this section to describe any additional notes or operation and maintenance activities, or if additional space is needed from a previous section. Attach additional pages if necessary. Page 5 of 5 Attachment C: Emission Calculations and Supporting Documentation P-136 Inlet TEG Dehy, AIRS ID: 123/0049/136 P136 PTE Emissions (2% ECD Downtime, P136 TEG Dehydration Unit Emissions) DCP Operating Company, LP Roggen Natural Gas Processing Plant Source ID P136 Description Dehydration Unit Manufacturer Evco Fabrication Model T-901 Serial # 2090 Operation Date 7/1/2011 Operation Wet Gas Temperature Wet Gas Pressure Wet Gas Water Content Dry Gas Flow Rate _ Dry Gas Water Content Lean Glycol Water Content Lean Glycol Flow Rate Cold Separator? _ Cold Separator Temperature Cold Separator Pressure Glycol Pump Make & Model _ Glycol Pump Type Glycol Gas Injection Pump Ratio Flash Tank?` Flash Tank Temperature Flash Tank Pressure Flash Tank Control VRU Downtime 8760 hr/yr 120 deg F 840 pslg Saturated IbH2OIMMscf 85.0 MMscfd 11.4 IbH20/MMscf 1.5 wt% H2O 24 gpm N YR4 WA deg F N/A psig Electric Elec. or Gas n/a acfnt/gpm YY/N 111.4 deg F 51.3 psig 100.00% Recycled to Inlet WA 'Pollutant NOS' CO' Uncontrolled Emission Factor 0.068 IbIMMBTU 0.31 lb/MME3TU Combustor Ambient Air Temp Combustor Excess Oxygen Combustor Destruction Efficiency Combustor Downtime Shipping Gas? What Is Stripping Gas? Stripping Gas Flow Rate Condenser? Condenser Temperature N Y/N NIA scfm N YIN deg F Condenser Pressure psis Combustor?° Y YIN Combustor Type Enclosed Combustor 60 deg F 0% 95.00% % 2% Uncontrolled Hours of SOD Downtime 175.2 hr/yr Hours of ECD Uptime 8584.8 hr/yr ' Controlled Emissions 2.63 ton/yr 11.97 ton/yr ' Emission Factors from AP -42, Chapter 135 VOC and HAP emissions from the gash ventstmam controlledwhh the VRU and still vent stream controlled with the ECD. P -ISO can either be controlled by the ECD, as sear here. or the RTO, DCP requests the ECD emission volumes (Illustrated here) be considered for this modification application. Total Emissions Gas Emssions Deny aull vent emts=iuna w.eL .,-.... •--•• Uncontrolled TEG Dehydration Unit Dehy Flash Dehy Flash Emissions'd Emissions' Emissions" Emissiyns Dehy Still Uncontrolled Emissions' ECD Uptime Emissions' ECD Downtime Emissions' ton/yr Controlled Emissions' ton/r 0.00 Emissions' tontyr 0.00 tanlyr tanlyr lb/hr tontyr tontyr Hydrogen Sulfide Iblhr 0.126 0.000 0.000 0.000 0.000 0 002 0.000 0.007 0,000 0.007 D.000 0.000 0 00 0.00 143.16 01.4 4 8 0.000 408.55.719 60 5 0..17 54.66 2927.25 287215 CO250.126 C 18 .59 2.090 0.000 9555 595.653 2608,958 2608,958 52.179 0.63 175.81 Water Methane 0.477 .59 34.596 151.529 1. D.oOa 0.000 1.895 6.325 8.300 27.704 0.407 1.357 0.166 0.554 210 .... •4.47:` 181.33 ":.225.0 .. Ethane Propane. - 31.211 33.262:'. 145.774 . 145.774 � .. 0.000 `�":.. . '-•' . 13.432' - SB.B30:.' .:' 2.883<: .` 1.177.::". 14747 FButane' . - .' r ,�. - n-Bdtane:;.. . 2572- - 17.563 : .. 24.407:.. : 76.928 15.106 0:0006:s.; �'-. 0 000`•^"•• :^: O.OOD:••`.- 0000 - 13:046' • 6•.4:669. v_.551fi • -1:872 • 57.140 ...20,452 25.911 8199 .2.800' 1.002 "1 270 0402 1.143 ---- .' -0 409 -,.: - 0.518 •--,-.0.464.as 4.34 1:65 3 _�.�,4630 '.. '...-..._ .. io ... ••3.449., -. -,.._ ' 3.712.:... 0?42 _: :. 16.258. - 1 059 .:_1.97,_6' , 0• �6 .. :tom t_ mane C old nt n .^.... ". s, ....�F Nr..yC.O c-^c^^•�•'yrr`"�S r I'A� G. �. ""' ;.Ei.•:L a'T- -010.8, 'Y"« zr.+ ee'a 0 U 8 21...,_, .. Cyolohe Heptan :.0 :'. .. .- Hap h ', .' 0.369 .:1:617 O.D00 2292. ,.• 0,000'.. 0.000 1.000 - 0.492 '"" '0.000. 0 201 7,3:1,000:,,7 :.: 0:00 o:aD 000 •DOD-'. • P..ent n 224-TnmethYF. ' �' � '� ' �O.ODO - 0.000 :0 000 :. p ppp '. , .. 2000. - 0;000 - 0.000, � z.005;••, • `O.000 : r aopD : 0 000 , 0:000.,,. 0:18 DDD .2 00 Octan e ,:* 4e�. , 'St BOWL_. �: -- ltE - ¢ y 006 u »: to ,? Z• ; tl OTif�'. ,w"- - ..., ''•�1., �5 i* t � mfi _ °x der t :` .a �a Zi/h' . a unm 'r>r -err'-SOS., ,. ..o 0269C'zr Eks =0 6",'' '.,' 0,500 �. .. fie' =-� MC * e, 9Th ... trig d 'rMr .�.-•ZFx nom'. 5't 5- w 4' " €: i0+ 4�Ls"v±.-.: r>= 0.000 :.• b ail a ..'0000.. x °.: d -t `a c'0.000 :0 0.000 . • 0 000 000 D.DD . .'':'0.000 " D.00D_:. D:ooD '... o.DOD 0.000 •. ::.O.Doo D.DDD:`.< ..D.Do 0.05.. 0.86 ' .. o.DoO -. .: O ..• ,0:000:. • 0.10." .. 0:773..• ...o.D3e:, 23.74 663.37 6821 .. 290.30,3 4 0,00 71.40 31272 15.32 6.25 8.36 130.24 VOC Total HAP 6fi.29 1.89 0,27 0.00 25.14 110.13 5.40 2.20 1. Uncontrolled Still Vent and Flash Tank emissions obtained born ProMax report dated November 9, 2017 2 ECD Control Emissions apply a 95% ORE to Still Vent Uncontrolled emissions and are annualized based on annual hours of ECD optima. 3.2% ECD Downtime Emissions are based on Still Vent Uncontrolled Emissions and are annualized based on annual hours of ECD downtime. 4. There is no flash tank downtime because emissions are piped to low-pressure InleL 5. Total Controlled Emissions are represented as the sum of ECD Uptime, ECD Downtkne, and Flash Tank emissions, with an added 10% buffer. sions with an 6. Total stoninglan emissions are represented of 9 as %ihl ul d asof iivent and flash tank tno %-rolal ControlledsSehy VOC Emssiodns/% buffer. /Total Uncontrolled Dehy Emissions] 7. Demonstrating an overall system control of 95%, calculated s e Overall System Control' 96.42% Promax Modeling Run —11/9/2017 Inlet TEG Dehy P-136 (AIRS 136) Roggen Gas Plant .l5WPruped,. 34 Napor Vt4Nreeiu Flmv(Ta al) BSI MMSCFD I 2 11 T-9101 Glycol Contactor 34 26 T-1 —30 • LCV-9101 —Water Addition V-9103 Dry Gas Scrubber 25-2"1---(14-12 A-9605 Lean Glycol Cooler P-9555NB Glycol Circulation Pumps Q-3 9 IX -102 SPLT-102 MIX -103 A I ----Q-4 PIPE -1 RCYL-1 Reflux Section 17 —To LP --I44 V-9505 Glycol Flash Tank 23 1 TEG Make -Up 24 10 E-9545 Hot Glycol Exchanger 111-9505 To ECD/RTO V-6001 RTO KO Drum T-5520 Sun Column 28 _ H-9530/ V-9540 Glycol Regenerator 8 Surge Drum Process Streams To LP To ECD /RTO Water Addition 1 Composition Status: Solved Phase: Total From Block: V-9108 TEG Flash Tank To Block: Solved V-8001 RTO KO Drum Solved Solved • 91 LV-9103 MIX -102 MIX -102 Mass Flow lb/h lb/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 18.5900 0 0.126428 34.5957 31.3110 33.2816 5.57242 17.5635 3.44883 3.71197 0.241813 1.65950 0.158108 0.369135 0 0 0.154515 0.0660096 0.00110642 0.00642959 0.0523044 0.477169 0.000967959 0 11.1231 0 0.00164845 1.89500 6.32509 13.4315 2.76595 13.0456 4.66930 5.91584 1.87184 5.05823 1.54626 2.29204 0 0 10.1354 8.08623 0.203300 1.66073 0.539342 595.653 0.176566 0 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 0* 250.116* 0* 0* 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Process Streams To LP To ECD /RTO Water Addition 1 Properties Phase: Total Status: From Block: To Block: Solved V-9108 TEG Flash Tank -- Solved V-8001 RTO KO Drum Solved =- MIX -102 Solved LV-9103 MIX -102 Property Units Temperature °F 111.405 221.494 70* Pressure psig 51.3 3.46185 65* 51.3* Mole Fraction Vapor % 100 100 0 Molecular Weight Ib/Ibmol 30.6778 19.7604 18.0153 124.885 Molar Flow lbmol/h 4.93478 34.7360 13.8835 0 Mass Flow lb/h 151.388 686.395 250.116 0 Mass Density Ib/ft^3 0.339382 0.0495741 62.2853 Specific Gravity 1.05922 0.682272 0.998657 Std Vapor Volumetric Flow MMSCFD 0.0449441 0.316362 0.126446 0 Vapor Volumetric Flow ft^3/h 446.071 13845.9 4.01565 Std Liquid Volumetric Flow sgpm 0.694715 1.48550 0.5* 0 Liquid Volumetric Flow gpm 55.6141 1726.24 0.500653 Compressibility 0.973412 0.990122 0.00405530 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow 2 2.11 3 Solved Solved Solved V-9103 Dry Gas Scrubber T-9101 Glycol Contactor T-9101 Glycol Contactor LV-9103 V-9103 Dry Gas Scrubber LCV-9101 lb/h - lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4 -Trim ethyl pentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Process Streams 2 Properties Status: Solved Solved Solved Phase: Total From Block: V-9103 Dry Gas Scrubber T-9101 Glycol Contactor T-9101 Glycol Contactor To Block: LV-9103 V-9103 Dry Gas Scrubber LCV-9101 Property Units Temperature °F Pressure ' psig Mole Fraction Vapor % Molecular Weight lb/lbmol Molar Flow lbmol/h Mass Flow lb/h Mass Density lb/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 9786.83 0 1280.95 105498 40098.0 31389.0 5504.00 14189.1 2629.41 2611.74 115.704 1197.26 91.7639 294.723 0 0 75.0036 37.4223 0.786359 4.27677 48.4479 40.3650 1.47377 0 29.7132 0 0.128076 36.4907 37.6361 46.7131 8.33837 30.6090 8.11813 9.62782 2.11391 6.71779 1.70477 2.66130 0 0 10.3369 8.26018 0.209753 1.75428 0.591736 640.011 13244.2 0 838 0 124.885 0 0 0 0 2.11 3 119.920 838 100 23.0455 9324.79 214894 3.85785 0.795699 84.9266 55703.1 1169.42 6944.81 0.818937 122.598 840 0 108.410 130.301 14125.9 67.0033 1.07430 1.18673 210.824 25.7067 26.2845 0.221309 Process Streams 4 5 6 Composition Status: Phase: Total From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane. 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol Solved Solved Solved LCV-9101 V-9103 Dry Gas Scrubber T-9104 Reflux Section MIX -102 PIPE -1 lb/h lb/h lb/h 29.7132 9786.83 11.1233 O 0 0 0.128076 1280.95 0.00164846 36.4907 105498 1.89500 37.6361 40098.0 6.32511 46.7131 31389.0 13.4315 8.33837 5504.00 2.76595 30.6090 14189.1 13.0456 8.11813 2629.41 4.66931 9.62782 2611.74 5.91586 2.11391 115.704 1.87186 6.71779 1197.26 5.05824 1.70477 91.7639 1.54627 2.66130 294.723 2.29205 O 0 0 0 0 0 10.3369 75.0036 10.1366 8.26018 37.4223 8.08731 0.209753 0.786359 0.203325 1.75428 4.27677 1.66102 0.591736 48.4479 0.539343 640.011 40.3650 615.540 13244.2 1.47377 7.25836 O 0 0 Process Streams 4 5 6 Properties Phase: Total Solved Status: Solved. From Block: LCV-9101 V-9103 Dry Gas Scrubber T-9104 Reflux Section To Block: MIX -102 PIPE -1 Property Units Temperature Pressure Mole Fraction Vapor Molecular Weight Molar Flow Mass Flow Mass Density Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility °F psig lb/lbmol lbmol/h lb/h lb/ft^3 125.080 51.3* 3.86450 108.410 130.301 14125.9 21.0098 1.18673 672.348 25.7067 83.8252 0.0542664 119.920 838 100 23.0455 9324.79 214894 3.85785 0.795699 84.9266 55703.1 1169.42 6944.81 0.818937 624.983 3.5 100 19.8781 35.8871 713.367 0.0311546 0.686337 0.326846 22897.7 1.53780 2854.77 0.997410 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow 7 8 9 Solved Solved Solved SPLT-102 V-9108 TEG Flash Tank LV-9108 T-9104 Reflux Condenser E-9106 Lean/Rich Exchanger T-9104 Still Column lb/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 14.8566 0 0.0640381 18.2453 18.8180 23.3566 4.16918 15.3045 4.05906 4.81391 1.05696 3.35890 0.852386 1.33065 0 0 5.16844 4.13009 0.104877 0.877139 0.295868 445.064 6622.08 0 Process Streams 7 Properties Status: Solved Solved Solved Phase: Total From Block: SPLT-102 V-9108 TEG Flash Tank LV-9108 To Block: T-9104 Reflux Condenser E-9106 Lean/Rich Exchanger T-9104 Still Column Property Units Temperature °F Pressure psig Mole FracVon Vapor Molecular Weight Ib/Ibmol Molar Flow lbmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 11.1232 0 0.00164845 1.89500 6.32509 13.4315 2.76595 13.0455 4.66930 5.91585 1.87210 5.05829 1.54666 2.29217 0 0 10.1824 8.19417 0.208647 1.74785 0.539431 889.650 13244.2 0 11.1232 0 0.00164845 1.89500 6.32509 13.4315 2.76595 13.0455 4.66930 5.91585 1.87210 5.05829 1.54666 2.29217 0 0 10.1824 8.19417 0.208647 1.74785 0.539431 889.650 13244.2 0 125.784 51.3 3.49178 99.7058 72.0921 7188.00 21.2497 0.656587 338.263 13.1034 42.1730 0.0492864 8 9 111.405 247.870 51.3 4* 0 1.67497 102.152 102.152 139.249 139.249 14224.6 14224.6 68.3845 12.2462 1.09645 1.26823 1.26823 208.009 1161.55 25.5120 25.5120 25.9336 144.816 0.0160861 0.0205389 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentaie Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Tri methylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol •10 11 Solved E-9105 TEG Reboiler/Surge Tank E-9106 Lean/Rich Exchanger Solved E-9106 Lean/Rich Exchanger TEG Make -Up lb/h lb/h Process Streams Properties Status: Solved Solved Phase: Total From Block: E-9105 TEG Reboiler/Surge Tank E-9106 Lean/Rich Exchanger To Block: E-9106 Lean/Rich Exchanger TEG Make -Up Property Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow lbmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 6.16714E-06 0 7.85559E-13 1.44756E-08 6.18383E-07 5.07298E-06 1.70200E-06 1.77839E-05 2.05174E-05 3.72104E-05 0.000280851 9.24144E-05 0.000429916 0.000143304 0 0 0.0475997 0.108907 0.00538053 0.0874932 9.42917E-05 279.801 13243.8 0 10 11 6.16714E-06 0 7.85559E-13 1.44756E-08 6.18383E-07 5.07298E-06 1.70200E-06 1.77839E-05 2.05174E-05 3.72104E-05 0.000280851 9.24144E-05 0.000429916 0.000143304 0 0 0.0475997 0.108907 0.00538053 0.0874932 9.42917E-05 279.801 13243.8 0 358.394 4.5 0 130.383 103.724 13523.8 59.7808 0.958502 0.944678 226.223 23.9977 28.2045 0.00476889 215.997 2.5 0 130.383 103.724 13523.8 65.1514 1.04461 0.944678 207.575 23.9977 25.8795 0.00474598 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow 12 13 Solved P-9107A/B TEG Pumps AC -9102 Glycol Cooler Solved E-9105 TEG Reboiler/Surge Tank T-9104 Still Column lb/h Ib/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane . 2,2,4-Trimethylpentane ethylpentan e Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 6.05576E-06 0 0 0 0 4.96919E-06 1.66621E-06 1.74209E-05 2.00875E-05 3.64202E-05 0.000275042 9.04407E-05 0.000421150 0.000140217 0 0 0.0467547 0.107033 0.00529043 0.0861115 9.22564E-05 279.285 13245.6 0 0.00106240 0 1.06860E-09 8.52221E-06 0.000165426 0.000897974 0.000251004 0.00213129 0.00167842 0.00275717 0.00762244 0.00497897 0.00967809 0.00529267 0 0 0.511892 0.860877 0.0343402 0.448216 0.00256530 845.998 177.368 0 Process Streams 12 13 Properties Status: _ ,_ Solved Solved Phase: Total From Block: P-9107A/B TEG Pumps E-9105 TEG Reboiler/Surge Tank To Block: AC -9102 Glycol Cooler T-9104 Still Column Property Units Temperature °F 218.420 358.394 Pressure psig 900* 4.5 Mole Fraction Vapor % 0 100 Molecular Weight Ib/Ibmol 130.416 21.2877 Molar Flow Ibmol/h 103.708 48.1621 Mass Flow lb/h 13525.2 1025.26 Mass Density Ib/ft^3 65.1593 0.0469062 Specific Gravity 1.04474 0.735007 Std Vapor Volumetric Flow MMSCFD 0.944530 0.438642 Vapor Volumetric Flow ft^3/h 207.570 21857.7 Std Liquid Volumetric Flow sgpm 24 2.00944 Liquid Volumetric Flow gpm 25.8789 2725.12 Compressibility 0.251583 0.992335 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow 14 15 Solved T-9104 Still Column E-9105 TEG Reboiler/Surge Tank Solved E-9106 Lean/Rich Exchanger LV-9108 lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2, 2,4-T ri m eth yl pentan e Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 0.00106857 0 1.06938E-09 8.53668E-06 0.000166044 0.000903047 0.000252706 0.00214907 0.00169894 0.00279438 0.00790329 0.00507138 0.0101080 0.00543597 0 0 0.559492 0.969783 0.0397207 0.535709 0.00265959 1125.80 13421.1 0 11.1232 0 0.00164845 1.89500 6.32509 13.4315 2.76595 13.0455 4.66930 5.91585 1.87210 5.05829 1.54666 2.29217 0 0 10.1824 8.19417 0.208647 1.74785 0.539431 889.650 13244.2 0 Process Streams 14 15 Properties Status: Solved Solved Phase: Total From Block: T-9104 Still Column E-9106 Lean/Rich Exchanger To Block: E-9105 TEG Reboiler/Surge Tank LV-9108 Property Units Temperature °F 281.787 250* Pressure psig 4.5 46.3 Mole Fraction Vapor % 0 0.361399 Molecular Weight Ib/Ibmol 95.7893 102.152 Molar Flow lbmol/h 151.886 139.249 Mass Flow lb/h 14549.1 14224.6 Mass Density Ib/ft^3 63.0062 50.0773 Specific Gravity 1.01022 Std Vapor Volumetric Flow MMSCFD 1.38332 1.26823 Vapor Volumetric Flow ft^3/h 230.915 284.053 Std Liquid Volumetric Flow sgpm 26.0072 25.5120 Liquid Volumetric Flow gpm 28.7894 35.4144 Compressibility 0.00366770 0.0163376 Process Streams Composition Phase: Total Mass Flow Status: From Block: To Block: 16 Solved T-9104 Still Column T-9104 Reflux Condenser lb/h 17 18 Solved T-9104 Reflux Section T-9104 Still Column lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane 1 -Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 11.1233 0 0.00164846 1.89500 6.32511 13.4315 2.76595 13.0456 4.66931 5.91586 1.87186 5.05824 1.54627 2.29205 0 0 10.1366 8.08731 0.203325 1.66102 0.539343 615.540 7.25836 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Solved T-9104 Reflux Condenser T-9104 Reflux Section lb/h Process Streams Properties . Phase: Total Property Temperature Pressure Mole Fraction Vapor Molecular Weight Molar Flow Mass Flow Mass Density Specific Gravity Std Vapor Volumetric Flow Vapor Volumetric Flow Std Liquid Volumetric Flow Liquid Volumetric Flow Compressibility 16 Status: Solved From Block: T-9104 Still Column To Block: T-9104 Reflux Condenser Units °F psig Ib/Ibmol lbmol/h lb/h Ib/ft^3 MMSCFD ft^3/h sgpm gpm 264.371 3.5 100 19.8781 35.8871 713.367 0.0469486 0.686337 0.326846 15194.7 1.53780 1894.40 0.991518 