HomeMy WebLinkAbout20190719.tiffCOL At
Departnient of Public
Health Et Environment
Dedicated to protecting and improving the health and environment of the people of Colorado
Weld County. - Clerk to the Board
1150 0 St
PO Box 758
Greeley, CO 80632
January 29, 2019
Dear Sir or Madam:
RECEIVED
FEB 04- 2019
WELD COUNTY
COMMISSIONERS
On January 31, 2019, the Air Pollution Control Division will begin a 30 -day public notice period for
DCP Operating Company, LP Roggen Natural Gas Processing Plant. A copy of this public notice and
the public comment packet are enclosed.
Thank you for assisting the Division by posting a copy of this public comment packet in your office.
Public copies of these documents are required by Colorado Air Quality Control Commission
regulations. The packet must be available for public inspection for a period of thirty (30) days from
the beginning of the public notice period. Please send any comment regarding this public notice to
the address below.
Colorado Dept. of Public Health Et Environment
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, Colorado 80246-1530
Attention: Clara Gonzales
Regards,
Clara Gonzales
Public Notice Coordinator
Stationary Sources Program
Air Pollution Control Division
Enclosure
4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe
John W. Hickenlooper, Governor I Larry Wolk, MD, MSPH, Executive Director and Chief Medical Officer
?4 UbVc. Pie\i‘ek_13
2.120 / 1°1
CC1P1.(TP,HL C31T),
wit (5M1 IC--kIc
2113h9
2019-0719
Air Pollution Control Division
Notice Of A Proposed Renewal Title V Operating Permit
Warranting Public Comment
Website Title: DCP Operating Company, LP Roggen Natural Gas Processing Plant - Weld County
Notice Period Begins: January 31, 2019
NOTICE is hereby given that an application to renew an Operating Permit has been submitted to the
Colorado Air Pollution Control Division, 4300 Cherry Creek Drive South, Denver, Colorado 80246-1530, for
the following source of air pollution:
Applicant: DCP Operating Company, LP
370 17th Street, Suite 250.0
Denver, CO 80202
Facility: Roggen Natural Gas Processing Plant
35409 Weld County Road 18
Roggen, CO 80652
DCP Operating Company, LP has applied to renew the Operating Permit for the Roggen Natural Gas
Processing Plant in Weld County, CO. This facility is a natural gas processing plant. The operating permit
renewal for this facility includes the following changes for all points: modification of permit limitations and
emission factors to reflect the facility's current mode of operation, incorporate Colorado Construction
Permits 01WE0208, 07WE0988, 10WE1659, 12WE1193 and 12WE1242, permit the plant emergency flare,
update monitoring requirements to be consistent with recently issued permits and include the most recent
version of applicable federal and state regulations. This operating permit renewal incorporates equipment
previously permitted under Colorado Construction Permits 01WE0208, 07WE0988, 10WE1659, 12WE1193 and
12WE1242. The limitations contained in these permits were subsequently modified to reflect the most
current mode of facility operation, as requested in various minor and significant modification applications.
The plant emergency flare was permitted for the first time under this renewal action. A facility -wide HAP
limit was introduced to ensure major source requirements are not triggered under federal rules. A copy of
the application, including supplemental information, the Division's analysis, and a draft of the Renewal
Operating Permit 95OPWE055 have been filed with the Weld County Clerk's office. A copy of the draft
permit and the Division's analysis are available on the Division's website at
https://www.colorado.gov/pacific/cdphe/air-permit-public-notices. The Division has made a preliminary
determination of approval of the application. Based on the information submitted by the applicant, the
Division has prepared the draft renewal operating permit for approval. Any interested person may contact
Elie Schuchardt of the Division at 303-692-6332 to obtain additional information. Any interested person may
submit written comments to the Division concerning 1) the sufficiency of the preliminary analysis, 2)
whether the permit application should be approved or denied, 3) the ability of the proposed activity to
comply with applicable requirements, 4) the air quality impacts of, alternatives to, and control technology
required on the source or modification, and 5) any other appropriate air quality considerations. Any
interested person may submit a written request to the Division for a public comment hearing before the
Colorado Air Quality Control Commission (Commission) to receive comments regarding the concerns listed
above as well as the sufficiency of the preliminary analysis and whether the Division should approve or deny
the permit application. If requested, the hearing will be held before the Commission within 60 days of its
receipt of the request for a hearing unless a longer time period is agreed upon by the Division and the
applicant. The hearing request must: 1) identify the individual or group requesting the hearing, 2) state his
or her address and phone number, and 3) state the reason(s) for the request, the manner in which the
person is affected by the proceedings, and an explanation of why the person's interests are not already
adequately represented. The Division will receive and consider the written public comments and requests
for any hearing for thirty calendar days after the date of this Notice.
Comments may be submitted using the following options:
Use the web form at https://www.colorado.Rov/pacific/cdphe/air-permit-public-notices. This page
also includes guidance for public participation
• Send an email to cdphe,commentsapcd®state.co.us
• Send comments to our mailing address:
Elie Schuchardt
Colorado Department of Public Health and Environment
4300 Cherry Creek Drive South, APCD-SS-B1
Denver, Colorado 80246-1530
Hearing requests may be submitted to the email address or the mailing address noted above.
Colorado Department
of Public Health
and Environment
OPERATING PERMIT
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
First Issued: May 1, 2001
Renewed: DRAT
AIR POLLUTION CONTROL DIVISION
COLORADO OPERATING PERMIT
FACILITY NAME:
FACILITY ID:
RENEWED:
EXPIRATION DA 1'E:
MODIFICATIONS:
Roggen Natural Gas
Processing Plant
123/0049
DRAFT
DRAFT
See Appendix F of Permit
OPERATING PERMIT NUMBER
95OPWE055
Issued in accordance with the provisions of the Colorado Air Pollution Prevention and Control Act, 25-7-101
et sec . and applicable rules and regulations.
ISSUED TO:
DCP Operating Company, LP
370 17th Street, Suite 2500
Denver, CO 80202
PLANT SI IE LOCATION:
Roggen Natural Gas Processing Plant
35409 Weld County Road 18
Roggen, CO 80652
INFORMATION RELIED UPON
Operating Permit Renewal Application Received:
And Additional Information Received:
Nature of Business:
Primary SIC:
Natural Gas Processing
1321
RESPONSIBLE OFFICIAL
Name:
Title:
David M. Jost
Vice President of Northern
Operations
Phone: (970) 378-6345
April 29, 2005
April 2, 2007; March 21, 2016; July 10, 2017;
July 31, 2017; September 11, 2017; September 22, 2017;
November 13, 2017, November 8, 2018,
December 14, 2018
FACILITY CONTACT PERSON
Name:
Title:
Roshini Shankaran
Senior Environmental Engineer
Phone: (303) 605-2039
SUBMITTAL DEADLINES —
First Semi -Annual Monitoring Period:; DRAFT
Subsequent Semi -Annual Monitoring Periods: DRAFT
Semi -Annual Monitoring Reports: DRAFT
First Annual Compliance Period.: DRAFT
Subsequent Annual Compliance Periods.: DRAFT
Annual Compliance CertificationDRAFT
Note that the Semi -Annual Monitoring Reports and the Annual Compliance report must be received at
the Division office by 5:00 p.m. on the due date. Postmarked dates will not be accepted for the purposes
of determining the timely receipt of those reports.
TABLE OF CONTENTS:
SECTION I - General Activities and Summary 1
1. Permitted Activities 1
2. Alternative Operating Scenarios 3
3. Non -Attainment New Source Review (NANSR) and Prevention of Significant Deterioration
(PSD) 10
4. Accidental Release Prevention Program (112(r)) 10
5. Compliance Assurance Monitoring (CAM) 10
6. Summary of Emission Units 12
SECTION II - Specific Permit Terms 14
1. C-154 — Waukesha 1,100 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 101 14
C-155/157/160 — Waukesha 806 HP Natural Gas Fired Internal Combustion Engines, AIRS ID:
102/107/113 14
C-159 — Waukesha 1,350 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 103 14
C-161 — Waukesha 1,350 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 108 14
C-158 — Waukesha 916 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 110 14
C-156 — Waukesha 806 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 114 14
C-223 —Cooper Superior 720 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 115 14
C-225 - Cooper Superior 800 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 117 14
C-227 — Cooper Superior 720 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 119 14
C-192 — Waukesha 1,478 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 140 14
2. C-181 — Waukesha 1,478 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 134 38
3. H037 — Heat Recovery Corp 7.55 MMBtu/hr Natural Gas Fired Hot Oil Heater, AIRS ID: 129 51
4. P-138 - OPF, Inc. 30.7 MMBtu/hr Natural Gas Fired Hot Oil Heater, AIRS ID: 138 57
5. P033 — Custom 4 MMSCFD Triethylene Glycol Dehydration Unit, AIRS ID: 130 65
P-136 — Evco Fabrication 85 MMSCFD Triethylene Glycol Dehydration Unit, AIRS ID: 136 65
6. P-137 — Evco Fabrication 85 MMSCFD Amine Sweetening Unit, AIRS ID: 137 81
7. P025 - Fugitive Emissions from Equipment Leaks, AIRS ID: 122 88
8. P039 - Eight (8) 300 -bbl Stabilized Condensate Storage Tanks, AIRS ID: 125 94
9. F029 — Stabilized Condensate Truck Loadout, AIRS ID: 126 104
10. F031 — Pressurized Liquids Loadout, AIRS ID: 133 106
11. FLARE — John Zink Company, LLC Plant Emergency Flare, AIRS ID: 141 109
12. ECD — John Zink Company, LLC Enclosed Combustion Device (ECD) 117
RTO — Anguil Environmental Systems, Inc. Regenerative Thermal Oxidizer (RTO) 117
13. Kohler Model CV15S Methanol Pump 126
14. Facility -Wide Hazardous Air Pollutant (HAP) Emission Limits 130
15. Statewide Controls For Oil and Gas Operations — Compressors 134
16. Compliance Assurance Monitoring (CAM) Requirements (ver 4/16/2009) 137
SECTION III - Permit Shield 142
1. Specific Non -Applicable Requirements 142
2. General Conditions 142
3. Stream -lined Conditions 143
SECTION IV - General Permit Conditions (ver 8/28/2018) 144
1. Administrative Changes 144
2. Certification Requirements 144
3. Common Provisions 144
TABLE OF CONTENTS:
4. Compliance Requirements 148
5. Emergency Provisions 149
6. Emission Controls for Asbestos 149
7. Emissions Trading, Marketable Permits, Economic Incentives 149
8. Fee Payment 149
9. Fugitive Particulate Emissions 150
10. Inspection and Entry 150
11. Minor Permit Modifications 150
12. New Source Review 150
13. No Property Rights Conveyed 150
14. Odor 150
15. Off -Permit Changes to the Source 151
16. Opacity 151
17. Open Burning 151
18. Ozone Depleting Compounds 151
19. Permit Expiration and Renewal 151
20. Portable Sources 151
21. Prompt Deviation Reporting 151
22. Record Keeping and Reporting Requirements 152
23. Reopenings for Cause 153
24. Requirements for Major Stationary Sources 153
25. Section 502(b)(10) Changes 154
26. Severability Clause 155
27. Significant Permit Modifications 155
28. Special Provisions Concerning the Acid Rain Program 155
29. Transfer or Assignment of Ownership 155
30. Volatile Organic Compounds 155
31. Wood Stoves and Wood burning Appliances 156
APPENDIX A - Inspection Information 158
1. Directions to Plant: 158
2. Safety Equipment Required: 158
3. Facility Plot Plan. 158
4. List of Insignificant Activities: 160
APPENDIX B 163
Reporting Requirements and Definitions 163
Monitoring and Permit Deviation Report - Part I 168
Monitoring and Permit Deviation Report - Part II 171
Monitoring and Permit Deviation Report - Part III 174
APPENDIX C 176
Required Format for Annual Compliance Certification Reports 176
APPENDIX D 180
Notification Addresses 180
APPENDIX E 181
Permit Acronyms 181
TABLE OF CONTENTS:
APPENDIX F 183
Permit Modifications 183
APPENDIX G 184
Engine AOS Applicability Reports 184
APPENDIX H 196
Compliance Assurance Monitoring Plans 196
Compliance Assurance Monitoring Plan — Natural Gas Fired RICE 196
Compliance Assurance Monitoring Plan — TEG Dehydration Unit 200
Compliance Assurance Monitoring Plan —Amine Sweetening Unit 203
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 1
1. Permitted Activities
1.1
SECTION I - General Activities and Summary
The Roggen Natural Gas Processing Plant upgrades field gas to a saleable natural gas product by removing
heavier hydrocarbon constituents as natural gas liquids (NGLs) and condensate. The processing capacity
at Roggen is 85 MMSCFD.
High pressure gas from the Enterprise and Marla Compressor Stations enters the facility through a
common pipeline. Liquid condensate formed during transfer is separated out from the gas in an inlet slug
catcher. Gas in excess of the 85 MMSCFD processing capacity at Roggen is routed to the two (2) Box
Elder compressors (AIRS 110, 140) and is either sent to the Anadarko Wattenberg Plant for additional
processing, or bypasses the Roggen facility entirely and is piped offsite as unprocessed sales gas. Low
pressure field gas enters the facility via three gathering lines where the pressure is boosted with three (3)
inlet compressors (AIRS 115, 117, 119) and combined with the remaining high pressure gas. This
combined gas stream may be further processed with an amine sweetening unit (AIRS 137) to absorb acid
gas, followed by a TEG dehydration unit (AIRS 136) and subsequently molecular sieve beds to remove
water prior to the cryogenic processing trains. These unit operations are only used as necessary to meet
sales gas pipeline specifications. The gas is then divided and sent to one of three cryogenic units to separate
NGLs from the residue sales gas. Cryogenic temperatures are achieved via gas/gas exchange, a propane
refrigeration loop (engine AIRS 113) and JT expansion. The NGLs are separated from the residue sales
gas in the cryogenic demethanizer towers. Six (6) residue gas compressors (AIRS 102, 103, 107, 108, 114,
134) boost the residue gas to pipeline pressures. The residue gas exits the facility in a sales pipeline. A
slipstream of the residue sales gas is heated and used to regenerate the molecular sieve beds upon
saturation. Water entrained in this stream is removed with a small 1EG dehydration unit (AIRS 130).
NGLs collected during the cryogenic processing are stored in pressurized bullet tanks. Additional
pressurized bullet tanks are used to store third -party propane and butane, which may be blended with the
NGLs produced at Roggen. NGLs from the bullet tanks are either pumped offsite through a sales pipeline
or trucked out at the pressurized liquid loadout racks (AIRS 133). Condensate collected throughout the
process is combined with condensate that is trucked to the facility and upgraded to sales specification in
a condensate stabilization unit. The stabilized condensate is stored in atmospheric tanks (AIRS 125) and
is trucked offsite from the condensate loadout racks (AIRS 126). Vapors generated by the condensate
stabilization unit are routed to a vapor recovery unit (VRU, AIRS 101) and combined with the inlet gas
downstream of the slug catcher for reprocessing. Two (2) hot oil heaters (AIRS 129 and 138) bring the
heat transfer media used throughout the facility up to the required temperature for reboiler operation. An
emergency plant flare (AIRS 141) destructs process emissions from equipment blowdowns and
emergency venting. In addition to these point sources, fugitive emissions (AIRS 122) are also permitted
at this facility.
Emission control devices include: thirteen (13) NSCR beds to control compressor engine exhaust
emissions, one (1) dedicated enclosed combustion device to control condensate tank emissions, one (1)
open plant emergency flare to control facility -wide process emissions, one (1) enclosed combustion device
(ECD) permitted 2% downtime to control still vent emissions from both dehydration units, and one (1)
regenerative thermal oxidizer (RTO) to control acid gas vent emissions from the amine unit. This RTO
may also serve as a backup control device for the larger dehydration unit (AIRS 136) only. Flash tank
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 2
emissions from the amine and both dehydration units are hard -piped directly back to the low-pressure
plant inlet.
The Roggen Natural Gas. Processing Plant is located in Weld County, Colorado. The area in which the
plant operates is classified as attainment for all pollutants except ozone. It is classified as non -attainment
for ozone and is part of the 8 -hr Ozone Control Area as defined in Regulation No. 7, Section II.A.l .
The plant is located within 100 kilometers of Rocky Mountain National Park, a Federal Class I area. There
are no affected states within 50 miles of this facility.
1.2 Until such time as this permit expires or is modified or revoked, the permittee is allowed to discharge air
pollutants from this facility in accordance with the requirements, limitations, and conditions of this permit.
1.3 The Operating Permit incorporates the applicable requirements contained in the underlying construction
permits, and does not affect those applicable requirements, except as modified during review of the
application or as modified subsequent to permit issuance using the modification procedures found in
Regulation No. 3, Part C. These Part C procedures meet all applicable substantive New Source Review
requirements of Part B. Any revisions made using the provisions of Regulation No. 3, Part C shall become
new applicable requirements for purposes of this Operating Permit and shall survive reissuance. This
permit incorporates the applicable requirements (except as noted in Section II) from the following
construction permits:
Construction Permit
Description
01WE0208
AIRS 130: 4 MMSCFD TEG Dehydration Unit
07WE0988
AIRS 134: 1,478 HP Compressor RICE
10WE1659
AIRS 136: 85 MMSCFD TEG Dehydration Unit
AIRS 137: 85 MMSCFD Amine Sweetening Unit
AIRS 122: Fugitive Equipment Leaks
AIRS 138: 30.7 MMBtu/hr Hot Oil Heater
12WE1193
AIRS 140: 1,478 HP Compressor RICE
12WE1242
AIRS 125: 8 x 300 BBL Condensate Storage Tanks
1.4 All conditions in this permit are enforceable by the US Environmental Protection Agency, Colorado Air
Pollution Control Division (hereinafter Division) and its agents, and citizens unless otherwise specified.
State -only enforceable conditions are:
Section II — Condition 1.10.2.1 (Colorado Regulation No. 7 Section XVII.B.1.b)
Section II — Condition 1.10.2.2 (Colorado Regulation No. 7 Section XVII.E.2.a, b)
Section II — Conditions 3.6.3, 4.6.3 (Colorado Regulation No. 6 Part B Section II.C.3)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 3
Section II - Condition 3.7 (Colorado Regulation No. 6, Part A, Subpart A)
Section II Conditions 5.10.2, 6.10.1, 8.5.2, 11.9.1, 12.8.1, 12.8.3 (Colorado Regulation No. 7 Section
XVII.B)
Section II — Condition 5.10.3 (Colorado Regulation No. 7 Section XVII.D)
Section II — Condition 8.5.3 (Colorado Regulation No. 7 Section XVILC)
Section II Condition 11.8.2 (Colorado Regulation No. 3, Part B, Section III.E)
Section IV — Condition 3.g (Colorado Common Provisions Regulation, Affirmative Defense)
Section IV — Condition 14 (Colorado Regulation No. 2, as noted)
Section IV - Condition 18 (Colorado Regulation No. 15, as noted)
1.5 All information gathered pursuant to the requirements of this permit is subject to the Recordkeeping and
Reporting requirements listed under Condition 22 of the General Conditions in Section IV of this permit.
Either electronic or hard copy records are acceptable.
2. Alternative Operating Scenarios
(ver 10/12/2012 —updated to reflect changes to Colorado Regulation No. 7, NSPS, and MACT rules)
The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of
natural gas fired reciprocating internal combustion engines has been reviewed in accordance with the
requirements of Regulation No. 3., Part A, Section IV.A, Operational Flexibility -Alternative Operating
Scenarios, Regulation No. 3, Part B, Construction Permits, and Regulation No. 3, Part D, Major Stationary
Source New Source Review and Prevention of Significant Deterioration, and it has been found to meet all
applicable substantive and procedural requirements. This permit incorporates and shall be considered a
Construction Permit for any engine replacement performed in accordance with this AOS, and the permittee
shall be allowed to perform such engine replacement without applying for a revision to this permit or
obtaining a new Construction Permit.
2.1 Engine Replacement
The following AOS is incorporated into this permit in order to deal with a compressor engine breakdown
or periodic routine maintenance and repair of an existing onsite engine that requires the use of either a
temporary or permanent replacement engine. "Temporary" is defined as in the same service for 90
operating days or less in any 12 month period. "Permanent" is defined as in the same service for more
than 90 operating days in any 12 month period. The 90 days is the total number of days that the engine is
in operation. If the engine operates only part of a day, that day shall count as a single day towards the 90 -
day total. The compliance demonstrations and any periodic monitoring required by this AOS are in
addition to any compliance demonstrations or periodic monitoring required by this permit.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 4
All replacement engines are subject to all federally applicable and state -only requirements set forth in this
permit (including monitoring and record keeping), and shall be subject to any shield afforded by this
permit.
The results of all tests and the associated calculations required by this AOS shall be, submitted to the
Division within 30 calendar days of the test or within 60 days of the test if such testing is required to
demonstrate compliance with NSPS or MACT requirements. Results of all tests shall be kept on site for
five (5) years and made available to the Division upon request.
The permittee shall maintain a log on -site and contemporaneously record the start and stop date of any
engine replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number
of the engine(s) that are replaced during the term of this permit, and the manufacturer, date of manufacture,
model number, horsepower, and serial number of the replacement engine. In addition to the log, the
permittee shall maintain a copy of all Applicability Reports required under Section 2.1.2 and make them
available to the Division upon request.
2.1.1 The permittee may temporarily replace an existing compressor engine that is subject to the
emission limits set forth in this permit with an engine that is of the same manufacturer, model,
and horsepower or a different manufacturer, model, or horsepower as the existing engine without
modifying this permit, so long as the temporary replacement engine complies with all permit
limitations and other requirements applicable to the existing engine. Measurement of emissions
from the temporary replacement engine shall be made as set forth in Section 2.2.
The permittee may temporarily replace a grandfathered or permit exempt engine or an engine
that is not subject to emission limits without modifying this permit. In this circumstance,
potential annual emissions of NOx and CO from the temporary replacement engine must be less
than or equal to the potential annual emissions of NOx and CO from the original grandfathered
or permit exempt engine or for the engine that is not subject to emission limits, as determined by
applying appropriate emission factors (e.g. AP -42 or manufacturer's emission factors).
2.1.2 The permittee may permanently replace the existing compressor engine for the emission points
specified in Table 1 with the manufacturer, model, and horsepower engines listed in Table 1
without modifying this permit so long as the permanent replacement engine complies with all
permit limitations and other requirements applicable to the existing engine as well as any new
applicable requirements for the replacement engine. Measurement of emissions from the
permanent replacement engine and compliance with the applicable emission limitations shall be
made as set forth in Section 2.2.
The AOS cannot be used for the permanent replacement of an entire engine at any source that is
currently a major stationary source for purposes of Prevention of Significant Deterioration or
Non -Attainment Area New Source Review ("PSDINANSR") unless the existing engine has
emission limits that are below the significance levels in Reg 3, Part D, II.A.44.
An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and
serial number and horsepower of the permanent replacement engine shall be filed with the
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 5
Division for the permanent replacement engine within 14 calendar days of commencing
operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN
filing fee, a cover letter explaining that the permittee is exercising an alternative operating
scenario and is installing a permanent replacement engine, and a copy of the relevant
Applicability Reports for the replacement engine. Example Applicability Reports can be found
in Appendix G. This submittal shall be accompanied by a certification from the Responsible
Official indicating that "based on the information and belief formed after reasonable inquiry, the
statements and information included in the submittal are true, accurate and complete".
This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt
engine or an engine that is not subject to emission limits.
The permittee shall agree to pay fees based on the normal permit processing rate for review of
information submitted to the Division in regard to any permanent engine replacement.
Nothing in this AOS shall preclude the Division from taking an action, based on any permanent
engine replacement(s), for circumvention of any state or federal PSD/NANSR requirement.
Additionally, in the event that any permanent engine replacement(s) constitute(s) a
circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse the
permittee from complying with PSD/NANSR and applicable permitting requirements.
2.2 Portable Analyzer Testing
Note: In some cases there may be conflicting and/or duplicative testing requirements due to overlapping
Applicable Requirements. In those instances, please contact the Division Field Services Unit to discuss
streamlining the testing requirements.
Note that the testing required by this Condition may be used to satisfy the periodic testing requirements
specified by the permit for the relevant time period (i.e. if the permit requires quarterly portable analyzer
testing, this test conducted under the AOS will serve as the quarterly test and an additional portable
analyzer test is not required for another three months).
The permittee may conduct a reference method test, in lieu of the portable analyzer test required by this
Condition, if approved in advance by the Division.
The permittee shall measure nitrogen oxide (NOX) and carbon monoxide (CO) emissions in the exhaust
from the replacement engine using a portable flue gas analyzer within seven (7) calendar days of
commencing operation of the replacement engine.
All portable analyzer testing required by this permit shall be conducted using the Division's Portable
Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's web site at:
https://www.colorado. gov/pacific/cdphe/portable-analyzer-monitoring-protocol.
Results of the portable analyzer tests shall be used to monitor the compliance status of this unit.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 6
For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of
the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month
or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of
operation the test results will be multiplied by the maximum number of hours in the month or year (8760),
whichever applies.
For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or
concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement
engine will be subject to, the results of the test shall be converted to the appropriate units as described in
the above -mentioned Portable Analyzer Monitoring Protocol document.
If the portable analyzer results indicate compliance with both the NOR and CO emission limitations, in the
absence of credible evidence to the contrary, the source may certify that the engine is in compliance with
both the NOR and CO emission limitations for the relevant time period.
Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if
the portable analyzer results fail to demonstrate compliance with either the NOR or CO emission
limitations, the engine will be considered to be out of compliance from the date of the portable analyzer
test until a portable analyzer test indicates compliance with both the NOR and CO emission limitations or
until the engine is taken offline.
2.3 Applicable Regulations for Permanent Engine Replacements
2.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § III.D.2
All permanent replacement engines that are located in an area that is classified as
attainment/maintenance or nonattainment must apply Reasonably Available Control Technology
(RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note
that both VOC and NOR are precursors for ozone. RACT shall be applied for any level of
emissions of the pollutant for which the area is in attainment/maintenance or nonattainment,
except as follows:
In the Denver Metropolitan PMio attainment/maintenance area, RACT applies to PMio at any
level of emissions and to NOR and SO2, as precursors to PMio, if the potential to emit of NOR or
SO2 exceeds 40 tons/yr.
For purposes of this AOS, the following shall be considered RACT for natural-gas fired
reciprocating internal combustion engines:
VOC:
CO:
NOR:
SO2:
PMio:
The emission limitations in NSPS JJJJ
The emission limitations in NSPS JJJJ
The emission limitations in NSPS JJJJ
Use of natural gas as fuel
Use of natural gas as fuel
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 7
As defined in 40 CFR Part 60 Subparts GG (§ 60.331) and 40 CFR Part 72 (§ 72.2), natural gas
contains 20.0 grains or less of total sulfur per 100 standard cubic feet.
2.3.2 Control Requirements and Emission Standards: Regulation No. 7, Sections XVI. and XVILE
(State -Only conditions).
Control Requirements: Section XVI
Any permanent replacement engine located within the boundaries of an ozone nonattainment
area is subject to the applicable control requirements specified in Regulation No. 7, section XVI,
as specified below:
Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non -selective
catalyst and air fuel controller to reduce emission.
Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation
catalyst to reduce emissions.
The above emission control equipment shall be appropriately sized for the engine and shall be
operated and maintained according to manufacturer specifications.
The source shall submit copies of the relevant Applicability Reports required under Condition
2.1.2.
Emission Standards: Section XVILE — State -only requirements
Any permanent engine that is either constructed or relocated to the state of Colorado from
another state, after the date listed in the table below shall operate and maintain each engine
according to the manufacturer's written instructions or procedures to the extent practicable and
consistent with technological limitations and good engineering and maintenance practices over
the entire life of the engine so that it achieves the emission standards required in the table below:
Max Engine
HP
Construction or
Relocation Date
Emission Standards in G/hp-hr
NOx
CO
VOC
100<Hp<500
January 1, 2008
2.0
4.0
1.0
January 1, 2011
1.0
2.0
0.7
500≤Hp
July 1, 2007
2.0
4.0
1.0
July 1, 2010
1.0
2.0
0.7
The source shall submit copies of the relevant Applicability Reports required under Condition
2.1.2.
2.3.3 NSPS for spark ignition internal combustion engines: 40 CFR 60, Subpart JJJJ
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page g
A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines
greater than 25 hp, 7/1/2008 for engines less than 500 hp, 7/1/2007 for engines greater than or
equal to 500 hp except for lean burn engines greater than or equal to 500 hp and less than 1,350
hp, and 1/1/2008 for lean burn engines greater than or equal to 500 hp and less than 1,350 hp are
subject to the requirements of 40 CFR Part 60, Subpart JJJJ. An analysis of applicable
monitoring, recordkeeping, and reporting requirements for the permanent engine replacement
shall be included in the Applicability Reports required under Condition 2.1.2. Any testing
required by the NSPS is in addition to that required by this AOS. Note that the initial test required
by NSPS Subpart JJJJ can serve as the testing required by this AOS under Condition 2.2, if
approved in advance by the Division, provided that such test is conducted within the time frame
specified in Condition 2.2.
Note that under the provisions of Regulation No. 6, Part B, Section I.C., upon adoption of NSPS
JJJJ into Regulation No. 6, Part A an internal combustion engine relocated from outside of the
State of Colorado into the State of Colorado shall meet the most recent emission standard
required in NSPS JJJJ. Engines with a manufacturer's rated horsepower of less than 500 and
with a relocation date no later than 5 years after the manufacture date are exempt from this
requirement per Regulation No. 6, Part B, Section I.C.2.a. Relocation is defined in Section
I.C.1.a.
However, as of January 9, 2017 the Division has not yet adopted NSPS JJJJ. Until such time as
it does, any engine subject to NSPS will be subject only under Federal law. Once the Division
adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS.
2.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ
A permanent replacement engine located at either an area or major source is subject to the
requirements in 40 CFR Part 63, Subpart ZZZZ. An analysis of the applicable monitoring,
recordkeeping, and reporting requirements for the permanent engine replacement shall be
included in the Applicability Reports required under Condition 2.1.2. Any testing required by
the MACT is in addition to that required by this AOS. Note that the initial test required by the
MACT can serve as the testing required by this AOS under Condition 2.2, if approved in advance
by the Division, provided that such test is conducted within the time frame specified in Condition
2.2.
2.3.5 Additional Sources
The replacement of an existing engine with a new engine is viewed by the Division as the
installation of a new emissions unit, not "routine replacement" of an existing unit. The AOS is
therefore essentially an advanced construction permit review. The AOS cannot be used for
additional new emission points for any site; an engine that is being installed as an entirely new
emission point and not as part of an AOS-approved replacement of an existing onsite engine has
to go through the appropriate Construction/Operating permitting process prior to installation.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
Table 1
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 9
Internal Combustion Engine Information for the AOS
Emission
Point
Replacement Engine
Periodic
Monitoring?
Subject to
CAM?
C-154
Waukesha Model L7042 GSI Turbocharged Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 1,100 hp
Portable
Monitoring
Quarterly
Yes
C-155
Waukesha Model L7042 GU Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller. Site
Rated at 806 hp
Portable
Monitoring
Quarterly
No
C-159
Waukesha Model L7042 GSI Turbocharged Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 1,350 hp
Portable
Monitoring
Quarterly
Yes
C-157
Waukesha Model L7042 GU Turbocharged Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp
Portable
Monitoring
Quarterly
No
C-161
Waukesha Model L7042 GSI Turbocharged Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 1,350 hp
Portable
Monitoring
Quarterly
Yes
C-158
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller, Site
Rated at 916 hp
Portable
Monitoring
Quarterly
No
C-160
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller, Site
Rated at 806 hp
Portable
Monitoring
Quarterly
No
C-156
Waukesha Model L7042 GU Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller, Site
Rated at 806 hp
Portable
Monitoring
Quarterly
No
C-223
Cooper Superior Model 8G825 Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller, Site
Rated at 720 hp
Portable
Monitoring
Quarterly
Yes
C-225
Cooper Superior Model 8G825 Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller,
Rated at 800 hp
Portable
Monitoring
Quarterly
Yes
C-227
Cooper Superior Model 8G825 Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR Controller, Site
Rated at 720 hp
Portable
Monitoring
Quarterly
Yes
C-181
Waukesha Model L7042 GSI Turbocharged Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 1,478 hp
Portable
Monitoring
Quarterly
Yes
C-192
Waukesha Model L7042 GSI Turbocharged Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 1,478 hp
Portable
Monitoring
Quarterly
Yes
Operating Permit 95OPWE055
First Issued: May I, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 10
3. Non -Attainment New Source Review (NANSR) and Prevention of Significant Deterioration (PSD)
3.1 This facility is categorized as a NANSR major stationary source (Potential to Emit of VOC or NOx > 100
Tons/Year). Future modifications at this facility resulting in a significant net emissions increase (see Reg
3, Part D, Sections II.A.27 and 44) for VOC or NOx or a modification which is major by itself (Potential
to Emit of > 100 TPY of either VOC or NOx) may result in the application of the NANSR review
requirements.
3.2 This facility is categorized as a PSD major stationary source (Potential to Emit > 250 Tons/Year) for CO.
Future modifications at this facility resulting in a significant net emissions increase (see Reg 3, Part D,
Sections II.A.27 and 44) or a modification which is major by itself (Potential to Emit of > 250 TPY) for
any pollutant listed in Regulation No. 3, Part D, Section II.A.44 for which the area is in attainment or
attainment/maintenance may result in the application of the PSD review requirements.
3.3 There are no other Operating Permits associated with this facility for purposes of determining applicability
of Prevention of Significant Deterioration regulations.
4. Accidental Release Prevention Program (112(r))
4.1 Based on the information provided by the applicant, this facility is subject to the provisions of the
Accidental Release Prevention Program (Section 112(r) of the Federal Clean Air Act)..
5. Compliance Assurance Monitoring (CAM)
5.1 The following emission points at this facility use a control device to achieve compliance with an emission
limitation or standard to which they are subject and have pre -control emissions that exceed or are
equivalent to the major source threshold. They are therefore subject to the provisions of the CAM program
as set forth in 40 CFR Part 64, as adopted by reference in Colorado Regulation No. 3, Part C, Section
XIV:
AIRS ID 101 (C-154)
AIRS ID 103 (C-159)
AIRS ID 108 (C-161)
AIRS ID 115 (C-223)
AIRS ID 117 (C-225)
AIRS ID 119 (C-227)
AIRS ID 134 (C-181)
AIRS ID 136 (P-136) —
— Compressor RICE (1,100 hp) for NOx
— Compressor RICE (1,350 hp) for NOx and CO
— Compressor RICE (1,350 hp) for NOx and CO
— Compressor RICE (720 hp) for CO
— Compressor RICE (800 hp) for CO
— Compressor RICE (720 hp) for NOx and CO
— Compressor RICE (1,478 hp) for NOx and CO
TEG Dehydration Unit (85 MMSCFD) for VOC and HAP
AIRS ID 137 (P-137) — Amine Sweetening Unit (85 MMSCFD) for HAP
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 11
AIRS ID 140 (C-192) — Compressor RICE (1,478 hp) for NOx and CO
See Section II, Condition 16 for compliance assurance monitoring requirements.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
6. Summary of Emission Units
6.1 The emissions units regulated by this permit are the following:
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 12
AIRS
ID
Facility
ID
Description
Pollution Control Device
Permit
101
C-154
P001
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,100 hp, Serial
Number 327597, Drive for VRU Compressor
Non -Selective Catalytic
Reduction
95OPWE055
102
C-155
P002
Waukesha Model L7042 GU Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
g y
Controller, Site Rated at 806 hp, Serial Number 382939,
Drive for Residue Compressor
Non -Selective Catalytic
Reduction
95OPWE055
103
C-159
P003
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,350 hp, Serial
Number 367248, Drive for Residue Compressor
Non -Selective Catalytic
Reduction
95OPWE055
107
C-157
P007
Waukesha Model L7042 GU Turbocharged Natural Gas
Fired Internal Combustion Engine, 4 -Cycle, Rich Burn
w/ AFR Controller, Site Rated at 806 hp, Serial Number
335512, Drive for Residue Compressor
Non -Selective Catalytic
Reduction
95OPWE055
108
C-161
P008
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,350 hp, Serial
Number 112585, Drive for Residue Compressor
Non -Selective Catalytic
Reduction
95OPWE055
110
C-158
P010
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 916 hp, Serial Number 389002,
Drive for Box Elder Compressor
Non -Selective Catalytic
Reduction
95OPWE055
113
C-160
P013
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp, Serial Number 338539,
Drive for Propane Compressor
Non -Selective Catalytic
Reduction
95OPWE055
114
C-156
P014
Waukesha Model L7042 GU Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp, Serial Number 250253,
Drive for Residue Compressor
Non -Selective Catalytic
Reduction
95OPWE055
115
C-223
P015
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 720 hp, Serial Number
20675, Drive for Inlet Compressor
Non -Selective Catalytic
Reduction
95OPWE055
117
C-225
P017
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Rated at 800 hp, Serial Number
270129, Drive for Inlet Compressor
Non -Selective Catalytic
Reduction
95OPWE055
119
C-227
P019
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
Non -Selective Catalytic
Reduction
95OPWE055
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 13
AIRS
IDAFR
Facility
ID
Description
Pollution Control Device
Permit
Controller, Site Rated at 720 hp, Serial Number
264619, Drive for Inlet Compressor
122
P025
Fugitive Emissions from Equipment Leaks
Uncontrolled
10WE1659
125
P039
Eight (8) 300 bbl Stabilized Condensate Storage Tanks
ECD (95% CE)
12WE1242
126
F029
Stabilized Condensate Truck Loadout, 285,714 bbl/yr
throughput
Uncontrolled
95OPWE055
129
H037
Heat Recovery Corp. Hot Oil Heater, Natural Gas Fired,
Rated at 7.55 IvMBtu/hr, Serial Number H -80273A
Uncontrolled
95OPWE055
130
P033
Triethylene Glycol Dehydration Unit, Rated at 4
Flash Gas: Recycle (hard
piped) to Inlet
Still Vent: ECD (95% CE)
01WE0208
MMSCFD, 3.5 gpm l'EG recirculation rate, Serial
Number (none; custom fabricated)
133
F031
Pressurized Liquids Loadout
Uncontrolled
95OPWE055
134
C 181
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,478 hp, Serial
Number 5283701033, Drive for Residue Compressor
Non -Selective Catalytic
Reduction
07WE0988
136
P-136
Evco Fabrication Model T-901 Triethylene Glycol
Dehydration Unit, Rated at 85 MMSCFD, 24 gpm TEG
recirculation rate, Serial Number 2090
Flash Gas: Recycle (hard-
piped) to Inlet
Still Vent: ECD (95% CE) or
RTO (97% CE;
backup to ECD)
10WE1659
137
P-137
Evco Fabrication Model T-9002 Amine Sweetening
Unit, Rated at 85 MMSCFD, 350 gpm lean amine
recirculation rate, Serial Number 2082
Flash Gas: Recycle (hard -
piped) to Inlet
Acid Gas Vent: RTO (97% CE)
10WE1659
138
P-138
Optimized Process Furnaces, Inc., Model H-7201 Hot
Oil Heater, Natural Gas Fired, equipped with Low NOx
burners, Rated at 30.7 MMBtu/hr, Serial Number
J101045
Uncontrolled
l0WE1659
140
C 192
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,478 hp, Serial
Number 386916, Drive for Box Elder Compressor
Non -Selective Catalytic
Reduction
12WE1193
141
FLARE
John Zink Model Kaldair P-684 Plant Emergency Flare
for Maintenance and Malfunctions
N/A
95OPWE055
N/A
N/A
Kohler Model CV 15S Gasoline Fueled Internal
Combustion Engine, 4 -Cycle, Rich Burn, Site Rated at
15 hp, Drive for Methanol Pump
None
95OPWE055
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 14
SECTION II - Specific Permit Terms
1. C-154 — Waukesha 1,100 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 101
C-155/157/160 — Waukesha 806 HP Natural Gas Fired Internal Combustion Engines, AIRS ID:
102/107/113
C-159 — Waukesha 1,350 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 103
C-161 — Waukesha 1,350 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 108
C-158 — Waukesha 916 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 110
C-156 — Waukesha 806 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 114
C-223 — Cooper Superior 720 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 115
C-225 - Cooper Superior 800 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 117
C-227 — Cooper Superior 720 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 119
C-192 — Waukesha 1,478 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 140
Parameter
Permit
Condition
Number
Limitation
Compliance
Emission Factor
Monitoring
Method
Interval
Emission & Consumption Limits
101 — C-154, Waukesha 1,100 HP Natural Gas Fired Internal Combustion Engine
NO.
1.1
21.2 tons/year
0.573 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
CO
21.2 tons/year
0.573 lb/MMiBtu
VOC
1.2
10.6 tons/year
0.285 lb/MMBtu
Natural Gas
Consumption
1.3
77.45 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits'
102/107/113 - C-155/157/160, Three (3) Waukesha 806 HP Natural Gas Fired Internal Combustion Engines
NO),
16.3 tons/year
0.518 lb/MMBtu
Recordkeeping and
CO
1.1
16.3 tons/year
0.518 lb/MMBtu
Twelve Month Rolling
Total Calculation
Monthly
VOC
1.2
7.8 tons/year
0.247 lb/MMBtu
Natural Gas
Consumption
1.3
65.84 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
103 — C-159, Waukesha 1,350 HP Natural Gas Fired Internal Combustion Engine
NO.
1.1
26.1 tons/year
0.537 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
27.4 tons/year
0.5641b/1VIlV1Btu
VOC
1.2
13.0 tons/year
0.268 lb/MMBtu
Natural Gas
Consumption
1.3
101.4 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
108 — C-161, Waukesha 1,350 HP Natural Gas Fired Internal Combustion Engine
NO.
13.0 tons/year
0.268 lb/MN'lBtu
Monthly
CO
1.1
26.1 tons/year
0.537 lb/MMBtu
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 15
Parameter
Permit
Condition
Number
Limitation
Compliance
Emission Factor
Monitoring
Method
Interval
VOC
1.2
9.1 tons/year
0.188 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Natural Gas
Consumption
1.3
101.4 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption
110 — C-158, Waukesha
Limits
916 HP Natural Gas Fired Internal Combustion Engine
NOx
1.1
18.6 tons/year
0.5441b/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
CO
18.6 tons/year
0.544 lb/MMBtu
VOC
1.2
8.9 tons/year
0.259 lb/MMBtu
Natural Gas
Consumption
1.3
71.3 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
114 — C-156, Waukesha 806 HP Natural Gas Fired Internal Combustion Engine
NOx
1.1
7.8 tons/year
0.247 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Calculation
Monthly
CO
15.6 tons/year
0.494 lb/MltvlBtu
0.173 lb/MMBtuTotal
VOC
1.2
5.5 tons/year
Natural Gas
Consumption
1.3
65.84 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
115 — C-223, Cooper Superior 720 HP Natural Gas Fired Internal Combustion Engine
NOx
1.1
14.6 tons/year
0.538 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
CO
14.6 tons/year
0.538 lb/MMBtu
VOC
1.2
7.0 tons/year
0.256 lb/MMBtu
Natural Gas
Consumption
1.3
56.69 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
117 — C-225, Cooper Superior 800 HP Natural Gas Fired Internal Combustion Engine
NO„
1.1
7.7 tons/year
0.276 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
CO
15.5 tons/year
0.551 lb/MMBtu
VOC
1.2
5.4 tons/year
0.193 lb/MMBtu
Natural Gas
Consumption
1.3
58.52 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
119 — C-227, Cooper Superior 720 HP Natural Gas Fired Internal Combustion Engine
NO„
1.1
13.9 tons/year
0.512 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
CO
14.6 tons/year
0.538 lb/MlvIBtu
VOC
1.2
7.0 tons/year
0.258 lb/IVIMBtu
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 16
Parameter
Permit
Condition
Number
Limitation
Compliance
Emission Factor
Monitoring
Method
Interval
Natural Gas
Consumption
1.3
56.69 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Emission & Consumption Limits
140 — C-192, Waukesha 1,478 HP Natural Gas Fired Internal Combustion Engine
NO„
CO
1.1
14.3 tons/year
0.282 lb/IVEMBtu
28.6 tons/year
0.565 lb/MMBtu
VOC
1.2
10.0 tons/year
0.198 lb/MMBtu
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
Natural Gas
Consumption
1.3
105.7 MMSCF/year
Fuel Meter, Twelve
Month Rolling Total
Monthly
Other Requirements'
Fuel Gas Heat Content
1.4
ASTM Methods
Semi -Annually
Hours of Operation
1.5
Recordkeeping
Monthly
Opacity
1.6
Control Device
Requirements
1.7
Portable Monitoring
1.8
Not to exceed 20%, except as
provided for below:
For Certain Operational
Activities - Not to exceed 30%
for a period or periods
aggregating more than six (6)
minutes in any sixty (60)
consecutive minutes
Fuel Restriction — Natural Gas Only
Recordkeeping
See Condition
1.7
Flue Gas Analyzer
Quarterly
Compliance Assurance
Monitoring (CAM)
1.9
Engines C-154/159/161/223/225/227/192 only:
See Condition 1.9
Statewide Controls for
Oil and Gas
Operations
1.10
See Condition 1.10
40 CFR 60 Subpart
OOOO NSPS
Compressor driven by engine C-192 only:
See Condition 1.11
40 CFR 60 Subpart A
General Provisions
NSPS
1.12
Compressor driven by engine C-192 only:
See Condition 1.12
40 CFR 63 Subpart
ZZZZ NESHAP
1.13
See Condition 1.13
40 CFR 63 Subpart A
General Provisions
NESHAP
1.14
See Condition 1.14
'Emission & Consumption Limits and Other Requirements apply to each engine individually
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 17
1.1 NOx & CO Emission Limitations & Compliance Monitoring
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from each engine shall not exceed the
limitations listed in Summary Table 1 above (Colorado Construction Permit 12WE1193 for C-192 only,
and as provided for under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part
B, Section ILA.6 and Part C, Section X based on the requested emissions identified on the APENs received
on 8/12/2016 for C-154, 2/15/2017 for C-159, 4/30/2015 for C-161, 4/30/2015 for C-156, 6/20/2013 for
C-225 and 1/29/2015 for C-227). The emission factors listed above have been approved by the Division
and shall be used to calculate emissions from these engines, except in the event of a failed portable flue
gas analyzer test, as provided for in Condition 1.8. Compliance with the emission limitations shall be
monitored as follows:
1.1.1 Monthly emissions shall be calculated by the end of the subsequent month using the above
emission factors, the monthly natural gas consumption (as required by Condition 1.3) and the heat
content of the natural gas (as required by Condition 1.4) in the equation below:
1b MMBtu MMSCF
tons Emission Factor l x Heat Content x Fuel Use
NOx or CO Emissions ( ) =
�MMBtuI 000untl CF� month
\monthl Unit Conversion (2000 lb)
ton )
Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the
annual limitations. Each month, a new twelve month total shall be calculated using the previous
twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
1.1.2 Portable monitoring shall be conducted quarterly as required by Condition 1.8. If the results of the
portable analyzer testing conducted under the provisions of Condition 1.8 show that either the NOx
or CO emission rates/factors are greater than those listed above, and in the absence of subsequent
testing results to the contrary (as approved by the Division), the permittee shall apply for a
modification to this permit to reflect, at a minimum, the higher emission rates/factors within 60
days of the completion of the test.
1.2 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) from each engine shall not exceed the limitations listed
in Summary Table 1 above (Colorado Construction Permit 12WE1193 for C-192 only, and as provided
for under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part B, Section II.A.6
and Part C, Section X based on the requested emissions identified on the APENs received on 8/12/2016
for C-154, 2/15/2017 for C-159, 4/30/2015 for C-161, 4/30/2015 for C-156, 6/20/2013 for C-225 and
1/29/2015 for C-227). Compliance with the emission limitations shall be monitored as follows:
1.2.1 Monthly emissions shall be calculated by the end of the subsequent month using the above
emission factors, the monthly natural gas consumption (as required by Condition 1.3) and the heat
content of the natural gas (as required by Condition 1.4) in the equation below:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
tons ll Emission Factor
VOC Emissions (month)
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 18
(lb (MMBtu)x Fuel Use (MMSCF
MMBtuJl x Heat Content \MMSCF l month
Unit Conversion (2000 lb)
ton )
Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the
annual limitations. Each month, a new twelve month total shall be calculated using the previous
twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
1.22 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the methods required by Condition 14 and used in a twelve
month rolling total to monitor compliance with the facility -wide HAP emission limitations.
1.3 Natural Gas Consumption Limitations & Compliance Monitoring
Natural gas consumption from each engine shall not exceed the limitations listed in Summary Table 1
above (Colorado Construction Permit 12WE1193 for C-192 only). Compliance with the consumption
limitation shall be monitored as follows:
1.3.1 Facility -wide natural gas consumption for each month shall be recorded using the existing fuel
meter. The facility -wide natural gas consumption shall be measured on the same day that run time
hours have been recorded for each engine in accordance with Condition 1.5.
1.3.1.1 In the event the fuel meter cannot be used to determine fuel usage at any time, the
manufacturer -provided fuel consumption of each natural-gas consuming unit may be
used in lieu of the meter.
1.3.2 Allocation of natural gas to each engine shall be calculated using the following calculation:
Btu \
MMSCF) HREngine (month) MMSCF)
FCEngine ( month ) HR ( Btu l + HR ( Btu ) (month)
\ x FCFaciiity ( month /
Engine month) Heater month) + HRather month)
Where:
Btu hr
HREngine (month/ — BSFC (hp hr) x Hours of Operation (month) x Site Rated HP (hp)
Btu Btu hr
HRHeater (monthl ) = Design Heat Rating ( kr ) x Hours of Operation (month)
And:
FCEngine = Individual Engine Fuel Consumption, MMSCF/Month
HREngine = Individual Engine Heat Requirement, Btu/Month
HRHeater = Individual Heater Heat Requirement, Btu/Month
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 19
'Mother = Other Users Heat Requirement, Btu/Month
FCFaciiity = Facility Wide Fuel Consumption (metered), MMSCF/Month
BSFC = Brake Specific Fuel Consumption, Btu/hp • hr
Monthly natural gas consumption from each engine shall be used in a twelve month rolling total to
monitor compliance with the annual limitation. Each month, a new twelve month total shall be calculated
using the previous twelve months' data. Records of calculations shall be maintained and made available
to the Division upon request.
Monthly natural gas consumption from each engine shall be used to monitor compliance with the annual
NOx, CO and VOC emission limitations, as required by Condition 1.1 and 1.2.
1.4 Fuel Gas Heat Content
The heat content of the natural gas used to fuel these engines shall be verified semi-annually, or once
every six months, using the appropriate ASTM Methods or equivalent, if approved in advance by the
Division. The heat content of the natural gas shall be based on the higher heating value (HHV) of the
fuel. Results of the heat content verification shall be retained and made available to the Division upon
request.
The heat content indicated by the most recent analysis shall be used to monitor compliance with the annual
NOx, CO and VOC emission limitations for each engine, as required by Condition 1.1 and 1.2.
1.5 Hours of Operation
Hours of operation of each engine shall be monitored and recorded monthly. Hours of operation shall be
recorded on the same day that the monthly facility -wide fuel gas consumption is measured. Monthly hours
of operation shall be used in a running total for each annual compliance period. Records shall be made
available for Division review upon request.
The hours of operation shall be used to monitor compliance with the annual fuel gas consumption
limitation, as required by Condition 1.3.
1.6 Opacity
The following opacity requirements apply to each engine:
1.6.1 Except as provided for in Condition 1.6.2 below, no owner or operator of a source shall allow or
cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity
(Colorado Regulation No. 1, Section II.A.1).
1.6.2 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air
pollutant resulting from the building of a new fire, cleaning of fire boxes, soot blowing, start-up,
process modifications, or adjustment or occasional cleaning of control equipment which is excess
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 20
of 30% opacity for a period or periods aggregating more than six (6) minutes in any sixty (60)
consecutive minutes (Colorado Regulation No. 1, Section II.A.4).
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be presumed
since only natural gas is permitted to be used as fuel for these engines. The permittee shall maintain
records that verify that only natural gas is used as fuel.
1.7 Control Device Requirements
Each engine shall be equipped with both a non -selective catalytic reduction system and an air fuel
controller (as required by Condition 1.10.1.1). Parameters associated with the air -to -fuel ratio controller
(AFR) and non -selective catalyst reduction unit shall be monitored as follows:
1.7.1 The pressure drop across the catalyst shall be monitored and recorded monthly. The pressure drop
shall not exceed 2 inches of water column from the baseline value established by the source when
the engine is operating at maximum achievable load. This baseline pressure drop shall be
established by the source during each initial compliance and portable analyzer test, and as noted
below.
If the pressure is outside this range, then the appropriate maintenance shall be performed to bring
the pressure back into range. In lieu of maintenance, the source may choose to perform a portable
analyzer test of the engine to establish a new pressure drop value within fourteen (14) days of the
exceedance. If the test demonstrates that the engine is in compliance with its emission limits, the
pressure drop value at which the engine is tested shall become the new baseline.
The catalyst will be cleaned, reconditioned and replaced per the manufacturer's recommended
schedule and a copy of maintenance reports shall be kept for Division review upon request. For
new, cleaned or reconditioned catalyst: the new pressure drop baseline must be established by the
operator within the first seven days of engine/catalyst operation and re-established during the next
regularly scheduled emission test.
1.7.2 The catalyst inlet temperature shall be monitored and recorded daily and kept between 750°F and
1250°F. If the temperature is outside of this range, then appropriate maintenance activities shall
be performed. A log of periods observed outside this range and subsequent maintenance activities
performed shall be maintained and made available for Divisions review upon request.
1.7.3 When portable monitoring is scheduled, the parameters above in Conditions 1.7.1 and 1.7.2 shall
be recorded during the portable monitoring event.
1.7.4 The millivolt reading for the Air -Fuel Ratio Controller (AFR) O2 sensor for each engine will be
monitored and recorded weekly to assess the air to fuel ratio controller operating condition. During
those weeks when portable monitoring is scheduled, the millivolt reading shall be monitored and
recorded during the portable monitoring event. Recording of the millivolt reading shall be used to
verify that the AFR controller is operated in accordance with the manufacturer's recommendations.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
"
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 21
1.7.5 The oxygen concentration in the engine exhaust gas shall be measured and recorded for each
engine during each portable monitoring event required by Condition 1.8.
1.8 Portable Monitoring (ver 06/26/2014)
Emission measurements of nitrogen oxides (NOx) and carbon monoxide (CO) shall be conducted
quarterly using a portable flue gas analyzer. At least one calendar month shall separate the quarterly tests.
Note that if the engine is operated for less than one hundred (100) hours in any quarterly period, then the
portable monitoring requirements do not apply.
All portable analyzer testing required by this permit shall be conducted using the Division's Portable
Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's website at:
https://www.colorado. gov/pacific/cdphe/portable-analyzer-monitoring-protocol
Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For
comparison with an annual or short term emission limit, the results of the tests shall be converted to a lb/hr
basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to
monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied
by the maximum number of hours in the month or year (8760), whichever applies.
If the portable analyzer results indicate compliance with both the NOx and CO emission limitations, in
the absence of credible evidence to the contrary, the source may certify that the engine is in compliance
with both the NOx and CO emission limitations for the relevant time period.
Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if
the portable analyzer results fail to demonstrate compliance with either the NOx or CO emission
limitations, the engine will be considered to be out of compliance from the date of the portable analyzer
test until a portable analyzer test indicates compliance with both the NOx and CO emission limitations or
until the engine is taken offline.
For comparison with the emission rates/factors, the emission rates/factors determined by the portable
analyzer tests and approved by the Division shall be converted to the same units as the emission
rates/factors in the permit. If the portable analyzer tests show that either the NOx or CO emission
rates/factors are greater than the relevant ones set forth in the permit, and in the absence of subsequent
testing results to the contrary (as approved by the Division), the permittee shall apply for a modification
to this permit to reflect, at a minimum, the higher emission rate/factor within sixty (60) days of the
completion of the test.
Results of all tests conducted shall be kept on site and made available to the Division upon request.
1.9 Compliance Assurance Monitoring (CAM)
Engines C-154, C-159, C-161, C-223, C-225, C-227 and C-192 only are subject to the Compliance
Assurance Monitoring (CAM) requirements with respect to the annual emission limitations in Condition
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 22
1.1 for the pollutants identified in the following table. Compliance with the CAM requirements shall be
monitored in accordance with the requirements in Condition 16 and the CAM Plan in Appendix H.
AIRS ID
Facility ID
Pollutants
Subject to CAM
101
C-154
NOx
103
C-159
NOx, CO
108
C-161
NOx, CO
115
C-223
CO
117
C-225
CO
119
C-227
NOx, CO
140
C-192
NOx, CO
1.10 Statewide Controls for Oil and Gas Operations
1.10.1 Colorado Regulation No. 7, Section XVI Requirements:
Each engine is subject to the following requirements of Colorado Regulation No. 7, Section XVI,
"Control of Emissions from Stationary and Portable Combustion Equipment in the 8 -Hour Ozone
Control Area":
Conditions shown in italic text below represent monitoring, recordkeeping and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
Air Pollution Technology Requirements
1.10.1.1 For rich burn reciprocating internal combustion engines, a non -selective catalyst
reduction and an air fuel controller shall be required. A rich burn reciprocating internal
combustion engine is one with a normal exhaust oxygen concentration of less than 2%
by volume (Colorado Regulation No. 7, Section XVI.B.1).
1.10.1.2 The emission control equipment required by this Section XVI.B (Condition 1.10.1.1)
shall be appropriately sized for the engine and shall be operated and maintained
according to manufacturer specifications (Colorado Regulation No. 7, Section
XVLB.3).
Exemptions
1.10.1.3 The following stationary combustion equipment are exempt from the emission
limitation requirements of Section XVI.D.4., the compliance demonstration
requirements in Section XVI.D.5., and the related recordkeeping and reporting
requirements of Sections XVI.D.7.a-f. and XVI.D.8, but these sources must maintain
any and all records necessary to demonstrate that an exemption applies (Condition
1.10.1.8b). These records must be maintained for a minimum of five years and made
available to the Division upon request. Qualifying for an exemption in this section does
not preclude the combustion process adjustment requirements of Section XVI.D.6.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 23
(Conditions 1.10.1.6 through ' 1.10.1.7), when required by XVI.D.6.a (Condition
1.10.1.5).
Once stationary combustion equipment no longer qualifies for any exemption, the
owner or operator must comply with the applicable requirements of this Section XVI.D.
as expeditiously as practicable but no later than 36 months after any exemption no
longer applies. Additionally, once stationary combustion equipment that is not
equipped with CEMS or CERMS no longer qualifies for any exemption, the owner or
operator must conduct a performance test using EPA test methods within 180 days and
notify the Division of the results and whether emission controls will be required to
comply with the emission limitations of Section XVI.D.4 (Colorado Regulation No. 7,
Section XVI.D.2.).
a. Any natural gas -fired reciprocating internal combustion engines subject to a work
practice or emission control requirement contained in this Regulation 7, Section
XVI.A. or B. (Condition 1.10.1.1) (Colorado Regulation No. 7, Section
XVI.D.2.e.).
1.10.1.4 [Additional Recordkeeping: Notwithstanding, the owner or operator shall comply
with the recordkeeping requirements of Section XVID.7.f. (Condition 1.10.1.8a) for
the combustion process adjustments required under Section XVLD.6.b. (Condition
1.10.1.6.)]
Combustion Process Adjustment
1.10.1.5 As of January 1, 2017, this Section XVI.D.6.(Condition 1.10.1.6) applies to boilers,
duct burners, process heaters, stationary combustion turbines, and stationary
reciprocating internal combustion engines with uncontrolled actual emissions of NOx
equal to or greater than five (5) tons per year that existed at major sources of NOx as
of June 3, 2016. (Colorado Regulation No. 7, Section XVI.D.6.a.).
1.10.1.6 Combustion Process Adjustment (Colorado Regulation No. 7, Section XVI.D.6.b.)
a. The owner or operator of a stationary internal combustion engine must conduct the
following inspections and adjustments, as applicable (Colorado Regulation No. 7,
Section XVI.D.6.b.(iv)):
(i) Change oil and filters as necessary (Colorado Regulation No. 7, Section
XVI.D.6.b.(iv)(A)).
(ii) Inspect air cleaners, fuel filters, hoses, and belts and clean or replace as
necessary (Colorado Regulation No. 7, Section XVI.D.6.b.(iv)(B)).
(iii)Inspect spark plugs and replace as necessary (Colorado Regulation No. 7,
Section XVI.D.6.b.(iv)(C)).
b. The owner or operator must operate and maintain the boiler, duct burner, process
heater, stationary combustion turbine, or stationary internal combustion engine
consistent with manufacturer's specifications, if available, or good engineering and
maintenance practices (Colorado Regulation No. 7, Section XVI.D.6.b.(v)).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 24
c. Frequency (Colorado Regulation No. 7, Section XVI.D.6.b.(vi))
(i) The owner or operator must conduct the initial combustion process adjustment
by April 1, 2017. An owner or operator may rely on a combustion process
adjustment conducted in accordance with applicable requirements and schedule
of a New Source Performance Standard in 40 CFR Part 60 or National Emission
Standard for Hazardous Air Pollutants in 40 CFR Part 63 to satisfy the
requirement to conduct an initial combustion process adjustment by April 1,
2017 (Colorado Regulation No. 7, Section XVI.D.6.b.(vi)(A)).
(ii) The owner or operator must conduct subsequent combustion process
adjustments at least once every twelve (12) months after the initial combustion
adjustment, or on the applicable schedule according to Sections XVI.D.6.c.(i).
(Condition 1.10.1.7a) or XVI.D.6.c.(ii). (Condition 1.10.1.7b) (Colorado
Regulation No. 7, Section XVI.D.6.b.(vi)(B)).
Alternative Requirements
1.10.1.7 As an alternative to the requirements described in Sections XVI.D.6.b.(iv) (Condition
1.10.1.6a) and XVI.D.6.b.(v) (Condition 1.10.1.6b) (Colorado Regulation No. 7,
Section XVI.D.6.c.):
a. The owner or operator may conduct the combustion process adjustment according
to the manufacturer recommended procedures and schedule (Colorado Regulation
No. 7, Section XVI.D.6.c.(i)); or
b. The owner or operator of combustion equipment that is subject to and required to
conduct a period tune-up or combustion adjustment by the applicable requirements
of a New Source Performance Standard in 40 CFR Part 60 or National Emission
Standard for Hazardous Air Pollutants in 40 CFR Part 63 may conduct tune-ups or
adjustments according to the schedule and procedures of the applicable
requirements of 40 CFR Part 60 or 40 CFR Part 63 (Colorado Regulation No. 7,
Section XVI.D.6.c.(ii)).
Recordkeeping
1.10.1.8 Recordkeeping. The following records must be kept for a period of five years and made
available to the Division upon request (Colorado Regulation No. 7, Section XVI.D.7.):
a. For stationary combustion equipment subject to the combustion process adjustment
requirements in Section XVI.D.6. (Condition 1.10.1.6), the following
recordkeeping requirements apply (Colorado Regulation No. 7, Section
XVLD.7.f):
(i) The owner or operator must create a record once every calendar year identifying
the combustion equipment at the source subject to Section XVI.D. (Condition
1.10.1.5) and including for each combustion equipment (Colorado Regulation
No. 7, Section XVI.D.7.(f).(i)):
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 25
(A) The date of the adjustment (Colorado Regulation No. 7, Section
XVI.D.7.f.(i)(A));
(B) Whether the combustion process adjustment under Sections
XVI.D.6.b.(iv) (Condition 1.10.1.6a) and XVI.D.6.b.(v) (Condition
1.10.1.6b). was followed, and what procedures were performed
(Colorado Regulation No. 7, Section XVI.D.7.f.(i)(B));
(C) Whether a combustion process adjustment under Sections
XVI.D.6.a. (Condition 1.10.1.5) and XVI.D.6.b. (Condition
1.10.1.6). was followed, what procedures were performed, and what
New Source Performance or National Emission Standard for
Hazardous Air Pollutants applied, if any (Colorado Regulation No.
7, Section XVI.D.7.f.(i)(C)); and
(D) A description of any corrective action taken (Colorado Regulation
No. 7, Section XVI.D.7.f.(i)(D)).
(E) If the owner or operator conducts the combustion process
adjustment according to the manufacturer recommended procedures
and schedule and the manufacturer specifies a combustion process
adjustment on an operation time schedule, the hours of operation.
(Colorado Regulation No. 7, Section XVI.D.7.f.(i)(E)).
(F) [Additional Recordkeeping: If the owner or operator conducts an
alternative combustion process adjustment under Section
XVI.D.6.c. (Condition 1.10.1.7), the owner or operator shall
document that these requirements were followed, what procedures
were performed, and what New Source Performance or National
Emission Standard for Hazardous Air Pollutants applied, if any.]
(ii) The owner or operator must retain manufacturer recommended procedures,
specifications, and maintenance schedule if utilized under Section XVI.D.6.a.
(Condition 1.10.1.5) for the life of the equipment (Colorado Regulation No. 7,
Section XVI.D.7.f.(ii)).
(iii)As an alternative to the requirements described in Section XVI.D.7.f.(i)
(Condition (i) above), the owner or operator may comply with applicable
recordkeeping requirements related to combustion process adjustments
conducted according to a New Source Performance Standard in 40 CFR Part 60
or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63
(Colorado Regulation No. 7, Section XVI.D.7.f.(iii)).
b. All sources qualifying for an exemption under Section XVI.D.2. (Condition
1.10.1.3) must maintain all records necessary to demonstrate that an exemption
applies (Colorado Regulation No. 7, Section XVI.D.7.g.).
1.10.2 Colorado Regulation No. 7, Section XVII Requirements:
Each engine is subject to the following requirements of Colorado Regulation No. 7, Section XVII,
"Statewide Controls for Oil and Gas Operations and Natural Gas -Fired Reciprocating Internal
Combustion Engines":
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 26
Conditions shown in italic text below represent monitoring, recordkeeping and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
[Additional Monitoring: For the purposes of permanent replacements made to this engine in
accordance with the AOS provisions of SECTION I - 2, this Condition does not apply to any
replacement engine that is subject to an emissions control requirement in a federal maximum
achievable control technology ("MACT ") standard under 40 CFR Part 63, a Best Available
Control Technology ("BACT ") limit, or a New Source Performance Standard under 40 CFR Part
60.]
1.10.2.1 [State -Only Enforceable] At all times, including periods of start-up and shutdown, the
facility and air pollution control equipment must be maintained and operated in a
manner consistent with good air pollution control practices for minimizing emissions.
Determination of whether or not acceptable operation and maintenance procedures are
being used will be based on information available to the Division, which may include,
but is not limited to, monitoring results, opacity observations, review of operation and
maintenance procedures, and inspection of the source (Colorado Regulation No. 7,
Section XVII.B.1.b).
1.10.2.2 [State -Only Enforceable] Engines C-154, C-159, C-225 and C-227 only: Except as
provided in Section XVII.E.2.b., the owner or operator of any natural gas fired
reciprocating internal combustion engine that is either constructed or relocated to the
state of Colorado from another state, on or after the date listed in the table below shall
operate and maintain each engine according to the manufacturer's written instructions
or procedures to the extent practicable and consistent with technological limitations
and good engineering and maintenance practices over the entire life of the engine so
that it achieves the emission standards required in the table below (Colorado Regulation
No. 7, Section XVII.E.2.a.).
Actual emissions from natural gas fired reciprocating internal combustion engines shall
not exceed the emission performance standards in the table below as expressed in units
of grams per horsepower -hour (g/hp-hr) (Colorado Regulation No. 7, Section
XVII.E.2.b.).
Maximum
Engine Hp
Construction or Relocation
Date
Emission Standard in g/hp-hr
NOx
CO
VOC
≥500 HP
On or after July 1, 2007
2.0
4.0
1.0
On or after July 1, 2010
1.0
2.0
0.7
[Additional Monitoring: Compliance with the NOx and CO emission limitations shall
be monitored by conducting portable monitoring quarterly as specified in Condition
1.8. For comparison with the short—term limits in this Condition, the results of the
portable monitoring test shall be converted to units of g/hp-hr to assess compliance
with the NOx and CO emission limitations in this Condition 1.10.2.2.]
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 950PWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 27
1.10.2.3
[Compliance Demonstration: In the absence of credible evidence to the contrary,
compliance with the VOC limitation is presumed provided the portable monitoring
indicates compliance with the NOx and CO emission limitations in this Condition
1.10.2.2.]
Engines C-155, C-159, C-157, C-161, C-158, C-160, C-156, C-223 and C-192 only:
Except as provided in Sections XVII.E.3.a.(i)(B) and (C) and XVII.E.3.a.(ii), all rich
burn reciprocating internal combustion engines with a manufacturer's name plate
design rate greater than 500 horsepower, constructed or modified before February 1,
2009 shall install and operate both a non -selective catalytic reduction system and an air
fuel controller by July 1, 2010. A rich burn reciprocating internal combustion engine is
one with a normal exhaust oxygen concentration of less than 2% by volume (Colorado
Regulation No. 7, Section XVII.E.3.a.(i)).
All control equipment required by Section XVII.E.3.a. shall be operated and
maintained pursuant to manufacturer specifications or equivalent to the extent
practicable, and consistent with technological limitations and good engineering and
maintenance practices. The owner or operator shall keep manufacturer specifications
or equivalent on file. (Colorado Regulation No. 7, Section XVII.E.3.a.(i)(A)).