17 11.1233 0 0.00164846 1.89500 6.32511 13.4315 2.76595 13.0456 4.66931 5.91586 1.87186 5.05824 1.54627 2.29205 0 0 10.1366 8.08731 0.203325 1.66102 0.539343 615.540 7.25836 0 18 Solved Solved T-9104 Reflux Section T-9104 Reflux Condenser T-9104 Still Column T-9104 Reflux Section 3.5 0 0 0 0 0 624.983 3.5 100 19.8781 35.8871 713.367 0.0311546 0.686337 0.326846 22897.7 1.53780 2854.77 0.997410 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow 19 20 21 22 23 Solved Solved Solved Solved Solved SPLT-102 MIX -102 TEG Make -Up RCYL-1 MIX -103 SPLT-102 RCYL-1 P-9107A/B TEG Pumps TEG Ma- ke -Up lb/h lb/h Ib/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane m ethyl pentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 14.8566 29.7132 6.16714E-06 0 0 0 0.0640381 0.128076 0 18.2453 36.4907 0 18.8180 37.6361 0 23.3566 46.7131 5.07298E-06 4.16918 8.33837 1.70200E-06 15.3045 30.6090 1.77839E-05 4.05906 8.11813 2.05174E-05 4.81391 9.62782 3.72104E-05 1.06696 2.11391 0.000280851 3.35890 6.71779 9.24144E-05 0.852386 1.70477 0.000429916 1.33065 2.66130 0.000143304 0 0 0 0 0 0 5.16844 10.3369 0.0475997 4.13009 8.26018 0.108907 0.104877 0.209753 0.00538053 0.877139 1.75428 0.0874932 0.295868 0.591736 9.42917E-05 445.064 890.127 279.802 6622.08 13244.2 13245.0 0 0 0 6.05576E-06 0 O 0 O 0 O 0 0 0 4.96919E-06 0 1.66621E-06 0 1.74209E-05 0 2.00875E-05 0 3.64202E-05 0 0.000275042 0 9.04407E-05 0 0.000421150 0 0.000140217 0 0 0 0 0 0.0467547 0 0.107033 0 0.00529043 0 0.0861115 0 9.22564E-05 0 279.285 0.00127970 13245.6 1.27842 0 0 Process Streams 19 20 21 22 23 Properties Phase: Total Status: Solved From Block: SPLT-102 To Block: MIX -103 Solved MIX -102 SPLT-102 Solved TEG Make -Up RCYL-1 Solved RCYL-1 P-9107A/B TEG Pumps Solved TEG Make -Up Property Units Temperature °F 125.784 125.784 215.985 215.885 80* Pressure psig 51.3 51.3 2.5 2.5 5.30405* Mole Fraction Vapor '/G 3.49178 3.49178 0 0 0 Molecular Weight Ib/Ibmol 99.7058 99.7058 130.384 130.416 149.079 Molar Flow Ibmol/h 72.0921 144.184 103.733 103.708 0.00858399 Mass Flow lb/h 7188.00 14376.0 13525.1 13525.2 1.27970 Mass Density lb/ft^3 21.2497 21.2497 65.1518 65.1553 70.1981 Specific Gravity 1.04462 1.04467 1.12553 Std Vapor Volumetric Flow MMSCFD 0.656587 1.31317 0.944757 0.944530 7.81797E-05 Vapor Volumetric Flow ft^3/h 338.263 676.526 207.593 207.583 0.0182298 Std Liquid Volumetric Flow sgpm 13.1034 26.2067 24* 24 0.00226500 Liquid Volumetric Flow gpm 42.1730 84.3461 25.8818 25.8805 0.00227280 Compressbility 0.0492864 0.0492864 0.00474609 0.00474770 0.00733382 Process Streams Composition Status: Phase: Total From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane ethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 24 Solved TEG Make -Up lb/h 25 26 Solved Solved AC -9102 Glycol Cooler SAT -1 T-9101 Glycol Contactor T-9101 Glycol Contactor Ib/h lb/h O 6.05576E-06 9816.54 O 0 ,0 O 0 1281.08 0 0 105535 0 0 40135.7 0 4.96919E-06 31435.7 0 1.66621E-06 5512.33 0 1.74209E-05 14219.7 0 2.00875E-05 2637.53 O 3.64202E-05 2621.37 0 0.000275042 117.817 0 9.04407E-05 1203.98 O 0.000421150 93.4683 O 0.000140217 297.384 0 0 0 0 0 0 0 0.0467547 85.2937 O 0.107033 45.5754 0 0.00529043 0.990822 0 0.0861115 5.94493 O 9.22564E-05 49.0396 0 279.285 401.092 0 13245.6 0 O 0 0 Process Streams 24 Properties Status: Solved Solved Solved Phase: Total From Block: TEG Make -Up AC -9102 Glycol Cooler SAT -1 To Block: T-9101 Glycol Contactor T-9101 Glycol Contactor Property Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow Ibmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 2.5 130.383 0 0 0 0 25 26 70* 895 0 130.416 103.708 13525.2 70.2674 1.12664 0.944530 192.481 24 23.9977 0.297033 120 840 100 23.0442 9351.38 215495 3.86779 0.795654 85.1688 55715.3 1171.13 6946.33 0.818590 Process Streams Composition Status: Phase: Total From Block: To Block: 27 28 29 30 Solved Solved Solved Solved MIX -103 V-8001 RTO KO Drum PIPE -1 V-9108 TEG Flash Tank -- V-8001 RTO KO Drum SAT -1 Mass Flow lb/h lb/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 29.7132 0 0.128076 36.4907 37.6361 46.7131 8.33837 30.6090 8.11813 9.62782 2.11391 6.71779 1.70477 2.66130 0 0 10.3369 8.26018 0.209753 1.75428 0.591736 890.127 13244.2 0 0.000181135 0 1.36990E-09 3.36047E-06 1.55362E-05 3.37004E-05 4.35319E-06 4.08927E-05 1.09498E-05 1.45486E-05 1.53155E-05 1.06373E-05 1.47368E-05 3.92858E-06 0 0 0.00118775 0.00107587 2.41695E-05 0.000288722 8.83630E-07 19.8871 7.08180 0 11.1233 0* 0 0* 0.00164846 0* 1.89500 0* 6.32511 0* 13.4315 0* 2.76595 0* 13.0456 0* 4.66931 0* 5.91586 0* 1.87186 0* 5.05824 0* 1.54627 0* 2.29205 0* 0 0* 0 0* 10.1366 0* 8.08731 0* 0.203325 0* 1.66102 0* 0.539343 0* 615.540 333.838* 7.25836 0* 0 0* Process Streams 27 28 29 30 Properties Phase: Total Status: Solved From Block: MIX -103 To Block: V-9108 TEG Flash Tank Solved V-8001 RTO KO Drum -- Solved PIPE -1 V-8001 RTO KO Drum Solved — SAT -1 Property Units Temperature °F 111.405 221.494 221.494 525.685 Pressure psig 51.3 3.46185 3.46185 840 Mole Fraction Vapor % 3.42255 0 96.7925 79.3819 Molecular Weight Ib/Ibmol 99.7058 23.4314 19.8781 18.0153 Molar Flow Ibmol/h 144.184 1.15109 35.8871 18.5308 Mass Flow lb/h 14376.0 26.9718 713.367 333.838 Mass Density lb/ft^3 21.9789 61.6429 0.0515204 2.26772 Specific Gravity 0.988357 Std Vapor Volumetric Flow MMSCFD 1.31317 0.0104837 0.326846 0.168772 Vapor Volumetric Flow ft^3/h 654.081 0.437549 13846.3 147.213 Std Liquid Volumetric Flow sgpm 26.2067 0.0522954 1.53780 0.667367 Liquid Volumetric Flow gpm 81.5477 0.0545516 1726.29 18.3539 Compressibility 0.0488510 0.000944200 0.958394 0.642107 , Process Streams 34 41 Composition Status: Solved Solved Phase: Total From Block: T-9104 Reflux Condenser To Block: SAT -1 MIX -103 Mass Flow lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 9816.54* 0* 1281.08* 105535* 40135.7* 31435.7* 5512.33* 14219.7* 2637.53* 2621.37* 117.817* 1203.98* 93.4683* 297.384* 0* 0* 85.2937* 45.5754* 0.990822* 5.94493* 49.0396* 67.2536* 0* 0* 14.8566 0 0.0640381 18.2453 18.8180 23.3566 4.16918 15.3045 4.05906 4.81391 1.05696 3.35890 0.852386 1.33065 0 0 5.16844 4.13009 0.104877 0.877139 0.295868 445.064 6622.08 0 Process Streams 34 41 Properties Status: Solved Solved Phase: Total From Block: - T-9104 Reflux Condenser To Block: SAT -1 MIX -103 Property Units Temperature °F 120* 96.84* Pressure psig 840* 51.3 Mole Fraction Vapor % 100 3.34979 Molecular Weight Ib/Ibmol 23.0542 99.7058 Molar Flow Ibmol/h 9332.85 72.0921 Mass Flow lb/h 215161 7188.00 Mass Density lb/ft^3 3.86985 22.7624 Specific Gravity 0.795999 Std Vapor Volumetric Flow MMSCFD 85* 0.656587 Vapor Volumetric Flow ft^3/h 55599.5 315.784 Std Liquid Volumetric Flow sgpm 1170.46 13.1034 Liquid Volumetric Flow gpm 6931.88 39.3704 Compressibility 0.818509 0.0484042 ;M Process Streams To LP To ECD /RTO Water Addition 1 Composition Status: Solved Solved Solved Solved Phase: Vapor From Block: V-9108 TEG Flash Tank V-8001 RTO KO Drum - LV-9103 To Block: MIX -102 MIX -102 Mass Flow I lb/h lb/h lb/h Ib/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 18.5900 0 0.126428 34.5957 31.3110 33.2816 5.57242 17.5635 3.44883 3.71197 0.241813 1.65950 0.158108 0.369135 0 0 0.154515 0.0660096 0.00110642 0.00642959 0.0523044 0.477169 0.000967959 0 11.1231 0 0.00164845 1.89500 6.32509 13.4315 2.76595 13.0456 4.66930 5.91584 1.87184 5.05823 1.54626 2.29204 0 0 10.1354 8.08623 0.203300 1.66073 0.539342 595.653 0.176566 0 Process Streams To LP To ECD /RTO Water Addition 1 Properties Status: Solved Solved Solved Solved Phase: Vapor From Block: V-9108 TEG Flash Tank V-8001 RTO KO Drum -- LV-9103 To Block: - MIX -102 MIX -102 Property Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow lbmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 111.405 51.3 100 30.6778 4.93478 151.388 0.339382 1.05922 0.0449441 446.071 0.694715 55.6141 0.973412 221.494 3.46185 100 19.7604 34.7360 686.395 0.0495741 0.682272 0.316362 13845.9 1.48550 1726.24 0.990122 Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow 2 2.11 3 Solved Solved Solved V-9103 Dry Gas Scrubber T-9101 Glycol Contactor T-9101 Glycol Contactor LV-9103 V-9103 Dry Gas Scrubber LCV-9101 lb/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water EG Methanol T 9786.83 0 1280.95 105498 40098.0 31389.0 5504.00 14189.1 2629.41 2611.74 115.704 1197.26 91.7639 294.723 0 0 75.0036 37.4223 0.786359 4.27677 48.4479 40.3650 1.47377 0 Process Streams 2 Properties Status: Solved Solved Solved Phase: Vapor From Block: V-9103 Dry Gas Scrubber T-9101 Glycol Contactor T-9101 Glycol Contactor To Block: LV-9103 V-9103 Dry Gas Scrubber LCV-9101 Property Units Temperature °F Pressure psig Mole Fraction Vapor % Molecular Weight Ib/Ibmol Molar Flow Ibmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 2.11 3 119.920 838 100 23.0455 9324.79 214894 3.85785 0.795699 84.9266 55703.1 1169.42 6944.81 0.818937 • Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow 4 5 6 Solved Solved Solved LCV-9101 V-9103 Dry Gas Scrubber T-9104 Reflux Section MIX -102 PIPE -1 lb/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane e Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 19.6578 0 0.126473 34.6991 31.7558 34.2277 5.75771 18.4064 3.69106 3.97079 0.277580 1.82814 0.182936 0.418311 0 0 0.202357 0.0882830 0.00150358 0.00882530 0.0598897 0.565193 0.00220460 0 9786.83 0 1280.95 105498 40098.0 31389.0 5504.00 14189.1 2629.41 2611.74 115.704 1197.26 91.7639 294.723 0 0 75.0036 37.4223 0.786359 4.27677 48.4479 40.3650 1.47377 0 11.1233 0 0.00164846 1.89500 6.32511 13.4315 2.76595 13.0456 4.66931 5.91586 1.87186 5.05824 1.54627 2.29205 0 0 10.1366 8.08731 0.203325 1.66102 0.539343 615.540 7.25836 0 Process Streams 4 Properties Status: Solved Solved Solved Phase: Vapor From Block: LCV-9101 V-9103 Dry Gas Scrubber T-9104 Reflux Section To Block: MIX -102 — PIPE -1 Property ' Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow lbmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 5 6 125.080 51.3 100 30.9659 5.03547 155.928 0.334039 1.06917 0.0458611 466.796 0.710553 58.1980 0.974924 119.920 838 100 23.0455 9324.79 214894 3.85785 0.795699 84.9266 55703.1 1169.42 6944.81 0.818937 624.983 3.5 100 19.8781 35.8871 713.367 0.0311546 0.686337 0.326846 22897.7 1.53780 2854.77 0.997410 Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 7 8 9 Solved Solved Solved SPLT-102 V-9108 TEG Flash Tank LV-9108 T-9104 Reflux Condenser E-9106 Lean/Rich Exchanger T-9104 Still Column lb/h lb/h lb/h 9.70230 0 0.0631911 17.3164 15.8288 17.0917 2.88188 9.21046 1.86348 2.02135 0.142872 0.944717 0.0941311 0.220170 0 0 0.102743 0.0452584 0.000775405 0.00455486 0.0320366 0.374659 0.00100749 0 Process Streams Properties Status: Solved Solved Solved Phase: Vapor From Block: SPLT-102 V-9108 TEG Flash Tank LV-9108 To Block: T-9104 Reflux Condenser E-9106 Lean/Rich Exchanger T-9104 Still Column Property -' Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow lbmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 9.43312 0 0.00162883 1.83187 5.80364 11.6896 2.35270 10.5337 3.40955 4.15956 0.785263 3.07981 0.568512 1.12331 0 0 1.55162 0.858215 0.0169686 0.109606 0.212868 20.1690 0.356835 0 7 125.784 51.3 100 30.9628 2.51730 77.9425 0.333584 1.06906 0.0229266 233.652 0.354928 29.1306 0.974979 8 9 247.870 4 100 33.4625 2.33238 78.0474 0.0829503 1.15537 0.0212424 940.893 0.245812 117.306 0.993285 T Process Streams Composition Status: Phase: Vapor From Block: To Block: 10 11 Solved E-9105 TEG Reboiler/Surge Tank E-9106 Lean/Rich Exchanger Solved E-9106 Lean/Rich Exchanger TEG Make -U p Mass Flow lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water EG Methanol Process Streams 10 11 Properties Phase: Vapor Status: Solved From. Block:- E-9105 TEG Reboiler/Surge Tank To Block: ` E-9106 Lean/Rich Exchanger Solved E-9106 Lean/Rich Exchanger TEG Make -Up Property Units Temperature Pressure Mole Fraction Vapor Molecular Weight Molar Flow Mass Flow Mass Density Specific Gravity Std Vapor Volumetric Flow Vapor Volumetric Flow Std Liquid Volumetric Flow Liquid Volumetric Flow Compressibility °F psig % Ib/Ibmol lbmol/h lb/h lb/ft^3 MMSCFD ft^3/h sgpm gpm Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water EG Methanol T 12 13 Solved P-9107A/B TEG Pumps AC -9102 Glycol Cooler lb/h lb/h Process Streams Properties Status: Solved Solved Phase: Vapor From Block: P-9107A/B TEG Pumps E-9105 TEG Reboiler/Surge Tank To Block: AC -9102 Glycol Cooler T-9104 Still Column Property Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow lbmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Solved E-9105 TEG Reboiler/Surge Tank T-9104 Still Column 0.00106240 0 1.06860E-09 8.52221E-06 0.000165426 0.000897974 0.000251004 0.00213129 0.00167842 0.00275717 0.00762244 0.00497897 0.00967809 0.00529267 0 0 0.511892 0.860877 0.0343402 0.448216 0.00256530 845.998 177.368 0 Compressibility 12 13 358.394 4.5 100 21.2877 48.1621 1025.26 0.0469062 0.735007 0.438642 21857.7 2.00944 2725.12 0.992335 Process Streams Composition Phase: Vapor Mass Flow Status: From Block: To Block: 14 15 Solved T-9104 Still Column E-9105 TEG Reboiler/Surge Tank lb/h Solved E-9106 Lean/Rich Exchanger LV-9108 lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol Process Streams Properties Phase: Vapor Property Temperature Pressure Mole Fracion Vapor Molecular Weight Molar Flow Mass Flow Mass Density Specific Gravity Std Vapor Volumetric Flow Vapor Volumetric Flow Std Liquid Volumetric Flow Liquid Volumetric Flow Compressibility 14 15 2.99569 0 0.00138719 1.23761 2.67910 4.15630 0.766007 2.87692 0.727512 0.823712 0.0887712 0.491509 0.0599564 0.144442 0 0 0.126469 0.0672538 0.00131125 0.00833775 0.0237563 1.41415 0.0271516 0 Status: _ Solved From Block: T-9104 Still Column To Block: E-9105 TEG Reboiler/Surge Tank Units 'F psig Ib/Ibmol lbmol/h Ib/h lb/ft^3 MMSCFD ft^3/h sgpm gpm Solved E-9106 Lean/Rich Exchanger LV-9108 250 46.3 100 37.1932 0.503246 18.7173 0.303533 1.28418 0.00458337 61.6650 0.0701923 7.68810 0.981385 Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow 16 Solved T-9104 Still Column T-9104 Reflux Condenser lb/h 17 18 Solved T-9104 Reflux Section T-9104 Still Column lb/h Solved T-9104 Reflux Condenser T-9104 Reflux Section lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2, 2,4-Tri m ethyl pentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 11.1233 0 0.00164846 1.89500 6.32511 13.4315 2.76595 13.0456 4.66931 5.91586 1.87186 5.05824 1.54627 2.29205 0 0 10.1366 8.08731 0.203325 1.66102 0.539343 615.540 7.25836 0 Process Streams Properties Phase: Vapor Property Temperature Pressure Mole Fraction Vapor Molecular Weight Molar Flow Mass Flow Mass Density Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility 16 17 11.1233 0 0.00164846 1.89500 6.32511 13.4315 2.76595 13.0456 4.66931 5.91586 1.87186 5.05824 1.54627 2.29205 0 0 10.1366 8.08731 0.203325 1.66102 0.539343 615.540 7.25836 0 18 Status: Solved - Solved Solved From Block: T-9104 Still Column T-9104 Reflux Section T-9104 Reflux Condenser To Block: T-9104 Reflux Condenser T-9104 Still Column T-9104 Reflux Section Units °F psig Ib/Ibmol Ibmol/h lb/h lb/ft^3 264.371 3.5 100 19.8781 35.8871 713.367 0.0469486 0.686337 0.326846 15194.7 1.53780 1894.40 0.991518 624.983 3.5 100 19.8781 35.8871 713.367 0.0311546 0.686337 0.326846 22897.7 1.53780 2854.77 0.997410 Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 19 20 21 22 23 Solved Solved Solved Solved Solved SPLT-102 MIX -102 TEG Make -Up RCYL-1 MIX -103 SPLT-102 RCYL-1 P-9107A/B TEG Pum lb/h lb/h lb/h lb/h 9.70230 19.4046 0 0 0.0631911 0.126382 17.3164 34.6328 15.8288 31.6575 17.0917 34.1834 2.88188 5.76377 9.21046 18.4209 1.86348 3.72696 2.02135 4.04270 0.142872 0.285744 0.944717 1.88943 0.0941311 0.188262 0.220170 0.440340 0 0 0 0 0.102743 0.205486 0.0452584 0.0905169 0.000775405 0.00155081 0.00455486 0.00910971 0.0320366 0.0640732 0.374659 0.749318 0.00100749 0.00201498 0 0 Process Streams Properties Status: Solved Solved Solved " Solved Solved Phase: Vapor From Block: SPLT-102 MIX -102 TEG Make -Up RCYL-1 To Block: MIX -103 SPLT-102 RCYL-1 - P-9107A/B TEG Pumps TEG Make -Up Property Units Temperature °F Pressure psig Mole Fraction Vapor Molecular Weight Ib/Ibmol Molar Flow Ibmol/h Mass Flow lb/h Mass Density Ib/ft^3 Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility P s TEG Make -Up lb/h 19 20 21 22 23 125.784 125.784 51.3 51.3 100 100 30.9628 30.9628 2.51730 5.03459 77.9425 155.885 0.333584 0.333584 1.06906 1.06906 0.0229266 0.0458531 233.652 467.303 0.354928 0.709856 29.1306 58.2612 0.974979 0.974979 Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentame Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 24 25 26 Solved Solved Solved TEG Make -Up AC -9102 Glycol Cooler SAT -1 T-9101 Glycol Contactor T-9101 Glycol Contactor lb/h Ib/h Ib/h 9816.54 0 1281.08 105535 40135.7 31435.7 5512.33 14219.7 2637.53 2621.37 117.817 1203.98 93.4683 297.384 0 0 85.2937 45.5754 0.990822 5.94493 49.0396 401.092 0 0 Process Streams 24 25 26 Properties Status: Solved Phase: Vapor From Block: TEG Make -Up To Block: - Property Units Solved Solved AC -9102 Glycol Cooler SAT -1 T-9101 Glycol Contactor T-9101 Glycol Contactor. Temperature Pressure Mole Fraction Vapor Molecular Weight Molar Flow Mass Flow Mass Density Specific Gravity Std Vapor Volumetric Flow MMSCFD Vapor Volumetric Flow ft^3/h Std Liquid Volumetric Flow sgpm Liquid Volumetric Flow gpm Compressibility °F psig Ib/Ibmol Ibmol/h lb/h Ib/ft^3 120 840 100 23.0442 9351.38 215495 3.86779 0.795654 85.1688 55715.3 1171.13 6946.33 0.818590 • Process Streams Composition Status: Phase: Vapor From Block: To Block: Mass Flow 27 28 29 30 i V Solved Solved Solved Solved MIX -103 V-8001 RTO KO Drum PIPE -1 V-9108 TEG Flash Tank V-8001 RTO KO Drum SAT -1 lb/h lb/h lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2, 2, 4-T ri m eth yl p e ntan e Benzene Toluene Ethylbenzene o-Xylene Octane Water TEG Methanol 18.5900 0 0.126428 34.5957 31.3110 33.2816 5.57242 17.5635 3.44883 3.71197 0.241813 1.65950 0.158108 0.369135 0 0 0.154515 0.0660096 0.00110642 0.00642959 0.0523044 0.477169 0.000967959 0 11.1231 0 0 0 0.00164845 0 1.89500 0 6.32509 0 13.4315 0 2.76595 0 13.0456 0 4.66930 0 5.91584 0 1.87184 0 5.05823 0 1.54626 0 2.29204 0 0 0 0 0 10.1354 0 8.08623 0 0.203300 0 1.66073 0 0.539342 0 595.653 265.007 0.176566 0 0 0 Process Streams 27 28 29 30 Properties Phase: Vapor Status: Solved Solved From Block: MIX -103 V-8001 RTO KO Drum To Block: , V-9108 TEG Flash Tank -- Solved PIPE -1 V-8001 RTO KO Drum Solved — SAT -1 Property Units Temperature °F 111.405 221.494 525.685 Pressure psig 51.3 3.46185 840 Mole Fraction Vapor % 100 100 100 Molecular Weight Ib/Ibmol 30.6778 19.7604 18.0153 Molar Flow lbmol/h 4.93478 34.7360 14.7101 Mass Flow lb/h 151.388 686.395 265.007 Mass Density Ib/ft^3 0.339382 0.0495741 1.81808 Specific Gravity 1.05922 0.682272 0.622019 Std Vapor Volumetric Flow MMSCFD 0.0449441 0.316362 0.133974 Vapor Volumetric Flow ft^3/h 446.071 13845.9 145.762 Std Liquid Volumetric Flow sgpm 0.694715 1.48550 0.529768 Liquid Volumetric Flow gpm 55.6141 1726.24 18.1730 Compressibility 0.973412 0.990122 0.800912 Process Streams 34 41 Composition Status: Solved Solved Phase: Vapor From Block: — T-9104 Reflux Condenser To Block: SAT -1 MIX -103 Mass Flow lb/h lb/h Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane i-Butane n -Butane i-Pentane n -Pentane Cyclopentane Hexane Cyclohexane Heptane Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Fthylbenzene o-Xylene Octane Water TEG Methanol 9816.54 0 1281.08 105535 40135.7 31435.7 5512.33 14219.7 2637.53 2621.37 117.817 1203.98 93.4683 297.384 0 0 85.2937 45.5754 0.990822 5.94493 49.0396 67.2536 0 0 8.83701 0 0.0632356 17.2758 15.4557 16.1216 2.67629 8.30276 1.57543 1.68109 0.100479 0.715182 0.0651875 0.151346 0 0 0.0566905 0.0234398 0.000383665 0.00220499 0.0208613 0.146772 0.000220350 0 Process Streams 34 41 Properties Phase: Vapor Status: Solved From Block: -- To Block: SAT -1 Solved T-9104 Reflux Condenser MIX -103 Property Units . . Temperature °F 120 96.84 Pressure psig 840 51.3 Mole Fraction Vapor %° 100 100 Molecular Weight Ib/Ibmol 23.0542 30.3411 Molar Flow lbmol/h 9332.85 2.41493 Mass Flow lb/h 215161 73.2717 Mass Density lb/ft^3 3.86985 0.345026 Specific Gravity 0.795999 1.04760 Std Vapor Volumetric Flow MMSCFD 85 0.0219943 Vapor Volumetric Flow ft^3/h 55599.5 212.366 Std Liquid Volumetric Flow sgpm 1170.46 0.339061 Liquid Volumetric Flow gpm 6931.88 26.4768 Compressibility 0.818509 0.971762 PROJECT NO. : COMPANY NAME : ACCOUNT NO. : PRODUCER : LEASE NO. : NAME/DESCRIP ***FIELD DATA*** SAMPLE PRES. : VAPOR PRES. : COMMENTS . Componet Helium Hydrogen Carbon Dioxide Nitrogen Methane Ethane Propane Isobutane n -Butane Isopentane n -Pentane Cyclopentane n -Hexane Cyclohexane Other Hexanes Heptanes Methycyclohexane 2,2,4 Trimethylpentane Benzene Toluene Ethylbenzene Xylenes C8+ Heavies Subtotal Oxygen/Argon Total 303-637-0150 365 S. MAIN ST. BRIGHTON, CO 80601 EXTENDED NATURAL GAS ANALYSIS (*DHA) GLYCALC INFORMATION 201412030 DCP MIDSTREAM BILLING CODE: G031 ROGGEN INLET 09:45 874 SPOT; NO PROBE ANALYSIS NO. : ANALYSIS DATE: SAMPLE DATE : CYLINDER NO. : SAMPLED BY : SAMPLE TEMP. : AMBIENT TEMP.: GRAVITY . Mole % Wt % 0.01 0.00 0.00 0.00 2.39 4.56 0.49 0.60 70.48710 49.04450 14.3020 18.6522 7.6386 14.6091 1.0162 2.5617 2.6214 6.6083 0.3917 1.2258 0.3893 1.2182 0.0180 0.0547 0.0510 0.1906 0.0119 0.0435 0.0987 0.3672 0.0318 0.1370 0.0000 0.0000 0.0000 0.0000 0.0117 0.0396 0.0053 0.0212 0.0001 0.0005 0.0006 0.0028 0.0046 0.0231 99.97000 99.96000 0.03 0.04 100.00000 100.00000 THE DATA PRESENTED HEREIN HAS BEEN ACQUARED THROUGH JUDICIOUS APPLICATION OF CURRENT STATE -OF -THE ART ANALYTICAL TECHNIQUES. THE APPLICATIONS OF THIS INFORMATION IS THE RESPONSIBILITY OF THE USER. EMPACT ANALYTICAL SYSTEMS, INC. ASSUMES NO RESPONSIBILITY FOR ACCURACY OF THE REPORTED INFORMATION NOR ANY CONSEQUENCES OF IT'S APPLICATION. 03 DECEMBER 5, 2014 DECEMBER 3, 2014 0652 SAM WOOD 76 • Baseline Actual Emissions for P-033 and P-136 DCP Operating Company, LP Roggen Natural Gas Processing Plant Regen Dehy - P033 I Inlet TEG Dehy - P136 VOC Emission? 1 VOC Emission? NOx Emission? CO Emission? tons/mo 2 -year average VOC (tons) 2 -year average tons/mo 2 -year average tons/mo 2 -year average July -11 0.11 - 0.39 - 0.00 - - 0.00 August -11 0.08 - 0.38 - 0.00 - 0.00 — September -11 0.06 - 0.41 - 0.13 -- 0.72 October -11 0.05 - 0.49 - 0.18 -- 0.97 — November -11 0.07 - 0.43 - 0.20 - 1.07 — December -11 0.03 -- 0.40 - 0.18 - 0.96 — January 0.03 - 0.44 -- 0.17 - 0.94 — -12 0.03 - 0.39 - 0.15 0.81 — Februa -12 March 0.03 - 0.46 - 0.22 -- 1.19 — -12 April 0.02 - 0.42 - 0.18 - 0.97 - -12 May -12 0.03 - 0.44 - 0.21 — 1.14 — June -12 0.03 - 0.41 - 0.18 -- 1.00 — July -12 0.03 - 0.46 - 0.21 --1.14 - 0.03 - 0.46 - 0.20 — 1.11 — August -12 - 0.44 - 0.20 — 1.08 — September -12 October 0.03 0.03 - 0.45 - 0.23 -- 1.24 — -12 November -12 0.03 - 0.43 - 0.22 — 1.19 — December -12 0.02 - 1.64 - 0.22 — 1.19 — January -13 0.06 -I 1.48 - 0.22 — 1.17 — February-13 0.05 -I 1.25 - 0.16 0.86 -- March 0.06 -- 1.37 - 0.15 -- 0.82 — -13 0.07 --1 1.34 - 0.18 - 0.98 — May -13 May 0.07 -I 0.36 - 0.05 -- 0.26 — -13 June 0.06 0.561 0.00 7.36 0.00 1.91 0.00 10.42 -13 July -13 0.05 0.521 0.00 7.17 0.00 1,91 0,00 10.42 August 0.05 0.511 0.00 6.98 0.00 - 1.91 0.00 10.42 -13 0.06 0.511 0.00 6.78 0.00 1.85 0.00 10.06 September -13 October 0.05 0.511 0.00 6.53 0.00 1.76 0.00 9.57 -13 November -13 0.05 0.50) 0.00 6.32 0.00 1.66 0.00 9.03 8.55 December -13 0.26 0.611 0.00 6.11 0.00 1.57 0.00 0.24 0.721 0.00 5.90 0.00 1.48 0.00 8.08 January -14 February -14 0.17 0.791 0.00 5.70 0.00 1,41 0.00 7.67 0.23 0.891 0.00 5.47 0.00 1.30 0.00 7.08 March -14 April 0.20 0.981 0.00 5.26 0.00 1.21 0.00 6.59 -14 May -14 0.20 1.071 0.00 5.04 0.00 1.11 0.00 6.02 5.52 June 0.14 1.121 0.00 4.84 0.00 1.02 0.00 -14 Jul -14 0.22 1.221 0.0D 4.61 0.00 0.91 0.00 4.95 4.40 August 0.28 1.341 0.00 4.38 0.00 0.61 0.00 -14 September -14 0.26 1.461 0.00 4.16 0.00 0.71 0.00 3.85 3.23 - October - 0.04 1.46i - 0.00. 3.93 0.00 0.59 0.00 -14 0.00 1.451 0.00 3.72 0.00 0.49 0.00 2.64 November -14 December -14 0.01 1.441 0.00 2.90 0.00 0.38 - 0.00 2.04 0.01 1.421 0.00 2.16 0.00 0.27 0.00 1.46 January -15 0.00 1.391 0.65 1.86 0.07 0.22 0.36 1.21 February -15 0.00 1.361 0.73 1.54 0.08 0.19 0.42 1.01 March -15 1.331 0.71 1.22 0.07 0.13 0.40 0.72 April -15 May 0.00 0.00 1.29) 0.43 1.26 0.03 0.13 0.18 0.68 -15 June 0.00 1.261 0.00 1,26 0.00 0.13 0.00 0.68 -15 July 0.00 1.241 0.00 1.26 0.00 0.13 0.00 0.68 -15 August 0.00 1.211 0.00 1.26 0.00 0.13 0.00 0.68 -15 0.00 1.181 0.03 1.28 0.01 0.13 0.08 0.72 September -15 0.00 1.161 0.17 1.36 0.06 0.17 0.35 0.90 October -15 0.00 1.131 0.13 1.42 0.06 0.19 0.30 1.05 November -15 December -15 0.00 1.001 0.16 1.50 0.06 0.22 0.34 1.22 Janus -16 0.00 0.881 0.16 1.58 0.06 0.26 0.34 1.39 1.65 0.06 0.28 0.31 1.55 1.58 February -16 0,00 0.801 0.13 March 0.00 0.681 0.18 1.74 0.01 0.29 0.06 -16 April 0.00 0.58) 0.06 1.77 0.01 0.29 0.03 1.59 -16 May 0.00 0.481 0.01 1.77 0.00 0.29 0.00 1.60 -16 June 0.00 0.411 0.00 1.77 0,00 0.29 0.00 1.60 -16 July 0.00 0.301 0,00 1.77 0.00 0.29 0.00 1.60 -16 August -16 0.00 0.161 0.00 1.77 0.00 0.29 0.00 1.60 0.00 0.031 0.00 1.77 0.00 0.29 0.00 1.60 September -16 0.00 0.01) 0.00 1.77 0.00 0.29 0.00 1.60 October -16 November 0.00 0.011 0.00 1.77 0.00 0.29 0.00 1.60 -16 December 0.00 0.001 0.05 1.80 0.00 0.30 0.02 1.61 -16 January -17 0.00 0.001 0.17 1.88 0.01 0.30 0.04 1.63 0.00 0.001 0.19 1.65 0.01 0.27 0.04 1.47 February -17 March 0.00 0.00) 0.19 1.38 0.01 0.24 0.04 1.28 -17 April - 0.00 0.001 0.00 1.02 0.00 0.20 0.00 1.08 -17 May 0.00 0.001 0.00 0.81 0.00 0.18 0.00 0.99 -17 June 0.00 0.001 0.00 0.81 0.00 0.18 0.00 0.99 0.99 -17 July -17 0.00 0,001 0.00 0.81 0.00 0.18 0.00 'Actual emissions for P-033 and P-136 taken from Roggen 12 -month rolling totals compliance workbook. =tit Form APCD-102 Company Name: DCP Operating Company, LP Source Name: Roggen Gas Plant Source AIRS ID: 123/0049 Colorado Department of Public Health and Environment Air Pollution Control Division Facility Wide Emissions Inventory Form Ver. April, 2015 Uncontrolled Potential to Emit (PTE) Controlled Potential to Emit (PTE) Criteria (TPY) I HAPs (Ibs/yr) Criteria (TOY) I HAPs ( bs/yr) AIRS ID Equipment Description TSP PM10 PM2.5 502 NOz VOC CO i HCHO Acetal Acro BZ Tol EB Xyl n -Hex Meth 224-TMP TSP- PMIO PM23 SO2 Non VOL CO I HCHO Acetal Acro BZ Tol EB Xyl ` n -Hex Meth 224-TMP 123/0049/101 Engine C-154/0001/5001 0.72 0.72 0.72 0.02 116.84 15.93 84.98 1.521 207 195 117 41 2 14 0 227 0 0.72 0.72 0.72 0.02 21.24 10.62 21.24 I 365 104 98 59 21 I 7 0 114 0 123/0049/102 Engine C-155/P002/S002 0.61 0.61 0.61 0.02 85.61 11.67 I 62.26 1,293 176 166 100 35 2 12 0 193 0 0.61 061 0.61 0.02 16.34 7.78 16.34 310 I 88 83 50 d8 1 6 0 _ 97 0 123/0049/103 Engine C-159/0003/5003 0.94 0.94 0.94 0.03 169.47 26.07 117.32 I 1.992 271 256 153 54 2 19 0 297 0 0.94 0.94 0.94 0.03 26.07 13.04 27.38 478 I 136 128 77 27 - 1 9 0 149 0 123/0049/107 Engine C -157/0007/S007 0.61 0.61 0.61 0.02 . 85.61 11.67 62.26 I 1,293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 16.34 7.78 16.34 310 88 83 50 18 1 6 0 97 0 123/0049/108 Engine C-I61/P008/S008 0.94 0.94 0.94 0.03 143.40 19.55 104.29 I 1,992 271 256 153 54 2 19 0 297 0 0.94 0.94 0.94 0.03 13.04 9.13 26.07 I 478 136 128 77 27 I 9 0 149 0 123/0049/110 Engine C -158/P010/5010 0.66 0.66 0.66 0.02 97.30 13.27 70.76 I 1,401 191 180 108 38 2 13 0 209 0 0,66 0.66 0.66 0.02 18.57 8.85 18.57 I 336 95 90 54 19 1 7 0 105 0 123/0049/113 Engine C-160/0013/$013 0:61 0.61 0.61 0.02 85.61 11.67 62.26 I 1.293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 16.34 7.78 16.34 I 310 88 83 50 18 1 6 0 97 0 123/0049/114 Engine C-156/P014/S014 0.61 0.61 0.61 0.02 85.61 11.67 62.26 I 1,293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 7.78 5.45 1557 I 310 88 83 50 18 I 6 0 97 0 123/0049/115 Engine C-223/P015/S015 0.53 0.53 0.53 0.02 61.64 9.72 101.02 I 1,113 152 143 86 30 1 14 0 227 0 0.53 0.53 0.53 0.02 14.60 6.95 14.60 I 267 76 98 59 15 1 5 0 83 0 123/0049/117 Engine C -225/0017/S017 0.54 0.54 0.54 0.02 63.63 10.04 104.28 I 1.149 156 147 89 31 1 11 0 172 0 034 0.54 0.54 0.02 7.73 5.41 15.45 I 276 78 74 44 16 1 5 0 86 0 123/0049/119 Engine C-227/P019/S019 0.53 0.53 0.53 0.02 104.29 9.73 100.81 I 1.113 152 143 86 30 1 11 0 166 0 0.53 _ 0.53 053 0.02 13.91 6.95 14.60 I 267 76 71 43 15 I 5 0 83 0 123/0049/122 P025/FUGITIVES 0.00 0.00 0,00 0.00 0.00 114.07 0.00 I 0 0 0 913 215 82 154 • 1,788 0 0 0,00 0.00 0.00 0.00 0.00 33.54 0.00 I 0 0 0 268 63 24 45 524 0 0 123/0049/125 P039, Stablized Condensate Tanks 0.00 0.00 0.00 0,00 0.00 28.84 0.00 0 0 0 771 2,571 200 1,857 5.600 0 0 0.00 0.00 0.00 0.00 0.00 1.44 0.00 I 0 0 0 39 129 - 10 93 280 0 0 123/0049/126 F029, Condensate Truck Loadout 0.00 0.00 0.00 0.00 0.00 30.84 I, 0.00 0 0 0 916 2.749 305 2.138 6.110 0 0 000 0.00 0.00 0.00 0.00 30.84 0.00 I 0 0 0 916 2.749 305 2.138 6.110 0 0 123/0049/129 H037, Hot Oil Heater 0.26 0.26 0.26 0.02 3.45 0.19 2.90 I 5 0 0 0 0 0 0 124 0 0 0.26 0.26 0.26 0.02 3.45 0.19 2.90 5 I 0 0 0 0 0 0 124 0 0 123/0049/130 P-033, Regeo Dehy 0.00 0.00 0.00 • 0.00- 0.06 49.10 0.17 I 0 0 0 3,378 3.761 138 1.247 1.151 0 0 0.00 0.00 0.00 0.00 0.06 1.05 0.17 0 0 0 228 256 9 86 44 0 0 123/0049/133 F031, Pressorized Liquids Loadout 0.00 0 00 0.00 0.00 000 5.00 0.00 I 0 0 0 0 0 0 0 0 0 0 000 000 0.00 0.00 0.00 5.00 0.00 I 0 0 0 0 0 0 0 0 0 0 123/0049/134 Engine C-181 0.98 0.98 0.98 0.03 156.99 21,41 114.18 I 2,070 282 266 160 56 3 20 0 309 0 0.98 0.98 0.98 0.03 14.27 9.99 28.54 I 497 141 133 80 28 1 10 0 155 0 123/0049/136 P-136, Inlet TEG Dehy 0.00 0.00 0.00 0.00 2.63 663.37 11.97 I 0 0 0 99.154 78,555 1,970 16.065 64.732 0 0 0.00 0.00 0.00 0.00 2.63 23.74 11.97 I 0 0 0 6,739 5,376 135 1,104 3.363 0 0 123/0049/137 P-137. Amine Unit 0.00 0.00 0.00 0.00 0.00 282.96 0.00 I 0 0 0 50.789 33,225 1,074 174 6,509 0 0 0.00 0,00 0.00 30.04 0.85 2.32 3.86 I 0 0 0 1,436 950 31 174 21 288 • 0 123/0049/138 Hot Oil Heater 107 1.07 1.07 008 7.02 0.65 11.79 I 0 0 0 0 0 0 0 505 0 0 1,07 1.07 107 0.08 7.02 0.65 11.79 I 0 0 0 0 0 0 0 505 "0 0 123/0049/140 Engine C-192 0.98 0.98 0.98 0.03 156.99 21.41 114.18 I 2.076 282 266 160 56 3 20 0 310 0 0.98 0.98 0.98 0.03 14.27 9,99 28.54 I 1,038 141 133 80 28 I 10 0 155 0 TBD Flare ' 0.00 0.00 0.00 0.01 1.55 190.00 6,84 I 0 0 0 406 217 0 0 2.034 0 0 0,00 0.00 0.00 0.01 1,55 9.50 6.84 I 0 0 0 20 11 0 0 101 A 0 0 Permitted Sources Subtotal = APEN Only - Permit Exempt Sources 10.60 10.60 10.60 0.40 1427.71 1558.86 1194.55 I 19,604 2,667 2,514 157,839 121,828 3,794 21,826 88,553 2,986 0 10.60 10.60 10.60 30.44 216.07 217.99 297.14 I 5,249 1,334 1,283 10,417 9,801 527 3,734 11,073 1,751 0 I I I I I I I I I I I I APEN Only Subtotal = APEN Exempt / Insignificant sources 0.0 0.0 0.0 0.0 0.0 0.0 0.0 i 0 0 0 0 0 0 0 0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 i 0 0 0 0 0 0 0 0 0 0 APEN Exempt / Insignificant sources 1.5 . 1.3 3.8 T 139 157 176 1.5 1.3 3.8 I 139 157 176 I I I I I I I I I I Insignificant Subtotal = Total, All Sources = 0.0 0.0 0.0 0.0 1.5 1.3 3.8 I 0 0 0 139 0 0 0 157 176 0 0.0 0.0 0.0 0.0 1.5 1.3 3.8 I 0 0 0 139 0 0 0 - 157 176 0 10.6 10.6 10.6 0.4 1429.2 1560.1 r 1198.4 119,604 2,667 2,514 157,978 121,828 3,794 21,826 88,710 3,162 0 I 10.6 10.6 10.6 30.4 217.6 219.3 I 301.0 I 5,249 1,334 1,283 10,555 9,801 527 13,7341 11,230 1,927 0 Uncontrolled Uncontrolled HAPs Total, Summary All HAPs Controlled HAPs Summary Controlled Total, All HAPs (TPY) = 9.8 1.3 1.3 79.0 60.9 1.9 10.9 44.4 1.6 0.0 (TPY) =I 2.6 I 0.7 I 0.6 I 5.3 I 4.9 I 0.3 I 1.9 I 5.6 I 1.0 I 0.0 I (TPY) =t 211.0 (TPY) _' 22.8 Footnotes: 1. This form should be completed to include both existing sources and all proposed new or modifications to existing emissions sources 2. If the emissions source is new then enter "proposed" under the Permit No. and AIRS ID data columns 3. HAP abbreviations include: BZ =Benzene 224-TMP = 2,2,4-Trimethylpentane Tol = Toluene Acetal = Acetaldehyde EB = Ethylbenzene Acro = Acrolein Xyl = Xylene n -Hex = n -Hexane HCHO = Formaldehyde Meth = Methanol 4. APEN Exempt/Insignificant Sources should be included when warranted. Company Name 11/9/2017 - Page 1 of 1 Attachment E: Regulatory Analysis for changes to P-136 ROGGEN GAS PLANT REGULATORY ANALYSIS UNIT P-136 1.0 Federal New Source Review Please see the cover letter of this application for a full analysis of Federal New Source Review requirements. 2.0 Federal Operating Permits Sources are required to obtain a Part 70 Title V Operating Permit if they are a major source of emissions. A major source is defined as a stationary source that emits or has the potential to emit 10 tpy of any single hazardous air pollutant (HAP), 25 tpy of total HAPs, or 100 tpy of any regulated air pollutant. Fugitive criteria pollutant emissions are included in determining major source status only if the facility is a listed source type. A gas processing facility is not a listed source type and fugitive emissions are not included in determining major source status. This facility is already defined as a major source for Title V Operating Permits, and currently operates under Title V permit 95OPWE055. There will be no change in Title V applicability as a result of the proposed changes to unit P-136. 3.0 New Source Performance Standards Unit P-136 is an existing source, with no applicable NSPS requirements. There will be no change in NSPS applicability for unit P-136 as a result of the proposed changes in this application. 