1.11 40 CFR Part 60 Subpart OOOO NSPS
The compressor driven by engine C-192 only is subject to the New Source Performance Standards
requirements of Colorado Regulation No. 6, Part A, Subpart OOOO (40 CFR Part 60, Subpart OOOO)
"Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution for
which Construction, Modification or Reconstruction Commenced After August 23, 2011, and on or before
September 18, 2015" including, but not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
OOOO published in the Federal Register on June 3, 2016. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 60 Subpart OOOO.
Standards for Reciprocating Compressor Affected Facilities
1.11.1 You must replace the reciprocating compressor rod packing according to either paragraph (a)(1)
(Condition 1.11.1.1) or (2) (Condition 1.11.1.2) of this section or you must comply with paragraph
(a)(3) (Condition 1.11.1.3) of this section (§60.5385(a)).
1.11.1.1 Before the compressor has operated for 26,000 hours. The number of hours of operation
must be continuously monitored beginning upon initial startup of your reciprocating
compressor affected facility, or October 15, 2012, or the date of the most recent
reciprocating compressor rod packing replacement, whichever is later
(§60.5385(a)(1)).
1.11.1.2 Prior to 36 months from the date of the most recent rod packing replacement, or 36
months from the date of startup for a new reciprocating compressor for which the rod
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 28
packing has not yet been replaced (§60.5385(a)(2)).
1.11.1.3 Collect the emissions from the rod packing using a rod packing emissions collection
system which operates under negative pressure and route the rod packing emissions to
a process through a closed vent system that meets the requirements of §60.5411(a)
(Conditions 1.11.6 through 1.11.8) (§60.5385(a)(3)).
1.11.2 You must demonstrate initial compliance with standards that apply to reciprocating compressor
affected facilities as required by §60.5410 (Condition 1.11.5) (§60.5385(b)).
1.11.3 You must demonstrate continuous compliance with standards that apply to reciprocating
compressor affected facilities as required by §60.5415 (Condition 1.11.9) (§60.5385(c)).
1.11.4 You must perform the required notification, recordkeeping, and reporting as required by §60.5420
(Condition 1.11.14) (§60.5385(d)).
Initial Compliance Requirements for Reciprocating Compressor Affected Facilities
1.11.5 You must determine initial compliance with the standards for each affected facility using the
requirements in paragraph (c) (Condition 1.11.5.1) of this section. The initial compliance period
begins on October 15, 2012, or upon initial startup, whichever is later, and ends no later than one
year after the initial startup date for your affected facility or no later than one year after October
15, 2012. The initial compliance period may be less than one full year (§60.5410).
1.11.5.1 To achieve initial compliance with the standards for each reciprocating compressor
affected facility you must comply with paragraphs (c)(1) (Condition a) through (4)
(Condition d) of this section (§60.5410(c)).
a. If complying with §60.5385(a)(1) (Condition 1.11.1.1) or (2) (Condition 1.11.1.2),
during the initial compliance period, you must continuously monitor the number of
hours of operation or track the number of months since the last rod packing
replacement (§60.5410(c)(1)).
b. If complying with §60.5385(a)(3) (Condition 1.11.1.3), you must operate the rod
packing emissions collection system under negative pressure and route emissions
to a process through a closed vent system that meets the requirements of
§60.5411(a) (Conditions 1.11.6 through 1.11.8) (§60.5410(c)(2)).
c. You must submit the initial annual report for your reciprocating compressor as
required in §60.5420(b) (Condition 1.11.13). (§60.5410(c)(3)).
d. You must maintain the records as specified in §60.5420(c)(3) (Condition 1.11.14.1)
for each reciprocating compressor affected facility (§60.5410(c)(4)).
Additional Initial Compliance Requirements for Closed Vent Systems
1.11.6 You must design the closed vent system to route all gases, vapors, and fumes emitted from the
material in the reciprocating compressor rod packing emissions collection system or the wet seal
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 29
fluid degassing system to a control device or to a process that meets the requirements specified in
§60.5412(a) through (c) of this Subpart (§60.5411(a)(1)).
1.11.7 You must design and operate the closed vent system with no detectable emissions as demonstrated
by §60.5416(b) (Condition 1.11.11) (§60.5411(a)(2)).
1.11.8 You must meet the requirements specified in paragraphs (a)(3)(i) (Condition 1.11.8.1) and (ii)
(Condition 1.11.8.2) of this section if the closed vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control
device (§60.5411(a)(3)).
1.11.8.1 Except as provided in paragraph (a)(3)(ii) (Condition 1.11.8.2) of this section, you must
comply with either paragraph (a)(3)(i)(A) (Condition a) or (B) (Condition b) of this
section for each bypass device (§60.5411(a)(3)(i)).
a. You must properly install, calibrate, maintain, and operate a flow indicator at the.
inlet to the bypass device that could divert the stream away from the control device
or process to the atmosphere that is capable of taking periodic readings as specified
in §60.5416(a)(4) (Condition 1.11.10.4) and either sounds an alarm, or initiates
notification via remote alarm to the nearest field office, when the bypass device is
open such that the stream is being, or could be, diverted away from the control
device or process to the atmosphere. You must maintain records of each time the
alarm is activated according to §60.5420(c)(8) (Condition 1.11.14.4)
(§60.5411(a)(3)(i)(A)).
b. You must secure the bypass device valve installed at the inlet to the bypass device
in the non -diverting position using a car -seal or a lock -and -key type configuration
(§60.5411(a)(3)(i)(B)).
1.11.8.2 Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and
safety devices are not subject to the requirements of paragraph (a)(3)(i) (Condition
1.11.8.1) of this section (§60.5411(a)(3)(ii)).
Continuous Compliance Demonstration Requirements for Reciprocating Compressor Affected Facilities
1.11.9 For each reciprocating compressor affected facility complying with §60.5385(a)(1) (Condition
1.11.1.1) or (2) (Condition 1.11.1.2), you must demonstrate continuous compliance according to
paragraphs (c)(1) (Condition 1.11.9.1) through (3) (Condition 1.11.9.3) of this section. For each
reciprocating compressor affected facility complying with §60.5385(a)(3) (Condition 1.11.1.3),
you must demonstrate continuous compliance according to paragraph (c)(4) (Condition L11.9.4)
of this section (§60.5415(c)).
1.11.9.1 You must continuously monitor the number of hours of operation for each reciprocating
compressor affected facility or track the number of months since initial startup, or
October 15, 2012, or the date of the most recent reciprocating compressor rod packing
replacement, whichever is later (§60.5415(c)(1)).
1.11.9.2 You must submit the annual report as required in §60.5420(b) (Condition 1.11.13) and
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 30
maintain records as required in §60.5420(c)(3) (Condition 1.11.14.1) (§60.5415(c)(2)).
1.11.9.3 You must replace the reciprocating compressor rod packing before the total number of
hours of operation reaches 26,000 hours or the number of months since the most recent
rod packing replacement reaches 36 months (§60.5415(c)(3)).
1.11.9.4 You must operate the rod packing emissions collection system under negative pressure
and continuously comply with the closed vent requirements in §60.5416(a) (Condition
1.11.10) and (b) (Condition 1.11.11) (§60.5415(c)(4)).
Initial and Continuous Cover and Closed Vent System Inspection and Monitoring Requirements
1.11.10Except as provided in paragraphs §60.5416(b)(11) and (12) of this Subpart, you must inspect each
closed vent system according to the procedures and schedule specified in paragraphs (a)(1)
(Condition 1.11.10.1) and (2) (Condition 1.11.10.2) of this section, inspect each cover according
to the procedures and schedule specified in paragraph (a)(3) (Condition 1.11.10.3) of this section,
and inspect each bypass device according to the procedures of paragraph (a)(4) (Condition
1.11.10.4) of this section (§60.5416(a)).
1.11.10.1 For each closed vent system joint, seam, or other connection that is permanently or
semi -permanently sealed (e.g., a welded joint between two sections of hard piping or a
bolted and gasketed ducting flange), you must meet the requirements specified in
paragraphs (a)(1)(i) (Condition a) and (ii) (Condition b) of this section
(§60.5416(a)(1)).
a. Conduct an initial inspection according to the test methods and procedures specified
in paragraph (b) (Condition 1.11.11) of this section to demonstrate that the closed
vent system operates with no detectable emissions. You must maintain records of
the inspection results as specified in §60.5420(c)(6) (Condition 1.11.14.2)
(§60.5416(a)(1)(i)).
b. Conduct annual visual inspections for defects that could result in air emissions.
Defects include, but are not limited to, visible cracks, holes, or gaps in piping; loose
connections; liquid leaks; or broken or missing caps or other closure devices. You
must monitor a component or connection using the test methods and procedures in
paragraph (b) (Condition 1.11.11) of this section to demonstrate that it operates
with no detectable emissions following any time the component is repaired or
replaced or the connection is unsealed. You must maintain records of the inspection
results as specified in §60.5420(c)(6) (Condition 1.11.14.2) ((§60.5416(a)(1)(ii)).
1.11.10.2 For closed vent system components other than those specified in paragraph (a)(1)
(Condition 1.11.10.1) of this section, you must meet the requirements of paragraphs
(a)(2)(i) (Condition a) through (iii) (Condition c) of this section (§60.5416(a)(2)).
a. Conduct an initial inspection according to the test methods and procedures specified
in paragraph (b) (Condition 1.11.11) of this section to demonstrate that the closed
vent system operates with no detectable emissions. You must maintain records of
the inspection results as specified in §60.5420(c)(6) (Condition 1.11.14.2)
(§60.5416(a)(2)(i)).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 31
b. Conduct annual inspections according to the test methods and procedures specified
in paragraph (b) (Condition 1.11.11) of this section to demonstrate that the
components or connections operate with no detectable emissions. You must
maintain records of the inspection results as specified in §60.5420(c)(6) (Condition
1.11.14.2) (§60.5416(a)(2)(ii)).
c. Conduct annual visual inspections for defects that could result in air emissions.
Defects include, but are not limited to, visible cracks, holes, or gaps in ductwork;
loose connections; liquid leaks; or broken or missing caps or other closure devices.
You must maintain records of the inspection results as specified in §60.5420(c)(6)
(Condition 1.11.14.2) (§60.5416(a)(2)(iii)).
1.11.10.3 For each cover, you must meet the requirements in paragraphs (a)(3)(i) (Condition a)
and (ii) (Condition b) of this section (§60.5416(a)(3)).
a. Conduct visual inspections for defects that could result in air emissions. Defects
include, but are not limited to, visible cracks, holes, or gaps in the cover, or between
the cover and the separator wall; broken, cracked, or otherwise damaged seals or
gaskets on closure devices; and broken or missing hatches, access covers, caps, or
other closure devices. In the case where the storage vessel is buried partially or
entirely underground, you must inspect only those portions of the cover that extend
to or above the ground surface, and those connections that are on such portions of
the cover (e.g., fill ports, access hatches, gauge wells, etc.) and can be opened to
the atmosphere (§60.5416(a)(3)(i)).
b. You must initially conduct the inspections specified in paragraph (a)(3)(i)
(Condition a) of this section following the installation of the cover. Thereafter, you
must perform the inspection at least once every calendar year, except as provided
in paragraphs §60.5416(b)(11) and (12) of this Subpart. You must maintain records
of the inspection results as specified in §60.5420(c)(7) (Condition 1.11.14.3)
(§60.5416(a)(3)(ii)).
1.11.10.4 For each bypass device, except as provided for in §60.5411 (Condition 1.11.8.2), you
must meet the requirements of paragraphs (a)(4)(i) (Condition a) or (ii) (Condition b)
of this section (§60.5416(a)(4)).
a. Set the flow indicator to take a reading at least once every 15 minutes at the inlet to
the bypass device that could divert the stream away from the control device to the
atmosphere (§60.5416(a)(4)(i)).
b. If the bypass device valve installed at the inlet to the bypass device is secured in
the non -diverting position using a car -seal or a lock -and -key type configuration,
visually inspect the seal or closure mechanism at least once every month to verify'
that the valve is maintained in the non -diverting position and the vent stream is not
diverted through the bypass device. You must maintain records of the inspections
according to §60.5420(c)(8) (Condition 1.11.14.4) (§60.5416(a)(4)(ii)).
1.11.11No detectable emissions test methods and procedures. If you are required to conduct an inspection
of a closed vent system or cover at your centrifugal compressor or reciprocating compressor
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 32
affected facility as specified in paragraphs (a)(1) (Condition 1.11.10.1), (2) (Condition 1.11.10.2),
or (3) (Condition 1.11.10.3) of this section, you must meet the requirements of paragraphs (b)(1)
through (13) of this Subpart (§60.5416(b)).
Notification, Recordkeeping and Reporting Requirements
1.11.12If you own or operate a reciprocating compressor facility you are not required to submit the
notifications required in §60.7(a)(1), (3), and (4) (§60.5420(a)(1)).
1.11.13Reporting requirements. You must submit annual reports containing the information specified in
paragraphs §60.5420(b)(4) of this Subpart to the Administrator and performance test reports as
specified in paragraph §60.5420(b)(7) or (8) of this Subpart. The initial annual report is due no
later than 90 days after the end of the initial compliance period as determined according to
§60.5410 (Condition 1.11.5). Subsequent annual reports are due no later than same date each year
as the initial annual report. If you own or operate more than one affected facility, you may submit
one report for multiple affected facilities provided the report contains all of the information
required as specified in paragraph §60.5420(b)(4) of this section. Annual reports may coincide
with title V reports as long as all the required elements of the annual report are included. You may
arrange with the Administrator a common schedule on which reports required by this part may be
submitted as long as the schedule does not extend the reporting period (§60.5420(b)).
1.11.14Recordkeeping requirements. You must maintain the records identified as specified in §60.7(f)
(Condition 1.12.1) and in paragraphs (c)(3) (Condition 1.11.14.1), (c)(6) (Condition 1.11.14.2)
through (c)(9) Condition 1.11.14.5) and (c)(14) (Condition 1.11.14.6) of this section. All records
required by this subpart must be maintained either onsite or at the nearest local field office for at
least 5 years (§60.5420(c)).
1.11.14.1 For each reciprocating compressors affected facility, you must maintain the records in
paragraphs (c)(3)(i) (Condition a) through (iii) (Condition c) of this section
(§60.5420(c)(3)).
a. Records of the cumulative number of hours of operation or number of months since
initial startup or October 15, 2012, or the previous replacement of the reciprocating
compressor rod packing, whichever is later (§60.5420(c)(3)(i)).
b. Records of the date and time of each reciprocating compressor rod packing
replacement, or date of installation of a rod packing emissions collection system
and closed vent system as specified in §60.5385(a)(3) (Condition 1.11.1.3)
(§60.5420(c)(3)(ii)).
c. Records of deviations in cases where the reciprocating compressor was not operated
in compliance with the requirements specified in §60.5385 (Conditions 1.11.1
through 1.11.3) (§60.5420(c)(3)(iii)).
1.11.14.2 Records of the cumulative number of hours of operation or number of months since
initial startup or October 15, 2012, or the previous replacement of the reciprocating
compressor rod packing, whichever is later (§60.5420(c)(6)).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 33
1.11.14.3 A record of each cover inspection required under §60.5416(a)(3) (Condition 1:11.10.3)
for reciprocating compressors (§60.5420(c)(7)).
1.11.14.4 If you are subject to the bypass requirements of §60.5416(a)(4) (Condition 1.11.10.4)
for reciprocating compressors or, a record of each inspection or a record each time the
key is checked out or a record of each time the alarm is sounded (§60.5420(c)(8)).
1.11.14.5 If you are subject to the closed vent system no detectable emissions requirements of
§60.5416(b) (Condition 1.11.11) for reciprocating compressors, a record of the
monitoring conducted in accordance with §60.5416(b) (Condition 1.11.11)
(§60.5420(c)(9))
1.11.14.6 A log of records as specified in §60.5413(e)(4) of this Subpart for all inspection, repair
and maintenance activities for each control device failing the visible emissions test
(§60.5420(c)(14)).
1.12 40 CFR Part 60, Subpart A NSPS
The compressor driven by engine C-192 only is subject to the requirements in 40 CFR Part 60 Subpart
A "General Provisions", as specified in 40 CFR Part 60 Subpart OOOO §60.5425. These requirements
include, but are not limited to, the following:
1.12.1 Notification and recordkeeping (§60.7)
1.12.2 Circumvention (§60.12)
1.12.3 General notification and reporting requirements (§60.19)
1.13 40 CFR Part 63, Subpart ZZZZ NESHAP
Each engine is subject to the National Emissions Standards for Hazardous Air Pollutants requirements of
Regulation No. 8, Part E, Subpart ZZZZ (40 CFR Part 63, Subpart ZZZZ) "National Emissions Standards
for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines", including, but
not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 63 Subpart
7.7,ZZ published in the Federal Register on February 27, 2014. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 63 Subpart ZZZZ.
Note that as of the date of revised permit issuance , the requirements in 40 CFR Part 63
Subpart ZZZZ promulgated on March 3, 2010 and later have not been adopted into Colorado Regulation
No. 8, Part E by the Division and are therefore not state -enforceable. In the event that the Division adopts
these requirements, they will become both state and federally enforceable.
General Requirements
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 34
1.13.1 You must be in compliance with the emission limitations, operating limitations, and other
requirements in this subpart that apply to you at all times (§63.6605(a)).
1.13.2 At all times you must operate and maintain any affected source, including associated air pollution
control equipment and monitoring equipment, in a manner consistent with safety and good air
pollution control practices for minimizing emissions. The general duty to minimize emissions does
not require you to make any further efforts to reduce emissions if levels required by this standard
have been achieved. Determination of whether such operation and maintenance procedures are
being used will be based on information available to the Administrator which may include, but is
not limited to, monitoring results, review of operation and maintenance procedures, review of
operation and maintenance records, and inspection of the source (§63.6605(b)).
Emission Limitations, Operating Limitations and Work Practices
1.13.3 If you own or operate an existing stationary RICE located at an area source of HAP emissions, you
must comply with the requirements in Table 2d (Condition 1.13.3.1) to this subpart that apply to
you (§63.6603(a)).
1.13.3.1 Table 2d Item 11 for non -emergency, non -black start 4SRB remote stationary RICE >
500 HP:
a. Change oil and filter every 2,160 hours of operation or annually, whichever comes
first (Table 2d, Item 11.a).
b. Inspect spark plugs every 2,160 hours of operation or annually, whichever comes
first, and replace as necessary (Table 2d, Item 11.b).
c. Inspect all hoses and belts every 2,160 hours of operation or annually, whichever
comes first, and replace as necessary (Table 2d, Item 11.c).
1.13.3.2 Sources have the option to utilize an oil analysis program as described in §63.6625(j)
(Condition 1.13.6) in order to extend the specified oil change requirement in Table 2d
(Condition 1.13.3.1a) of this subpart (Table 2d, Footnote 1).
1.13.4 An existing non -emergency SI 4SLB and 4SRB stationary RICE with a site rating of more than
500 HP located at area sources of HAP must meet the definition of remote stationary RICE in
§63.6675 of this subpart on the initial compliance date for the engine, October 19, 2013, in order
to be considered a remote stationary RICE under this subpart. Owners and operators of existing
non -emergency SI 4SLB and 4SRB stationary RICE with a site rating of more than 500 HP located
at area sources of HAP that meet the definition of remote stationary RICE in §63.6675 of this
subpart as of October 19, 2013 must evaluate the status of their stationary RICE every 12 months.
Owners and operators must keep records of the initial and annual evaluation of the status of the
engine. If the evaluation indicates that the stationary RICE no longer meets the definition of remote
stationary RICE in §63.6675 of this subpart, the owner or operator must comply with all of the
requirements for existing non -emergency SI 4SLB and 4SRB stationary RICE with a site rating of
more than 500 HP located at area sources of HAP that are not remote stationary RICE within 1
year of the evaluation (§63.6603(f)).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 35
Testing and Initial Compliance Requirements
1.13.5 If you operate a new, reconstructed, or existing stationary engine, you must minimize the engine's
time spent at idle during startup and minimize the engine's startup time to a period needed for
appropriate and safe loading of the engine, not to exceed 30 minutes, after which time the emission
standards applicable to all times other than startup in Table 2d (Condition 1.13.3.1) to this subpart
apply (§63.6625(h)).
1.13.6 You have the option of utilizing an oil analysis program in order to extend the specified oil change
requirement in Tables 2d (Condition 1.13.3.1a) to this subpart. The oil analysis must be performed
at the same frequency specified for changing the oil in Table 2d (Condition 1.13.3.1a) to this
subpart. The analysis program must at a minimum analyze the following three parameters: Total
Acid Number, viscosity, and percent water content. The condemning limits for these parameters
are as follows: Total Acid Number increases by more than 3.0 milligrams of potassium hydroxide
(KOH) per gram from Total Acid Number of the oil when new; viscosity of the oil has changed
by more than 20 percent from the viscosity of the oil when new; or percent water content (by
volume) is greater than 0.5. If all of these condemning limits are not exceeded, the engine owner
or operator is not required to change the oil. If any of the limits are exceeded, the engine owner or
operator must change the oil within 2 business days of receiving the results of the analysis; if the
engine is not in operation when the results of the analysis are received, the engine owner or
operator must change the oil within 2 business days or before commencing operation, whichever
is later. The owner or operator must keep records of the parameters that are analyzed as part of the
program, the results of the analysis, and the oil changes for the engine. The analysis program must
be part of the maintenance plan for the engine (§63.6625(j)).
Continuous Compliance Requirements
1.13.7 You must demonstrate continuous compliance with each emission limitation, operating limitation,
and other requirements in Table 2d (Condition 1.13.3.1) to this subpart that apply to you according
to methods specified in Table 6 (Condition 1.13.7.1) to this subpart (§63.6640(a)).
1.13.7.1 Table 6 Item 9 for existing non -emergency 4SLB and 4SRB stationary RICE >500 HP
located at an area source of HAP that are remote stationary RICE:
a. Work or Management practices
(i) Operating and maintaining the stationary RICE according to the manufacturer's
emission -related operation and maintenance instructions (Table 6, Item 9.a.i);
or
(ii) Develop and follow your own maintenance plan which must provide to the
extent practicable for the maintenance and operation of the engine in a manner
consistent with good air pollution control practice for minimizing emissions
(Table 6, Item 9.a.ii).
1.13.8 You must report each instance in which you did not meet each emission limitation or operating
limitation in Table 2d (Condition 1.13.3.1) to this subpart that apply to you. These instances are
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 36
deviations from the emission and operating limitations in this subpart. These deviations must be
reported according to the requirements in §63.6650 (Condition 1.13.10). If you change your
catalyst, you must reestablish the values of the operating parameters measured during the initial
performance test. When you reestablish the values of your operating parameters, you must also
conduct a performance test to demonstrate that you are meeting the required emission limitation
applicable to your stationary RICE (§63.6640(b)).
1.13.9 You must also report each instance in which you did not meet the requirements in Table 8
(Condition 1.14) to this subpart that apply to you (§63.6640(e)).
Reporting Requirements
1.13.10Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 71
must report all deviations as defined in this subpart (Condition 1.13.8) in the semiannual
monitoring report required by 40 CFR 70.6 (a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A)
(§63.6650(f)).
Recordkeeping Requirements
1.13.11If you must comply with the emission and operating limitations (Condition 1.13.3.1), you must
keep the records described in paragraphs §63.6655(a)(1) through (a)(5) of this subpart
(§63.6655(a)).
1.13.12You must keep the records required in Table 6 (Condition 1.13.7.1) of this subpart to show
continuous compliance with each emission or operating limitation that applies to you
(§63.6655(d)).
1.13.13You must keep records of the maintenance conducted on the stationary RICE in order to
demonstrate that you operated and maintained the stationary RICE and after -treatment control
device (if any) according to your own maintenance plan (§63.6655(e)).
1.13.14Your records must be in a form suitable and readily available for expeditious review according to
§63.10(b)(1). (Condition 1.14.2) (§63.6660(a)).
1.13.15As specified in §63.10(b)(1), (Condition 1.14.2), you must keep each record for 5 years following
the date of each occurrence, measurement, maintenance, corrective action, report, or record
(§63.6660(b)).
1.13.16You must keep each record readily accessible in hard copy or electronic form for at least 5 years
after the date of each occurrence, measurement, maintenance, corrective action, report, or record,
according to §63.10(b)(1) (Condition 1.14.2) (§63.6660(c)).
1.14 40 CFR Part 63, Subpart A NESHAP
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 37
Each engine is subject to the requirements in 40 CFR Part 63 Subpart A "General Provisions",as adopted
by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart ZZZZ
§63.6665. These requirements include, but are not limited to, the following:
1.14.1 Prohibited activities and circumvention (§63.4)
1.14.2 Recordkeeping and reporting requirements (§63.10)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 38
2. C-181 — Waukesha 1,478 hp Natural Gas Fired Internal Combustion Engine, AIRS ID: 134
Parameter
Permit
Condition
Number
Limitation
Compliance
Emission Factor
Monitoring
Method
Interval
Emission & Consumption Limits
NOx
CO
2.1
14.3 tons/year
0.283 lb/MMBtu
28.5 tons/year
0.565 lb/MMBtu
VOC
2.2
10.0 tons/year.
Natural Gas
Consumption
2.3
Other Requirements
Fuel Gas Heat
Content
2.4
Hours of Operation
2.5
Opacity
2.6
Control Device
Requirements
2.7
Portable Monitoring
2.8
0.198 lb/MMBtu
97.1 MMSCF/year
Not to exceed 20%, except as
provided for below:
For Certain Operational
Activities - Not to exceed
30% for a period or periods
aggregating more than six (6)
minutes in any sixty (60)
consecutive minutes
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
Fuel Meter, Twelve
Month Rolling Total
Monthly
ASTM Methods
Semi -
Annually
Recordkeeping
Monthly
Fuel Restriction — Natural Gas Only
Recordkeeping
See Condition
2.7
Flue Gas Analyzer
Quarterly
Compliance Assurance
Monitoring (CAM)
2.9
See Condition 2.9
Statewide Controls for
Oil and Gas
Operations
2.10
See Condition 2.10
40 CFR 63 Subpart
ZZZZ NESHAP
2.11
Complies by meeting 40 CFR 60 Subpart JJJJ NSPS
See Condition 2.11
40 CFR 63 Subpart A
General Provisions
NESHAP
2.12
See Condition 2.12
40 CFR 60 Subpart
JJJJ NSPS
40 CFR 60 Subpart A
General Provisions
NSPS
2.13
2.14
NOx - 1.0 g/hp-hr or 82 ppmvd @ 15% O2
CO - 2.0 g/hp-hr or 270 ppmvd @ 15% O2
VOC - 0.7 g/hp-hr or 60 ppmvd @ 15% O2
See Condition 2.13
See Condition 2.14
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
2.1 NOx & CO Emission Limitations & Compliance Monitoring
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 39
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from this engine shall not exceed the
limitations listed in Summary Table 2 above (Colorado Construction Permit 07WE0988, as modified
under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part B, Section II.A.6
and Part C, Section X, based on the requested emissions identified on the APEN submitted on 8/18/2015).
The emission factors listed above have been approved by the Division and shall be used to calculate
emissions from this engine, except in the event of a failed portable flue gas analyzer test, as provided for
in Condition 2.8. Compliance with the emission limitations shall be monitored as follows:
2.1.1 Monthly emissions shall be calculated by the end of the subsequent month using the above
emission factors, the monthly natural gas consumption (as required by Condition 2.3) and the heat
content of the natural gas (as required by Condition 2.4) in the equation below:
Emission Factor lb) ( x Heat Content (MMMMSBtu MMn CF) ( month
x Fuel Use
r tons __ (MMBtu
month / Unit Conversion (2000 lb)
ton
NOx or CO Emissions
Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the
annual limitations. Each month, a new twelve month total shall be calculated using the previous
twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
2.1.2 Portable monitoring shall be conducted quarterly as required by Condition 2.8. If the results of the
portable analyzer testing conducted under the provisions of Condition 2.8 show that either the NOx
or CO emission rates/factors are greater than those listed above, and in the absence of subsequent
testing results to the contrary (as approved by the Division), the permittee shall apply for a
modification to this permit to reflect, at a minimum, the higher emission rates/factors within 60
days of the completion of the test.
2.2 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) from this engine shall not exceed the limitation listed
in Summary Table 2 above (Colorado Construction Permit 07WE0988, as modified under the provisions
of Section I, Condition 1.3 and Colorado Regulation No. 3, Part B, Section II.A.6 and Part C, Section X,
based on the requested emissions identified on the APEN submitted on 8/18/2015). Compliance with the
emission limitation shall be monitored as follows:
2.2.1 Monthly emissions shall be calculated by the end of the subsequent month using the above
emission factors, the monthly natural gas consumption (as required by Condition 2.3) and the heat
content of the natural gas (as required by Condition 2.4) in the equation below:
Emission Factor lb x Heat Content (MMBtu x Fuel Use (MMSCF
tons l — (MMBtu) IMMSCF) l month )
VOC Emissions (month/ 2000 ib
Unit Conversion ( ton )
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP. Operating Company, LP
Roggen Natural Gas Processing Plant
Page 40
Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the
annual limitations. Each month, a new twelve month total shall be calculated using the previous
twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
2.2.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility-
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the methods required by Condition 14 and used in a twelve
month rolling total to monitor compliance with the facility -wide HAP emission limitations.
2.3 Natural Gas Consumption Limitations & Compliance Monitoring
Natural gas consumption from this engine shall not exceed the limitation listed in Summary Table 2 above
(Colorado Construction Permit 07WE0988). Compliance with the consumption limitation shall be
monitored as follows:
2.3.1 Facility -wide natural gas consumption for each month shall be recorded using the existing fuel
meter. The facility -wide natural gas consumption shall be measured on the same day that run time
hours have been recorded for this engine in accordance with Condition 2.5.
2.3.1.1 In the event the fuel meter cannot be used to determine fuel usage at any time, the
manufacturer -provided fuel consumption of each natural-gas consuming unit may be
used in lieu of the meter.
2.3.2 Allocation of natural gas to this engine shall be calculated using the following calculation:
Btu
MMSCF HREngine (month) MMSCF
FCEngine(
month / l Btu Btu Btu x FCFaciiity month
E
\ l
HREngine (month) + E HRHeater (month + E HR Btu
(month
Where:
HREngine (montBtuh = BSFC (hp B•tu
1 x Hours of Operation (mhr onth) x Site Rated HP (hp)
HRHeater Design Heat Rating l x Hours of Operation
(month ( hr Btuhr
) (month))
And:
FCEngine = Individual Engine Fuel Consumption, MMSCF/Month
HREngine = Individual Engine Heat Requirement,Btu/
HRHeater = Individual Heater Heat Requirement, Btu/Month
'Mother = Other Users Heat Requirement, Btu/Month
FCFaciiity = Facility Wide Fuel Consumption (metered), MMSCF/Month
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 41
BSFC = Brake Specific Fuel Consumption, Btu/hp • hr
Monthly natural gas consumption from this engine shall be used in a twelve month rolling total to monitor
compliance with the annual limitation. Each month, a new twelve month total shall be calculated using
the previous twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
Monthly natural gas consumption from this engine shall be used to monitor compliance with the annual
NOx, CO and VOC emission limitations as required by Condition 2.1 and 2.2.
2.4 Fuel Gas Heat Content
The heat content of the natural gas used to fuel this engine shall be verified semi-annually, or once every
six months, using the appropriate ASTM Methods or equivalent, if approved in advance by the Division.
The heat content of the natural gas shall be based on the higher heating value (HI -1V) of the fuel. Results
of the heat content verification shall be retained and made available to the Division upon request.
The heat content indicated by the most recent analysis shall be used to monitor compliance with the annual
NOx, CO and VOC emission limitations for this engine, as required by Condition 2.1 and 2.2.
2.5 Hours of Operation
Hours of operation of this engine shall be monitored and recorded monthly. Hours of operation shall be
recorded on the same day that the monthly facility -wide fuel gas consumption is measured. Monthly hours
of operation shall be used in a running total for each annual compliance period. Records shall be made
available for Division review upon request.
The hours of operation shall be used to monitor compliance with the annual fuel gas consumption
limitation, as required by Condition 2.3.
2.6 Opacity
The following opacity requirements apply to this engine:
2.6.1 Except as provided for in Condition 2.6.2 below, no owner or operator of a source shall allow or
cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity
(Colorado Regulation No. 1, Section II.A.1).
2.6.2 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air
pollutant resulting from the building of a new fire, cleaning of fire boxes, soot blowing, start-up,
process modifications, or adjustment or occasional cleaning of control equipment which is excess
of 30% opacity for a period or periods aggregating more than six (6) minutes in any sixty (60)
consecutive minutes (Colorado Regulation No. 1, Section II.A.4).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 42
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be presumed
since only natural gas is permitted to be used as fuel for this engine. The permittee shall maintain records
that verify that only natural gas is used as fuel.
2.7 Control Device Requirements
This engine shall be equipped with both a non -selective catalytic reduction system and an air fuel
controller (as required by Condition 2.10.1.1). Parameters associated with the air -to -fuel ratio controller
(AFR) and non -selective catalyst reduction unit shall be monitored as follows:
2.7.1 The pressure drop across the catalyst shall be monitored and recorded monthly. The pressure drop
shall not exceed 2 inches of water column from the baseline value established by the source when
the engine is operating at maximum achievable load. This baseline pressure drop shall be
established by the source during each initial compliance and portable analyzer test, and as noted
below.
If the pressure is outside this range, then the appropriate maintenance shall be performed to bring
the pressure back into range. In lieu of maintenance, the source may choose to perform a portable
analyzer test of the engine to establish a new pressure drop value within fourteen (14) days of the
exceedance. If the test demonstrates that the engine is in compliance with its emission limits, the
pressure drop value at which the engine is tested shall become the new baseline.
The catalyst will be cleaned, reconditioned and replaced per the manufacturer's recommended
schedule and a copy of maintenance reports shall be kept for Division review upon request. For
new, cleaned or reconditioned catalyst: the new pressure drop baseline must be established by the
operator within the first seven days of engine/catalyst operation and re-established during the next
regularly scheduled emission test.
2.7.2 The catalyst inlet temperature shall be monitored and recorded daily and kept between 750°F and
1250°F. If the temperature is outside of this range, then appropriate maintenance activities shall
be performed. A log of periods observed outside this range and subsequent maintenance activities
performed shall be maintained and made available for Divisions review upon request.
2.7.3 When portable monitoring is scheduled, the parameters above in Conditions 2.7.1 and 2.7.2 shall
be recorded during the portable monitoring event.
2.7.4 The millivolt reading for the Air -Fuel Ratio Controller (AFR) O2 sensor for this engine will be
monitored and recorded weekly to assess the air to fuel ratio controller operating condition. During
those weeks when portable monitoring is scheduled, the millivolt reading shall be monitored and
recorded during the portable monitoring event. Recording of the millivolt reading shall be used to
verify that the AFR controller is operated in accordance with the manufacturer's recommendations.
2.7.5 The oxygen concentration in the engine exhaust gas shall be measured and recorded for this engine
during each portable monitoring event required by Condition 2.8.
2.8 Portable Monitoring (ver 06/26/2014)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 43
Emission measurements of nitrogen oxides (NOx) and carbon monoxide (CO) shall be conducted
quarterly using a portable flue gas analyzer. At least one calendar month shall separate the quarterly tests.
Note that if the engine is operated for less than one hundred (100) hrs in any quarterly period, then the
portable monitoring requirements do not apply.
All portable analyzer testing required by this permit shall be conducted using the Division's Portable
Analyzer Monitoring Protocol (ver March 2006 or newer) as found on the Division's website at:
https://www.colorado.gov/pacific/cdphe/portable-analyzer-monitoring-protocol
Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For
comparison with an annual or short term emission limit, the results of the tests shall be converted to a lb/hr
basis and multiplied by the allowable operating hours in the month or year (whichever applies) in order to
monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied
by the maximum number of hours in the month or year (8760), whichever applies.
If the portable analyzer results indicate compliance with both the NOx and CO emission limitations, in
the absence of credible evidence to the contrary, the source may certify that the engine is in compliance
with both the NOx and CO emission limitations for the relevant time period.
Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if
the portable analyzer results fail to demonstrate compliance with either the NOx or CO emission
limitations, the engine will be considered to be out of compliance from the date of the portable analyzer
test until a portable analyzer test indicates compliance with both the NOx and CO emission limitations or
until the engine is taken offline.
For comparison with the emission rates/factors, the emission rates/factors determined by the portable
analyzer tests and approved by the Division shall be converted to the same units as the emission
rates/factors in the permit. If the portable analyzer tests show that either the NOx or CO emission
rates/factors are greater than the relevant ones set forth in the permit, and in the absence of subsequent
testing results to the contrary (as approved by the Division), the permittee shall apply for a modification
to this permit to reflect, at a minimum, the higher emission rate/factor within sixty (60) days of the
completion of the test.
Results of all tests conducted shall be kept on site and made available to the Division upon request.
2.9 Compliance Assurance Monitoring
This engine is subject to the Compliance Assurance Monitoring (CAM) requirements with respect to the
annual emission limitations in Condition 2.1 for NOx and CO. Compliance with the CAM requirements
shall be monitored in accordance with the requirements in Condition 16 and the CAM Plan in Appendix
H.
2.10 Statewide Controls for Oil and Gas Operations
2.10.1 Colorado Regulation No. 7, Section XVI Requirements:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 44
This engine is subject to the following requirements of Colorado Regulation No. 7, Section XVI,
"Control of Emissions from Stationary and Portable Combustion Equipment in the 8 -Hour Ozone
Control Area":
Conditions shown in italic text below represent monitoring, recordkeeping ' and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
Air Pollution Technology Requirements
2.10.1.1 For rich burn reciprocating internal combustion engines, a non -selective catalyst
reduction and an air fuel controller shall be required. A rich burn reciprocating internal
combustion engine is one with a normal exhaust oxygen concentration of less than 2%
by volume (Colorado Regulation No. 7, Section XVI.B.1).
2.10.1.2 The emission control equipment required by this Section XVI.B (Condition 2.10.1.1)
shall be appropriately sized for the engine and shall be operated and maintained
according to manufacturer specifications (Colorado Regulation No. 7, Section
XVI.B.3).
Exemptions
2.10.1.3 The following stationary combustion equipment are exempt from the emission
limitation requirements of Section XVI.D.4., the compliance demonstration
requirements in Section XVI.D.5., and the related recordkeeping and reporting
requirements of Sections XVI.D.7.a-f. and XVI.D.8, but these sources must maintain
any and all records necessary to demonstrate that an exemption applies (Condition
2.10.1.8b). These records must be maintained for a minimum of five years and made
available to the Division upon request. Qualifying for an exemption in this section does
not preclude the combustion process adjustment requirements of Section XVI.D.6.
(Conditions 2.10.1.6 through 2.10.1.7), when required by XVI.D.6.a (Condition
2.10.1.5).
Once stationary combustion equipment no longer qualifies for any exemption, the
owner or operator must comply with the applicable requirements of this Section XVI.D.
as expeditiously as practicable but no later than 36 months after any exemption no
longer applies. Additionally, once stationary combustion equipment that is not
equipped with CEMS or CERMS no longer qualifies for any exemption, the owner or
operator must conduct a performance test using EPA test methods within 180 days and
notify the Division of the results and whether emission controls will be required to
comply with the emission limitations of Section XVI.D.4 (Colorado Regulation No. 7,
Section XVI.D.2.).
a. Any natural gas -fired reciprocating internal combustion engines subject to a work
practice or emission control requirement contained in this Regulation 7, Section
XVI.A. or B. (Condition 2.10.1.1) (Colorado Regulation No. 7, Section
XVI.D.2.e.).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 45
2.10.1.4 [Additional Recordkeeping: Notwithstanding, the owner or operator shall comply
with the recordkeeping requirements of Section XVI.D.7..f (Condition 2.10.1.8a) for
the combustion process adjustments required under Section XVI.D.6.b. (Condition
2.10.1.6.)]
Combustion Process Adjustment
2.10.1.5 As of January 1, 2017, this Section XVI.D.6.(Condition 2.10.1.6) applies to boilers,
duct burners, process heaters, stationary combustion turbines, and stationary
reciprocating internal combustion engines with uncontrolled actual emissions of NOx
equal to or greater than five (5) tons per year that existed at major sources of NOx as
of June 3, 2016. (Colorado Regulation No. 7, Section XVI.D.6.a.).
2.10.1.6 Combustion Process Adjustment (Colorado Regulation No. 7, Section XVI.D.6.b.)
a. The owner or operator of a stationary internal combustion engine must conduct the
following inspections and adjustments, as applicable (Colorado Regulation No. 7,
Section XVI.D.6.b.(iv)):
(i) Change oil and filters as necessary (Colorado Regulation No. 7, Section
XVI.D.6.b.(iv)(A)).
(ii) Inspect air cleaners, fuel filters, hoses, and belts and clean or replace as
necessary (Colorado Regulation No. 7, Section XVI.D.6.b.(iv)(B)).
(iii)Inspect spark plugs and replace as necessary (Colorado Regulation No. 7,
Section XVI.D.6.b.(iv)(C)).
b. The owner or operator must operate and maintain the boiler, duct burner, process
heater, stationary combustion turbine, or stationary internal combustion engine
consistent with manufacturer's specifications, if available, or good engineering and
maintenance practices (Colorado Regulation No. 7, Section XVI.D.6.b.(v)).
c. Frequency (Colorado Regulation No. 7, Section XVI.D.6.b.(vi))
(i) The owner or operator must conduct the initial combustion process adjustment
by April 1, 2017. An owner or operator may rely on a combustion process
adjustment conducted in accordance with applicable requirements and schedule
of a New Source Performance Standard in 40 CFR Part 60 or National Emission
Standard for Hazardous Air Pollutants in 40 CFR Part 63 to satisfy the
requirement to conduct an initial combustion process adjustment by April 1,
2017 (Colorado Regulation No. 7, Section XVI.D.6.b.(vi)(A)).
(ii) The owner or operator must conduct subsequent combustion process
adjustments at least once every twelve (12) months after the initial combustion
adjustment, or on the applicable schedule according to Sections XVI.D.6.c.(i).
(Condition 2.10.1.7a) or XVI.D.6.c.(ii). (Condition 2.10.1.7b) (Colorado
Regulation No. 7, Section XVI.D.6.b.(vi)(B)).
Alternative Requirements
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 46
2.10.1.7 As an alternative to the requirements described in Sections XVI.D.6.b.(iv) (Condition
2.10.1.6a) and XVI.D.6.b.(v) (Condition 2.10.1.6b) (Colorado Regulation No. 7,
Section XVI.D.6.c.):
a. The owner or operator may conduct the combustion process adjustment according
to the manufacturer recommended procedures and schedule (Colorado Regulation
No. 7, Section XVI.D.6.c.(i)); or
b. The owner or operator of combustion equipment that is subject to and required to
conduct a period tune-up or combustion adjustment by the applicable requirements
of a New Source Performance Standard in 40 CFR Part 60 or National Emission
Standard for Hazardous Air Pollutants in 40 CFR Part 63 may conduct tune-ups or
adjustments according to the schedule and procedures of the applicable
requirements of 40 CFR Part 60 or 40 CFR Part 63 (Colorado Regulation No. 7,
Section XVI.D.6.c.(ii)).
Recordkeeping
2.10.1.8 The following records must be kept for a period of five years and made available to the
Division upon request (Colorado Regulation No. 7, Section XVI.D.7.):
a. For stationary combustion equipment subject to the combustion process adjustment
requirements in Section XVI.D.6. (Condition 2.10.1.6), the following
recordkeeping requirements apply (Colorado Regulation No. 7, Section
XVI.D.7.f.):
(i)
The owner or operator must create a record once everycalendar year identifying
the combustion equipment at the source subject to Section XVI.D. (Condition
2.10.1.5) and including for each combustion equipment (Colorado Regulation
No. 7, Section XVI.D.7.(f).(i)):
(A) The date of the adjustment (Colorado Regulation No. 7, Section
XVI.D.7.f.(i)(A));
(B) Whether the combustion process adjustment under Sections
XVI.D.6.b.(iv) (Condition 2.10.1.6a) and XVI.D.6.b.(v) (Condition
2.10.1.6b). was followed, and what procedures were performed
(Colorado Regulation No. 7, Section XVI.D.7.f.(i)(B));
(C) Whether a combustion process adjustment under Sections
XVI.D.6.a. (Condition 2.10.1.5) and XVI.D.6.b. (Condition
2.10.1.6). was followed, what procedures were performed, and what
New Source Performance or National Emission Standard for
Hazardous Air Pollutants applied, if any (Colorado Regulation No.
7, Section XVI.D.7.f.(i)(C)); and
(D) A description of any corrective action taken (Colorado Regulation
No. 7, Section XVI.D.7.f.(i)(D)).
(E) If the owner or operator conducts the combustion process
adjustment according to the manufacturer recommended procedures
and schedule and the manufacturer specifies a combustion process
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 47
adjustment on an operation time schedule, the hours of operation.
(Colorado Regulation No. 7, Section XVI.D.7.f.(i)(E)).
(F) [Additional Recordkeeping: If the owner or operator conducts an
alternative combustion process adjustment under Section
XVI.D.6.c. (Condition 2.10.1.7), the owner or operator shall
document that these requirements were followed, what procedures
were performed, and what New Source Performance or National
Emission Standard for Hazardous Air Pollutants applied, if any.]
(ii) The owner or operator must retain manufacturer recommended procedures,
specifications, and maintenance schedule if utilized under Section XVI.D.6.a.
(Condition 2.10.1.5) for the life of the equipment (Colorado Regulation No. 7,
Section XVI.D.7.f.(ii)).
(iii)As an alternative to the requirements described in Section XVI.D.7.f.(i)
(Condition (i) above), the owner or operator may comply with applicable
recordkeeping requirements related to combustion process adjustments
conducted according to a New Source Performance Standard in 40 CFR Part 60
or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63
(Colorado Regulation No. 7, Section XVI.D.7.f.(iii)).
b. All sources qualifying for an exemption under Section XVI.D.2. (Condition
2.10.1.3) must maintain all records necessary to demonstrate that an exemption
applies (Colorado Regulation No. 7, Section XVI.D.7.g.).
2.11 40 CFR Part 63, Subpart ZZZZ NESHAP
This engine is subject to the National Emissions Standards for Hazardous Air Pollutants requirements of
Regulation No. 8, Part E, Subpart ZZZZ (40 CFR Part 63, Subpart ZZZZ) "National Emissions Standards
for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines", including, but
not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 63 Subpart
ZZZZ published in the Federal Register on February 27, 2014. However, if revisions to this Subpart are
published at- a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 63 Subpart ZZZZ.
Note that as of the date of revised permit issuance XX/XX/XXXX, the requirements in 40 CFR Part 63
Subpart ZZZZ promulgated on March 3, 2010 and later have not been adopted into Colorado Regulation
No. 8, Part E by the Division and are therefore not state -enforceable. In the event that the Division adopts
these requirements, they will become both state and federally enforceable.
What This Subpart Covers
2.11.1 Stationary RICE subject to Regulations under 40 CFR Part 60. An affected source that meets any
of the criteria in paragraphs (c)(1) (Condition 2.11.1.1) through (7) of this section must meet the
requirements of this part by meeting the requirements of 40 CFR part 60 subpart IIII, for
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 48
compression ignition engines or 40 CFR part 60 subpart JJJJ, for spark ignition engines. No further
requirements apply for such engines under this part (§63.6590(c)).
2.11.1.1 A new or reconstructed stationary RICE located at an area source (§63.6590(c)(1)).
2.12 40 CFR Part 63, Subpart A NESHAP
This engine is subject to the requirements in 40 CFR Part 63 Subpart A "General Provisions", as adopted
by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart ZZZZ
§63.6665. These requirements include, but are not limited to the following:
2.12.1 Prohibited activities and circumvention (§63.4)
2.13 40 CFR Part 60, Subpart JJJJ NSPS
This engine is subject to the New Source Performance Standards requirements of 40 CFR Part 60, Subpart
JJJJ "Standards of Performance for Stationary Spark Ignition Internal Combustion Engines", including,
but not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
JJJJ published in the Federal Register on August 30, 2016. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 60 Subpart JJJJ.
These requirements have not been adopted into Colorado Regulation No. 6, Part A as of the date of this
permit issuance XX/XXfXX X, and are therefore not state -enforceable. In the event that these
requirements are adopted into Colorado Regulations, they will become state -enforceable.
Emission Standards for Owners and Operators
2.13.1 Owners and operators of stationary SI ICE with a maximum engine power greater than or equal to
75 KW (100 HP) (except gasoline and rich burn engines that use LPG) must comply with the
emission standards in Table 1 (Condition 2.13.1.1) to this subpart for their stationary SI ICE
(§60.4233(e)).
2.13.1.1 Table 1: NOx, CO, and VOC Emission Standards for Stationary Non -Emergency SI
Engines ≥100 HP
Engine Type
and Fuel
Maximum
Engine
Power
Manufacture
Date
Emission Standards
(g/hp-hr)
Emission Standards
(ppmvd at 15% O2)
NOx
CO
VOC
NOx
CO
VOC
Non-
Emergency SI
Natural Gas
HP ≥ 500
July 1, 2007
2.0
4.0
1.0
160
540
86
July 1, 2010
1.0
2.0
0.7
82
270
60
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 49
2.13.1.1
2.13.1.2
Owners and operators of stationary non -certified SI engines may choose to
comply with the emission standards in units of either g/ITP-hr or ppmvd at
15 percent O2 (Table 1 Footnote (a)).
For purposes of this subpart, when calculating emissions of volatile organic
compounds, emissions of formaldehyde should not be included (Table 1
Footnote (d)).
2.13.2 Owners and operators of stationary SI ICE must operate and maintain stationary SI ICE that
achieve the emission standards as required in §60.4233 (Condition 2.13.1) over the entire life of
the engine (§60.4234).
Compliance Requirements for Owners and Operators
2.13.3 If you are an owner or operator of a stationary SI internal combustion engine and must comply
with the emission standards specified in §60.4233(e) (Condition 2.13.1), you must demonstrate
compliance according to the methods specified in paragraph (b)(1) and (b)(2) of this section
(§60.4243(b)).
2.13.3.1 Purchasing an engine certified according to procedures specified in this subpart, for the
same model year and demonstrating compliance according to one of the methods
specified in §60.4243(a) of this subpart (§60.4243(b)(1)).
2.13.3.2 Purchasing a non -certified engine and demonstrating compliance with the emission
standards specified in §60.4233(e) (Condition 2.13.1) and according to the
requirements specified in §60.4244 (Condition 2.13.5), as applicable, and according to
paragraph (b)(2)(ii) (Condition a) of this section (§60.4243(b)(2)).
a. If you are an owner or operator of a stationary SI internal combustion engine greater
than 500 HP, you must keep a maintenance plan and records of conducted
maintenance and must, to the extent practicable, maintain and operate the engine in
a manner consistent with good air pollution control practice for minimizing
emissions. In addition, you must conduct an initial performance test and conduct
subsequent performance testing every 8,760 hours or 3 years, whichever comes
first, thereafter to demonstrate compliance (§60.4243(b)(2)(ii)).
2.13.4 It is expected that air -to -fuel ratio controllers will be used with the operation of three-way
catalysts/non-selective catalytic reduction. The AFR controller must be maintained and operated
appropriately in order to ensure proper operation of the engine and control device to minimize
emissions at all times (§60.4243(g)).
Testing Requirements for Owners and Operators
2.13.5 Owners and operators of stationary SI ICE who conduct performance tests must follow the
procedures in §60.4244(a) through (g) of this subpart (§60.4244).
Notification, Reports, and Records for Owners and Operators
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 50
2.13.6 Owners or operators of stationary SI ICE must meet the following notification, reporting and
recordkeeping requirements (§60.4245):
2.13.6.1 Owners and operators of all stationary SI ICE must keep records of the information in
paragraphs (a)(1) through (4) of this section (§60.4245(a)).
a. All notifications submitted to comply with this subpart and all documentation
supporting any notification (§60.4245(a)(1)).
b. Maintenance conducted on the engine (§60.4245(a)(2)).
c. If the stationary SI internal combustion engine is a certified engine, documentation
from the manufacturer that the engine is certified to meet the emission standards
and information as required in 40 CFR parts 90, 1048, 1054, and 1060, as applicable
§60.4245(aX3).
d. If the stationary SI internal combustion engine is not a certified engine or is a
certified engine operating in a non -certified manner and subject to §60.4243(a)(2),
documentation that the engine meets the emission standards (§60.4245(a)(4)).
2.13.6.2 Owners and operators of stationary SI ICE that are subject to performance testing must
submit a copy of each performance test as conducted in §60.4244 (Condition 2.13.5)
within 60 days after the test has been completed. Performance test reports using EPA
Method 18, EPA Method 320, or ASTM D6348-03 (incorporated by reference —see 40
CFR 60.17) to measure VOC require reporting of all QA/QC data. For Method 18,
report results from sections 8.4 and 11.1.1.4; for Method 320, report results from
sections 8.6.2, 9.0, and 13.0; and for ASTM D6348-03 report results of all QA/QC
procedures in Annexes 1-7 (§60.4245(d)).
2.14 40 CFR 60 Subpart A NSPS
This engine is subject to the requirements in 40 CFR Part 60 Subpart A "General Provisions", as specified
in 40 CFR Part 60 Subpart JJJJ §60.4246. These requirements include, but are not limited to the following:
2.14.1 Notification and recordkeeping (§60.7)
2.14.2 Performance tests (§60.8)
2.14.3 Compliance with standards and maintenance requirements (§60.11)
2.14.4 Circumvention (§60.12)
2.14.5 General notification and reporting requirements (§60.19)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 51
3. 11037 — Heat Recovery Corp 7.55 MMBtu/hr Natural Gas Fired Hot Oil Heater, AIRS ID: 129
Parameter
Permit
Condition
Number
Limitations
Emission
Factors
Monitoring
Method
Interval
Emission & Consumption Limits
NOx
CO
3.1
100 lb/MMSCF
84 lb/NIMSCF
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
Particulate Matter
3.2
Fuel Restriction — Natural Gas Only
Natural Gas
Consumption
3.3
Fuel Meter
Recordkeeping
Monthly
Other Requirements
Fuel Gas Heat
Content
3.4
Hours of
Operation
3.5
Opacity
3.6
Not to exceed 20% except as
provided below:
For Startup - Not to exceed
30%, for a period or periods
aggregating more than six (6)
minutes in any sixty (60)
consecutive minutes
Statewide Controls
for Oil and Gas
Operations
3.7
ASTM Methods
Semi -
Annually
Recordkeeping
Monthly
Fuel Restriction — Natural Gas Only
See Condition 3.7
40 CFR 60
Subpart A General
Provisions NSPS
3.7
See Condition 3.7
3.1 NOx & CO Emission Limitations & Compliance Monitoring
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO), for the purposes of APEN reporting,
shall be calculated as follows:
3.1.1 Emissions shall be calculated monthly using the above emission factors (from EPA's AP -42:
Compilation of Emission Factors, Section 1.4 for Natural Gas Combustion, Final Section, dated
7/98), and the monthly natural gas consumption, as required by Condition 3.3, in the following
equation:
lb MMSCF
NOx or CO Emissions ( tons l _ EF (MMSCF)l x FEFuel ( month
month
l Unit Conversion (2000 lb)
ton 1
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
Where:
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 52
EF = Emission Factor, lb/MMSCF
FRFuel = Flow Rate of Fuel Gas, MMSCF/month
Annual emissions shall be calculated for the purposes of APEN reporting. Records of calculations
shall be maintained and made available to the Division upon request.
3.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the methods required by Condition 14 and used in a twelve
month rolling total to monitor compliance with the facility -wide HAP emission limitations.
3.2 Particulate Matter Emission Limitations & Compliance Monitoring
Emissions of Particulate Matter (PM) from this heater shall not exceed the limitation required by Colorado
Regulation No. 1, Section III.A.1.b. The numeric PM limitation, for the purposes of Colorado Regulation
No. 1, Section III.A.1.b., was determined using the design heat rate (fuel input) for this heater in the
following equation:
( 16
PE \MMBtu) — 0.5 x
Where:
r _
PE (MMiBtulb/ Particulate Emission
MMBtu
FI ( hr ) = Fuel Input
In the absence of credible evidence to the contrary, compliance with the particulate matter emission limit
set forth in Colorado Regulation No. 1, Section III.A.1.b. shall be presumed since only natural gas is
permitted to be used as fuel for this heater. The permittee shall maintain records that verify that only
natural gas is used as fuel.
3.3 Natural Gas Consumption Limitations & Compliance Monitoring
Natural gas consumption from this heater, for the purposes of APEN reporting, shall be monitored as
follows:
3.3.1 Facility -wide natural gas consumption for each month shall be recorded using the existing fuel
meter. The facility -wide natural gas consumption shall be measured on the same day that run time
hours for this heater have been recorded in accordance with Condition 3.5.
3.3.2 Allocation of natural gas to this heater shall be determined using the following calculation:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 53
Btu l
MMSCF HRHeater (month) MMSCF
Hearer month l HR (Btu + HR Btu l + Fmother
Btu Fatality month
FC / Engine lmonth) Heater L other lmonth) X FC
Where:
Btu HREngine ( month) — BSFC (hp t hr) x Hours o f Operation (month) x Site Rated HP (hp)
Btu — Btu hr
HRHeaterDesign Heat Rating x Hours of Operation
month hr month
And:
FCHeater = Individual Heater Fuel Consumption, MMSCF/Month
HREngine = Individual Engine Heat Requirement, Btu/Month
HRHeater = Individual Heater Heat Requirement, Btu/Month
HRother = Other Users Heat Requirement, Btu/Month
FCFacility = Facility Wide Fuel Consumption (metered), MMSCF/Month
BSFC = Brake Specific Fuel Consumption, Btu/hp • hr
Annual natural gas consumption shall be calculated for the purposes of APEN reporting. Records of
calculations shall be maintained and made available to the Division upon request.
Natural gas consumption from this heater shall be used to calculate NOx and CO emissions for the
purposes of APEN reporting, as required by Condition 3.1.
3.4 Fuel Gas Heat Content
The heat content of the natural gas used to fuel this heater shall be verified semi-annually, or once every
six months, using the appropriate ASTM Methods or equivalent, if approved in advance by the Division.
The heat content of the natural gas shall be based on the higher heating value (HHV) of the fuel. Results
of the heat content verification shall be retained and made available to the Division upon request.
3.5 Hours of Operation
Hours of operation of this heater shall be monitored and recorded monthly. Hours of operation shall be
recorded on the same day that the facility -wide fuel gas consumption is measured. Records shall be made
available for Division review upon request.
The hours of operation shall be used in the calculation of monthly fuel gas consumption, as required by
Condition 3.3.
3.6 Opacity
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
The following opacity requirements apply to this heater:
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 54
3.6.1 Except as provided for in Condition 3.6.2 below, no owner or operator of a source shall allow or
cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity
(Colorado Regulation No. 1, Section II.A.1).
3.6.2 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air
pollutant resulting from the building of a new fire, cleaning of fire boxes, soot blowing, start-up,
process modifications, or adjustment or occasional cleaning of control equipment which is excess
of 30% opacity for a period or periods aggregating more than six (6) minutes in any sixty (60)
consecutive minutes (Colorado Regulation No. 1, Section II.A.4).
3.6.3 [State -Only Enforceable]: No owner or operator shall discharge, or cause the discharge, into the
atmosphere of any particulate matter which is greater than twenty percent (20%) opacity (Colorado
Regulation No. 6, Part B, Section II.C.3).
Note that this opacity standard applies at all times except during periods of startup, shutdown, and
malfunction (40 CFR Part 60, Subpart A, §60.11(c), as adopted by reference in Colorado
Regulation No. 6, Part B, Section I.A).
Note that this opacity requirement is more stringent than the opacity requirement in Condition
3.6.2 above during periods of fire building, cleaning of fire boxes, soot blowing, process
modification, or adjustment or occasional cleaning of control equipment.
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be presumed
since only natural gas is permitted to be used as fuel for this heater. The permittee shall maintain records
that verify that only natural gas is used as fuel.
3.7 Statewide Controls for Oil and Gas Operations
3.7.1 Colorado Regulation No. 7, Section XVI Requirements:
This heater is subject to the following requirements of Colorado Regulation No. 7, Section XVI,
"Control of Emissions from Stationary and Portable Combustion Equipment in the 8 -Hour Ozone
Control Area":
Exemptions
3.7.1.1 The following stationary combustion equipment are exempt fromthe emission
limitation requirements of Section XVI.D.4., the compliance demonstration
requirements in Section XVI.D.5., and the related recordkeeping and reporting
requirements of Sections XVI.D.7.a-f. and XVI.D.8, but these sources must maintain
any and all records necessary to demonstrate that an exemption applies (Condition
3.7.1.2a). These records must be maintained for a minimum of five years and made
available to the Division upon request. Qualifying for an exemption in this section does
not preclude the combustion process adjustment requirements of Section XVI.D.6.,
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
'Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 55
when required by XVI.D.6.a.
Once stationary combustion equipment no longer qualifies for any exemption, the
owner or operator must comply with the applicable requirements of this Section XVI.D.
as expeditiously as practicable but no later than 36 months after any exemption no
longer applies. Additionally, once stationary combustion equipment that is not
equipped with CEMS or CERMS no longer qualifies for any exemption, the owner or
operator must conduct a performance test using EPA test methods within 180 days and
notify the Division of the results and whether emission controls will be required to
comply with the emission limitations of Section XVI.D.4 (Colorado Regulation No. 7,
Section XVI.D.2.).
a. Any stationary combustion equipment with total uncontrolled actual emissions less
than 5 tpy NOx on a calendar year basis. (Colorado Regulation No. 7, Section
XVI.D.2.d.).
Recordkeeping
3.7.1.2 The following records must be kept for a period of five years and made available to the
Division upon request (Colorado Regulation No. 7, Section XVI.D.7.):
a. All sources qualifying for an exemption under Section XVI.D.2. (Condition
3.7.1.1) must maintain all records necessary to demonstrate that an exemption
applies (Colorado Regulation No. 7, Section XVI.D.7.g.).
3.8 40 CFR Part 60 Subpart A General Provisions
[State -Only Enforceable]: This heater is subject to the requirements in Colorado Regulation No. 6, Part
B, Section I.A. Specifically, this unit is subject to the following requirements:
3.8.1 No owner or operator subject to the provisions of this part shall build, erect, install, or use any
article,machine, equipment or process, the use of which conceals an emission which would
otherwise constitute a violation of an applicable standard. Such concealment includes, but is not
limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a
standard which is based on the concentration of a pollutant in the gases discharged to the
atmosphere (§60.12, as adopted by reference in Colorado Regulation No. 6, Parts A, Subpart A
and B, Section I.A).
3.8.2 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall,
to the extent practicable, maintain and operate any affected facility including associated air
pollution control equipment in a manner consistent with good air pollution control practice for
minimizing emissions. Determination of whether acceptable operating and maintenance
procedures are being used will be based on information available to the Administrator which may
include, but is not limited to, monitoring results, opacity observations, review of operating and
maintenance procedures, and inspection of the source (§60.11(d), as adopted by reference in
Colorado Regulation No. 6, Parts A, Subparts A and B, Section I.A).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 56
3.8.3 Any owner or operator subject to the provisions of this part shall maintain records of the
occurrence and duration of any startup, shutdown, or malfunction in the operation of an affected
facility; any malfunction of the air pollution control equipment; or any periods during which a
continuous monitoring system or monitoring device is inoperative (§60.7(b), as adopted by
reference in Colorado Regulation No. 6, Parts A, Subparts A and B, Section I.A).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 57
4. P-138 — OPF, Inc. 30.7 MMBtu/hr Natural Gas Fired Hot Oil Heater, AIRS ID: 138
Parameter
Permit
Condition
Number
Limitations
Emission Factors
Monitoring
Method
Interval
Emission & Consumption Limits
NOx
CO
4.1
7.0 tons/year
50 lb/MMSCF
11.8 tons/year
84 lb/MMSCF
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
Particulate Matter
4.2
Fuel Restriction — Natural Gas Only
Natural Gas
Consumption
4.3
280.7 MMSCF/year
Fuel Meter
Recordkeeping
Monthly
Other Requirements
Fuel Gas Heat
Content
4.4
ASTM Methods
Semi -
Annually
Hours of
Operation
4.5
Opacity
4.6
Not to exceed 20% except as
provided below:
For Startup - Not to exceed
30%, for a period or periods
aggregating more than six (6)
minutes in any sixty (60)
consecutive minutes
Recordkeeping
Monthly
Fuel Restriction — Natural Gas Only
Statewide Controls
for Oil and Gas
Operations
4.7
See Condition 4.7
40 CFR 60
Subpart Dc NSPS
4.8
See Condition 4.8
40 CFR 60
Subpart A General
Provisions NSPS
4.9
4.1 NOx & CO Emission Limitations & Compliance Monitoring
See Condition 4.9
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from this heater shall not exceed the
limitations listed in Summary Table 4 above (Colorado Construction Permit 10WE1659). Compliance
with the emission limitations shall be monitored as follows:
4.1.1 Monthly emissions shall be calculated by the end of the subsequent month using the above
emission factors (from EPA's AP -42: Compilation of Emission Factors, Section 1.4 for Natural
Gas Combustion, Final Section, dated 7/98), and the monthly natural gas consumption, as required
by Condition 4.3, in the following equation:
Operating Permit 95OPWE055
First Issued: May 1, 2001
................ _ .................
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
Where:
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 58
lb MMSCF)
NOx or CO Emissions ( tons l _ EF MMSCF) X FR Fuel
( month
lmonth) (2000 Ibl
Unit Conversion
ton I
EF = Emission Factor, lb/MMSCF
FRFuet = Flow Rate of Fuel Gas, MMSCF/month
Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the
annual limitations. Each month, a new twelve month total shall be calculated using the previous
twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
4.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the methods required by Condition 14 and used in a twelve
month rolling total to monitor compliance with the facility -wide HAP emission limitations.
4.2 Particulate Matter Emission Limitations & Compliance Monitoring
Emissions of Particulate Matter (PM) from this heater shall not exceed the limitation required by Colorado
Regulation No. 1, Section III.A.1.b. The numeric PM limitation, for the purposes of Colorado Regulation
No. 1, Section III.A.1.b., was determined using the design heat rate (fuel input) for this heater in the
following equation:
PE ( lb MMBtu) = 0.5 x FI-° 26
Where:
PE ( lb l MMBtu) = Particulate Emission
Fl (MMBtu
) = Fuel Input
hr
In the absence of credible evidence to the contrary, compliance with the particulate matter emission limit
set forth in Colorado Regulation No. 1, Section III.A.1.b. shall be presumed since only natural gas is
permitted to be used as fuel for this heater. The permittee shall maintain records that verify that only
natural gas is used as fuel.
4.3 Natural Gas Consumption Limitations & Compliance Monitoring
Natural gas consumption shall not exceed the limitation listed in Summary Table 4 above (Colorado
Construction Permit 10WE1659). Compliance with the consumption limitation shall be monitored as
follows:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 59
4.3.1 Facility -wide natural gas consumption for each month shall be recorded using the existing fuel
meter. The facility -wide natural gas consumption shall be measured on the same day that run time
hours for this heater have been recorded in accordance with Condition 4.5.
4.3.2 Allocation of natural gas to this heater shall be determined using the following calculation:
Btu 1
MMSCF) HRHeater (month] MMSCF)
FCHeater ( month ) Btu l Btu Btu l X FCFacility ( month )
HREngine (month) + E HRHeater (month + E HROther (month)
Where:
HREngine (month) = BSFC (hp•hr) x Hours of Operation hr (month/ x Site Rated HP (hp)
Btu ) Btu hr l
HRHeater (month = Design Heat Rating ( hr ) x Hours o f Operation (month)
And:
FCHeater = Individual Heater Fuel Consumption, MMSCF/Month
HREngine = Individual Engine Heat Requirement, Btu/Month
HRHeater = Individual Heater Heat Requirement, Btu/Month
HRother = Other Users Heat Requirement, Btu/Month
FCFacility = Facility Wide Fuel Consumption (metered), MMSCF/Month
BSFC = Brake Specific Fuel Consumption, Btu/hp • hr
Monthly natural gas consumption from this heater shall be used in a twelve month rolling total to monitor
compliance with the annual limitation. Each month, a new twelve month total shall be calculated using
the previous twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
Monthly natural gas consumption from this heater shall be used to monitor compliance with the annual
NOx and CO emission limitations as required by Condition 4.1.
4.4 Fuel Gas Heat Content
The heat content of the natural gas used to fuel this heater shall be verified semi-annually, or once every
six months, using the appropriate ASTM Methods or equivalent, if approved in advance by the Division.
The heat content of the natural gas shall be based on the higher heating value (HHV) of the fuel. Results
of the heat content verification shall be retained and made available to the Division upon request.
4.5 Hours of Operation
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 60
Hours of operation of this heater shall be monitored and recorded monthly. Hours of operation shall be
recorded on the same day that the monthly facility -wide fuel gas consumption is measured. Monthly hours
of operation shall be used in a running total for each annual compliance period. Records shall be made
available for Division review upon request.
The hours of operation of this heater shall be used to monitor compliance with the annual fuel gas
consumption limitation, as required by Condition 4.3.