4.0 National Emission Standards for Hazardous Air Pollutants (NESHAP) 40 CFR Part 63 Subpart HH - National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities Unit P-136 is subject to the area source requirements of 40 CFR 63, Subpart HH, as detailed in Condition 25 of Construction Permit 10WE1659. There are no changes in applicable NESHAP Subpart HH requirements caused by this permit modification. This unit will continue to comply with all applicable Subpart HH requirements. 5.0 State Regulations Regulation 1, Section h A.1. All new or modified sources are Regulation 2. Odor Emission All new or modified sources are Colorado Regulation 2. limited to emissions with a maximum opacity of 20%. subject to the general odor emission provisions detailed in Regulation 3, Part A, Section II Regulation 3, Part A, Section II describes when an Air Pollutant Emission Notice (APEN) must be submitted for new, modified, and existing sources. An APEN is included in this application for updated emissions from unit P-136, based on a representative model developed for this unit in Promax. Regulation 3, Part B Regulation 3, Part B describes the requirements for Construction Permits. This application requests a modification to existing emission sources. Roggen Gas Plant is located in an ozone nonattainment area and thus the equipment modified in this application is subject to RACT requirements. Please see Attachment J for RACT determinations for unit P-136. Regulation 3, Part C Regulation 3, Part C describes the requirements for Operating Permits. This modification application requests changes to the active operating permit for this facility, 95OPWE055. Regulation 3, Part D Regulation 3, Part D describes the requirements for major stationary source new source review and prevention of significant deterioration. This facility is not subject to new source review at this time. Please refer to the cover letter of this application for a detailed analysis of NANSR and PSD requirements. Regulation 6 Regulation 6 incorporates by reference the EPA's New Source Performance Standards (NSPS). There are no newly applicable NSPS requirements based upon the proposed modifications to unit P-136. Regulation 7, Section XII.H Regulation 7, Section XII describes requirements for VOC emissions from oil and gas operations located in an ozone non -attainment area. This section applies to natural gas processing plants, including Roggen. The following emission reduction requirement detailed in XII.H.1. applies to the natural gas dehydrator P-136: ■ (State Only) Beginning January 30, 2009, 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, drip station or gas processing plant in any Ozone Nonattainment or Attainment/Maintenance Area and subject to control requirements pursuant to Section XII.H.3., shall reduce uncontrolled actual emissions of volatile organic compounds by at least 90 percent on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. Additionally, this unit is subject to the Monitoring and Recordkeeping requirements detailed in XII.H.5, as well as the Reporting requirements detailed in XII.H.6. Regulation 7, Section XVII Regulation 7, Section XVII describes statewide requirements for oil and gas operations and natural gas -fired reciprocating internal combustion engines. This section applies to atmospheric condensate storage tanks, glycol natural gas dehydrators, and natural gas fired reciprocating internal combustion engines. The following sections apply due to the modifications requested in this package: • General Provisions under XVII.B • The following emission reduction requirements detailed in XVII.D apply to the natural gas dehydrator P-136: o Beginning May 1, 2015, still vents and vents from any flash separator or flash tank on a glycol natural gas dehydrator located at an oil and gas exploration and production operation, natural gas compressor station, or gas processing plant subject to control requirements pursuant to Section XVII.D.4., shall reduce uncontrolled actual emissions of hydrocarbons by at least 95 percent on a rolling twelve-month basis through the use of a condenser or air pollution control equipment. If a combustion device is used, it shall have a design destruction efficiency of at least 98% for hydrocarbons. Regulation 8 Regulation 8 incorporates by reference the EPA's NESHAP standards in 40 CFR 61 and 40 CFR 63. A stated above, the natural gas dehydrator is already subject to 40 CFR 63, Subpart HH. No additional NESHAPs are applicable to the modifications discussed. ROGGEN GAS PLANT RACT REQUIREMENTS The sources at Roggen Gas Plant are subject to RACT requirements for NOX and VOC emissions, due to their location in the Denver ozone non -attainment area. RACT requirements for unit P-136 are discussed below: Inlet TEG Dehydration Unit (P-136) • Still vent overhead emissions of VOC's will be controlled through the use of an enclosed combustor (ECD) to achieve 95% destruction efficiency. The ECD will have a maximum annual downtime of 2.0%, during which time still vent overhead emissions will be vented to atmosphere. • Still vent overhead emissions of VOC's can be alternatively controlled through the use of a regenerative thermal oxidizer (RTO) as a backup control device. This control device only operates when the Amine Unit P-137 at this facility is online. The RTO achieves a 97% destruction efficiency, and has no associated annual downtime. • Flash gas emissions are recycled back to the inlet via a closed loop system with an uptime efficiency of 100%. Attachment G: Redlined Title V Compliance Assurance Monitoring (CAM) Plans P-136 Inlet TEG Dehy, AIRS ID: 123/0049/136 P-137 Amine Unit, AIRS ID: 123/0049/137 Compliance Assurance Monitoring Plan — Amine Sweetening Unit and Glycol Dehydrator I. Background a. Emission Unit Description: The emissions from the amine sweetening unit and the TEG dehydration unit are controlled with the same thermal oxidizer. The pre control VOC emissions from the units are above the major source threshold. Since both pollutant specific emission units have the same control device and similar emission limitations, the following CAM plan applies to both emission units. The emissions from the amine sweetening unit P-137 (AIRS 137) are controlled with a regenerative thermal oxidizer (RTO). The pre -control VOC emissions from unit P-137 are above the major source threshold. The following CAM plan applies to unit P-137 as a result of the pre -control emission levels. b. Applicable Regulation, Emission Limit, Monitoring Requirements: TEG Dehydration Unit (P136): Regulations: Operating Permit Condition 4.1 Emission Limitations: VOC 21.6 tons/yr Amine Unit (P137): Regulations: Emission Limitations: Uncontrolled Emissions: c. Control Technology: Regenerative Thermal Oxidizer Operating Permit Condition 5.1 VOC 2.3 tons/yr VOC 282.5 tons/yr : 8r II. Monitoring Approach I. Indicator Measurement Approach Combustion Chamber Temperature The outlet temperature is measured with a thermocouple. II. Indicator Range An excursion is any temperature reading below 1450°F. Excursions trigger an inspection and corrective action. III. Performance Criteria a. Data Representativeness Temperature is measured at the outlet of the combustion chamber. The minimum accuracy is +/- 5 °F. b. Verification of Operational Status Thermocouple manufacturer guarantee. c. QA/QC Practices/Criteria Annual calibration. d. Monitoring Frequency Daily. e. Data Collection Procedures Temperature automatically or manually recorded daily if operating. f. Averaging Time None III. Justification a. Background: The pollutant specific emission units are is an amine unit and a dehydration unit, which functions to remove CO2 and water vapor from the gas stream; respectively. Flash emissions from the amine unit flash tank are routed to a vapor recovery unit the plant inlet using a closed loop system with 100% efficiency and the still vent emissions are routed to the thermal oxidizer b. Rational for Selection of Performance Indicators and Indicator Ranges: The destruction of VOC is dependent upon combustion. The combustion chamber of the thermal oxidizer must meet a minimum temperature in order to achieve optimal combustion. The Division has approved the use of 1450°F as a minimum combustion chamber temperature to monitor thermal oxidizer performance. The Division has found that operating the oxidizer above this temperature results in efficient destruction of VOC. iN Compliance Assurance Monitoring Plan — Glycol Dehydrator I. Background a. Emission Unit Description: The emissions from the inlet TEG dehydration unit P-136 (AIRS 136) are controlled with either an enclosed combustor (ECD) or the same regenerative thermal oxidizer (RTO) used as the primary control device for the Amine Unit P- 137. The RTO is only online when unit P-137 is online, and can only act as a control device for unit P-136 during these periods. Thus, the ECD is considered the primary control device for unit P-136. The pre -control VOC emissions from unit P-136 are above the major source threshold. The following CAM plan applies to unit P-136 as a result of the pre -control emission levels. The monitoring requirements for the ECD will apply during all ECD operation, and the monitoring requirements for the RTO will apply during any potential RTO operation. b. Applicable Regulation, Emission Limit, Monitoring Requirements: TEG Dehydration Unit (P136): Regulations: Emission Limitations: Uncontrolled Emissions: c. Control Technology: Operating Permit Condition 4.1 VOC 23.7 tons/yr VOC 663.4 tons/yr Still vent routed to enclosed combustor (ECD) with DRE of 95.0% as primary control device. This ECD is permitted 2.0% annual downtime for maintenance and malfunctions, during which time the P-136 still vent shall vent to atmosphere. Still vent may be routed to RTO as a backup control device when the RTO is online. II. Monitoring Approach Indicator No. 1 Indicator No. 2 I. Indicator Measurement Approach Enclosed Combustor RTO - Combustion Chamber Temperature Presence of a flame is continuously monitored with thermocouple or equivalent temperature sensing device. Device senses heat and when there is an absence of a flame, then an alarm is sent to the control room. This enclosed combustor is permitted 2% annual downtime, during which the presence of a flame is not required. The outlet temperature is measured with a thermocouple. II. Indicator Range Any absence of a flame, apart from during periods of permitted downtime, will trigger an investigation to determine the problem and to perform corrective action, record keeping relating to the problem, and reporting of the problem when necessary. An excursion is any temperature,reading below 1450°F. Excursions trigger an inspection and corrective action. III. Performance Criteria i a. Data Representativeness i Device sensing heat will determine the presence or absence of the flame. Temperature is measured at the outlet of the combustion chamber. The minimum accuracy is +/- 5 °F. b. Verification of Operational Status The observation of the presence of a flame will indicate that the device is operational. Thermocouple manufacturer guarantee. c. QA/QC Practices/Criteria Sensor will be calibrated and maintained. Annual calibration. d. Monitoring Frequency Heat sensor will be monitored continuously. Daily. e. Data Collection Procedures Excursions and any adjustments or repairs made to the enclosed combustor following an excursion shall be recorded in a log. Temperature automatically or manually recorded daily if operating. f. Averaging Time i Heat sensor will operate continuously and averaging will not be necessary. None III. Justification a. Background: The pollutant specific emission unit is a dehydration unit, which functions to remove water vapor from the gas stream. Flash emissions from the inlet dehydrator flash tank are routed to the plant inlet using a closed loop system with 100% efficiency and the still vent emissions are routed primarily to the enclosed combustor. The RTO can be used as a backup control device when the amine unit P-137 is also operating. b. Rational for Selection of Performance Indicators and Indicator Ranges: The destruction of VOC is dependent upon combustion. ECD: The enclosed combustor has a manufacturer's guaranteed VOC destruction efficiency of 98% when operational. The Division has accepted a VOC destruction efficiency of 95% for enclosed combustors with a 98% manufacturer's guarantee. The presence of a flame indicates the ECD is operational. In order to ensure the ECD is operating at all times that emissions are vented to it, it is continuously monitored for the presence of heat / a flame. RTO: The combustion chamber of the thermal oxidizer must meet a minimum temperature in order to achieve optimal combustion. The Division has approved the use of 1450°F as a minimum combustion chamber temperature to monitor thermal oxidizer performance. The Division has found that operating the oxidizer above this temperature results in efficient destruction of VOC. dEp Midstream DCP Midstream 370 17"' St., Suite 2500 Denver, CO 80202 (303) 605-2039 www.dcpmidstream.com November 07, 2018 UPS Tracking No. 1Z F46 915 02 9921 2290 Colorado Department of Public Health and Environment Air Pollution Control Division ATTN: Elie Schuchardt 4300 Cherry Creek Drive South Denver, CO 80246-1530 Re: Roggen Natural Gas Processing Plant Title V Modification: 95OPWE055 AIRS ID 123/0049 - 2018 Dear Ms. Schuchardt: DCP Operating Company, LP ("DCP") is submitting the attached operating permit modification application for the Roggen Natural Gas Processing Plant ("Facility"), located at Section 24, Range 63W, Township 2N in Weld County, Colorado. This facility currently operates under Title V permit 95OPWE055 originally issued on May 1, 2001 and last revised on August 29, 2005, with an expiration date of May 1, 2006. A timely Title V permit renewal application was submitted in April 2005, and a draft operating permit renewal was issued July 26, 2018. Proposed Changes ■ Plant Flare (AIRS 141)1 o Increase total metered waste and purge gas throughput limit from 35.78 to 86.75 MMscf/yr. o Clarification on how throughput for this flare is monitored. ■ The pilot fuel gas is constant at 150 scf/hr. This value is not metered, and does not vary from month to month. DCP is requesting no change to this pilot gas throughput. • The purge and waste gas throughput to this plant flare shall be monitored and recorded monthly using a single dedicated flowmeter. The purge gas flowrate is a constant hourly rate of 5,417 scf/hr that will be subtracted from the monthly metered value. The resulting waste gas is assumed to be a 50/50 split of inlet waste gas and residue waste gas. 1 This plant flare has no underlying construction permit, and the draft operating permit with this flare included has not yet reached final issuance. DCP is therefore treating this modification as significant, as it pertains to a "new" source of emissions. o Revision of the existing monitoring, recordkeeping, and reporting requirements in the draft operating permit renewal, to match the above clarification on how throughputs to this flare are monitored.2 o Increase emission limits based on above increases to flaring gas throughputs • Increase VOC emissions limit from 9.5 tpy to 17.19 tpy ■ Increase NOx emissions limit from 1.55 tpy to 3.55 tpy • Increase CO emissions limit from 6.84 tpy to 15.93 tpy • Facility Insignificant Activities o DCP has provided updated list of facility insignificant activities in both Attachment B (alongside relevant Colorado Title V operating permit forms) and in Attachment D. Regulatory Analysis This flare is subject to the work practice requirements under NSPS Subpart A, General Provisions. There are no proposed changes in either State or Federal regulatory applicability based on these requested modifications. DCP will comply with all applicable requirements detailed in the draft operating permit 95OPWE055 for this plant flare. Attachments The following attachments needed to make the requested changes to operating permit 95OPWE055 have been included: • Attachment A: APEN Fee ■ Attachment B: Updated APEN Forms • Attachment C: Emission Calculation and Supporting Documentation Attachment D: Form APCD-102: Facility Emissions Inventory • Attachment E: Updated Colorado Title V operating permit forms If you have any questions or require any additional information about this submittal, please contact me at (303) 605-2039 or RShankaran@dcpmidstream.com. Sincerely, DCP Operating Company, LP Roshini Shankaran Senior Environmental Engineer 2 Per discussions with the Division, DCP has not provided updated monitoring, recordkeeping, and reporting Colorado Title V operating permit forms reflecting these proposed changes. Attachment A: APEN Fees $191.13 — Plant Flare Roggen Natural Gas Processing Plant Attachment B: Updated APEN Forms Plant Flare (AIRS 141) Roggen Natural Gas Processing Plant General APEN - Form APCD-200 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. There may be a more specific APEN for your source (e.g. boiler, mining operations, engines, etc.). A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Permit Number: 95OPWE055 AIRS ID Number: 123 /0049/141 [Leave blank unless APCD has already assigned a permit /t and AIRS ID] Section 1 - Administrative Information Company Name: Site Name: Site Location: Mailing Address: DCP Operating Company, LP Roggen Gas Plant 35409 Weld County Road 18 Roggen, CO 80652 370 17th Street, Suite 2500 (Include Zip Code) Portable Source Home Base: Site Location County: Weld NAICS or SIC Code: 1321 Denver, CO 80202 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. Form APCD-200 - General APEN - Revision 7/2018 390109 I COLORADO 1I&UVI � H[aHl:b EnNWPn1KA Permit Number: 95OPWE055 AIRS ID Number: 123 /0049/141 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source (check one below) ❑ STATIONARY source O PORTABLE source -OR- ✓❑ MODIFICATION to existing permit (check each box below that applies) ❑ Change fuel or equipment O Change company name3 ❑ Add point to existing permit 0 Change permit limit ❑ Transfer of ownership4 ❑ Other (describe below) -OR- ❑ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - ❑ 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: Revised throughput limits for purge and waste gas directed to plant flare 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: Plant Flare for Maintenance and Malfunctions Manufacturer: John Zink Model No.: Kaldair P-684 Serial No.: Company equipment Identification No. (optional): For existing sources, operation began on: Flare < 2010 For new or reconstructed sources, the projected start-up date is: 0 Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below: Normal Hours of Source Operation: hours/day Seasonal use percentage: Dec -Feb: Mar -May: Form APCD-200 - General APEN - Revision 7/2018 days/week weeks/year Jun -Aug: Sep -Nov: COLORADO 2 I AV cpu msn of Rt k HoaIIT h EnvlronMrtt Permit Number: 95OPWE055 [Leave blank unless APCD has already assigned a permit # and AIRS ID] AIRS ID Number: "I Zi I UU' I I'+ i Section 4 - Processing/Manufacturing Information &t Material Use 0 Check box if this information is not applicable to source or process From what year is the actual annual amount? Design Process Rate (Specify Units) Material Consumption: Finished Product(s): Actual Annual Amount (Specify Units) 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. Requested Annual Permit Limits (Specify Units) Section 5 - Stack Information Geographical Coordinates Latitude/Longitude or UTM) - 40.1174 / -104.3883 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. 60.0 Flare Indicate the direction of the stack outlet: (check one) ✓ l Upward O Horizontal o Downward O Other (describe): O Upward with obstructing raincap Indicate the stack opening and size: (check one) O Circular Interior stack diameter (inches): Square/rectangle Interior stack width (inches): Interior stack depth (inches): Other (describe): Form APCD-200 - General APEN - Revision 7/2018 COLORADO 3I AV' �. H..un Rs cnutmnn.0 Permit Number: 95OPWE055 AIRS ID Number: 123 /0049 / 141 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 6 - Combustion Equipment £t Fuel Consumption Information ❑ Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated with this emission source) Design Input Rate (MMBTUIhr) Actual Annual Fuel Use (Specify Units) Requested Annual Permit Limits (Specify Units) Pilot: 0.17 Pilot: 1.31 MMscf/yr, Purge+Waste: 86.75 MMscf/yr From what year is the actual annua fuel use data? Indicate the type of fuel used6: ❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF) ❑ Field Natural Gas Heating value: BTU/SCF ❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon) ❑ Propane (assumed fuel heating value of 2,300 BTU/SCF) ❑ Coal Heating value: BTU/lb Ash content: Sulfur content: 0 Other (describe): Fuel/Residue/Purge, Waste Gas Heating value (give units): 1141 Btu/scf, 1318 Btu/scf 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field. Section 7 - Criteria Pollutant Emissions Information Attach all emission calculations and emission factor documentation to this APEN form. Is any emission control equipment or practice used to reduce emissions? ✓❑ Yes ❑ No ction): It oescrioe the con rot equipuiciit. rutiv zi.a« <i.� �.�,—,.--..-•--• _..._._.._, ,.- yes, Pollutant Control Equipment Description Overall Collection Efficiency Overall Control Efficiency .. (%reduction in emissions) TSP (PM) PM10 PM2.s SOx NOx CO VOC Open Flare 95% 95% Other: HAPs - Open Flare 95% 95% Form APCD-200 - General APEN - Revision 7/2018 COLORADO 4 A.V� Ncallh h Envlmrvnent Permit Number: 95O PWE055 AIRS ID Number: 123 /0049/141 [Leave blank unless APCD has already assigned a permit # and AIRS ID] From what year is the following reported actual annual emissions data? Use the following table to report the criteria pollutant emissions from source: (use Lne craw I rlluI Pollutant Lru Uncontrolled Emission Factor (Specify Units) Emission Factor Source (AP-42,et.) Mfg., S Actual Annual Emissions =N Requested Annual Permit Emission Limit(s)5 Uncontrolled (tons/year) d Controlled tnyaar) Uncontrolled s/yea tons/ ear Controlled (tons/year) ) TSP (PM) PMio PM2.5 SOx 0.6 lb/MMscf AP -42 0.03 0.03 NOx 0.068 lb/MMBtu AP -42 3.55 3.55 CO 0.31 lb/MMBtu AP -42 15.93 15.93 VOC 7,925.851b/MMscf Eng. Est. 343.78 17.19 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Section 8 - Non -Criteria Pollutant Emissions Information Does the emissions source have any uncontrolled actual emissions of non -criteria pollutants (e.g. HAP - hazardous air pollutant) equal to or greater than 250 lbs/year? E✓ Yes ❑ No criteria pollutant (HAP) emissions from source: IT yes, use CAS Number Lne rou�w Chemical Name Overall Control Efficiency Uncontrolled Emission Factor (Specify Units) Emission Factor Source AP 42, M etc.) ( fg.' Uncontrolled Actual* Emissions Ohs/year) Controlled Actual* Emissions (lbs/year) 110-54-3 n -Hexane 95% 30.45 lb/MMscf Eng. Est. 2,641.73 215.47 71-43-2 Benzene 95% 5.46 lb/MMscf Eng. Est. 473.85 23.79 108-88-3 Toluene 95% 2.92 lb/MMscf Eng. Est. 253.24 12.82 7 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. * The values provided represent potential emissions of HAPs from this source. Form APCD-200 - General APEN - Revision 7/2018 COLORADO 5 I �� `�"°"":o�� ' Hvnhh 6 EiwiKn.nwhl Permit Number: 95O PWE055 AIRS ID Number: 123 /0049/141 [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. Date Signature of Legally Authorized Person (not a vendor or consultant) Roshini Shankaran Senior Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance O Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https://www.colorado.Rov/cdphe/apcd Form APCD-200 - General APEN - Revision 7/2018 COLORADO 6 Ay Fxalllf b &WlrofunMl Attachment C: Emission Calculations and Supporting Documentation Plant Flare (AIRS 141) Roggen Natural Gas Processing Plant Roggen Plant Flare Roggen Natural Gas Processing Plant DCP Operating Company, LP Source ID Description Manufacturer Model Serial # Manufacture Date Fuel Heat Value Pilot Flow Rate Heat Input Hours of operation Potential Fuel Usage Destruction Efficiency Emissions from Pilot Emission Factor (lb/MMsof) 100.0 (lb/hr) 0.02 lb/r 131.40 (ton/yr) 0.07 Source of Emission Factor AP -42t AP -42' Pollutant CAS Number NOx 84 0 5.5 06 7.6 0.01 8.25E -D4 9.00E-05 1.14E-03 110.38 7.23 0.79 9.99 0.06 3.61E-03 3.94E-04 0.00 0.046 AR -02° CO VOC AP -42 AP -42'5O2 PM 1.05E-02 92.06 Total HAPs 1 ,-nn , me i Fifth Petition. JnIV 1998, Table 1.4-1 Plant Flare Flare John Zink Kaldair P-684 N/A 1141 Btu/scf 150 scf/hr 0.17 MMBtU/hr 8760 hr/yr 1.31 MMscf/yr 95 % z EPA AP -42, Volume I, Fifth Edition, July 1998, Table 1.4-2 Vents to Combustion Device Vent Stream Slowdowns to Flare (residue gas) Blowdowns to Flare (inlet gas) Purge Gas` Total Waste/Purge Gas Flow Rate 9902.83 Flow rate volumes to flare for residue gas and Inlet gas were eshmated from total volume at FlowCal Meter Number 217111. Based on engineering knowledge, 50% of waste gas has residue gas composition and 50% has inlet gas composition. z Purge gas flow rate calculated based an maximum metered monthly flow of 130,000 Mcf Heatvalue of purge gas Is equal to residue gas heat value. Flow Rate (sof/hr) 2243.08 2243.08 5416.67 Operation (hrlyr) 8760 8760 8760 Flow Rate (MMScf/yr)" 19.65 19.65 47.45 86.75 Heat Value. • . (Btulscf)a • 1141 1318 1141 Heat Rate ;. (MMBtoryr) 22,413 25,900 54,124 102,437 Combustion Emissions • - Pollutant. . NOx CO SOu NOx and CO emission factor obtained from EPA AP -42 Section 13.5, Table 13.5-1 and 13.5-2 (April 2015 a Fuel gas emissions reflect pilot gas combustion. 'S0z emission factor from EPA AP -42, Volume I, Fifth Edition, July 1998, Table 1.4-2 Waste/Purge Gas Combustion 'Emission Factor' (Ib/MMBtu) 0.068 0.310 (Ib/MMscf) - • (lb/hr) 0.80 3.63 (lb/hr) 0.01 Emissions' (tPy) 3.48 15.88 RPWI • 0.03 - Pilot Combustor?' • (lb/hr) • 0,02 0.01 (lb/hr) • 9,00E-05 Emissions Iy .. Waste Gas Flaring Emissions Specific Volume of Air 0.6 379 scfllb-mol Pollutant .... • VOC n -Hexane 2,2,4 Trimettylpentane McOH Serene Toluene Residue Waste Gas ,'.7Uneontrolled' _.:. (tPY) -' 53.30 .• (Ibltr) 82.00 Residue Waste Gas Controlledz- 2.66 (Ib/yr) 4.10 Inlet Waste Gas • Uncontrolled'. - - -IVY)' 161.78 (lb/yr) I 2273.94 473.75 253.07 Inlet Waite Gas :.. Contrplledr-, - llpY) . 8.09 (Ib/yr) 113.70 23.69 12.65 0.28 1.65 Ethylbenzene Xylenes 5.51 33.04 0.07 0.06 3.94E-04 as linen 128.70 (Ib/yr) • 198.02 • Total Emissions . (toy) • 3.55 15.93 COY) 0.03 Purge Gas Controlled'. - 6.44 • Plant Combustion'., 3.61E-03 Total Uncontrolled' 343.78 (lb/yr) 2641.73 Total Controlled': • (Iblyr) 9.90 (Ib/yr) 8738 0.10 0.17 473.85 253.24 5.51 33,04 17.19 (Ib/yr)' . 216.47 23.79 12.82 0.28 1.65 Uncontrolled emissions calculated based an deal gas law, assuming that if is a mbdure of inlet gas and residue gas VOC (tpy) = Flared Volume fMMscf/Vrl x MW gas fib/lb-moll x f1 tf sef/MMsefl Sr VOC IA% Air Specific Volume (scf/lb-moll x (2000 Ibnon) a Controlled emissions calculated using Flare DRE of 95%: Controlled VOC (toy). Uncontrolled VOC (tpy) x (100951% Total emissions are the sum of emissions from a) Blowdowns with residue gas composition b) Blowdowns with inlet gas composition c) Purge gas combustion end d) pilot combustion Total Flare Emissions Summary Pollutant 1100 CO S02 VOC n -Hexane Benzene Toluene Controlled Emissions 3.55 tpy 15.93 tpy 0.03 tpy 17.19 tpy 215.47 Ib/yr 23.79 Ib/yr 12.82 lb/yr Emission Factors 0.068 lb/MMBtu 0.31 lb/MMBtu 0.62 Ib/MMscf 7,925.83 Ib/MMscf 30.45 lb/MMscf 5.46 lb/MMsof 2.92 Ib/MMscf Roggen Residue Analysis - 9/1/2017 Mol%" MW Component Mass ‘441/4, Pure Component Heat Value (Btufscf) Component Fraction Heat Value (Btu/act) N2 0.247953 28 6.94 0.350 0 0.00 Carbon Dioxide 2.734480 44 120.32 6.072 0 0.00 Methane 80.477710 16 1287.64 65.147 1010.0 812.82 Ethane 12.505624 30 375.17 18.974 1769.6 221.30 Propene 3.392355 44 149.26 7.548 2516.1 85.36 i-Butane 0.228956 58 13.28 0.671 3251.9 7.45 n -Butane 0.369930 58 21,46 1,085 3262.3 12.07 i-Pentane 0.023995 72 1.73 0.087 4000.9 0.9600 n -Pentane 0,014997 72 1.08 0.055 4008.9 0.6012 Hexane 0.002000 86 0.17 0.008 4755.9 0.0951 Total 1977.1 100.0 1140.6 MW of Gas' 19.8 VOC Wt%4 10.4 % Mol%s for Residue gas values use on representative gas analysis performed on ep em Component mass = Mo %x MW. MW of Gas = Total Mass / 100 "VOC Wt % calculated as sum of individual VOC components. Includes added buffer of 10% Roggen Gas Plant Inlet -12/3/2019 Constituent mol°h' Helium 0.01 N2 0.4900 C02 2.3900 H2O 0.0000 McSH 0.0000 C1 70.4871 C2 14.3020 C3 7.6386 /04 1.0162 nC4 2.6214 iC5 0.3917 nC5 0.3893 Cyclopentane 0.0180 nC6 0.0510 Cyclohexane 0.0119 nC7 0,0987 n08 0.0318 Methylcycloh, 0.0000 2,2,4-Tnmeth 0.0000 MoOH 0.0000 Benzene 0.0117 Toluene 0.0053 Ethylbenzene 0.0001 Xylenes 0.0006 C8+ Heavies 0.0046 MW' 4 28 44 34 48 16 30 44 58 58 72 72 70 86 84 86 114 98 114 32 78 92 105 106 114 Pure Comoone Component Mass' weight% nt Heat Value Component Fraction Heat Value tBtu/sett fBtu/scfl 0.04 0.00174 0 0.00 13.72 0.5966 0 0.00 105.16 4.5725 0 __. 0.00 0,60 0.0000 0 0.00 '0.60 0.0000 0 0.00 1127.79 49.0377 1010.0 711.92 429.06 18.6560 1769.6 253.09 336.10 14.6139 2516.1 192.19 58.94 2.5628 3251.9 33.05 15204 6.6109 3262.3 85.52 28.20 1.2263 4000.9 15.67 28.03 1.2188 4008.9 15.61 1.26 0.0549 3763.9 0.68 4.39 0.1907 4755.9 2.43 1.00 0.0435 4481.5 0.53 8.49 0.3691 4755.9 4.69 3.63 0.1576 5502.5 1.75 0.00 0.0000 5215.7 0.00 0.00 0.0000 6231.7 0.00 0.00 0.0000 0 0.00 0.91 0.0397 3741.8 0.44 0.49 0.0212 4475.0 0.24 0.01 0.0005 5222.2 0.01 0.06 0.0028 5208.8 0.03 0,53 0.0228 6248.9 0.29 Total 100 2299.85 100 1318.12 MW of Gas' 23.00 VOC wt%' 27.14 Mol%s for Inlet -gas values based 86 conservative gas analysis performed on 12/3/2014.. 2 Component mess = Mol % z MW. MW of Gas = Total Mass /100. • VOC Vat 94 calculated as sum of individual VOC components. Insignificant Activities List DCP Operating Company, LP Roggen Natural Gas Processing Plant NO, CO VOC n•hexane Benzene (too) Methanol (ton) EF Source 2.5 MMBtu/hr, Broach Regen Heater Regulation No. 3, Part C, Section II.E.3.k 1.07 0.90 0.06 0.02 0.00 — AP -42, Table 1.4-1 and -2 0.115 MMBtu/hr, Office Heater 1 Regulation No. 3, Part C, Section II.E.3.ggg 0.05 0.04 0.00 0.00 0.00 — AP -42, Table 1.4-1 and -2 0.115 MMBtu/hr, Office Heater 1 Regulation No. 3, Part C, Section II.E.3.ggg 0.05 0.04 0.00 0.00 0.00 — AP -42, Table 1.4-1 and -2 0.038 MMBtu/hr, Hot Water Heater Regulation No. 3, Part C, Section II.E.3.k 0.02 0.01 0.00 0.00 0.00 — AP -42, Table 1.4-1 and -2 0.02 MMBtumr, Shop Heater Regulation No. 3, Part C, Section II.E.3.ggg 0.01 0.01 0.00 0.00 0.00 — AP -42, Table 1.4-1 and -2 Tank Combustor - Pilot Emissions Regulation No. 3, Part C, Section II.E.3.a 0.05 0.05 0.05 0.00 0.00 — TNRCC Flare Factors Dehy Combustor- Pilot Emissions Regulation No. 3, Part C, Section II.E.3,a 0.05 0.05 0.05 0.00 0.00 — AP -42, Table 1.4-1 and -2 C-154 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.16 0.001 0.000 — Engineering Calculation C-155 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.01 0.000 0.000 — Engineering Calculation C-159 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.04 0.000 0.000 — Engineering Calculation C-157 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.01 0.000 0.000 — Engineering Calculation C-161 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.04 0.000 0.000 — Engineering Calculation C-158 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.51 0.004 0.001 — Engineering Calculation C-160 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.00 0.000 0.000 — Engineering Calculation C-156 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.01 0.000 0.000 — Engineering Calculation C-223 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.09 0.001 0.000 — Engineering Calculation C-225 Maintenance Blowdown Vent Regulation No. 3, Pert C, Section II.E.3.a 0.09 0.001 0.000 — Engineering Calculation C-227 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.09 0.001 0.000 — Engineering Calculation C-181 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.04 0.000 0.000 — Engineering Calculation C-192 Maintenance Slowdown Vent Regulation No. 3, Part C, Section II.E.3.a — — 0.88 0.006 0.001 — Engineering Calculation Atmospheric Slowdowns Regulation No. 3, Part C, Section II.E.3.a — — 0.99 0.007 0.001 — Engineering Calculation 500 gal, Kerosene tank Regulation No. 3, Part C, Section II.E.3.a — — 0.00 neg. neg. neg. TANKS 4.0.9d 500 gal, Scavenger tank, AST- 27 Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. neg. 500 gal, Diesel tank Regulation No. 3, Part C, Section II.E.3.a — — 0.00 neg. neg. — TANKS 4.0.9d 500 gal, Dyed Diesel tank Regulation No. 3, Part C, Section II.E.3.a — — 0.00 neg. neg. — TANKS 4.0.9d 300 gal, Unleaded Gasoline Tank Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. — 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz — — neg. neg. neg. — 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz — — neg. nag. neg. — 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz — — neg. neg. neg. — 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz — — neg. neg. neg. — 80 bbl, Produced Water Tank, Sump 1 Regulation No. 3, Part C, Section II.E.3.uu — — 0.14 0.01 0.00 — Produced Water Tank Default EF from PS Memo 09-02 80 bbl, Produced Water Tank, Sump 2 Regulation No. 3, Part C, Section II.E.3.uu — — — 80 bbl, Produced Water Tank, Sump 14 Regulation No. 3, Part C, Section II.E.3.uu — — — 80 bbl, Produced Water Tank, Sump 6 Regulation No. 3, Part C, Section II.E.3.uu — — — 200 bbl, Produced Water Tank, Tank 7209 Regulation No. 3, Part C, Section II.E.3.uu — — — 80 bbl, Produced Water Tank, Tank 7213 Regulation No. 3, Part C, Section II.E.3.uu — — — 200 bbl, Produced Water Tank, Tank 7214 Regulation No. 3, Part C, Section II.E.3.uu — — — Insignificant Activities List DCP Operating Company, LP Roggen Natural Gas Processing Plant NO, CO VOC n•hexane Benzene EF Source Description 80 bbl, Wastewater Tank, Sump 8 insignmcant rer Regulation No. 3, Part C, Section II.E.3.a PPYI — MI I — PM neg. 1r, neg. , r.