4.6 Opacity
The following opacity requirements apply to this heater:
4.6.1 Except as provided for in Condition 4.6.2 below, no owner or operator of a source shall allow or
cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity
(Colorado Regulation No. 1, Section II.A.1).
4.6.2 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air
pollutant resulting from the building of a new fire, cleaning of fire boxes, soot blowing, start-up,
process modifications, or adjustment or occasional cleaning of control equipment which is excess
of 30% opacity for a period or periods aggregating more than six (6) minutes in any sixty (60)
consecutive minutes (Colorado Regulation No. 1, Section II.A.4).
4.6.3 [State -Only Enforceable]: No owner or operator shall discharge, or cause the discharge, into the
atmosphere of any particulate matter which is greater than twenty percent (20%) opacity (Colorado
Regulation No. 6, Part B, Section II.C.3).
Note that this opacity standard applies at all times except during periods of startup, shutdown, and
malfunction (40 CFR Part 60, Subpart A, §60.11(c), as adopted by reference in Colorado
Regulation No. 6, Part B, Section I.A).
Note that this opacity requirement is more stringent than the opacity requirement in Condition
4.6.2 above during periods of fire building, cleaning of fire boxes, soot blowing, process
modification, or adjustment or occasional cleaning of control equipment.
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be presumed
since only natural gas is permitted to be used as fuel for this heater. The permittee shall maintain records
that verify that only natural gas is used as fuel.
4.7 Statewide Controls for Oil and Gas Operations
4.7.1 Colorado Regulation No. 7, Section XVI Requirements:
This heater is subject to the following requirements of Colorado Regulation No. 7, Section XVI,
"Control of Emissions from Stationary and Portable Combustion Equipment in the 8 -Hour Ozone
Control Area":
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 61
Conditions shown in italic text below represent monitoring, recordkeeping and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
Combustion Process Adjustment
4.7.1.1 As of January 1, 2017, this Section XVI.D.6.(Condition 4.7.1.2) applies to boilers, duct
burners, process heaters, stationary combustion turbines, and stationary reciprocating
internal combustion engines with uncontrolled actual emissions of NOx equal to or
greater than five (5) tons per year that existed at major sources of NOx as of June 3,
2016. (Colorado Regulation No. 7, Section XVI.D.6.a.).
4.7.1.2 Combustion Process Adjustment (Colorado Regulation No. 7, Section XVI.D.6.b.)
a. When burning the fuel that provides the majority of the heat input since the last
combustion process adjustment and when operating at a firing rate typical of normal
operation, the owner or operator must conduct the following inspections and
adjustments of boilers and process heaters, as applicable (Colorado Regulation No.
7, Section XVI.D.6.b.(i)):
(i) Inspect the burner and combustion controls and clean or replace components as
necessary (Colorado Regulation No. 7, Section XVI.D.6.b.(i)(A)).
(ii) Inspect the flame pattern and adjust the burner or combustion controls as
necessary to optimize the flame pattern (Colorado Regulation No. 7, Section
XVI.D.6.b.(i)(B)).
(iii)Inspect the system controlling the air -to -fuel ratio and ensure that it is correctly
calibrated and functioning properly (Colorado Regulation No. 7, Section
XVI.D.6.b.(i)(C)).
(iv)Measure the concentration in the effluent stream of carbon monoxide and
nitrogen oxide in ppm, by volume, before and after the adjustments in Sections
XVI.D.6.b.(i)(A) (Condition (i) above) through (C) (Condition (iii) above).
Measurements may be taken using a portable analyzer (Colorado Regulation
No. 7, Section XVI.6.b.(i)(D)).
b. The owner or operator must operate and maintain the boiler, duct burner, process
heater, stationary combustion turbine, or stationary internal combustion engine
consistent with manufacturer's specifications, if available, or good engineering and
maintenance practices (Colorado Regulation No. 7, Section XVI.D.6.b.(v)).
c. Frequency (Colorado Regulation No. 7, Section XVI.D.6.b.(vi))
(i) The owner or operator must conduct the initial combustion process adjustment
by April 1, 2017. An owner or operator may rely on a combustion process
adjustment conducted in accordance with applicable requirements and schedule
of a New Source Performance Standard in 40 CFR Part 60 or National Emission
Standard for Hazardous Air Pollutants in 40 CFR Part 63 to satisfy the
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 62
requirement to conduct an initial combustion process adjustment by April 1,
2017 (Colorado Regulation No. 7, Section XVI.D.6.b.(vi)(A)).
(ii) The owner or operator must conduct subsequent combustion process
adjustments at least once every twelve (12) months after the initial combustion
adjustment, or on the applicable schedule according to Sections XVI.D.6.c.(i).
(Condition 4.7.1.3a) or XVI.D.6.c.(ii). (Condition 4.7.1.3b) (Colorado
Regulation No. 7, Section XVI.D.6.b.(vi)(B)).
Alternative Requirements
4.7.1.3 As an alternative to the requirements described in Sections XVI.D.6.b.(i) (Condition
4.7.1.2a) and XVI.D.6.b.(v) (Condition 4.7.1.2b) (Colorado Regulation No. 7, Section
XVI.D.6.c.):
a. The owner or operator may conduct the combustion process adjustment according
to the manufacturer recommended procedures and schedule (Colorado Regulation
No. 7, Section XVI.D.6.c.(i)); or
b. The owner or operator of combustion equipment that is subject to and required to
conduct a period tune-up or combustion adjustment by the applicable requirements
of a New Source Performance Standard in 40 CFR Part 60 or National Emission
Standard for Hazardous Air Pollutants in 40 CFR Part 63 may conduct tune-ups or
adjustments according to the schedule and procedures of the applicable
requirements of 40 CFR Part 60 or 40 CFR Part 63 (Colorado Regulation No. 7,
Section XVI.D.6.c.(ii)).
Recordkeeping
4.7.1.4 Recordkeeping. The following records must be kept for a period of five years and made
available to the Division upon request (Colorado Regulation No. 7, Section XVI.D.7.):
a. For stationary combustion equipment subject to the combustion process adjustment
requirements in Section XVI.D.6. (Condition 4.7.1.2), the following recordkeeping
requirements apply (Colorado Regulation No. 7, Section XVI.D.7.f):
(i) The owner or operator must create a record once every calendar year identifying
the combustion equipment at the source subject to Section XVI.D. (Condition
4.7.1.1) and including for each combustion equipment (Colorado Regulation
No. 7, Section XVI.D.7.(f).(i)):
(A) The date of the adjustment (Colorado Regulation No. 7, Section
XVI.D.7.f.(i)(A));
(B) Whether the combustion process adjustment under Sections
XVI.D.6.b.(i) (Condition 4.7.1.2a) and XVI.D.6.b.(v) (Condition
4.7.1.2b). was followed, and what procedures were performed
(Colorado Regulation No. 7, Section XVI.D.7.f.(i)(B));
(C) Whether a combustion process adjustment under Sections
XVI.D.6.a. (Condition 4.7.1.1) and XVI.D.6.b. (Condition 4.7.1.2).
was followed, what procedures were performed, and what New
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 63
Source Performance or National Emission Standard for Hazardous
Air Pollutants applied, if any (Colorado Regulation No. 7, Section
XVI.D.7.f.(i)(C)); and
(D) A description of any corrective action taken (Colorado Regulation
No. 7, Section XVI.D.7.f.(i)(D)).
(E) If the owner or operator conducts the combustion process
adjustment according to the manufacturer recommended procedures
and schedule and the manufacturer specifies a combustion process
adjustment on an operation time schedule, the hours of operation.
(Colorado Regulation No. 7, Section XVI.D.7.f.(i)(E)).
(F) [Additional Recordkeeping: If the owner or operator conducts an
alternative combustion process adjustment under Section
XVI.D.6.c. (Condition 4.7.1.3), the owner or operator shall
document that these requirements were followed, what procedures
were performed, and what New Source Performance or National
Emission Standard for Hazardous Air Pollutants applied, if any.]
(ii) The owner or operator must retain manufacturer recommended procedures,
specifications, and maintenance schedule if utilized under Section XVI.D.6.a.
(Condition 4.7.1.1) for the life of the equipment (Colorado Regulation No. 7,
Section XVI.D.7.f.(ii)).
(iii)As an alternative to the requirements described in Section XVI.D.7.f.(i)
(Condition (i) above), the owner or operator may comply with applicable
recordkeeping requirements related to combustion process adjustments
conducted according to a New Source Performance Standard in 40 CFR Part 60
or National Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63
(Colorado Regulation No. 7, Section XVI.D.7.f.(iii)).
4.8 40 CFR Part 60, Subpart Dc NSPS
This heater is subject to the New Source Performance Standards requirements of Colorado Regulation No.
6, Part A, Subpart Dc (40 CFR Part 60, Subpart Dc) "Standards of Performance for Small Industrial -
Commercial -Institutional Steam Generating Units", including, but not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
Dc published in the Federal Register on February 16, 2012. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 60 Subpart Dc.
Reporting and Recordkeeping Requirements
4.8.1 Except as provided under paragraphs (g)(2) of this section, the owner or operator of each affected
facility shall record and maintain records of the amount of each fuel combusted during each
operating day '(§60.48c(g)(1)).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 64
4.8.2 As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or
operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification
in §60.48c(f) to demonstrate compliance with the SO2 standard, fuels not subject to an emissions
standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records
of the amount of each fuel combusted during each calendar month (§60.48c(g)(2)).
4.9 40 CFR Part 60, Subpart A NSPS
This heater is subject to the requirements in 40 CFR Part 60 Subpart A "General Provisions", as adopted
by reference in Colorado Regulation No. 6, Part A, Subpart A as specified in 40 CFR Part 60 Subpart Dc.
These requirements include, but are not- limited to the following:
4.9.1 Notification and recordkeeping (§60.7)
4.9.2 Compliance with standards and maintenance requirements (§60.11)
4.9.3 Circumvention (§60.12)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 65
5. P033 — Custom 4 MMSCFD Triethylene Glycol Dehydration Unit, AIRS ID: 130
P-136 — Evco Fabrication 85 MMSCFD Triethylene Glycol Dehydration Unit, AIRS ID: 136
Parameter
Permit
Condition
Number
Limitations
P033
P-136
Emission
Factor
Monitoring
Method
Interval
Emission & Throughput Limits'
VOC
5.1
1.1 tons/year
23.7 tons/year
ProMax or
GLYCaIc 4.0
or higher
Process Simulation and
Twelve Month Rolling
Total Calculation
Monthly
NOx
CO
5.2
See Condition 12.1
NOx: 0:068
lb/MIv1Btu
CO: 0.31
lb/MMBtu
Process Simulation and
Twelve Month Rolling
Total Calculation
Monthly
Wet Gas
Throughput
Limitations
5.3
Total:
1,460 MMSCF/year
Uncontrolled:
Not to exceed 2% of
total
Total:
31,025 MMSCF/year
Uncontrolled:
Not to exceed 2% of
total
Lean Glycol
Circulation
Rate
5.4
3.5 gpm
24 gpm
Unit Inlet Meter and
Twelve Month Rolling
Total Calculation
Monthly
See Condition 5.4
Daily
Other Requirements'
Extended Gas
Analysis of
Inlet Wet Gas
5.5
Parametric
Monitoring
5.6
Hours of
Operation
5.7
Still Vent
Emissions
Routing
5.8
P-136 Only:
See Condition 5.9
ASTM Methods or
Equivalent
Annually
Recordkeeping
Weekly
Recordkeeping &
Calculation
Monthly
Recordkeeping
Daily
Compliance
Assurance
Monitoring
(CAM)
5.9
Statewide
Controls for
Oil and Gas
Operations
5.10
See Condition 5.10
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 66
40 CFR 63
Subpart HET
NESHAP
5.11
40 CFR 63
Subpart A
General
Provisions
NESHAP
5.12
Lopt
OR
< 1,984 lb/year benzene or
< 3 MMSCF/day wet gas
See Condition 5.11
See Condition 5.12
'Emission & Consumption Limits and Other Requirements apply to each glycol dehydration unit individually
5.1 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) for each dehydration unit shall not exceed the
limitations listed in Summary Table 5 above (Colorado Construction Permits 01WE0208 and 10WE1659,
as modified under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part C,
Section I.A.7 and Part C, Section III.B.7, based on requested emissions identified on the APEN submitted
on 7/10/2017 for P033 and 11/13/2017 for P-136). Compliance with the emission limitations shall be
monitored as follows:
5.1.1 Monthly determination of VOC and HAP emissions shall be conducted by the end of the
subsequent month utilizing the Gas Research Institute's GLYCaic (Version 4.0 or higher) or Bryan
Research and Engineering's ProMax (Colorado Construction Permits 01 WE0208 and
10WE1659).
5.1.1.1 The following parameters shall be input to the process model:
a. The inlet wet gas composition obtained from the most recent extended gas analysis,
as required by Condition 5.5.
b. The average daily inlet wet gas throughput, as required by Condition 5.3.
c. The average monthly value of the inlet wet gas temperature and pressure, the flash
tank operating temperature and pressure and the lean glycol circulation rate, as
required by Conditions 5.4 and 5.6.
5.1.1.2 Control Efficiencies
a. A control efficiency (CE) of 95% shall apply to the enclosed combustion device
(ECD) when it is operational and still vent emissions from either dehydration unit
are routed to it, provided the requirements of Conditions 12.6.1 and 12.8 are met.
b. P-136 only: A control efficiency (CE) of 97% shall apply to the regenerative
thermal oxidizer (RTO) when it is operational and still vent emissions from P-136
are routed it, provided the requirements of Conditions 12.6.2 and 12.8 are met.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 67
c. A control efficiency (CE) of 0% shall apply to still vent emissions during periods
of ECD downtime when still vent emissions from either dehydration unit are routed
to atmosphere.
5.1.1.3 Operating Scenario Hours
a. Controlled hours of operation (as required by Condition 5.7.2) for each
dehydration unit shall be input to the equation below, along with the
corresponding control efficiency (CE) of 95% for the ECD (or, for P-136 only,
97% for the RTO), to determine actual emissions of VOC and HAP for the periods
during which still vent emissions were routed to the ECD (and/or, for P-136 only,
the RTO).
b. Uncontrolled hours of operation (as required by Condition 5.7.3) for each
dehydration unit shall be input to the equation below, along with the
corresponding control efficiency (CE) of 0%, to determine actual emissions of
VOC and HAP for the periods of ECD downtime, during which still vent emissions
were routed to atmosphere.
c Actual emissions of VOC and HAP for each month shall be the sum total of
emissions destructed during ECD operation (and/or, for P-136 only, RTO
operation) during controlled hours of operation, and emissions routed to
atmosphere during ECD downtime during uncontrolled hours of operation.
5.1.1.4 Monthly emissions of VOC and HAP shall be monitored using the following equation:
(lb hrs ( CEO (%)1
tons l SVVOC/xAP U27.)x OH (month x 1 100 )
VOC or HAP Emissions (month/ �(2000 lb\
Operating Unit Conversion l ton 1
Scenario
Where:
SVvoc/HAP = Uncontrolled Still Vent Emissions of VOC or HAP, lb/hr
OH = Operating Scenario Hours of Still Vent to ECD, RTO (P — 136 only) or Atmosphere, hrs/month
CEsv = Control Efficiency of Still Vent to ECD, RTO (P — 136 only) or Atmosphere,
The monthly VOC emissions obtained from this calculation shall be used in a twelve month rolling
total to monitor compliance with the annual limitations. Each month, a new twelve month total
shall be calculated using the previous twelve months' data. Records of calculations shall be
maintained and made available to the Division upon request.
5.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the same method as indicated above for VOC and used in a
twelve month rolling total to monitor compliance with the facility -wide HAP emission limitations.
5.2 NOx & CO Emission Limitations & Compliance Monitoring
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 68
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) generated by the destruction of still
vent emissions from each dehydration unit via the ECD (or, for P-136 only, the RTO) shall not exceed
the limitations listed in Summary Table 12 below (Colorado Construction Permit 10WE1659, as modified
under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part C, Section I.A.7 and
Part C, Section III.B.7, based on requested emissions identified on the APEN submitted on 11/13/2017
for P-136). Compliance with the emission limitation shall be monitored as follows:
5.2.1 Monthly emissions shall be calculated by the end of the subsequent month using the emission
factors listed above (from EPA's. AP -42: Compilation of Emission Factors, Section 13.5 for
Industrial Flares, Final Section, dated 12/16), the hourly still vent (SV) flowrate and still vent (SV)
heat content obtained from the most recent monthly process model run (as required by Condition
5.1) and the total monthly controlled hours of operation for each dehydration unit (as required by
Condition 5.7.2) as inputs to the equation below.
(MA hrs MMBtu lb
NOx or CO Emissions (month
SV Flowrate hr ) x Controlled Hours month) x SV Heat Content (M ) x Emission Factor (MMBtu)
\month Unit Conversion (2000 lb)
\ ton
Monthly emissions of NOx and CO as calculated above shall be used to monitor compliance with the
annual limitations set forth in Condition 12.1.
5.3 Wet Gas Throughput Limitations & Compliance Monitoring
5.3.1 Total Wet Gas Throughput: The total amount of wet gas processed by each dehydration unit
shall not exceed the limitations listed in Summary Table 5 above (Colorado Construction Permits
01 WE0208 and l OWE 1659). The gas throughput to each dehydration unit shall be monitored and
recorded monthly using a dedicated flowmeter located at the inlet to each unit. The monthly wet
gas throughput shall be used in a twelve month rolling total to monitor compliance with the annual
limitations. Each month, a new twelve month total shall be calculated using the previous twelve
months' data. Records of calculations shall be maintained and made available to the Division upon
request.
An average daily gas throughput rate shall be used as an input to the monthly process model runs,
as required by Condition 5.1. This average daily gas throughput rate shall be calculated for each
dehydration unit by dividing the total monthly wet gas throughput by the total unit hours of
operation (as required by Condition 5.7.1) as follows:
MMSCF Total Monthly Gas Throughput month x Unit Conversion (2days)
Average Daily Gas Throughput
day Total Hours of Operation hrs
(month)
5.3.2 Uncontrolled Wet Gas Throughput: The amount of wet gas processed by each dehydration
unit during periods of ECD downtime shall not exceed 2% of the total wet gas throughput to each
dehydration unit (as required by Condition 5.3.1, above) on a rolling twelve month basis (as
provided for under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part
C, Section I.A.7 and Part C, Section III.B.7 based on requested limitations identified on the APEN
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 69
submitted on 7/10/2017 for P033 and 11/13/2017 for P-136). ECD downtime is defined as periods
when either dehydration unit is operating and still vent emissions from that dehydration unit are
routed to atmosphere instead of to the ECD (or, for P-136 only, the RTO). The wet gas throughput
to each dehydration unit during periods of ECD downtime shall be monitored using the existing
meters located at the inlet of each dehydration unit in conjunction with the still vent emissions
routing records (as required by Condition 5.8). Uncontrolled throughput shall be determined as the
total amount of inlet wet gas sent to either dehydration unit, as indicated by each inlet meter, during
periods for which still vent emissions were routed to atmosphere, as indicated by the control valve
positioning.
The monthly uncontrolled wet gas throughput shall be used in a twelve month rolling total to
monitor compliance with the annual limitations. Each month, a new twelve month total shall be
calculated using the previous twelve months' data. Records of calculations shall be maintained
and made available to the Division upon request.
5.4 Lean Glycol Circulation Rate Limitations & Compliance Monitoring
The circulation rate of lean glycol for each dehydration unit shall not exceed the limitations listed in
Summary Table 5 above (Colorado Construction Permits 01WE0208 and 10WE1659). The lean glycol
circulation rate shall be recorded daily and obtained using the methods outlined below:
5.4.1 P033 only: The lean glycol flowrate shall be calculated by recording the pump strokes per minute
and using manufacturer correlations to convert this parameter into the lean glycol flowrate in
gallons per minute. Records of the pump make/model and strokes per minute/circulation rate
relationship shall be made available to the Division upon request.
5.4.2 P-136 only: The lean glycol flowrate shall be recorded using the existing glycol flowmeter. The
recorded flowrate shall be the sum of the flowrate from each pump.
Records of the daily lean glycol circulation rate shall be maintained and made available to the Division
upon request.
A monthly average of the lean glycol circulation rate shall be calculated from the daily recorded values
from that month for each dehydration unit. These monthly averages shall be used as inputs to the monthly
process model runs, as required by Condition 5.1.
5.5 Extended Gas Analysis of Inlet Wet Gas
An extended gas analysis of the inlet wet gas to each dehydration unit shall be performed annually
according to appropriate ASTM methods, or equivalent, if approved in advance by the Division (Colorado
Construction Permit 01WE0208 and 10WE1659). The extended analysis shall identify the relevant VOC
and HAP constituents of the wet gas, including any BTEX components. Results of the wet gas analysis
shall be retained and made available to the Division upon request.
The composition indicated by the most recent extended wet gas analysis shall be used in the monthly
process model run, as required by Condition 5.1.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
5.6 Parametric Monitoring
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 70
The following operating parameters for each dehydration unit shall be monitored and recorded at the
intervals specified in the table below. Values of the parameters monitored shall be representative of the
unit's operation for the duration of the monitoring period. Records of the values recorded shall be
maintained and made available to the Division upon request.
Parameter
Monitoring Frequency
Inlet Wet Gas Temperature
Weekly
Inlet Wet Gas Pressure
Weekly
Flash Tank Operating Temperature
Weekly
Flash Tank Operating Pressure
Weekly
Monthly averages of each parameter shall be obtained by averaging the operating values recorded for that
month. These monthly averages shall be used as inputs to the monthly process model run, as required by
Condition 5.1 (Colorado Construction Permits 01 WE0208 and 10WE1659).
5.7 Hours of Operation
5.7.1 Total Hours of Operation: Hours of operation for each dehydration unit shall be monitored and
recorded monthly in a log that is to be made available to the Division upon request. Monthly hours
of operation shall be used to determine the average daily gas throughput, as required by Condition
5.3.1.
5.7.2 Controlled Hours of Operation: Hours of operation during which either dehydration unit is
operating and still vent emissions are routed to the ECD (or, for P-136 only, the RTO) shall be
determined as follows:
5.7.2.1 P033: Hours of operation during which P033 was controlled by the ECD shall be
determined monthly using the still vent emissions routing records for P033, as required
by Condition 5.8.1. Controlled hours of operation shall be defined as times that P033
was operating and still vent emissions from P033 were routed to the ECD, as indicated
by records of the daily valve alignment visual inspection.
5.7.2.2 P-136: Hours of operation during which P-136 was controlled by either the ECD or
RTO shall be determined monthly using the still vent emissions routing records for P-
136, as required by Condition 5.8.2. Controlled hours of operation shall be defined as
times during which P-136 was operating and still vent emissions from P-136 were
routed to either the ECD or RTO, as indicated by control valve positioning records.
Controlled hours of operation shall be used to determine the length of time for which the control
efficiencies of the ECD (and/or, for P-136 only, the RTO) are applicable, as required by Condition
5.1.1.3, in order to monitor compliance with the VOC and HAP emission limitations for each
dehydration unit, and to monitor compliance with the NOx and CO emission limitations for the
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 71
ECD (and/or, for P-136 only, the RTO), as required by Condition 5.2.
5.7.3 Uncontrolled Hours of Operation: Hours of operation during which still vent emissions from
either dehydration unit are routed to atmosphere during ECD downtime shall be determined as
follows:
5.7.3.1 P033: Hours of operation during which the still vent emissions from P033 were routed
to atmosphere shall be determined monthly using the still vent emissions routing
records for P033, as required by Condition 5.8.1. Uncontrolled hours of operation shall
be defined as times that P033 was operating and still vent emissions from P033 were
routed to atmosphere, as indicated by records of the daily valve alignment visual
inspection.
5.7.3.2 P-136: Hours of operation during which the still vent emissions from P-136 were
routed to atmosphere shall be determined monthly using the still vent emissions routing
records for P-136, as required by Condition 5.8.2. Uncontrolled hours of operation shall
be defined as times that P-136 was operating and still vent emissions from P-136 were
routed to atmosphere, as indicated by control valve positioning records.
Uncontrolled hours of operation shall be used to determine the length of time for which each
dehydration unit still vent was routed to atmosphere, during which a control efficiency of 0% is
applicable, as required by Condition 5.1.1.3, in order to monitor compliance with the VOC and
HAP emission limitations for each dehydration unit.
5.8 Still Vent Emissions Routing
5.8.1 P033: The routing of still vent emissions from P033 to either the ECD or atmosphere shall be
monitored and recorded daily in a log to be made available to the Division upon request. This
record shall indicate the date and time at which each new routing configuration commences. Daily
visual inspections of the valve alignment shall be used to determine the routing configuration and
duration for which that routing configuration is applicable.
The length of time for which each routing configuration was applicable shall be used to determine
both controlled and uncontrolled hours of operation for P033, as required by Condition 5.7, and to
monitor compliance with the uncontrolled throughput limitations, as required by Condition 5.3.2.
5.8.2 P-136: The routing of still vent emissions from P-136 to the ECD, RTO or atmosphere shall be
monitored and recorded daily in a log to be made available to the Division upon request. This
record shall indicate the date and time at which each new routing configuration commences. Valve
position indicators shall be used to determine the routing configuration and the duration for which
that routing configuration is applicable.
The length of time for which each routing configuration was applicable shall be used to determine
both the controlled and uncontrolled hours of operation for P-136, as required by Condition 5.7,
and to monitor compliance with the uncontrolled throughput limitations, as required by Condition
5.3.2. Additionally, the routing configuration shall be used to determine the applicable Colorado
Regulation No. 7 requirements for the RTO, as required by Condition 12.8.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
5.9 Compliance Assurance Monitoring (CAM)
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 72
P-136 only: This dehydration unit is subject to the Compliance Assurance Monitoring (CAM)
requirements with respect to the annual emission limitations in Condition 5.1 for VOC and Condition 14.1
for HAP. Compliance with the CAM requirements shall be monitored in accordance with the requirements
in Condition 16 and the CAM Plan in Appendix H.
5.10 Statewide Controls for Oil and Gas Operations
5.10.1 Colorado Regulation No. 7, Section XII.H. Requirements:
Each dehydration unit is subject to the following "Emission Reductions from Glycol Natural
Gas Dehydrators" of Colorado Regulation No. 7, Section XII, "Volatile Organic Compound
Emissions from Oil and Gas Operations":
Conditions shown in italic text below represent monitoring, recordkeeping and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
Section XII Control Requirements
5.10.1.1
Beginning May 1, 2005, 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 the 8 -
Hour Ozone Control Area and subject to control requirements pursuant to Section
XII.H.3. (Condition 5.10.1.2), 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 (Colorado Regulation No. 7,
Section XII.H.1.).
[Compliance Demonstration: In absence of credible evidence to the contrary,
compliance with the VOC reduction requirements of Condition 5.10.1.1 shall be
presumed as long as the control device requirements in Conditions 12.6 and 12.8.2 are
met.]
5.10.1.2 The control requirements of Sections XII.H.1. (Condition 5.10.1.1) apply where:
a. Actual uncontrolled emissions of volatile organic compounds from the glycol
natural gas dehydrator are equal to or greater than one ton per year (Colorado
Regulation No. 7, Section XII.H.3.a.); and
b. The sum of actual uncontrolled emissions of volatile organic compounds from any
single glycol natural gas dehydrator or grouping of glycol natural gas dehydrators
at a single stationary source is equal to or greater than 15 tons per year. To
determine if a grouping of dehydrators meets or exceeds the 15 tons per year
threshold, sum the total actual uncontrolled emissions of volatile organic
compounds from all individual dehydrators at the stationary source, including those
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 73
with emissions less than one ton per year (Colorado Regulation No. 7, Section
XII.H.3.b.).
5.10.1.3 For purposes of Section XII.H. (Condition 5.10.1), emissions from still vents and vents
from any flash separator or flash tank on a glycol natural gas dehydrator shall be
calculated using a method approved in advance by the Division (Colorado Regulation
No. 7, Section XII.H.4.).
Section XII Monitoring and Recordkeeping Requirements
5.10.1.4 [Additional Monitoring: The owner or operator shall maintain current records of
uncontrolled actual emissions on a rolling twelve month basis for each glycol
dehydrator. Such records shall be used to determine whether the control requirements
in Condition 5.10.1.1 apply. Such records shall be maintained and made available for
the Division upon request.
Dehydrators that are not subject to the control requirements in Condition 5.10.1.1 that
increase uncontrolled actual emissions from the dehydrator and/or group of
dehydrators at the facility above the thresholds listed in Conditions 5.10.1.2a and/or
5.10.1.2b shall comply with the control requirements of Condition 5.10.1.1 within 60
days of discovery of the emission increase.]
5.10.1.5 Monitoring and Recordkeeping (Colorado Regulation No. 7, Section XII.H.5.)
a. Beginning January 1, 2017, owners or operators of glycol natural gas dehydrators
subject to the control requirements of Sections XII.H.1. (Condition 5.10.1.1) must
check on a weekly basis that any condenser or air pollution control equipment used
to control emissions of volatile organic compounds is operating properly (Colorado
Regulation No. 7, Section XII.H.5.a.), and document:
(i) The date of each inspection (Colorado Regulation No. 7, Section XII.H.5.a.(i));
(ii) A description of any problems observed during the inspection of the condenser
or air pollution control equipment (Colorado Regulation No. 7, Section
XII.H.5.a.(ii)); and
(iii)A description and date of any corrective actions taken to address problems
observed during the inspection of the condenser or air pollution control
equipment (Colorado Regulation No. 7, Section XII.H.5.a.(iii)).
b. The owner or operator must check and document on a weekly basis that the pilot
light on a combustion device is lit, that the valves for piping of gas to the pilot light
are open, and visually check for the presence or absence of smoke (Colorado
Regulation No. 7, Section XII.H.5.b.).
c. The owner or operator must document the maintenance of the condenser or air
pollution control equipment, consistent with manufacturer specifications or good
engineering and maintenance practices (Colorado Regulation No. 7, Section
XII.H.5.c.).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 74
d. The owner or operator must retain records for a period of five years and make these
records available to the Division upon request (Colorado Regulation No. 7, Section
XII.H.5.d.).
Section XII Reporting Requirements
5.10.1.6 On or before November 30, 2017, and semi-annually by April 30 and November 30 of
each year thereafter, the owner or operator must submit the following information for
the preceding calendar year (April 30 report) and for May 1 through September 30
(November 30 report) using Division -approved format (Colorado Regulation No. 7,
Section XII.H.6.a.)
a. A list of the glycol natural gas dehydrator(s) subject to Section XII.H (Colorado
Regulation No. 7, Section XII.H.6.a.(i));
b. A list of the condenser or air pollution control equipment used to control emissions
of volatile organic compounds from the glycol natural gas dehydrator(s) (Colorado
Regulation No. 7, Section XII.H.6.a.(ii)); and
c. The date(s) of inspection(s) where the condenser or air pollution control equipment
was found not operating properly or where smoke was observed (Colorado
Regulation No. 7, Section XII.H.6.a.(iii)).
5.10.2 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.B. Requirements
Each dehydration unit is subject to the following State -Only Enforceable "General Provisions"
of Colorado Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas Operations and
Natural Gas -Fired Reciprocating Internal Combustion Engines":
Section XVII General Requirements
5.10.2.1 All intermediate hydrocarbon liquids collection, storage, processing, and handling
operations, regardless of size, shall be designed, operated, and maintained so as to
minimize leakage of VOCs and other hydrocarbons to the atmosphere to the extent
reasonably practicable (Colorado Regulation No. 7, Section XVII.B.1.a.).
5.10.2.2 At all times, including periods of start-up and shutdown, the facility and air pollution
control equipment must be maintained and operated in a manner consistent with good
air pollution control practices for minimizing emissions. Determination of whether or
not acceptable operation and maintenance procedures are being used will be based on
information available to the Division, which may include, but is not limited to,
monitoring results, opacity observations, review of operation and maintenance
procedures, and inspection of the source (Colorado Regulation No. 7, Section
XVII.B .1.b.).
5.10.3 -[State-Only Enforceable] Colorado Regulation No. 7, Section XVII.D. Requirements:
Each dehydration unit is subject to the following State -Only Enforceable "Emission Reductions
from Glycol Natural Gas Dehydrators" of Colorado Regulation No. 7, Section XVII, "Statewide
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 75
Controls for Oil. and Gas Operations and Natural Gas -Fired Reciprocating Internal Combustion
Engines":
Conditions shown in italic text below represent monitoring, recordkeeping and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
Section XVII Control Requirements
5.10.3.1
Beginning May 1, 2008, 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 XVILD.2. (Condition 5.10.3.2), shall reduce
uncontrolled actual emissions of volatile organic compounds by at least 90 percent
through the use of a condenser or air pollution control equipment (Colorado Regulation
No. 7, Section XVII.D.1.).
[Compliance Demonstration: In absence of credible evidence to the contrary,
compliance with the requirements VOC reduction requirements of Condition 5.10.3.1
shall be presumed as long as the control device requirements in Conditions 12.6 and
12.8.3 are met.]
5.10.3.2 The control requirements in Section XVII.D.1. (Condition 5.10.3.1) apply where:
a. Actual uncontrolled emissions of volatile organic compounds from the glycol
natural gas dehydrator are equal to or greater than two tons per year; and (Colorado
Regulation No. 7, Section XVII.D.2.a.)
b. The sum of actual uncontrolled emissions of volatile organic compounds from any
single glycol natural gas dehydrator or grouping of glycol natural gas dehydrators
at a single stationary source is equal to or greater than 15 tons per year. To
determine if a grouping of dehydrators meets or exceeds the 15 tons per year
threshold, sum the total actual uncontrolled emissions of volatile organic
compounds from all individual dehydrators at the stationary source, including those
with emissions less than two tons per year (Colorado Regulation No. 7, Section
XVII.D .2.b.).
5.10.3.3 Beginning May 1, 2015, still vents and vents from any flash separator or flash tank on
a glycol natural gas dehydrator located at an oil and gas exploration and production
operation, natural gas compressor station, or gas -processing plant subject to control
requirements pursuant to Section XVII.D.4. (Condition 5.10.3.4), 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
(Colorado Regulation No. 7, Section XVII.D.3.).
[Compliance Demonstration: In absence of credible evidence to the contrary,
compliance with the hydrocarbon reduction requirements of Condition 5.10.3.3 shall
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 76
be presumed as long as the control device requirements in Conditions 12.6 and 12.8.3
are met.]
If a combustion device is used (to meet the requirements of Condition 5.10.3.3), it shall
have a design destruction efficiency of at least 98% for hydrocarbons except where:
a. The combustion device has been authorized by permit prior to May 1, 2014; and
(Colorado Regulation No. 7, Section XVII.D.3.a.).
b. A building unit or designated outside activity area (as defined in Section
XVII.D.4.c.) is not located within 1,320 feet of the facility at which the natural gas
glycol dehydrator is located. (Colorado Regulation No. 7, Section XVII.D.3.b.).
[Compliance Demonstration: In absence of credible evidence to the contrary,
compliance with the design destruction efficiency requirements of Condition 5.10.3.3
shall be presumed as long as the requirements in Conditions 5.10.3.6 and 5.10.3.7 are
met.]
5.10.3.4 The control requirements in Section XVII.D.3. (Condition 5.10.3.3) apply where:
a. Uncontrolled actual emissions of VOCs from a single glycol natural gas dehydrator
constructed before May 1, 2015, are equal to or greater than (Colorado Regulation
No. 7, Section XVII.D.4.b.):
(i) six (6) tons per year, or
(ii) two (2) tons per year if the glycol natural gas dehydrator is located within 1,320
feet of a building unit or designated outside activity area (as defined in Section
XVII.D.4.c.).
Section XVII Recordkeeping Requirements
5.10.3.5 [Additional Monitoring: The owner or operator shall maintain current records of
uncontrolled actual emissions on a rolling twelve month basis for each glycol
dehydrator. Such records shall be used to determine whether the control requirements
in either Conditions 5.10.3.1 or 5.10.3.3 apply. Such records shall be maintained and
made available for the Division upon request.
Dehydrators that are not subject to the control requirements in Conditions 5.10.3.1 or
5.10.3.3 that increase uncontrolled actual emissions from the dehydrator and/or group
of dehydrators at the facility above the thresholds listed in Conditions 5.10.3.2 and/or
5.10.3.4 shall comply with the control requirements of Conditions 5.10.3.1 and/or
5.10.3.3 within 60 days of discovery of the emission increase.]
5.10.3.6
[Additional Monitoring: If the owner or operator is claiming an exemption from the
control requirements of Condition 5.10.3.3 based on the location of the facility, the
owner or operator shall maintain records that document whether the facility is located
within 1, 320 feet of a residential building unit or designated outside activity area. Such
records shall be reviewed annually and updated if necessary, and made available to
Operating Permit 95OPWE055 First Issued: May 1, 2001
............._.________._._..
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 77
the Division upon request.
Dehydrators that are not subject to the control requirements in Condition 5.10.3.3 that
become subject based on additions of or changes to residential building units or
designated outside activity areas shall comply with the control requirements of
Condition 5.10.3.3 within 60 days of discovery of the changes.]
5.10.3.7 [Compliance Demonstration: The owner or operator shall maintain records that
document the design efficiency of the combustion device used to meet the requirements
of Condition 5.10.3.3. Such records shall be maintained and made available for
Division review.]
5.11 40 CFR Part 63, Subpart HH, NESHAP
Each dehydration unit is subject to the National Emission Standards for Hazardous Air Pollutants
requirements of Colorado Regulation No. 8, Part E, Subpart HH (40 CFR Part 63, Subpart HH) "National
Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities",
including, but not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 63 Subpart
HH published in the Federal Register on August 16, 2012. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 63 Subpart HH.
Affirmative Defense for Violations of Emission Standards during Malfunction
5.11.1 The provisions set forth in this subpart shall apply at all times (§63.762(a)).
General Standards
5.11.2 Except as specified in paragraph (e)(1) (Condition 5.11.3.1) of this section, the owner or
operator of an affected source located at an existing or new area source of HAP emissions shall
comply with the applicable standards specified in paragraph (d) (Condition 5.11.2.1) of this section
(§63.764(d)).
5.11.2.1 Each Owner or operator of an area source not located in a UA plus offset and UC
boundary (as defined in §63.761) shall comply with paragraphs (d)(2)(i) through (iii)
(Conditions a through c, below) of this section (§63.764(d)(2)).
a. Determine the optimum glycol circulation rate using the following equation
(§63.764(d)(2)(i)):
( gal TEG\ F x (I — 0)
Lopr = 1.15 x 3.0 lb H2O J x 24 hr/day
Where:
LOPT = Optimalcirculation rate, gal/hr
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 78
F = Gas flowrate (MMSCF/D)
I = Inlet water content (lb/MMSCF)
0 = Outlet water content (lb/MMSCF)
3.0 = The industry accepted rule of thumb for a TEG to water ratio (gal TEG/lb H20)
1.15 =Adjustment factor included for a margin of safety
b. Operate the TEG dehydration unit such that the actual glycol circulation rate does
not exceed the optimum glycol circulation rate determined in accordance with
paragraph (d)(2)(i) (Condition a, above) of this section. If the TEG dehydration unit
is unable to meet the sales gas specification for moisture content using the glycol
circulation rate determined in accordance with paragraph (d)(2)(i) (Condition a,
above), the owner or operator must calculate an alternate circulation rate using GRI-
GLYCalcTM, Version 3.0 or higher. The owner or operator must document why
the LEG dehydration unit must be operated using the alternate circulation rate and
submit this documentation with the initial notification in accordance with
§63.775(c)(7) of this subpart (§63.764(d)(2)(ii)).
c. Maintain a record of the determination specified in paragraph (d)(2)(ii) (Condition
b, above) in accordance with the requirements in §63.774(f) (Condition 5.11.8) and
submit the Initial Notification in accordance . with the requirements in
§63.775(c)(7). If operating conditions change and a modification to the optimum
glycol circulation rate is required, the owner or operator shall prepare a new
determination in accordance with paragraph (d)(2)(i) (Condition a, above) or (ii)
(Condition b, above) of this section and submit the information specified under
§63.775(c)(7)(ii) through (v) of this subpart (§63.764(d)(2)(iii)).
5.11.3 §63.764(e) Exemptions
5.11.3.1 The owner or operator of an area source is exempt from the requirements of
paragraph (d) (Condition 5.11.2) of this section if the criteria listed in paragraph
(e)(1)(i) (Condition a, below) or (ii) (Condition b, below) of this section are met, except
that the records of the determination of these criteria must be maintained as required in
§63.774(d)(1) (Condition 5.11.7) (§63.764(e)(1)).
a. The actual annual average flowrate of natural gas to the glycol dehydration unit is
less than 85 thousand standard cubic meters per day, as determined by the
procedures specified in §63.772(b)(1) (Condition 5.11.5.1) of this subpart
(§63.764(e)(1)(i)); or
b. The actual average emissions of benzene from the glycol dehydration unit process
vent to the atmosphere are less than 0.90 megagram per year, as determined by the
procedures specified in §63.772(b)(2) (Condition 5.11.5.2) of this subpart
(§63.764(e)(1)(ii)).
5.11.4 At all times the owner or operator must operate and maintain any affected source, including
associated air pollution control equipment and monitoring equipment, in a manner consistent with
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRA H
Air Pollution Control Division
Colorado Operating. Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 79
safety and good air pollution control practices for minimizing emissions. Determination of whether
such operation and maintenance procedures are being used will be based on information available
to the Administrator which may include, but is not limited to, monitoring results, review of
operation and maintenance procedures, review of operation and maintenance records, and
inspection of the source (§63.764(j)).
Test methods, compliance procedures, and compliance demonstrations
5.11.5 Determination of glycol dehydration unit flowrate, benzene emissions, or BTEX emissions. The
procedures of this paragraph shall be used by an owner or operator to determine glycol dehydration
unit natural gas flowrate, benzene emissions, or BTEX emissions (§63.772(b)).
5.11.5.1 The determination of actual flowrate of natural gas to a glycol dehydration unit shall
be made using the procedures of either paragraph (b)(1)(i) (Condition a, below) or
(b)(1)(ii) (Condition b, below) of this section (§63.772(b)(1)).
a. The owner or operator shall install and operate a monitoring instrument that directly
measures natural gas flowrate to the glycol dehydration unit with an accuracy of
plus or minus 2 percent or better. The owner or operator shall convert annual natural
gas flowrate to a daily average by dividing the annual flowrate by the number of
days per year the glycol dehydration unit processed natural gas (§63.772(b)(1)(i)).
b. The owner or operator shall document, to the Administrator's satisfaction, the actual
annual average natural gas flowrate to the glycol dehydration unit
(§63.772(b)(1)(ii)).
5.11.5.2 The determination of actual average benzene or BTEX emissions from a glycol
dehydration unit shall be made using the procedures of paragraph (b)(2)(i) (Condition
a, below) of this section. Emissions shall be determined either uncontrolled, or with
federally enforceable controls in place (§63.772(b)(2)).
a. The owner or operator shall determine actual average benzene or BTEX emissions
using the model GRI-GLYCalcTM, Version 3.0 or higher, and the procedures
presented in the associated GRI-GLYCalcTM Technical Reference Manual. Inputs
to the model shall be representative of actual operating conditions of the glycol
dehydration unit and maybe determined using the procedures documented in the
Gas Research Institute (GRI) report entitled "Atmospheric Rich/Lean Method for
Determining Glycol Dehydrator Emissions" (GRI-95/0368.1) (§63.772(b)(2)(i)).
b. The owner or operator shall determine an average mass rate of benzene or BTEX
emissions in kilograms per hour through direct measurement using the methods in
§63.772(a)(1)(i) or (ii) (Method 18 of 40 CFR Part 60 Appendix A or ASTM
D6420-99, respectively; see full rule text), or an alternative method according to
§63.7(f) (Condition 5.12.2). Annual emissions in kilograms per year shall be
determined by multiplying the mass rate by the number of hours the unit is operated
per year. This result shall be converted to megagrams per year (§63.772(b)(2)(ii)).
Recordkeeping Requirements
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 80
5.11.6 Except as specified in paragraphs (d) (Condition 5.11.7) and (f) (Condition 5.11.8) of this
section, each owner or operator of a facility subject to this subpart shall maintain the records
specified in paragraphs (b)(1) (Condition 5.11.6.1) through (2) (Condition 5.11.6.2) of this section
(§63.774(b)):
5.11.6.1 The owner or operator of an affected source subject to the provisions of this subpart
shall maintain files of all information (including all reports and notifications) required
by this subpart. The files shall be retained for at least 5 years following the date of each
occurrence, measurement, maintenance, corrective action, report or period. Records
shall be maintained in accordance with §63.774(b)(1)(i) through (iv) of this subpart
(§63.774(b)(1)).
5.11.6.2 Records specified in §63.10(b)(2) (Condition 5.12.3) (§63.774(b)(2)).
5.11.7 An owner or operator of a glycol dehydration unit that meets the exemption criteria in
§63.764(e)(1)(i) (Condition 5.11.3.1a) or §63.764(e)(1)(ii) (Condition 5.11.3.1b) shall maintain
the records specified in paragraph (d)(1)(i) (Condition 5.11.7.1) or paragraph (d)(1)(ii) (Condition
5.11.7.2) of this section, as appropriate, for that glycol dehydration unit (§63.774(d)(1)).
5.11.7.1 The actual annual average natural gas throughput (in terms of natural gas flowrate to
the glycol dehydration unit per day) as determined in accordance with §63.772(b)(1)
(Condition 5.11.5.1) (§63.774(d)(1)(i)), or
5.11.7.2 The actual average benzene emissions (in terms of benzene emissions per year) as
determined in accordance with §63.772(b)(2) (Condition 5.11:5.2) (§63.774(d)(1)(ii)).
5.11.8 The owner or operator of an area source not located within a UA plus offset and UC boundary
must keep a record of the calculation used to determine the optimum glycol circulation rate in
accordance with §63.764(d)(2)(i) (Condition 5.11.2.1a) or §63.764(d)(2)(ii) (Condition 5.11.2.Ib),
as applicable (§63.774(f)).
5.12 40 CFR Part 63, Subpart A NESHAP
Each dehydration unit is subject to the requirements in 40 CFR Part 63 Subpart A "General Provisions",
as adopted by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63
Subpart HE §63.764(a). These requirements include, but are not limited to the following:
5.12.1 Prohibited activities and circumvention (§63.4)
5.12.2 Performance testing requirements (§63.7)
5.12.3 Recordkeeping and reporting requirements (§63.10)
5.12.4 Addresses of State air pollution control agencies and EPA Regional Offices (§63.13)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: RAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 81
6. P-137 — Evco Fabrication 85 MMSCFD Amine Sweetening Unit, AIRS ID: 137
Parameter
Permit
Condition
Number
Limitations
Emission Factors
Monitoring
Method
Interval
Emission & Throughput. Limits
VOC
6.1
2.4 tons/year
ProMax or Division -
Approved Equivalent
SO2
6.2
30.0 tons/year
1.88 ton SO2/ ton H2S
Process Simulation
and Twelve Month
Rolling Total
Calculation
Monthly
NOx
CO
6.3
See Condition 12.1
NOx: 0.068 lb/M MBtu
CO: 0.31 lb/MMBtu
Process Simulation
and Twelve Month
Rolling Total
Calculation
Monthly
Sour Gas
Throughput
Limitations
6.4
31,025 MMSCF/yr
Lean Amine
Recirculation
Rate
6.5
Other Requirements
Extended Gas
Analysis of
Inlet Sour Gas
Parametric
Monitoring
6.6
6.7
Hours of
Operation
6.8
Compliance
Assurance
Monitoring
(CAM)
6.9
350 gpm
See Condition 6.9
Unit Inlet Meter and
Twelve Month
Rolling Total
Calculation
Monthly
Recordkeeping
Daily
ASTM Methods or
Equivalent
Recordkeeping
Annually
Weekly
Recordkeeping
Monthly
Statewide
Controls for
Oil and Gas
Operations
6.10
See Condition 6.10
40 CFR 60,
Subpart LLL
NSPS
6.11
Design Capacity < 2 Long
Tons/Day H2S
See Condition 6.11
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 82
40 CRF 60,
Subpart A
General
6.12Con
dition See 6.12
Provisions
NSPS
6.1 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) for this amine sweetening unit shall not exceed the
limitation listed in Summary Table 6 above (Colorado Construction Permit 10WE1659). Compliance with
the emission limitations shall be monitored as follows:
6.1.1 Monthly determination of VOC and HAP emissions shall be conducted by the end of the
subsequent month utilizing Bryan Research and Engineering's ProMax or other Division -approved
modeling software (Colorado Construction Permit 10WE1659).
6.1.1.1 The following parameters shall be input to the process model:
a. The inlet sour gas composition obtained from the most recent extended gas analysis,
as required by Condition 6.6.
b. The average daily inlet sour gas throughput, as required by Condition 6.4.
c. The average monthly value of the inlet sour gas temperature and pressure, the flash
tank operating temperature and pressure, and the lean amine circulation rate, as
required by Conditions 6.5 and 6.7.
6.1.1.2 Control Efficiencies
a. A control efficiency (CE) of 97% shall be applied to the acid gas vent emissions,
which are controlled by regenerative thermal oxidizer (RTO), provided the
requirements of Conditions 12.6.2 and 12.8.1 are met.
6.1.1.3 Hours of Operation
a. The monthly hours of operation shall be input to the equation below, as required by
Condition 6.8.
6.1.1.4 Monthly emissions of VOC and HAP shall be monitored using the following equation:
VOC or HAP Emissions
lb)hrs ( CERTo�%)1
( tons l AGVvoc/eaP (hrx OH (month x 1 100 J
l
-month l Unit Conversion (2000 lb)
ton 1
Where:
AGVvoc/Har = Uncontrolled Acid Gas Vent Emissions of VOC or HAP, lb/hr
OH = Hours of Operation, hrs/month
CERT° = Control Efficiency of Still Vent to RTO, 97%
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 83
The monthly VOC emissions obtained from this calculation shall be used in a twelve month rolling
total to monitor compliance with the annual limitations. Each month, a new twelve month total
shall be calculated using the previous twelve months' data. Records of calculations shall be
maintained and made available to the Division upon request.
6.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the same method as indicated above for VOC and used in a
twelve month rolling total to monitor compliance with the facility -wide HAP emission limitations.
6.2 SO2 Emission Limitations & Compliance Monitoring
Emissions of Sulfur Dioxide (SO2) for this amine sweetening unit shall not exceed the limitation listed in
Summary Table 6 above (Colorado Construction Permit 10WE1659). Compliance with the emission
limitations shall be monitored as follows:
6.2.1 Monthly determination of SO2 emissions shall be conducted by the end of the subsequent month
using the most recent monthly process model run (as required by Condition 6.1), in conjunction
with the most recent extended gas analysis (as required by Condition 6.6) (Colorado Construction
Permit 10WE1659).
6.2.1.1 The above emission factor (EF), H2S acid gas vent mass flowrate obtained from the
most recent monthly process model run (as required by Condition 6.1) and monthly
hours of operation (as required by Condition 6.8) shall be used to monitor compliance
with the SO2 emission limit using the following equation. A conversion efficiency (CE)
of 97% shall be used, provided the requirements of Conditions 12.6.2 and 12.8.1 are
met.
tons AGVHzs (lbhrZs) x EF (tonHos) hrs
x OH \month x CERT0(%)
SO2 Emissions ( ) 2000 lb z
month Unit Conversion ( tonxZs s)
Where:
AGVHzs = Uncontrolled Still Vent Emissions of H2S, lb/hr
EF = Emission Factor,1.88 tonsoz/tonH2s
OH = Hours of Operation, hrs/month
CERT° = Conversion Efficiency of RTO, 97%
The monthly SO2 emissions obtained from the preceding calculation shall be used in a twelve
month rolling total to monitor compliance with the annual limitations. Each month, a new twelve
month total shall be calculated using the previous twelve months' data. Records of calculations
and the monthly process model runs used to determine compliance with the SO2 emission
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 84
limitation shall be maintained for a period of at least five years and made immediately available
to the Division upon request.
6.3 NOx & CO Emission Limitations & Compliance Monitoring
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) generated by the destruction of the
amine sweetening unit emissions via the RTO shall not exceed the limitations listed in Summary Table
12 below (Colorado Construction Permit 10WE1659, as modified under the provisions of Section I,
Condition 1.3 and Colorado Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7, based on
requested emissions identified on the APEN submitted on 11/13/2017). Compliance with the emission
limitation shall be monitored as follows:
6.3.1 Monthly emissions shall be calculated by the end of the subsequent month using the emission
factors listed above (from EPA's AP -42: Compilation of Emission Factors, Section 13.5 for
Industrial Flares, Final Section, dated 12/16), the hourly acid gas vent (AGV) flowrate and acid
gas vent (AGV) heat content obtained from the most recent monthly process model run (as required
by Condition 6.1), and the monthly hours for the amine sweetening unit (as required by Condition
6.8) as inputs to the equation below:
MMSCF hrs MMBtu lb
tons
AGV Flowrate ( x Hours of 0 eration / x AGV Heat Content x Emission Factor,
NOx or CO Emissions hr F lmonth� MMSCF MMBtu
\month/ Unit Conversion (2 to lb
ton )
Monthly emissions of NOx and CO as calculated above shall be used to monitor compliance with the
annual limitations set forth in Condition 12.1.
6.4 Sour Gas Throughput Limitations & Compliance Monitoring
The total amount of sour gas processed by this amine sweetening unit shall not exceed the limitation listed
in Summary Table 6 above (Colorado Construction Permit 10WE1659). The gas throughput to this amine
sweetening unit shall be monitored and recorded monthly using a dedicated flowmeter located at the inlet
to the unit. The monthly sour gas throughput shall be used in a twelve month rolling total to monitor
compliance with the annual limitations. Each month, a new twelve month total shall be calculated using
the previous twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
An average daily gas throughput rate shall be used as an input to the monthly process model run, (as
required by Condition 6.1). This average daily gas throughput rate shall be calculated by dividing the
monthly sour gas throughput by the total monthly hours of operation (as required by Condition 6.8):
MMSCF) Monthly Gas Throughput ( month x Unit Conversion (mmscF\Zdays)
Average Daily Gas Throughput ( J
day hrs Hours of Operation
�month�
6.5 Lean Amine Circulation Rate Limitations & Compliance Monitoring
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 85
The circulation rate of lean amine shall not exceed the limitationlisted in Summary Table 6 above
(Colorado Construction Permit 10WE1659, as modified under the provisions of Section I, Colorado
Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7., based on the flowrate identified on
the APEN received on 11/13/2017). The lean amine circulation rate shall be recorded daily and obtained
using the methods outlined below:
6.5.1 Primary Determination Method: The lean amine circulation rate shall be recorded using the
existing amine flowmeter. The recorded lean amine circulation rate shall be the sum of the
circulation rates from each pump. Records of the lean amine circulation rate shall be maintained
and made available to the Division upon request.
6.5.2 Backup Determination Method: If the primary method of determining the lean amine circulation
rate cannot be utilized, the circulation rate of lean amine shall be assumed to be equivalent to the
maximum design rate of the pump. Records of the pump make/model and manufacturer circulation
rate specifications shall be made to the Division upon request.
Records of the daily lean amine circulation rate shall be maintained and made availableto the Division
upon request.
A monthly average of the lean amine circulation rate shall be calculated from the daily recorded values of
that month and used as an input to the monthly process model run, as required by Condition 6.1.
6.6 Extended Gas Analysis of Inlet Sour Gas
An extended gas analysis of the inlet sour gas to the amine sweetening unit shall be performed annually
according to appropriate ASTM methods, or equivalent, if approved in advance by the Division. The
extended analysis must identify total sulfur in the gas fed to the amine sweetening unit (Colorado
Construction Permit 10WE1659). Results of the inlet sour gas analysis shall be retained and made
available to the Division upon request.
The composition indicated by the extended sour gas analysis shall be used in the monthly process model
run, as required by Condition 6.1.
6.7 Parametric Monitoring
The following operating parameters for this amine sweetening unit shall be monitored and recorded at the
intervals specified in the table below. Values of the parameters monitored shall be representative of the
unit's operation for the duration of the monitoring period. Records of the values recorded shall be
maintained and made available to the Division upon request.
Parameter
Monitoring Frequency
Inlet Sour Gas Temperature'
Weekly'
Inlet Sour Gas Pressure'
Weekly'
Flash Tank Operating Temperature
Weekly
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 86
Flash Tank Operating Pressure
Weekly
'As required by Colorado Construction Permit 10WE1659
Monthly averages of each parameter shall be obtained by averaging the operating values recorded for that
month. These monthly averages shall be used as inputs to the monthly process model run, as required by
Condition 6.1.
6.8 Hours of Operation
Hours of operation for this amine sweetening unit shall be monitored and recorded monthly in a log that
is to be made available to the Division upon request. Monthly hours of operation shall be used to determine
the average daily gas throughput, as required by Condition 6.4.
6.9 Compliance Assurance Monitoring (CAM)
This amine sweetening unit is subject to the Compliance Assurance Monitoring (CAM) requirements with
respect to the annual emission limitations in Condition 14.1 for HAP. Compliance with the CAM
requirements shall be monitored in accordance with the requirements in Condition 16 and the CAM Plan
in Appendix H.
6.10 Statewide Controls for Oil and Gas Operations
6.10.1 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.B. Requirements
This amine sweetening unit is subject to the following State -Only Enforceable "General
Provisions" of Colorado Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas
Operations and Natural Gas -Fired Reciprocating Internal Combustion Engines":
General Requirements
6.10.1.1 At all times, including periods of start-up and shutdown, the facility and air pollution
control equipment must be maintained and operated in a manner consistent with good
air pollution control practices for minimizing emissions. Determination of whether or
not acceptable operation and maintenance procedures are being used will be based on
information available to the Division, which may include, but is not limited to,
monitoring results, opacity observations, review of operation and maintenance
procedures, and inspection of the source (Colorado Regulation No. 7, Section
XVII.B.1.b.).
6.11 40 CFR Part 60, Subpart LLL NSPS
This amine sweetening unit is subject to the New Source Performance Standards requirements of Colorado
Regulation No. 6, Part A, Subpart LLL (40 CFR Part 60, Subpart LLL) "Standards of Performance for
SO2 Emissions From Onshore Natural Gas Processing for Which Construction, Reconstruction, or
Modification Commenced After January 20, 1984, and on or Before August 23, 2011", including, but not
limited to, the following:
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 87
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
LLL published in the Federal Register on August 16, 2012. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 60 Subpart LLL.
Applicability and designation of affected facilities
6.11.1 Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide
(H2S) in the acid gas (expressed as sulfur) are required to comply with §60.647(c) (Condition
6.11.2) but are not required to comply with §§60.642 through 60.646 (§60.640(b)).
Recordkeeping and reporting requirements
6.11.2 To certify that a facility is exempt from the control requirements of these standards, each owner
or operator of a facility with a design capacity less than 2 LT/D of H2S in the acid gas (expressed
as sulfur) shall keep, for the life of the facility, an analysis demonstrating that the facility's design
capacity is less than 2 LT/D of H2S expressed as sulfur (§60.647(c)).
6.12 40 CFR Part 60, Subpart A NSPS
This amine sweetening unit is subject to the requirements in 40 CFR Part 60 Subpart A "General
Provisions", as adopted by reference in Colorado Regulation No. 6, Part A, Subpart A as specified in 40
CFR Part 60 Subpart LLL. These requirements include, but are not limited to the following:
6.12.1 Circumvention (§60.12)
Operating Permit 95OPWE055 First Issued: May 1, 2001
........................................
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 88
P025 - Fugitive Emissions from Equipment Leaks, AIRS ID: 122
Parameter
Permit
Condition
Number
Limitations
Emission Factor
Monitoring
Method
Interval
Emission Limits
VOC
7.1
33.5 tons/year
By Component -
EPA Protocol for
Equipment Leak
Estimates
Recordkeeping
and Twelve
Month Rolling
Total
Calculation
Monthly
Other Requirements
Component
Count
7.2
Extended Gas
Analysis of
Process Gas
7.3
Running Total
and Hard Count
See Condition 7.2
ASTM Methods
or Equivalent
Annually
Statewide
Controls of Oil
and Gas
Operations
7.4
Complies by meeting 40 CFR 60 Subpart OOOO NSPS
See Condition 7.4
40 CFR 60,
Subpart KKK
NSPS
7.5
Complies by meeting 40 CFR 60 Subpart OOOO NSPS
See Condition 7.5
40 CFR 60,
Subpart OOOO
NSPS
7.6
See Condition 7.6
40 CFR 60,
Subpart A
NSPS
7.7
See Condition 7.7
7.1 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) from equipment leaks shall not exceed the limitation
listed in Summary Table 7 above (Colorado Construction Permit 10WE1659). Compliance with the
emission limitations shall be monitored as follows:
7.1.1 The following emission factors to be used in the listed equations are derived from the Total Organic
Compound (TOC) Emission Factors (EF) for individual types of components in lb/component-hr
(EPA - 453/R 95-017, "EPA's Protocol for Equipment Leak Emission Estimates", Table 2-4,
November 1995).
Component
Emission Factors (lb/component-hr)
Gas Service
Light Liquid
Heavy Liquid
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 89
Connectors
4.41 x 10-4
4.63 x 10-4
1.65 x 10-5
Flanges
8.60 x 10-4
2.43 x 10-4
8.60 x 10-7
Open -Ends
4.41 x 10-3
3.09 x 10-3
3.09 x 10-4
Pump Seals
5.29 x 10-3
2.87 x 10-2
N/A
Valves
9.92 x 10-3
5.51 x 10-3
1.85 x 10"5
Other*
1.94 x 10-2
1.65 x 10-2
7.05 x 10-5
*Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms,
hatches, instrument meters, polish rods, and vents.
7.1.2 The following component -specific control factors have been approved by the Division for use in
determining compliance with the annual emission limitations for fugitive emissions at this facility:
Component
Control Factor
Connectors
30%
Flanges
30%
Open -Ends
N/A
Pump Seals
75%
Valves
75%
Other*
75%
*Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms, drains, dump arms,
hatches, instrument meters, polish rods, and vents.
7.1.3 Monthly determination of VOC and HAP emissions shall be calculated by the end of the
subsequent month using the appropriate emission factors (Condition 7.1.1), control factors
(Condition 7.1.2), the most recent extended gas analysis (as required by Condition 7.3) and the
values from the most recent component count (as required by Condition 7.2) in the equations
below:
( tons ll _tons l tons l tons l
Total VOC or HAP Emissions \monthl — GSVOC/HAP ( monthl + LLVOC/HAP (monthl + HLVOC/HAP (month)
Where:
tons l GSvoc/HAP (month)_
Each. Component
tons l _
LLvoc/HAP (month)
Each Component
CC (component) x EF ( lb \ x /730 hrsl x x x (1 CF(%)\
cs p ) cs component — hr) ( month J Gs 100 J
Unit Conversion (2000 lb)
ton
CCLL (component) x EFLL
lb (730 hrs CF(%)\
— hr) x (month ) x xLL x (1 100 ) (component
Unit Conversion (2000 !b)
ton
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
/ tons
HLVO l
n _
C/HAP month
Each Component
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 90
( lb (730 hrs) ( _ CF(%))
CCHL (component) x EFHL (component — hr) x month )>< xHL x 1 100 J
Unit Conversion (2000 lb)
ton 11
And:
GSvoc/HAP = Gas Service VOC or HAP Emissions, tons/month
CCGS = Component Count in Gas Service, qty
EFGs = Component • Specific Emission Factor for Gas Service, lb/component — hr
XGS = Gas VOC or HAP Content, mass fraction
LLVOC/HAP = Light Liquid Service V0C or HAP Emissions, tons/month
CCLL = Component Count in Light Liquid Service, qty
EFLL = Component • Specific Emission Factor for Light Liquid Service, lb/component — hr
xLL = Light Liquid VOC or HAP Content, mass fraction
HLvoc/HAP = Heavy Liquid Service VOC or HAP Emissions, tons/month
CCHL = Component Count in Heavy Liquid Service, qty
EFHL = Component • Specific Emission Factor for Heavy Liquid Service, lb/component — hr
xHL = Heavy Liquid VOC or HAP Content, mass fraction
CF = Component • Specific Control Factor, %
Monthly VOC emissions shall be used in a twelve month rolling total to monitor compliance with
the annual limitations. Each month, a new twelve month total shall be calculated using the
previous twelve months' data. Records of calculations shall be maintained and made available to
the Division upon request.
7.1.4 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the same method as indicated above for VOC and used in a
twelve month rolling total to monitor compliance with the facility -wide HAP emission limitations.
7.2 Component Count
An initial physical hard -count of facility components shall be performed within ninety (90) calendar days
of permit issuance and conducted every five years thereafter. This hard count shall distinguish between
components in different services as indicated in EPA - 453/R 95-017, "EPA's Protocol for Equipment
Leak Emission Estimates" (i.e., gas/light oil/heavy oil/water-oil) service. In the interim, a running total of
all additions and subtractions to the component count shall be maintained. Monthly emissions shall be
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 91
calculated based on the most recent running total. The five-year hard count shall be used as a check against
the running total. The hard component count and running total of all component additions/subtractions
shall be made available for the Division upon request.
The most recent running total component count shall be used to monitor compliance with the annual VOC
and HAP emission limitations (Colorado Construction Permit 10WE1659), as required by Condition 7.1.3.
7.3 Extended Gas Analysis of Process Gas
An extended gas analysis of process gas shall be performed annually according to appropriate ASTM
methods, or equivalent, if approved in advance by the Division. The process gas sampled shall be
representative of the VOC and HAP content of fugitive emissions present at the facility (Colorado
Construction Permit l OWE1659). Results of the process gas analysis shall be retained and made available
to the Division upon request.
The most recent extended gas analysis shall be used to monitor compliance with the annual limitations for
VOC and HAP (Colorado Construction Permit 10WE1659), as set forth in Condition 7.1.3. The VOC and
HAP content identified in the extended analysis shall be used to calculate VOC and HAP emissions for
the components in gas service. For components in light liquid service, it is permissible to assume that
fugitive emissions are composed of 100% VOC and are of the same HAP composition as indicated on the
extended analysis for the representative gas sample.
7.4 Statewide Controls for Oil and Gas Operations
7.4.1 Colorado Regulation No. 7, Section XII.G Requirements:
This facility is subject to the following State -Only Enforceable requirements for gas -processing
plants located in the 8 -hour Ozone Control Area of Colorado Regulation No. 7, Section XII,
"Volatile Organic Compound Emissions from Oil and Gas Operations":
7.4.1.1 For fugitive volatile organic compound emissions from leaking equipment, the leak
detection and repair (LDAR) program as provided at 40 CFR Part 60, Subpart OOOO
(July 1, 2017; Condition 7.6) applies, regardless of the date of construction of the
affected facility, unless subject to the LDAR program provided at 40 CFR Part 60,
Subpart 0000a (July 1, 2017). (Colorado Regulation No. 7, Section XII.G.1.).
7.4.1.2 Natural gas processing plants within the 8 -hour Ozone Control Area constructed before
January 1, 2018 must comply with the requirements of Section XII.G. (Condition
7.4.1.1) beginning January 1, 2019 (Colorado Regulation No. 7, Section XII.G.3.).
7.5 40 CFR Part 60, Subpart KKK NSPS
This facility, except for Process Units RC, RP and RTF, is subject to the New Source Performance
Standards requirements of Colorado Regulation No. 6, Part A, Subpart KKK (40 CFR Part 60, Subpart
KKK) "Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 92
Plants for Which Construction, Reconstruction or Modification Commenced After January 20, 1984, and
on or Before August 23, 2011", including, but not limited to, the following:
7.5.1 Compliance with NSPS KKK is presumed, provided the requirements of NSPS OOOO (Condition
7.6) are met.
7.6 40 CFR Part 60, Subpart OOOO NSPS
This facility is subject to the New Source Performance Standards requirements of Colorado Regulation
No. 6, Part A, Subpart OOOO (40 CFR Part 60, Subpart OOOO) "Standards of Performance for Crude
Oil and Natural Gas Production, Transmission and Distribution for which Construction, Modification or
Reconstruction Commenced After August 23, 2011, and on or before September 18, 2015", as required
by Condition 7.4.1.1, including, but not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
OOOO published in the Federal Register on June 3, 2016. However, if revisions to this Subpart are
published at a later date, the owner or operator is subject to the requirements contained in the revised
version of 40 CFR Part 60 Subpart OOOO.
This facility is subject to the following applicable requirements:
7.6.1 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall
maintain and operate any affected facility including associated air pollution control equipment in
a manner consistent with good air pollution control practice for minimizing emissions.
Determination of whether acceptable operating and maintenance procedures are being used will
be based on information available to the Administrator which may include but is not limited to,
monitoring results, opacity observations, review of operating and maintenance procedures, and
inspection of the source (§60.5370(b)).