• neg. -"-- - - - - — 80 bbl, StormwaterTank, Sump 5 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — 240 bbl, Lube Oil tank, 805 Central Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. — 6,000 Lube Oil tank, 805 West Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. — gal, 500 Lube Oil tank, AST -24 Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. — gal, 500 Used Oil Tank Regulation No. 3, Part C, Section lt.E.3.aaa — — neg. neg. neg. — gal, portable 225 Used Oil Tank, #1 Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. gal, 225 Used Oil Tank, #2 Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. gal, 225 Used Oil Tank, #3 Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. gal, 110 bbl, Used Oil tank, AST -13 Regulation No. 3, Part C, Section II.E.3.aaa — — neg. neg. neg. — 80 bbl, Slop Oil Tank, Sump 5 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — 10 bbl, Slop Oil Tank, Sump 7 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — 80 bbl, Slop Oil Tank, Sump 9 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — 210 bbl, Slop Oil Tank, Sump 12 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — 10 bbl, Slop Oil Tank, Sump 10 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. 30 bbl, Slop Oil Tank Sump 4 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — 220 Slop Oil tank, Air Compressor Sump Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal, 1,000 Norkool tank, AST 7 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. gal, 1000 Norkool tank, AST 8 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal, 1000 Norkool tank, AST 19 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal, 100 Portable Methanol Tank Regulation No. 3, Part C, Section II.E.3.a — — 0.00 — — 0.00 gal, 500 Methanol tank, Randal Regulation No. 3, Part C, Section II.E.3.a — — 0.01 — — 0.01 TANKS 4.0.9d gal, 500 Methanol tank, Petro Frac Regulation No. 3, Part C, Section II.E.3.a — — 0.01 — — 0.01 TANKS 4.0.9d gal, 500 Methanol tank, 212 Regulation No. 3, Part C, Section II.E.3.a — — 0.01 — — 0.01 TANKS 4.0.9d gal, 500 Methanol tank, CIG Regulation No. 3, Part C, Section II.E.3.a — — 0.01 — — 0.01 TANKS 4.0.9d gal, 1,000 Methanol tank, AST 20 Regulation No. 3, Part C, Section II.E.3.a — — 0.02 — — 0.02 TANKS 4.0.9d gal, 1,000 Methanol tank, AST 9 Regulation No. 3, Part C, Section II.E.3.a — — 0.02 — — 0.02 TANKS 4.0.9d gal, 4,000 TEG Tank, Tank 7210 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal, 500 TEG tank, Ast 28 Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. gal, 80,000 Pressurized Butane Storage Tank Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal 80,000 Pressurized Butane Storage Tank Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal 30,000 Pressurized Propane Storage Tank Regulation No. 3, Part C, Section II.E.3.zz — — neg. neg. neg. gal 18,000 Pressurized Methanol Storage Tank Regulation No. 3, Part C, Section II.E.3.a — — neg. neg. neg. — gal Kohler Commercial Pro 15 Methonal Trailer Pump Regulation No. 3, Part C, Section II.E.3.nnn(iii) — — neg. neg. neg. — Briggs & Stratton Vangaurde 16HP Hotsy Pump Regulation No. 3, Part C, Section II.E.3.nnn(iii) — — neg. neg. neg. Hotly Heater, 385,800 BTU/hr Regulation No. 3, Part C, Section II.E.3.ggg 0.17 0.14 0.01 3E-03 3E-06 AP -42, Table 1.4-1 and -2 Catco 12,000 BTUIHr CIG Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg 0.01 0.00 0.00 9E-05 1E-07 — AP -42, Table 1.4-1 and -2 Catco 12,000 BTU/Hr Excel Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg 0.01 0.00 0.00 9E-05 1 E-07 — AP -42, Table 1.4-1 and -2 CataDyne 12,000 BTUIHr Box Elder Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg 0.01 0.00 0.00 9E-05 1 E-07 - AP -42, Table 1.4-1 and -2 CataDyne 6,000 BTU/Hr Bypass Gas Meter Shed Heater Regulation No. 3, Part C. Section II.E.3.ggg 0.00 0.00 0.00 5E-05 5E-08 AP -42, Table 1.4-1 and -2 6,000 BTUIHr North Inlet Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg 0.00 0.00 0.00 5E-05 5E-08 — AP -42, Table 1.4-1 and -2 CataDyne 6,000 BTUIHr South Inlet Meter Shed Healer Regulation No. 3, Part C, Section II.E.3.ggg 0.00 0.00 0.00 5E-05 5E-08 — AP -42, Table 1.4-1 and -2 CataDyne 6,000 BTU/Hr Low Pressure Inlet Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg 0.00 0.00 0.00 5E-05 5E-08 — AP -42, Table 1.4-1 and -2 CataDyne AO .1 7R %'1R 0 00 0.01 0.09 otals Attachment D: Form APCD-102: Facility Emissions Inventory Roggen Natural Gas Processing Plant Form APCD-102 Company Name: DCP Operating Company, LP Source Name: Roggen Gas Plant Source AIRS ID: 123/0049 Colorado Department of Public Health and Environment Air Pollution Control Division Facility Wide Emissions Inventory Form Ver, April, 2015 Uncontrolled Potential to Emit (PTE) • Controlled Potential to Emit (PTE) Criteria (TPY) I HAPs (lbs/yr) Criteria (TPY) ' HAPs (lbs/yr) AIRS ID Equipment Description TSP PM10 PM2.5 SO2 NOx VOC CO ' HCHO Acetal Acro BZ Tol EB Xyl n -Hex Meth 224-TMP TSP PM10 PM2.5 S02 NO: VOC CO I HCHO Aortal Acro BZ Tol EB Xyl n -Hex Meth 224-TMP 123/0049/101 Engine C-154/P001/S001 0.72 0.72 0.72 0.02 116.84 15.93 84.98 I 1.521 207 195 117 41 2 14 0 227 0 0.72 0.72 0.72 0.02 21.24 10.62 21.24 ' 365 104 98 59 21 1 7 0 114 0 123/0049/102 Engine C-155/P002/S002 0.61 0.61 0.61 0.02 85.61 1167 62.26 1.293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 16.34 7.78 16.34 310 88 83 50 18 1 6 0 97 0 123/0049/103 Engine C-159/P003/S003 0.94 0.94 0.94 0.03 169.47 26.07 117.32 I 1.992 271 256 153 54 2 19 0 297 0 0.94 0.94 0.94 003 26.07 13.04 27.38' 478 136 128 77 27 1 9 0 149 0 123/0049/107 Engine C -157/0007/S007 0.61 0.61 0.61 0.02 85.61 11.67 62.26 I 1.293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 16.34 7.78 16.34 I 310 88 83 50 18 I 6 0 97 0 123/0049/108 Engine C-161/P008/S008 0.94 0.94 0.94 0.03 143.40 19.55 104.29 I 1.992 271 256 153 54 2 19 0 297 0 0.94 0.94 0.94 0.03 13.04 9.13 26.07 1 478 136 128 77 27 I 9 0 149 0 123/0049/110 Engine C-158/P010/Solo 0.66 0.66 0.66 0.02 97.30 13.27 70.76 I 1.401 191 180 108 38 2 13 0 209 0 0.66 0.66 0.66 0_02 18.57 8.85 18.57 I 336 95 90 54 19 1 7 0 105 0 123/0049/113 Engine C -160/0013/S013 0,61 0.61 0.61 0.02 85.61 11.67 62.26 I 1.293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 16.34 7.78 16.34 I 310 88 83 50 18 1 6 0 97 0 123/0049/114 Engine C -156/0014/S014 0.61 0.61 0.61 0.02 85.61 11.67 62.26 I 1.293 176 166 100 35 2 12 0 193 0 0.61 0.61 0.61 0.02 7.78 5.45 15.57 I 310 88 83 50 18 1 6 0 97 0 123/0049/115 Engine C -223/0615/S015 0.53 0.53 0.53 0.02 61.64 9.72 101.02 I 1,113 152 143 86 30 1 14 0 227 0 053 0.53 0.53 0.02 14.60 6.95 14.60 I 267 76 98 59 15 1 5 0 83 0 123/0049/117 Engine C-225/P017/S017 0.54 0.54 0.54 0.02 63.63 10.04 104.28 I 1,149 156 147 89 31 I 11 0 172 0 0.54 0.54 0.54 0.02 7.73 5.41 15.45 I 276 78 74 44 16 1 5 0 86 0 123/0049/119 • Engine C -227/0019/S019 0.53 0.53 0.53 0.02 104.29 9.73 100.81 I 1.113 152 143 86 30 1 11 141) 166 0 0.53 0.53 0.53 0.02 13.91 6.95 14.60 I 267 76 71 43 15 1 5 0 83 0 123/0049/122 P025/FUGITIVES 0.00 0.00 0.00 0.00 0.00 114.07 0.00 I 0 0 0 913 215 82 154 1.788 0 0 0.00 0.00 0.00 0.00 0.00 33.54 0.00 I 0 0 0 268 63 24 45 524 0 0 123/0049/125 P039, Stahlized Condensate Tanks 0.00 0.00 0.00 0.00 0.00 28.84 0.00 I 0 0 0 771 2.571 200 1.857 5.600 0 0 0.00 0.00 0.00 0.00 0.00 1,44 0.00 I 0 0 0 39 129 10 93 280 0 0 123/0049/126 F029. Condensate Truck Loadout 0.00 0.00 0.00 0.00 0.00 30.84 0.00 0 0 0 • 916 2,749 305 2.138 6.110 0 0 0.00 0.00 0.00 0.00 0.00 30.84 0.00 0 0 0 916 2.749 305 2.138 6.110 0 0 123/0049/129 H037. Hot OEHeater 0.26 0.26 0.26 0.02 3.45 0.19 2.90 I 5 0 0 0 0 0 0 124 0 0 0.26 0.26 0.26 0.02 3.45 0.19 2.90 I 5 0 0 0 0 0 0 124 0 0 123/0049/130 9-033. Regen Delp' 0.00 0.00 0.00 0.00 0.06 49.10 0.17 I 0 0 0 3.378 3.761 138 1.247 1.151 0 0 0.00 0.00 0.00 0.00 0.06 1.05 0.17 I 0 0 0 228 256 9 86 44 0 0 123/0049/133 F031. Pressurized Liquids Loadout 0.00 0.00 0.00 0.00 0.00 5,00 0.00 I 0 0 0 0 0 0 0 236 0 0 0.00 0,00 0.00 0.00 0.00 5.00 0.00 I 0 0 0 0 0 0 0 236 0 0 123/0049/134 Engine C-181 0.98 0.98 0.98 0.03 156.99 21.41 114.18 I 2.070 282 266 160 56 3 20 0 309 0 0.98 0.98 0.98 0.03 14.27 9.99 28.54 I 497 141 133 80 28 1 10 0 155 0 123/0049/136 P-136. Inlet TEG Delis 0.00 0,00 0.00 0.00 0.89 663.37 4.04 I 0 0 0 99.154 78,555 1,970 16.065 64,732 0 0 0.00 0.00 0.00 0.00 0.89 23.74 4.04 I 0 0 0 6.739 5.376 135 1.104 3.363 0 0 123/0049/137 P-137, Amine Unit 0.00 0.00 0.00 0.00 0.00 282.96 0.00 I 0 0 0 50.789 33,225 1.074 174 6.509 0 0 0.00 0.00 0.00 30.04 0.85 2.32 4.60 I 0 0 0 1.436 950 31 174 21 288 0 123/0049/138 Hot Oil Heater 1.07 1.07 1.07 0.08 7.02 0.65 11.79 I 0 0 0 0 0 0 0 505 0 0 1.07 1.07 1.07 0.08 7.02 0.65 11.79 I 0 ' 0 0 0 0 0 0 505 0 0 123/0049/140 Engine C-192 0.98 0.98 0.98 0.03 156.99 21.41 114.18 I 2.076 282 266 160 56 3 20 0 310 . 0 0,98 0.98 0.98 0.03 14.27 9.99 28.54 I 1.038 141 133 80 28 1 10 0 155 0 123/0049/141 Flare 0.00 0.00 0.00 0.03 3.55 343.78 15.93 I 0 0 0 474 253 0 0 2.642 0 0 0.00 0.00 0.00 0.03 3.55 17.19 15.93 I 0 0 0 24 13 0 0 215 0 0 Permitted Sources Subtotal = APEN Only - Permit Exempt Sources 10.60 10.60 10.60 0.41 1427.96 1712.63 1195.70 119,604 2,667 2,514 157,907 121,864 3,794 21,826 89,397 2,986 0 10.60 10.60 10.60 30.45 216.33 225.68 299.04 I 5,249 1,334 1,283 10,420 9,803 527 3,734 11,423 1,751 0 I I I I I I I I I I I I APEN Only Subtotal= APEN Exempt / Insignificant sources 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I 0 0 0 0 0 0 0 0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 i 0 0 0 0 0 0 0 0 0 0 APEN Exempt / Insignificant sources 0.0 0.0 0.0 0.0 1.5 1.3 3.4 1 0 0 0 18 0 0 0 118 176 0 0.0 0.0 0.0 0.0 1.5 1.3 3.4 I 0 0 0 18 0 0 0 118 176 0 I I I I I I I I I I Insignificant Subtotal = Total, All Sources = ( 0.0 0.0 0.0 0.0 1.5 1.3 3.4 I 0 0 0 18 0 0 0 118 176 0 0.0 0.0 0.0 0.0 ..... 1.5 1.3 3.4 I 0 0 0 18 0 0 0 118 176 0 10.6 10.6 10.6 0.4 1429.5 1713.9 1199.1 119,604 2,667 2,514 157,925 121,864 3,794 21,826 89,515 3,162 0 I 10.6 I 10.6 I 10.6 30.5 217.8 227.0 302.4 I 5,249 1,334 1,283 10,438 9,803 527 3,734 11,541 1927 0 Uncontrolled HAPs Uncontrolled Total, Summary All HAPs Controlled Controlled HAPs Total, Summary All HAPs (TPY) = 9.8 1.3 1.3 79.0 60.9 1.9 10.9 44.8 1.6 0.0 (TPY) =I 2.6 I 0.7 I 0.6 I 5.2 I 4.9 I 0.3 I 1.9 I 5.8 I 1.0 I 0.0 (TPY) =II 211.4 I (TPY) _I 22.9 Footnotes: 1. This form should be completed to include both existing sources and all proposed new or modifications to existing emissions sources 2. If the emissions source is new then enter "proposed" under the Permit No. and AIRS ID data columns 3. HAP abbreviations include: BZ = Benzene 224-TMP = 2,2,4-Trimethylpentane Tol = Toluene Acetal = Acetaldehyde EB = Ethylbenzene Acro = Acrolein Xyl = Xylene n -Hex = n -Hexane HCHO = Formaldehyde Meth = Methanol 4. APEN Exempt/Insignificant Sources should be included when warranted. DCP Operating Company, LP * Please note that this Form APCD-102 does not account for the emission controls claimed for AIRS 125, stablized condensate loadout. An ERC application for this update was submitted 10-11-2018, and is currently pending review with the Division. 11/7/2018 Page 1 of 1 Attachment E: Updated Colorado Title V operating permit forms operating rernuttippucauon Colorado Department of Public Health and Environment Air Pollution Control Division 1'Al..1L11 1 1L111, au'a�.caa av1 SEE INSTRUCTIONS ON REVERSE SIDE Rev 06-95 1. Facility name and Name Roggen Gas Plant mailing address Street or Route 370 17th Street, Suite 2500 City, State, Zip Code Denver, Colorado 80202 2. Facility location Street Address 35409 Weld County Road 18 (No P.O. Box) City, County, Zip Roggen, Colorado 80652 Code 3. Parent corporation Name Street or Route City, State, Zip Code Country (if not U.S.) DCP Operating Company, LP 370 17th Street, Suite 2500 Denver, Colorado 80202 4. Responsible Name official Title Telephone David M. Jost Vice President of Northern Operations 970-378-6345 5. Permit contact person Name Title (If Different than 4) Telephone Roshini Shankaran Environmental Engineer 303-605-2039 6. Facility SIC code: 1321 7. Facility identification code: CO 123-0049 8. Federal Tax I. D. Number: 841041166 9. Primary activity of the operating establishment: Natural Gas Liquids Processing and Compression 10. Type of operating permit 0 New X Modified 0 Renewal 11. Is the facility located in a "nonattainment" area: X Yes 0 No If "Yes", check the designated "non -attainment" pollutant(s): E Carbon Monoxide X Ozone PM10 ❑ Other (specify) 12. List all (Federal and State) air pollution permits (including grandfathered units), plan approvals and exemptions issued to this facility. List the number, date and what unit/process is covered by each permit. For a Modified Operating Permit, do not complete this item. 1 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division Facility Name: Roggen Gas Plant Facility Identification Code: CO 123-0049 NOTE: The operating permit must be prepared and submitted on forms supplied by the Division. This is a supplemental form for use only when necessary to provide complete information in the operating permit application. The Division will not consider or act upon your application unless each form used has been entirely completed. Please see included Supplemental Form 700 for complete list of Insignificant Activities Certain categories of sources and activities are considered to be insignificant contributors to air pollution and are listed below. A source solely comprised of one or more of these activities is not required to obtain an operating permit pursuant to Regulation 3, unless the source's emissions trigger the major source threshold as defined in Part A, Section I.B.58 of Regulation 3. For the facility, mark all insignificant existing or proposed air pollution emission units, operations, and activities listed below. ❑ (a) noncommercial (in-house) experimental and analytical laboratory equipment which is bench scale in nature including quality control/quality assurance laboratories, process support laboratories, environmental laboratories supporting a manufacturing or industrial facility, and research and development laboratories. (b) research and development activities which are of a small pilot scale and which process less than 10,000 pounds of test material per year. (c) small pilot scale research and development projects less than six months in duration with controlled actual emissions less than 500 pounds of any criteria pollutant or 10 pounds of any non -criteria reportable pollutant. Disturbance of surface areas for purposes of land development, which do not exceed 25 contiguous acres and which do not exceed six months in duration. (This does not include mining operations or disturbance of contaminated soil). x Each individual piece of fuel burning equipment, other than smokehouse generators and internal combustion engines, which uses gaseous fuel, and which has a design rate less than or equal to 5 million Btu per hour. (See definition of fuel burning equipment, Common Provisions Regulation). Petroleum industry flares, not associated with refineries, combusting natural gas containing no H2S except in trace (less than 500 ppmw) amounts, approved by the Colorado Oil and Gas Conservation Commission and having uncontrolled emissions of any pollutant of less than five tons per year. Chemical storage tanks or containers that hold less than 500 gallons, and which have a daily throughput less than 25 gallons. Landscaping and site housekeeping devices equal to or less than 10 H.P. in size (lawnmowers, trimmers, snow blowers, etc.). Crude oil or condensate loading truck equipment at crude oil production sites where the loading rate does not exceed 10,000 gallons per day averaged over any 30 day period. Chemical storage areas where chemicals are stored in closed containers, and where total storage capacity does not exceed 5000 gallons. This exemption applies solely to storage of such chemicals. This exemption does not apply to transfer of chemicals from, to, or between such containers. x Oil production wastewater (produced water tanks), containing less than 1% by volume crude