7.6.2 Equipment leak standards applicable to affected facilities at an onshore natural gas processing
plant (§60.5400)
7.6.3 Exceptions to the equipment leak standards for affected facilities at an onshore natural gas
processing plant (§60.5401)
7.6.4 Alternative emission limitations for equipment leaks from onshore natural gas processing plants
(§60.5402)
7.6.5 Continuous compliance demonstration with the standards for affected facilities at onshore natural
gas processing plants (§60.5415(f))
7.6.6 Recordkeeping Requirements for affected facilities subject to VOC requirements for onshore
natural gas processing plants (§60.5421)
7.6.7 Reporting Requirements for affected facilities subject to VOC requirements for onshore natural
gas processing plants (§60.5422)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 93
7.7 40 CFR Part 60, Subpart A NSPS
This facility, with respect to fugitive emissions, is subject to the requirements in 40 CFR Part 60 Subpart
A "General Provisions", as adopted by reference in Colorado Regulation No. 6, Part A, Subpart A as
specified in 40 CFR Part 60 Subpart KKK and Subpart OOOO. These requirements include, but are not
limited to the following:
7.7.1 Notification and recordkeeping (§60.7)
7.7.2 Circumvention (§60.12)
7.7.3 Incorporations by reference (§60.17)
7.7.4 General notification and reporting requirements (§60.19)
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 94
8. P039 - Eight (8) 300 -bbl Stabilized Condensate Storage Tanks, AIRS ID: 125
Permit
Parameter Condition
Number
Limitations
Emission
Factor
Monitoring
Method
Interval
Emission & Throughput Limits
VOC
8.1
1.5 tons/year
0.0101 lb/bbl
Twelve Month Rolling
Total Calculation
Monthly
Condensate
Throughput
8.2
285,714 bbl/year
Recordkeeping and
Twelve Month Rolling
Total Calculation
Monthly
Other Requirements
Opacity
8.3
Not to exceed 30% for a
period or periods
aggregating more than six
(6) minutes in any sixty (60)
consecutive minutes
See Condition 8.4
See Condition
8.3
Control Device
Requirements
8.4
Statewide
Controls for Oil
and Gas
Operations
8.5
See Condition 8.5
8.1 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) from the stabilized condensate storage tanks shall not
exceed the limitation listed in Summary Table 8 above (Colorado Construction Permit 12WE1242).
Compliance with the emission limitations shall be monitored as follows:
8.1.1 Monthly determination of VOC emissions shall be conducted by the end of the subsequent month
utilizing the above emission factor and the monthly condensate throughput, as required by
Condition 8.2, in the equation below:
00101 lb bbl
.
tons \ Emission Factor ( bbl.x Condensate Throughput (month
VOC Emissions (month) 2000 lb
Unit Conversion ( ton
Monthly VOC emissions shall be used in a twelve month rolling total to monitor compliance with
the annual limitations. Each month, a new twelve month total shall be calculated using the
previous twelve months' data. Records of calculations shall be maintained and made available to
the Division upon request.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 95
8.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the methods required by Condition 14 and used in a twelve
month rolling total to monitor compliance with the facility -wide HAP emission limitations.
8.2 Condensate Throughput Limitations & Compliance Monitoring
The maximum processing rate of condensate sent through this tank battery shall not exceed the limitation
listed in Summary Table 8 above (Colorado Construction Permit 12WE1242). The condensate throughput
shall be monitored and recorded monthly using sales or haul tickets from truck loading. The monthly
condensate throughput shall be the sum of the volume transferred, as indicated on each sales or haul ticket,
for all loading operations that took place during that month. The monthly condensate throughput shall be
used in a twelve month rolling total to monitor compliance with the annual limitations. Each month, a
new twelve month total shall be calculated using the previous twelve months' data. Records of calculations
shall be maintained and made available to the Division upon request.
This monthly condensate throughput shall be used to monitor compliance with the annual VOC and HAP
emission limitations, as required by Condition 8.1.
8.3 Opacity
The following opacity requirements apply to the enclosed combustion device (ECD):
8.3.1 No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall
allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity
for a period or periods aggregating more than six minutes in any sixty consecutive minutes.
(Colorado Regulation No. 1, Section II.A.5).
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be presumed,
provided the requirements of Conditions 8.4.2.3 and 8.5.2.4 are met.
8.4 Control Device Requirements
Emissions from the stabilized condensate tanks are destructed with an enclosed combustion device (see
Permitted Activities, SECTION I - 1). The following requirements apply to the enclosed combustion
device and relief devices associated with each condensate tank:
8.4.1 Leakage of VOCs to the atmosphere shall be minimized as follows:
8.4.1.1 Thief hatch seals shall be inspected for integrity annually and replaced as necessary.
8.4.1.2 Thief hatch covers shall be weighted and properly seated.
8.4.1.3 Pressure relief valves (PRV) shall be inspected annually for proper operation and
replaced as necessary.
8.4.1.4 PRVs shall be set to release at a pressure that will ensure flashing, working and
breathing losses (as applicable) are routed to the control device under normal operating
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
conditions.
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 96
8.4.1.5 Annual inspections shall be documented with an indication of status, a description of
any problems found, and their resolution.
8.4.2 Control Equipment Monitoring
8.4.2.1 The enclosed combustion device shall be operated at all times when emissions are
routed to it.
8.4.2.2 The enclosed combustion device shall be operated with the pilot light present at all
times.
a. The auto -igniter signal shall detect the presence of the pilot light and shall alert the
operator if the pilot light cannot be detected. A daily record of the auto -igniter
signal shall be maintained and made available to the Division upon request.
b. In the event that the auto -igniter cannot be used to verify the presence of a pilot
light, the temperature signal from the thermocouple on the combustion device may
be used to verify the presence of a flame on a daily basis. Alternatively, a visual
inspection of the pilot light may be completed daily to verify pilot light presence.
A daily log with the results from the visual inspection or temperature reading from
the thermocouple shall be maintained and made available to the Division upon
request.
c. Records of pilot light outage events and the duration of such events shall be
maintained and made available to the Division upon request.
8.4.2.3 EPA Method 22 observations shall be conducted daily to determine whether visible
emissions are present for a period of at least one (1) minute in any fifteen (15) minute
period of normal operation. The results of the daily visual observations shall be kept
on file and made available to the Division upon request.
a. In the event visible emissions are observed, an EPA Reference Method 9 opacity
observation shall be performed to monitor compliance with the opacity standard.
The result(s) of the visual observations and the Method 9 observations shall be kept
on file and made available for Division review upon request.
(i) The EPA Reference Method 9 opacity observations shall be performed by an
observer with a current and valid Method 9 certification. A clear and readable
copy of the observer's certificate and any opacity observations shall be kept on
file and made available to the Division for review upon request.
(ii) Subject to the provisions of §25-7-123.1, C.R.S., and in the absence of credible
evidence to the contrary, exceedance of the opacity limit (as required by
Condition 8.3) shall be considered to exist from the time a Method 9 reading is
taken that shows an exceedance of the opacity limit until a Method 9 reading is
taken that shows the opacity is less than the opacity limit.
8.5 Statewide Controls for Oil and Gas Operations
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 97
8.5.1 Colorado Regulation No. 7, Section XII.C. Requirements:
The control equipment for this tank battery is subject to the following "General Requirements for
Air Pollution Control Equipment" of Colorado Regulation No. 7, Section XII, "Volatile Organic
Compound Emissions from Oil and Gas Operations":
Conditions shown in italic text below represent monitoring, recordkeeping and recording
provisions that are not included in Colorado Regulation No. 7 as of the issuance date of this permit,
but are being included as per Colorado Regulation No. 3, Part C, Section V.C.5.b.
8.5.1.1 All air pollution control equipment used to demonstrate compliance with this Section
XII. shall be operated and maintained consistent with manufacturer specifications and
good engineering and maintenance practices. The owner or operator shall keep
manufacturer specifications on file. In addition, all such air pollution control equipment
shall be adequately designed and sized to achieve the control efficiency rates required
by this Section XII and to handle reasonably foreseeable fluctuations in emissions of
volatile organic compounds. Fluctuations in emissions that occur when the separator
dumps into the tank are reasonably foreseeable (Colorado Regulation No. 7, Section
XII.C.I.a.)
8.5.1.2 All condensate collection, storage, processing and handling operations, regardless of
size, shall be designed, operated and maintained so as to minimize leakage of volatile
organic compounds to the atmosphere to the maximum extent practicable (Colorado
Regulation No. 7, Section XII.C.1.b.).
8.5.2 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.B. Requirements:
This tank battery is subject to the following State -Only Enforceable "General Provisions" of
Colorado Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas Operations and
Natural Gas -Fired Reciprocating Internal Combustion Engines":
General Requirements
8.5.2.1 All intermediate hydrocarbon liquids collection, storage, processing, and handling
operations, regardless of size, shall be designed, operated, and maintained so as to
minimize leakage of VOCs and other hydrocarbons to the atmosphere to the extent
reasonably practicable (Colorado Regulation No. 7, Section XVII.B.1.a.).
8.5.2.2 At all times, including periods of start-up and shutdown, the facility and air pollution
control equipment must be maintained and operated in a manner consistent with good
air pollution control practices for minimizing emissions. Determination of whether or
not acceptable operation and maintenance procedures are being used will be based on
information available to the Division, which may include, but is not limited to,
monitoring results, opacity observations, review of operation and maintenance
procedures, and inspection of the source (Colorado Regulation No. 7, Section
XVII.B .1.b.).
8.5.2.3 All air pollution control equipment shall be operated and maintained pursuant to the
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 98
manufacturing specifications or equivalent to the extent practicable, and consistent
with technological limitations and good engineering and maintenance practices. The
owner or operator shall keep manufacturer specifications or equivalent on file. In
addition, all such air pollution control equipment shall be adequately designed and
sized to achieve the control efficiency rates and to handle reasonably foreseeable
fluctuations in emissions of VOCs and other hydrocarbons during normal operations.
Fluctuations in emissions that occur when the separator dumps into the tank are
reasonably foreseeable (Colorado Regulation No. 7, Section XVII.B.2.a.).
Combustion Device Requirements
8.5.2.4 If a combustion device is used to control emissions of VOCs and other hydrocarbons,
it shall be enclosed, have no visible emissions during normal operation, and be designed
so that an observer can, by means of visual observation from the outside of the enclosed
combustion device, or by other means approved by the Division, determine whether it
is operating properly (Colorado Regulation No. 7, Section XVII.B.2.b.).
[Compliance Demonstration: In the absence of credible evidence to the contrary,
compliance with the no visible emissions requirement is presumed provided the
monitoring in Condition 8.4.2.3 indicates no visible emissions.]
8.5.2.5 Auto -igniters: All combustion devices used to control emissions of hydrocarbons must
be equipped with and operate an auto -igniter as follows (Colorado Regulation No. 7,
Section XVII.B.2.d.):
a. All combustion devices installed before May 1, 2014, must be equipped with an
operational auto -igniter by or before May 1, 2016, or after the next combustion
device planned shutdown, whichever comes first (Colorado Regulation No. 7,
Section XVII.B.2.d.(ii)).
8.5.3 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.C. Requirements:
This tank battery is subject to the following State -Only Enforceable "Emission Reduction from
Storage Tanks at Oil and Gas Exploration and Production Operations, Well Production Facilities,
Natural Gas Compressor Stations and Natural Gas Processing Plants" requirements of Colorado
Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas Operations and Natural Gas -
Fired Reciprocating Internal Combustion Engines":
Control Requirements:
8.5.3.1 Beginning May 1, 2008, owners or operators of all storage tanks storing condensate
with uncontrolled actual emissions of VOCs equal to or greater than twenty (20) tons
per year based on a rolling twelve-month total must operate air pollution control
equipment that has an average control efficiency of at least 95% for VOCs (Colorado
Regulation No. 7, Section XVII.C.1.a.).
[Compliance Demonstration: In the absence of credible evidence to the contrary,
compliance with the 95% average VOC control efficiency requirement shall be
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control. Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 99
presumed as long as the requirements in Conditions 8.4 and 8.5.2 are met.]
[Additional Monitoring: For the purposes of Condition 8.5.3.1, the owner or operator
shall determine the uncontrolled actual annual VOC emissions on a monthly basis.
Monthly calculations shall be determined at the end of the subsequent month and shall
be used in a twelve month rolling total to determine uncontrolled actual VOC
emissions. If the twelve month rolling uncontrolled actual VOC total is greater than or
equal to twenty tons per year, the owner or operator shall comply with the required
control efficiency of 95% within 60 days of that determination. The owner or operator
shall continue to comply with 95% control efficiency requirement until uncontrolled
actual VOC emissions are less than twenty tons per year, at which point, the 95%
control efficiency requirement will no longer apply beginning on the first day of the
month following the new determination. Records of the required calculations and
monthly applicability determination shall be maintained and made available to the
Division upon request.]
8.5.3.2 Owners or operators of storage tanks with uncontrolled actual emissions of VOCs equal
to or greater than six (6) tons per year based on a rolling twelve-month total must
operate air pollution control equipment that achieves an average hydrocarbon control
efficiency of 95% (Colorado Regulation No. 7, Section XVII.C.1.b.).
[Compliance Demonstration: In the absence of credible evidence to the contrary,
compliance with the 95% average hydrocarbon control efficiency requirement shall be
presumed as long as the requirements in Conditions 8.4 and 8.5.2 are met.]
8.5.3.3 Control requirements of Section XVII.C.I.b (Condition 8.5.3.2) must be achieved in
accordance with the following schedule (Colorado Regulation No. 7, Section
XVII.C.1.b.(i)):
a. A storage tank constructed before May 1, 2014, must be in compliance by May 1,
2015 (Colorado Regulation No. 7, Section XVII.C.1.b.(i)(B)).
b. A storage tank not otherwise subject to Section XVII.C.1.b.(i)(B) (Condition a of
this section) that increases uncontrolled actual emissions to six (6) tons per year
VOC or more on a rolling twelve month basis after May 1, 2014, must be in
compliance within sixty (60) days of discovery of the emissions increase (Colorado
Regulation No. 7, Section XVII.C.1.b.(i)(C)).
Visual Inspection Requirements:
8.5.3.4 Beginning May 1,2014, or the applicable compliance date in Section XVII.C.1.b.(i)
(Condition 8.5.3.3), whichever comes later, owners or operators of storage tanks
subject to Section XVII.C.1. must conduct audio, visual, olfactory ("AVO") and
additional visual inspections of the storage tank and any associated equipment (e.g.
separator, air pollution control equipment, or other pressure reducing equipment) at the
same frequency as liquids are loaded out from the storage tank. These inspections are
not required more frequently than every seven (7) days but must be conducted at least
every thirty one (31) days. Monitoring is not required for storage tanks or associated
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 100
equipment that are unsafe, difficult, or inaccessible to monitor, as defined in Section
XVII.C.1.e. (Condition 8.5.3.5). The additional visual inspections must include, at a
minimum (Colorado Regulation No. 7, Section XVII.C.1.d.):
a. Visual inspection of any thief hatch, pressure relief valve, or other access point to
ensure that they are closed and properly sealed (Colorado Regulation No. 7, Section
XVII.C.1.d.(i));
b. Visual inspection or monitoring of the air pollution control equipment to ensure
that it is operating, including that the pilot light is lit on combustion devices used
as air pollution control equipment (Colorado Regulation No. 7, Section
XVII.C.1.d.(ii));
c. If a combustion device is used, visual inspection of the autoigniter and valves for
piping of gas to the pilot light to ensure they are functioning properly (Colorado
Regulation No. 7, Section XVII.C.1.d.(iii));
d. Visual inspection of the air pollution control equipment to ensure that the valves
for the piping from the storage tank to the air pollution control equipment are open
(Colorado Regulation No. 7, Section XVII.C.1.d.(iv)); and
e. If a combustion device is used, inspection of the device for the presence or absence
of smoke. If smoke is observed, either the equipment must be immediately shut-in
to investigate the potential cause for smoke and perform repairs, as necessary, or
EPA Method 22 must be conducted to determine whether visible emissions are
present for a period of at least one (1) minute in fifteen (15) minutes (Colorado
Regulation No. 7, Section XVII.C.1.d.(v)).
8.5.3.5 If storage tanks or associated equipment is unsafe, difficult, or inaccessible to monitor,
the owner or operator is not required to monitor such equipment until it becomes
feasible to do so (Colorado Regulation No. 7, Section XVII.C.I.e.).
Capture Requirements:
8.5.3.6 Capture requirements for storage tanks that are fitted with air pollution control
equipment as required by Section XVII.C.1. (Conditions 8.5.3.1 and 8.5.3.2):
Owners or operators of storage tanks must route all hydrocarbon emissions to air
pollution control equipment, and must operate without venting hydrocarbon emissions
from the thief hatch (or other access point to the tank) or pressure relief device during
normal operation, unless venting is reasonably required for maintenance, gauging, or
safety of personnel and equipment. Compliance must be achieved in accordance with
the schedule in Section XVII.C.2.b.(ii) (Condition 8.5.3.7) (Colorado Regulation No.
7 Section XVII.C.2.a.).
a. Venting is emissions from a controlled storage tank thief hatch, pressure relief
device, or other access point to the storage tank (Colorado Regulation No. 7,
Section XVII.C.2.a.(i)), which:
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DR l
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 101
(i) Are primarily the result of over -pressurization, whether related to design,
operation, or maintenance (Colorado Regulation No. 7, Section
XVII.C.2.a.(i)(A)); or
(ii) Are the result of an open, unlatched, or visibly unseated pressure relief device
(e.g., thief hatch or pressure relief valve), an open vent line, or an unintended
opening in the storage tank (e.g., crack or hole) (Colorado Regulation No. 7,
Section XVII.C.2.a.(i)(B))
When emissions from a controlled storage tank are observed, the Division may
require the owner or operator to submit sufficient information demonstrating
whether or not the emissions were primarily the result of over -pressurization.
Absent a demonstration that such emissions were not primarily the result of over -
pressurization, such emissions will be considered venting for purposes of Section
XVII.C.2.a. (Condition 8.5.3.6) (Colorado Regulation No. 7, Section
XVII.C.2.a.(ii)).
[Compliance Demonstration: In the absence of credible evidence to the contrary,
compliance with the requirements of this Condition shall be presumed as long as the
recordkeeping requirements of Conditions 8.5.3.8b and 8.5.3.8e indicate that
hydrocarbon emissions venting did not occur during normal operation unless venting
is reasonably required for maintenance, gauging, or safety of personnel and
equipment. For the purposes of this condition, approved instrument monitoring
method means an infra -red camera, or EPA Method 21.]
8.5.3.7 Owners or operators must achieve the requirements of Section XVII.C.2.a. (Condition
8.5.3.6) and begin implementing the required approved instrument monitoring method
in accordance with the following schedule (Colorado Regulation No. 7, Section
XVII.C.2.b.(ii)):
Initial Compliance Dates for Capture Requirements and AIMM Inspections
a. A storage tank constructed before May 1, 2014, must comply with the requirements
of Sections XVII.C.2.a. (Condition 8.5.3.6) by May 1, 2015. Approved instrument
monitoring method inspections must begin within ninety (90) days of the Phase -In
Schedule in Table 1, or within thirty (30) days for storage tanks with uncontrolled
actual VOC emissions greater than 50 tons per year (Section XVII.C.2.b.(ii)(B)).
b. A storage tank not otherwise subject to Section XVII.C.2.b.(ii)(b) (Condition a,
above) that increases uncontrolled actual emissions to six (6) tons per year VOC or
more on a rolling twelve month basis after May 1, 2014, must comply with the
requirements of Section XVII.C.2.a. (Condition 8.5.3.6) and implement the
required approved instrument monitoring method inspections within sixty (60) days
of discovery of the emissions increase (Section XVII.C.2.b.(ii)(C)).
AIMMInspection Frequency
c. Following the first approved instrument monitoring method inspection, owners or
operators must continue conducting approved instrument monitoring method
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 102
inspections in accordance with the Inspection Frequency in the table below (Section
XVII.C.2.b.(ii)(D)).
Storage Tank Inspections
Threshold: Storage Tank
Uncontrolled Actual
VOC Emissions (tpy)
Approved Instrument
Monitoring Method
Inspection Frequency
Phase in
Schedule
> 6 and < 12
-Annually
January 1, 2016
> 12 and < 50
Quarterly
July 1, 2015
>50
Monthly
January 1, 2015
[Additional Monitoring: For the purposes of this Condition 8.5.3.7, uncontrolled
actual emissions shall be evaluated on a rolling twelve month basis. When rolling
twelve month actual uncontrolled emissions increase such that a storage tank
becomes subject to a higher inspection frequency, the owner or operator shall
conduct the next inspection within 30 days of the discovery of the emission increase,
or at the time that next inspection was scheduled as per the previous inspection
frequency, whichever occurs first.]
d. Owners or operators are not required to monitor storage tanks and associated
equipment that are unsafe, difficult, or inaccessible to monitor, as defined in Section
XVII.C.1.e (Colorado Regulation No. 7, Section XVII.C.2.b.(iii)).
Recordkeeping
8.5.3.8 The owner or operator of each storage tank subject to Section XVII.C must maintain
records of STEM, if applicable, including the plan, any updates, and the certification,
and make them available to the Division upon request. In addition, the owner or
operator must maintain records of any required monitoring and make them available to
the Division upon request, including (Colorado Regulation No. 7, Section XVII.C.3.):
a. The AIRS ID for the storage tank (Section XVII.C.3.a.).
b. The date and duration of any period where the thief hatch, pressure relief device, or
other access point are found to be venting hydrocarbon emissions, except for
venting that is reasonably required for maintenance, gauging, or safety of personnel
and equipment (Section XVII.C.3.b.).
c. The date and duration of any period where the air pollution control equipment is
not operating (Section XVII.C.3.c.).
d. Where a combustion device is being used, the date and result of any EPA Method
22 test or investigation pursuant to Section XVII.C.1.d.(v) (Condition 8.5.3.4e)
(Section XVII.C.3.d.).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 103
e. The timing of and efforts made to eliminate venting, restore operation of air
pollution control equipment, and mitigate visible emissions (Section XVII.C.3.e.).
f. A list of equipment associated with the storage tank that is designated as unsafe,
difficult, or inaccessible to monitor, as described in Section XVII.C.1.e. (Condition
8.5.3.5), an explanation stating why the equipment is so designated, and the plan
for monitoring such equipment (Section XVII.C.3.f.).
8.5.3.9 [Additional Monitoring: The owner or operator shall maintain records that document
the hydrocarbon design destruction efficiency. Such records shall be maintained and
made available to the Division for review.]
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
9. F029 — Stabilized Condensate Truck Loadout, AIRS ID: 126
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 104
Parameter
Permit
Condition
Number
Limitations
Compliance Emission
Factor
Monitoring
Method
Interval
Emission & Throughput Limits
VOC
9.1
30.8 tons/year
5.14 lb/1,000 gal
Condensate
Throughput
9.2
285,714 bbl/year
Recordkeeping
and Twelve
Month Rolling
Total Calculation
Monthly
9.1 VOC Emission Limitations & Compliance Monitoring
Emissions of Volatile Organic Compounds (VOC) from condensate truck loading shall not exceed the
limitation listed in Summary Table 9 above (as modified under the provisions of Colorado Regulation No.
3, Part B, Section II.A.6 and Part C, Section X, based on requested emissions identified on the APEN
submitted on 4/2/2007). Compliance with the emission limitations shall be monitored as follows:
9.1.1 Monthly determination of VOC and HAP emissions shall be calculated by the end of the
subsequent month using the above emission factor and the monthly condensate throughput, as
required by Condition 9.2, in the equation below:
lb tons Emission Factor (1,000 gal) x Condensate Throughput (lmon h000 all
VOC Emissions (month) 2000 lb))
Unit Conversion ( ton
Monthly VOC emissions shall be used in a twelve month rolling total to monitor compliance with
the annual limitations. Each month, a new twelve month total shall be calculated using the
previous twelve months' data. Records of calculations shall be maintained and made available to
the Division upon request.
9.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the methods required by Condition 14 and used in a twelve
month rolling total to monitor compliance with the facility -wide HAP emission limitations.
9.2 Condensate Throughput Limitations & Compliance Monitoring
The condensate loadout throughput shall not exceed the limitation listed in Summary Table 9 above (as
modified under the provisions of Colorado Regulation No. 3, Part B, Section II.A.6 and Part C, Section
X, based on requested emissions identified on the APEN submitted on 4/2/2007). Sales or haul tickets
from each loading operation shall be used to monitor the volume of condensate transferred. The monthly
condensate throughput shall be the sum of the volume transferred, as indicated on each sales or haul ticket,
for all loading operations that took place during that month. The monthly condensate throughput shall be
used in a twelve month rolling total to monitor compliance with the annual limitations. Each month, a
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 105
new twelve month total shall be calculated using the previous twelve months' data. Records of calculations
shall be maintained and made available to the Division upon request.
This monthly condensate throughput shall be used in the calculation required by Condition 9.1 to monitor
compliance with the annual VOC and HAP emission limitations.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 106
10. F031 — Pressurized Liquids Loadout, AIRS ID: 133
Parameter
Permit
Condition
Number
Limitations
Compliance Emission Factor
Monitoring
Method
Interval
Emission & Throughput Limits
VOC
10.1
5.0
tons/year
Propane Loading: 0.79 lb/load
Butane Loading: 0.90 lb/load
Natural Gasoline Loading: 1.15 lb/load
Product
Throughput
10.2
Other Requirements
GC Analysis of
Natural Gasoline
10.3
8,670
loads/year
10.1 VOC Emission Limitations & Compliance Monitoring
Recordkeeping and
Twelve Month
Rolling Total
Calculation
Monthly
ASTM Methods or
Equivalent
See
Condition
10.3
Emissions of Volatile Organic Compounds (VOC) from pressurized liquids loading shall not exceed the
limitation listed in Summary Table 10 above. Compliance with the emission limitations shall be monitored
as follows:
10.1.1 Monthly determination of VOC and HAP emissions shall be calculated by the end of the
subsequent month using the above emission factors and the methodology specified below:
10.1.1.1 The following parameters shall be input to the equation below:
a. The number of trucks loading/unloading each species (propane, butane, natural
gasoline), as required by Condition 10.2.
b. The VOC or HAP content of each species loaded/unloaded, according to the table
below:
Species Transferred
VOC Content
HAP Content
Propane
100%
0%
Butane
100%
0%
Natural Gasoline
See Condition 10.3
See Condition 10.3
10.1.1.2 Monthly VOC and HAP emissions shall be calculated via the following equation:
(truck lb ( truck lb
tons __ N�.i lmonth� x EFL i (truck) x xi Nu,' kmonth) x — u i (truck x xi
VOC or IMP Emissions (+
(month 2000 Ib (2000 lb)
Each Service Unit Conversion ( ton ) Each Service Unit Conversion l ton
Where:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 107
NL = Number of trucks loaded for each species, i, truck/month
N� t = Number of trucks unloaded for each species, i, truck/month
EFL,i = Loading Emission Factor for each species, i,lb/load
EFU,t = Unloading Emission Factor for each species, i, lb/load
x; = VOC or HAP content for each species, i, mass fraction
i = Service designation (propane, butane, natural gasoline)
Monthly VOC emissions shall be used in a twelve month rolling total to monitor compliance with
the annual limitations. Each month, a new twelve month total shall be calculated using the
previous twelve months' data. Records of calculations shall be maintained and made available to
the Division upon request.
10.1.2 Facility -wide emissions of Hazardous Air Pollutants (I -TAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the same method as indicated above for VOC and used in a
twelve month rolling total to monitor compliance with the facility -wide HAP emission limitations.
10.2 Pressurized Loading Throughput Limitations & Compliance Monitoring
The number of trucks loaded each month at the pressurized liquids loadout shall not exceed the limitation
listed in Summary Table 10 above. Sales or haul tickets from each loading operation shall be used to
monitor the number of trucks loaded during each month. Additionally, the type of product species loaded
(propane, butane or natural gasoline) shall be recorded for each loading event, and shall be made available
to the Division upon request. The number of trucks loaded each month shall be used in a twelve month
rolling total to monitor compliance with the annual limitations. Each month, a new twelve month total
shall be calculated using the previous twelve months' data. Records of calculations shall be maintained
and made available to the Division upon request.
The truck traffic for each month shall be used to monitor compliance with the annual VOC and HAP
emission limitations as required by Condition 10.1.
10.3 GC Analysis of Natural Gasoline
A gas chromatography (GC) analysis of the natural gasoline shall be performed annually according to
appropriate ASTM methods, or equivalent, if approved in advance by the Division. The composition
indicated on the analysis may be used as a representative composition for all natural gasoline loading
completed within one year of the GC analysis. The GC analysis is not required for years during which
natural gasoline loading does not take place. For the purposes of HAP content determination, the hexanes+
constituent shall be assumed to be 100% n -hexane. Records of the GC analysis shall be maintained and
made available to the Division upon request.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 108
The VOC and HAP mass fraction of the natural gasoline shall be used to monitor compliance with the
annual VOC and HAP emission limitations as required by Condition 10.1.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
11.
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 109
FLARE — John Zink Company, LLC Plant Emergency Flare, AIRS ID: 141
Parameter
Permit
Condition
Number
Limitations
Emission Factor
Monitoring
Method
Interval
Emission & Throughput Limits
VOC
17.2 tons/year
Pilot Gas: 5.5 lb/IVLMSCF
Purge/Waste Gas:
Calculation
Twelve Month
Rolling Total
Calculation
Monthly
NOx
CO
11.2
3.6 tons/year
Pilot Gas: 100 lb/MMSCF
Purge/Waste Gas: 0.068
lb/NIIv1Btu
15.9 tons/year
Flare Gas
Throughput
Limitations
11.3
Other Requirements
Extended Gas
Analysis of
Flare Gas
Hours of
Operation
11.4
11.5
Opacity
11.5
Pilot Gas: 1.31 MMSCF/year
Purge/Waste Gas: 86.75 MMSCF/year
Not to exceed 30% for a period or
periods aggregating more than six (6)
minutes in any sixty (60) consecutive
minutes
Control
Device
Requirements
11.7
Pilot Gas: 84 lb/MMSCF
Purge/Waste Gas: 0.31
lb/MMBtu
See Condition 11.7
Twelve Month
Rolling Total
Calculation
Monthly
Meter and
Twelve Month
Rolling Total
Calculation
Monthly
ASTM
Methods or
Equivalent
Recordkeeping
Annually
Monthly
See Condition 11.5
Initial
Compliance
Requirements
11.8
See Condition 11.8
Statewide
Controls for
Oil and Gas
Operations
11.9
See Condition 11.9
40 CFR 60
Subpart A
§60.18 NSPS
11.10
See Condition 11.10
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
11.1 VOC Emission Limitations & Compliance Monitoring
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 110
Emissions of Volatile Organic Compounds (VOC) from the flare shall not exceed the limitations listed in
Summary Table 11 above (as provided for under the provisions of Section I, Condition 1.3 and Colorado
Regulation No.. 3, Part C, Section I.A.7 and Part C, Section III.B.7, based on requested emissions identified
on the APEN received 11/8/2018). Compliance with the emission limitations shall be monitored as
follows:
11.1.1 Monthly determination of VOC and HAP emissions shall be conducted by the end of the
subsequent month utilizing the following methodology:
11.1.1.1 Pilot Gas: VOC and HAP emissions contributed by the pilot gas destruction shall be
calculated using the above emission factor (from EPA's AP -42: Compilation of
Emission Factors, Section 1.4 for Natural Gas Combustion, Final Section, dated 7/98)
and the monthly pilot gas flowrate, as required by Condition 11.3, in the equation
below:
lb MMSCF)
VOC or HAP Emissions ( tons ) _ EF (MMSCF) x FRPEiat ( month
!monthUnit Conversion (20001b)
ton )
Where:
EF = Emission Factor, lb/MMSCF
FRp1iot = Flow Rate of Pilot Gas, MMSCF/month
11.1.1.2 Purge/Waste Gas: VOC and HAP emissions contributed by purge and waste gas
destruction shall be calculated using the monthly purge and waste gas flowrates, as
required by Condition 11.3, the molecular weight, and the VOC and HAP content of
the purge and waste gas obtained from the most recent extended analysis, as required
by Condition 11.4, in the equation below. A control efficiency of 95% shall apply to
the flare, provided the requirements of Conditions 11.7, 11.8 and 11.9 are met.
MMSCFIl lb l ( CE(%)
tons l FRpurge/waste ( month / X MWpurge/waste (lbmoll X xpurge/Waste X \1 100 )
VOC or HAP Emissions (month! 2000 lb MMSCF 379.5 SCF
Unit Conversion ( ton X 106 SCF X 1bmo1
Where:
FR pu,.gexas1e = Flow Rate of Purge or Waste Gas, MMSCF/month
MWpurge/waste = Molecular Weight of Purge or Waste Gas, lb/lbmol
xpurge/waste = Purge or Waste Gas VOC or HAP Content, mass fraction
CE = Control Efficiency of Flare, %a
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 111
Monthly VOC emissions shall be the sum total of the VOC contributions of the pilot, purge and
waste gases sent to the flare for each month. The monthly VOC emissions shall be used in a twelve
month rolling total to monitor compliance with the annual limitations. Each month, a new twelve
month total shall be calculated using the previous twelve months' data. Records of calculations
shall be maintained and made available to the Division upon request.
11.1.2 Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the annual facility -
wide limitations set forth in Condition 14. Monthly emissions of each HAP shall be calculated by
the end of the subsequent month with the same method as indicated above for VOC (for purge and
waste gas only) in conjunction with the method indicated in Condition 14 (for pilot gas only) and
used in a twelve month rolling total to monitor compliance with the facility -wide HAP emission
limitations. Monthly emissions of HAP shall be the sum total of the HAP contributions from the
pilot, purge and waste gases sent to the flare for each month.
11.2 NOx & CO Emission Limitations & Compliance Monitoring
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from the flare shall not exceed the
limitations listed in Summary Table 11 above (as provided for under the provisions of Section I, Condition
1.3 and Colorado Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7, based on requested
emissions identified on the APEN received 11/8/2018). Compliance with the emission limitations shall be
monitored as follows:
11.2.1 Monthly determination of NOx and CO emissions shall be conducted by the end of the subsequent
month utilizing the following methodology:
11.2.1.1 Pilot Gas: NOx and CO emissions contributed by the pilot gas combustion shall be
calculated using the above emission factors (from EPA's AP -42: Compilation of
Emission Factors, Section 1.4 for Natural Gas Combustion, Final Section, dated 7/98)
and the monthly pilot gas flowrate, as required by Condition 11.3, in the equation
below:
NOx or CO Emissions
( lb MMSCF
( tons l = EF IMMSCF) x FRpi•
cor k month
\monthl Unit Conversion (2000 Ib)
\ ton
Where:
EF = Emission Factor, lb/MMSCF
FRPaot = Flow Rate of Pilot Gas, MMSCF/month
11.2.1.2 Purge/Waste Gas: NOx and CO emissions contributed by purge and waste gas
destruction shall be calculated using the above emission factors (from EPA's AP -42:
Compilation of Emission Factors, Section 13.5 for Industrial Flares, Final Section,
dated 12/16), the monthly purge and waste gas flowrate, as required by Condition 11.3,
and the heat content of the purge and waste gas obtained from the most recent extended
analysis, as required by Condition 11.4, in the equation below:
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 112
lb Btu MMSCF
tons )= EF (MMBtu) X HCpurge/waste (SCF� X FRpurge/waste ( month
NOx or CO Emissions (month./ (2000 lb 106 Btu MMSCF)
Unit Conversion ` ton X MMBtu X 106 SCF)
Where:
EF = Emission Factor, lb/MMBtu
FRpurge/waste = Flow Rate of Purge or Waste Gas, MMSCF/month
HCpurge/waste = Heat Content of Purge or Waste Gas, Btu/SCF
Monthly NOx and CO emissions shall be the sum total of the NOx and CO contributions of the
pilot, purge and waste gases sent to the flare for that month. The monthly NOx and CO emissions
shall be used in a twelve month rolling total to monitor compliance with the annual limitations.
Each month, a new twelve month total shall be calculated using the previous twelve months' data.
Records of calculations shall be maintained and made available to the Division upon request.
11.3 Flare Gas Throughput Limitations & Compliance Monitoring
The amount of pilot, purge and waste gas sent to the plant emergency flare shall not exceed the limitations
listed in Summary Table 11 above (as provided for under the provisions of Section I, Condition 1.3 and
Colorado Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7, based on requested
limitations identified on the APEN received 11/8/2018). The pilot, purge and waste gas throughput to this
plant emergency flare shall be determined as follows:
11.3.1 Pilot Gas: The pilot gas throughput to the plant emergency flare shall be assumed to have a
constant value of 150 SCFH. Monthly pilot gas throughput shall be determined by multiplying this
hourly pilot gas throughput by the plant emergency flare monthly hours of operation, as required
by Condition 11.5. Records of the monthly pilot gas throughput calculation and the manufacturer
specification for the hourly pilot gas throughput shall be maintained and made available to the
Division upon request.
11.3.2 Purge/Waste Gas: The purge and waste gas combined throughput shall be continuously
monitored and recorded monthly using the existing flare header flowmeter. All purge and waste
gas streams routed to the plant emergency flare shall be introduced upstream of this meter. During
periods of flare operation, a purge gas flowrate of 5,417 SCFH shall be assumed at all times that
the metered value is below the detection level of the flare header flowmeter. Records of the flare
header flowmeter readings shall be maintained and made available to the Division upon request.
The monthly pilot, purge and waste gas throughput shall be used in a twelve month rolling total to monitor
compliance with the annual limitations. Each month, a new twelve month total shall be calculated using
the previous twelve months' data. Records of calculations shall be maintained and made available to the
Division upon request.
The monthly pilot, purge and waste gas throughput shall be used to monitor compliance with the annual
VOC, HAP, NOx and CO emission limitations, as required by Conditions 11.1 and 11.2.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
11.4 Extended Gas Analysis of Flare Gases
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 113
An extended gas analysis of the inlet and residue gas shall be performed annually according to appropriate
ASTM methods, or equivalent, if approved in advance by the Division (as provided for under the
provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part C, Section I.A.7 and Part C,
Section III.B.7). The extended analyses shall identify the relevant VOC and HAP constituents of the inlet
and residue gas.
The composition indicated by the extended gas analyses for the inlet and residue gas shall be used to
determine the heat content and VOC or HAP fractions for the pilot, purge and waste gases. The waste gas
is assumed to be a mixture of the inlet and residue gases. The pilot and purge gas composition is equivalent
to the residue gas composition. Results of the extended gas analyses shall be retained and made available
to the Division upon request.
The composition and heat content values obtained from the most recent extended analysis shall be used
to monitor compliance with the annual VOC, HAP, NOx and CO emission limitations, as required by
Conditions 11.1 and 11.2.
11.5 Hours of Operation
Hours of operation of the plant emergency flare shall be monitored and recorded monthly in a log to be
made available to the Division upon request. Monthly hours of operation shall be used to monitor
compliance with the annual pilot gas limitations, as required by Condition 11.3.
11.6 Opacity
The following opacity requirements apply to the plant emergency flare:
11.6.1 No owner or operator of a smokeless flare or other flare for the combustion of waste gases shall
allow or cause emissions into the atmosphere of any air pollutant which is in excess of 30% opacity
for a period or periods aggregating more than six minutes in any sixty consecutive minutes.
(Colorado Regulation No. 1, Section II.A.5).
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be presumed,
provided the requirements of Condition 11.7.3 is met.
11.7 Control Device Requirements
The following operating requirements apply to the plant emergency flare:
11.7.1 The flare shall be operated at all times when emissions are routed to it
11.7.2 The flare shall be operated with the pilot light present at all times. A flame detector shall
continuously monitor the presence of the pilot light. If the presence of a flame cannot be detected,
an auto -igniter shall automatically re -light the pilot. The pilot light shall be monitored as follows:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 114
11.7.2.1 Visual inspection of the pilot light shall be completed daily to verify pilot light
presence. A daily log with the results from the visual inspection shall be maintained
and made available to the Division upon request.
11.7.2.2 Records of pilot light outage events and the duration of such events shall be maintained
and made available to the Division upon request.
11.7.3 EPA Method 22 observations shall be conducted daily to determine whether visible emissions are
present for a period of at least one (1) minute in any fifteen (15) minute period of normal operation.
The results of the daily visual observations shall be kept on file and made available to the Division
upon request.
11.7.3.1 In the event visible emissions are observed, an EPA Reference Method 9 opacity
observation shall be performed to monitor compliance with the opacity standard. The
result(s) of the visual observations and the Method 9 observations shall be kept on file
and made available for Division review upon request.
a. The EPA Reference Method 9 opacity observations shall be performed by an
observer with a current and valid Method 9 certification. A clear and readable
copy of the observer's certificate and any opacity observations shall be kept on
file and made available to the Division for review upon request.
b. Subject to the provisions of §25-7-123.1, C.R.S., and in the absence of credible
evidence to the contrary, exceedance of the opacity limit (Condition 11.5) shall
be considered to exist from the time a Method 9 reading is taken that shows an
exceedance of the opacity limit until a Method 9 reading is taken that shows the
opacity is less than the opacity limit.
11.8 Initial Compliance Requirements
Self -Certification Requirements:
11.8.1 Within one hundred and eighty days (180) of the issuance of this permit, compliance with the
conditions contained in Section II Condition 11 of this permit shall be demonstrated to the
Division. It is the owner or operator's responsibility to self -certify compliance with the conditions.
Submittal of the next required semi-annual monitoring report shall serve as the self -certification
that the plant emergency flare is in compliance with the requirements of this permit. Failure to
demonstrate compliance within 180 days may result in revocation of the permit authorization for
the operation of the plant emergency flare. (Colorado Regulation No. 3, Part B, Section III.G.2).
State Requirements:
11.8.2 [State -Only Enforceable] The permit number and AIRS ID point number shall be marked on the
subject equipment for ease of identification. (Colorado Regulation Number 3, Part B, Section
III.E.)
Testing Requirements:
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 115
11.8.3 The operator shall complete an initial site specific extended gas analysis within one hundred and
eighty days (180) after issuance of this permit of the inlet and residue gas routed to the plant
emergency flare in order to verify the heat content and identify the relevant VOC and HAP
components (weight fraction). The volume from the flowmeters, along with a 95% DRE, shall be
used to demonstrate compliance with the emission limitations set forth in Condition 11.1. The heat
content indicated by the extended analyses and appropriate emission factors from AP -42 Sections
1.4 and 13.5 shall be used to demonstrate compliance with the emission limitations set forth in
Condition 11.2. The results of these extended gas analyses and compliance calculations shall be
submitted to the Division as part of the Self -Certification, as required by Condition 11.8.1
(Colorado Regulation No. 3, Part B, Section III.E).
11.9 Statewide Controls for Oil and Gas Operations
11.9.1 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.B. Requirements
The plant emergency flare is subject to the following State -Only Enforceable "General Provisions"
of Colorado Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas Operations and
Natural Gas -Fired Reciprocating Internal Combustion Engines":
Section XVII General Requirements
11.9.1.1 At all times, including periods of start-up and shutdown, the facility and air pollution
control equipment must be maintained and operated in a manner consistent with good
air pollution control practices for minimizing emissions. Determination of whether or
not acceptable operation and maintenance procedures are being used will be based on
information available to the Division, which may include, but is not limited to,
monitoring results, opacity observations, review of operation and maintenance
procedures, and inspection of the source. (Colorado Regulation No. 7, Section
XVILB.1.b.).
11.10 40 CFR Part 60, Subpart A 60.18 NSPS
The plant emergency flare is subject to the New Source Performance Standards requirements of Colorado
Regulation No. 6, Part A, Subpart A (40 CFR Part 60, Subpart A §60.18) "General Control Device and
Work Practice Requirements", including, but not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
A §60.18 published in the Federal Register on December 22, 2008. However, if revisions to this
Subpart are published at a later date, the owner or operator is subject to the requirements contained in
the revised version of. 40 CFR Part 60 Subpart A §60.18.
11.10.1Flares shall be designed for and operated with no visible emissions as determined by the methods
specified in paragraph (f) (Condition 11.10.6), except for periods not to exceed a total of 5 minutes
during any 2 consecutive hours (§60.18(c)(1)).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 116
11.10.2Flares shall be operated with a flame present at all times, as determined by the methods specified
in paragraph (f) (Condition 11.10.7) (§60.18(c)(2)).
11.10.3An owner/operator has the choice of adhering to either the heat content specifications
§60.18(c)(3)(ii) and the maximum tip velocity specifications in §60.18(c)(4), or adhering to the
requirements in §60.18(c)(3)(i) (§60.18(c)(3)).
11.10.4Owners or operators of flares used to comply with the provisions of this subpart shall monitor
these control devices to ensure that they are operated and maintained in conformance with their
designs. Applicable subparts will provide provisions stating how owners or operators of flares
shall monitor these control devices (§60.18(d)).
11.10.5Flares used to comply with provisions of this subpart shall be operated at all times when emissions
may be vented to them (§60.18(e)).
11.10.6Method 22 of appendix A to this part shall be used to determine the compliance of flares with the
visible emission provisions of this subpart. Theobservation period is 2 hours and shall be used
according to Method 22 (§60.18(f)(1)).
11.10.7The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent
device to detect the presence of a flame (§60.18(f)(2)).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055,
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 117
12. ECD — John Zink Company, LLC Enclosed Combustion Device (ECD)
RTO — Anguil Environmental Systems, Inc. Regenerative Thermal Oxidizer (RTO)
Parameter
Permit
Condition
Number
Limitations
ECD
RTO
Emission Factor
Monitoring
Method
Interval
Emission & Throughput Limits
NOx
CO
12.1
Pilot: 0.05 tons/year
P033: 0.04 tons/year
P-136: 0.9 tons/year
Total: 1.0 tons/year
Burner: 2.1 tons/year
P-136: 0.9 tons/year
P-137: 0.9 tons/year
Total: 3.9 tons/year
Pilot/Burner: 100
lb/MMSCF
Dehy Still Vents: See
Condition 5.2
Amine Acid Gas Vent:
See Condition 6.3
Pilot: 0.05 tons/year
P033: 0.2 tons/year
P-136: 4.0 tons/year
Total: 4.3 tons/year
Burner: 1.8 tons/year
P-136: 4.0 tons/year
P-137: 3.9 tons/year
Total: 9.7 tons/year
Pilot/Burner: 84
lbMIMSCF
Dehy Still Vents: See
Condition 5.2
Amine Acid Gas Vent:
See Condition 6.3
Twelve Month
Rolling Total
Calculation
Monthly
Pilot &
Burner Gas
Throughput
Limitations
12.2
Pilot: 0.44
MMSCF/year
Burner: 41.71
MMSCF/year
Meter and
Twelve Month
Rolling
Calculation
Monthly
Other Requirements
Extended
Analysis of
Burner Gas
12.3
Hours of
Operation
12.4
Opacity
12.4
ECD
Only:
Not to exceed 30% for a period or
periods aggregating more than six
(6) minutes in any sixty (60)
consecutive minutes
RTO
Only:
Not to exceed 20%, except as
provided for below:
For Certain Operational Activities -
Not to exceed 30% for a period or
periods aggregating more than six
(6) minutes in any sixty (60)
consecutive minutes
See Condition 12.6
ASTM
Methods or
Equivalent
Annually
Recordkeeping
Monthly
See. Condition 12.4
Control
Device
Requirements
12.6
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed:DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 118
Initial
Compliance
Requirements
12.7
RTO Only:
See Condition 12.7
Statewide
Controls for
Oil and Gas
Operations
12.8
See Condition 12.8
12.1 NOx & CO Emission Limitations & Compliance Monitoring
Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from the regenerative thermal oxidizer
(RTO) and enclosed combustion device (ECD) shall not exceed the limitations listed in Summary Table
12 above (Colorado Construction Permit 10WE1659, as modified under the provisions of Section I,
Condition 1.3 and Colorado Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7, based on
requested emissions identified on the APENs submitted on 9/22/2017 for P033 and 11/13/2017 for P-136
and P-137). Compliance with the emission limitations shall be monitored as follows:
12.1.1 Monthly determination of NOx and CO emissions shall be conducted by the end of the subsequent
month utilizing the following methodology:
12.1.1.1 The NOx and CO emissions from the dehydration units P033 and P-136 shall be
calculated using the methodology set forth in Condition 5.2.
12.1.1.2 The NOx and CO emissions from the amine sweetening unit P-137 shall be calculated
using the methodology set forth in Condition 6.3.
12.1.1.3 ECD only: The NOx and CO emissions contributed by the pilot gas combustion shall
be calculated using the above emission factors (from EPA's AP -42: Compilation of
Emission Factors, Section 1.4 for Natural Gas Combustion, Final Section, dated 7/98)
and the pilot gas flowrate, as required by Condition 12.2, in the equation below:
lb MMSCF
tons l _ EF (MMSCF x FRpaot ( month
NOx or CO Emissions r
\monthl Unit Conversion (2000 lb)
ton
Where:
EF = Emission Factor, lb/MMSCF
FRpitot = Flow Rate of Pilot Gas, MMSCF/month
12.1.1.4 RTO Only: NOx and CO emissions contributed by burner gas destruction shall be
calculated using the above emission factors (from EPA's AP -42: Compilation of
Emission Factors, Section 1.4 for Natural Gas Combustion, Final Section, dated 7/98)
and the burner gas flowrate, as required by Condition 12.2, in the equation below:
lb MMSCF
NOx or CO Emissions r tons l _ EF (MMSCF X FReurner ( month
(tons
(2000 lb)
Unit Conversion
ton I
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
Where:
EF = Emission Factor, lb/MMSCF
FRBu,,. = Flow Rate of Burner Gas, MMSCF/month
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 119
12.1.1.5 Monthly NOx and CO emissions for the ECD shall be the sum total of the emissions
contributed by the pilot gas (as calculated above), the dehydration unit P033 still vent
(as calculated in Condition 5.2) and the dehydration unit P-136 still vent (as calculated
in Condition 5.2).
12.1.1.6 Monthly NOx and CO emissions for the RTO shall be the sum total of the emissions
contributed by the burner gas (as calculated above), the amine sweetening unit P-137
acid gas vent (as calculated in Condition 6.3) and, when routed to the RTO, the
dehydration unit P-136 still vent (as calculated in Condition 5.2).
The monthly NOx and CO emissions shall be used in a twelve month rolling total to monitor
compliance with the annual limitations. Each month, a new twelve month total shall be calculated
using the previous twelve months' data. Records of calculations shall be maintained and made
available to the Division upon request.
12.2 Pilot / Burner Gas Throughput Limitations & Compliance Monitoring
12.2.1 ECD Only: The amount of pilot gas throughput to the ECD shall not exceed the limitations listed
in Summary Table 12 above. The pilot gas throughput to the ECD shall be assumed to have a
constant value of 50 SCFH. Monthly pilot gas throughput shall be determined by multiplying this
hourly pilot gas throughput by the ECD monthly hours of operation, as required by Condition 12.4.
Records of the monthly pilot gas throughput calculation and the manufacturer specification for the
hourly pilot gas throughput shall be maintained and made available to the Division upon request.
The monthly pilot gas throughput shall be used to demonstrate compliance with NOx and CO
emissions, as required by Condition 12.1.
12.2.2 RTO Only: The amount of burner gas throughput to the RTO shall not exceed the limitations
listed in Summary Table 12 above. The burner gas throughput to the RTO shall be calculated from
the full burner rating of 5 MMBtu/hr, the heat content of the burner gas, as required by Condition
12.3, and the RTO monthly hours of operation, as required by Condition 12.4. Records of the
monthly burner gas throughput calculation and the manufacturer specification for the burner rating
shall be maintained and made available to the Division upon request. The monthly burner gas
throughput shall be used to demonstrate compliance with NOx and CO emissions, as required by
Condition 12.1.
12.3 Extended Gas Analysis of Burner Gas
An extended gas analysis of the residue gas shall be performed annually according to appropriate ASTM
methods, or equivalent, if approved in advance by the Division.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 120
The composition indicated by the extended gas analysis for residue gas shall be used to determine the heat
content of the burner gas throughput to the RTO. The burner gascomposition is equivalent to the residue
gas composition. The burner gas heat content shall be used to monitor compliance with the burner gas
throughput limitation, as required by Condition 12.2. Results of the extended gas analyses shall be retained
and made available to the Division upon request.
12.4 Hours of Operation
12.4.1 ECD Only: Hours of operation of the ECD shall be monitored and recorded monthly in a log to
be made available to the Division upon request. Monthly hours of operation shall be used to
monitor compliance with the annual pilot throughput limitation, as required by Condition 12.2.
12.4.2 RTO Only: Hours of operation of the RTO shall be monitored and recorded monthly in a log to
be made available to the Division upon request. Monthly hours of operation shall be used to
monitor compliance with the annual burner gas throughput limitation, as required by Condition
12.2.
12.5 Opacity
12.5.1 The following opacity requirements apply to the enclosed combustion device (ECD) only:
12.5.1.1 No owner or operator of a smokeless flare or other flare for the combustion of waste
gases shall allow or cause emissions into the atmosphere of any air pollutant which is
in excess of 30% opacity for a period or periods aggregating more than six minutes in
any sixty consecutive minutes. (Colorado Regulation No. 1, Section II.A.5).
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be
presumed, provided the requirements of Conditions 12.6.1.5 and 12.8.3.2 are met.
12.5.2 The following opacity requirements apply to the regenerative thermal oxidizer (RTO) only:
12.5.2.1 Except as provided for in Condition 12.5.2.2 below, no owner or operator of a source
shall allow or cause the emission into the atmosphere of any air pollutant which is in
excess of 20% opacity (Colorado Regulation No. 1, Section II.A.1).
12.5.2.2 No owner or operator of a source shall allow or cause to be emitted into the atmosphere
any air pollutant resulting from the building of a new fire, cleaning of fire boxes, soot
blowing, start-up, process modifications, or adjustment or occasional cleaning of
control equipment which is excess of 30% opacity for a period or periods aggregating
more than six (6) minutes in any sixty (60) consecutive minutes (Colorado Regulation
No. 1, Section II.A.4).
In the absence of credible evidence to the contrary, compliance with the opacity limit shall be
presumed, provided the requirements of Conditions 12.6.2.4 and 12.8.3.2 are met.
12.6 Control Device Requirements
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 121
12.6.1 Enclosed Combustion Device (ECD): The following requirements apply to the operation of the
ECD:
12.6.1.1 The ECD shall be operated at all times when emissions are routed to it.
12.6.1.2 The ECD shall be operated with the pilot light present at all times. If the presence of a
flame cannot be detected, an auto -igniter shall automatically re -light the pilot. The pilot
light shall be monitored as follows:
a. Verification of pilot light presence shall be determined using a thermocouple or
equivalent heat sensing device. In the event the thermocouple or equivalent heat
sensing device cannot be used due to equipment malfunction, a visual inspection
conducted daily may be used as an alternate method to verify pilot light presence.
A daily log indicating the pilot light presence and method used to determine
presence shall be maintained and made available to the Division upon request.
b. Records of pilot light outage events and the duration of such events shall be
maintained and made available to the Division upon request.
12.6.1.3 The owner or operator shall complete a daily visual inspection of the auto -igniter and
valve for the piping of gas to the pilot light to ensure they are functioning properly. The
results of this daily visual inspection shall be kept on file and made available to the
Division upon request.
12.6.1.4 The owner or operator shall complete a daily visual inspection of the air pollution
control equipment to ensure that the valves for the piping from the dehydrator(s) P033
and/or P-136 to the air pollution control equipment are open. The results of this daily
visual inspection shall be kept on file and made available to the Division upon request.
12.6.1.5 EPA Method 22 observations shall be conducted daily to determine whether visible
emissions are present for a period of at least one (1) minute in any fifteen (15) minute
period of normal operation (Colorado Construction Permits 01WE0208 and
10WE1659). The results of the daily visual observations shall be kept on file and made
available to the Division upon request.
a. In the event visible emissions are observed, an EPA Reference Method 9 opacity
observation shall be performed to monitor compliance with the opacity standard.
The result(s) of the visual observations and the Method 9 observations shall be kept
on file and made available for Division review upon request.
(i) The EPA Reference Method 9 opacity observations shall be performed by an
observer with a current and valid Method 9 certification. A clear and readable
copy of the observer's certificate and any opacity observations shall be kept on
file and made available to the Division for review upon request.
(ii) Subject to the provisions of §25-7-123.1, C.R.S., and in the absence of credible
evidence to the contrary, exceedance of the opacity limit (Condition 12.5.1)
shall be considered to exist from the time a Method 9 reading is taken that shows
an exceedance of the opacity limit until a Method 9 reading is taken that shows
the opacity is less than the opacity limit,
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 122
12.6.2 Regenerative Thermal Oxidizer (RTO): The following requirements apply to the operation of
the RTO:
12.6.2.1 The RTO shall be operated at all times when emissions are routed to it.
12.6.2.2 The RTO shall be operated with a minimum combustion chamber temperature of
1450°F (Colorado Construction Permit 10WE1659). The combustion chamber
temperature shall be recorded daily. Manufacturer specifications and records of the
combustion chamber temperature reading shall be maintained and made available to
the Division upon request (Colorado Construction Permit 10WE1659).
12.6.2.3 The owner or operator shall complete a daily visual inspection of the air pollution
control equipment to ensure that the valves for the piping from the dehydrator P-136
and/or amine sweetening unit P-137 to the air pollution control equipment are open.
The results of this daily visual inspection shall be kept on file and made available to
the Division upon request.
12.6.2.4 EPA Method 22 observations shall be conducted daily to determine whether visible
emissions are present for a period of at least one (1) minute in any fifteen (15) minute
period of normal operation (Colorado Construction Permit lOWE1659). The results of
the daily visual observations shall be kept on file and made available to the Division
upon request.
a. In the event visible emissions are observed, an EPA Reference Method 9 opacity
observation shall be performed to monitor compliance with the opacity standard.
The result(s) of the visual observations and the Method 9 observations shall be kept
on file and made available for Division review upon request.
(i) The EPA Reference Method 9 opacity observations shall be performed by an
observer with a current and valid Method 9 certification. A clear and readable
copy of the observer's certificate and any opacity observations shall be kept on
file and made available to the Division for review upon request.
(ii) Subject to the provisions of §25-7-123.1, C.R.S., and in the absence of credible
evidence to the contrary, exceedance of the opacity limit (Condition 12.5.2)
shall be considered to exist from the time a Method 9 reading is taken that shows
an exceedance of the opacity limit until a Method 9 reading is taken that shows
the opacity is less than the opacity limit.
12.7 Initial Compliance Testing Requirements
The Regenerative Thermal Oxidizer (RTO) only is subject to the following initial testing requirements:
12.7.1 The owner or operator shall demonstrate compliance with opacity standards using EPA Method
22 to determine the presence or absence of visible emissions. "Visible Emissions" means
observations of smoke for any period or periods of duration greater than or equal to one (1) minute
in any fifteen (15) minute period during normal operation (Colorado Construction Permit
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 123
l 0WE1659, as modified under the provisions of Section I, Condition 1.3 and Colorado Regulation
No. 3, Part C, Section I.A.7 and Part C, Section III.B.7).
12.7.2 A source initial compliance test shall be conducted on the combined emission streams being routed
to the RTO to measure the emission rate(s) for the pollutants listed below in order to demonstrate
compliance with the emissions limits contained in this permit (Conditions 6.1 and 6.2). The test
shall include inlet and outlet testing for VOC in order to demonstrate compliance with the
minimum destruction efficiency of 97% for the RTO in addition to outlet testing for sulfur dioxide
(SO2). Any compliance test conducted to show compliance with a monthly or annual emission
limitation shall have the results projected up to the monthly or annual averaging time by
multiplying the test results by the allowable number of operating hours for that averaging time
(Colorado Construction Permit 10WE1659, as modified under the provisions of Section I,
Condition 1.3 and Colorado Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7).
The test protocol, test, and test report must be in accordance with the requirements of the APCD
Compliance Test Manual (https://www.colorado.gov/pacific/cdphe/air/compliance-enforcement).
A stack testing protocol shall be submitted for Division approval at least forty-five (45) calendar
days prior to any performance of the test required under this condition. In order to facilitate the
Division's ability to make plans to witness the test, notice of the date (s) for the stack test shall be
submitted to the Division at least thirty (30) calendar days prior to the test. The compliance test
results shall be submitted to the Division within forty-five (45) calendar days of the completion of
the test unless a longer period is approved by the Division.
12.7.2.1 This performance test shall be conducted at the permitted minimum combustion
chamber temperature of 1450°F, as indicated by Condition 12.6.2.2.
12.7.2.2 The following parameters shall be recorded during the performance testing and shall
be reported to the Division:
Parameter
P-136
P-137
RTO
Unit Inlet Gas Throughput
X
X
Lean Glycol Circulation Rate
X
Lean Amine Circulation Rate
X
Unit Inlet Sulfur Content
X
Unit Inlet Temperature
X
X
Unit Inlet Pressure
X
X
Flash Tank Operating Temperature
X
X
Flash Tank Operating Pressure
X
X
RTO Combustion Chamber Temperature
X
Supplemental Fuel Throughput
X
Burner Gas Throughput
X
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 124
12.7.3 Within one hundred eighty (180) days after startup of the RTO, compliance with the conditions
contained in this section shall be demonstrated to the Division. The operator shall complete the
initial opacity compliance demonstration, as required by Condition 12.7.1, and the initial stack
testing, as required by Condition 12.7.2, and submit the results to the Division as part of the next
required semi-annual monitoring report (Colorado Construction Permit lOWE1659, as modified
under the provisions of Section I, Condition 1.3 and Colorado Regulation No. 3, Part C, Section
I.A.7 and Part C, Section III.B.7)_
12.8 Statewide Controls for Oil and Gas Operations
The following requirements are applicable to the ECD and to the RTO at all times:
12.8.1 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.B. Requirements
Each control device is subject to the following State -Only Enforceable "General Provisions" of
Colorado Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas Operations and
Natural Gas -Fired Reciprocating Internal Combustion Engines":
Section XVII General Requirements
12.8.1.1 At all times, including periods of start-up and shutdown, the facility and air pollution
control equipment must be maintained and operated in a manner consistent with good
air pollution control practices for minimizing emissions. Determination of whether or
not acceptable operation and maintenance procedures are being used will be based on
information available to the Division, which may include, but is not limited to,
monitoring results, opacity observations, review of operation and maintenance
procedures, and inspection of the source (Colorado Regulation No. 7, Section
XVII.B.1.b.).
The following requirements are applicable to the ECD at all times, and to the RTO when emissions from
dehydration unit P-136 are routed to it, as monitored in Condition 5.8:
12.8.2 Colorado Regulation No. 7, Section XII.C. Requirements:
Each control device is subject to the following "General Requirements for Air Pollution Control
Equipment" of Colorado Regulation No. 7, Section XII, "Volatile Organic Compound Emissions
from Oil and Gas Operations":
12.8.2.1 All air pollution control equipment used to demonstrate compliance with this Section
XII. shall be operated and maintained consistent with manufacturer specifications and
good engineering and maintenance practices. The owner or operator shall keep
manufacturer specifications on file. In addition, all such air pollution control equipment
shall be adequately designed and sized to achieve the control efficiency rates required
by this Section XII and to handle reasonably foreseeable fluctuations in emissions of
volatile organic compounds. Fluctuations in emissions that occur when the separator
dumps into the tank are reasonably foreseeable (Colorado Regulation No. 7, Section
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 125
XII.C.1.a.).
12.8.3 [State -Only Enforceable] Colorado Regulation No. 7, Section XVII.B. Requirements
Each control device is subject to the following State -Only Enforceable "General Provisions" of
Colorado Regulation No. 7, Section XVII, "Statewide Controls for Oil and Gas Operations and
Natural Gas -Fired Reciprocating Internal Combustion Engines":
Section XVII General Requirements
12.8.3.1 All air pollution control equipment shall be operated and maintained pursuant to the
manufacturing specifications or equivalent to the extent practicable, and consistent
with technological limitations and good engineering and maintenance practices. The
owner or operator shall keep manufacturer specifications or equivalent on file. In
addition, all such air pollution control equipment shall be adequately designed and
sized to achieve the control efficiency rates and to handle reasonably foreseeable
fluctuations in emissions of VOCs and other hydrocarbons during normal operations.
Fluctuations in emissions that occur when the separator dumps into the tank are
reasonably foreseeable (Colorado Regulation No. 7, Section XVII.B.2.a.).
Section XVII Combustion Device Requirements
12.8.3.2
12.8.3.3
If a combustion device is used to control emissions of VOCs and other hydrocarbons,
it shall be enclosed, have no visible emissions during normal operation, and be designed
so that an observer can, by means of visual observation from the outside of the enclosed
combustion device, or by other means approved by the Division, determine whether it
is operating properly (Colorado Regulation No. 7, Section XVII.B.2.b.).
[Compliance Demonstration: In the absence of credible evidence to the contrary,
compliance with the no visible emissions requirement is presumed provided the
monitoring in Conditions 12.6.1.5 (for the ECD) and 12.6.2.4 (for the RTO) indicates
no visible emissions.]
Auto -igniters: All combustion devices used to control emissions of hydrocarbons must
be equipped with and operate an auto -igniter as follows (Colorado Regulation No. 7,
Section XVII.B.2.d.):
a. All combustion devices installed before May 1, 2014, must be equipped with an
operational auto -igniter by or before May 1, 2016, or after the next combustion
device planned shutdown, whichever comes first (Colorado Regulation No. 7,
Section XVII.B.2.d.(ii)).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
13. Kohler Model CV15S Methanol Pump
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 126
Parameter
Permit
Condition
Number
Limitation
Compliance
Emission Factor
Monitoring
Method
Interval
Other Requirements
Opacity
13.1
Not to exceed 20%, except as provided for
below:
For Certain Operational Activities - Not to
exceed 30% for a period or periods
aggregating more than six (6) minutes in any
sixty (60) consecutive minutes
EPA Method 9
Annually
40 CFR 63 Subpart
ZZZZ NESHAP
13.2
See Condition 13.2
40 CFR 63 Subpart A
General Provisions
NESHAP
13.3
See Condition 13.3
13.1 Opacity
The following opacity requirements apply to this engine:
13.1.1 Except as provided for in Condition 13.1.2 below, no owner or operator of a source shall allow or
cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity
(Colorado Regulation No. 1, Section II.A.1).
13.1.2 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air
pollutant resulting from the building of a new fire, cleaning of fire boxes, soot blowing, start-up,
process modifications, or adjustment or occasional cleaning of control equipment which is excess
of 30% opacity for a period or periods aggregating more than six (6) minutes in any sixty (60)
consecutive minutes (Colorado Regulation No. 1, Section II.A.4).
13.1.3 An EPA Reference Method 9 opacity observation shall be performed annually to monitor
compliance with the opacity limitations above (Condition 13.1.1 and 13.1.2). The results of the
Method 9 observations shall be kept on file and made available for Division review upon request.
13.1.3.1 The EPA Reference Method 9 opacity observations shall be performed by an observer
with a current and valid Method 9 certification. A clear and readable copy of the
observer's certificate and any opacity observations shall be kept on file and made
available to the Division for review upon request.
13.1.3.2 Subject to the provisions of §25-7-123.1, C.R.S., and in the absence of credible
evidence to the contrary, exceedance of the opacity limitations (Conditions 13.1.1 and
13.1.2) shall be considered to exist from the time a Method 9 reading is taken that
shows an exceedance of the opacity limit until a Method 9 reading is taken that shows
the opacity is less than the opacity limit.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
13.2 40 CFR Part 63, Subpart ZZZZ NESHAP
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 127
This engine is subject to the National Emissions Standards for Hazardous Air Pollutants requirements of
Regulation No. 8, Part E, Subpart ZZZZ (40 CFR Part 63, Subpart ZZZZ) "National Emissions Standards
for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines", including, but
not limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 63 Subpart
ZZZZ published in the Federal Register on 2/27/2014. However, if revisions to this Subpart are published
at a later date, the owner or operator is subject to the requirements contained in the revised version of 40
CFR Part 63 Subpart ZZZZ.
Note that as of the date of revised permit issuance XX/XXfXXXX, the requirements in 40 CFR Part 63
Subpart ZZZZ promulgated on March 3, 2010 and later have not been adopted into Colorado Regulation
No. 8, Part E by the Division and are therefore not state -enforceable. In the event that the Division adopts
these requirements, they will become both state and federally enforceable.
General Requirements
13.2.1 You must be in compliance with the emission limitations, operating limitations, and other
requirements in this subpart that apply to you at all times (§63.6605(a)).
13.2.2 At all times you must operate and maintain any affected source, including associated air pollution
control equipment and monitoring equipment, in a manner consistent with safety and good air
pollution control practices for minimizing emissions. The general duty to minimize emissions
does not require you to make any further efforts to reduce emissions if levels required by this
standard have been achieved. Determination of whether such operation and maintenance
procedures are being used will be based on information available to the Administrator which may
include, but is not limited to, monitoring results, review of operation and maintenance
procedures, review of operation and maintenance records, and inspection of the source
(§63.6605(b)).
Emission Limitations, Operating Limitations and Work Practices
13.2.3 If you own or operate an existing stationary RICE located at an area source of HAP emissions,
you must comply with the requirements in Table 2d to this subpart that apply to you
(§63.6603(a)):
13.2.3.1 Non -emergency, non -black start 4SRB stationary RICE <500 HP shall:
a. Change oil and filter every 1,440 hours of operation or annually, whichever comes
first (Table 2d, Item 10.a)
b. Inspect spark plugs every 1,440 hours of operation or annually, whichever comes
first, and replace as necessary (Table 2d, Item 10.b); and
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 128
c. Inspect all hoses and belts every 1,440 hours of operation or annually, whichever
comes first, and replace as necessary (Table 2d, Item 10.c).
Monitoring, Installation, Collection, Operation and Maintenance Requirements
13.2.4 You must operate and maintain the stationary RICE and after -treatment control device (if any)
according to the manufacturer's emission -related written instructions or develop your own
maintenance plan which must provide to the extent practicable for the maintenance and operation
of the engine in a manner consistent with good air pollution control practice for minimizing
emissions (§63.6625(e)).
13.2.5 If you operate a new, reconstructed, or existing stationary engine, you must minimize the engine's
time spent at idle during startup and minimize the engine's startup time to a period needed for
appropriate and safe loading of the engine, not to exceed 30 minutes, after which time the
emission standards applicable to all times other than startup in Table 2d (Condition 13.2.3.1) to
this subpart apply (§63.6625(h)).
Continuous Compliance Demonstration
13.2.6 You must demonstrate continuous compliance with each emission limitation, operating
limitation, and other requirements in Table 2d to this subpart that apply to you according to
methods specified in Table 6 to this subpart (§63.6640(a)):
13.2.6.1 Existing 4SRB stationary RICE ≤500 HP located at an area source of HAP shall:
a. Operate and maintain the stationary RICE according to the manufacturer's
emission -related operation and maintenance instructions (Table 6, Item 9.a.i); or
b. Develop and follow your own maintenance plan which must provide to the extent
practicable for the maintenance and operation of the engine in a manner consistent
with good air pollution control practice for minimizing emissions (Table 6, Item
9.a.ii).
13.2.7 You must report each instance in which you did not meet each emission limitation or operating
limitation in Table 2d (Condition 13.2.3.1) to this subpart that apply to you. These instances are
deviations from the emission and operating limitations in this subpart. These deviations must be
reported according to the requirements in §63.6650 (Condition 13.2.9). If you change your
catalyst, you must reestablish the values of the operating parameters measured during the initial
performance test. When you reestablish the values of your operating parameters, you must also
conduct a performance test to demonstrate that you are meeting the required emission limitation
applicable to your stationary RICE (§63.6640(b)).
13.2.8 You must also report each instance in which you did not meet the requirements in Table 8
(Condition 13.3) to this subpart that apply to you (§63.6640(e)).
Reporting Requirements
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 129
13.2.9 Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or
71 must report all deviations as defined in this subpart (Condition 13.2.7) _ in the semiannual
monitoring report required by 40 CFR 70.6 (a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A)
(§63.6650(f)).
Recordkeeping Requirements
13.2.10 If you must comply with the emission and operating limitations (Condition 13.2.3.1), you must
keep the records described in paragraphs §63.6655(a)(1) through (a)(5) of this subpart
(§63.6655(a)).
13.2.11 You must keep the records required in Table 6 (Condition 13.2.6.1) of this subpart to show
continuous compliance with each emission or operating limitation that applies to you
(§63.6655(d)).
13.2.12 You must keep records of the maintenance conducted on the stationary RICE in order to
demonstrate that you operated and maintained the stationary RICE and after -treatment control
device (if any) according to your own maintenance plan (§63.6655(e)).
13.2.13 Your records must be in a form suitable and readily available for expeditious review according
to §63.10(b)(1) (Condition 13.3.2) (§63.6660(a)).
13.2.14 As specified in §63.10(b)(1) (Condition 13.3.2), you must keep each record for 5 years following
the date of each occurrence, measurement, maintenance, corrective action, report, or record
(§63.6660(b)).
13.2.15You must keep each record readily accessible in hard copy or electronic form for at least 5 years
after the date of each occurrence, measurement, maintenance, corrective action, report, or record,
according to §63.10(b)(1) (Condition 13.3.2) (§63.6660(c)).
13.3 40 CFR Part 63, Subpart A NESHAP
This engine is subject to the requirements in 40 CFR Part 63 Subpart A "General Provisions", as adopted
by reference in Colorado Regulation No. 8, Part E, Section I as specified in 40 CFR Part 63 Subpart ZZZZ
§63.6665. These requirements include, but are not limited to, the following:
13.3.1 Prohibited activities and circumvention (§63.4)
13.3.2 Recordkeeping and reporting requirements (§63.10)
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
14. Facility -Wide Hazardous Air Pollutant (HAP) Emission Limits
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 130
Parameter
Permit
Condition
Number
Limitation
Compliance
p
Emission Factor
Monitoring
Method
Interval
Emission & Throughput Limits
HAP
14.1
8.0 tons/year single HAP
22.9 tons/year total HAP
See Condition
14.1.1
Recordkeeping and
Twelve Month
Rolling Total
Calculation
Monthly
Insignificant Activity
Tracking
14.2
See Condition 14.2
14.1 HAP Emission Limitations & Compliance Monitoring
Facility -wide emissions of Hazardous Air Pollutants (HAP) shall not exceed the facility -wide limitations
listed in Summary Table 14 above (Colorado Construction Permit 01WE0208, 07WE0988, 10WE1659,
12WE1193 and 12WE1242, as modified under the provisions of Section I, Condition 1.3 and Colorado
Regulation No. 3, Part C, Section I.A.7 and Part C, Section III.B.7). Compliance with the emission
limitations shall be monitored as follows:
14.1.1 Monthly emission calculations shall be completed for each HAP emitted at this facility. Point -
specific calculations of HAP emissions are outlined as follows:
14.1.1.1 For Natural Gas Fired Reciprocating Internal Combustion Engines:
a. Uncontrolled emission factors for each HAP shall be obtained from the most recent
edition of EPA's AP -42: Compilation of Emission Factors, Section 3.2 for Natural
Gas Fired Reciprocating Engines, Final Section, Table 3.2-3 "Uncontrolled
Emission Factors for 4 -Stroke Rich -Burn Engines".
b. The following control efficiencies (CE) shall be applied to the referenced HAP
species
Hazardous Air Pollutant 1 Control Efficiency
Formaldehyde
76%
Other HAP
50%
c. Monthly emissions of each HAP shall be calculated for each engine by the end of
the subsequent month using the above emission factors and control efficiencies
(CE), the monthly natural gas consumption (as required by Conditions 1.3 and 2.3)
and the heat content of the natural gas (as required by Conditions 1.4 and 2.4) in
the equation below:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 131
tons Emission Factor ( 1b MMBtu MMSCF CE(%))
MMBtu) x Heat Content (MMSCF x Fuel ` Use month ) ( 1 100 J
HAP Emissions
month
14.1.1.2 For Process Heaters:
Unit Conversion (200 ton
a Uncontrolled emission factors for each HAP shall be obtained from the most recent
edition of EPA's AP -42: Compilation of Emission Factors, Section 1.4 for Natural
Gas Combustion, Final Section, Table 1.4-3 "Emission Factors for Speciated
Organic Compounds from Natural Gas Combustion".
b. Monthly emissions of each HAP shall be calculated for each heater by the end of
the subsequent month using the above emission factors and the monthly natural gas
consumption (as required by Conditions 3.3 and 4.3) in the equation below:
tons l Emission Factor (MMMMSCF)
) x Fuel Use ( month
HAP Emissions (month/ 2000 lb
)
Unit Conversion ( ton
14.1.1.3 For TEG Dehydration Units:
a. See Condition 5.1.1
14.1.1.4 For Amine Sweetening Units:
a. See Condition 6.1.1
14.1.1.5 For Fugitive Emissions:
a. See Condition 7.1.3
14.1.1.6 For Stabilized Condensate Storage Tanks:
a. Controlled emission factors for each HAP shall be obtained from the following
table:
Hazardous Air Pollutant I
Emission Factor (lb/bbl)
n -Hexane
0.0010
Benzene
0.0002
Toluene
0.0005
Ethylbenzene
0.0001
Xylene
0.0004
b. Monthly emissions of each HAP shall be calculated by the end of the subsequent
month using the above emission factors and the monthly condensate throughput, as
required by Condition 8.2, in the equation below:
bbl tons l Emission Factor (bbl) x Condensate Throughput (month)
HAP Emissions (month/ 2000 lb
Unit Conversion ( ton )
14.1.1.7 For Stabilized Condensate Truck Loadout:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 132
a. Uncontrolled emission factors for each HAP shall be obtained from the following
table:
Hazardous Air Pollutant 1
Emission Factor (113/1,000 gal)
n -Hexane
0.51
Benzene
0.08
Toluene
0.23
Ethylbenzene
0.03
Xylene
0.18
b. Monthly emissions of each HAP shall be calculated by the end of the subsequent
month using the above emission factors and the monthly condensate throughput, as
required by Condition 9.2, in the equation below:
Emission Factor ( lb ) x Condensate Throughput (1,000 gall
tons _ 1,000 gal month )
HAP Emissions (month) 2000 lb)
Unit Conversion ( ton )
14.1.1.8 For Pressurized Liquids Loadout:
a. See Condition 10.1
14.1.1.9 For Plant Emergency Flare:
a. See Condition 11.1.1 for purge and waste gas only
b. For Pilot Gas Only:
(i) Uncontrolled emission factors (EF) for each HAP shall be obtained from the
most recent edition of EPA's AP -42: Compilation of Emission Factors, Section
1.4 for Natural Gas Combustion, Final Section, Table 1.4-3 "Emission Factors
for Speciated Organic Compounds from Natural Gas Combustion".
(ii) Monthly emissions of each HAP shall be calculated for the plant emergency
flare pilot gas by the end of the subsequent month using the above emission
factors and the monthly pilot gas flowrate (as required by Conditions 11.3) in
the equation below:
HAP Emissions
MMSCF\
r tons Emission Factor (MMSCF) x Fuel Use ( month )
\month) Unit Conversion (2000 lb)
ton i
c. Total emissions of each HAP for the plant emergency flare shall be the sum of the
HAP emissions from the waste, purge and pilot gases.
14.1.2 Determination of Compliance with the Facility -Wide Individual HAP Limit
14.1.2.1 Facility -wide emissions for an individual HAP shall be the sum total emissions of that
HAP from each point within the facility, including insignificant activities (as required
by Condition 14.2).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 133
Monthly emissions of each HAP shall be used in a twelve month rolling total to monitor
compliance with the individual HAP annual limitations. Each month, a new twelve
month total shall be calculated using the previous twelve months' data. Records of
calculations shall be maintained and made available to the Division upon request.
14.1.3 Determination of Compliance with the Facility -Wide Total HAP Limit
14.1.3.1 Facility -wide emissions for total HAP shall be the sum total of all HAP emitted from
any point within the facility, including insignificant activities (as required by Condition
14.2).
Monthly emissions of total HAP shall be used in a twelve month rolling total to monitor
compliance with the total HAP annual limitations. Each month, a new twelve month
total shall be calculated using the previous twelve months' data. Records of calculations
shall be maintained and made available to the Division upon request.
14.2 Insignificant Activity Tracking
The Potential -to -Emit (PTE) of each individual HAP from all insignificant activities, permitted points and
grandfathered points combined shall not exceed 10 tons per year. The PTE of total HAP emissions from
all insignificant activities, permitted points and grandfathered points combined shall not exceed 25 tons
per year. Compliance with the limitation shall be monitored by conducting a P lB analysis of HAP
emissions from all insignificant activities, permitted points and grandfathered points. This PTE analysis
shall be completed within 60 days of this permit issuance. The PTE for insignificant activities and
grandfathered points is normally estimated using the maximum design/emission rate of the unit and
assuming operation at 8760 hours per year. The PTE for the permitted points is based on the permitted
consumption/throughput limits. The PTE analysis shall be updated if any new insignificant activities that
can potentially emit HAP are added to this facility. In addition, the PTE analysis shall be reviewed once
per calendar year to assure all insignificant emission units are included, and verify that the emission
estimates are still suitable (e.g. check for updated emission factors).
The analysis, as well as the calculations and any supporting documentation, shall be retained on site and
made available to the Division upon request. For the purposes of this condition, insignificant activities
shall be defined as any activity or equipment which emits any amount of HAP but does not require an Air
Pollutant Emission Notice (APEN) or is exempt from the construction permitting requirements in
Colorado Regulation No. 3, Part B.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
15. Statewide Controls For Oil and Gas Operations — Compressors
15.1.1 Colorado Regulation No. 7, Section XII.C. Requirements:
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 134
Air pollution control equipment used to comply with the requirements of Section XII.J (Condition
15.1.2) is subject to the following "General Requirements for Air Pollution Control Equipment"
of Colorado Regulation No. 7, Section XII, "Volatile Organic Compound Emissions from Oil and
Gas Operations":
15.1.1.1 All air pollution control equipment used to demonstrate compliance with Section
XII.J.(Condition 15.1.2) must meet a control efficiency of at least 95%. Failure to
properly install, operate, and maintain air pollution control equipment at the locations
indicated in the Division -approved spreadsheet is a violation of this regulation
(Colorado Regulation No. 7, Section XII.C.1.c.).
15.1.1.2 If a flare or other combustion device is used to control emissions of volatile organic
compounds to comply with Section XII.J. (Condition 15.1.2) it shall be enclosed, have
no visible emissions, and be designed so that an observer can, by means of visual
observation from the outside of the enclosed flare or combustion device, or by other
convenient means, such as a continuous monitoring device, approved by the Division,
determine whether it is operating properly (Colorado Regulation No. 7, Section
XII.C.1.d.).
15.1.1.3 All combustion devices used to control emissions of volatile organic compounds to
comply with Section XII.J. (Condition 15.1.2) shall be equipped with and operate an
auto -igniter as follows (Colorado Regulation No. 7, Section XII.C.1.e.):
a. All combustion devices installed on or after January 1, 2018, and used to comply
with Sections XII.J (Condition 15.1.2) must be equipped with an operational auto
igniter upon installation of the combustion device (Colorado Regulation No. 7,
Section XII.C.1.e.(iv)).
15.1.2 Colorado Regulation No. 7, Section XII.J Requirements:
Each compressor is subject to the following "Compressor Requirements" of Colorado Regulation
No. 7, Section XII, "Volatile Organic Compound Emissions from Oil and Gas Operations":
Control Requirements
15.1.2.1 Beginning January 1, 2018, the rod packing on reciprocating compressors located
between the wellhead and the point of custody transfer to the natural gas transmission
and storage segment must be replaced every 26,000 hours of operation or every thirty
six (36) months (Colorado Regulation No. 7, Section XII.J.2.a.).
Owners or operators of reciprocating compressors located at a natural gas processing
plant and constructed before January 1, 2018, must:
a. Begin monitoring the hours of operation starting January 1, 2018; or (Colorado
Regulation No. 7, Section XII.J.2.a.(i)(A))
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 135
b. Conduct the first rod packing replacement required under Section XII.J.2. prior to
January 1, 2021 (Colorado Regulation No. 7, Section XII.J.2.a.(i)(B)).
15.1.2.2 As an alternative to the requirement described in Section XII.J.2.a. (Condition
15.1.2.1), beginning May 1, 2018, the owner or operator may collect rod packing
volatile organic compound emissions using a rod packing emissions collection system
that operates under negative pressure and routes the rod packing emissions through a
closed vent system to a process (Colorado Regulation No. 7, Section XII.J.2.b.).
a. The owner or operator must conduct annual visual inspections of the cover and
closed vent system for defects that could result in air emissions. Defects of the
closed vent system include, but are not limited to, visible cracks, holes, gaps in
piping, loose connections, liquid leaks, or broken or missing caps or other closure
devices. Defects of the cover include, but are not limited to, visible cracks, holes,
gaps in the cover or between the cover and separator wall, broken or damaged seals
or gaskets on closure devices, broken or missing hatches or other closure devices
(Colorado Regulation No. 7, Section XII.J.2.b.(i)).
b. The owner or operator must conduct annual EPA Method 21 inspections of the
cover and closed vent system to determine whether the cover and closed vent
system operates with volatile organic compound emissions less than 500 ppm
(Colorado Regulation No. 7, Section XII.J.2.b.(ii)).
c. In the event that a defect that could result in air emissions or leak is detected, the
owner or operator must make a first attempt to repair no later than five (5) days
after detecting the defect or leak and complete repair no later than thirty (30) days
after detecting the defect or leak (Colorado Regulation No. 7, Section
XII.J.2.b.(iii)).
d. Owners or operators may delay inspection or repair of a cover or closed vent system
if:
(i) Repair is technically infeasible without a shutdown. If shutdown is required, a
repair attempt must be made during the next scheduled shutdown and final
repair completed within two (2) years after discovery (Colorado Regulation No.
7, Section XII.J.2.b.(iv)(A)).
(ii) The cover or closed vent system is unsafe to inspect or repair because personnel
would be exposed to an immediate danger as a consequence of completing the
inspection or repair (Colorado Regulation No. 7, Section XII.J.2.b.(iv)(B)).
(iii)The cover or closed vent system is difficult to inspect or repair because
personnel must be elevated more than two (2) meters above a supported surface
or are unable to inspect or repair via a wheeled scissor -lift or hydraulic type
scaffold that allows access up to 7.6 meters (25 feet) above the ground
(Colorado Regulation No. 7, Section XII.J.2.b.(iv)(C)).
(iv)The cover or closed vent system is inaccessible to inspect or repair because the
cover or closed vent system is buried, insulated, or obstructed by equipment or
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 136
piping that prevents access (Colorado Regulation No. 7, Section
XII.J.2.b.(iv)(D)).
Recordkeeping Requirements
15.1.2.3 Owners or operators must maintain the following records for at least five (5) years and
make records available to the Division upon request (Colorado Regulation No. 7,
Section XII.J.2.c.(i)):
a. Identification of each reciprocating compressor (Colorado Regulation No. 7,
Section XII.J.2.c.(i)(A))
b. The hours of operation or the number of months since the previous rod packing
replacement, or a statement that emissions from the rod packing are being routed
to a process through a closed vent system under negative pressure (Colorado
Regulation No. 7, Section XII.J.2.c.(i)(B))
c. The date of each rod packing replacement, or date of installation of a rod packing
emissions collection system and closed vent system (Colorado Regulation No. 7,
Section XII.J.2.c.(i)(C))
d. Each cover and closed vent system inspection and any resulting responsive actions
(Colorado Regulation No. 7, Section XII.J.2.c.(i)(D)), and
e. Each cover or closed vent system on the delay of inspection or repair list, the reason
for and duration of the delay of inspection or repair, and the schedule for inspecting
or repairing such cover or closed vent system (Colorado Regulation No. 7, Section
XII.J.2.c.(i)(E)).
15.1.2.4 As an alternative to the inspection, repair, and recordkeeping provisions in Sections
XII.J.2.b. (Condition 15.1.2.2), XII.J.2.c.(i)(D) (Condition 15.1.2.3d), and
XII.J.2.c.(i)(E) (Condition 15.1.2.3e), the owner or operator may inspect, repair, and
document the cover and closed vent system in accordance with the leak detection and
repair program in Section XII.L., including the inspection frequency (Colorado
Regulation No. 7, Section XII.J.2.d.).
Alternate Compliance Option
15.1.2.5 As an alternative to the emission control, inspection, repair, and recordkeeping
provisions described in Sections XII.J.2.a. (Condition 15.1.2.1) through XII.J.2.d.
(Condition 15.1.2.4), the owner or operator may comply with reciprocating compressor
emission control, monitoring, recordkeeping, and reporting requirements of a New
Source Performance Standard in 40 CFR Part 60 (Colorado Regulation No. 7, Section
XII.J.2.e.).
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAF I
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 137
16. Compliance Assurance Monitoring (CAM) Requirements (ver 4/16/2009)
16.1 The Compliance Assurance Monitoring (CAM) requirements in 40 CFR Part 64, as adopted by reference
in Colorado Regulation No. 3, Part C, Section XIV, apply to the following units, pursuant to the referenced
conditions:
16.1.1 C-154, C-159, C-161, C-223, C-225, C-227 and C-192 —Natural Gas Fired Reciprocating Internal
Combustion Engines (Condition 1.9)
16.1.1.1 The permittee shall follow the CAM Plan provided in Appendix H.
16.1.1.2 Excursions, for the purposes of reporting, are defined as any instance for which the pre -
catalyst temperature is less than 750°F or greater than 1250°F.
16.1.2 C-181 - Natural Gas Fired Reciprocating Internal Combustion Engine (Condition 2.9)
16.1.2.1 The permittee shall follow the CAM Plan provided in Appendix H.
16.1.2.2 Excursions, for the purposes of reporting, are defined as any instance for which the pre -
catalyst temperature is less than 750°F or greater than 1250°F.
16.1.3 P-136 - Triethylene Glycol Dehydration Units (Condition 5.9)
16.1.3.1 The permittee shall follow the CAM Plan provided in Appendix H.
16.1.3.2 Excursions, for the purposes of reporting, are defined as any instance for which the
daily average combustion chamber temperature of the Regenerative Thermal Oxidizer
(RTO) is less than 1450°F, or any absence of the pilot light for the Enclosed
Combustion Device (ECD).
16.1.4 P-137 — Amine Sweetening Unit (Condition 6.9)
16.1.4.1 The permittee shall follow the CAM Plan provided in Appendix H.
16.1.4.2 Excursions, for the purposes of reporting, are defined as any instance for which the
daily average combustion chamber temperature of the Regenerative Thermal Oxidizer
(RTO) is less than 1450°F.
Excursions shall be reported as required by Section IV, Conditions 21 and 22.d of this permit.
16.2 Operation of Approved Monitoring
16.2.1 At all times, the owner or operator shall maintain the monitoring, including but not limited to,
maintaining necessary parts for routine repairs of the monitoring equipment (40 CFR Part 64 §
64.7(b), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.2.2 Except for, as applicable, monitoring malfunctions, associated repairs, and required quality
assurance or control activities (including, as applicable, calibration checks and required zero and
span adjustments), the owner or operator shall conduct all monitoring in continuous operation (or
shall collect data at all required intervals) at all times that the pollutant -specific emissions unit is
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 138
operating. Data recorded during monitoring malfunctions, associated repairs, and required quality
assurance or control activities shall not be used for purposes of these CAM requirements, including
data averages and calculations, or fulfilling a minimum data availability requirement, if applicable.
The owner or operator shall use all the data collected during all other periods in assessing the
operation of the control device and associated control system. A monitoring malfunction is any
sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data.
Monitoring failures that are caused in part by poor maintenance or careless operation are not
malfunctions (40 CFR Part 64 § 64.7(c), as adopted by reference in Colorado Regulation No. 3,
Part C, Section XIV).
16.2.3 Response to excursions or exceedances
16.2.3.1 Upon detecting an excursion or exceedance, the owner or operator shall restore
operation of the pollutant -specific emissions unit (including the control device and
associated capture system) to its normal or usual manner of operation as expeditiously
as practicable in accordance with good air pollution control practices for minimizing
emissions. The response shall include minimizing the period of any startup, shutdown
or malfunction and taking any necessary corrective actions to restore normal operation
and prevent the likely recurrence of the cause of an excursion or exceedance (other than
those caused by excused startup or shutdown conditions). Such actions may include
initial inspection and evaluation, recording that operations returned to normal without
operator action (such as through response by a computerized distribution control
system), or any necessary follow-up actions to return operation to within the indicator
range, designated condition, or below the applicable emission limitation or standard, as
applicable (40 CFR Part 64 § 64.7(d)(1), as adopted by reference in Colorado
Regulation No. 3, Part C, Section XIV).
16.2.3.2 Determination of whether the owner of operator has used acceptable procedures in
response to an excursion or exceedance will be based on information available, which
may include but is not limited to, monitoring results, review of operation and
maintenance procedures and records, and inspection of the control device, associated
capture system, and the process (40 CFR Part 64 § 64.7(d)(2), as adopted by reference
in Colorado Regulation No. 3, Part C, Section XIV).
16.2.4 After approval of the monitoring required under the CAM requirements, if the owner or operator
identifies a failure to achieve compliance with an emission limitation or standard for which the
approved monitoring did not provide an indication of an excursion or exceedance while providing
valid data, or the results of compliance or performance testing document a need to modify the
existing indicator ranges or designated conditions, the owner or operator shall promptly notify the
Division and, if necessary submit a proposed modification for this permit to address the necessary
monitoring changes. Such a modification may include, but is not limited to, reestablishing
indicator ranges or designated conditions, modifying the frequency of conducting monitoring and
collecting data, or the monitoring of additional parameters (40 CFR Part 64 § 64.7(e), as adopted
by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.3 Quality Improvement Plan (QIP) Requirements
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 139
16.3.1 Based on the results of a determination made under the provisions of Condition 16.2.3.2, the
Division may require the owner or operator to develop and implement a QIP (40 CFR Part 64 §
64.8(a), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.3.2 The owner or operator shall maintain a written QIP, if required, and have it available for inspection
(40 CFR Part 64 § 64.8(b)(1), as adopted by reference in Colorado Regulation No. 3, Part C,
Section XIV).
16.3.3 The QIP initially shall include procedures for evaluating the control performance problems and,
based on the results of the evaluation procedures, the owner or operator shall modify the plan to
include procedures for conducting one or more of the following actions, as appropriate:
16.3.3.1 Improved preventative maintenance practices (40 CFR Part 64 § 64.8(b)(2)(i), as
adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.3.3.2 Process operation changes (40 CFR Part 64 § 64.8(b)(2)(ii), as adopted by reference in
Colorado Regulation No. 3, Part C, Section XIV).
16.3.3.3 Appropriate improvements to control methods (40 CFR Part 64 § 64.8(b)(2)(iii), as
adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.3.3.4 Other steps appropriate to correct control performance (40 CFR Part 64 §
64.8(b)(2)(iv), as adopted by reference in Colorado Regulation No. 3, Part C, Section
XIV).
16.3.3.5 More frequent or improved monitoring (only in conjunction with one or more steps
under Conditions 16.3.3.1 through 16.3.3.4 above) (40 CFR Part 64 § 64.8(b)(2)(v), as
adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.3.4 If a QIP is required, the owner or operator shall develop and implement a QIP as expeditiously as
practicable and shall notify the Division if the period for completing the improvements contained
in the QIP exceeds 180 days from the date on which the need to implement the QIP was determined
(40 CFR Part 64 § 64.8(c), as adopted by reference in Colorado Regulation No. 3, Part C, Section
XIV).
16.3.5 Following implementation of a QIP, upon any subsequent determination pursuant to Condition
16.2.3.2, the Division or the U.S. EPA may require that an owner or operator make reasonable
changes to the QIP if the QIP is found to have:
16.3.5.1 Failed to address the cause of the control device performance problems (40 CFR Part
64 § 64.8(d)(1), as adopted by reference in Colorado Regulation No. 3, Part C, Section
XIV); or
16.3.5.2 Failed to provide adequate procedures for correcting control device performance
problems as expeditiously as practicable in accordance with good air pollution control
practices for minimizing emissions (40 CFR Part 64 § 64.8(d)(2), as adopted by
reference in Colorado Regulation No. 3, Part C, Section XIV).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Peanut # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 140
16.3.6 Implementation of a QIP shall not excuse the owner or operator of a source from compliance with
any existing emission limitation or standard, or any existing monitoring, testing, reporting or
recordkeeping requirement that may apply under federal, state, or local law, or any other applicable
requirements under the Federal Clean Air Act (40 CFR Part 64 § 64.8(e), as adopted by reference
in Colorado Regulation No. 3, Part C, Section XIV).
16.4 Reporting and Recordkeeping Requirements
16.4.1 Reporting Requirements: The reports required by Section IV, Condition 22.d, shall contain the
information specified in Appendix B of the permit and the following information, as applicable:
16.4.1.1 Summary information on the number, duration and cause (including unknown cause, if
applicable), for monitoring downtime incidents (other than downtime associated with
zero and span or other daily calibration checks, if applicable) ((40 CFR Part 64 §
64.9(a)(2)(ii), as adopted by reference in Colorado Regulation No. 3, Part C, Section
XIV); and
16.4.1.2 The owner or operator shall submit, if necessary, a description of the actions taken to
implement a QIP during the reporting period as specified in Condition 16.3 of this
permit. Upon completion of a QIP, the owner or operator shall include in the next
summary report documentation that the implementation of the plan has been completed
and reduced the likelihood of similar levels of excursions or exceedances occurring (40
CFR Part 64 § 64.9(a)(2)(iii), as adopted by reference in Colorado Regulation No. 3,
Part C, Section XIV).
16.4.2 General Recordkeeping Requirements: In addition to the recordkeeping requirements in Section
IV, Condition 22.a through c.
16.4.2.1 The owner or operator shall maintain records of any written QIP required pursuant to
Condition 16.3 and any activities undertaken to implement a QIP, and any supporting
information required to be maintained under these CAM requirements (such as data
used to document the adequacy of monitoring, or records of monitoring maintenance
or corrective actions) (40 CFR Part 64 § 64.9(b)(1), as adopted by reference in
Colorado Regulation No. 3, Part C, Section XIV).
16.4.2.2 Instead of paper records, the owner or operator may maintain records on alternative
media, such as microfilm, computer files, magnetic tape disks, or microfiche, provided
that the use of such alternative media allows for expeditious inspection and review, and
does not conflict with other applicable recordkeeping requirements (40 CFR Part 64 §
64.9(b)(2), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.5 Savings Provisions
16.5.1 Nothing in these CAM requirements shall excuse the owner or operator of a source from
compliance with any existing emission limitation or standard, or any existing monitoring, testing,
reporting or recordkeeping requirement that may apply under federal, state, or local law, or any
other applicable requirements under the Federal Clean Air Act. These CAM requirements shall
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
.................,.......... _...
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 141
not be used to justify the approval of monitoring less stringent than the monitoring which is
required under separate legal authority and are not intended to establish minimum requirements
for the purposes of determining the monitoring to be imposed under separate authority under the
Federal Clean Air Act, including monitoring in permits issued pursuant to Title I of the Federal
Clean Air Act. The purpose of the CAM requirements is to require, as part of the issuance of this
Title V operating permit, improved or new monitoring at those emissions units where monitoring
requirements do not exist or are inadequate to meet the requirements of CAM (40 CFR Part 64 §
64.10(a)(1), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.5.2 Nothing in these CAM requirements shall restrict or abrogate the authority of the U.S. EPA or the
Division to impose additional or more stringent monitoring, recordkeeping, testing or reporting
requirements on any owner or operator of a source under any provision of the Federal Clean Air
Act, including but not limited to sections 114(a)(1) and 504(b), or state law, as applicable (40 CFR
Part 64 § 64.10(a)(2), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV).
16.5.3 Nothing in these CAM requirements shall restrict or abrogate the authority of the U.S. EPA or the
Division to take any enforcement action under the Federal Clean Air Act for any violation of an
applicable requirement or of any person to take action under section 304 of the Federal Clean Air
Act (40 CFR Part 64 § 64.10(a)(2), as adopted by reference in Colorado Regulation No. 3, Part C,
Section XIV).
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
SECTION III - Permit Shield
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 142
Regulation No. 3, 5 CCR 1001-5, Part C, §& I.A.4, V.D. & XIII.B; § 25-7-114.4(3)(a), C.R.S.
1. Specific Non -Applicable Requirements
Based on the information available to the Division and supplied by the applicant, the following
parameters and requirements have been specifically identified as non -applicable to the facility to which
this permit has been issued. This shield does not protect the source from any violations that occurred
prior to or at the time of permit issuance. In addition, this shield does not protect the source from any
violations that occur as a result of any modifications or reconstruction on which construction
commenced prior to permit issuance.
Emission Unit
Description &
Number
Applicable Requirement
Justification
Compressor RICE
C-154, 155, 159,
157, 161, 158, 160,
156, 223, 225, 227,
Colorado Regulation No. 1 Section III.A.l.b
Internal combustion engines are not considered
fuel burning equipment for the purposes of the
referenced regulation.
181 and 192
These regulations are intended to apply to
Facility Wide
Colorado Regulation No. 7 Section VI.B.1
Colorado Regulation No. 7 Section VI.B.2
gasoline storage and loading facilities and are
therefore not applicable to condensate at a gas
plant.
This regulation requires storage tanks over
40,000 gallons to comply with selected
requirements from Colorado Regulation No. 7
Facility -Wide
Colorado Regulation No. 7 Section VII.C
Section VI. Section VI is intended to regulate
gasoline storage and loading facilities and is
therefore not applicable to condensate at a gas
plant.
2. General Conditions
Compliance with this Operating Permit shall be deemed compliance with all applicable requirements
specifically identified in the permit and other requirements specifically identified in the permit as not
applicable to the source. This permit shield shall not alter or affect the following:
2.1 The provisions of §§ 25-7-112 and 25-7-113, C.R.S., or § 303 of the federal act, concerning enforcement
in cases of emergency;
2.2 The liability of an owner or operator of a source for any violation of applicable requirements prior to or
at the time of permit issuance;
2.3 The applicable requirements of the federal Acid Rain Program, consistent with § 408(a) of the federal act;
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 143
2.4 The ability of the Air Pollution Control Division to obtain information from a source pursuant to §25-7-
111(2)(I), C.R.S., or the ability of the Administrator to obtain information pursuant to § 114 of the federal
act;
2.5 The ability of the Air Pollution Control Division to reopen the Operating Permit for cause pursuant to
Regulation No. 3, Part C, § XIII.
2.6 Sources are not shielded from terms and conditions that become applicable to the source subsequent to
permit issuance.
3. Stream -lined Conditions
The following applicable requirements have been subsumed within this operating permit using the
pertinent streamlining procedures approved by the U.S. EPA. For purposes of the permit shield,
compliance with the listed permit conditions will also serve as a compliance demonstration for purposes
of the associated subsumed requirements.
Permit Condition
Streamlined (Subsumed) Requirements
Section II, Condition 1.13.2
All engines except C-181: Colorado Regulation No. 7, Section XVII.B.2.a [general
good operation and maintenance practices] — State -Only Requirement
Section II, Conditions 3.2 and 4.2
Colorado Regulation No. 6, Part B, Section II.C.2 [fuel burning equipment particulate
matter requirement] — State -Only Requirement
Section II, Condition 14.1
Colorado Construction Permit 07WE0988 Condition 3 [formaldehyde limitation only]
Section IV, Conditions 22.b and c
Colorado Regulation No. 7, Section XVII.C.3 [requirement to maintain records for 2
years only] — State -Only Requirement
40 CFR Part 60 Subpart Dc NSPS [requirement to maintain records for 2 years only;
§60.48c(i))] — less stringent than 5 year Title V retention requirements
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 144
SECTION IV - General Permit Conditions (ver 8/28/2018)
1. Administrative Changes
Regulation No. 3, 5 CCR 1001-5, Part A, § IIL
The permittee shall submit an application for an administrative permit amendment to the Division for those permit changes
that are described in Regulation No. 3, Part A, § I.B.1. The permittee may immediately make the change upon
submission of the application to the Division.
2. Certification Requirements
Regulation No. 3, 5 CCR 1001-5, Part C, §§ III.B.9., V.C.16.a.& e. and V.C.17.
a. Any application, report, document and compliance certification submitted to the Air Pollution Control Division
pursuant to Regulation No. 3 or the Operating Permit shall contain a certification by a responsible official of the
truth, accuracy and completeness of such form, report or certification stating that, based on information and belief
formed after reasonable inquiry, the statements and information in the document are true, accurate and complete.
b. All compliance certifications for terms and conditions in the Operating Permit shall be submitted to the Air Pollution
Control Division at least annually unless -a more frequent period is specified in the applicable requirement or by the
Division in the Operating Permit.
c_ Compliance certifications shall contain:
(i) the identification of each permit term and condition that is the basis of the certification;
(ii) the compliance status of the source;
(iii) whether compliance was continuous or intermittent;
(iv) method(s) used for determining the compliance status of the source, currently and over the reporting
period; and
(v) such other facts as the Air Pollution Control Division may require to determine the compliance status of the
source.
d. All compliance certifications shall be submitted to the Air Pollution Control Division and to the Environmental
Protection Agency at the addresses listed in Appendix D of this Permit. -
e. If the permittee is required to develop and register a risk management plan pursuant to § 112(r) of the federal act, the
permittee shall certify its compliance with that requirement; the Operating Permit shall not incorporate the contents
of the risk management plan as a permit term or condition.
3. Common Provisions
Common Provisions Regulation, 5 CCR 1001-2 §§ II.A., II.B., 11.C., II.E., II.F., II.I, and 11.1
a. To Control Emissions Leaving Colorado
When emissions generated from sources in Colorado cross the State boundary line, such emissions shall not cause
the air quality standards of the receiving State to be exceeded, provided reciprocal action is taken by the receiving
State.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
b. Emission Monitoring Requirements
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 145
The Division may require owners or operators of stationary air pollution sources to install, maintain, and use
instrumentation to monitor and record emission data as a basis for periodic reports to the Division.
c. Performance Testing
The owner or operator of any air pollution source shall, upon request of the Division, conduct performance test(s)
and furnish the Division.a written report of the results of such test(s) in order to determine compliance with
applicable emission control regulations.
Performance test(s) shall be conducted and the data reduced in accordance with the applicable reference test
methods unless the Division:
(i) specifies or approves, in specific cases, the use of a test method with minor changes in methodology;
(ii) approves the use of an equivalent method;
(iii) approves the use of an alternative method the results of which the Division has determined to be adequate
for indicating where a specific source is in compliance; or
(iv) waives the requirement for performance test(s) because the owner or operator of a source has demonstrated
by other means to the Division's satisfaction that the affected facility is in compliance with the standard.
Nothing in this paragraph shall be construed to abrogate the Commission's or Division's authority to
require testing under the Colorado Revised Statutes, Title 25, Article 7, and pursuant to regulations
promulgated by the Commission.
Compliance test(s) shall be conducted under such conditions as the Division shall specify to the plant operator based
on representative performance of the affected facility. The owner or operator shall make available to the Division
such records as may be necessary to determine the conditions of the performance test(s). Operations during period of
startup, shutdown, and malfunction shall not constitute representative conditions of performance test(s) unless
otherwise specified in the applicable standard.
The owner or operator of an affected facility shall provide the Division thirty days prior notice of the performance
test to afford the Division the opportunity to have an observer present. The Division may waive the thirty day notice
requirement provided that arrangements satisfactory to the Division are made for earlier testing.
The owner or operator of an affected facility shall provide, or cause to be provided, performance testing facilities as
follows:
(i) Sampling ports adequate for test methods applicable to such facility;
(ii) Safe sampling platform(s);
(iii) Safe access to sampling platform(s); and
(iv) Utilities for sampling and testing equipment.
Each performance test shall consist of at least three separate runs using the applicable test method. Each run shall be
conducted for the time and under the conditions specified in the applicable standard. For the purpose of determining
compliance with an applicable standard, the arithmetic mean of results of at least three runs shall apply. In the event
that a sample is accidentally lost or conditions occur in which one of the runs must be discontinued because of
forced shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological conditions, or other
circumstances beyond the owner or operator's control, compliance may, upon the Division's approval, be
determined using the arithmetic mean of the results of the two other runs.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT.
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 146
Nothing in this section shall abrogate the Division's authority to conduct its own performance test(s) if so warranted.
Affirmative Defense Provision for Excess Emissions during Malfunctions
An affirmative defense to a claim of violation under these regulations is provided to owners and operators for civil
penalty actions for excess emissions during periods of malfunction. To establish the affirmative defense and to be
relieved of a civil penalty in any action to enforce an applicable requirement, the owner or operator of the facility
must meet the notification requirements below in a timely manner and prove by a preponderance of evidence that:
(i)
The excess emissions were caused by a sudden, unavoidable breakdown of equipment, or a sudden,
unavoidable failure of a process to operate in the normal or usual manner, beyond the reasonable control of
the owner or operator;
(ii) The excess emissions did not stem from any activity or event that could have reasonably been foreseen and
avoided, or planned for, and could not have been avoided by better operation and maintenance practices;
(iii) Repairs were made as expeditiously as possible when the applicable emission limitations were being
exceeded;
(iv) The amount and duration of the excess emissions (including any bypass) were minimized to the maximum
extent practicable during periods of such emissions;
(v) All reasonably possible steps were taken to minimize the impact of the excess emissions on ambient air
quality;
(vi) All emissions monitoring systems were kept in operation (if at all possible);
(vii) The owner or operator's actions during the period of excess emissions were documented by properly
signed, contemporaneous operating logs or other relevant evidence;
(viii) The excess emissions were not part of a recurring pattern indicative of inadequate design, operation, or
maintenance;
(ix) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions.
This section is intended solely to be a factor in determining whether an affirmative defense is available to
an owner or operator, and shall not constitute an additional applicable requirement; and
(x) During the period of excess emissions, there were no exceedances of the relevant ambient air quality
standards established in the Commissions' Regulations that could be attributed to the emitting source.
The owner or operator of the facility experiencing excess emissions during a malfunction shall notify the division
verbally as soon as possible, but no later than noon of the Division's next working day, and shall submit written
notification following the initial occurrence of the excess emissions by the end of the source's next reporting period.
The notification shall address the criteria set forth above.
The Affirmative Defense Provision contained in this section shall not be available to claims for injunctive relief.
The Affirmative Defense Provision does not apply to failures to meet federally promulgated performance standards
or emission limits, including, but not limited to, new source performance standards and national emission standards
for hazardous air pollutants. The affirmative defense provision does not apply to state implementation plan (sip)
limits or permit limits that have been set taking into account potential emissions during malfunctions, including, but
not necessarily limited to, certain limits with 30 -day or longer averaging times, limits that indicate they apply during
malfunctions, and limits that indicate they apply at all times or without exception.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
Circumvention Clause
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 147
A person shall not build, erect, install, or use any article, machine, equipment, condition, or any contrivance, the use
of which, without resulting in a reduction in the total release of air pollutants to the atmosphere, reduces or conceals
an emission which would otherwise constitute a violation of this regulation. No person shall circumvent this
regulation by using more openings than is considered normal practice by the industry or activity in question.
f. Compliance Certifications
For the purpose of submitting compliance certifications or establishing whether or not a person has violated or is in
violation of any standard in the Colorado State Implementation Plan, nothing in the Colorado State Implementation
Plan shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether
a source would have been in compliance with applicable requirements if the appropriate performance or compliance
test or procedure had been performed. Evidence that has the effect of making any relevant standard or permit term
more stringent shall not be credible for proving a violation of the standard or permit term.
g.
When compliance or non-compliance is demonstrated by a test or procedure provided by permit or other applicable
requirement, the owner or operator shall be presumed to be in compliance or non-compliance unless other relevant
credible evidence overcomes that presumption.
Affirmative Defense Provision for Excess Emissions During Startup and Shutdown
An affirmative defense is provided to owners and operators for civil penalty actions for excess emissions during
periods of startup and shutdown. To establish the affirmative defense and to be relieved of a civil penalty in any
action to enforce an applicable requirement, the owner or operator of the facility must meet the notification
requirements below in a timely manner and prove by a preponderance of the evidence that:
(1)
The periods of excess emissions that occurred during startup and shutdown were short and infrequent and
could not have been prevented through careful planning and design;
(ii) The excess emissions were not part of a recurring pattern indicative of inadequate design, operation or
maintenance;
(iii) If the excess emissions were caused by a bypass (an intentional diversion of control equipment), then the
bypass was unavoidable to prevent loss of life, personal injury, or severe property damage;
(iv) The frequency and duration of operation in startup and shutdown periods were minimized to the maximum
extent practicable;
(v) All possible steps were taken to minimize the impact of excess emissions on ambient air quality;
(vi) All emissions monitoring systems were kept in operation (if at all possible);
(vii) The owner or operator's actions during the period of excess emissions were documented by properly
signed, contemporaneous operating logs or other relevant evidence; and,
(viii) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions.
This subparagraph is intended solely to be a factor in determining whether an affirmative defense is
available to an owner or operator, and shall not constitute an additional applicable requirement.
The owner or operator of the facility experiencing excess emissions during startup and shutdown shall notify the
Division verbally as soon as possible, but no later than two (2) hours after the start of the next working day, and shall
submit written quarterly notification following the initial occurrence of the excess emissions. The notification shall
address the criteria set forth above.
The Affirmative Defense Provision contained in this section shall not be available to claims for injunctive relief.
Operating Permit 95OPWE055
First Issued: May 1, 2001
............._._..__.______..
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 148
The Affirmative Defense Provision does not apply to State Implementation Plan provisions or other requirements
that derive from new source performance standards or national emissions standards for hazardous air pollutants, or
any other federally enforceable performance standard or emission limit with an averaging time greater than twenty-
four hours. In addition, an affirmative defense cannot be used by a single source or small group of sources where
the excess emissions have the potential to cause an exceedance of the ambient air quality standards or Prevention of
Significant Deterioration (PSD) increments.
In making any determination whether a source established an affirmative defense, the Division shall consider the
information within the notification required above and any other information the Division deems necessary, which
may include, but is not limited to, physical inspection of the facility and review of documentation pertaining to the
maintenance and operation of process and air pollution control equipment.
4. Compliance Requirements
Regulation No. 3, 5 CCR 1001-5, Part C. §§ IILC.9., V.C.11. & 16.d. and § 25-7-122.1(2), C.R.S.
a. The permittee must comply with all conditions of the Operating Permit. Any permit noncompliance relating to
federally -enforceable terms or conditions constitutes a violation of the federal act, as well as the state act and
Regulation No. 3. Any permit noncompliance relating to state -only terms or conditions constitutes a violation of the
state act and Regulation No. 3, shall be enforceable pursuant to state law, and shall not be enforceable by citizens
under § 304 of the federal act. Any such violation of the federal act, the state act or regulations implementing either
statute is grounds for enforcement action, for permit termination, revocation and reissuance or modification or for
denial of a permit renewal application.
b. It shall not be a defense for a permittee in an enforcement action or a consideration in favor of a permittee in a
permit termination, revocation or modification action or action denying a permit renewal application that it would
have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of
the permit.
c. The permit may be modified, revoked, reopened, and reissued, or terminated for cause. The filing of any request by
the permittee for a permit modification, revocation and reissuance, or termination, or any notification of planned
changes or anticipated noncompliance does not stay any permit condition, except as provided in §§ X. and XI. of
Regulation No. 3, Part C.
d. The permittee shall furnish to the Air Pollution Control Division, within a reasonable time as specified by the
Division, any information that the Division may request in writing to determine whether cause exists for modifying,
revoking and reissuing, or terminating the permit or to determine compliance with the permit. Upon request, the
permittee shall also furnish to the Division copies of records required to be kept by the permittee, including
information claimed to be confidential. Any information subject to a claim of confidentiality shall be specifically
identified and submitted separately from information not subject to the claim.
e. Any schedule for compliance for applicable requirements with which the source is not in compliance at the time of
permit issuance shall be supplemental, and shall not sanction noncompliance with, the applicable requirements on
which it is based.
f. For any compliance schedule for applicable requirements with which the source is not in compliance at the time of
permit issuance, the permittee shall submit, at least every 6 months unless a more frequent period is specified in the
applicable requirement or by the Air Pollution Control Division, progress reports which contain the following:
(i)
dates for achieving the activities, milestones, or compliance required in the schedule for compliance, and
dates when such activities, milestones, or compliance were achieved; and
(ii) an explanation of why any dates in the schedule of compliance were not or will not be met, and any
preventive or corrective measures adopted.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
g.
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 149
The permittee shall not knowingly falsify, tamper with, or render inaccurate any monitoring device or method
required to be maintained or followed under the terms and conditions of the Operating Permit.
5. Emergency Provisions
Regulation No. 3, 5 CCR 1001-5, Part C, § VII
An emergency means any situation arising from sudden and reasonably unforeseeable events beyond the control of the
source, including acts of God, which situation requires immediate corrective action to restore normal operation, and
that causes the source to exceed the technology -based emission limitation under the permit due to unavoidable
increases in emissions attributable to the emergency. "Emergency" does not include noncompliance to the extent
caused by improperly designed equipment, lack of preventative maintenance, careless or improper operation, or
operator error. An emergency constitutes an affirmative defense to an enforcement action brought for
noncompliance with a technology -based emission limitation if the permittee demonstrates, through properly signed,
contemporaneous operating logs, or other relevant evidence that:
a. an emergency occurred and that the permittee can identify the cause(s) of the emergency;
b. the permitted facility was at the time being properly operated;
c. during the period of the emergency the permittee took all reasonable steps to minimize levels of emissions that
exceeded the emission standards, or other requirements in the permit; and
d. the permittee submitted oral notice of the emergency to the Air Pollution Control Division no later than noon of the
next working day following the emergency, and followed by written notice within one month of the time when
emissions limitations were exceeded due to the emergency. This notice must contain a description of the
emergency, any steps taken to mitigate emissions, and corrective actions taken.
This emergency provision is in addition to any emergency or malfunction provision contained in any applicable requirement.
6. Emission Controls for Asbestos
Regulation No. 8, 5 CCR 1001-10, Part B
The permittee shall not conduct any asbestos abatement activities except in accordance with the provisions of Regulation No.
8, Part B, "asbestos control."
7. Emissions Trading, Marketable Permits, Economic Incentives
Regulation No. 3, 5 CCR 1001-5, Part C, § V.C.13.
No permit revision shall be required under any approved economic incentives, marketable permits, emissions trading and
other similar programs or processes for changes that are specifically provided for in the permit.
8. Fee Payment
C.R.S §§ 25-7-114.1(6) and 25-7-114.7
a. The permittee shall pay an annual emissions fee in accordance with the provisions of C.R.S. § 25-7-114.7. A 1%
per month late payment fee shall be assessed against any invoice amounts not paid in full on the 91st day after the
date of invoice, unless a permittee has filed a timely protest to the invoice amount.
b. The permittee shall pay a permit processing fee in accordance with the provisions of C.R.S. § 25-7-114.7. If the
Division estimates that processing of the permit will take more than 30 hours, it will notify the permittee of its
estimate of what the actual charges may be prior to commencing any work exceeding the 30 hour limit.
c. The permittee shall pay an APEN fee in accordance with the provisions of C.R.S. § 25-7-114.1(6) for each APEN or
revised APEN filed.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
9. Fugitive Particulate Emissions
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 150
Regulation No. 1, 5 CCR 1001-3, § lII.D.l.
The permittee shall employ such control measures and operating procedures as are necessary to minimize fugitive particulate
emissions into the atmosphere, in accordance with the provisions of Regulation No. 1, § m.D.1.
10. Inspection and Entry
Regulation No. 3, 5 CCR 1001-5, Part C, § V.C.16.b.
Upon presentation of credentials and other documents as may be required by law, the permittee shall allow the Air Pollution
Control Division, or any authorized representative, to perform the following:
a. enter upon the permittee's premises where an Operating Permit source is located, or emissions -related activity is
conducted, or where records must be kept under the terms of the permit;
b. have access to, and copy, at reasonable times, any records that must be kept under the conditions of the permit;
c. inspect at reasonable times any facilities, equipment (including monitoring and air pollution control equipment),
practices, or operations regulated or required under the Operating Permit;
d. sample or monitor at reasonable times, for the purposes of assuring compliance with the Operating Permit or
applicable requirements, any substances or parameters.
11. Minor Permit Modifications
Regulation No. 3, 5 CCR 1001-5, Part C, $$ X. & XI.
The permittee shall submit an application for a minor permit modification before making the change requested in the
application. The permit shield shall not extend to minor permit modifications.
12. New Source Review
Regulation No. 3, 5 CCR 1001-5, Parts B & D
The permittee shall not commence construction or modification of a source required to be reviewed under the New Source
Review provisions of Regulation No. 3, Parts B and/or D, as applicable, without first receiving a construction permit.
13. No Property Rights Conveyed
Regulation No. 3, 5 CCR 1001-5, Part C, 4 V.C.11.d.
This permit does not convey any property rights of any sort, or any exclusive privilege.
14. Odor
Regulation No. 2, 5 CCR 1001-4, Part A
As a matter of state law only, the permittee shall comply with the provisions of Regulation No. 2 concerning odorous
emissions.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DR
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 151
15. Off -Permit Changes to the Source
Regulation No. 3, 5 CCR 1001-5, Part C, § XII.B.
The permittee shall record any off -permit change to the source that causes the emissions of a regulated pollutant subject to an
applicable requirement, but not otherwise regulated under the permit, and the emissions resulting from the change, including
any other data necessary to show compliance with applicable ambient air quality standards. The permittee shall provide
contemporaneous notification to the Air Pollution Control Division and to the Environmental Protection Agency at the
addresses listed in Appendix D of this Permit. The permit shield shall not apply to any off -permit change.
16. Opacity
Regulation No. 1, 5 CCR 1001-3, S§ I., H.
The permittee shall comply with the opacity emissions limitation set forth in Regulation No. 1, §§ I.- II.
17. Open Burning
Regulation No. 9, 5 CCR 1001-11
The permittee shall obtain a permit from the Division for any regulated open burning activities in accordance with provisions
of Regulation No. 9.
18. Ozone Depleting Compounds
Regulation No. 15, 5 CCR 1001-19
The permittee shall comply with the provisions of Regulation No. 15 concerning emissions of ozone depleting compounds.
Sections I., II.C., II.D., HI. IV., and V. of Regulation No. 15 shall be enforced as a matter of state law only.
19. Permit Expiration and Renewal
Regulation No. 3, 5 CCR 1001-5, Part C, §§ III.B.6., IV.C., V.C.2.
a. The permit term shall be five (5) years. The permit shall expire at the end of its term. Permit expiration terminates
the permittee's right to operate unless a timely and complete renewal application is submitted.
b. Applications for renewal shall be submitted at least twelve months, but not more than 18 months, prior to the
expiration of the Operating Permit. An application for permit renewal may address only those portions of the permit
that require revision, supplementing, or deletion, incorporating the remaining permit terms by reference from the
previous permit. A copy of any materials incorporated by reference must be included with the application.
20. Portable Sources
Regulation No. 3, 5 CCR 1001-5, Part C, §
Portable Source permittees shall notify the Air Pollution Control Division at least 10 days in advance of each change in
location.
21. Prompt Deviation Reporting
Regulation No. 3, 5 CCR 1001-5, Part C, § V.C.7.b.
The permittee shall promptly report any deviation from permit requirements, including those attributable to malfunction
conditions as defined in the permit, the probable cause of such deviations, and any corrective actions or preventive measures
taken.
"Prompt" is defined as follows:
Operating Permit 95OPWE055
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 152
a. Any definition of "prompt" or a specific timeframe for reporting deviations provided in an underlying applicable
requirement as identified in this permit; or
b. Where the underlying applicable requirement fails to address the time frame for reporting deviations, reports of
deviations will be submitted based on the following schedule:
(i)
For emissions of a hazardous air pollutant or a toxic air pollutant (as identified in the applicable regulation)
that continue for more than an hour in excess of permit requirements, the report shall be made within 24
hours of the occurrence;
(ii) For emissions of any regulated air pollutant, excluding a hazardous air pollutant or a toxic air pollutant that
continue for more than two hours in excess of permit requirements, the report shall be made within 48
hours; and
(iii) For all other deviations from permit requirements, the report shall be submitted every six (6) months,
except as otherwise specified by the Division in the permit in accordance with paragraph 22.d. below.
c. If any of the conditions in paragraphs b.i or b.ii above are met, the source shall notify the Division by telephone
(303-692-3155) or facsimile (303-782-0278) based on the timetables listed above. [Explanatory note: Notification
by telephone or facsimile must speck that this notification is a deviation report for an Operating Permit.] A
written notice, certified consistent with General Condition 2.a. above (Certification Requirements), shall be
submitted within 10 working days of the occurrence. All deviations reported under this section shall also be
identified in the 6 -month report required above.
"Prompt reporting" does not constitute an exception to the requirements of "Emergency Provisions" for the purpose of
avoiding enforcement actions.
22. Record Keeping and Reporting Requirements
Regulation No. 3, 5 CCR 1001-5, Part A, § II.; Part C, && V.C.6., V.C.7.
a. Unless otherwise provided in the source specific conditions of this Operating Permit, the permittee shall maintain
compliance monitoring records that include the following information:
(i) date, place as defined in the Operating Permit, and time of sampling or measurements;
(ii) date(s) on which analyses were performed;
(iii) the company or entity that performed the analysis;
(iv) the analytical techniques or methods used;
(v) the results of such analysis; and
(vi) the operating conditions at the time of sampling or measurement.
b. The permittee shall retain records of all required monitoring data and support information for a period of at least five
(5) years from the date of the monitoring sample, measurement, report or application. Support information, for this
purpose, includes all calibration and maintenance records and all original strip -chart recordings for continuous
monitoring instrumentation, and copies of all reports required by the Operating Permit. With prior approval of the
Air Pollution Control Division, the permittee may maintain any of the above records in a computerized form.
c. Permittees must retain records of all required monitoring data and support information for the most recent twelve
(12) month period, as well as compliance certifications for the past five (5) years on -site at all times. A permittee
shall make available for the Air Pollution Control Division's review all other records of required monitoring data
and support information required to be retained by the permittee upon 48 hours advance notice by the Division.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 153
The permittee shall submit to the Air Pollution Control Division all reports of any required monitoring at least every
six (6) months, unless an applicable requirement, the compliance assurance monitoring rule, or the Division requires
submission on a more frequent basis. All instances of deviations from any permit requirements must be clearly
identified in such reports.
The permittee shall file an Air Pollutant Emissions Notice ("APEN") prior to constructing, modifying, or altering
any facility, process, activity which constitutes a stationary source from which air pollutants are or are to be emitted,
unless such source is exempt from the APEN filing requirements of Regulation No. 3, Part A, § II.D. A revised
APEN shall be filed annually whenever a significant change in emissions, as defined in Regulation No. 3, Part A, §
II.C.2., occurs; whenever there is a change in owner or operator of any facility, process, or activity; whenever new
control equipment is installed; whenever a different type of control equipment replaces an existing type of control
equipment; whenever a permit limitation must be modified; or before the APEN expires. An APEN is valid for a
period of five years. The five-year period recommences when a revised APEN is received by the Air Pollution
Control Division. Revised APENs shall be submitted no later than 30 days before the five-year term expires.
Permittees submitting revised APENs to inform the Division of a change in actual emission rates must do so by
April 30 of the following year. Where a permit revision is required, the revised APEN must be filed along with a
request for permit revision. APENs for changes in control equipment must be submitted before the change occurs.
Annual fees are based on the most recent APEN on file with the Division.
23. Reopenings for Cause
Regulation No. 3, 5 CCR 1001-5, Part C, & XIII.
a. The Air Pollution Control Division shall reopen, revise, and reissue Operating Permits; permit reopenings and
reissuance shall be processed using the procedures set forth in Regulation No. 3, Part C, § 11L, except that
proceedings to reopen and reissue permits affect only those parts of the permit for which cause to reopen exists.
b. The Division shall reopen a permit whenever additional applicable requirements become applicable to a major
source with a remaining permit term of three or more years, unless the effective date of the requirements is later than
the date on which the permit expires, or unless a general permit is obtained to address the new requirements;
whenever additional requirements (including excess emissions requirements) become applicable to an affected
source under the acid rain program; whenever the Division determines the permit contains a material mistake or that
inaccurate statements were made in establishing the emissions standards or other terms or conditions of the permit;
or whenever the Division determines that the permit must be revised or revoked to assure compliance with an
applicable requirement.
c. The Division shall provide 30 days' advance notice to the permittee of its intent to reopen the permit, except that a
shorter notice may be provided in the case of an emergency.
d. The permit shield shall extend to those parts of the permit that have been changed pursuant to the reopening and
reissuance procedure.
24. Requirements for Major Stationary Sources
Regulation No. 3, 5 CCR 1001-5, Part D, V.A.7, VI.B.5 & VI.B.6
The following provisions apply to projects at existing emissions units at a major stationary source (other than projects at a
source with a PAL) that are not part of a major modification and where the owner or operator relies on projected actual
emissions. The definitions of baseline actual emissions, major modification, major stationary source, PAL, projected
actual emissions, regulated NSR pollutant and significant can be found in Regulation No. 3, Part D, § ILA.
a. Before beginning actual construction of the project, the owner or operator shall document and maintain a record of
the following information:
(i) a description of the project;
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 154
(ii) identification of the emissions unit(s) whose emissions of a regulated NSR pollutant could be affected by
the project; and
(iii) a description of the applicability test used to determine the project is not a major modification for any
regulated NSR pollutants, including the baseline actual emissions, the projected actual emissions, the
amount of emissions excluded and an explanation for why such amount was excluded, and any netting
calculations, if applicable.
b. The owner or operator shall monitor emissions of any regulated NSR pollutant that could increase as a result of the
project from any emissions units identified in paragraph a.(ii) and calculate and maintain a record of the annual
emissions, in tons per year on a calendar year basis, for a period of five (5) years following resumption of regular
operation after the change, or for a period of ten (10) years following resumption of regular operation after the
change if the project increases the design capacity or potential to emit of that regulated NSR pollutant at such
emissions unit.
c. For existing electric utility steam generating units the following requirements apply:
(i)
Before beginning actual construction, the owner or operator shall provide a copy of the information
required by paragraph a above to the Division. The owner or operator is not required to obtain a
determination from the Division prior to beginning actual construction.
(ii) The owner or operate shall submit a report to the Division within sixty days after the end of each year
during which records must be generated under paragraph b above setting out the unit's annual emissions
during the calendar year that preceded submission of the report.
d. For existing emissions units that are not electric utility steam generating units, the owner or operator shall submit a
report to the Division if the annual emissions from the project, in tons per year, exceed the baseline actual emissions
(documented and maintained per paragraph a(iii)) by a significant amount for that regulated NSR pollutant, and if
such emissions differ from the preconstruction projection (documented and maintained per paragraph a.(iii)). Such
report shall be submitted to the Division within sixty days after the end of such year. The report shall contain the
following:
(i) The name, address and telephone number of the owner or operator;
(ii) The annual emissions as calculated per paragraph b; and
(iii) Any other information that the owner or operator wishes to include in the report.
e. The owner of operation of the source shall make the information in paragraph a available for review upon request to
the Division or the general public.
25. Section 502(b)(10) Changes
Regulation No. 3, 5 CCR 1001-5, Part C, & XII.A.
The permittee shall provide a minimum 7 -day advance notification to the Air Pollution Control Division and to the
Environmental Protection Agency at the addresses listed in Appendix D of this Permit. The permittee shall attach a copy of
each such notice given to its Operating Permit.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural Gas Processing Plant
Page 155
26. Severability Clause
Regulation No. 3, 5 CCR 1001-5, Part C. & V.C.10.
In the event of a challenge to any portion of the permit, all emissions limits, specific and general conditions, monitoring,
record keeping and reporting requirements of the permit, except those being challenged, remain valid and enforceable.
27. Significant Permit Modifications
Regulation No. 3, 5 CCR 1001-5, Part C, § III.B.2.
The permittee shall not make a significant modification required to be reviewed under Regulation No. 3, Part B
("Construction Permit" requirements) without first receiving a construction permit. The permittee shall submit a complete
Operating Permit application or application for an Operating Permit revision for any new or modified source within twelve
months of commencing operation, to the address listed in Item 1 in Appendix D of this permit. If the permittee chooses to
use the "Combined Construction/Operating Permit" application procedures of Regulation No. 3, Part C, then the Operating
Permit must be received prior to commencing construction of the new or modified source.
28. Special Provisions Concerning the Acid Rain Program
Regulation No. 3,5 CCR 1001-5, Part C, 'S& V.C.1.b. & 8
a. Where an applicable requirement of the federal act is more stringent than an applicable requirement of regulations
promulgated under Title IV of the federal act, 40 Code of Federal Regulations (CFR) Part 72, both provisions shall
be incorporated into the permit and shall be federally enforceable.
b. Emissions exceeding any allowances that the source lawfully holds under Title IV of the federal act or the
regulations promulgated thereunder, 40 CFR Part 72, are expressly prohibited.
29. Transfer or Assignment of Ownership
Regulation No. 3, 5 CCR 1001-5, Part C, 'S II.C.
No transfer or assignment of ownership of the Operating Permit source will be effective unless the prospective owner or
operator applies to the Air Pollution Control Division on Division -supplied Administrative Permit Amendment forms, for
reissuance of the existing Operating Permit. No administrative permit shall be complete until a written agreement containing
a specific date for transfer of permit, responsibility, coverage, and liability between the permittee and the prospective owner
or operator has been submitted to the Division.
30. Volatile Organic Compounds
Regulation No. 7, 5 CCR 1001-9, §§ III & V.
The requirements in paragraphs a, b and e apply to sources located in an ozone non -attainment area or the Denver 1 -hour
ozone attainment/maintenance area. The requirements in paragraphs c and d apply statewide.
a. All storage tank gauging devices, anti -rotation devices, accesses, seals, hatches, roof drainage systems, support
structures, and pressure relief valves shall be maintained and operated to prevent detectable vapor loss except when
opened, actuated, or used for necessary and proper activities (e.g. maintenance). Such opening, actuation, or use
shall be limited so as to minimize vapor loss.
Detectable vapor loss shall be determined visually, by touch, by presence of odor, or using a portable hydrocarbon
analyzer. When an analyzer is used, detectable vapor loss means a VOC concentration exceeding 10,000 ppm.
Testing shall be conducted as in Regulation No. 7, Section VIII.C.3.
b. Except when otherwise provided by Regulation No. 7, all volatile organic compounds, excluding petroleum liquids,
transferred to any tank, container, or vehicle compartment with a capacity exceeding 212 liters (56 gallons), shall be
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit # 95OPWE055
DCP Operating Company, LP
Roggen Natural gas Processing Plant
Page 156
transferred using submerged or bottom filling equipment. For top loading, the fill tube shall reach within six inches
of the bottom of the tank compartment. For bottom -fill operations, the inlet shall be flush with the tank bottom.
c. The permittee shall not dispose of volatile organic compounds by evaporation or spillage unless Reasonably
Available Control Technology (RACT) is utilized.
d. No owner or operator of a bulk gasoline terminal, bulk gasoline plant, or gasoline dispensing facility as defined in
Colorado Regulation No. 7, Section VI, shall permit gasoline to be intentionally spilled, discarded in sewers, stored
in open containers, or disposed of in any other manner that would result in evaporation.
e. Beer production and associated beer container storage and transfer operations involving volatile organic compounds
with a true vapor pressure of less than 1.5 PSIA actual conditions are exempt from the provisions of paragraph b,
above.
31. Wood Stoves and Wood burning Appliances
Regulation No. 4, 5 CCR 1001-6
The permittee shall comply with the provisions of Regulation No. 4 concerning the advertisement, sale, installation, and use
of wood stoves and wood burning appliances.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Appendices
OPERATING PERMIT APPENDICES
A INSPECTION INFORMATION
B - MONITORING AND PERMIT DEVIATION REPORT
C - COMPLIANCE CERTIFICATION REPORT
D NOTIFICATION ADDRESSES
E - PERMIT ACRONYMS
F - PERMIT MODIFICATIONS
G - ENGINE AOS APPLICABILITY REPORTS
H - COMPLIANCE ASSURANCE MONITORING PLANS
*DISCLAIMER:
None of the information found in these Appendices shall be considered to be State or
Federally enforceable, except as otherwise provided in the permit, and is presented to assist
the source, permitting authority, inspectors, and citizens.
Operating Permit 95OPWE055 First Issued: May 1, 2001
'Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Inspection Information
APPENDIX A - Inspection Information
1. Directions to Plant:
Appendix A
Page 158
The facility address is 35409 Weld County Road 18, Roggen, Colorado. It is located in the southeast
quarter of Section 24, Township 2 North, Range 63 West, approximately 5 miles south of the town of
Roggen in Weld County.
2. Safety, Equipment Required:
Hard Hat
Safety Shoes (Steel -Toed Boots)
Hearing Protection
Eye Protection
Flame Retardant Clothing
3. Facility Plot Plan:
The attached Figure (following page) shows the plot plan as submitted in the Title V Modification
Application received by the Division on March 21, 2016.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Operating Permit 95OPWE055
/
k°./
• pa 0
°
• ti
§co
0
2/»
d
o • co
a §»
Air Pollution Control Division
Colorado Operating Permit
Inspection Information
Appendix A
Page 160
4. List of Insignificant Activities:
The following list of insignificant activities was provided by the source to assist in the understanding of
the facility layout. Since there is no requirement to update such a list, activities may have changed since
the last filing.
The asterisk (*) denotes an insignificant activity source category based on the size of the activity,
emissions levels fromthe activity or the production rate of the activity. The owner or operator of
individual emission points in insignificant activity source categories marked with an asterisk (*) must
maintain sufficient record keeping verifying that the exemption applies. Such records shall be made
available for Division review upon request. (Colorado Regulation No. 3, Part C, Section II.E)
*Colorado Regulation No. 3, Part C, Section II.E.3.a: Individual emission points in nonattainment
areas having uncontrolled actual emissions of any criteria pollutant (as defined in Section I.B.17. of Part
A of this Regulation Number 3) of less than one ton per year and individual emission points in attainment
or attainment/maintenance areas having uncontrolled actual emissions of any criteria pollutant of less
than two tons per year, and each individual emission point with uncontrolled actual emissions of lead
less than one hundred pounds per year, regardless of where the source is located.