oil, except for commercial facilities which accept oil production wastewater for processing. X Storage of butane, propane, or liquified petroleum gas in a vessel with a capacity of less than 60,000 gallons, provided the requirements of Regulation No. 7, Section IV are met, where applicable. x Storage tanks of capacity < 40,000 gallons of lubricating oils. Venting of compressed natural gas, butane or propane gas cylinders, with a capacity of 1 gallon or less. Fuel storage and dispensing equipment in ozone attainment areas operated solely for company -owned vehicles where the daily fuel throughput is no more than 400 gallons per day, averaged over a 30 day period. Crude oil or condensate storage tanks with a capacity of 40,000 gallons or less. Storage tanks meeting all of the following criteria: (i) annual throughput is less than 400,000 gallons; and (ii) the liquid stored is one of the following: (A) diesel fuels 1-D, 2-D, or 4-D; (B) fuel oils #1 through #6; (C) gas turbine fuels 1-GT through 4-GT; (D) an oil/water mixture with a vapor pressure lower than that of diesel fuel (Reid vapor pressure of .025 PSIA). x Each individual piece of fuel burning equipment which uses gaseous fuel, and which has a design rate less than or equal to 10 million Btu per hour, and which is used solely for heating buildings for personal comfort. x Stationary Internal Combustion Engines which: (i) power portable drilling rigs; or (ii) are emergency power generators which operate no more than 250 hours per year; or (iii) have actual emissions less than five tons per year or rated horsepower of less than 50. Surface mining activities which mine 70,000 tons or fewer of product material per year. A fugitive dust control plan is required for such sources. Crushers, screens and other processing equipment activities are not included in this exemption. x Air pollution emission units, operations or activities with emissions less than the appropriate de minimis reporting level. NOTE: Material Data Safety Sheets (MSDS) do not have to be submitted for any insignificant activities. USE FORM 2000-700 TO PROVIDE AN ITEMIZED LIST OF THE SOURCES OR ACTIVITIES BEING IDENTIFIED AS INSIGNIFICANT ACTIVITIES. DO NOT ITEMIZE INDIVIDUAL PIECES OF LANDSCAPING EQUIPMENT. THE LIST IS NEEDED TO ACCURATELY ACCOUNT FOR ALL ACTIVITIES AT THE FACILITY 2 Operating Permit Application Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE SUYYLLMJ N IAL 11VrUK1V1Al1U1V rUKlvl Luuu-/uu 09-94 1. Facility name: Roggen Gas Plant 2. Facility identification code: CO 123-0049 3. This form supplements Form 2000 — 102B for Emission Unit Insignificant Sources Source Description Insignificant Per 2.5 MMBtu/hr, Broach Regen Heater Regulation No. 3, Part C, Section II.E.3.k 0.115 MMBtu/hr, Office Heater 1 Regulation No. 3, Part C, Section II.E.3.ggg 0.115 MMBtu/hr, Office Heater 1 Regulation No. 3, Part C, Section II.E.3.ggg 0.038 MMBtu/hr, Hot Water Heater Regulation No. 3, Part C, Section II.E.3.k 0.02 MMBtu/hr, Shop Heater Regulation No. 3, Part C, Section II.E.3.ggg Tank Combustor - Pilot Emissions Regulation No. 3, Part C, Section II.E.3.a Dehy Combustor - Pilot Emissions Regulation No. 3, Part C, Section II.E.3.a C-154 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-155 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-159 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-157 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-161 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-158 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-160 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-156 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-223 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-225 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-227 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-181 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a C-192 Maintenance Blowdown Vent Regulation No. 3, Part C, Section II.E.3.a Atmospheric Blowdowns Regulation No. 3, Part C, Section II.E.3.a 500 gal, Kerosene tank Regulation No. 3, Part C, Section II.E.3.a 500 gal, Scavenger tank, AST- 27 Regulation No. 3, Part C, Section II.E.3.aaa 500 gal, Diesel tank Regulation No. 3, Part C, Section II.E.3.a 500 gal, Dyed Diesel tank Regulation No. 3, Part C, Section II.E.3.a 300 gal, Unleaded Gasoline Tank Regulation No. 3, Part C, Section II.E.3.aaa 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz 30,000 gal Pressurized NGL Storage Tank Regulation No. 3, Part C, Section II.E.3.zz 1 80 bbl, Produced Water Tank, Sump 1 Regulation No. 3, Part C, Section II.E.3.uu 80 bbl, Produced Water Tank, Sump 2 Regulation No. 3, Part C, Section II.E.3.uu 80 bbl, Produced Water Tank, Sump 14 Regulation No. 3, Part C, Section II.E.3.uu 80 bbl, Produced Water Tank, Sump 6 Regulation No. 3, Part C, Section II.E.3.uu. 200 bbl, Produced Water Tank, Tank 7209 Regulation No. 3, Part C, Section II.E.3.uu 80 bbl, Produced Water Tank, Tank 7213 Regulation No. 3, Part C, Section II.E.3.uu 200 bbl, Produced Water Tank, Tank 7214 Regulation No. 3, Part C, Section II.E.3.uu 80 bbl, Wastewater Tank, Sump 8 Regulation No. 3, Part C, Section II.E.3.a 80 bbl, Stormwater Tank, Sump 5 Regulation No. 3, Part C, Section II.E.3.a 240 bbl, Lube Oil tank, 805 Central Regulation No. 3, Part C, Section II.E.3.aaa 6,000 gal, Lube Oil tank, 805 West Regulation No. 3, Part C, Section II.E.3.aaa 500 gal, Lube Oil tank, AST -24 Regulation No. 3, Part C, Section II.E.3.aaa 500 gal, portable Used Oil Tank Regulation No. 3, Part C, Section II.E.3.aaa 225 gal, Used Oil Tank, #1 Regulation No. 3, Part C, Section II.E.3.aaa 225 gal, Used Oil Tank, #2 Regulation No. 3, Part C, Section II.E.3.aaa 225 gal, Used Oil Tank, #3 Regulation No. 3, Part C, Section II.E.3.aaa 110 bbl, Used Oil tank, AST -13 Regulation No. 3, Part C, Section II.E.3.aaa 80 bbl, Slop Oil Tank, Sump 5 Regulation No. 3, Part C, Section II.E.3.a 10 bbl, Slop Oil Tank, Sump 7 Regulation No. 3, Part C, Section II.E.3.a 80 bbl, Slop Oil Tank, Sump 9 Regulation No. 3, Part C, Section II.E.3.a 210 bbl, Slop Oil Tank, Sump 12 Regulation No. 3, Part C, Section II.E.3.a 10 bbl, Slop Oil Tank, Sump 10 Regulation No. 3, Part C, Section II.E.3.a 30 bbl, Slop Oil Tank Sump 4 Regulation No. 3, Part C, Section II.E.3.a 220 gal, Slop Oil tank, Air Compressor Sump Regulation No. 3, Part C, Section II.E.3.a 1,000 gal, Norkool tank, AST 7 Regulation No. 3, Part C, Section II.E.3.a 1000 gal, Norkool tank, AST 8 Regulation No. 3, Part C, Section II.E.3.a 1000 gal, Norkool tank, AST 19 Regulation No. 3, Part C, Section II.E.3.a 100 gal, Portable Methanol Tank Regulation No. 3, Part C, Section II.E.3.a 500 gal, Methanol tank, Randel Regulation No. 3, Part C, Section II.E.3.a 500 gal, Methanol tank, Petro Frac Regulation No. 3, Part C, Section II.E.3.a 500 gal, Methanol tank, 212 Regulation No. 3, Part C, Section II.E.3.a 500 gal, Methanol tank, CIG Regulation No. 3, Part C, Section II.E.3.a 1,000 gal, Methanol tank, AST 20 Regulation No. 3, Part C, Section II.E.3.a 1,000 gal, Methanol tank, AST 9 Regulation No. 3, Part C, Section II.E.3.a 4,000 gal, TEG Tank, Tank 7210 Regulation No. 3, Part C, Section II.E.3.a 2 500 gal, TEG tank, Ast 28 Regulation No. 3, Part C, Section II.E.3.a 80,000 gal Pressurized Butane Storage Tank Regulation No. 3, Part C, Section II.E.3.a 80,000 gal Pressurized Butane Storage Tank Regulation No. 3, Part C, Section II.E.3.a 30,000 gal Pressurized Propane Storage Tank Regulation No. 3, Part C, Section II.E.3.zz 18,000 gal Pressurized Methanol Storage Tank Regulation No. 3, Part C, Section II.E.3.a Kohler Commercial Pro 15 Methonal Trailer Pump Regulation No. 3, Part C, Section II.E.3.nnn(iii) Briggs & Stratton Vangaurde 16HP Hotsy Pump Regulation No. 3, Part C, Section II.E.3.nnn(iii) Hotsy Heater, 385,800 BTU/hr Regulation No. 3, Part C, Section II.E.3.ggg Catco 12,000 BTU/Hr CIG Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg Catco 12,000 BTU/Hr Excel Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg CataDyne 12,000 BTU/Hr Box Elder Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg CataDyne 6,000 BTU/Hr Bypass Gas Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg CataDyne 6,000 BTU/Hr North Inlet Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg CataDyne 6,000 BTU/Hr South Inlet Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg CataDyne 6,000 BTU/Hr Low Pressure Inlet Meter Shed Heater Regulation No. 3, Part C, Section II.E.3.ggg 3 Operating Permit Application Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE MISCELLANEOUS PROCESSES FORM 2000-3U6 Rev 06-95 1. Facility name: Roggen Natural Gas Processing Plant 3. Stack identification code: Flare 2. Facility identification code: CO 123-0049 4. Process (Unit) code: Flare 5. Unit description: Plant Flare 6. Indicate the control technology status. ❑ Uncontrolled ® Controlled If the process is controlled, enter the control device code(s) from the appropriate form(s): 2000-400 Flare 2000-401 2000-402 2000-403 2000-404 2000-405 2000-406 2000-407 7 Actual annual process rates for 19 8. Date first placed in service: < 2010 Date of last modification: 9. Normal operating schedule: 24 hrs./day 7 days/wk. 8760 hours/yr. 10. Describe this process (please attach a flow diagram of the process). Attached? ❑ Plant flare with a DRE of 95% to handle maintenance and malfunction emissions. 11. List the types and amounts of raw materials used in this process: Material Storage/material handling process Actual usage Units Maximum usage Units Clean-up solvents Other (specify) 12. List the types and amounts of finished products: Material Storage/material handling process Actual Units amount produced Maximum Units amount produced 13. Process fuel usage: Type of fuel Maximum heat input to process million BTU/hr. Actual usage Units Maximum usage Units Pilot Fuel Gas 0.17 1.31 MMscf/year Purge/Waste Gas NA 86.75 MMscf/year 14. Describe any fugitive emissions associated with this process, such as outdoor storage piles, unpaved roads, open conveyors, etc.: ***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 2000-500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 and its attachment(s) to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. ***** Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS Colorado Department of Public Health and Environment Air Pollution Control Division FORM 2000-601 09-94 SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Stack identification code: Flare 4. Unit identification code: Flare 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached X Air pollutant Actual. Potential to emit Maximum allowable Quantity U TPY U TPY Particulates (TSP) TPY PM -10 TPY Nitrogen oxides 3.55 TPY 0.065 2 3.55 Volatile organic compounds . . 17.19 TPY 396.3 7 17.19 Carbon monoxide 15.93 TPY 0.31 2 15.93 Lead :.:" . TPY Sulfur dioxide 0.03 TPY 0.6 7 0.03 Total reduced sulfur TPY Reduced sulfur compounds TPY Hydrogen sulfide ,........... ... ..._.... - — TPY Sulfuric Acid Mist TPY Fluorides ': ._ TPY TPY TPY TPY TPY Units (U) should be entered as follows: 1= lb/hr 2 = lb/mmBTU 3 = grains/dscf 4 = lb/ gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other (specify) 9 = other (specify) 10 = other (specify) Operating Permit Application PLANT -WIDE HAZARDOUS AIR POLLUTANTS Colorado Department of Public Health and Environment Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE FORM 2000-602 Rev 06-95 1. Facility name: Roggen Natural Gas Processing Plant 2. Facility identification code: CO 123-0049 3. Complete the following emissions summary for all hazardous air emissions at this facility. Calculations attached. Attach a copy of all calculations to this form. Attached X — Updated calculations for Flare Pollutant CAS Common or Generic Pollutant Name Actual emissions. Allowable OR Potential to emit uantity Units Quantity Units Highest Individual HAP < 8.0 TPY Total Facilitywide HAPs <22.9 TPY NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application Colorado Department of Public Health and Environment Air Pollution Control Division PLANT -WIDE CRITERIA AIR POLLUTANTS FORM 2000-603 09-94 SEE INSTRUCTIONS ON REVERSE SIDE 1.Facility name: Roggen Natural Gas 2.Facility identification code: Processing Plant CO 123-0049 3. Complete the following emissions summary for the listed emissions at this facility. Air pollutant Actual Potential to emit Maximum allowable TPY TPY TPY Particulates (TSP) 10.6 10.6 PM -10 10.6 10.6 Nitrogen oxides 217.8 217.8 Volatile organic compounds 227.0 227.0 Carbon monoxide 302.4 302.4 Lead Sulfur dioxide 30.5 30.5 Total reduced sulfur Reduced sulfur compounds Hydrogen sulfide Sulfuric acid mist Fluorides Colorado Department of Health Air Pollution Control Division Facility Name: Roggen Gas Plant I, ADMINISTRATION Facility Identification Code: CO 123-0049 This application contains the following forms: II. EMISSIONS SOURCE DESCRIPTION This application contains the following forms (one form for each facility boiler, printing • Form 2000-100, Facility Identification O Form 2000-101, Facility Plot Plan X Forms 2000-102, -102A, and -102B, Source and Site Descriptions *Form 2000-102B included with updated list of insignificant activities at this facility.Total Number of This Form O Form 2000-200, Stack Identification Form 2000-300, Boiler or Furnace Operation ❑ Form 2000-301, Storage Tanks O Form 2000-302, Internal Combustion Engine ❑ Form 2000-303, Incineration ❑ Form 2000-304, Printing Operations ❑ Form 2000-305, Painting and Coating Operations X Form 2000-306, Miscellaneous Processes ❑ Form 2000-307, Glycol Dehydration Unit III. AIR POLLUTION CONTROL SYSTEM This application contains the following forms: IV. COMPLIANCE DEMONSTRATION This application contains the following forms (one for each facility boiler, printing operation, O Form 2000-400, Miscellaneous ❑ Form 2000-401, Condensers ❑ Form 2000-402, Adsorbers ❑ Form 2000-403, Catalytic or Thermal Oxidation O Form 2000-404, Cyclones/Settling Chambers ❑ Form 2000-405, Electrostatic Precipitators ❑ Form 2000-406, Wet Collection Systems ❑ Form 2000-407, Baghouses/Fabric Filters ❑ Form 2000-500, Compliance Certification - Monitoring and Reporting ❑ Form 2000-501, Continuous Emission Monitoring O Form 2000-502, Periodic Emission Monitoring Using Portable Monitors ❑ Form 2000-503, Control System Parameters or Operation parameters of a Process ❑ Form 2000-504, Monitoring Maintenance Procedures p Form 2000-505, Stack Testing ❑ Form 2000-506, Fuel Sampling and Analysis ❑ Form 2000-507, Recordkeeping ❑ Form 2000-508, Other Methods 1 Total Number of This Form Total Number of This Form 1 V. EMISSION SUMMARY AND COMPLIANCE CERTIFICATION This application contains the following forms quantifying emissions, certifying compliance with applicable requirements, and developing a compliance plan Total Number of This Form ❑ Form 2000-600, Emission Unit Hazardous Air Pollutants X Form 2000-601, Emission Unit Criteria Air Pollutants x Form 2000-602, Facility Hazardous Air Pollutants 1 1 X Form 2000-603, Facility Criteria Air Pollutants ❑ Form 2000-604, Applicable Requirements and Status of Emission Unit ❑ Form 2000-605, Permit Shield Protection Identification ❑ Form 2000-606, Emission Unit Compliance Plan - Comrnitments and Schedule ❑ Form 2000-607, Plant -Wide Applicable Requirements ❑ Form 2000-608, Plant -Wide Compliance Plan - Commitments and Schedule 1 SIGNATURE OF RESPONSIBLE OFFICIAL - FEDERAL/STATE CONDITIONS STATEMENT OF COMPLETENESS I have reviewed this application in its entirety and, based on information and belief formed after reasonable inquiry, I certify that the statements and information contained in this application are true, accurate and complete. B. CERTIFICATION OF FACILITY COMPLIANCE STATUS - FEDERAL/STATE CONDITIONS (check one box only) x I certify that the facility described in this air pollution permit application is with all applicable requirements. ❑ I certify that the facility described in this air pollution permit application is fully applicable requirements, except for the following emissions unit(s): fully in compliance in compliance with all (list all non -complying units) WARNING: Any person who knowingly, as defined in § 18-1-501(6), C.R.S., makes any false material statement, representation, or certification in, or omits material information from this application is guilty of a misdemeanor and may be punished in accordance with the provisions of § 25-7122.1, C.R.S. Printed or Typed Name David M. Jost Signature 13a,1/1/ Title Vice President of Northern Operations Date Signed A.)/al-Vc)-O i vyc.au..g . c...a1. Colorado Department of Health Air Pollution Control Division Facility Name: Roggen Gas Plant 09-94 Facility Identification Code: CO 123-0049 VI. SIGNATURE OF RESPONSIBLE OFFICIAL - STATE ONLY CONDITIONS A. STATEMENT OF COMPLETENESS I have reviewed this application in its entirety and, based on information and belief formed after reasonable inquiry, I certify that the statements and information contained in this application are true, accurate and complete. B. CERTIFICATION OF FACILITY COMPLIANCE STATUS FOR STATE -ONLY CONDITIONS (check one box only) X I certify that the facility described in this air pollution permit application is fully in compliance with all applicable requirements. ❑ I certify that the facility described in this air pollution permit application is fully in compliance with all applicable requirements, except for the following emissions unit(s): (list all non -complying units) WARNING: Any person who knowingly, as defined in § 18-1-501(6), C.R.S., makes any false material statement, representation, or certification in, or omits material information from this application is guilty of a misdemeanor and may be punished in accordance with the provisions of § 25-7122.1, C.R.S. Printed or Typed Name David M. Jost Title Vice President of Northern Operations Signature /j� aitr. / ley)AJ' Date Signed kV -U-4)6 )6 I? 1 SEND ALL MATERIALS TO: COLORADO DEPARTMENT OF HEALTH APCD-SS-B 1 4300 CHERRY CREEK DRIVE SOUTH DENVER, CO 80246-1530 3 dcp Midstream. DCP Midstream 370 17th St., Suite 2500 Denver, CO 80202 (303) 605-2039 www.dcpmidstream.com December 13, 2018 Delivered via UPS Tracking No. — 1Z F46 915 02 9650 3721 Colorado Department of Public Health and Environment Air Pollution Control Division ATTN: Elie Schuchardt 4300 Cherry Creek Drive South Denver, CO 80246-1530 Re: Roggen Natural Gas Processing Plant Title V Modification: 95OPWE055 AIRS ID 123/0049 Dear Ms. Schuchardt: DCP Operating Company, LP ("DCP") is submitting the attached revised calculations and updated APEN form for the pressurized liquid loadout source at the Roggen Natural Gas Processing Plant located at Section 24, Range 63W, Township 2N in Weld County; Colorado. This facility currently operates under Title V permit 95OPWE055 originally issued on May 1, 2001 and last revised on August 29, 2005, with an expiration date of May 1, 2006. A timely Title V permit renewal application was submitted in April 2005, and a draft operating permit was issued July 26, 2018. As part of the source review process for the 95OPWE055 Title V renewal, DCP requested minor changes to the proposed throughput limit and emission factors for the pressurized liquids loadout source F031 (AIRS 133) while retaining the previously established emission limit of 5.0 tpy VOCs. DCP is submitting the attached updated APEN form and emission calculations in support of these requested changes. If you have any questions or require any additional information about this submittal, please contact me at (303) 605-2039 or RShankaran@dcpmidstream.com. Sincerely, DCP Operating Company, LP Roshini Shankaran Senior Environmental Engineer RECEIVED DEC 142018 Hydrocarbon Liquid Loading APEN Form APCD-208 Air Pollutant Emission Notice (APEN) and Application for Construction Permit All sections of this APEN and application must be completed for both new and existing facilities, including APEN updates. An application with missing information may be determined incomplete and may be returned or result in longer application processing times. You may be charged an additional APEN fee if the APEN is filled out incorrectly or is missing information and requires re -submittal. This APEN is to be used for hydrocarbon liquid loading only. If your emission unit does not fall into this category, there may be a more specific APEN for your source (e.g. amine sweetening unit, glycol dehydration unit, condensate storage tanks, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd. This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. ,„tAP, hD Souree!- Permit Number: 95OPWE055 AIRS ID Number: 123 / 0049 / 133 [Leave blank unless APCD has already assigned a permit II and AIRS ID] Section 1 - Administrative Information Company Name': DCP Operating Company, LP Site Name: Roggen Gas Plant Site Location: 35409 Weld County Road 18 Roggen, CO 80652 Mailing Address: (Include Zip Code) 370 17th Street, Suite 2500 Denver, CO 80202 Site Location County: Weld NAICS or SIC Code: 1321 Contact Person: Roshini Shankaran Phone Number: 303-605-2039 E -Mail Address2: RShankaran@DCPMidstream.com I Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear on all documents issued by the APCD. Any changes will require additional paperwork. 2 Permits, exemption letters, and any processing invoices will be issued by the APCD via e-mail to the address provided. 391098 Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 1 I [y1, ae v�w�c Permit Number: 95OPWE055 AIRS ID Number: 123 /0049/133 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 2 - Requested Action ❑ NEW permit OR newly -reported emission source 0 Request coverage under construction permit ❑✓ Request coverage under General Permit GP07 If General Permit coverage is requested, the General Permit registration fee of $312.50 must be submitted along with the APEN filing fee. -OR - ❑✓ MODIFICATION to existing permit (check each box below that applies) 0 Change fuel or equipment ❑ Change company name3 ❑✓ Change permit limit 0 Transfer of ownership4 0 Other (describe below) - OR ▪ APEN submittal for update only (Note blank APENs will not be accepted) - ADDITIONAL PERMIT ACTIONS - El Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE) Additional Info Et Notes: Revise emission calculations, update annual throughput limit. No change in permit limit for VOC emissions. 3 For company name change, a completed Company Name Change Certification Form (Form APCD-106) must be submitted. 4 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted. Section 3 - General Information General description of equipment and purpose: pressurized liquids Ioadout Company equipment Identification No. (optional): F031 For existing sources, operation began on: 1/1/1990 For new or reconstructed sources, the projected start-up date is: Will this equipment be operated in any NAAQS nonattainment area? Yes No p • Is this equipment located at a stationary source that is considered a Major Source of (HAP) emissions? Yes No • IS Does this source load gasoline into transport vehicles? Yes No ■ SI Is this source located at an oil and gas exploration and production site? Yes No ■ p If yes: Does this source load less than 10,000 gallons of crude oil per day on an annual average? Yes No • ■ Does this source splash fill less than 6750 bbl of condensate per year? Yes No • ■ Does this source submerge fill less than 16308 bbl of condensate per year? Yes No ■ ■ Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 MW.[COLORADO 2 I I 11=;,=. Permit Number: 95OPWE055 AIRS ID Number: 123 / 0049 /133 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 4 - Process Equipment Information Product Loaded: O Condensate ❑ Crude oil ❑✓ Other: propane, butane, NGLs If this APEN is being filed for vapors displaced from cargo carrier, complete the following: Requested Volume Loaded5: bbl/year This product is loaded from tanks at this facility into: (e.g. "rail tank cars" or "tank trucks") Actual Volume Loaded: bbl/year If site specific emission factor is used to calculate emissions, complete the following: Saturation Factor: Average temperature of bulk liquid loading: '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 lines, complete the following: Requested Volume Loaded5: 2,064,286 bbl/year Actual Volume Loaded: 3,216 2 bbl/year Product Density: See Below 3 lb/ft3 Load Line Volume: 0.0236 ft3/truckload Vapor Recovery Line Volume: 0.0236 ft3/truckload 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 1 Limit Requested = 8,670 loads/yr. DCP requests a limit on number of loadout events per year rather than a throughput limit. DCP assumed 100% of the annual loads as Natural Gas Liquids (NGL) to provide a conservative estimate of potential emissions from this source. 2 Actual 2017 volume loaded = 36 loads/yr 3 Propane density = 31.72 lb/ft3 Butane density = 36.20 lb/ft3 Natural Gas Liquids (NGL) = 46.15 lb/ft3 - Emission calculations use this worst case product to provide a conservative estimate of potential emissions from this source. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 31 AVCOLORADO I °,'' Permit Number: 95OPWE055 AIRS ID Number: 123 / 0049 / 133 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 5 - Stack Information Geographical Coordinates (Latitude/Longitude or UTM) 40.1174 / -104.3883 Stack ID No. Discharge Height Above Ground Level. (feet) Temp. F) Flow Rate _ (ACFM) Velocity (ft -/sec) S031 Indicate the direction of the stack outlet: (check one) ❑ Upward O Horizontal ❑ Downward O Other (describe): Indicate the stack opening and size: (check one) O Circular Interior stack diameter (inches): ❑ Other (describe): O Upward with obstructing raincap Section 6 - Control Device Information Check this box if no emission control equipment or practices are used to reduce emissions, and skip to the next section. O Loading occurs using a vapor balance system: Requested Control Efficiency: % ❑ Combustion Device: Used for control of: Rating: Type: Requested Control Efficiency: Manufacturer Guaranteed Control Efficiency: MMBtu/hr Make/Model: Minimum Temperature: °F Waste Gas Heat Content: Btu/scf Constant Pilot Light: O Yes O No Pilot Burner Rating: MMBtu/hr ❑ Other: Pollutants Controlled: Description: Requested Control Efficiency: Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO A- ! 4 i nnsantd . Maat�l�LEnvir6�rM Permit Number: 95OPWE055 AIRS ID Number: 123 /0049/133 PM [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 7 - Emissions Inventory Information Attach all emissions calculations and emission factor documentation to this APEN form. If multiple emission control methods were identified in Section 6, the following table can be used to state the overall (or combined) control efficiency (% reduction): Description of Control Method(s) Overall Requested Control Efficiency (% reduction in emissions) SOx NO. CO VOC HAPs Other: ❑ Using State Emission Factors (Required for GP07) VOC Benzene n -Hexane ❑ Condensate 0.236 Lbs/BBL 0.00041 Lbs/BBL 0.0036 Lbs/BBL ❑ Crude 0.104 Lbs/BBL 0.00018 Lbs/BBL 0.0016 Lbs/BBL From what year is the following reported actual annual emissions data? 2017 Criteria Pollutant Emissions Inventory Pollutant PM Emission Factor Actual Annual Emissions Requested Annual Permit Emission Limit(s)5 Uncontrolled Basis Units _. Source (AP -42; Mfg., etc.) Uncontrolled Emissions (tons/year). Controlled Emissions6 (tons/year) Uncontrolled Emissions (tons/year) Controlled -- Emissions (tons/year) SOx NO. CO VOC 1.15° lb/load Eng. Calc. 0.01 0.01 5.0 5.0 4 Propane = 0.79 lb/load, Butane = 0.90 lb/load, NGL = 1.15 lb/load - NGL emission factor used to provide a conservative estimate of potential emissions from this source. Non -Criteria Reportable Pollutant Emissions Inventory Chemical Name Chemical Abstract Service (CAS) Number Emission Factor Actual Annual Emissions Uncontrolled Basis Units6 Source. (AP -42, Mfg., etc.) Uncontrolled Emissions (pounds/year) Controlled Emissions (pounds/year) Benzene 71432 Toluene 108883 Ethylbenzene 100414 Xylene 1330207 n -Hexane 110543 2,2,4- Trimethylpentane 540841 Other: 5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. 6 Annual emissions fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. Form APCD-208 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 COLORADO 5 I V x.,ur. s emn.rnmeni Permit Number: 95OPWE055 AIRS ID Number: 123 / 0049 / 133 [Leave blank unless APCD has already assigned a permit # and AIRS ID] Section 8 - Applicant Certification I hereby certify that all information contained herein and information submitted with this application is complete, true, and correct. If this is a registration for coverage under General Permit GP07, I further certify that this source is and will be operated in full compliance with each condition of General Permit GP07. i3 /2-O8" Signature of Legally Authorized Person (not a vendor or consultant) Date Roshini Shankaran Senior Environmental Engineer Name (print) Title Check the appropriate box to request a copy of the: ❑ Draft permit prior to issuance ❑ Draft permit prior to public notice (Checking any of these boxes may result in an increased fee and/or processing time) This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration of the five-year term, or when a reportable change is made (significant emissions increase, increase production, new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements. Send this form along with $191.13 and the General Permit registration fee of $312.50, if applicable, to: Colorado Department of Public Health and Environment Air Pollution Control Division APCD-SS-B1 4300 Cherry Creek Drive South Denver, CO 80246-1530 Make check payable to: Colorado Department of Public Health and Environment For more information or assistance call: Small Business Assistance Program (303) 692-3175 or (303) 692-3148 APCD Main Phone Number (303) 692-3150 Or visit the APCD website at: https: / /www.colorado.gov/cdphe/apcd Form APCD-2O8 - Hydrocarbon Liquid Loading APEN - Revision 7/2018 [COLORADO 6 I o a Attachment B: Updated Emission Calculations and Supporting Documentation F013 (AIRS 133) — Pressurized Liquids Loadout Roggen Natural Gas Processing Plant VOC Emissions from Liquid Hoses Loaded Liq. Density° Hose Vol. Loads Per Emission Emission Emission Factors .Product Ib ft3 Year Jlb/year) (ton/year) II_Al Propane Loading & Unloading 31.72 0.0236 0 0.00 0.00 0.75 Butane Loading & Unloading 36.20 0.0236 0 0.00 0.00 0.86 NGL Loading & Unloading 46.15 0.0236 8670 9457.04 4.73 1.09 Total 9457.04 4.73 Liquid Density converted from lb/gal AP -42 Appendix A values, using 7.48 gal/scf conversion factor. Liquid Density of gasoline used for NGL's VOC Emissions from Vapor Return Hoses Loaded Vap. Density Hose Vol. Loads Per Emission Emission Emission Factors Product Ib ft3 jft3) Year (lb/year) (ton/vear). lb/load Propane Loading & Unloading 1.5818 0.0236 0 0.00 0.00 0.04 Butane Loading & Unloading 2.0846 0.0236 0 0.00 0.00 0.05 NGL Loading & Unloading 2.6363 0.0236 8670 540.20 0.27 0.06 Total — — — 540.20 0.27 POTENTIAL VOC EMISS. FROM TRUCK LOADOUT Roggen Natural Gas Plant Hose Emissions From Truck Loadout VOC n-Hexanes'6 Emission Factors (Ib/loadj Propane Butane NGL 0.79 0.90 1.15 Annual Emissions 5.00 tpy 235.8 lb/yr n -Hexane Emissions (lb/yr) = VOC emissions (ton/yr) • 2000 (lb/ton) / NGL MW 1733 lb/lb-moll. n -Hexane mol frac. 12.0116%/100)* n -Hexane MW (86.18 lb/lb-moll 5 n -Hexane mol%from Plant GC analysis. C6+ mol% assumed to be 100% n -Hexane to provide conservative look at potential HAP emissions . ESTIMATE OF PRESSURIZED TRUCK LOADOUT EMISSIONS (F031) Roggen Natural Gas Plant Potential to Emit Calculation of Potential VOC Emissions from Propane, Butane, and NGL Truck Loading Losses Assumptions: There are two hoses connected to each truck during loadout. Liquid Hose Diameter = Vapor Hose Diameter = Liquid Hose Length = Vapor Hose Length = Liquid Hose Volume = Vapor Hose Volume = Each truck is pressurized to storage tank pressure as listed below. Propane Tank Pressure = Butane Tank Pressure = Natural Gasoline Tank Pressure = 2 inches 2 inches 1.1 feet 1.1 feet 0.0236 cubic feet 0.0236 cubic feet 200.0 psia 200.0 psia 200.0 psis Tot. volume of products loaded/year and tot. loadout events/year as listed below. Potential Throughput Product bbl Yeart't Loads Year C3, C4, NGL Loading & Unloading C3, C4, NGL Loading & Unloading C3, C4, NGL Loading & Unloading C3, C4, NGL Loading & Unloading C3, C4, NGL Loading & Unloading C3, C4, NGL Loading & Unloading Propane 0 0 Butane 0 0 Natural Gas Liquids (NGL)3 2,064,286 8670 Yearly Total 2,064,286 8670 t Each tank truck has a capacity of 11,000 gallons. Assume 10,000 gallons/load. 2 Annual throughput (bbl/yr) = loads/yr * 10,000 gallons/load " 1 gallon / 42 bbl 3 All loadout events calculated for NGL loading and unloading, to provide a conservative estimate of emissions All liquid lines contain liquid products at individual specific gravity. All vapor return lines contain products that behave as Ideal Gases at 60 deg. F and storage tank press. P*V=n*R*T Where: Propane: Butane: Natural Gasoline: P = pressure in hose at time of disconnect = storage tank pressure (psig) V = volume of hoses (cubic feet) n = number of lb -moles of product in hoses R = Universal Gas Constant = 10.73 cubic feet *psi / Ibmole*deg R T = ave. loadout temp. 60 deg F = 519.67 deg R n = 0.0359 Ibmole/ft3 * 44.1 Ib/Ibmol = 1.5818 Ib/ft3 n = 0.0359 Ibmole/ft3 * 58.12 Ib/Ibmol = 2.0846 Ib/ft3 n = 0.0359 Ibmole/ft3 * 73.5 Ib/Ibmol = 2.6363 lb/ft3 Hello