• One (1) Tank Combustor Pilot Emissions
• One (1) C-154 Maintenance Blowdown Vent
• One (1) C-155 Maintenance Blowdown Vent
• One (1) C-156 Maintenance Blowdown Vent
• One (1) C-157 Maintenance Blowdown Vent
• One (1) C-158 Maintenance Blowdown Vent
• One (1) C-159 Maintenance Blowdown Vent
• One (1) C-160 Maintenance Blowdown Vent
• One (1) C-161 Maintenance Blowdown Vent
• One (1) C-181 Maintenance Blowdown Vent
• One (1) C-223 Maintenance Blowdown Vent
• One (1) C-225 Maintenance Blowdown Vent
• One (1) C-227 Maintenance Blowdown Vent
• One (1) C-192 Maintenance Blowdown Vent
• Atmospheric Blowdowns
• One (1) 500 gal Kerosene Tank
• One (1) 500 gal Diesel Tank
• One (1) 500 gal Dyed Diesel Tank
• One (1) 80 bbl Wastewater Tank (Sump 8)
• One (1) 80 bbl Stormwater Tank (Sump 5)
• Two (2) 80 bbl Slop Oil Tanks (Sump 5 & 9)
• Two (2) 10 bbl Slop Oil Tanks (Sump 7 & 10)
• One (1) 210 bbl Slop Oil Tank (Sump 12)
• One (1) 30 bbl Slop Oil Tank (Sump 4)
• One (1) 220 gal Slop Oil Tank/Air Compressor Sump
Operating Permit 95OPWE055
Air Pollution Control Division
Colorado Operating Permit
Inspection Information
Three (3) 1,000 gal Norkool Tanks (AST 7, 8 & 19)
One (1) 100 gal Portable Methanol Tank
• One (1) 500 gal Methanol Tank (Randel)
• One (1)500 gal Methanol Tank (Petro Frac)
• One (1) 500 gal Methanol Tank (212)
• One (1) 500 gal Methanol Tank (CIG)
• Two (2) 1,000 gal Methanol Tanks (AST 9 & 20)
• One (1) 4,000 gal TEG Tank (Tank 7210)
• One (1) 500 gal 1'EG Tank (AST 28)
• Two (2) 80,000 gal Pressurized Butane Storage Tanks
• One (1) 18,000 gal Pressurized Methanol Storage Tank
• One (1) 300 gal Unleaded Gasoline Tank
*Colorado Regulation No. 3, Part C, Section II.E.3.k: Each individual piece of fuel burning
equipment, other than smokehouse generators and internal combustion engines, that uses gaseous fuel,
and that has a design rate less than or equal to five million British thermal units per hour.
• One (1) 2.5 MMBtu/hr Broach Regen Heater
• One (1) 0.038 MMBtu/hr Hot Water Heater
Appendix A
Page 161
*Colorado Regulation No. 3, Part C, Section II.E.3.uu: Oil production wastewater (produced water
tanks), containing less than one percent by volume annual average crude oil, except for commercial
facilities that accept oil production wastewater for processing.
• Five (5) 80 bbl Produced Water Tanks (Sump 1, 2, 6, 14 and Tank 7213)
• Two (2) 200 bbl Produced Water Tanks (Tank 7209 & 7214)
*Colorado Regulation No. 3, Part C, Section II.E.3.zz: Storage of butane, propane, or liquefied
petroleum gas in a vessel with a capacity of less than sixty thousand gallons, provided the requirements
of Regulation Number 7, Section IV. are met, where applicable.
• Four (4) 30,000 gal Pressurized NGL Storage Tanks
• One (1) 30,000 gal Pressurized Propane Storage Tank
Colorado Regulation No. 3, Part C, Section II.E.3.aaa: Storage tanks of capacity less than forty
thousand gallons of lubricating oils or waste lubricating oils.
• One (1) 500 gal Scavenger Tank (AST -27)
• One (1) 240 bbl Lube Oil Tank (805 Central)
• One (1) 6,000 gal Lube Oil Tank (805 West)
• One (1) 500 gal Lube Oil Tank (AST -24)
• One (1) 500 gal Portable Used Oil Tank
• Three (3) 225 gal Used Oil Tanks(#1, #2 & #3)
• One (1) 110 bbl Used Oil Tank (AST -13)
Operating Permit 95OPWE055 ' First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Inspection Information
Appendix A
Page 162
Colorado Regulation No. 3, Part C, Section H.E.3.ggg: Each individual piece of fuel burning
equipment that uses gaseous fuel, and that has a design rate less than or equal to ten million British
thermal units per hour, and that is used solely for heating buildings for personal comfort.
• Two (2) 0.115 MMBtu/hr Office Heaters
• One (1) 0.02 MMBtu/hr Shop Heater
• One (1) 385,000 Btu/hr Hotsy Heater
• One (1) 12,000 Btu/hr Catco Heater (CIG Meter Shed)
• One (1) 12,000 Btu/hr Catco Heater (Excel Meter Shed)
• One (1) 12,000 Btu/hr CataDyne Heater (Box Elder Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (Bypass Gas Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (North Inlet Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (South Inlet Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (Low Pressure Inlet Meter Shed)
Colorado Regulation No. 3, Part C, Section II.E.3.nnn (iii): Stationary Internal Combustion Engines
that have uncontrolled actual emissions less than five tons per year or manufacturer's site -rated
horsepower of less than fifty.
• One (1) 16 hp Briggs & Stratton Vangaurde Hotsy Pump
NOTE: This engine is considered to be non -road and is therefore not subject to the stationary
source requirements in federal or state regulations for owners/operators of such equipment. It
was retained in the insignificant activities list to indicate this pump is allowed to be present on -
site.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
APPENDIX B
Reporting Requirements and Definitions
with codes ver 8/20/14
Appendix B
Page 163
Please note that, pursuant to 113(c)(2) of the federal Clean Air Act, any person who knowingly:
(A) makes any false material statement, representation, or certification in, or omits material information from,
or knowingly alters, conceals, or fails to file or maintain any notice, application, record, report, plan, or
other document required pursuant to the Act to be either filed or maintained (whether with respect to the
requirements imposed by the Administrator or by a State);
(B) fails to notify or report as required under the Act; or
(C) falsifies, tampers with, renders inaccurate, or fails to install any monitoring device or method required to
be maintained or followed under the Act shall, upon conviction, be punished by a fine pursuant to title 18
of the United States Code, or by imprisonment for not more than 2 years, or both. If a conviction of any
person under this paragraph is for a violation committed after a first conviction of such person under this
paragraph, the maximum punishment shall be doubled with respect to both the fine and imprisonment.
The permittee must comply with all conditions of this operating permit. Any permit noncompliance
constitutes a violation of the Act and is grounds for enforcement action; for permit termination,
revocation and reissuance, or modification; or for denial of a permit renewal application.
The Part 70 Operating Permit program requires three types of reports to be filed for all permits.
All required reports must be certified by a responsible official.
Report #1: Monitoring Deviation Report (due at least every six months)
For purposes of this operating permit, the Division is requiring that the monitoring reports are due
every six months unless otherwise noted in the permit. All instances of deviations from permit
monitoring requirements must be clearly identified in such reports.
For purposes of this operating permit, monitoring means any condition determined by observation, by
data from any monitoring protocol, or by any other monitoring which is required by the permit as well
as the recordkeeping associated with that monitoring. This would include, for example, fuel use or
process rate monitoring, fuel analyses, and operational or control device parameter monitoring.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
Appendix B
Page 164
Report #2: Permit Deviation Report (must be reported "promptly")
In addition to the monitoring requirements set forth in the permits as discussed above, each and every
requirement of the permit is subject to deviation reporting. The reports must address deviations from
permit requirements, including those attributable to malfunctions as defined in this Appendix, the
probable cause of such deviations, and any corrective actions or preventive measures taken. All
deviations from any term or condition of the permit are required to be summarized or referenced in the
annual compliance certification.
For purposes of this operating permit, "malfunction" shall refer to both emergency conditions and
malfunctions. Additional discussion on these conditions is provided later in this Appendix.
For purposes of this operating permit, the Division is requiring that the permit deviation reports are due
as set forth in General Condition 21. Where the underlying applicable requirement contains a definition
of prompt or otherwise specifies a time frame for reporting deviations, that definition or time frame shall
govern. For example, quarterly Excess Emission Reports required by an NSPS or Regulation No. 1,
Section IV.
In addition to the monitoring deviations discussed above, included in the meaning of deviation for the
purposes of this operating permit are any of the following:
(1) A situation where emissions exceed an emission limitation or standard contained in the permit;
(2) A situation where process or control device parameter values demonstrate that an emission limitation or
standard contained in the permit has not been met;
(3)
A situation in which observations or data collected demonstrates noncompliance with an emission
limitation or standard or any work practice or operating condition required by the permit; or,
(4) A situation in which an excursion or exceedance as defined in 40CFR Part 64 (the Compliance Assurance
Monitoring (CAM) Rule) has occurred. (only if the emission point is subject to CAM)
For reporting purposes, the Division has combined the Monitoring Deviation Report with the Permit Deviation
Report. All deviations shall be reported using the following codes:
1 = Standard:
2 = Process:
3 = Monitor:
4 = Test:
5 = Maintenance:
6 = Record:
7 = Report:
When the requirement is an emission limit or standard
When the requirement is a production/process limit
When the requirement is monitoring
When the requirement is testing
When required maintenance is not performed
When the requirement is recordkeeping
When the requirement is reporting
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
8 = CAM:
9 = Other:
Appendix B
Page 165
A situation in which an excursion or exceedance as defined in 40CFR Part 64 (the
Compliance Assurance Monitoring (CAM) Rule) has occurred.
When the deviation is not covered by any of the above categories
Report #3: Compliance Certification (annually, as defined in the permit)
Submission of compliance certifications with terms and conditions in the permit, including emission
limitations, standards, or work practices, is required not less than annually.
Compliance Certifications are intended to state the compliance status of each requirement of the permit
over the certification period. They must be based, at a minimum, on the testing and monitoring
methods specified in the permit that were conducted during the relevant time period. In addition, if the
owner or operator knows of other material information (i.e. information beyond required monitoring that
has been specifically assessed in relation to how the information potentially affects compliance status),
that information must be identified and addressed in the compliance certification. The compliance
certification must include the following:
The identification of each term or condition of the permit that is the basis of the certification;
• Whether or not the method(s) used by the owner or operator for determining the compliance status
with each permit term and condition during the certification period was the method(s) specified in
the permit. Such methods and other means shall include, at a minimum, the methods and means
required in the permit. If necessary, the owner or operator also shall identify any other material
information that must be included in the certification to comply with section 113(c)(2) of the
Federal Clean Air Act, which prohibits knowingly making a false certification or omitting material
information;
• The status of compliance with the terms and conditions of the permit, and whether compliance was
continuous or intermittent. The certification shall identify each deviation and take it into account
in the compliance certification. Note that not all deviations are considered violations.'
• Such other facts as the Division may require, consistent with the applicable requirements to which
the source is subject, to determine the compliance status of the source.
The Certification shall also identify as possible exceptions to compliance any periods during which
compliance is required and in which an excursion or exceedance as defined under 40 CFR Part 64 (the
1 For example, given the various emissions limitations and monitoring requirements to which a source may be
subject, a deviation from one requirement may not be a deviation under another requirement which recognizes an
exception and/or special circumstances relating to that same event.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
Appendix B
Page 166
Compliance Assurance Monitoring (CAM) Rule) has occurred. (only for emission points subject to
CAM)
Note the requirement that the certification shall identify each deviation and take it into account in the
compliance certification. Previously submitted deviation reports, including the deviation report
submitted at the time of the annual certification, may be referenced in the compliance certification.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
Startup, Shutdown, Malfunctions and Emergencies,
Appendix B
Page 167
Understanding the application of Startup, Shutdown, Malfunctions and Emergency Provisions, is very important
in both the deviation reports and the annual compliance certifications.
Startup, Shutdown, and Malfunctions
Please note that exceedances of some New Source Performance Standards (NSPS) and Maximum Achievable
Control Technology (MACT) standards that occur during Startup, Shutdown or Malfunctions may not be
considered to be non-compliance since emission limits or standards often do not apply unless specifically stated
in the NSPS. Such exceedances must, however, be reported as excess emissions per the NSPS/MACT rules and
would still be noted in the deviation report. In regard to compliance certifications, the permittee should be
confident of the information related to those deviations when making compliance determinations since they are
subject to Division review. The concepts of Startup, Shutdown and Malfunctions also exist for Best Available
Control Technology (BACT) sources, but are not applied in the same fashion as for NSPS and MACT sources.
Emergency Provisions
Under the Emergency provisions of Part 70 certain operational conditions may act as an affirmative defense
against enforcement action if they are properly reported.
DEFINITIONS
Malfunction (NSPS) means any sudden, infrequent, and not reasonably preventable failure of air pollution
control equipment, process equipment, or a process to operate in a normal or usual manner. Failures that are
caused in part by poor maintenance or careless operation are not malfunctions.
Malfunction (SIP) means any sudden and unavoidable failure of air pollution control equipment or process
equipment or unintended failure of a process to operate in a normal or usual manner. Failures that are primarily
caused by poor maintenance, careless operation, or any other preventable upset condition or preventable
equipment breakdown shall not be considered malfunctions.
Emergency means any situation arising from sudden and reasonably unforeseeable events beyond the control of
the source, including acts of God, which situation requires immediate corrective action to restore normal
operation, and that causes the source to exceed a technology -based emission limitation under the permit, due to
unavoidable increases in emissions attributable to the emergency. An emergency shall not include noncompliance
to the extent caused by improperly designed equipment, lack of preventative maintenance, careless or improper
operation, or operator error.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
APPENDIX B:
Monitoring and Permit Deviation Report - Part I
Appendix B
Page 168
1. Following is the required format for the Monitoring and Permit Deviation report to be submitted to the
Division as set forth in General Condition 21. The Table below must be completed for all equipment or
processes for which specific Operating Permit terms exist.
2. Part II of this Appendix B shows the format and information the Division will require for describing
periods of monitoring and permit deviations, or malfunction or emergency conditions as indicated in the
Table below. One Part II Form must be completed for each Deviation. Previously submitted reports (e.g.
EER's or malfunctions) may be referenced and the form need not be filled out in its entirety.
FACILITY NAME: DCP Operating Company, LP - Roggen Natural Gas Processing Plant
OPERATING PERMIT NO: 95OPWE055
REPORTING PERIOD: (see first page of the permit for specific reporting period and dates)
Operating
p g
Permit Unit
ID
Unit Description
Deviations noted
During Period? t
2
Deviation CodeCondition
Malfunction/Emergency
Reported
During Period?
YES
NO
e psi%.
YES
NO
C-154
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,100 hp
C-155
Waukesha Model L7042 GU Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 806 hp
C-159
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,350 hp
C-157
Waukesha Model L7042 GU Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 806 hp
C-161
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,350 hp
C-158
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 916 hp
C-160
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
Appendix B
Page 169
Operating
Permit Unit
ID
Unit Description
p
Deviations noted
During Period?'
Deviation Code 2
Malfunction/Emergency
Condition Reported
During Period?
YES
NO
S ,W i%,
YES
NO
C-156
Waukesha Model L7042 GU Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 806 hp
C-223
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 720 hp
C-225
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Rated at 800 hp
C-227
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 720 hp
P025
Fugitive Emissions from Equipment Leaks
P039
Eight (8) 300 bbl Stabilized Condensate Storage
Tanks
F029
Stabilized Condensate Truck Loadout, 285,714 bbl/yr
throughput
H037
Heat Recovery Corp. Hot Oil Heater, Natural Gas
Fired, Rated at 7.55 MMBtu/hr
P033
Triethylene Glycol Dehydration Unit, Rated at 4
MMSCFD, 3.5 gpm TEG recirculation rate
F031
Pressurized Liquids Loadout
C-181
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,478 hp
P-136
Evco Fabrication Model T-901 Triethylene Glycol
Dehydration Unit, Rated at 85 MMSCFD, 24 gpm
TEG recirculation rate
P-137
Evco Fabrication Model T-9002 Amine Sweetening
Unit, Rated at 85 MMSCFD, 350 gpm lean amine
recirculation rate
P-138
Optimized Process Furnaces, Inc., Model H-7201 Hot
Oil Heater, Natural Gas Fired, equipped with Low
NOx burners, Rated at 30.7 MMBtu/hr
C-192
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,478 hp
FLARE
John Zink Model Kaldair P-684 Plant Emergency
Flare for Maintenance and Malfunctions
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
Appendix B
Page 170
Operating
Permit Unit
ID
General
Conditions
Insignificant
Activities
Unit Description
Deviations noted
During Period?'
Deviation Code 2
Malfunction/Emergency
Condition Reported
During Period?
YES
NO
YES
NO
i See previous discussion regarding what is considered to be a deviation. Determination of whether or not a deviation has occurred shall
be based on a reasonable inquiry using readily available information.
2 Use the following entries, as appropriate
1 = Standard:
2 = Process:
3 = Monitor:
4 = Test:
5 = Maintenance:
6 = Record:
7 = Report:
8=CAM:
9 = Other:
When the requirement is an emission limit or standard
When the requirement is a production/process limit
When the requirement is monitoring
When the requirement is testing
When required maintenance is not performed
When the requirement is recordkeeping
When the requirement is reporting
A situation in which an excursion or exceedance as defined in 40CFR Part 64 (the
Compliance Assurance Monitoring (CAM) Rule) has occurred.
When the deviation is not covered by any of the above categories
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
APPENDIX B:
Monitoring and Permit Deviation Report - Part II
FACILITY NAME: DCP Operating Company, LP - Roggen Natural Gas Processing Plant
OPERATING PERMIT NO: 95OPWE055
REPORTING PERIOD:
Is the deviation being claimed as an: Emergency Malfunction _
(For NSPS/MACT) Did the deviation occur during: Startup Shutdown
Normal Operation
OPERATING PERMIT UNIT IDENTIFICATION:
Operating Permit Condition Number Citation
Explanation of Period of Deviation
Duration (start/stop date & time)
Action Taken to Correct the Problem
Measures Taken to Prevent a Reoccurrence of the Problem
Dates of Malfunctions/Emergencies Reported (if applicable)
Deviation Code Division Code QA:
Appendix B
Page 171
N/A
Malfunction
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
SEE EXAMPLE ON THE NEXT PAGE
Appendix B
Page 172
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
EXAMPLE
FACILITY NAME: Acme Corp.
OPERATING PERMIT NO: 96OPZZXXX
REPORTING PERIOD: 1/1/04 - 6/30/06
Is the deviation being claimed as an:
(For NSPS/MACT) Did the deviation occur during:
Emergency
Appendix B
Page 173
Malfunction XX N/A
Startup Shutdown Malfunction
Normal Operation
OPERATING PERMIT UNIT IDENTIFICATION:
Asphalt Plant with a Scrubber for Particulate Control - Unit XXX
Operating Permit Condition Number Citation
Section II, Condition 3.1 - Opacity Limitation
Explanation of Period of Deviation
Slurry Line Feed Plugged
Duration
START- 1730 4/10/06
END- 1800 4/10/06
Action Taken to Correct the Problem
Line Blown Out
Measures Taken to Prevent Reoccurrence of the Problem
Replaced Line Filter
Dates of Malfunction/Emergencies Reported (if applicable)
5/30/06 to A. Einstein, APCD
Deviation Code
Division Code QA:
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
APPENDIX B:
Monitoring and Permit Deviation Report - Part III
Appendix B
Page 174
REPORT CERTIFICATION
SOURCE NAME: DCP Operating Company, LP — Roggen Natural Gas Processing Plant
FACILITY IDENTIFICATION NUMBER: 123/0049
PERMIT NUMBER: 95OPWE055
REPORTING PERIOD: (see first page of the permit for specific reporting period and dates)
All information for the Title V Semi -Annual Deviation Reports must be certified by a responsible official as
defined in Colorado Regulation No. 3, Part A, Section I.B. This signed certification document must be packaged
with the documents being submitted.
STATEMENT OF COMPLETENESS
I have reviewed the information being submitted in its entirety and, based on information and belief formed
after reasonable inquiry, I certify that the statements and information contained in this submittal are true,
accurate and complete.
Please note that the Colorado Statutes state that any person who knowingly, as defined in Sub -Section 18-
1-501(6), C.R.S., makes any false material statement, representation, or certification in this document is
guilty of a misdemeanor and may be punished in accordance with the provisions of Sub -Section 25-7122.1,
C.R.S.
Printed or Typed Name Title
Signature of Responsible Official Date Signed
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Monitoring and Permit Deviation Report
Appendix B
Page 175
Note: Deviation reports shall be submitted to the Division at the address given in Appendix D of this permit.
No copies need be sent to the U.S. EPA.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
APPENDIX C
Required Format for Annual Compliance Certification Reports
with codes ver 8/20/14
Appendix C
Page 176
Following is the format for the Compliance Certification report to be submitted to the Division and the U.S. EPA
annually based on the effective date of the permit. The Table below must be completed for all equipment or
processes for which specific Operating Permit terms exist.
FACILITY NAME: DCP Operating Company, LP / Roggen Natural Gas Processing Plant
OPERATING PERMIT NO: 95OPWE055
REPORTING PERIOD:
I. Facility Status
During the entire reporting period, this source was in compliance with ALL terms and conditions contained
in the Permit, each term and condition of which is identified and included by this reference. The method(s) used
to determine compliance is/are the method(s) specified in the Permit.
With the possible exception of the deviations identified in the table below, this source was in compliance
with all terms and conditions contained in the Permit, each term and condition of which is identified and included
by this reference, during the entire reporting period. The method used to determine compliance for each term and
condition is the method specified in the Permit, unless otherwise indicated and described in the deviation report(s).
Note that not all deviations are considered violations.
Operating
Permit
Unit ID
Unit Description
Deviations
Reported 1
Monitoring
Method per
Permit?2
Was compliance
continuous or
intermittent?3
Previous
Current
YES
NO
Continuous
Intermittent
C-154
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,100 hp
C-155
Waukesha Model L7042 GU Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp
C-159
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,350 hp
C-157
Waukesha Model L7042 GU Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 806 hp
C-161
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,350 hp
Operating Permit 95OPWE055
First Issued:. May 1, 2001
Renewed: I)I AFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 177
Operating
Permit
Unit ID
Unit Description
Deviations
Reported 1
Monitoring
Method per
Permit?'
Was compliance
continuous or
intermittent?3
Previous
Current
YES I
NO
Continuous
Intermittent
C-158
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 916 hp
C-160
Waukesha Model L7042 G Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp
C-156
Waukesha Model L7042 GU Natural Gas Fired Internal
Combustion Engine, 4 -Cycle, Rich Burn w/ AFR
Controller, Site Rated at 806 hp
C-223
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 720 hp
C-225
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Rated at 800 hp
C-227
Cooper Superior Model 8G825 Natural Gas Fired
Internal Combustion Engine, 4 -Cycle, Rich Burn w/
AFR Controller, Site Rated at 720 hp
P025
Fugitive Emissions from Equipment Leaks
P039
Eight (8) 300 bbl Stabilized Condensate Storage Tanks
F029
Stabilized Condensate Truck Loadout, 285,714 bbl/yr
throughput
H037
Heat Recovery Corp. Hot Oil Heater, Natural Gas
Fired, Rated at 7.55 MMBtu/hr
P033
Triethylene Glycol Dehydration Unit, Rated at 4
MMSCFD, 3.5 gpm TEG recirculation rate
F031
Pressurized Liquids Loadout
C-181
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,478 hp
P-136
Evco Fabrication Model T-901 Triethylene Glycol
Dehydration Unit, Rated at 85 MMSCFD, 24 gpm TEG
recirculation rate
P-137
Evco Fabrication Model T-9002 Amine Sweetening
Unit, Rated at 85 MMSCFD, 350 gpm lean amine
recirculation rate
P-138
Optimized Process Furnaces, Inc., Model H-7201 Hot
Oil Heater, Natural Gas Fired, equipped with Low NOx
burners, Rated at 30.7 MMBtu/hr
C-192
Waukesha Model L7042 GSI Turbocharged Natural
Gas Fired Internal Combustion Engine, 4 -Cycle, Rich
Burn w/ AFR Controller, Site Rated at 1,478 hp
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 178
Operating
Permit
Unit ID
Unit Description
Deviations
Reported 1
Monitoring
Method per
Permit.
Was compliance
continuous or
intermittent? 3
Previous
Current
YES
NO
Continuous
Intermittent
FLARE
John Zink Model Kaldair P-684 Plant Emergency Flare
for Maintenance and Malfunctions
General Conditions
Insignificant Activities 4
If deviations were noted in a previous deviation report , put an "X" under "previous". If deviations were noted in the current deviation
report (i.e. for the last six months of the annual reporting period), put an "X" under "current". Mark both columns if both apply.
2 Note whether the method(s) used to determine thecompliance status with each term and condition was the method(s) specified in the
permit. If it was not, mark "no" and attach additional information/explanation.
3 Note whether the compliance status with of each term and condition provided was continuous or intermittent. "Intermittent
Compliance" can mean either that noncompliance has occurred or that the owner or operator has data sufficient to certify compliance
only on an intermittent basis. Certification of intermittent compliance therefore does not necessarily mean that any noncompliance has
occurred.
NOTE:
The Periodic Monitoring requirements of the Operating Permit program rule are intended to provide assurance that even in the absence
of a continuous system of monitoring the Title V source can demonstrate whether it has operated in continuous compliance for the
duration of the reporting period. Therefore, if a source 1) conducts all of the monitoring and recordkeeping required in its permit, even
if such activities are done periodically and not continuously, and if 2) such monitoring and recordkeeping does not indicate non-
compliance, and if 3) the Responsible Official is not aware of any credible evidence that indicates non-compliance, then the Responsible
Official can certify that the emission point(s) in question were in continuous compliance during the applicable time period.
4 Compliance status for these sources shall be based on a reasonable inquiry using readily available information.
II. Status for Accidental Release Prevention Program:
A. This facility is subject is not subject to the provisions of the Accidental Release
Prevention Program (Section 112(r) of the Federal Clean Air Act)
B. If subject: The facility is is not in compliance with all the
requirements of section 112(r).
1. A Risk Management Plan will be has been submitted to the appropriate
authority and/or the designated central location by the required date.
III. Certification
All information for the Annual Compliance Certification must be certified by a responsible official as defined in
Colorado Regulation No. 3, Part A, Section I.B. This signed certification document must be packaged with the
documents being submitted.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 179
I have reviewed this certification in its entirety and, based on information and belief formed after
reasonable inquiry, I certify that the statements and information contained in this certification are true,
accurate and complete.
Please note that the Colorado Statutes state that any person who knowingly, as defined in § 18-1-501(6),
C.R.S., makes any false material statement, representation, or certification in this document is guilty of a
misdemeanor and may be punished in accordance with the provisions of § 25-7 122.1, C.R.S.
Printed or Typed Name
Title
Signature Date Signed
NOTE: All compliance certifications shall be submitted to the Air Pollution Control Division and to the Environmental Protection
Agency at the addresses listed in Appendix D of this Permit.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Notification Addresses
Appendix D
Page 180
APPENDIX D
Notification Addresses
ver. 02/05/14
1. Air Pollution Control Division
Colorado Department of Public Health and Environment
Air Pollution Control Division
Operating Permits Unit
APCD-SS-B 1
4300 Cherry Creek Drive S.
Denver, CO 80246-1530
ATTN: Matt Burgett
2. United States Environmental Protection Agency
Compliance Notifications:
Office of Enforcement, Compliance and Environmental Justice
Mail Code 8ENF-AT
U.S. Environmental Protection Agency, Region VIII
1595 Wynkoop Street
Denver, CO 80202-1129
502(b)(10) Changes, Off Permit Changes:
Office of Partnerships and Regulatory Assistance
Mail Code 8P -AR
U.S. Environmental Protection Agency, Region VIII
1595 Wynkoop Street
Denver, CO 80202-1129
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit Acronyms
Appendix E
Page 181
Listed Alphabetically:
AIRS -
AP -42 -
APEN -
APCD -
ASTM -
BACT -
BTU -
CAA -
CCR-
CEM -
CF -
CFR -
CO -
COM -
CRS -
EF -
EPA -
FI -
FR -
G -
Gal -
GPM -
HAPs -
HP -
HP -HR -
LAER-
LBS-
M-
MM-
MMscf -
MMscfd -
N/A or NA
NOx -
NESHAP -
NSPS -
P-
PE -
PM -
PMio -
APPENDIX E
Permit Acronyms
Aerometric Information Retrieval System
EPA Document Compiling Air Pollutant Emission Factors
Air Pollution Emission Notice (State of Colorado)
Air Pollution Control Division (State of Colorado)
American Society for Testing and Materials
Best Available Control Technology
British Thermal Unit
Clean Air Act (CAAA = Clean Air Act Amendments)
Colorado Code of Regulations
Continuous Emissions Monitor
Cubic Feet (SCF = Standard Cubic Feet)
Code of Federal Regulations
Carbon Monoxide
Continuous Opacity Monitor
Colorado Revised Statute
Emission Factor
Environmental Protection Agency
Fuel Input Rate in MMBtu/hr
Federal Register
Grams
Gallon
Gallons per Minute
Hazardous Air Pollutants
Horsepower
Horsepower Hour (G/HP-HR = Grams per Horsepower Hour)
Lowest Achievable Emission Rate
Pounds
Thousand
Million
Million Standard Cubic Feet
Million Standard Cubic Feet per Day
Not Applicable
Nitrogen Oxides
National Emission Standards for Hazardous Air Pollutants
New Source Performance Standards
Process Weight Rate in Tons/Hr
Particulate Emissions
Particulate Matter
Particulate Matter Under 10 Microns
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit Acronyms
Appendix E
Page 182
PSD -
PTE -
RACT -
SCC -
SCF -
SIC -
SO2 -
TPY -
TSP -
VOC-
Prevention of Significant Deterioration
Potential To Emit
Reasonably Available Control Technology
Source Classification Code
Standard Cubic Feet
Standard Industrial Classification
Sulfur Dioxide
Tons Per Year
Total Suspended Particulate
Volatile Organic Compounds
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit Modifications
Appendix F
Page 183
APPENDIX F
Permit Modifications
DATE OF
REVISION
TYPE OF
REVISION
SECTION NUMBER,
CONDITION NUMBER
DESCRIPTION OF REVISION
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 184
APPENDIX G
Engine AOS Applicability Reports
ver 10/12/12 (with updated web links and Reg 3 citations as of 8/20/2014)
Note: A MS Word version of this Appendix can be found at:
https://www.colorado.gov/pacific/cdphe/air/AOS
DISCLAIMER:
These are only example reports and do not cover all possible requirements.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 185
Engine AOS Applicability Report Certification Language
All information for the Applicability Reports must be certified by either 1) for Operating Permits, a Responsible
Official as defined in Colorado Regulation No. 3, Part A, Section I.B.40) for Construction and General Permits,
the person legally authorized to act on behalf of the source. This signed certification document must be
packaged with the documents being submitted.
I have reviewed this certification in its entirety and, based on information and belief formed after reasonable
inquiry, I certify that the statements and information contained in this certification are true, accurate and
complete. Further, I agree that by signing and submitting these documents I agree that any new requirements
identified in the Applicability Report(s) shall be considered to be Applicable Requirements as defined in
Colorado Regulation No. 3, Part A, Section I.B.9., and that such requirements shall be enforceable by the
Division and its agents and shall be considered to be revisions to the underlying permit(s) referenced in the
Report(s) until such time as the Permit is revised to reflect the new requirements.
Please note that the Colorado Statutes state that any person who knowingly, as defined in § 18-1-501(6), C.R.S.,
makes any false material statement, representation, or certification in this document is guilty of a misdemeanor
and may be punished in accordance with the provisions of § 25-7 122.1, C.R.S.
Printed or Typed Name
Title
Signature Date Signed
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 186
Colorado Regulation No. 7
Sections XVI and XVII.E
DISCLAIMER: This is only an example report and does not cover all possible Reg 7 requirements.
Company: Acme Gas Processing
Source ID: 9991234
Permit #: 93OPXX999
Date: October 1, 2008
Determination of compliance and reporting requirements for a
Manufacturer: BestEngineCompany
Model: 777 LowNox
Nameplate HP: 1340
Construction date: July 1, 2007
Note: If the engine is exempt from a requirement due to construction date or was relocated from within
Colorado, supporting documentation must be provided.
Determination of Regulation No. 7 requirements:
Regulation No. 7, § XVI
n Does not apply to this engine. Engine is not located in the ozone nonattainment area or does not have a
manufacturer's design rate greater than 500 horsepower or did not commence operation on or after June 1, 2004.
n Does apply to this engine and applicable emissions controls have been installed.
Regulation No. 7, § XVII.E
n Does not apply to this engine. Engine does not have a maximum horsepower greater than 100 or the
construction or relocation date precedes the applicability dates.
n Does apply to this engine. The following emission limits apply to the engine:
NOx (g/hp-hr):
CO (g/hp-hr):
VOC (g/hp-hr):
2.0
4.0
1.0
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 187
Max Engine
HP
Construction or
Relocation Date
Emission Standards in g/hp-hr
NOx
CO
VOC
100<Hp<500
January 1, 2008
2.0
4.0
1.0
January 1, 2011
1.0
2.0
0.7
500≤Hp
July 1, 2007
2.0
4.0
1.0
July 1, 2010
1.0
2.0
0.7
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 188
NSPS JJJJ Example Report Format
DISCLAIMER: This is only an example report and does not cover all possible JJJJ requirements.
Note that as of August 20, 2015 that the Division has not yet adopted NSPS JJJJ. Until such time as it
does, any engine subject to NSPS JJJJ will be subject only under Federal law. Once the Division adopts
NSPS JJJJ, there will be an additional step added to the determination of the NSPS. Under the provisions
of Regulation No. 6, Part B, § I.C, upon adoption of NSPS JJJJ into Regulation No. 6, Part A, an internal
combustion engine relocated from outside the State of Colorado into the Date of Colorado shall meet the
most recent emission standard required in NSPS JJJJ. Engines with a manufacturer's rated horsepower of
less than 500 and with a relocation date no later than 5 years after the manufacture date are exempt from
this requirement per Regulation No. 6, Part B, Section I.C.2.a. Relocation is defined in Section I.C.I.a.
NSPS Subpart JJJJ: Standards of Performance for Stationary Spark Ignition Internal Combustion
Engines
Company: Acme Gas Processing
Source ID: 9991234
Permit #: 93OPXX999
Date: October 1, 2008
Manufacturer: BestEngineCompany
Model: 777 LowNox
Nameplate HP: 1340
Engine Type: 2 Stroke Lean Burn
Manufacture Date: July 1, 2007
Date Engine Ordered: April 1, 2007
Note: If the engine is exempt from a requirement due to construction/manufacture date, supporting
documentation must be provided.
Upon adoption of NSPS Subpart JJJJ into Colorado Regulation No. 6, Part A, if the engine is exempt because
the engine was relocated within the state of Colorado, supporting documentation must be provided.
❑ NSPS JJJJ does not apply to this engine.
NSPS JJJJ does apply to this engine.
Note: Using the format below, the source must submit to the Division an analysis of all of the NSPS JJJJ
applicable requirements that apply to this specific engine. The analysis below is an example only, based on a
hypothetical engine that is a rich burn engine, greater than 500 HP, with a manufacture date after July 1, 2007.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 189
Determination of NSPS JJJJ requirements:
60.4230 Applicability
(a)(4)(i) Applies to this engine since it is a rich burn engine, greater than 500 HP, with a
manufacture date after July 1, 2007.
60.4233 Emission Standards for Owners and Operators
(e) Owners and operators of stationary SI ICE with a maximum engine power greater than
100 HP must comply with the standards in Table 1.
Non -Emergency SI, Natural Gas, HP≥500, Manufactured after 7/1/2007
NOX 2.0 g/HP-hr or 160 ppmvd@15% O2
CO 4.0 g/HP-hr or 540 ppmvd@15% O2
VOC 1.0 g/HP-hr or 86 ppmvd@15% O2
Other Requirements for Owners and Operators
60.4234 Emission standards must be met for the lifetime of the engine.
60.4235 N/A - Sulfur content of gasoline.
60.4236 N/A (for now) - After July 1, 2009 owners and operators may not install engines with a
power rating > 500HP that do not meet the emissions standards in 60.4233.
60.4237 N/A - Emergency Engines.
60.4238 - 60.4242 Compliance Requirements for Manufacturers — (Not Applicable)
60.4243 Compliance Requirements for Owners and Operators
(b)(2)(ii) To maintain compliance with the emission limits in 60.4233, owners of SI ICE > 500HP
must:
• Keep a maintenance plan;
• Keep records of conducted maintenance;
• Maintain and operate the engine in a manner consistent with good air pollution
control practice for minimizing emissions;
• Conduct an initial performance test; and
• Conduct subsequent performance tests every 8,760 hours or every three years,
which ever comes first, in order to demonstrate compliance with the emission
limits.
(g) Air to fuel ratio controllers (AFRCs) must be maintained and operated appropriately in
order to ensure proper operation of the engine and control device to minimize emissions at
all times.
60.4244 Testing Requirements for Owners and Operators
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 190
(a) Each performance test must be conducted within 10% of the highest achievable load and
must comply with the testing requirements listed in 60.8 and Table 2 of NSPS JJJJ.
(b) Performance tests may not be conducted during periods of startup, shutdown, or
malfunction, as specified in 60.8(c). If the engine is non -operational when a performance
test is due, the engine does not need to be started up just to test it, but will need to be
tested immediately upon startup.
(c) Three separate test runs must be conducted for each performance test as specified by
60.8(f). Each run must be within 10% of max load and be at least 1 hour in duration.
(d) To determine compliance with the NON, CO, and VOC mass per unit output emission
limitations, the measured concentration must be converted using the equations outlined in
this section of NSPS JJJJ.
60.4245 Notification, Reports, and Records for Owners and Operators
(a) Owners of all stationary SI ICE must keep records of the following:
(1) All notifications submitted to comply with this subpart;
(2) Maintenance conducted on the engine;
(3) N/A - Manufacturer information for certified engines, and
(4) Documentation that shows non -certified engines are in compliance with the emission
standards.
(b) N/A — For emergency engines only.
(c)
Owners of non -certified engines > 500HP must submit an initial notification as required
in 60.7(a)(1) which includes the following information:
(1) Name and address of the owner or operator;
(2) The address of the affected source;
(3) Engine information including make, model, engine family, serial number, model
year, maximum engine power, and engine displacement;
(4) Emission control equipment; and
(5) Fuel used.
CONCLUSION OF FINDINGS (EXAMPLE ONLY)
In general, Acme's 1,235HP, Waukesha 7042 GSI engine is subject to the emissions limitations summarized in
Table 1 of NSPS JJJJ. ACME will meet these emission limitations using an AFRC and a non -selective catalytic
converter (NSCR). These emission rates will be met throughout the life of the engine. A maintenance plan will
be kept and all maintenance activities will be recorded. Compliance with the emission limits will be confirmed
by the initial performance tests, which shall be conducted following the procedures outlined in 60.4244.
Copies of performance test results will be submitted within 60 days of the completion of each test. Since this is
an uncertified engine, an initial notification will be submitted including all of the requested information in
40.4245 within 30 days of startup. ACME will keep records of all compliance related materials.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: GRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 191
MACT ZZZZ Example Report Format
DISCLAIMER: This is only an example report and does not cover all possible. ZZZZ requirements.
MACT Subpart ZZZZ: National Emissions Standards for Hazardous Air Pollutants for Stationary
Reciprocating Internal Combustion Engines
Company:
Source. ID:
Permit #:
Date:
Manufacturer:
Model:
Nameplate HP:
Engine Type:
Manufacture Date: July 1, 2007
Date Engine Ordered: April 1, 2007
Acme Gas Processing
9991234
93OPXX999
October 1, 2008
BestEngineCompany
777 LowNox
1340
2 Stroke Lean Burn
Note: If the engine is exempt from a requirement due to construction/reconstruction date, supporting
documentation must be provided.
MACT ZZZZ does not apply to this engine.
❑ MACT ZZZZ does apply to this engine.
Note: Using the format below, the source must submit to the Division an analysis of all of the MACT ZZZZ
applicable requirements that apply to this specific engine. The analysis below is an example only, based on a
hypothetical new engine located at an area source of HAP emissions.
Determination of MACT ZZZZ requirements:
63.6585 Applicability
This subpart is applicable to Acme's engine since they are going to be operating a new
stationary reciprocating internal combustion engine (RICE) at a major source of HAP
emissions.
63.6590 What Parts of My Plant Does This Subpart Cover?
This subpart covers Acme's new stationary reciprocating internal combustion engine.
63.6595 When do I have to comply with this Subpart?
(a)(5) The engine must comply with the applicable emission limitations and operating limitations
upon startup.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 192
63.6600 Emission and operating limitations for RICE site rated at more than 500 hp
(a)
The engine is subject to the emission limits in table 1 a and the operating limits in table
lb. ACME will meet the emission limitations by reducing formaldehyde emissions by 76
percent and will maintain the catalyst such that the pressure drop does not change by more
than 2 inches of H2O at 100 % load plus or minus 10 percent from the pressure drop
measured during the initial performance test and will maintain the temperature of the
engine exhaust so that the catalyst inlet temperature is greater than or equal to 750 ° F and
less than or equal to 1250 ° F.
The engine will be equipped with non -selective catalytic reduction and an air fuel
controller to meet the emission limitations.
63.6601 & 63.6611 Requirements for 4SLB engines between 250 and 500 hp
These requirements do not apply.
63.6605 General Requirements
(a) The engine will comply with the emission and operating limitations at all times, except
during periods of startup, shutdown and malfunction (SSM)
(b) The engine, including air pollution control and monitoring equipment shall be operating in
a manner consistent with good air pollution control practices for minimizing emissions at
all times, including during SSM.
63.6610 Initial performance test
(a) The performance tests specified in Table 4 (select sampling port and measure O2, moisture
and formaldehyde at inlet and outlet of the control device) shall be conducted within 180
days of startup.
(b) & (c) Not applicable. Construction did not commence between 12/19/02 and 6/15/04.
(d) Previous performance tests have not been conducted on this unit within two years,
therefore, this provision does not apply.
63.6615 Subsequent performance tests
Subsequent tests will be conducted as specified in Table 3. No additional testing is
required for 4SRB engines meeting the formaldehyde percent reduction requirements.
63.6620 Performance test procedures
(b) Tests must be conducted at 100 % load plus or minus 10%
(c) Tests may not be conducted during periods of SSM.
(d) Must conduct three 1 -hr test runs
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 193
(e) Equation (e)(1) shall be used to determine compliance with the percent reduction
requirement.
(f), (g) & (h) Not applicable
(i) Engine load during test shall be determined as specified in this paragraph.
63.6625 Monitoring, installation, operation and maintenance requirements
(a), (c) & (d) Not applicable
(b) A continuous parameter monitoring system (CPMS) shall be installed to measure the
catalyst inlet temperature. The CPMS will meet the requirements in § 63.8
63.6630 Demonstrating initial compliance
(a)
(b)
(c)
Initial compliance shall be determined in accordance with Table 5 (initial performance test
must indicate formaldehyde reduction of 76 percent or more, a CPMS must be installed to
measure inlet temperature of the catalyst and the pressure drop and catalyst inlet
temperature must be recorded during the initial performance test).
Pressure differential will be established during the initial performance test.
Notification of compliance status will be submitted and will contain the results of the
initial compliance demonstration.
63.6635 Monitoring to demonstrate continuous compliance
(b) Except for monitor malfunctions, associated repairs, and required QA/QC activities
monitoring must be continuous at all time the engine is operating.
(c) Data recorded during monitoring malfunctions, associated repairs and required QA/QC
activities must not be used in data averages and calculations to report operating levels,
however, all the valid data collected during other periods shall be used.
63.6640 Demonstrating continuous compliance
(a)
(b)
63.6645 Notifications
Continuous compliance will be demonstrated as specified in Table 6 (collect catalyst inlet
temperature data, reduce that data to 4 -hr rolling average and maintain the 4 -hr rolling
averages to within the operating limitation and measuring the pressure drop across the
catalyst once per month and demonstrating that the pressure drop meets the operating
limitation).
Deviations from the emission and operating limitations must be reported per § 63.6550.
If catalyst is changed the operating parameters established during the initial performance
test must be re-established.
When operating parameters re-established a performance test must also be conducted.
(a) Submit notifications in §§ 63.7(b) & (c), 63.8(e), (f)(4) and (f)(6), 63.9(b) thru (e) & (g) &
(h) that apply by dates specified.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 194
(b) Not applicable. Acme unit started after effective dated for Subpart ZZZZ.
(c) Submit initial notification within 120 days after becoming subject to Subpart ZZZZ.
(d) thru (1) Not applicable. Acme engine greater than 500 hp and subject to requirements in Subpart
ZZZZ.
(g) & (h) Submit notification of intent to conduct performance test and notification of compliance
status.
616650 Reports
(a) Submit reports required by Table 7 (compliance report and SSM reports (if actions
inconsistent with SSM plan)
(b) Not applicable, an alternate schedule for report submittal has been approved. Reports will
be submitted with Title V reports
(c) Compliance reports to contain the following information: company name and address,
statement by responsible official certifying accuracy, date of report and beginning and end
of reporting period, if SSM the information in 63.10(d)(5)(i), if no deviations a statement
saying that, if no periods when CPMS out of control a statement saying that.
(d) Not applicable, using CPMS
(e) For each deviation the information in (e)(1) thru (e)(12) shall be provided.
(f) Applicable. Compliance reports are submitted with title v reports. Compliance reports
under Subpart ZZZZ include all necessary info for title v deviation report with respect to
Subpart ZZZZ requirements.
(g) Not applicable. Acme engine not firing landfill or digester gas.
63.6655 Recordkeeping
(a) Retain records as follows: copy of each notification and report (including all
documentation supporting any initial notification or notification of compliance status),
records in 63.6(e)(iii) thru (v) related to SSM, and records of performance tests and
evaluations.
(b) CPMS records including records in 63.10(b)(2)(vi) thru (xi), previous versions of the
performance evaluation plan required by 63.8(d)(3) and requests for alternatives to the
relative accuracy test for CPMS as required by 63.8(f)(6)(i).
(c) Not applicable. Acme engine not firing landfill or digester gas.
(d) Will keep records required in Table 6 (monthly pressure drop readings, 4 -hr averages of
catalyst inlet temperature) to show continuous compliance with emission and operating
limits.
63.6660 Form and length of records
(a) Records must be in a form suitable and readily available for expeditions review.
(b) Records must be retained for five years.
(c) Records must be retained on -site for first 2 years, may be retained off -site for the
remaining 3 years.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: D1 A F T
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 195
63.6665 General Provisions
This engine must comply with the general provisions as indicated in Table 8.
CONCLUSION OF FINDINGS (EXAMPLE ONLY)
Since this engine is subject to the requirements of MACT Subpart ZZZZ. The engine will be installed with a
non -selective catalyst to meet the formaldehyde reduction requirement of 76% or more. An initial performance
test will be conducted within 180 days of startup to demonstrate compliance with the formaldehyde percent
reduction requirement. During the initial performance test, the pressure drop across the catalyst will be
measured. A CPMS will be installed to measure the catalyst inlet temperature. Continuous compliance will be
demonstrated by keeping the 4 -hr rolling averages of catalyst inlet temperature within the operating limitations
and recording the pressure drop across the catalyst monthly and demonstrating that the pressure drop is within
the operating limitation.
Records, notifications and reports will be submitted as required. To that end required reports and notifications
include initial notification, notice of intent to conduct performance test, notification of compliance status, SSM
reports (if required) and semi-annual compliance reports.
Operating Permit 950PWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 196
APPENDIX H
Compliance Assurance Monitoring Plans
Compliance Assurance Monitoring Plan — Natural Gas Fired RICE
I. Background
a. Emission Unit Description:
AIRS ID 101 (C-154) — Compressor RICE (1,100 hp) for NOx
AIRS ID 103 (C-159) — Compressor RICE (1,350 hp) for NOx and CO
AIRS ID 108 (C-161) — Compressor RICE (1,350 hp) for NOx and CO
AIRS ID 115 (C-223) — Compressor RICE (720 hp) for CO
AIRS ID 117 (C-225) — Compressor RICE (800 hp) for CO
AIRS ID 119 (C-227) — Compressor RICE (720 hp) for NOx and CO
AIRS ID 134 (C-181) — Compressor RICE (1,478 hp) for NOx and CO
AIRS ID 140 (C-192) — Compressor RICE (1,478 hp) for NOx and CO
b. Applicable Regulation, Emission Limit, Monitoring Requirements:
Engine C-154:
Regulations: Operating Permit Condition 1.1
Emission Limitations: NOx 21.2 tons/year
Monitoring Requirements: Catalyst inlet temperature
Engine C-159:
Regulations: Operating Permit Condition 1.1
Emission Limitations: NOx 26.1 tons/year
CO 27.4 tons/year
Monitoring Requirements: Catalyst inlet temperature
Engine C-161:
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 197
Regulations:
Emission Limitations:
Monitoring Requirements:
Engine C-223:
Regulations:
Emission Limitations:
Monitoring Requirements:
Engine C-225:
Regulations:
Emission Limitations:
Monitoring Requirements:
Engine C-227.:
Regulations:
Emission Limitations:
Monitoring Requirements:
Engine C-181:
Regulations:
Emission Limitations:
Monitoring Requirements:
Engine C-192:
Regulations:
Emission Limitations:
Monitoring Requirements:
Operating Permit Condition 1.1
NOx 13.0 tons/year
CO 26.1 tons/year
Catalyst inlet temperature
Operating Permit Condition 1.1
CO 14.6 tons/year
Catalyst inlet temperature
Operating Permit Condition 1.1
CO 15.5 tons/year
Catalyst inlet temperature
Operating Permit Condition 1.1
NOx 13.9 tons/year
CO 14.6 tons/year
Catalyst inlet temperature
Operating Permit Condition 2.1
NOx 14.3 tons/year
CO 28.5 tons/year
Catalyst inlet temperature
Operating Permit Condition 1.1
NOx 14.3 tons/year
CO 28.6 tons/year
Catalyst inlet temperature
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 198
c. Control Technology:
Each engine is equipped with an Air/Fuel Ratio controller and Non -Selective Catalytic Reduction
(NSCR) to control NOx and CO emissions.
II. Monitoring Approach
Compliance Indicator
I. Indicator
Catalyst Inlet Temperature
a. Measurement Approach
The temperature of the exhaust gas into the catalyst is measured using an in -line
thermocouple or equivalent.
II. Indicator Range
Excursions, for the purposes of reporting, are defined as an inlet catalyst temperature
that is less than 750°F or greater than 1250°F.
Excursions above 1250°F trigger engine shutdown. Excursions trigger the permittee
to investigate the engine performance and make any repairs or adjustments
necessary. Any adjustments or repairs shall be recorded in a log to be made
available to the Division upon request.
III. Performance Criteria
a. Data Representativeness
The catalyst inlet temperature is measured upstream of the catalyst by a
thermocouple. The minimum accuracy is +/- 5° F.
b. Verification of Operational
Status
N/A.
c. QA/QC Practices and Criteria
Proper thermocouple operation shall be verified annually. Thermocouples shall be
replaced if proper operation cannot be verified. The results of this verification and
any replacements made shall be maintained in a log to be made available to the
Division upon request.
d. Monitoring Frequency
Continuous.
e. Data. Collection Procedures
The catalyst inlet temperature is automatically recorded in the Distributed Control
System (DCS). The catalyst inlet temperature shall be manually recorded daily in a
log to be made available to the Division upon request.
f. Averaging Period
None, unless more than one reading is taken, then a daily average.
III. Justification
a. Background:
The pollutant specific emission units are eight (8) internal combustion engines. Each engine is
equipped with a non -selective catalytic reduction unit to control NOx and CO emissions. The n6n-
selective reduction catalyst reduces NOx emissions to nitrogen and water as well as reducing CO
emissions by formation of CO2.
b. Rational for Selection of Performance Indicators:
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 199
The Division approved inlet temperature to the catalyst as it is an indicator of the catalyst
performance. The temperature into the NSCR unit is measured because the catalytic reactions that
destroy pollutants are temperature -dependent. The reactions occur favorably if the engine exhaust
temperature into the catalyst is greater than 750°F. Catalyst damage will occur if the inlet
temperature is too high and deterioration of the catalyst would reduce emission destruction
efficiency. Either excessive or inadequate temperature indicated possible problems with the engine
operation that might be correctable after investigation. Monitoring of the temperature -sensing
device of the inlet exhaust gas into the catalyst will ensure the presence of optimum conditions for
the catalytic reaction.
The final RICE MACT requires monitoring of inlet temperature to the catalyst. The CAM rule
specifies that monitoring required for a MACT standard is presumptively acceptable monitoring,
provided the monitoring is applicable to the performance of the control device (40 CFR Part 64 §
64.4(b)(4)). Since the MACT monitoring is for the same control device, the Division considers
that the indicator is presumptively acceptable.
c. Rationale for Selection of Indicator Ranges:
The indicator range for the catalyst inlet temperature was selected based on available operational
data from compliance tests, observations, and manufacturer data for rich burn engines equipped
with AFR and catalytic control. The indicator range for the catalyst inlet temperature is the same
range as specified in the final RICE MACT. The Division considers that the indicator range is
also presumptively acceptable.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 200
Compliance Assurance Monitoring Plan — TEG Dehydration Unit
I. Background
a. Emission Unit Description:
AIRS ID 136 (P-136) — TEG Dehydration Unit (85 MMSCFD) for VOC and HAP
Still vent emissions from the TEG dehydration unit P-136 are controlled with either an enclosed
combustion device (ECD) or the same regenerative thermal oxidizer (RTO) used as the control
device for the amine sweetening 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 RTO shall serve as a backup control
device to P-136. The pre -control VOC emissions from the dehydration unit still vent are above the
major source threshold of 100 tons/year. Additionally, the pre -control emissions of HAP from the
dehydration unit still vent are above the major source thresholds of 10 tons/year individual HAP
and 25 tons/year total HAP. The following CAM plan includes requirements for both the ECD and
RTO. The requirements specific to each control device shall be adhered to at all times when still
vent emissions from the dehydration unit are routed to that control device.
b. Applicable Regulation, Emission Limit, Monitoring Requirements:
TEG Dehydration Unit (P-136):
Regulations:
Emission Limitations:
c. Control Technology:
Operating Permit Conditions 5.1, 14.1
VOC 23.7 tons/year
HAP 8 tons/year individual, 22.9 tons/year total (Facility -Wide)
Enclosed Combustion Device (primary)
Regenerative Thermal Oxidizer (backup)
Still vent emissions are routed to the enclosed combustor (ECD) with a DRE of 95% as the primary
control device. This ECD is permitted 2% annual downtime for maintenance and malfunctions,
during which time the P-136 still vent shall vent to atmosphere. During periods of amine
sweetening unit operation, the P-136 still vent may be routed to the regenerative thermal oxidizer
(RTO) with a DRE of 97% as a backup control device. It should be noted that the RTO is not
permitted any control device downtime.
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 201
II. Monitoring Approach
Enclosed Combustion Device (ECD)
Indicator No. 1
I. Indicator
Presence of Pilot Flame
a. Measurement Approach
Presence of a flame is continuously monitored with a thermocouple or equivalent heat
sensing device. In the event of a pilot light outage, an alarm is sent to the control room.
II. Indicator Range
Excursions, for the purposes of reporting, are defined as any absence of a pilot light,
except during periods of permitted downtime.
Excursions shall trigger an investigation and corrective action shall be performed as
necessary. Any adjustments or repairs made shall be recorded in a log to be made
available to the Division upon request.
III. Performance Criteria
a. Data Representativeness
A thermocouple or equivalent heat sensing device will determine the presence or
absence of the flame.
b. Verification of Operational Status
Visual observations of the pilot flame will be conducted daily to verify the indication
from the thermocouple or equivalent heat sensing device.
c. QA/QC Practices/Criteria
Proper thermocouple operation shall be verified annually. Thermocouples shall be
replaced if proper operation cannot be verified as expeditiously as practicable. The
results of this verification and any replacements made shall be maintained in a log to
be made available to the Division upon request.
d. Monitoring Frequency
Continuous.
e. Data Collection Procedures
The presence of the pilot light shall be monitored continuously using a thermocouple
or equivalent heat sensing device. Pilot light status, including all instances of pilot light
absence and the duration of each absence, except during periods of permitted
downtime, shall be recorded daily in a log to be made available to the Division upon
request.
f. Averaging Time
N/A.
Regenerative Thermal Oxidizer (RTO)
Indicator No. 1
I. Indicator
Combustion Chamber Temperature
a. Measurement Approach
The combustion chamber outlet temperature is continuously monitored with a
thermocouple.
II. Indicator Range
Excursions, for the purposes of reporting, is an average daily temperature reading
below 1450°F.
Excursions shall trigger an investigation and corrective action shall be performed as
necessary. Any adjustments or repairs made shall be recorded in a log to be made
available to the Division upon request.
III. Performance Criteria
Operating Permit 95OPWE055
First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance. Assurance Monitoring
Appendix H
Page 202
a. Data Representativeness
Temperature is measured at the outlet of the combustion chamber. The minimum
accuracy is +/- 5 T.
b. Verification of Operational Status
N/A.
c. QA/QC Practices/Criteria
Proper thermocouple operation shall be verified annually. Thermocouples shall be
replaced if proper operation cannot be verified as expeditiously as practicable. The
results of this verification and any replacements made shall be maintained in a log to
be made available to the Division upon request.
d. Monitoring Frequency
Continuous.
e. Data Collection Procedures
The combustion chamber temperature shall be automatically recorded by the
Distributed Control System (DCS) during periods of RTO operation. The temperature
readings obtained for each calendar day shall be averaged to obtain an average daily
temperature. This average daily temperature shall be recorded in a log to be made
available to the Division upon request.
f. Averaging Time
Daily.
III. Justification
a. Background:
The pollutant specific emission unit is a TEG dehydration unit, which functions to remove water
prior to downstream cryogenic processing. Flash emissions from the dehydration unit are routed
to the plant inlet via a closed loop system and the still vent emissions are routed to either the
enclosed combustion device (ECD) or regenerative thermal oxidizer (RTO). This CAM plan
applies to the operation of both the ECD and RTO.
b. Rationale for Selection of Performance Indicators and Indicator Ranges:
ECD: The enclosed combustion device (ECD) has a manufacturer's guaranteed VOC destruction
efficiency of 98%, when operational. The Division has accepted a VOC destruction efficiency of
95% for enclosed combustion devices with a 98% manufacturer's guarantee. In order to achieve
this destruction efficiency, the ECD must have a pilot light that is continuously lit to ensure the
still vent vapors from TEG dehydration unit P-136 are ignited. Verification of pilot light presence
is accomplished by continuously monitoring the pilot light with a thermocouple or equivalent heat
sensing device.
RTO: The destruction of VOC and HAP is dependent upon effective combustion. The combustion
chamber of the regenerative thermal oxidizer (RTO) must meet a minimum temperature in order
to achieve optimal combustion, resulting in the destruction efficiency necessary to comply with
the VOC and HAP limits set forth in Operating Permit Conditions 5.1 and 14.1, respectively. This
RTO was permitted a minimum combustion chamber temperature of 1450°F under Colorado
Construction Permit 10WE1659. Therefore, a minimum combustion chamber temperature of
1450°F shall be maintained in order to effectively destruct still vent emissions routed to the RTO.
Verification of the combustion chamber temperature is accomplished by continuously monitoring
the combustion chamber outlet temperature with a thermocouple and computing a daily average
of the temperatures recorded.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 203
Compliance Assurance Monitoring Plan —Amine Sweetening Unit
I. Background
a. Emission Unit Description:
AIRS ID 137 (P-137) — Amine Sweetening Unit (85 MMSCFD) for HAP
Acid gas vent emissions from the amine sweetening unit are sent exclusively to a regenerative
thermal oxidizer (RTO), which may also control still vent emissions from the TEG dehydration
unit P-136. The pre -control emissions of HAP from the amine sweetening unit are above the major
source thresholds of 10 tons/year individual HAP and 25 tons/year total HAP. The following CAM
plan shall apply at all times during which the amine sweetening unit is operating:
b. Applicable Regulation, Emission Limit, Monitoring Requirements:
Amine Sweetening Unit (P-137):
Regulations: Operating Permit Conditions 14.1
Emission Limitations: HAP 8 tons/year individual, 22.9 tons/year total (Facility -Wide)
c. Control Technology:.
Regenerative Thermal Oxidizer
Acid gas vent emissions are routed exclusively to the regenerative thermal oxidizer (RTO) with a
DRE of 97%. The RTO is not permitted any control device downtime.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 204
II. Monitoring Approach
Compliance Indicator
I. Indicator
Combustion Chamber Temperature
b. Measurement Approach
The combustion chamber outlet temperature is continuously monitored
with a thermocouple.
II. Indicator Range
Excursions, for the purposes of reporting, is an average daily
temperature reading below 1450°F.
Excursions shall trigger an investigation and corrective action shall be
performed as necessary. Any adjustments or repairs made shall be
recorded in a log to be made available to the Division upon request.
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
N/A.
c. QA/QC Practices/Criteria
Proper thermocouple operation shall be verified annually.
Thermocouples shall be replaced if proper operation cannot be verified
as expeditiously as practicable. The results of this verification and any
replacements made shall be maintained in a log to be made available to
the Division upon request.
d. Monitoring Frequency
Continuous.
e. Data Collection Procedures
The combustion chamber temperature shall be automatically recorded
by the Distributed Control System (DCS) during periods of RTO
operation. The temperature readings obtained for each calendar day
shall be averaged to obtain an average daily temperature. This average
daily temperature shall be recorded in a log to be made available to the
Division upon request.
f. Averaging Time
Daily.
HI. Justification
a. Background:
The pollutant specific emission unit is an amine sweetening unit, which functions to remove acid
gases from the inlet field gas stream. Flash emissions from the amine sweetening unit are routed
to the plant inlet via a closed loop system and the acid gas vent emissions are routed to the
regenerative thermal oxidizer (RTO). This CAM plan applies to the operation of the RTO.
b. Rationale for Selection of Performance Indicators and Indicator Ranges:
The destruction of HAP is dependent upon effective combustion. The combustion chamber of the
regenerative thermal oxidizer (RTO) must meet a minimum temperature in order to achieve
optimal combustion, resulting in the destruction efficiency necessary to comply with the HAP
limits set forth in Operating Permit Condition 14.1. This RTO was permitted a minimum
combustion chamber temperature of 1450°F under Colorado Construction Permit 10WE1659.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Assurance Monitoring
Appendix H
Page 205
Therefore, a minimum combustion chamber temperature of 1450°F shall be maintained in order
to effectively destruct acid gas vent emissions routed to the RTO. Verification of the combustion
chamber temperature is accomplished by continuously monitoring the combustion chamber outlet
temperature with a thermocouple and computing a daily average of the temperatures recorded.
Operating Permit 95OPWE055 First Issued: May 1, 2001
Renewed: DRAFT
TECHNICAL REVIEW DOCUMENT
For
DRAFT RENEWAL OF OPERATING PERMIT 95OPWE055
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Weld County
Source ID 123/0049
February 2017 — Date
Operating Permit Engineer:
Operating Permit Supervisor review:
Field Services Unit review:
I. PURPOSE
Elie Schuchardt
Blue Parish
Alex Scherer
This document establishes the basis for decisions made regarding the applicable
requirements, emission factors, monitoring plan and compliance status of emission
units covered by the renewed Operating Permit for the Roggen Natural Gas Processing
Plant. The previous Operating Permit for this facility was issued on May 1, 2001, was
last revised on August 29, 2005 and expired on May 1, 2006. However, since a timely
and complete renewal application was submitted, under Colorado Regulation No. 3,
Part C, Section IV.C all of the terms and conditions of the existing permit shall not expire
until the renewal operating permit is issued and any previously extended permit shield
continues in full force and operation.
The source has submitted the following permit modification applications:
• Minor Modification (Rec'd. 4/2/2007) — Request to increase stabilized
condensate tank (P039) and condensate truck loadout (F029) VOC and
throughput limits.
• Significant Modification (Rec'd. 3/21/2016) — Request to increase fugitive VOC
emissions (F025), increase throughput for glycol dehydration unit (P033), and
add an enclosed combustion device to control the glycol dehydration unit still
vent emissions (P033, P-136).
• Significant Modification (Rec'd. 7/10/2017, amendment rec'd. 7/31/2017) —
Request to amend NOx and CO limitation and emission factors for engines C-
154, C-159, C-161, C-156, C-225, C-227 and C-181 to reflect those requested
on APENs submitted with AOS applications for these units. Additional request to
permit 2% downtime for the regenerative thermal oxidizer (RTO) and enclosed
combustion device (ECD) associated with the dehydration units and amine
sweetening unit.
• Significant Modification (Rec'd. 9/11/2017) — Request to permit the facility
emergency flare (FLARE) which has exceeded de minimis reporting levels for
NOx, CO and VOC. Request to include NSPS OOOO requirements for fugitive
123/0049 Page 1 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
emissions from three process units that underwent a qualifying modification
within the applicability dates of that subpart.
• Significant Modification (Rec'd. 11/13/2017) — Request to cancel previous
modifications to the dehydration unit P-136 received on 7/10/2017 and APEN
updates received on 9/22/2017 and replace with this 11/13/2017 modification to
make the ECD the primary control device for P-136, permit 2% downtime and a
95% control efficiency for the ECD, and update emissions based on a new
ProMax model run. Additional request to cancel previous modifications to the
amine sweetening unit P-137 received on 7/10/2017 and 7/31/2017 and APEN
updates received on 9/22/2017 and return all limitations and requirements to
those set forth in issuance 5 of Colorado Construction Permit 10WE1659,
effectively cancelling RTO downtime request.
• Significant Modification (Rec'd. 11/8/2018) — Request to increase waste gas and
purge gas throughput to the plant emergency flare (FLARE), and to adjust the
NOx, CO and VOC emission limitations for the plant emergency flare as a result
of the throughput increases. Additional request to update the insignificant
activities list.
The significant modifications must be processed as required by Colorado Regulation
No. 3, Part C, Section I.A.7.c. A significant modification is processed under the same
procedures as a renewal, i.e. it must go through a 30 -day public comment period and
EPA 45 -day review period. Therefore, since the renewal application has been submitted
the Division is incorporating these modifications with the renewal.
This document is designed for reference during the review of the proposed permit by
the EPA, the public, and other interested parties. The conclusions made in this report
are based on information provided in the original application submitted on 4/29/2005,
comments on the draft permit submitted on 11/2/2018, previous inspection reports and
various email correspondence, as well as telephone conversations with the applicant.
Please note that copies of the Technical Review Document for the original permit and
any Technical Review Documents associated with subsequent modifications of the
original Operating Permit may be found in the Division files as well as on the Division
website at https://www.colorado.gov/cdphe/title-v-operating-permits. This narrative is
intended only as an adjunct for the reviewer and has no legal standing.
Any revisions made to the underlying construction permits associated with this facility
made in conjunction with the processing of this operating permit application have been
reviewed in accordance with the requirements of Regulation No. 3, Part B, Construction
Permits, and have been found to meet all applicable substantive and procedural
requirements. This operating permit incorporates and shall be considered to be a
combined construction/operating permit for any such revision, and the permittee shall
be allowed to operate under the revised conditions upon issuance of this operating
permit without applying for a revision to this permit or for an additional or revised
construction permit.
123/0049 Page 2 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
II. DESCRIPTION OF SOURCE
The Roggen Natural Gas Processing Plant upgrades field gas to a saleable natural gas
product by removing heavier hydrocarbon constituents as natural gas liquids (NGLs)
and condensate. The processing capacity at Roggen is 85 MMSCFD.
High pressure gas from the Enterprise and Marla Compressor Stations enters the facility
through a common pipeline. Liquid condensate formed during transfer is separated out
from the gas in an inlet slug catcher. Gas in excess of the 85 MMSCFD processing
capacity at Roggen is routed to the two (2) Box Elder compressors (AIRS 110, 140) and
is either sent to the Anadarko Wattenberg Plant for additional processing, or bypasses
the Roggen facility entirely and is piped offsite as unprocessed sales gas. Low pressure
field gas enters the facility via three gathering lines where the pressure is boosted with
three (3) inlet compressors (AIRS 115, 117, 119) and combined with the remaining high
pressure gas. This combined gas stream may be further processed with an amine
sweetening unit (AIRS 137) to absorb acid gas, followed by a TEG dehydration unit
(AIRS 136) and subsequently molecular sieve beds to remove water prior to the
cryogenic processing trains. These unit operations are only used as necessary to meet
sales gas pipeline specifications. The gas is then divided and sent to one of three
cryogenic units to separate NGLs from the residue sales gas. Cryogenic temperatures
are achieved via gas/gas exchange, a propane refrigeration loop (engine AIRS 113)
and JT expansion. The NGLs are separated from the residue sales gas in the cryogenic
demethanizer towers. Six (6) residue gas compressors (AIRS 102, 103, 107, 108, 114,
134) boost the residue gas to pipeline pressures. The residue gas exits the facility in a
sales pipeline. A slipstream of the residue sales gas is heated and used to regenerate
the molecular sieve beds upon saturation. Water entrained in this stream is removed
with a small TEG dehydration unit (AIRS 130). NGLs collected during the cryogenic
processing are stored in pressurized bullet tanks. Additional pressurized bullet tanks
are used to store third -party propane and butane, which may be blended with the NGLs
produced at Roggen. NGLs from the bullet tanks are either pumped offsite through a
sales pipeline or trucked out at the pressurized liquid loadout racks (AIRS 133).
Condensate collected throughout the process is combined with condensate that is
trucked to the facility and upgraded to sales specification in a condensate stabilization
unit. The stabilized condensate is stored in atmospheric tanks (AIRS 125) and is trucked
offsite from the condensate loadout racks (AIRS 126). Vapors generated by the
condensate stabilization unit are routed to a vapor recovery unit (VRU, AIRS 101) and
combined with the inlet gas downstream of the slug catcher for reprocessing. Two (2)
hot oil heaters (AIRS 129 and 138) bring the heat transfer media used throughout the
facility up to the required temperature for reboiler operation. An emergency plant flare
(AIRS 141) destructs process emissions from equipment blowdowns and emergency
venting. In addition to these point sources, fugitive emissions (AIRS 122) are also
permitted at this facility.
Emission control devices include: thirteen (13) NSCR beds to control compressor
engine exhaust emissions, one (1) dedicated enclosed combustion device to control
condensate tank emissions, one (1) open plant emergency flare to control facility -wide
process emissions, one (1) enclosed combustion device (ECD) permitted 2% downtime
to control still vent emissions from both dehydration units, and one (1) regenerative
123/0049 Page 3 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
thermal oxidizer (RTO) to control acid gas vent emissions from the amine unit. This RTO
may also serve as a backup control device for the larger dehydration unit (AIRS 136)
only. Flash tank emissions from the amine and both dehydration units are hard -piped
directly back to the low-pressure plant inlet.
The Roggen Natural Gas Processing Plant is located in Weld County, Colorado. The
area in which the plant operates is classified as attainment for all pollutants except
ozone. It is classified as non -attainment for ozone and is part of the 8 -hr Ozone Control
Area as defined in Regulation No. 7, Section II.A.1.
The plant is located within 100 kilometers of Rocky Mountain National Park, a Federal
Class I area. There are no affected states within 50 miles of this facility.
Emissions (in tons/yr) at the facility are as follows:
AIRS ID
Facility ID
Source
Controlled Emissions (tons/year)
NOx
CO
VOC
Fugitive
VOC
Total HAP
Reportable
HAP
101
C-154
VRU Compressor
21.24
21.24
10.62
--
0.40
0.18
102
C-155
Residue Compressor
16.34
16.34
7.78
--
0.34
0.16
103
C-159
Residue Compressor
26.07
27.38
13.04
--
0.53
0.44
107
C-157
Residue Compressor
16.34
16.34
7.78
--
0.34
0.16
108
C-161
Residue Compressor
13.04
26.07
9.13
--
0.53
0.44
110
C-158
Box Elder Compressor
18.57
18.57
8.85
--
0.37
0.17
113
C-160
Propane Compressor
16.34
16.34
7.78
--
0.34
0.16
114
C-156
Residue Compressor
7.78
15.57
5.45
--
0.34
0.16
115
C-223
Inlet Compressor
14.60
14.60
6.95
--
0.30
0.13
117
C-225
Inlet Compressor
7.73
15.45
5.41
--
0.30
0.14
119
C-227
Inlet Compressor
13.90
14.60
7.00
--
0.30
0.13
122
P025
Fugitive Emissions
--
--
--
33.54
0.43
0.39
125
P039
Stabilized Condensate Tanks
--
--
1.50
--
0.28
0.28
126
F029
Stabilized Condensate Loadout
--
--
30.84
--
6.10
5.97
129
H037
Hot Oil Heater
3.45
2.90
--
--
--
--
130
P033
TEG Dehydration Unit
--
--
1.05
--
0.30
0.30
133
F031
Pressurized Liquids Loadout
--
--
5.00
--
--
--
134
C-181
Residue Compressor
14.27
28.54
9.99
--
0.55
0.46
136
P-136
TEG Dehydration Unit
--
4.04
23.74
--
8.36
8.36
137
P-137
Amine Sweetening Unit
2.93
5.61
2.43
--
1.34
1.34
138
P-138
Hot Oil Heater
7.02
11.79
--
--
0.30
0.25
140
C-192
Box Elder Compressor
14.30
28.60
10.00
--
0.82
0.73
141
FLARE
Plant Emergency Flare
3.55
15.93
17.19
--
0.08
0.08
Total Permitted Facility Emissions (tons/year)
217.47
299.91
191.53
33.54
22.67
20.45
2016 Actual Facility Emissions (tons/year)
178.04
213.15
144.64*
--
--
5.28
'Actual VOC emissions includes fugitive VOC emissions
123/0049
Page 4 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Pursuant to the emissions summary above, this facility is classified as follows:
• Non -Attainment New Source Review (NANSR): Major stationary source for NOx
and VOC
• Prevention of Significant Deterioration (PSD): Major stationary source
• Title V Applicability: Major Source for NOx, CO and VOC, Syn Minor for HAP
• 40 CFR 63 Designation: Area Source of HAP
III. APPLICABLE REQUIREMENTS
Prevention of Significant Deterioration (PSD)
This facility is categorized as a NANSR major stationary source (Potential to Emit of
VOC or NOx ≥ 100 Tons/Year). Future modifications at this facility resulting in a
significant net emissions increase (see Reg 3, Part D, Sections II.A.27 and 44) for VOC
or NOx or a modification which is major by itself (Potential to Emit of ≥ 100 TPY of either
VOC or NOx) may result in the application of the NANSR review requirements.
This facility is categorized as a PSD major stationary source (Potential to Emit ≥ 250
Tons/Year) for CO. Future modifications at this facility resulting in a significant net
emissions increase (see Reg 3, Part D, Sections II.A.27 and 44) or a modification which is major by itself (Potential to Emit of ≥ 250 TPY) for any pollutant listed in Regulation
No. 3, Part D, Section II.A.44 for which the area is in attainment or
attainment/maintenance may result in the application of the PSD review requirements.
Accidental Release Program — 112(r)
Section 112(r) of the Clean Air Act mandates a new federal focus on the prevention of
chemical accidents. Sources subject to these provisions must develop and implement
risk management programs that include hazard assessment, a prevention program, and
an emergency response program. They must prepare and implement a Risk
Management Plan (RMP) as specified in the Rule.
The Roggen Natural Gas Processing Plant is subject to the provisions of Section 112(r)
of the Federal Clean Air Act. 112(r) requires the submittal of a risk management plan
(RMP) by June 20, 1999 and DCP Operating Company, LP did submit an RMP by the
June 20, 1999 deadline.
Compliance Assurance Monitoring (CAM)
The following emission points at this facility use a control device to achieve compliance
with an emission limitation or standard to which they are subject and have pre -control
emissions that exceed or are equivalent to the major source threshold. They are
therefore subject to the provisions of the CAM program as set forth in 40 CFR Part 64
as adopted by reference into Colorado Regulation No. 3, Part C, Section XIV:
AIRS ID 101 (C-154) — Compressor RICE (1,100 hp) for NOx
123/0049 Page 5 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
AIRS ID 103 (C-159) Compressor RICE (1,350 hp) for NOx and CO
AIRS ID 108 (C-161) - Compressor RICE (1,350 hp) for NOx and CO
AIRS ID 115 (C-223) Compressor RICE (720 hp) for CO
AIRS ID 117 (C-225) — Compressor RICE (800 hp) for CO
AIRS ID 119 (C-227) — Compressor RICE (720 hp) for NOx and CO
AIRS ID 134 (C-181) — Compressor RICE (1,478 hp) for NOx and CO
AIRS ID 136"(P-136) — TEG Dehydration Unit (85 MMSCFD) for VOC and HAP
AIRS ID 137 (P-137) — Amine Sweetening Unit (85 MMSCFD) for HAP
AIRS ID 140 (C-192) — Compressor RICE (1,478 hp) for NOx and CO
The Roggen Natural Gas Processing Plant is a synthetic minor source for HAP and is
subject to facility -wide HAP limits. It has been determined that a facility -wide limit (as
opposed to a point -specific limit) does not preclude an emissions unit from CAM, since
it is theoretically possible for that single unit to emit HAP in excess of the major source
thresholds for HAP. As such, pollutant -specific emissions units with pre -control
emissions of HAP that exceed major source thresholds are considered to be subject to
CAM.
The emissions from the dehydration units' and amine sweetening unit's flash tanks are
routed directly back to the process. This method of controlling emissions is not subject
to the requirements of CAM. As such, the flash tank emissions from all units were
deducted from the uncontrolled emissions totals for the TEG dehydration unit P-136 and
amine sweetening unit P-137. As a result, the amine sweetening unit is subject to CAM
for HAP only, while the dehydration unit is subject to CAM for both VOC and HAP.
The remaining permitted points at this facility are not subject to CAM per the following
justifications:
AIRS ID 102 (C-155) — Compressor RICE (806 hp) exempt due to pre -control emissions
below major source thresholds
AIRS ID 107 (C-157) — Compressor RICE (806 hp) exempt due to pre -control emissions
below major source thresholds
AIRS ID 110 (C-158) - Compressor RICE (916 hp) exempt due to pre -control emissions
below major source thresholds
AIRS ID 113 (C-160) — Compressor RICE (806 hp) exempt due to pre -control emissions
below major source thresholds
AIRS ID 114 (C-156) — Compressor RICE (806 hp) exempt due to pre -control emissions
below major source thresholds
AIRS ID 122 (P025) —Fugitive Emissions exempt as an uncontrolled emissions unit
123/0049 Page 6 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
AIRS ID 125 (P039) - Stabilized Condensate Tanks (8 x 300 bbl) exempt due to pre -
control emissions below major source thresholds
AIRS ID 126 (F029) - Stabilized Condensate Loadout exempt as an uncontrolled
emission unit
AIRS ID 129 1H037) — Hot Oil Heater (7.55 MMBtu/hr) exempt as an uncontrolled
emission unit
AIRS ID 130 (P033) — TEG Dehydration Unit (4 MMSCFD) exempt due to pre -control
emissions below major source thresholds
AIRS ID 133 (F031) — Pressurized Liquid Loadout exempt as an uncontrolled emission
unit
AIRS ID 138 (P-138) — Hot Oil Heater (30.7 MMBtu/hr) exempt as an uncontrolled
emissions unit
AIRS ID 141 (FLARE) — The PSEUs routed to the flare cumulatively result in
uncontrolled VOC emissions of 344 tons/year, which exceeds the major source
threshold of 100 tons/year. However, §64.2(a) states that the requirements of CAM
"shall apply to a pollutant -specific emissions unit at a major source that is required to
obtain a part 70 or 71 permit if the unit satisfies... potential pre -control device emissions
of the applicable regulated air pollutant that are equal to or greater than 100 percent of
the amount, in tons per year, required for a source to be classified as a major source".
The plant emergency flare is used to dispose of process vapors generated by equipment
blowdowns and emergency safety relief devices. Each of the blowdown contributions
from permitted units is, when evaluated individually, less than the 100 tons/year major
source threshold. Therefore, because each PSEU venting to the flare contributes
emissions below the major source thresholds, the plant emergency flare was
determined to be exempt from the requirements of CAM.
Hazardous Air Pollutants (HAP)
The Roggen Natural Gas Processing Plant is considered a synthetic minor source in
regards to HAP emissions. As such, a facility -wide permit limit of 8 tons/year individual
HAP and 22.9 tons/year total HAP have been implemented for this facility. Because the
total HAP emission limit is greater than 20 tons/year, the source is required to track the
potential to emit (PTE) for all insignificant activities present at the Roggen Natural Gas
Processing Plant. For a more detailed discussion on HAP emission limitations, please
refer to Section VI of this document.
Calculated HAP emissions for this facility are summarized in the following table:
Pollutant
Controlled Emissions
2016 Actual
Emissions
Total HAP
(tons/year)
Reportable HAP
(tons/year)
tons/year
Acetaldehyde
0.67
0.28
0.04
Acrolein
0.63
0.26
0.04
123/0049 Page 7 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Pollutant
Controlled Emissions
2016 Actual
Emissions
Total HAP
(tons/year)
Reportable HAP
(tons/year)
tons/year
Methanol
0.73
0.30
0.00
Formaldehyde
2.63
2.62
1.65
n -Hexane
5.54
5.48
0.44
2,2,4-TMP
0.17
0.17
--
Benzene
5.16
4.78
1.43
Toluene
4.91
4.74
1.30
Ethylbenzene
0.21
0.08
0.00
Xylenes ,
1.78
1.72
0.38
Other HAP
0.24
0.00
--
Facility Total
22.67
20.45
5.28
It should be noted that these totals reflect the Division's independent calculation of HAP
emissions. The facility -wide total HAP emission limitation of 22.9 tons/year was based
on the source's calculations and was specifically requested in source correspondence
dated 12/21/2018. Slight differences in rounding account for the difference between the
facility -wide limit of 22.9 tons/year (based on source calculations) and the total HAP
reported in the preceding table (based on Division analysis).
Source Determination
With this permit action, the Division revisited the source determination in regards to the
natural gas operations in the area surrounding the Roggen Natural Gas Processing
Plant to verify that the proper pollutant emitting activities are included in this permit as
part of this facility. The applicant did not identify any other pollutant emitting activities in
the vicinity of the Roggen Natural Gas Processing Plant that are dependent upon the
facility to maintain operations. The Division considers the current determination for this
facility to be accurate, and the proper pollutant emitting activities are included in this
permit.
40 CFR Part 63 Subpart 7777 NESHAP — National Emission Standards for
Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines
This section addresses the final version of Subpart ZZZZ, last updated in the Federal
Register on 2/27/2014. For the purposes of the Roggen Natural Gas Processing Plant,
this subpart applies to compressor engines.
Affected facilities under this subpart include both area and major sources of HAP. A
major source of HAP is defined in 63.2 as "any stationary source or group of stationary
sources located within a contiguous area and under common control that emits or has
the potential to emit considering controls, in the aggregate, 10 tons per year or more of
any hazardous air pollutant or 25 tons per year or more of any combination of hazardous
air pollutants". Section §63.6675 of subpart ZZZZ lists four (4) clarifications to this
definition:
123/0049 Page 8 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
1. Emissions from any oil or gas exploration or production well (with its associated
equipment (as defined in this section)) and emissions from any pipeline
compressor station or pump station shall not be aggregated with emissions from
other similar units, to determine whether such emission points or stations are
major sources, even when emission points are in a contiguous area or under
common control
Based on the facility plot plan, there are no exploration or production wells
associated with the Roggen Natural Gas Processing Plant. Therefore, this
clarification does not apply.
2. For oil and gas production facilities, emissions from processes, operations, or
equipment that are not part of the same oil and gas production facility, as defined
in §63.1271 of subpart HHH of this part, shall not be aggregated
A natural gas processing plant is considered an oil and gas production facility
pursuant to the definition provided in §63.6675. There are no other facilities in
the vicinity of the Roggen Natural Gas Processing Plant (see Source
Determination discussion above). As such, all emissions reported from this
facility belong to it and no aggregation of other sources was undertaken for major
source determination.
3. For production field facilities, only HAP emissions from glycol dehydration units,
storage vessel with the potential for flash emissions, combustion turbines and
reciprocating internal combustion engines shall be aggregated for a major source
determination
Production field facilities are defined in §63.6675 as "oil and gas production
facilities located prior to the point of custody transfe►'. Custody transfer is defined
in this subpart as "the point at which such liquids or natural gas enters a natural
gas processing plant". The Roggen Natural Gas Processing Plant is, by
definition, located downstream of the point of custody transfer. Therefore, this
clarification does not apply.
4. Emissions from processes, operations, and equipment that are not part of the
same natural gas transmission and storage facility, as defined in §63.1271 of
subpart HHH of this part, shall not be aggregated
A natural gas transmission facility is defined in subpart HHH as "the pipelines
used for the long distance transport of natural gas (excluding processing)". The
Roggen Natural Gas Processing Plant is a processing facility and is therefore
excluded from the definition of a natural gas transmission facility. As such, this
clarification does not apply.
Pursuant to the definition of major source set forth in §62.3, the HAP emissions from
this facility are below the major source thresholds of 10 tons/year individual and 25
tons/year total HAP. Therefore, for the purposes of subpart 777Z, the Roggen Natural
Gas Processing Plant is considered to be an area source of HAP emissions.
123/0049 Page 9 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Subpart ZZZZ requires that new or reconstructed stationary RICE located at an area
source meet the requirements of subpart ZZZZ by meeting the requirements of NSPS
JJJJ for spark ignition engines. For the purposes of subpart ZZZZ, a stationary RICE
located at an area source of HAP is considered new if construction is commenced after
6/12/2006. The following table summarizes the commenced construction date reported
on the most recent APENs:
AIRS ID
Facility
Identifier
Date of Commenced
Construction
40 CFR 60 Subpart ZZZZ
Classification
101
C-154
Unknown
Existing1
102
C-155
Before 1984
Existing
103
C-159
1974
Existing
107
C-157
Before 2002
Existing
108
C-161
Before 2006
Existing
110
C-158
Before 5/2001
Existing
113
C-160
12/11/1979
Existing
114
C-156
1973
Existing
115
C-223
1/1973
Existing
117
C-225
Before 2002
Existing
119
C-227
1974
Existing
134
C-181
2011
New
140
C-192
1984
Existing
'The dates of order, manufacture and commenced operation for C-154 (AIRS 101) were reported to have taken place
between 1978 and 1979. As such, the date of commenced construction is assumed to have occurred during this time
period and this engine is therefore classified as "existing".
Based on this data, C-181 (AIRS 134) is classified as a "new" engine under subpart
Z777 Pursuant to the subpart, this engine shall meet the requirements of subpart ZZZZ
by complying with NSPS JJJJ, and is not subject to any other requirements under
subpart ZZZZ.
Under subpart ZZZZ, a source may be subject to abbreviated requirements if it is
classified as a "remote stationary RICE". To be considered a "remote stationary RICE",
the facility must meet any one of the three listed criteria in §63.6675. The Roggen
Natural Gas Processing Facility was found to meet the second criteria, which states:
A pipeline segment with 10 or fewer buildings intended for human occupancy and no
buildings with four or more stories within 220 yards (200 meters) on either side of the
centerline of any continuous 1 -mile (1.6 kilometers) length of pipeline. Each separate
dwelling unit in a multiple dwelling unit building is counted as a separate building
intended for human occupancy, AND
The pipeline segment does not lie within 100 yards (91 meters) of either a building or a
small, well-defined outside area (such as a playground, recreation area, outdoor
theater, or other place of public assembly) that is occupied by 20 or more persons on at
least 5 days a week for 10 weeks in any 12 -month period. The days and weeks need
not be consecutive. The building or area is considered occupied for a full day if it is
occupied for any portion of the day.
123/0049 Page 10 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
A "pipeline segment" is defined in §63.6675 as "all parts of those physical facilities
through which gas moves in transportation, including but not limited to pipe, valves, and
other appurtenance attached to pipe, compressor units, metering stations, regulator
stations, delivery stations, holders, and fabricated assemblies". A gas processing plant
could, therefore, be interpreted to be part of a pipeline segment. At the time of permit
issuance, the Roggen Natural Gas Processing Plant meets the above criteria and can
therefore be classified as a remote facility for the purposes of Subpart ZZZZ.
In summary, each compressor engine at the Roggen Natural Gas Processing Plant is
classified as an existing, remote engine at an area source of HAP for the purposes of
Subpart ZZZZ EXCEPT for C-181 which, as a new engine, must comply with the
applicable requirements of NSPS JJJJ. For more detailed applicability determinations,
requirements and/or exemptions for these engines, please refer to Section V of this
document.
40 CFR Part 60 Subpart JJJJ NSPS - Standards of Performance for Stationary Spark
Ignition Internal Combustion Engines
This section addresses the final version of Subpart JJJJ, last updated 8/30/2016. For
the purposes of the Roggen Natural Gas Processing Plant, this subpart applies to
compressor engine C-181.
Under the MACT ZZZZ requirements (see 40 CFR 63 Subpart ZZZZ discussion), engine
C-181 is classified as a "new" stationary RICE at an area source of HAP and must
comply with NSPS JJJJ. NSPS JJJJ is applicable to spark -ignition ICE that were
manufactured "On or after July 1, 2007, for engines with a maximum engine power
greater than or equal to 500 HP'. The rated horsepower of C-181 is 1,478 hp and the
date of manufacture, based on the most recent APEN received 8/18/2015, is 2/2011.
As such, this engine is subject to Subpart JJJJ.
For more detailed applicability determinations, requirements and/or exemptions for this
engine, please refer to Section V of this document.
40 CFR Part 60 Subpart Dc NSPS - Standards of Performance for Small Industrial -
Commercial -Institutional Steam Generating Units
This section addresses the final version of Subpart Dc, last updated in the Federal
Register on 2/16/2012. For the purposes of the Roggen Natural Gas Processing Plant,
this subpart applies to the hot oil heaters.
Affected facilities under this subpart include "each steam -generating unit for which
construction, modification, or reconstruction is commenced after June 9, 1989 and that
has a maximum design heat input capacity of 29 megawatts (MW) (100 million British
thermal units per hour (MMBtu/h)) or less, but greater than or equal to 2.9 MW (10
MMBtu/h)". A "steam generating unit" is defined in this subpart as "a device that
combusts any fuel and produces steam or heats water or heats any heat transfer
medium". The heaters at Roggen were installed after the June 9, 1989 applicability date
and are used to raise the temperature of a hot oil heat transfer fluid to facilitate the heat
exchange required to operate reboilers throughout the facility. Hot oil is, by definition, a
123/0049 Page 11 of 132
DCP Operating Company, LP Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
heat transfer medium. Therefore, for the purposes of this subpart, the hot oil heaters
are considered to be "steam generating units".
However, H037 (AIRS 129) has a design heat rating of 7.55 MMBtu/hr, which is below
the 10 MMBtu/hr applicability threshold. Therefore, H037 is not subject to the
requirements of NSPS Dc. The design heat rating of hot oil heater P-138 (AIRS 138) of
30.7 MMBtu/hr does fall within the applicability range and is therefore subject to NSPS
Dc.
For more detailed applicability determinations, requirements and/or exemptions for
these heaters, please refer to Section V of this document.
40 CFR Part 63 Subpart HH NESHAP — National Emission Standards for Hazardous
Air Pollutants From Oil and Natural Gas Production Facilities
This section addresses the final version of Subpart HH, last updated in the Federal
Register on 8/16/2012. For the purposes of the Roggen Natural Gas Processing Plant,
this subpart applies to the dehydration units.
Affected facilities under this subpart include both area and major sources of HAP. A
major source of HAP is defined in 63.2 as "any stationary source or group of stationary
sources located within a contiguous area and under common control that emits or has
the potential to emit considering controls, in the aggregate, 10 tons per year or more of
any hazardous air pollutant or 25 tons per year or more of any combination of hazardous
air pollutants". Section §63.761 of subpart HH lists three (3) clarifications to this
definition:
1. Emissions from any oil or gas exploration or production well (with its associated
equipment (as defined in this section)) and emissions from any pipeline
compressor station or pump station shall not be aggregated with emissions from
other similar units, to determine whether such emission points or stations are
major sources, even when emission points are in a contiguous area or under
common control
Based on the facility plot plan, there are no exploration or production wells
associated with the Roggen Natural Gas Processing Plant. Therefore, this
clarification does not apply.
2. Emissions from processes, operations, or equipment that are not part of the
same facility, as defined in this section, shall not be aggregated
Per subpart HH, "For the purpose of a major source determination, facility
(including a building, structure, or installation) means oil and natural gas
production and processing equipment that is located within the boundaries of an
individual surface site as defined in this section". A "surface site" is defined as
"any combination of one or more graded pad sites, gravel pad sites, foundations,
platforms, or the immediate physical location upon which equipment is physically
affixed'. Per these definitions, all equipment within the Roggen Natural Gas
Processing Plant is located on an individual surface site and is considered to be
123/0049 Page 12 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
of the "same facility". There are no other facilities within the vicinity of Roggen,
and, as such, no aggregation was undertaken for major source determination.
3. For facilities that are production field facilities, only HAP emissions from glycol
dehydration units and storage vessels shall be aggregated for a major source
determination. For facilities that are not production field facilities, HAP emissions
from all HAP emission units shall be aggregated for a major source determination
Production field facilities are defined in §63.761 as "facilities located prior to the
point of custody transfer". Custody transfer is defined in this subpart as "the point
at which such liquids or natural gas enters a natural gas processing plant". The
Roggen Natural Gas Processing Plant is, by definition, located downstream of
the point of custody transfer. Therefore, all sources of HAP emissions throughout
the facility were included in major source determination.
Pursuant to the definition of major source set forth in §62.3 and the clarifications in
§63.761, the HAP emissions from this facility are below the major source thresholds of
10 tons/year individual and 25 tons/year total HAP. Therefore, for the purposes of
subpart HH, the Roggen Natural Gas Processing Plant is considered to be an area
source of HAP. Area sources under subpart HH are subject to only TEG dehydration
unit requirements per §63.760(b)(2). Therefore, fugitive emission and storage tank
requirements set forth in this subpart have been omitted from the operating permit.
For more detailed applicability determinations, requirements and/or exemptions for
these TEG dehydration units, please refer to Section V of this document.
40 CFR Part 60 Subpart LLL NSPS - Standards of Performance for SO2 Emissions
From Onshore Natural Gas Processing for Which Construction, Reconstruction, or
Modification Commenced After January 20, 1984, and on or Before August 23, 2011
This section addresses the final version of Subpart LLL, last updated in the Federal
Register on 8/16/2012. For the purposes of the Roggen Natural Gas Processing Plant,
this subpart applies to the amine sweetening unit.
Per the most recent APEN for the amine sweetening unit, received on 7/31/2017,
operation began on 7/1/2011. Based on these dates, the amine sweetening unit
underwent construction within the applicable date range specified in this rule, and is
therefore subject to it.
For more detailed applicability determinations, requirements and/or exemptions for this
amine sweetening unit, please refer to Section V of this document.
40 CFR Part 60 Subpart KKK NSPS - Standards of Performance for Equipment Leaks
of VOC From Onshore Natural Gas Processing Plants for Which Construction,
Reconstruction or Modification Commenced After January 20, 1984, and on or Before
August 23, 2011
This section addresses the final version of Subpart KKK, last updated in the Federal
Register on 8/16/2012. For the purposes of the Roggen Natural Gas Processing Plant,
this subpart applies to fugitive emissions.
123/0049 Page 13 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
The Roggen Natural Gas Processing Plant has undergone construction, reconstruction
and modification within the applicability timeframe and, as such, is subject to the
provisions of Subpart KKK.
For more detailed applicability determinations, requirements and/or exemptions for the
fugitive emissions at this facility, please refer to Section V of this document.
40 CFR Part 60 Subpart OOOO NSPS - Standards of Performance for Crude Oil and
Natural Gas Production, Transmission and Distribution for which Construction,
Modification or Reconstruction Commenced After August 23, 2011, and on or Before
September 18, 2015
This section addresses the final version of Subpart OOOO. last updated in the Federal
Register on 6/3/2016. For the purposes of the Roggen Natural Gas Processing Plant,
this subpart applies to fugitive emissions for the entire facility.
Affected facilities under Subpart OOOO are those which include any of the following:
natural gas wells, centrifugal compressors, reciprocating compressors, natural gas
driven pneumatic controllers, storage vessels, process units, sweetening units and
hydraulically fractured gas well facilities that commence construction, reconstruction or
modification after August 23, 2011 and before September 18, 2015. The Roggen
Natural Gas Processing Plant does not have natural gas wells, centrifugal compressors,
or hydraulically fractured natural gas wells within the facility. All pneumatic controllers
at Roggen are instrument air -driven, per source correspondence received 6/2/2017.
The amine sweetening unit and storage vessels at Roggen were constructed prior to
the applicability date set forth in Subpart OOOO. Similarly, all compressors, except the
compressor driven by engine C-192, were constructed prior to the applicability dates of
NSPS OOOO. Pursuant to the NSPS OOOO initial notification received on 10/18/2012,
the compressor associated with engine C-192 commenced construction on 6/12/2012,
which falls within the applicability date range of NSPS OOOO. As such, this compressor
is subject to the requirements of NSPS OOOO. As noted in the significant modification
received on 9/11/2017, the process units RC (Roggen Compression), RP (Roggen
Plant) and RTF (Roggen Tank Farm) underwent modification within the applicability
timeframe. Process unit RC triggered NSPS OOOO requirements starting in the second
quarter of 2013, and the process units RP and RTF triggered NSPS OOOO
requirements starting in the first quarter of 2015. Therefore, NSPS OOOO is applicable
to the fugitive emissions for these three process units only. The rest of the facility is
subject to the fugitive emissions requirements under NSPS KKK.
However, it should be noted that the 12/30/2017 updates to Colorado Regulation No. 7,
Section XI I.G.1, which is federally enforceable, now require that a gas plant comply with
the LDAR requirements of Subpart OOOO, regardless of the date of construction of the
facility. As such, all process units at the Roggen Natural Gas Processing Plant are
subject to NSPS OOOO, not just those that underwent a qualifying modification as
described above. For the purposes of the Roggen Natural Gas Processing Plant,
compliance with NSPS KKK shall be presumed, provided the requirements of NSPS
OOOO are met.
123/0049 Page 14 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
For more detailed applicability determinations, requirements and/or exemptions for the
compressor associated with engine C-192 and plant fugitive emissions, please refer to
Section V of this document.
40 CFR Part 60 Subpart A §60.18 NSPS - Standards- of Performance for New
Stationary Sources General Control Device and Work Practice Requirements
This section addresses the final version of Subpart A, §60.18, last updated in the
Federal Register on 12/22/2008. For the purposes of the Roggen Natural Gas
Processing Plant, this subpart applies to the plant emergency flare.
In the significant modification received 9/11/2017, the source identified that the plant
emergency flare is no longer considered an insignificant source for the purposes of
APEN reporting. Pursuant to Subpart A, "the provisions of this part apply to the owner
or operator of any stationary source which contains an affected facility, the construction
or modification of which is commenced after the date of publication in this part of any
standard (or, if earlier, the date of publication of any proposed standard) applicable to
that facility' (§60.1(a)). The Roggen Natural Gas Processing Plant is an affected facility
under the NSPS standards and, as such, is subject to the requirements of Subpart A.
The plant emergency flare is subject to the flaring requirements addressed §60.18.
For more detailed applicability determinations, requirements and/or exemptions for this
plant emergency flare, please refer to Section V of this document.
Colorado Regulation No. 7 Section XII — Volatile Organic Compound Emissions from
Oil and Gas Operations
This section addresses the final version of Colorado Regulation No. 7 Section XII, last
updated 12/30/2017. For the purposes of the Roggen Natural Gas Processing Plant,
this section applies to oil and gas operations located within the ozone non -attainment
area.
Requirements applicable to the Roggen Natural Gas Processing Plant are as follows:
• Section XII.C.1 — General Requirements, including good engineering practice
requirements, and, for air pollution control equipment used to comply with
Section XII.J, requirements to meet a 95% control efficiency, no visible emissions
(if combustion device used) and to operate a combustion device (if used) with an
autoigniter.
o It should be noted that although Section XII.J.2 for reciprocating
compressors does not explicitly require the use of a control device to
achieve compliance, the applicability requirements Section XII.A.6
mandate that Section XII.C.1.c, d and e be complied with for reciprocating
compressors. As such, these requirements were included in the operating
permit.
• Section XII.G — Gas Processing Plant Requirements, addressing fugitive
emissions
123/0049 Page 15 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Section XII.H — Natural Gas Dehydration Units Requirements, addressing VOC
emission reductions, monitoring and recordkeeping relating to the air pollution
control equipment utilized, and semi-annual reporting
• Section XII.J — Reciprocating compressor requirements, addressing periodic rod
packing replacements and rod packing emissions collection systems
For more detailed applicability determinations, requirements and/or exemptions for the
affected operations, please refer to Section V of this document.
The following requirements from Section XII were found to be non -applicable to the
Roggen Natural Gas Processing Plant pursuant to the provided justification:
• Section XII.C.1.f — This condition requires a surveillance system be installed for
condensate storage tanks with uncontrolled actual emissions of VOC greater
than 100 tons/year. Pursuant to the most recent APEN received 5/2/2016, actual
uncontrolled emissions, as well as permitted uncontrolled emissions from these
tanks are less than the 100 ton/year threshold and as such, are not subject to
the surveillance system requirements of this section.
• Section XII.C.2 — This condition applies to condensate storage tanks subject to
Section XII.D. The condensate storage tanks at the Roggen Natural Gas
Processing Plant are not subject to Section XII.D (see below determination). As
such, the requirements of Section XII.C.2 do not apply to this facility.
• Section XII.D — This section applies to atmospheric condensate storage tanks at
affected operations. "Affected Operations" are defined in Section XII.B.1 as "oil
and gas exploration and production operations, natural gas compressor stations
and natural gas drip stations to which Section XII. applies". This definition of
affected operations excludes gas plants. Therefore, the requirements of XII.D do
not apply to the Roggen Natural Gas Processing Plant.
• Section XII.E This section addresses monitoring for condensate tanks
operating in a non -attainment area that are "controlled pursuant to this Section
Xlr. The control requirements for condensate tanks in Section XII are contained
within Section XII.D, which is not applicable to gas processing plants (see above
rationale). As such, the condensate tanks at the Roggen Natural Gas Processing
Plant are not being "controlled pursuant to this Section X11" and are therefore not
subject to Section XII.E.
• Section XII.F — This section addresses the recordkeeping and reporting
requirements for atmospheric condensate storage tanks and applies to "any
atmospheric condensate storage tank subject to control pursuant to Section
XII.D.2.". The condensate tanks at the Roggen Natural Gas Processing Plant are
not subject to XII.D (see discussion above) and are therefore not subject to the
requirements of XII.F.
• Section XII.G.2 — This section requires that control devices for unstabilized
condensate tanks achieve a control efficiency of 95%. The Roggen Natural Gas
Processing Plant has a condensate stabilization unit. Condensate stored in the
123/0049 Page 16 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
atmospheric storage tanks has been stabilized prior to entering the tank battery.
As such, this requirement is not applicable to the Roggen Natural Gas
Processing Plant and was not included in the operating permit.
• Section XII.I — These exemptions are applicable only to compressor stations and
drip stations. The Roggen Natural Gas Processing Plant is a gas plant and,
therefore, does not qualify for the exemptions set forth in Section XII.I.
• Section XII.K — This section sets forth requirements for natural gas driven
pneumatic pumps operating in the ozone non -attainment area. Per source
correspondence received 1/2/2018, there are no natural gas driven pneumatic
pumps present at the Roggen Natural Gas Processing Plant. As such, Section
XII.K does not apply to this facility.
• Section XII.L — This section sets forth LDAR requirements for natural gas
compressor stations and well production facilities operating in the ozone non -
attainment area. The Roggen Natural Gas Processing Plant, for the purposes of
Colorado Regulation No. 7, is classified as a natural gas processing plant and is
not a compressor station nor a well production facility. Therefore, Section XII.L
is not applicable to this facility.
Colorado Regulation No. 7 Section XVI — Control of Emissions from Stationary and
Portable Engines and Other Combustion Equipment in the 8 -Hour Ozone Control Area
This section addresses the final version of Colorado Regulation No. 7 Section XVI, last
updated 10/16/2018. For the purposes of the Roggen Natural Gas Processing Facility,
this section applies to stationary engines and combustion equipment located within the
ozone non -attainment area.
Requirements applicable to the Roggen Natural Gas Processing Plant are as follows:
• Section XVI.B — Air pollution control technology requirements
o Section XVI.B applies to natural gas fired stationary internal combustion
engines operating in the 8 -Hour Ozone Control Area. All engines at the
Roggen Natural Gas Processing Plant, which is located in the ozone non -
attainment area, are rated to greater than 500 hp. As such all engines are
subject to the applicable requirements of this section.
• Section XVI.D — Combustion Process Adjustment requirements
o The requirements of this section apply to affected combustion equipment
that is located at a major source of NOx as of 6/3/2016. The Roggen
Natural Gas Processing Plant was determined to be a major source of
NOx emissions prior to 6/3/2016. Affected equipment at this facility
includes the following:
• Stationary internal combustion engines of any rated horsepower
with uncontrolled actual emissions greater than or equal to five (5)
tons/year are required to comply with Section XVI.D. All engines at
123/0049 Page 17 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
the Roggen Natural Gas Processing Plant are therefore subject to
this section.
• Process heaters are affected equipment under Section XVI.D. The
Section XVI.D definition of a process heater is "an enclosed device
using controlled flame and a primary purpose to transfer heat
indirectly to a process material or to a heat transfer material for use
in a process". The hot oil heaters at Roggen are used to transfer
heat via combustion to a hot oil heat medium that is used to supply
the heat necessary to operate process reboilers. As such, these
heaters are affected combustion equipment under Section XVI.D.
For more detailed applicability determinations, requirements and/or exemptions for the
affected operations, please refer to Section V of this document.
Colorado Regulation No. 7 Section XVII — Statewide Controls for Oil and Gas
Operations and Natural Gas -Fired Reciprocating Internal Combustion Engines
This section addresses the final version of Colorado Regulation No. 7 Section XVII, last
updated 12/30/2017. For the purposes of the Roggen Natural Gas Processing Facility,
this section applies to oil and gas operations and RICE located within the state of
Colorado.
Requirements applicable to the Roggen Natural Gas Processing Plant are as follows:
• Section XVII.B — General Provisions, including good engineering practice
requirements
• Section XVII.C — Storage Tank Requirements, addressing VOC and hydrocarbon
emission reductions, audio, visual, and olfactory (AVO) inspections and
Approved Instrument Monitoring Method (AIMM) requirements
o Section XVII.C.2.b states that "owners or operators are not required to
develop and implement STEM for storage tanks containing only stabilized
liquids". The condensate tanks at the Roggen Natural Gas Processing
Plant contain only stabilized condensate. Therefore, this tank battery is
exempt from the requirements related to STEM. However, it should be
noted that the condensate tanks are still required to achieve compliance
with the operational practices of Section XVII.C.2.a according to the
schedule set forth in Section XVII.C.2.b.(ii). Compliance shall be
demonstrated with this condition by conducting approved instrument
monitoring method (AIMM) inspections, and the audio, visual and olfactory
(AVO) observations, as required by Section XVII.C.1.d.
• Section XVII.D — Dehydration Unit Requirements, addressing VOC and
hydrocarbon emission reductions
• Section XVII.E — Natural Gas Fired RICE Requirements, addressing emissions
standards for NOx, CO and VOC, AFR and NSCR installation and good
engineering practices for air pollution control equipment
123/0049 Page 18 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
For more detailed applicability determinations, requirements and/or exemptions for the
affected operations, please refer to Section V of this document.
The following requirements from Section XVII were found to be non -applicable to the
Roggen Natural Gas Processing Plant pursuant to the provided justification:
Section XVII.B.2 — For the amine sweetening unit only— Section XVII.B.2 sets forth
general requirements for 'air pollution control equipment used to comply with Section
XVII". The amine sweetening unit is not subject to any compliance requirements within
Section XVII. As such, Section XVII.B.2 is not applicable to the air pollution control
equipment used to control the amine unit. Therefore, when only the amine unit is
routed to the regenerative thermal oxidizer (RTO), this Section XVII.B.2 shall not
apply. However, if the dehydration unit P-136 is routed to the RTO, it is then subject to
the applicable requirements of Section XVII, including XVII.B.2 (see applicable
dehydration unit requirements in Section V of this document)
Section XVII.B.3 — The requirements in Section XVII.B.3 pertain to open ended lines
located at well production facilities and natural gas compressor stations (XVII.B.3.a),
wet seal centrifugal compressors (XVII.B.3.b) and rod packing for reciprocating
compressors located at natural gas compressor stations (XVII.B.3.c). Because the
Roggen Natural Gas Processing Plant is classified as a "gas processing plant" and there
are no wet seal centrifugal compressors located at this facility, none of the requirements
of Section XVII.B.3 are applicable to this facility.
Section XVII.B.5 — This section allows for an exemption for dehydration units and
engines from complying with the Section XVII requirements, provided these units "are
subject to an emissions control requirement in a federal maximum achievable control
technology ("MACT") standard under 40 CFR Part 63, a Best Available Control
Technology ("BACT") limit, or a New Source Performance Standard ("NSPS") under 40
CFR Part 60 are not subject to Section XVII., except for the leak detection and repair
requirements in Section XVII.F. The natural gas dehydration units are subject to 40
CFR 63 Subpart HH (MACT). However, as an area source, these units are subject to
area source requirements which include compliance with the optimal lean glycol
circulation rate (if they do not otherwise achieve the throughput or benzene exemption
criteria; see Section V for a more detailed discussion of the MACT HH requirements).
The Division does not consider these requirements to be a qualifying "emissions control
requirement" (i.e., numerical emissions limitation) for the purposes of the XVII.B.5
exemption. As such, the dehydration units at Roggen are subject to the provisions of
Section XVII. Similarly, the internal combustion engines at the Roggen Natural Gas
Processing Plant, which are subject to 40 CFR 63 Subpart ZZZZ (MACT), are only
required to comply with the requirements for remote area sources under this subpart.
These requirements include only work practices. These practices are not considered to
be a qualifying "emissions control requirement". Therefore, these engines must comply
with the applicable requirements of Section XVII. It should be noted, however, that C-
181, which is considered a new engine under Subpart ZZZZ must comply with NSPS
JJJJ, pursuant to Subpart ZZZZ (see the Subpart ZZZZ and JJJJ discussion above).
The NSPS Subpart JJJJ does set forth numerical emissions limitations for NOx, CO and
VOC. These limitations are considered by the Division to be a sufficient "emissions
123/0049 Page 19 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
control requirement", and, as such, engine C-181 only is exempt from the requirements
of Colorado Regulation No. 7 Section XVII.
Section XVII.C.1.b (98% DRE) — In addition to the applicable requirement for a 95%
VOC reduction for tanks with greater than six (6) tons/year actual uncontrolled VOC
emissions (see Section V of this document), this section also requires that the
combustion device must have a design destruction efficiency for hydrocarbon of 98% if
the device was authorized by permit after 5/1/2014. The combustion device associated
with the condensate tanks was authorized under Issuance 1 of Colorado Construction
Permit 12WE1242. This version of 12WE1242 was issued on 10/26/2012, prior to the
applicability date of this section. Therefore, this combustion device is not subject to the
98% DRE requirement of XVII.C.1.b.
Section XVII.C.2.b, C.2.b.(i), C.2.b.(iii) and C.2.b.(iv) — This section sets forth the
Storage Tank Emission Management (STEM) system applicability and requirements.
STEM is required for tanks that are subject to Section XVII.C.1.a and b, which set forth
emission reduction standards for tanks exceeding twenty (20) and six (6) tons/year of
actual uncontrolled VOC emissions, respectively. The storage tanks at Roggen have
permitted VOC emissions greater than both of these thresholds and, as such, qualify
for the STEM plan requirement. However, Section XVII.C.2.b states that "owners or
operators are not required to develop and implement STEM for storage tanks containing
only stabilized liquids". The condensate tanks at the Roggen Natural Gas Processing
Plant contain only stabilized condensate. Therefore, this tank battery is exempt from the
requirements related to STEM. However, it should be noted that the condensate tanks
are still required to achieve compliance with the operational practices of Section
XVII.C.2.a according to the schedule set forth in Section XVII.C.2.b.(ii). Compliance
shall be demonstrated with this condition by conducting approved instrument monitoring
method (AIMM) inspections, and the audio, visual and olfactory (AVO) observations, as
required by Section XVII.C.1.d. These requirements have been included in the
operating permit.
Section XVII.F — Section XVII.F sets forth LDAR requirements for well production
facilities and natural gas compressor stations. Since the Roggen Natural Gas
Processing Plant is classified as a gas processing plant, it is not subject to the LDAR
requirements of XVII.F.
Non -Applicable Regulations
Please note that the Roggen Natural Gas Processing Plant was determined to be totally
exempt from the following regulations:
NESHAP Subpart DDDDD — Subpart DDDDD applies to Industrial, Commercial and
Institutional Boilers and process heaters at major sources of HAP. The Roggen Natural
Gas Processing Plant is a synthetic minor source of HAP, and, as such, the provisions
of Subpart DDDDD do not apply to this facility.
NESHAP Subpart JJJJJJ — Subpart JJJJJJ applies to Industrial, Commercial and
Institutional Boilers located at area sources of HAP. Pursuant to §63.11237, a boiler is
defined as "an enclosed device using controlled flame combustion in which water is
heated to recover thermal energy in the form of steam and/or hot water... process
123/0049 Page 20 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
heaters...are excluded from the definition of Boiler" The heaters H037 (AIRS 129) and
P-138 (AIRS 138) transfer heat to a hot oil media which is used to provide heat for
reboilers. These heaters are considered "process heaters" for the purposes of this
Subpart and, as such, are not subject to the requirements of Subpart JJJJJJ.
NSPS Subpart Kb — Subpart Kb applies to storage vessels with a capacity greater than
75m3 (-472 bbl) used to store volatile organic liquids for which
construction/reconstruction/modification took place after July 23, 1984. The
atmospheric stabilized condensate storage tanks at the Roggen Natural Gas
Processing Plant each have a design capacity of 300 bbl, which is less than the
applicability threshold for subpart Kb. Therefore, Kb does not apply to these
atmospheric storage tanks. Pressurized bullet tanks storing propane, butane and
natural gasoline are also present at the Roggen Natural Gas Processing Plant.
However, per §60.110b(d)(2), subpart Kb does not apply to pressure vessels designed
to operate in excess of 204.9 kPa (-30 psi) which do not emit pollutants to atmosphere.
The bullet tanks at the Roggen Natural Gas Processing Plant fulfill both of these
exemption requirements and are therefore not subject to subpart Kb.
Colorado Regulation No. 7, Section VI - Section VI establishes requirements for the
storage and transfer of petroleum liquid. Per the definitions set forth in Section VI,
petroleum liquids are defined as "crude oil, condensate and any finished or intermediate
product manufactured or extracted in a petroleum refinery". The Roggen Natural Gas
Processing Plant stores condensate on its premises. However, the Division has
determined that the original intent of this rule was to regulate gasoline storage and
loading facilities, and is not applicable to facilities that have tanks that are otherwise
regulated. Because the stabilized condensate storage tanks at Roggen are subject to
Colorado Regulation No. 7, Section XVII (see above determination) and the facility is
not considered a gasoline storage or loading facility, the requirements of Section VI do
not apply to this facility.
Colorado Regulation No. 7, Section XVIII — Section XVIII pertains to natural gas
actuated pneumatic controllers associated with oil and gas operations. Per source
correspondence received 6/2/2017, there are no natural gas actuated pneumatic
controllers present at the Roggen Natural Gas Processing Plant. All pneumatic
controllers are instrument air -driven. As such, this section does not apply to this facility.
IV. CONSTRUCTION PERMIT REQUIREMENTS
Colorado Construction Permit 97WE0340 — Facility -Wide Permit
This facility -wide construction permit was never issued. Because the initial issuance of
the operating permit was being worked on concurrently, a draft of 97WE0340 was
submitted to the operating permit unit and incorporated into the initial issuance of the
operating permit. Units permitted under the initial issuance of the operating permit
include hot oil heater H0G7, stabilized condensate truck loadout F029, pressurized
liquids loadout F031, and all engines except C-181 (permitted under 07WE0988) and
C-192 (permitted under 12WE1193). Because this construction permit was never
issued, all references to 97WE0340 within the operating permit were removed.
123/0049 Page 21 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Colorado Construction Permit 01 WE0208 - 4 MMSCFD TEG Dehydration Unit P033,
AIRS ID 130
This section addresses the conditions established in Colorado Construction Permit
01 WE0208, Issuance 1. This permit was issued on 3/18/2015. The requirements from
this construction permit have been incorporated into the operating permit, as follows:
Conditions 1 thru 5: These conditions set forth the final approval requirements for a
newly issued construction permit. Final approval to operate was authorized by the
Division 3/29/2016 in accordance with these conditions. As such, these conditions were
not included in the operating permit.
Condition 6: Emissions of air pollutants shall not exceed the following limitations: 0.6
tons/year VOC, 8 tons/year facility -wide individual HAP, 20 tons/year facility -wide total
HAP
• The annual VOC emission limit set forth in this construction permit was
subsequently modified via the significant modification application received
7/10/2017, to account for ECD downtime. The emission limitation requested in
this application was incorporated into the operating permit. Please refer to
Section XII of this document for a more detailed discussion on the limitations
developed.
• The annual NOx and CO emissions for this dehydration unit (P033) were not
reported in this construction permit because they are below the APEN reporting
threshold of one (1) ton/year NOx (non -attainment threshold) and two (2)
tons/year for CO. However, NOx and CO emissions, including NOx and CO
resultant from pilot gas combustion for the ECD, were reported on the APEN
updates received 9/22/2017. Both NOx and CO emissions, even with the addition
of the pilot gas, remained below the de minimis thresholds listed above.
Emissions below these thresholds are typically not included in operating permits.
However, a separate condition was added to the operating permit to address
control devices, specifically the ECD and RTO. Combustion emission limitations
(NOx and CO) from each contributing source were incorporated into this
condition. Although the NOx and CO emissions from the dehydration unit P033
are below APEN reporting thresholds, these emissions were reported in the
control device condition because cumulatively, the NOx produced via
combustion at the ECD exceeds APEN thresholds.
• Since the issuance of this construction permit, modifications to the Roggen
Natural Gas Processing Plant have taken place that have increased facility -wide
HAP emissions above 20 tons/year. As such, the facility -wide HAP emission
limitation was updated to allow 22.9 tons/year total HAP. Compliance
determination for the facility -wide HAP limitations was included in a separate
condition in the operating permit (see Section VI of this document).
Condition 7: Compliance with the emission limits in this permit shall be demonstrated
by running the GRI-GLYCaIc model version 4.0 or higher on a monthly basis using the
most recent wet gas analysis and recorded operational values
123/0049 Page 22 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Condition 8: The emission points in the table below shall be operated and maintained
with the control equipment as listed in order to reduce emissions to less than or equal
to the limits established in this permit
Facility
Equipment ID
AIRS Point
Control Device
Pollutants Controlled
P033
130
Regenerative Thermal Oxidizer/Enclosed
Combustor for controlling still vent
emissions
VOC and HAP
Piping of flash gas emissions directly to
low pressure inlet
VOC and HAP
• In the permit modification submitted 7/10/2017, it was requested that the RTO
be removed as a control device for P033 and that the emissions be routed to the
ECD only. In the permit modification submitted on 11/13/2017, it was re -iterated
that the RTO be removed as a control device option for P033 and that the
emissions be routed exclusively to the ECD. This modification was incorporated
into the operating permit.
• This condition does not provide for monitoring to ensure adherence to the
specified routing of emissions, and was therefore not explicitly included as a
condition in the operating permit. However, the referenced control devices are
described in the process description in Section I of the operating permit.
Condition 9: 100% of emissions that result from the flash tank associated with this
dehydrator shall be recycled to the low pressure inlet and recompressed.
• This condition does not provide for monitoring to ensure adherence to the
specified routing of emissions, and was therefore not explicitly included as a
condition in the operating permit. However, the referenced control devices are
described in the process description in Section I of the operating permit.
• It should be noted that in the 11/13/2017 permit modification application, the
source indicated that flash emissions from the dehydration unit flash tank are
hard -piped directly to the plant inlet, not recompressed using a VRU. As such,
there is no downtime or alternative to this emissions routing. Therefore, a control
efficiency of 100% shall be applied to the flash tank emissions from the
dehydration unit, resulting in 0 emissions of VOC and HAP. Because this recycle
results in 0 flash tank emissions, flash tank emission calculations were not
included in the VOC and HAP emission calculation methods for P033.
Condition 10: This source shall be limited to the following maximum processing rates:
1,460 MMSCF/year
Condition 11: This unit shall be limited to the maximum lean glycol circulation rate of 3.5
gallons per minute.
Condition 12: The permit number and AIRS ID point number shall be marked on the
subject equipment for ease of identification. (State -Only Enforceable)
123/0049 Page 23 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 13: Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process modification, or
adjustment of control equipment visible emissions shall not exceed 30% opacity for
more than six minutes in any sixty consecutive minutes. Emission control devices
subject to Regulation 7, Sections XII.C.1.d or XVII.B.2.b shall have no visible emissions.
• It should be noted that for the purposes of Colorado Regulation No. 1, an
enclosed combustion device is considered to be a smokeless flare for the
combustion of waste gases. Therefore, this enclosed combustion device is
required to adhere only to the 30% opacity limitation of Colorado Regulation No.
1, Section II.A.5 for smokeless flares. This requirement was included in the
operating permit in lieu of the 20% opacity limitation of Colorado Regulation No.
1, Section II.A.1 and the 30% allowance of Section II.A.4, which are referenced
in this construction permit condition.
• The enclosed combustion device used to control the emissions from this
dehydration unit is subject to Section XVII.B.2.b of Regulation No. 7. Therefore,
both the opacity and visible emissions requirements of this section are included
in the operating permit under a separate condition specifically addressing control
devices.
Condition 14: This source is subject to the odor requirements of Regulation No. 2.
(State -Only Enforceable)
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 15: This equipment is subject to the control requirements for glycol natural
gas dehydrators under Regulation No. 7, Section XII.H. This source shall comply with
all applicable general provisions of Regulation 7, Section XII.
• Both the requirements from the general provisions of Section XII and the
requirements from Section XII.H specific to dehydration unit pollution control
were included as separate conditions in the operating permit.
Condition 16: The combustor covered by this permit is subject to Regulation No. 7,
Section XVII.B General Provisions (State -Only Enforceable). The operator shall
comply with all applicable requirements of Section XVII.
• Section XVII.B requires that all combustion devices used to control emissions of
hydrocarbons must be equipped with and operate an auto -igniter. The applicable
requirements of Section XVII general provisions and auto -igniter requirements
were included in the operating permit under a separate condition specifically
addressing control devices.
123/0049 Page 24 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Condition 17: This equipment is subject to the control requirements for glycol natural
gas dehydrators under Regulation No. 7, Section XVII.D (State -Only Enforceable).
This source shall comply with all applicable general provisions of Regulation 7, Section
XVII.
• The applicable requirements of Section XVII, including those referenced in this
condition, were included as separate conditions in the operating permit.
Condition 18: This source is subject to the requirements of 40 CFR, Part 63, Subpart
HH - National Emission Standards for Hazardous Air Pollutants for Source Categories
from Oil and Natural Gas Production Facilities.
• The applicable requirements of MACT HH, including those listed in this
construction permit, were absorbed into the operating permit.
Condition 19: 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.
• The terms of the most recent O&M plan (submitted with. the 11/13/2017 permit
modification application) were incorporated into the operating permit. Therefore,
this specific condition was not included.
Condition 20: When the regenerative thermal oxidizer (RTO) is used to control
emissions from the dehydration unit, the combustion chamber temperature of the RTO
shall be recorded as per the frequency required in the O&M Plan.
• In the permit modification submitted 7/10/2017, it was requested that the RTO
be removed as a control device for P033 and that the emissions be routed to the
ECD only. In the permit modification submitted on 11/13/2017, it was re -iterated
that the RTO be removed as a control device option for P033 and that the
emissions be routed exclusively to the ECD. This condition was therefore not
incorporated into the operating permit.
Condition 21: When the RTO is used to control emissions from the dehydration unit, the
operating temperature of the RTO shall be greater than 1450 °F, at all times that the
dehydration unit still vent emissions are routed to the RTO in order to meet the emission
limits in this permit.
• In the permit modification submitted 7/10/2017, it was requested that the RTO
be removed as a control device for P033 and that the emissions be routed to the
ECD only. In the permit modification submitted on 11/13/2017, it was re -iterated
that the RTO be removed as a control device option for P033 and that the
emissions be routed exclusively to the ECD. This condition was therefore not
incorporated into the operating permit.
Condition 22: Initial Testing Requirements - The owner or operator shall demonstrate
compliance with opacity standards, using EPA Method 22 to determine the presence or
absence of visible emissions. "Visible Emissions" means observations of smoke for any
123/0049 Page 25 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document —Renewal Operating Permit
period or periods of duration greater than or equal to one (1) minute in any fifteen (15)
minute period during normal operation.
• This construction permit was granted Final Approval to operate by the Division
3/29/2016. As such, initial testing requirements were not included in the
operating permit.
Condition 23: 'The owner or operator shall demonstrate compliance with opacity
standards, using EPA Method 22 to determine the presence or absence of visible
emissions per the frequency required in the O&M Plan. "Visible Emissions" means
observations of smoke for any period or periods of duration greater than or equal to one
(1) minute in any fifteen (15) minute period during normal operation.
• The most recent O&M plan (submitted with the 11/13/2017 permit modification
application) requires daily visual observations. This frequency was added to the
construction permit condition to conduct Method 22 readings and included in the
operating permit under a separate condition specifically addressing control
devices. To monitor compliance with the Colorado Regulation No. 1 Section
II.A.5 opacity standard, an additional requirement to conduct Method 9
observations in the event visual emissions are detected via Method 22 readings
was included in the operating permit.
Condition 24: The owner or operator shall complete an extended wet gas analysis prior
to the inlet of the TEG dehydrator on an annual basis.
Condition 25: All previous versions of this permit are cancelled upon issuance of this
permit.
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 26: Revised APEN submittal requirements and deadlines
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 27: This source is subject to the provisions of Regulation No. 3, Part C,
Operating Permits. The provisions of this construction permit must be incorporated into
the Operating Permit. The application for the modification to the Operating Permit is due
within one year of the issuance of this permit.
• With the issuance of this operating permit on XX/X(/)000(, this construction
permit is considered to be absorbed by the operating permit, thus fulfilling this
requirement. Therefore, this condition was not included in the operating permit.
Condition 28: MACT Subpart HH - National Emission Standards for Hazardous Air
Pollutants From Oil and Natural Gas Production Facilities major stationary source
requirements shall apply to this stationary source at any such time that this stationary
source becomes major solely by virtue of a relaxation in any permit limitation and shall
be subject to all appropriate applicable requirements of Subpart HH.
123/0049 Page 26 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• The PSD/NANSR relaxation requirements do not apply to federal NESHAPs. As
such, this condition was not included in the operating permit.
Conditions 29 thru 35: These requirements are included in the Section IV General
Conditions of the operating permit and/or the Colorado Revised Statutes. As such,
separate conditions for these requirements were not created for the operating permit.
Colorado Construction Permit 07WE0988 - 1,478 HP RICE C-181, AIRS ID 134
This section addresses the conditions established in Colorado Construction Permit
07WE0988. This permit was issued 8/26/2008. The requirements from this construction
permit have been incorporated into the operating permit as follows:
Condition 1: Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process modification, or
adjustment of control equipment visible emissions shall not exceed 30% opacity for
more than six minutes in any sixty consecutive minutes. EPA Method 9 shall be used to
measure opacity.
• Because this engine is permitted to use only natural gas as fuel, compliance with
this opacity limitation shall be presumed, provided the permittee demonstrates
that only natural gas was utilized during each compliance period. As such, EPA
Method 9 observations are not required and were therefore not included in the
operating permit.
Condition 2: The permit number shall be marked on the subject equipment for ease of
identification. (State -Only Enforceable)
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 3: Emissions of air pollutants shall not exceed the following limitations: 28.54
tons/year NOx, 14.27 tons/year VOC, 28.54 tons/year CO, 0.52 tons/year
formaldehyde, 8 tons/year facility -wide individual HAP, 20 tons/year facility -wide total
HAP
• The annual limits for NOx and VOC have been revised since the last issuance of
this construction permit. The emission limitations listed in the operating permit
reflect those requested in the permit modification application received 7/10/2017.
• The formaldehyde limit set forth in this construction permit has been streamlined
in favor of the 8 tons/year and 22.9 tons/year facility -wide HAP limits. This was
noted as such in the operating permit. Refer to Section XI of this document for
streamlining details.
• Since the issuance of this construction permit, modifications to the Roggen
Natural Gas Processing Plant have taken place that have increased facility -wide
HAP emissions above 20 tons/year. As such, the facility -wide HAP emission
limitation was updated to allow 22.9 tons/year total HAP. Compliance
determination for the facility -wide HAP limitations was included in a separate
condition in the operating permit (see Section VI of this document).
123/0049 Page 27 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Condition 4: This source shall be limited to a maximum consumption rate as listed:
Consumption of natural gas as fuel shall not exceed 97.10 MMSCF/year.
Condition 5: A source compliance test shall be conducted during self -certification to
measure the emission rate(s) for the pollutants listed, using EPA approved methods:
Oxides of Nitrogen, Carbon Monoxide, Volatile Organic Compounds, Formaldehyde
• Self -certification for this unit was received on 3/19/2009, fulfilling the
requirements of this condition. As such, this condition was omitted from the
operating permit.
Condition 6: This engine shall be equipped with a(n) NSCR capable of reducing
uncontrolled emissions as follows:
Pollutant
Control Efficiency
NOx
At least 84.6%
CO
At least 77.8%
VOC
At least 50%
Operating parameters of the control equipment are identified in the operation and
maintenance plan as specified in Attachment B. The identified operating parameters will
replace the control efficiency requirement on the final permit.
• At the time of permit issuance, the emission standards set forth in NSPS JJJJ
had not yet been adopted into Colorado Regulation No. 6. The emission
standards reflected in the operating permit have been updated to reflect those
set forth in NSPS JJJJ.
• The terms of the O&M plan were incorporated into the operating permit.
Therefore, the requirement related to the O&M plan was not included.
Condition 7: Within one hundred and eighty days (180) after commencement of
operation, the applicant shall adopt and follow the operating and maintenance plan and
record keeping format as specified in Attachment B, in order to demonstrate compliance
on an ongoing basis with the requirements of this permit.
• The terms of the O&M plan were incorporated into the operating permit.
Therefore, this specific condition was not included.
Condition 8: Prevention of Significant Deterioration (PSD) requirements shall apply to
this source at any such time that this source becomes major solely by virtue of a
relaxation in any permit condition. Any relaxation that increases the potential to emit
above the applicable PSD threshold will require a full PSD review of the source as
though construction had not yet commenced on the source. The source shall not exceed
the PSD threshold until a PSD permit is granted.
• This requirement is evaluated on a case -by -case basis that is dependent on
specific parameters of undefined future modifications. This requirement will be
evaluated at that time and, as such, this condition was not included in the
operating permit.
123/0049 Page 28 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
.Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Condition 9: MACT Subpart. ZZZZ - National Emission Standards for Hazardous Air
Pollutants for Stationary Reciprocating Internal Combustion Engines requirements shall
apply to this source at any such time that this source becomes major solely by virtue of
a relaxation in any permit limitation and shall be subject to all appropriate applicable
requirements of that Subpart on the date as stated in the rule as published in the Federal
Register.
• The PSD/NANSR relaxation requirements do not apply to federal NESHAPs. As
such, this condition was not included in the operating permit.
Condition 10: This source shall be subject to the requirements of Regulation Number 7,
Section XVI (Control -of emissions from stationary and portable engines in the 8 -hour
Ozone Control Area).
• The applicable requirements of Section XVI were included in the operating
permit.
Condition 11: Revised APEN submittal requirements and deadlines
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Conditions 12 & 13: These conditions set forth the final approval requirements for a
newly issued construction permit. Final approval to operate was authorized by the
Division 1/17/2015 in accordance with these conditions. As such, these conditions were
not included in the operating permit.
Colorado Construction Permit 10WE1659 — Fugitive Equipment Leaks P025, AIRS
ID 122; 85 MMSCFD TEG Dehydration Unit P-136, AIRS ID 136; 85 MMSCFD Amine
Sweetening Unit P-137, AIRS ID 137; 30.7 MMBtu/hr Hot Oil Heater P-138, AIRS ID
138
This section addresses the conditions established in Colorado Construction Permit
10WE1659. This permit was issued on 3/18/2015. As of the operating permit issuance
date of XX/XX/XXXJC, This permit has not yet obtained Final Approval to operate from
the Division. The requirements from this construction permit have been incorporated
into the operating permit as follows:
It should be noted that the outstanding final approval requirements pertain to the amine
sweetening unit and RTO (AIRS 137; P-137) only. This unit has not operated since 2013
and is not expected to operate in the foreseeable future, however, the source has
explicitly requested that the permit for this unit be retained. As such, the due date of the
semi-annual monitoring reports required by this operating permit will be more than 180
days after the amine sweetening unit AIRS 137 re -commences operation. Therefore,
under the provisions of Regulation No. 3, Part C, Section V.A.2, the Division is allowing
the initial approval construction permit to continue in full force and effect and will
consider the Responsible Official certification submitted with that report to serve as the
demonstration required pursuant to Regulation No. 3, Part B, Section III.G.2 and no final
123/0049 Page 29 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document Renewal Operating Permit
approval construction permit will be issued. The appropriate provisions of the initial
approval construction permit have been directly incorporated into this operating permit.
Condition 1: Within one hundred and eighty days (180) after issuance of this permit,
compliance with the conditions contained on this permit shall be demonstrated to the
Division.
• Self -certification for this permit was received by the Division on 9/14/2015, which
was within the 180 day window. However, the self -certification did not include the
required stack testing for the regenerative thermal oxidizer since this unit has not
been in operation since 5/8/2013. Because of this, the Division has not granted
the source final approval to operate. A separate condition for initial compliance
demonstration was included in the operating permit under a separate condition
specifically addressing control devices. This condition was modified to require
the outstanding stack test be completed within 60 days of startup of the
regenerative thermal oxidizer.
• Division -standard language addressing testing protocols and submission
timelines was added to this condition.
Condition 2: This permit shall expire if the owner or operator of the source for which this
permit was issued: (i) does not commence construction/modification or operation of this
source within 18 months after either, the date of issuance of this construction permit or
the date on which such construction or activity was scheduled to commence as set forth
in the permit application associated with this permit; (ii) discontinues construction for a
period of eighteen months or more; (iii) does not complete construction within a
reasonable time of the estimated completion date.
• All units permitted under 10WE1659 were constructed in a timely fashion. As
such, this condition was not included in the operating permit.
Condition 3: 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.
• This condition has been modified to require the applicable testing and was
included under a separate condition in the operating permit specifically
addressing control devices. See discussion under Conditions 1 and 34.
Condition 4: The operator shall retain the permit final authorization letter issued by the
Division after completion of self -certification, with the most current construction permit.
This construction permit alone does not provide final authority for the operation of this
source.
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 5: Emissions of air pollutants shall not exceed the following limitations:
Tons per Year
123/0049 Page 30 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Facility
Equipment ID
AIRS
Point
NOx
VOC
CO
SO2
Emission
Type
P025
122
---
33.5
---
---
Fugitives
P-136
136
2.6
21.6
14.3
---
Point
P-137
137
0.8
2.3
4.6
30.0
Point
Hot Oil Heater
138
7.0
0.7
11.8
---
Point
Facility -wide emissions of each individual hazardous air pollutant shall be less than 8.0
tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than 20.0 tpy.
• In the permit modification application received 11/13/2017, the source indicated
that all modification requests submitted for the dehydration unit P-136 between
July and September 2017 be cancelled, and that P-136 instead comply with the
limitations and requirements within the 11/13/2017 modification application. The
Division accepted this request and has therefore incorporated new VOC, NOx
and CO limitations into the operating permit renewal, based on an updated
ProMax model run and 2% permitted ECD downtime. Please refer to Section XII
of this document for a more detailed discussion on 11/13/2017 modification.
• In the permit modification application received 11/13/2017, the source indicated
that all modification requests submitted for the amine sweetening unit P-137
between July and September 2017 be cancelled, and that P-137 revert to
complying with the requirements of 10WE1659 Issuance 5. The Division
accepted this request and has therefore not incorporated any modification
requests subsequent to the 10WE1659 issuance on 3/18/2015 into the operating
permit renewal. However, in the P-137 APEN received with the 11/13/2017
permit modification application (submitted to effectively nullify all APEN updates
included with the modifications subsequent to the 10W1659 issuance and
reverting P-137 to the limitations of 10WE1659), the source updated the annual
CO emission limit for P-137 to reflect the new emission factor for CO from the
December 2016 modification to AP -42, Section 13.5 for Industrial Flares Table
13.5-2. In subsequent email correspondence received 2/9/2018, the source
requested that the potential burner fuel combustion be permitted for the RTO at
the maximum burner firing rate, thus increasing the NOx and CO emission
limitations for this unit. These requested modifications, though not reflected in
the 3/18/2015 issuance of 10WE1659, were incorporated into the operating
permit.
• The annual VOC emission limit for the hot oil heater (P-138) in this construction
permit is below the APEN reporting threshold for non -attainment areas of one (1)
ton/year. Limits below APEN reporting thresholds are typically not included in
operating permits. As such, this VOC limit was omitted from the operating permit.
• Since the issuance of this construction permit, modifications to the Roggen
Natural Gas Processing Plant have taken place that have increased facility -wide
HAP emissions above 20 tons/year. As such, the facility -wide HAP emission
limitation was updated to allow 22.9 tons/year total HAP. Compliance
123/0049 Page 31 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
determination for the facility -wide HAP limitations was included in a separate
condition in the operating permit (see Section VI of this document).
Condition 6: Point 122 — The operator shall calculate actual emissions from this emissions
point based on representative actual component counts for the facility along with the most
recent gas analysis.
Condition 7: Point 136 — Compliance with the emission limits in this permit shall be
demonstrated by running either the BR&E ProMax or the GRI-GLYCaIc process
simulation software or Division -approved equivalent software on a monthly basis using
the most recent plant inlet gas analysis and recorded operational values.
Condition 8: Point 136 — This unit shall be configured such that the still vent vapors are
routed to the regenerative thermal oxidizer (RTO) or an enclosed combustor as an
alternate control device. The RTO or enclosed combustor shall reduce uncontrolled
emissions of VOC from the TEG dehydration unit to the emission levels listed in this
section, above. The RTO or enclosed combustor shall achieve a minimum destruction
efficiency of 97% for VOC. Operating parameters of the control equipment are identified
in the operation and maintenance plan.
• In the permit modification application received 11/13/2017, the source indicated
that the enclosed combustion device shall now be the primary control device for
P-136, and the RTO shall serve as a backup control device. This change was
made since the RTO will only operate if the amine sweetening unit P-137 is
running. Dehydration unit P-136 operates more frequently than does amine
sweetening unit P-137. As such, the dehydration unit is often operating when the
RTO is not. Therefore, the primary control device was re -defined to be the
enclosed combustion device for P-136, which also destructs emissions from the
smaller dehydration unit P033.
• The destruction efficiency referenced in this condition was excluded from the
operating permit. This destruction efficiency is inherent to the annual limitation
calculation of VOC and HAP emissions, and is therefore indirectly included in the
operating permit and does not require a separate condition. It should also be
noted that the destruction efficiency of the ECD was lowered to 95% in the permit
modification application received 11/13/2017. This lower destruction efficiency
was used to calculate the new annual emission limitation for the dehydration unit,
and, as such, the destruction efficiency is indirectly included in the operating
permit.
• This condition does not provide for monitoring to ensure adherence to the
specified routing of emissions, and was therefore not explicitly included as a
condition in the operating permit. However, the referenced control devices and
emission routing are described in the process description in Section I of the
operating permit.
• The terms of the most recent O&M plan (submitted with the 11/13/2017 permit
modification application) were incorporated into the operating permit.
123/0049 Page 32 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Condition 9: Point 136 — 100% of emissions from the flash tank associated with this
dehydrator shall be recycled to the plant inlet and recompressed.
• This condition does not provide for monitoring to ensure adherence to the
specified routing of emissions, and was therefore not explicitly included as a
condition in the operating permit: However, the referenced control devices and
emission routing are described in the process description in Section I of the
operating permit.
• It should be noted that in the 11/13/2017 permit modification application, the
source indicated that flash emissions from the dehydration unit flash tank are
hard -piped directly to the plant inlet, not recompressed using a VRU. As such,
there is no downtime or alternative to this emissions routing. Therefore, a control
efficiency of 100% shall be applied to the flash tank emissions from the
dehydration unit, resulting in 0 emissions of VOC and HAP. Because this recycle
results in 0 flash tank emissions, flash tank emission calculations were not
included in the VOC and HAP emission calculation methods for P-136.
Condition 10: Point 137 — Compliance with the emission limits in this permit shall be
demonstrated by running the ProMax process simulation software or Division -approved
equivalent software on a monthly basis using the most recent amine unit inlet extended
gas analysis.
Condition 11: Point 137 — Emissions from the still vent shall be collected and controlled
by a regenerative thermal oxidizer (RTO) in order to reduce the emissions of volatile
organic compounds to the level listed in this section, above. The RTO shall achieve a
minimum destruction efficiency of 97% for VOC. Operating parameters of the thermal
oxidizer are identified in the operation and maintenance plan for this unit.
• The destruction efficiency referenced in this condition was excluded from the
operating permit. This destruction efficiency is inherent to the annual limitation
calculation of VOC. and HAP emissions, and is therefore indirectly included in the
operating permit and does not require a separate condition.
• This condition does not provide for monitoring to ensure adherence to the
specified routing of emissions, and was therefore not explicitly included as a
condition in the operating permit. However, the referenced control devices and
emission routing are described in the process description in Section I of the
operating permit.
• The terms of the most recent O&M plan (submitted with the 11/13/2017 permit
modification application) were incorporated into the operating permit.
Condition 12: Point 137 — 100% of emissions from the flash tank associated with this
amine unit shall be recycled to the plant inlet and recompressed.
This condition does not provide for monitoring to ensure adherence to the
specified routing of emissions, and was therefore not explicitly included as a
condition in the operating permit. However, the referenced control devices and
123/0049 Page 33 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
emission routing are described in the process description in Section I of the
operating permit.
• It should be noted that in the 11/13/2017 permit modification application, the
source indicated that flash emissions from the amine sweetening unit flash tank
are hard -piped directly to the plant inlet, not recompressed using a VRU. As such,
there is no downtime or alternative to this emissions routing. Therefore, a control
efficiency of 100% shall be applied to the flash tank emissions from the amine
sweetening unit, resulting in 0 emissions of VOC and HAP. Because this recycle
results in 0 flash tank emissions, flash tank emission calculations were not
included in the VOC and HAP emission calculation methods for P-137.
Condition 13: This source shall be limited to the following maximum consumption,
processing and/or operational rates as listed below.
Facility Equipment ID
AIRS Point
Process Parameter
Annual Limit
P-136
136
Natural gas plant throughput
31,025 MMscf/yr
P-137
137
Natural gas plant throughput
31,025 MMscf/yr
Hot Oil Heater
138
Natural gas throughput
280.7 MMscf/yr
Condition 14: Point 136 — This unit shall be limited to the maximum lean glycol
circulation rate 24 gallons per minute.
Condition 15: Point 137 — This unit shall be limited to the maximum lean amine
recirculation pump rate of 376 gallons per minute.
• The condition was modified in the operating permit to reflect the lean amine
circulation rate requested on the most recent APEN submitted 11/13/2017. The
lean amine circulation rate is correctly listed on the APEN as 350 gpm. The rich
amine circulation rate, which is not subject to any limitations, is 376 gpm.
Condition 16: The permit number and AIRS ID number shall be marked on the subject
equipment for ease of identification. (State -Only Enforceable).
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 17: Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process modification, or
adjustment of control equipment visible emissions shall not exceed 30% opacity for
more than six minutes in any sixty consecutive minutes.
• It should be noted that for the purposes of Colorado Regulation No. 1, an
enclosed combustion device is considered to be a smokeless flare for the
combustion of waste gases. Therefore, the enclosed combustion device used to
destruct still vent emissions from P-136 is required to adhere only to the 30%
opacity limitation of Colorado Regulation No. 1, Section II.A.5 for smokeless
flares. This requirement was included in the operating permit in lieu of the 20%
opacity limitation of Colorado Regulation No. 1, Section II.A.1 and the 30%
123/0049 Page 34 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
allowance of Section II.A.4, which are referenced in this construction permit
condition for the ECD only. It should be noted that both the hot oil heater P-138
and the RTO used to destruct acid gas vent emissions from the amine unit P-137
are subject to the Colorado Regulation No. 1 Section II.A.1 and II.A.4 opacity
requirements, as required by this construction permit condition. These
requirements have been included in the operating permit for both heater P-138
and the RTO for amine unit P-137.
Pursuant to Colorado Regulation No. 7, Section XVII.B.2.b., all air pollution
control equipment used to comply with Section XVII is required to operate with
no visible emissions (effectively, 0% opacity) during normal operation. Because
the ECD (and, for P-136 only, the RTO) are used to destruct emissions from
dehydration units, which are subject to the dehydration unit requirements of
Section XVII.D, these control devices must comply with the no visible emissions
requirements. As such, compliance with the Colorado Regulation No. 1, Section
II.A.1, II.A.4 and II.A.5 opacity requirements shall be presumed, provided the.
requirements of Colorado Regulation No. 7 Section XVII.B.2.b. are met.
Condition 18: This source is subject to the odor requirements of Regulation No. 2.
(State -Only Enforceable)
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 19: Point 122 — This source is subject to Regulation No. 7, Section XII.G.1
(State -Only Enforceable). The operator shall comply with all applicable requirements
of Section XII.G.
• The applicable requirements of Section XII.G were included in the operating
permit.
• It should be noted that Section XII.G, as it applies to the current 8 hour ozone
control area, is incorporated into the SIP and, as such, is federally enforceable.
Section XII.G is state -only enforceable for facilities operating in any new non-
attainment/maintenance areas that may exist in the future. Because the Roggen
Natural Gas Processing Plant operates within the current 8 hour ozone control
area, Section XII.G is state and federally enforceable. Therefore, the "state -only
enforceable" designation was removed from the operating permit.
Condition 20: Point 122 — This facility is subject to the New Source Performance
Standards requirements of Regulation No. 6, Part A, Subpart KKK, Standards of
Performance for Onshore Natural Gas Processing Plants.
• As noted in the significant modification received 9/11/2017, Process Units RC
(Roggen Compression), RP (Roggen Plant) and RTF (Roggen Tank Farm)
underwent subsequent modifications that triggered NSPS OOOO. The
applicable requirements of NSPS OOOO have been included in the operating
permit. It should be noted that the remainder of the facility is subject to NSPS
KKK.
123/0049 Page 35 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document -Renewal Operating Permit
With the 12/30/2017 updates to Colorado Regulation No. 7, Section XII, natural
gas processing plants are now subject to the LDAR requirements of NSPS
OOOO regardless of the date of plant construction. As such, for the purposes of
the Roggen Natural Gas Processing Plant, compliance with NSPS KKK shall be
presumed, provided the requirements of NSPS OOOO are met.
Condition 21: Point 136 — This equipment is subject to the control requirements for
glycol natural gas dehydrators under Regulation No. 7, Section XII.H. This source shall
comply with all applicable general provisions of Regulation 7, Section XII.H.
• Both the requirements from the general provisions of Section XII and the
requirements from Section XII.H specific to dehydration unit pollution control
were included as separate conditions in the operating permit.
Condition 22: Point 136 — The regenerative thermal oxidizer (RTO) covered by this
permit is subject to Regulation No. 7, Section XVII.B.1.a and XVII.B.1.c General
Provisions (State -Only Enforceable). The operator shall comply with all applicable
requirements of Section XVII.B.1.a and XVII.B.1.c.
• Section XVII.B.1.c no longer exists in Colorado Regulation No. 7, and was
therefore not included in the operating permit.
Condition 23: Point 136 — The combustor covered by this permit is subject to Regulation
No. 7, Section XVII.B General Provisions (State -Only Enforceable). If a flare or other
combustion device is used to control emissions of volatile organic compounds and other
hydrocarbons to comply with Section XVII, it shall be enclosed, have no visible
emissions during normal operations, and be designed so that an observer can, by
means of visual observation from the outside of the enclosed flare or combustion device,
or by other convenient means approved by the Division, determine whether it is
operating properly. The operator shall comply with all applicable requirements of
Section XVII.
All combustion devices used to control emissions of hydrocarbons must be equipped
with and operate an auto -igniter.
• The applicable requirements of Section XVII general provisions and auto -igniter
requirements were included in the operating permit under a separate control
device condition.
Condition 24: Point 136 — This equipment is subject to the control requirements for
glycol natural gas dehydrators under Regulation No. 7, Section XVII.D (State -Only
Enforceable). This source shall comply with all applicable general provisions of
Regulation 7, Section XVII.
• The applicable requirements of Section XVII, including those referenced in this
condition, were included as separate conditions in the operating permit.
Condition 25 & 26: Point 136 — This source is subject to the TEG dehydrator area source
requirements of 40 CFR, Part 63, Subpart HH - National Emission Standards for
Hazardous Air Pollutants for Source Categories from Oil and Natural Gas Production
Facilities
123/0049 Page 36 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
The applicable requirements of MACT HH, including those listed in this
construction permit, were absorbed into the operating permit EXCEPT as
specified below:
o The initial compliance notification for P-136 was received 1/15/2014.
Therefore, MACT HH conditions relating to initial notification activities
were omitted from the operating permit.
o The notification of process change conditions were omitted because these
requirements apply only to large dehydration units at major sources of
HAP
Condition 27: Point 137 — This amine unit is subject to the New Source Performance
Standards requirements of Regulation No. 6, Part A, Subpart LLL, Standards of
Performance for Onshore Natural Gas Processing: SO2 Emissions
• The applicable requirements of NSPS LLL, including those listed in this
construction permit, were absorbed into the operating permit.
Condition 28: Point 138 — This source is subject to the New Source Performance
Standards requirements of Regulation No. 6, Part A Subpart Dc, Standards of
Performance for Small Industrial -Commercial -Institutional Steam Generating Units
• The applicable requirements of NSPS Dc, including those listed in this
construction permit, were absorbed into the operating permit.
Condition 29: Upon issuance of this permit, the applicant shall follow the 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.
• The terms of the most recent O&M plan (submitted with the 11/13/2017 permit
modification application) were incorporated into the operating permit. Therefore,
this specific condition was not included.
Condition 30: Points 136 & 137 — When the regenerative thermal oxidizer (RTO) is used
to control emissions from the amine unit or dehydration unit, the combustion chamber
temperature of the RTO shall be recorded as per the frequency required in the O&M
Plan.
• The most recent O&M plan (submitted with the 11/13/2017 permit modification
application) requires daily monitoring of the combustion chamber temperature of
the RTO. This frequency was added to the construction permit condition and
included in the operating permit.
Condition 31: Points 136 & 137 — When the RTO is used to control emissions from the
amine unit or dehydration unit, the operating temperature of the RTO shall be greater
than 1450 °F, at all times that any amine unit and dehydration unit still vent emissions
are routed to RTO in order to meet the emission limits in this permit.
123/0049 Page 37 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document— Renewal Operating Permit
Condition 32: Point 137 — The inlet gas temperature and inlet gas pressure shall be
measured and recorded weekly.
Condition 33: Point 136— The owner or operator shall complete the initial annual
extended wet gas analysis testing required by this permit and submit the results to the
Division as part of the self -certification process to ensure compliance with emissions
limits.
• The required annual extended wet gas analysis was received 9/14/2015, fulfilling
this condition. Therefore, this condition was not included in the operating permit.
Condition 34: Initial Testing Requirements for the RTO/Enclosed Combustor — The
owner or operator shall demonstrate compliance with opacity standards, using EPA
Method 22 to determine the presence or absence of visible emissions. "Visible
Emissions" means observations of smoke for any period or periods of duration greater
than or equal to one (1) minute in any fifteen (15) minute period during normal operation.
• In general, initial compliance requirements are not included in the operating
permit. However, this construction permit has not yet been granted final approval.
The RTO stack test conducted on 3/12/2013 failed to comply with the SO2
emission limits set forth in this construction permit. However, the RTO has not
been operated since 5/8/2013 and as such, there has not been a viable
opportunity to perform a stack test to demonstrate compliance. Therefore, final
approval for this construction permit has not been authorized. For this reason,
initial compliance testing requirements were included in the operating permit
under a separate condition specifically addressing control devices.
Condition 35: A source initial compliance test shall be conducted on the combined
emission streams being routed to the RTO to measure the emission rate(s) for the
pollutants listed below in order to demonstrate compliance with the emissions limits
contained in this permit. The test shall include inlet and outlet testing for VOC in order
to demonstrate compliance with the minimum destruction efficiency of 97% for the RTO
in addition to outlet testing for sulfur dioxide. The test protocol must be in accordance
with the requirements of the Air Pollution Control Division Compliance Test Manual and
shall be submitted to the Division for review and approval at least thirty (30) days prior
to testing. No compliance test shall be conducted without prior approval from the
Division. Any compliance test conducted to show compliance with a monthly or annual
emission limitation shall have the results projected up to the monthly or annual
averaging time by multiplying the test results by the allowable number of operating hours
for that averaging time.
• In general, initial compliance requirements are not included in the operating
permit. However, this construction permit has not yet been granted final approval.
The RTO stack test conducted on 3/12/2013 failed to comply with the SO2
emission limits set forth in this construction permit. However, the RTO has not
been operated since 5/8/2013 and as such, there has not been a viable
opportunity to perform a stack test to demonstrate compliance. Therefore, final
approval for this construction permit has not been authorized. For this reason,
123/0049 Page 38 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
initial compliance testing requirements were included in the operating permit
under a separate condition specifically addressing control devices.
Condition 36: Point 122 — On an annual basis, the permittee shall complete an extended
gas analysis of gas samples that are representative of volatile organic compounds
(VOC) and hazardous air pollutants (HAP) that may be released as fugitive emissions.
Condition 37: Point 122 — This facility is subject to the leak detection and repair (LDAR)
requirements of 40 C.F.R Part 60, Subpart KKK.
• As noted in the significant modification received 9/11/2017, Process Units RC
(Roggen Compression), RP (Roggen Plant) and RTF (Roggen Tank Farm)
underwent subsequent modifications that triggered NSPS OOOO. The
applicable requirements of NSPS OOOO have been included in the operating
permit. It should be noted that the remainder of the facility is subject to NSPS
KKK.
• With the 12/30/2017 updates to Colorado Regulation No. 7, Section XII, natural
gas processing plants are now subject to the LDAR requirements of NSPS
OOOO regardless of the date of plant construction. As such, for the purposes of
the Roggen Natural Gas Processing Plant, compliance with NSPS KKK shall be
presumed, provided the requirements of NSPS OOOO are met.
Condition 38: Point 136 — The owner or operator shall complete an extended wet gas
analysis of the plant inlet on an annual basis.
Condition 39: RTO/Enclosed Combustor — The owner or operator shall demonstrate
compliance with opacity standards, using EPA Method 22 to determine the presence or
absence of visible emissions per the frequency required in the O&M Plan. "Visible
Emissions" means observations of smoke for any period or periods of duration greater
than or equal to one (1) minute in any fifteen (15) minute period during normal operation.
• The most recent O&M plan (submitted with the 11/13/2017 permit modification
application) requires daily visual observations. This frequency was added to the
construction permit condition to conduct Method 22 readings and included in the
operating permit under a separate condition specifically addressing control
devices. To monitor compliance with the Colorado Regulation No. 1 Section
II.A.5 opacity standard for the ECD and Section II.A.1 and 4 opacity standards
for the RTO, an additional requirement to conduct Method 9 observations in the
event visual emissions are detected via Method 22 readings was included in the
operating permit.
Condition 40: Point 137 — The operator shall sample the inlet gas to the plant on an
annual basis to determine the concentration of hydrogen sulfide (H2S) in the gas stream.
The sample results shall be monitored to demonstrate that this amine unit qualifies for
the exemption from the Standards of Performance for Onshore Natural Gas Processing:
SO2 Emissions (§60.640(b)).
• The NSPS LLL requirement is as follows: "To certify that a facility is exempt from
the control requirements of these standards, each owner or operator of a facility
123/0049 Page 39 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
with a design capacity less than 2 LT/D of H2S in the acid gas (expressed as
sulfur) shall keep, for the life of the facility, an analysis demonstrating that the
facility's design capacity is less than 2 LT/D of H2S expressed as sulfur." This
requirement refers to one analysis that identifies the sulfur content to which the
facility is designed. Such an analysis would have been completed prior to
construction of the facility and, pursuant to the rule, this one analysis shall serve
as sufficient evidence of facility design for the lifetime of that facility. Therefore,
the above construction permit requirement was not included in the operating
permit.
Condition 41: Point 137 — The owner or operator shall complete an extended sour gas
analysis prior to the inlet of the amine unit on an annual basis.
Condition 42: All previous versions of this permit are cancelled upon issuance of this
permit.
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 43: Revised APEN submittal requirements and deadlines
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 44: This source is subject to the provisions of Regulation No. 3, Part C,
Operating Permits. The provisions of this construction permit must be incorporated into
the Operating Permit. The application for the modification to the Operating Permit is due
within one year of the issuance of this permit.
• With the issuance of this operating permit on XX/XX/XXXX, this construction
permit is considered to be absorbed by the operating permit, thus fulfilling this
requirement. Therefore, this condition was not included in the operating permit.
Condition 45: Non -attainment New Source Review requirements shall apply to this
source at any such time that this source becomes major solely by virtue of a relaxation
in any permit condition. 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. The source shall not exceed the
NSR threshold until a NSR permit is granted.
• This requirement is evaluated on a case -by -case basis that is dependent on
specific parameters of undefined future modifications. This requirement will be
evaluated at that time and, as such, this condition was not included in the
operating permit.
Condition 46: MACT Subpart HH - National Emission Standards for Hazardous Air
Pollutants From Oil and Natural Gas Production Facilities major stationary source
requirements shall apply to this stationary source at any such time that this stationary
source becomes major solely by virtue of a relaxation in any permit limitation and shall
be subject to all appropriate applicable requirements of Subpart HH.
123/0049 Page 40 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• The PSD/NANSR relaxation requirements do not apply to federal NESHAPs. As
such, this condition was not included in the operating permit.
Conditions 47 thru 53: These requirements are included in the Section IV General
Conditions of the operating permit and/or the Colorado Revised Statutes. As such,
separate conditions for these requirements were not created for the operating permit.
Colorado Construction Permit 12WE1193- 1,478 RICE C-192, AIRS ID 140
This section addresses the conditions established in Colorado Construction Permit
12WE1193, Issuance 1. This permit was issued on 6/12/2012. The requirements from
this construction permit have been incorporated into the operating permit as follows:
Conditions 1 thru 5: These conditions set forth the final approval requirements for a
newly issued construction permit. Final approval to operate was authorized by the
Division 5/20/2013 in accordance with these conditions. As such, these conditions were
not included in the operating permit.
Condition 6: Emissions of air pollutants shall not exceed the following limitations: 14.3
tons/year NOx, 10.0 tons/year VOC, 28.6 tons/year CO, 8.0 tons/year facility -wide
individual HAP, 20.0 tons/year facility -wide total HAP
• Since the issuance of this construction permit, modifications to the Roggen
Natural Gas Processing Plant have taken place that have increased facility -wide
HAP emissions above 20 tons/year. As such, the facility -wide HAP emission
limitation was updated to allow 22.9 tons/year total HAP. Compliance
determination for the facility -wide HAP limitations was included in a separate
condition in the operating permit (see Section VI of this document).
Condition 7: This engine shall be equipped with a non -selective catalytic reduction
(NSCR) system and air -fuel ratio control. The NSCR shall reduce uncontrolled
emissions of NOx, CO and VOC from the unit to the emission levels listed in this section,
above. Operating parameters of the control equipment are identified in the operation
and maintenance plan.
• The terms of the O&M plan were included in the operating permit. The
requirements to install NSCR and an AFR are required under Colorado
Regulation No. 7 Section XVI.B.1. Therefore, this condition was not included as
a separate requirement in the operating permit.
Condition 8: This source shall be limited to the following maximum processing rates as
listed: 105.7 MMSCF/yr fuel
Condition 9: The permit number and AIRS ID number shall be marked on the subject
equipment for ease of identification. (State -Only Enforceable).
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 10: Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process modification, or
123/0049 Page 41 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
adjustment of control equipment visible emissions shall not exceed 30% opacity for
more than six minutes in any sixty consecutive minutes.
Condition 11: This source is subject to the odor requirements of Regulation No. 2.
(State -Only Enforceable)
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 12: This equipment is subject to the control requirements for stationary and
portable engines in the 8 -hour ozone control area under Regulation No. 7, Section
XVI.B.1. For rich burn reciprocating internal combustion engines, a non -selective
catalyst reduction system and an air fuel controller shall be required.
Condition 13: This equipment is subject to the control requirements for natural gas -fired
reciprocating internal combustion engines under Regulation No. 7, Section XVII.E.3.a
(State -Only Enforceable).
• The applicable requirements of Section XVII.E.3.a have been included in the
operating permit.
Condition 14: Replacements of this equipment may be subject to the control
requirements for natural gas -fired reciprocating internal combustion engines under
Regulation No. 7, Section XVII.E (State -Only Enforceable).
• The Alternative Operating Scenario (ver. 10/12/2012 w/ updated citations)
provisions of the operating permit effectively absorb this condition. Therefore,
this requirement was not included in the operating permit as a separate condition.
Condition 15: Upon startup of this point, the applicant shall follow the 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.
• The terms of the O&M plan were incorporated into the operating permit.
Therefore, this specific condition was not included.
Condition 16: A source initial compliance test shall be conducted on emissions point
140 to measure the emission rate(s) for the pollutants listed in order to demonstrate
compliance with the emissions limits contained in this permit: Oxides of Nitrogen,
Carbon Monoxide, Volatile Organic Compounds, Formaldehyde
• Self -certification for this unit was received on 3/20/2013, meeting the
requirements of this condition. As such, this condition was omitted from the
operating permit.
Condition 17: This engine is subject to the periodic testing requirements as specified in
the operating and maintenance (O&M) plan as approved by the Division. Revisions to
your O&M plan are subject to Division approval. Replacements of this unit completed
123/0049 Page 42 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
as Alternative Operating Scenarios may be subject to additional testing requirements
as specified in Attachment A.
• The terms of the O&M plan were incorporated into the operating permit.
Therefore, this specific condition was not included.
• The most recent Alternative Operating Scenario requirements (ver. 10/12/2012
w/ updated citations) were included in the operating permit.
Condition 18: Revised AP'EN submittal requirements and deadlines
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 19: This source is subject to the provisions of Regulation No. 3, Part C,
Operating Permits. The provisions of this construction permit must be incorporated into
the Operating Permit. The application for the modification to the Operating Permit is due
within one year of the issuance of this permit.
• With the issuance of this operating permit on XX/XX/XXXX, this construction
permit is considered to be absorbed by the operating permit, thus fulfilling this
requirement. Therefore, this condition was not included in the operating permit.
Condition 20: Prevention of Significant Deterioration (PSD) requirements shall apply to
this source at any such time that this source becomes major solely by virtue of a
relaxation in any permit condition. Any relaxation that increases the potential to emit
above the applicable PSD threshold will require a full PSD review of the source as
though construction had not yet commenced on the source. The source shall not exceed
the PSD threshold until a PSD permit is granted.
• This requirement is evaluated on a case -by -case basis that is dependent on
specific parameters of undefined future modifications. This requirement will be
evaluated at that time and, as such, this condition was not included in the
operating permit.
Condition 21: National Emission Standards for Hazardous Air Pollutants for Stationary
Reciprocating Internal Combustion Engines requirements shall apply to this source at
any such time that this source becomes major solely by virtue of a relaxation in any
permit limitation and shall be subject to all appropriate applicable requirements of that
Subpart on the date as stated in the rule as published in the Federal Register.
• The PSD/NANSR relaxation requirements do not apply to federal NESHAPs. As
such, this condition was not included in the operating permit.
Conditions 22 thru 28: These requirements are included in the Section IV General
Conditions of the operating permit and/or the Colorado Revised Statutes. As such,
separate conditions for these requirements were not created for the operating permit.
123/0049 Page 43 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Colorado Construction Permit 12WE1242 Eight (8) 300 bbl Stabilized Condensate
Storage Tanks P039, AIRS ID 125
This section addresses the conditions established in Colorado Construction Permit
12WE1242, Issuance 1. This permit was issued on 10/26/2012. The requirements from
this construction permit have been incorporated into the operating permit as follows:
Conditions 1 thru 4: These conditions set forth the final approval requirements for a
newly issued construction permit. Final approval to operate was authorized by the
Division 7/22/2013 in accordance with these conditions. As such, these conditions were
not included in the operating permit.
Condition 5: Emissions of air pollutants shall not exceed the following limitations: 1.5
tons/year VOC, 8 tons/year facility -wide individual HAP, 20 tons/year facility -wide total
HAP
• Since the issuance of this construction permit, modifications to the Roggen
Natural Gas Processing Plant have taken place that have increased facility -wide
HAP emissions above 20 tons/year. As such, the facility -wide HAP emission
limitation was updated to allow 22.9 tons/year total HAP. Compliance
determination for the facility -wide HAP limitations was included in a separate
condition in the operating permit (see Section VI of this document).
Condition 6: Emissions from this point shall be routed to an enclosed flare. The enclosed
flare shall reduce uncontrolled emissions of VOC to the emission levels listed in this
section, above. Operating parameters of the control equipment are identified in the
operation and maintenance plan.
• The routing of the emissions from the tanks to an enclosed combustion device
was not added as a separate condition in the operating permit because there is
no monitoring associated with it. However, a description of this emissions routing
is included in the process description of Section I in the operating permit.
• The terms of the O&M plan were incorporated into the operating permit.
Therefore, the part of this condition referencing the O&M plan parameters was
not included.
Condition 7: This source shall be limited to the following maximum processing rates as
listed: 285,714.3 bbl/year condensate
Condition 8: The permit number and AIRS ID number shall be marked on the subject
equipment for ease of identification.
• This condition is considered a construction permit only condition and was
therefore not included as a separate condition in the operating permit.
Condition 9: Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process modification, or
adjustment of control equipment visible emissions shall not exceed 30% opacity for
more than six minutes in any sixty consecutive minutes.
123/0049 Page 44 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• It should be noted that for the purposes of Colorado Regulation No. 1, an
enclosed combustion device is considered to be a smokeless flare for the
combustion of waste gases. Therefore, this enclosed combustion device is
required to adhere only to the 30% opacity limitation of Colorado Regulation No.
1, Section II.A.5 for smokeless flares. This requirement was included in the
operating permit in lieu of the 20% opacity limitation of Colorado Regulation No.
1, Section II.A.1 and the 30% allowance of Section II.A.4, which are referenced
in this construction permit condition.
• Pursuant to Colorado Regulation No. 7, Section XVII.B.2.b., all air pollution
control equipment used to comply with Section XVII is required to operate with
no visible emissions (effectively, 0% opacity) during normal operation. Because
the ECD is used to destruct emissions from the stabilized condensate storage
tanks, which are subject to the condensate storage tanks requirements of
Section XVII.C, this control device must comply with the no visible emissions
requirements. As such, compliance with the Colorado Regulation No. 1, Section
II.A.5 opacity requirements shall be presumed, provided the requirements of
Colorado Regulation No. 7 Section XVII.B.2.b. are met.
Condition 10: This source is subject to the odor requirements of Regulation No. 2.
(State -Only Enforceable)
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 11: The flare covered by this permit is subject to Regulation No. 7, Section
XVII.B General Provisions (State -Only Enforceable).
• The applicable requirements of Section XVII.B were included in the operating
permit as separate conditions.
Condition 12: The flare covered by this permit is subject to Regulation No. 7, Section
XII.C General Provisions (State -Only Enforceable).
• The applicable requirements of the Section XII.C General Provisions were
included in the operating permit.
Condition 13: The condensate storage tanks covered by this permit are subject to
Regulation 7, Section XVII emission control requirements. These requirements include,
but are not limited to: Sections XVII.C, XVII.C.1, XVII.C.3, XVII.C.4
• The applicable requirements of Section XVII.C were included in the operating
permit. However, since the issuance of this permit, Section XVII.C has been
updated to include Approved Instrument Monitoring Methods (AIMM). The
monitoring and recordkeeping requirements set forth in this construction permit
have been eclipsed by the new AIMM requirements. These new applicable
requirements have been included in the operating permit.
123/0049 Page 45 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Condition 14: This source is subject to the recordkeeping, monitoring, reporting and
emission control requirements of Regulation 7, Section XII. The operator shall comply
with all applicable requirements of Section XII.
• The applicable requirements of Section XII have been incorporated into the
operating permit.
Condition 15: Upon startup of these points, the applicant shall follow the 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.
• The terms of the O&M plan were incorporated into the operating permit.
Therefore, this condition referencing the O&M plan parameters was not included.
Condition 16: The owner or operator shall demonstrate compliance with Condition 11
and 12, using EPA Method 22 to measure opacity from the flare.
Condition 17: This permit replaces the following permits and/or points, which are
canceled upon issuance of this permit: Permit 97WE0340 Point 039.
• The stabilized condensate storage tank Point 039 was included in the 5/1/2001
revision of the operating permit. This construction permit effectively replaces the
conditions for these tanks in the operating permit. This condition was not included
in the operating permit.
Condition 18: Revised APEN submittal requirements and deadlines
• This condition is included in the General Conditions of Section IV in the operating
permit, and was not included as a separate condition for this AIRS point in
Section II of the operating permit.
Condition 19: This source is subject to the provisions of Regulation No. 3, Part C,
Operating Permits. The provisions of this construction permit must be incorporated into
the Operating Permit. The application for the modification to the Operating Permit is due
within one year of the issuance of this permit.
• With the issuance of this operating permit on XX/XX/XXX)(, this construction
permit is considered to be absorbed by the operating permit, thus fulfilling this
requirement. Therefore, this condition was not included in the operating permit.
Condition 20: Prevention of Significant Deterioration (PSD) requirements shall apply to
this source at any such time that this source becomes major solely by virtue of a
relaxation in any permit condition. Any relaxation that increases the potential to emit
above the applicable PSD threshold will require a full PSD review of the source as
though construction had not yet commenced on the source. The source shall not exceed
the PSD threshold until a PSD permit is granted.
• This requirement is evaluated on a case -by -case basis that is dependent on
specific parameters of undefined future modifications. This requirement will be
123/0049 Page 46 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
evaluated at that time and, as such, this condition was not included in the
operating permit.
Condition 21: MACT Subpart HH - National Emission Standards for Hazardous Air
Pollutants From Oil and Natural Gas Production Facilities major stationary source
requirements shall apply to this stationary source at any such time that this stationary
source becomes major solely by virtue of a relaxation in any permit limitation and shall
be subject to all appropriate applicable requirements of Subpart HH.
• The PSD/NANSR relaxation requirements do not apply to federal NESHAPs. As
such, this condition was not included in the operating permit.
Conditions 22-28: These requirements are included in the Section IV General
Conditions of the operating permit and/or the Colorado Revised Statutes. As such,
separate conditions for these requirements were not created for the operating permit.
V. EMISSION SOURCES
A. C-154 — Waukesha 1,100 HP Natural Gas Fired RICE, AIRS ID: 101
C-159 — Waukesha 1,350 HP Natural Gas Fired RICE, AIRS ID: 103
C-155/157/160 — Waukesha 806 HP Natural Gas Fired RICE, AIRS ID:
102/107/113
C-161 — Waukesha 1,350 HP Natural Gas Fired RICE, AIRS ID: 108
C-158 — Waukesha 916 HP Natural Gas Fired RICE, AIRS ID: 110
C-156 — Waukesha 806 HP Natural Gas Fired RICE, AIRS ID: 114
C-223 - Cooper Superior 720 HP Natural Gas Fired RICE, AIRS ID: 115
C-225 - Cooper Superior 800 HP Natural Gas Fired RICE, AIRS ID: 117
C-227 - Cooper Superior 720 HP Natural Gas Fired RICE, AIRS ID: 119
C-192 — Waukesha 1,478 HP Natural Gas Fired RICE, AIRS ID: 140
1. Applicable Requirements
This operating permit condition encompasses all eleven (11) operating engines included
in the 5/1/2001 issuance of the operating permit, as well as C-192, which was permitted
under Colorado Construction Permit 12WE1193 (see Construction Permit section
above). All applicable conditions of 12WE1193 for C-192 were found to either overlap
with those conditions governing the 11 engines permitted under the 5/1/2001 issuance
of the operating permit, or were determined to be new applicable requirements not yet
established at the time of the previous operating permit issuance. Because the
applicable requirements for both C-192 and the older engines are identical in nature,
123/0049 Page 47 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
they were permitted under the same condition in Section II of the operating permit. All
applicable conditions from 12WE1193 identified under the Construction Permit section
of this document are also considered to be applicable to the other eleven (11) engines.
Emission limitations and factors for NOx, CO and VOC were updated based on.
emissions requested in the permit modification received 7/10/2017 for engines C-154,
C-159, C-161, C-156, C-225 and C-227. Additionally, various Alternative Operating
Scenarios (AOS) have been executed since the operating permit issuance on 5/1/2001.
As such, engine serial numbers were updated to reflect the most recent information
available on the APENs.
Calculation methods for monthly emissions of NOx, CO and VOC were included in the
operating permit. Because fuel gas is measured by a single meter located on the fuel
gas header, a calculation was included to detail the partitioning of fuel gas among its
users based on the input heat requirement of each unit and hours of operation.
Other Applicable Requirements
This section addresses applicable requirements to C-192 that were not explicitly defined
in Colorado Construction Permit 12WE1193, but were included in the operating permit.
It should be noted that these conditions apply to the older engines permitted under this
Section II condition as well, unless otherwise noted.
• Additional Monitoring
o The heat content of the natural gas used to fuel each engine shall be
verified semi-annually using the appropriate ASTM methods. The heating
value reported shall be the higher heating value (HHV) of the fuel gas.
This heating value is used to partition the fuel gas among users based on
the total facility fuel gas flowrate obtained from a meter.
o Hours of operation shall be monitored and recorded monthly. The hours
of operation are used to determine the monthly fuel gas consumption for
this engine.
o Records verifying the use of only natural gas as fuel shall be maintained
to demonstrate compliance with the opacity limitations.
o Portable monitoring
• Emission measurements of nitrogen oxides (NOx) and carbon
monoxide (CO) shall be conducted quarterly using a portable flue
gas analyzer
• Pursuant to the O&M plan, the oxygen concentration in the engine
exhaust gas shall be measured and recorded for each engine
during each portable monitoring event
o Catalyst Monitoring
123/0049 Page 48 of 132
DCP Operating Company, LP Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
■ The pressure drop across the catalyst shall be monitored and
recorded monthly, not to exceed 2 inH2O from the baseline
pressure drop, as required by the O&M plan
• The catalyst inlet temperature shall be monitored and recorded
daily and kept between 750°F and 1250°F, as required by the O&M
plan
o As required by the O&M plan, the millivolt reading for the Air -Fuel Ratio
Controller (AFR) O2 sensor for each engine will be monitored and
recorded weekly to assess the air to fuel ratio controller operating
condition
• State Requirements
o Colorado Regulation No. 7 Section XVI
The engines at the Roggen Natural Gas Processing Plant operate in a
non -attainment area and are therefore subject to the following applicable
requirements of Colorado Regulation No. 7 Section XVI:
■ Section XVI.B — Each engine shall install NSCR and AFR. These
devices shall be appropriately sized for the engine and shall be
operated and maintained according to manufacturer specifications.
• Section XVI.D — This section establishes the requirements for
emission limitations, compliance demonstrations, combustion
process adjustments, reporting and recordkeeping applying to
stationary combustion equipment located at major sources of NOx.
In Section XVI.D.2., exemptions from the requirements of Section
XVI.D.4. (emission limitations), Section XVI.D.5. (compliance
demonstration), certain parts of Section XVI.D.7. (recordkeeping)
and Section XVI.D.8. (reporting) are listed. It should be noted that
all engines at the Roggen Natural Gas Processing Plant qualify for
the Section XVI.D.2.e. exemption, as each engine is greater than
500 hp and therefore subject to the emission control requirements
of Colorado Regulation No. 7, Section XVI.B. As such, these
engines are not required to comply with the aforementioned
sections. However, it should be noted that the Section XVI.D.2.
exemptions do not preclude the source from complying with the
combustion process adjustments of Section XVI.D.6. Affected
operations, pursuant to Section XVI.D.6.a., include stationary
internal combustion engines with greater than five tons/year of
actual uncontrolled NOx emissions. The requirements set forth in
this section include periodic maintenance, inspections and
recordkeeping. The Combustion Process Adjustment requirements
were promulgated 10/16/2018, and were not in existence at the
time of construction permit 12WE1193 issuance, nor at the time of
the 5/1/2001 issuance of the operating permit. Because each
engine is an internal combustion engine with actual uncontrolled
123/0049 Page 49 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document- Renewal Operating Permit
NOx emissions exceeding the five (5) tons/ year threshold, these
requirements have been added to the operating permit.
■ Additional recordkeeping — Two additional recordkeeping
requirements were included in the operating permit to fill monitoring
gaps left by Colorado Regulation No. 7, Section XVI, as provided
for under Colorado Regulation No. 3, Part C, Section V.C.5.b.
These additional requirements were clearly denoted in the
operating permit with italicized text and are summarized as follows:
o The owner/operator shall maintain records of the
combustion process adjustments performed, pursuant to
Colorado Regulation No. 7, Section XVI.D.7.f. As written,
Section XVI.D.2. precludes the source from complying with
the combustion process adjustment recordkeeping, despite
being required to perform combustion process adjustments.
Because these adjustments are required, proper
documentation must be maintained to demonstrate
compliance with these requirements, pursuant to Colorado
Regulation No. 3, Part C, Section V.C.5.b. Therefore, an
explicit requirement to keep records in accordance with
Colorado Regulation No. 7, Section XVI.D.7.f. was included
in the operating permit.
o The owner/operator shall maintain records of any alternative
combustion process adjustments performed under Colorado
Regulation No. 7, Section XVI.D.6.c. As written, Section XVI
does not include recordkeeping requirements sufficient to
demonstrate that a proper alternative combustion process
adjustment was performed. Because alternative combustion
process adjustments are allowed pursuant to Section
XVI.D.6.c., proper documentation is required to
demonstrate compliance with the alternative combustion
process adjustment provisions, pursuant to Colorado
Regulation No. 3, Part C, Section V.C.5.b. Therefore, an
explicit requirement to keep records of any alternative
combustion process adjustments performed, the
procedures used and what NSPS or MACT (if any) applied,
was included in the operating permit. It should be noted that
these requirements exactly mirror Colorado Regulation No.
7, Section XVI.D.7.f.(i)(C), and these requirements were
present in the 11/17/2016 promulgation of Colorado
Regulation No. 7 Section XVI.
Colorado Regulation No. 7 Section XVII
The engines at the Roggen Natural Gas Processing Plant are subject to
the following applicable requirements of Colorado Regulation No. 7
Section XVII:
123/0049 Page 50 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Section XVII.E.2 (State -Only Enforceable) - This section sets
forth requirements for new (or relocated) engines used in oil and
gas operations in the state of Colorado. New engines are defined
as those having been constructed or relocated to Colorado after
the date specified in the table below, and are subject to the listed
set of emission standards.
Maximum
Engine Hp
Construction or
Relocation Date
Emission Standard
in g/hp-hr
NOx
CO
VOC
≥ 500 HP
On or after July 1, 2007
2.0
4.0
1.0
On or after July 1, 2010
1.0
2.0
0.7
• Section XVII.E.3 — This section sets forth requirements for existing
engines used in oil and gas operations in the state of Colorado.
Existing engines are defined as those that have been constructed
or modified prior to 2/1/2009. Existing engines under this section
are required to install AFR controllers and an NSCR system.
The following table summarizes the requirements of Section XVII.E.2
and 3 as they apply to each engine:
AIRS
ID
Facility
Identifier
Date of
Commenced
Construction
Date of
Relocation to CO
CO Reg. No. 7
Section XVII.E.2
Requirement
CO Reg. No. 7
Section XVII.E.3
Requirement
101
C-154
Unknown
6/10/2010
July 1, 2007 Std.
--
102
C-155
Before 1984
Before 1984
--
NSCR and AFR
103
C-159
1974
11/28/2007
July 1, 2007 Std.
NSCR and AFR
107
C-157
Before 2002
5/1/2001
--
NSCR and AFR
108
C-161
Before 2006
Before 2006
--
NSCR and AFR
110
C-158
Before 5/2001
Before 5/2001
--
NSCR and AFR
113
C-160
12/11/1979
Before 2/2002
--
NSCR and AFR
114
C-156
1973
Before 5/2006
--
NSCR and AFR
115
C-223
1/1973
1996
--
NSCR and AFR
117
C-225
Before 2002
2013
July 1, 2010 Std.
--
119
C-227
1974
2/17/2010
July 1, 2007 Std.
--
140
C-192
1984
Before 1995
--
NSCR and AFR
• Federal Requirements
o Compliance Assurance Monitoring (CAM)
Compliance Assurance Monitoring (CAM) requirements are set forth in 40
CFR 64. Each engine is subject to emission limitations and uses a control
device to achieve compliance with those limitations. However, only C-154,
123/0049 Page 51 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
159, 161, 223, 225, 227 and 192 have potential pre-controlemissions that
exceed major source thresholds for NOx, CO or both pollutants. These
engines are therefore subject to CAM.
40 CFR 64 requires that the monitoring required by the CAM plan be
"presumptively acceptable". A presumptively acceptable monitoring
approach, in reference to §64.4(b)(4), includes those which are "included
for standards exempt from this part pursuant to §64.2(b)(1)(i) or (vi) to the
extent such monitoring is applicable to the performance of the control
device (and associated capture system) for the pollutant -specific
emissions unit". Section 64.2(b)(1)(i) identifies an exemption for rules
proposed under Section 111 (NSPS) or 112 (NESHAP). By extension,
monitoring required in a NESHAP or NSPS rule qualifies as a
presumptively acceptable monitoring approach. 40 CFR 63 Subpart ZZZZ
for Stationary RICE requires that the catalyst inlet temperature be
monitored to ensure it does not deviate from the range of 750°F and
1250°F for 4 -stroke rich burn (4SRB) engines. Because this requirement
is found in a federally -enforceable NESHAP rule, this catalyst inlet
temperature parameter was selected to fulfill the presumptively
acceptable monitoring approach required by CAM.
Pursuant to 64.3(b)(4), monitoring frequency is dependent upon the post -
control quantity of emissions. For pollutant -specific emission units with
post -control emissions of less than major source thresholds (i.e., small
PSEU), the monitoring frequency must be at least once every 24 hours.
Daily monitoring of the catalyst inlet temperature was included in the CAM
plan for this unit.
o 40 CFR 60 Subpart OOOO — Compressor associated with engine C-192
only
It should be noted that this subpart was not addressed in Colorado
Construction Permit 12WE1193, but was included in the operating permit
pursuant to the initial notification for NSPS OOOO applicability received
on 10/18/2012. This subpart requires periodic replacement of
reciprocating compressor rod packing or, alternatively, the routing of the
rod packing emissions to a closed vent system.
o 40 CFR 63 Subpart ZZZZ
Area source requirements were added to subpart ZZZZ 1/30/2013, and,
as such, were not yet established at the time of issuance of construction
permit 12WE1193 or for the previous revision of the operating permit.
Therefore, the applicable area source requirements for stationary RICE
engines were included in this operating permit. These requirements
include work practices, maintenance requirements and recordkeeping
only.
2. Emission Factors
123/0049 Page 52 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
The emission factors for this engine were derived from an emission factor and/or
control efficiency from the engine manufacturer, the engine -rated horsepower,.
hours of operation, fuel gas consumption and fuel gas heat content. The permitted
emission factors for each engine, as well as the heat content used to determine
these factors, are as follows:
Source
Heat Content
(Btu/SCF)
NOx
(lb/MMBtu)
CO
(lb/MMBtu)
VOC
(lb/MMBtu)
C-154
958
0.57 ,
0.57
0.29
C-155,
157 & 160
958
0.52
0.52
0.25
C-159
958
0.54
0.56
0.27
C-161
958
0.27
0.54
0.19
C-158
958
0.54
0.54
0.26
C-156
958
0.25
0.49
0.17
C-223
958
0.54
0.54
0.26
C-225
958
0.28
0.55
0.19
C-227
958
0.51
0.54
0.26
C-192
958
0.28
0.56
0.20
Uncontrolled emissions of HAP were estimated based on the emission factors in
AP -42 Chapter 3, Section 3.2, Table 3.2-3 "Uncontrolled Emission Factors for 4 -
Stroke Rich Burn Engine". A control efficiency of 76% was applied to
formaldehyde, which is congruous with the required efficiency for engines subject
to major source requirements in MACT ZZZZ. All other HAP were assumed to have
a 50% emission reduction.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Catalyst Pressure Drop — Monitored and recorded monthly, not to exceed 2
inH2O from the baseline pressure drop
• Catalyst Inlet Temperature — Monitored and recorded daily, to be maintained
between 750°F and 1250°F
• AFR O2 Sensor — Monitored and recorded weekly to verify proper operation
• Portable Monitoring — Required quarterly to ensure compliance with the NOx and
CO annual limitations
• Fuel Gas Consumption — Monthly monitoring required using the existing fuel gas
header meter and partition calculation to determine compliance with the rolling
twelve month emissions for NOx, CO, VOC and consumption
• Fuel Gas Analysis — Required semi-annually to verify the heat content used in
emission factor development and the allocation of fuel gas to each user
• Hours of Operation — Monitored and recorded monthly, used in rolling twelve
month emissions calculations for NOx, CO, VOC and consumption
123/0049 Page 53 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
4. Compliance Status
According to the 6/2/2016 inspection, C-192 is in compliance with all requirements
of Colorado Construction Permit 12WE1193. All other engines are in compliance
with the applicable conditions of the previous revision of the operating permit,
EXCEPT as follows:
• Failure to record catalyst pressure drop monthly: C-154, C-155, C-157, C-
158, C-160, C-156, C-223, C-225 and C-227
• Catalyst Inlet Temperature Excursion: C-159 and C-157
These violations have been addressed within the Division's enforcement group
and no separate compliance schedule/plan is required for the purposes of the Title
V Operating Permit.
B. C-181 —Waukesha 1,478 HP Natural Gas Fired Internal Combustion Engine,
AIRS ID: 134
1. Applicable Requirements
This operating permit condition addresses C-181, permitted under Colorado
Construction Permit 07WE0988. The applicable conditions from 07WE0988 have been
incorporated in the operating permit as described above in the Construction Permit
section of this document.
Emission limitations and factors for NOx and VOC were updated based on emissions
requested in the permit modification received 7/10/2017 for C-181. Additionally, the
most recent Alternative Operating Scenarios (AOS) for this engine was executed on
8/18/2015. As such, engine serial number was updated to reflect the most recent
information available on the AOS APEN.
Calculation methods for monthly emissions of NOx, CO and VOC were included in the
operating permit. Because fuel gas is measured by a single meter located on the fuel
gas header, a calculation was included to detail the partitioning of fuel gas among its
users based on the input heat requirement of each unit and hours of operation.
Other Applicable Requirements
This section addresses applicable requirements to C-181 that were not explicitly defined
in Colorado Construction Permit 07WE0988, but were included in the operating permit.
• Additional Monitoring
o The heat content of the natural gas used to fuel this engine shall be
verified semi-annually using the appropriate ASTM methods. The heating
value reported shall be the higher heating value (HHV) of the fuel gas.
This heating value is used to partition the fuel gas among users based on
the total facility fuel gas flowrate obtained from a meter.
123/0049 Page 54 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No.95OPWE055
Technical Review Document - Renewal Operating Permit
o Hours of operation shall be monitored and recorded monthly. The hours
of operation are used to determine the monthly fuel gas consumption for
this engine.
o Records verifying the use of only natural gas as fuel shall be maintained
to demonstrate compliance with the opacity limitations.
o Portable monitoring
■ Emission measurements of nitrogen oxides (NOx) and carbon
monoxide (CO) shall be conducted quarterly using a portable flue
gas analyzer
o Pursuant to the O&M plan, the oxygen concentration in the engine
exhaust gas shall be measured and recorded for each engine during each
portable monitoring event
o Catalyst Monitoring
• The pressure drop across the catalyst shall be monitored and
recorded monthly, not to exceed 2 inH20 from the baseline
pressure drop, as required by the O&M plan
• The catalyst inlet temperature shall be monitored and recorded
daily and kept between 750°F and 1250°F, as required by the O&M
plan
o As required by the O&M plan, the millivolt reading for the Air -Fuel Ratio
Controller (AFR) O2 sensor for each engine will be monitored and
recorded weekly to assess the air to fuel ratio controller operating
condition
• State Requirements
o Colorado Regulation No. 7 Section XVI
The engines at the Roggen Natural Gas Processing Plant operate in a
non -attainment area and are therefore subject to the following applicable
requirements of Colorado Regulation No. 7 Section XVI:
■ Section XVI.B — This engine shall install NSCR and AFR. These
devices shall be appropriately sized for the engine and shall be
operated and maintained according to manufacturer specifications.
■ Section XVI.D — This section establishes the requirements for
emission limitations, compliance demonstrations, combustion
process adjustments, reporting and recordkeeping applying to
stationary combustion equipment located at major sources of NOx.
In Section XVI.D.2., exemptions from the requirements of Section
XVI.D.4. (emission limitations), Section XVI.D.5. (compliance
demonstration), certain parts of Section XVI.D.7. (recordkeeping)
and Section XVI.D.8. (reporting) are listed. It should be noted that
123/0049 Page 55 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
all engines at the Roggen Natural Gas Processing Plant qualify for
the Section XVI.D.2.e. exemption, as each engine is greater than
500 hp and therefore subject to the emission control requirements
of Colorado Regulation No. 7, Section XVI.B. As such, these
engines are not required to comply with the aforementioned
sections. However, it should be noted that the Section XVI.D.2.
exemptions do not preclude the source from complying with the
combustion process adjustments of Section XVI.D.6. Affected,'
operations, pursuant to Section XVI.D.6.a., -include stationary
internal combustion engines with greater than or equal to five (5)
tons/year of actual uncontrolled NOx emissions. The requirements
set forth in this section include periodic maintenance, inspections
and recordkeeping. The Combustion Process Adjustment
requirements were promulgated 10/16/2018, and were not in
existence at the time of construction permit 07WE0988 issuance.
Because C-181 is an internal combustion engine with actual
uncontrolled NOx emissions exceeding the five (5) tons/ year
threshold, these requirements have been added to the operating
permit.
Additional recordkeeping — Two additional recordkeeping
requirements were included in the operating permit to fill monitoring
gaps left by Colorado Regulation No. 7, Section XVI, as provided
for under Colorado Regulation No. 3, Part C, Section V.C.5.b.
These additional requirements were clearly denoted in the
operating permit with italicized text and are summarized as follows:
o The owner/operator shall maintain records of the
combustion process adjustments performed, pursuant to
Colorado Regulation No. 7, Section XVI.D.7.f. As written,
Section XVI.D.2. precludes the source from complying with
the combustion process adjustment recordkeeping, despite
being required to perform combustion process adjustments.
Because these adjustments are required, proper
documentation must be maintained to demonstrate
compliance with these requirements, pursuant to Colorado
Regulation No. 3, Part C, Section V.C.5.b. Therefore, an
explicit requirement to keep records in accordance with
Colorado Regulation No. 7, Section XVI.D.7.f. was included
in the operating permit.
o The owner/operator shall maintain records of any alternative
combustion process adjustments performed under Colorado
Regulation No. 7, Section XVI.D.6.c. As written, Section XVI
does not include recordkeeping requirements sufficient to
demonstrate that a proper alternative combustion process
adjustment was performed. Because alternative combustion
process adjustments are allowed pursuant to Section
123/0049 Page 56 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
XVI.D.6.c., proper documentation is required to
demonstrate compliance with the alternative combustion
process adjustment provisions, pursuant to Colorado
Regulation No. 3, Part C, Section V.C.5.b. Therefore, an
explicit requirement to keep records of any alternative
combustion process adjustments performed, the
procedures used and what NSPS or MACT (if any) applied,
was included in the operating permit. It should be noted that
these requirements exactly mirror Colorado Regulation No.
7, Section XVI.D.7.f.(i)(C), and these requirements were
present in the 11/17/2016 promulgation of Colorado
Regulation No. 7 Section XVI.
• Federal Requirements
o Compliance Assurance Monitoring (CAM)
Compliance Assurance Monitoring (CAM) requirements are set forth in 40
CFR 64. C-181 is subject to emission limitations, uses a control device to
achieve compliance with those limitations and has potential pre -control
emissions that exceed major source thresholds for both NOx and CO. This
engine is therefore subject to CAM.
40 CFR 64 requires that the monitoring required by the CAM plan be
"presumptively acceptable". A presumptively acceptable monitoring
approach, in reference to §64.4(b)(4), includes those which are "included
for standards exempt from this part pursuant to §64.2(b)(1)(i) or (vi) to the
extent such monitoring is applicable to the performance of the control
device (and associated capture system) for the pollutant -specific
emissions unit". Section 64.2(b)(1)(i) identifies an exemption for rules
proposed under Section 111 (NSPS) or 112 (NESHAP). By extension,
monitoring required in a NESHAP or NSPS rule qualifies as a
presumptively acceptable monitoring approach. 40 CFR 63 Subpart ZZZZ
for Stationary RICE requires that the catalyst inlet temperature be
monitored to ensure it does not deviate from the range of 750°F and
1250°F for 4 -stroke rich burn (4SRB) engines. Because this requirement
is found in a federally -enforceable NESHAP rule, this catalyst inlet
temperature parameter was selected to fulfill the presumptively
acceptable monitoring approach required by CAM.
Pursuant to 64.3(b)(4), monitoring frequency is dependent upon the post -
control quantity of emissions. For pollutant -specific emission units with
post -control emissions of less than major source thresholds (i.e., small
PSEU), the monitoring frequency must be at least once every 24 hours.
Daily monitoring of the catalyst inlet temperature was included in the CAM
plan for this unit.
o 40 CFR 63 Subpart 777Z
123/0049 Page 57 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Area source requirements were added to Subpart ZZZZ 1/30/2013, and,
as such, were not yet established at the time of issuance of construction
permit 07WE0988. Although area source requirements are now included
in Subpart ZZZZ, there is also a requirement for new engines at area
sources to comply with NSPS JJJJ in lieu of MACT ZZZZ. Under MACT
ZZZZ, C-181 is classified as a new engine. The Subpart 777Z conditions
requiring compliance with NSPS JJJJ were included in the operating
permit.
o 40 CFR 60 Subpart JJJJ
The area source requirements of NESHAP ZZZZ that require compliance
with Subpart JJJJ were not yet established at the time of issuanc'b of
construction permit 07WE0988. The applicable conditions of Subpart JJJJ
have been added to the operating permit. These requirements include
compliance with NOx, CO and VOC emission limitations based on
manufacture date and engine power, compliance demonstration
requirements, testing requirements and reporting requirements.
An initial notification was received 10/8/2008, in accordance with Subpart
JJJJ. Because this action was completed, initial notification requirements
from this subpart were omitted from the operating permit.
2. Emission Factors
The emission factors for this engine were derived from an emission factor and/or
control efficiency from the engine manufacturer, the engine -rated horsepower,
hours of operation, fuel gas consumption and fuel gas heat content. The permitted
emission factors for each engine, as well as the heat content used to determine
these factors, are as follows:
Source
Heat Content
(Btu/SCF)
NOx
(Ib/MMBtu)
CO
(Ib/MMBtu)
VOC
(Ib/MMBtu)
C-181
1,040
0.28
0.57
0.20
Uncontrolled emissions of HAP were estimated based on the emission factors in
AP -42 Chapter 3, Section 3.2, Table 3.2-3 "Uncontrolled Emission Factors for 4 -
Stroke Rich Burn Engines". A control efficiency of 76% was applied to
formaldehyde, which is congruous with the required efficiency for engines subject
to major source requirements in MACT ZZZZ. All other HAP were assumed to have
a 50% emission reduction.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
Catalyst Pressure Drop — Monitored and recorded monthly, not to exceed 2
inH2O from the baseline pressure drop
123/0049
Page 58 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Catalyst Inlet Temperature — Monitored and recorded daily, to be maintained
between 750°F and 1250°F
• AFR O2 Sensor — Monitored and recorded weekly to verify proper operation
• Portable Monitoring — Required quarterly to ensure compliance with the NOx and
CO annual limitations
• Fuel Gas Consumption — Monthly monitoring required using the existing fuel gas
header meter and partition calculation to determine compliance with the rolling
twelve month emissions for NOx, CO, VOC and consumption
• Fuel Gas Analysis — Required semi-annually to verify the heat content used in
emission factor development and the allocation of fuel gas to each user
• Hours of Operation — Monitored and recorded monthly, used in rolling twelve
month emissions calculations for NOx, CO, VOC consumption
4. Compliance Status
According to the 6/2/2016 inspection, C-181 is in compliance with all conditions in
Colorado Construction Permit 07WE0988.
C. H037 — Heat Recovery Corp 7.55 MMBtu/hr Natural Gas Fired Hot Oil Heater,
AIRS ID: 129
1. Applicable Requirements
This operating permit condition encompasses hot oil heater H037 which was permitted
under the 5/1/2001 issuance of the operating permit.
It should be noted that this heater is categorically exempt from construction permit
requirements, pursuant to Colorado Regulation No. 3, Part B, Section II.D.1.e, which
exempts "each individual piece of fuel burning equipment, other than smokehouse
generators, that uses gaseous fuel, and that has a design rate less than or equal to ten
million British thermal units per hou►". H037 has a design heat rating of 7.55 MMBtu/hr,
which is less than the 10 MMBtu/hr threshold, thereby qualifying for this exemption.
Because of this, the NOx, CO and fuel gas consumption limitations were removed from
the operating permit. However, this heater is not classified as an insignificant activity for
the purposes of operating permits pursuant to Colorado Regulation No. 3, Part C,
Section II.E.3.k, which states that fuel burning equipment must have a design rating of
less than or equal to 5 MMBtu/hr to qualify as an insignificant activity. Additionally, this
heater is required to obtain an APEN pursuant to Colorado Regulation No. 3, Part A,
Section II.D.1.k, which requires that APENs be submitted for any fuel burning equipment
with a design rating of greater than 5 MMBtu/hr. As such, provisions were made in the
operating permit to facilitate the calculation of emissions generated in excess of the
APEN reporting thresholds of NOx and CO for sources located in areas of ozone non -
attainment. Furthermore, this heater is considered to be "fuel burning equipment"
pursuant to the State of Colorado Common Provisions Regulation. As such, H037 is
subject to the opacity, particulate matter and general requirements of Colorado
Regulations No. 1 and 6. The calculation methodologies for APEN reporting purposes
123/0049 Page 59 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
and applicable requirements from state regulations were incorporated into the operating
permit. These requirements are summarized in this section.
Colorado Regulation No. 7, Section XVI was recently revised to include combustion
process adjustment requirements for boilers, duct burners, process heaters, turbines
and engines located in ozone non -attainment areas emitting uncontrolled actual
emissions of NOx greater than 5 tons/year. Hot oil heater H037, which is an uncontrolled
emissions point, cannot produce NOx emissions in excess of the Section XVI.D
threshold of 5 tons/year. Pursuant to Section XVI.D.2. and XVI.D.7.g, records must be
kept demonstrating that the stationary combustion equipment is exempt from Section
XVI.D. Therefore, the applicable recordkeeping requirements were included in the
operating permit.
Additionally, it should be noted that NSPS Dc is not applicable to H037. The applicability
threshold for NSPS Dc is 10 MMBtu/hr. Hot oil heater H037 is rated to 7.55 MMBtu/hr,
which is below the applicability threshold for Dc and is therefore not subject to it.
Calculation methods for monthly emissions of NOx, CO and PM were included in the
operating permit. Because fuel gas is measured by a single meter located on the fuel
gas header, a calculation was included to detail the partitioning of fuel gas among its
users based on the input heat requirement of each unit and hours of operation. It should
be noted that because this unit is a permit exempt unit, the Division requires calculation
of emissions on an annual basis for APEN reporting. However, in the source comments
received 11/2/2018, it was indicated that because of the way the fuel gas is partitioned
among users from one facility -wide meter, the source completes these calculations for
this heater (as well as all other fuel -burning equipment) on a monthly basis and
requested that monthly calculation methods be retained in the permit. This request was
incorporated into the operating permit.
Other Applicable Requirements
This section addresses applicable requirements to H037 that were not explicitly defined
in the previous issuance of the operating permit, but were included in the renewed
operating permit:
• Additional Requirements
o Colorado Regulation No. 6, Part B, Section II.C.3 (State -Only
Enforceable): No owner or operator shall discharge, or cause the
discharge, into the atmosphere of any particulate matter which is greater
than twenty percent (20%) opacity
This heater is subject to the Colorado Regulation No. 1 Section II.A.1 20%
opacity requirement and the Section II.A.4 30% opacity requirement for
certain specific operational activities. The Section II.A.1 20% opacity
requirement applies at all times, except for certain specific operating
conditions under which the Section II.A.4 30% opacity requirement
applies. The heaters are also subject to the state -only Colorado
Regulation No. 6 Part B Section II.C.3 20% opacity requirement. Colorado
Regulation No. 6 Part B Section I.A, adopts, by reference, the 40 CFR
123/0049 Page 60 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Part 60 Subpart A general provisions. 40 CFR Part 60 Subpart A §
60.11(c) specifies that the opacity requirements are not applicable during
periods of startup, shutdown and malfunction. The Colorado Regulation
No. 1 Section II.A.1 and Il.A.4 20%/30% requirements are more stringent
than the Colorado Regulation 6 Part B Section II.C.3 opacity requirements
during periods of startup, shutdown and malfunction. However, the
Colorado Regulation No. 6 Part B Section II.C.3 20% opacity requirement
is more stringent during fire building, cleaning of fire boxes, soot blowing,
process modifications and adjustment or occasional cleaning of control
equipment. Therefore, since no one opacity requirement is more stringent
than the other atall times, all three opacity requirements are included in
the operating permit.
• Additional Monitoring
o Particulate matter emissions shall not exceed the limitation set forth in
Colorado Regulation No. 1, Section III.A.1.b.
■ Colorado Regulation No. 1, Section III.A.1.b. prescribes a
particulate matter limit based on the fuel input of the heater. When
using the design fuel input for H037, a limitation of 0.296 lb/MMBtu
is obtained. It should be noted, however, that this limitation is
significantly higher than what the total PM emission factor from AP -
42 Chapter 1.4, Table 1.4-2 predicts for natural gas combustion.
Because combustion of natural gas results in significantly lower
actual emissions of total PM, the Division has determined that
compliance with this limit may be presumed at all times, provided
natural gas only is used as fuel for this heater. As such, this heater
is permitted to use natural gas only as fuel and the source shall
demonstrate compliance with this Colorado Regulation No. 1
requirement by maintaining records to verify natural gas only is
used.
o Hours of operation shall be monitored and recorded monthly. The hours
of operation are used to determine the annual fuel gas consumption for
H037.
o Records verifying the use of only natural gas as fuel shall be maintained
to demonstrate compliance with the opacity limitations.
• State Requirements
o Colorado Regulation No. 7 Section XVI.D
This section establishes the requirements for emission limitations,
compliance demonstrations, combustion process adjustments, reporting
and recordkeeping applying to stationary combustion equipment located
at major sources of NOx. Section XVI.D.2.d. provides an exemption from
these requirements for stationary combustion equipment with less than 5
tons/year uncontrolled actual NOx emissions. H037 is an uncontrolled
123/0049 Page 61 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
emissions unit with a permitted NOx limit of less than 5 tons/year. As such,
it fulfills the Section XVI.D.2.d. exemption, and is required only to keep
records demonstrating this exemption applies, pursuant to Sections
XVI.D.2. and XVI.D.7.g. These requirements were included in the
operating permit.
■ It should be noted that the Section XVI.D.2. exemptions do not
preclude the source from complying with the combustion process
adjustments. However, pursuant to Section XVI.D.6.a., combustion
process adjustments are only performed on stationary combustion
sources generating uncontrolled actual emissions of NOx in excess
of 5 tons/year. As discussed above, H037 does not generate NOx
in these quantities. As such, the combustion process adjustment
requirements do not apply to H037.
o (State -Only Enforceable) — Colorado Regulation No. 6 Part A, Subpart
A
Colorado Regulation No. 6 requires compliance with the state -adopted
subparts of the federal NSPS rules. Due to the relatively low design heat
rating for H037, this heater is subject only to the NSPS Subpart A General
Provisions (see applicability discussion for NSPS Dc in this section
above). It should be noted, however, that these requirements are State -
Only Enforceable, since, at a federal level, this heater is not subject to
Subpart A because H037 is not also subject to another NSPS subpart.
The Subpart A requirements were included in the permit because they
were adopted in Colorado Regulation No. 6 and applicable to any source
subject to Colorado Regulation No. 6. These heaters are considered "fuel -
burning equipment" pursuant to the Colorado Common Provisions
Regulation and are therefore subject to the fuel -burning requirements of
Colorado Regulation No. 6, including the particulate matter and opacity
standards, which were incorporated into the operating permit (see above).
Because H037 is subject to Colorado Regulation No. 6, the state -adopted
requirements of NSPS Subpart A are applicable to this heater and shall
be enforced at a state -only level. The requirements included are as
follows:
■ Prohibition of circumvention (40 CFR Part 60, Subpart A, §60.12,
as adopted by reference in Colorado Regulation No. 6)
• Good air pollution control practices (40 CFR Part 60, Subpart A,
§60.11(d), as adopted by reference in Colorado Regulation No. 6)
• Recordkeeping of startup, shutdown or malfunction events (40
CFR Part 60, Subpart A, §60.7(b), as adopted by reference in
Colorado Regulation No. 6)
2. Emission Factors
123/0049 Page 62 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
The emission factors used to calculate NOx and CO emissions were obtained from
AP -42 Chapter 1, Section 1.4, Table 1.4-1 Emission Factors for Nitrogen Oxides
(NOx) and Carbon Monoxide (CO) from Natural Gas Combustion:
Source
NOx
(lb/MMSCF)
CO
(lb/MMSCF)
H037
100
84
These emission factors are applicable to natural gas fired "small boilers", which
are defined to have a design rating of less than 100 MMBtu/hr.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Fuel Gas Consumption — Monthly monitoring required using the existing fuel gas
header meter and partition calculation to determine annual emissions for NOx
and CO for the purposes of APEN reporting
• Fuel Gas Analysis — Required semi-annually to verify the heat content, which is
used for the allocation of fuel gas to each user
• Hours of Operation — Monitored and recorded monthly; used in annual emissions
calculations for NOx, CO and fuel gas consumption
4. Compliance Status
According to the 6/2/2016 inspection, H037 is in compliance with all applicable
conditions in the previous revision of the operating permit. It should be noted,
however, that H037 did not operate during the 2015-2016 compliance period.
D. P-138 — OPF, Inc. 30.7 MMBtu/hr Natural Gas Fired Hot Oil Heater, AIRS ID:
138
1. Applicable Requirements
This operating permit condition encompasses hot oil heater P-138, which was permitted
under Colorado Construction Permit 10WE1659 (see Construction Permit Section
above).
It should be noted that as of the permit issuance date of XX/XX/XXX , 10WE1659 has
not yet obtained final approval to operate due to an outstanding stack test for the
regenerative thermal oxidizer, which was also permitted under 10WE1659. However,
all compliance certification documentation pertinent to P-138 was received by the
Division on 9/14/2015. There are no further final approval requirements for this heater.
Calculation methods for monthly emissions of NOx, CO and PM were included in the
operating permit. Because fuel gas is measured by a single meter located on the fuel
gas header, a calculation was included to detail the partitioning of fuel gas among its
users based on the input heat requirement of each unit and hours of operation.
123/0049 Page 63 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Other Applicable Requirements
This section addresses applicable requirements to P-138 that were not explicitly defined
in Colorado Construction Permit 10WE1659, but were included in the operating permit
• Additional Requirements
o Colorado Regulation No. 6, Part B, Section II.C.3 (State -Only
Enforceable): No owner or operator shall discharge, or cause the
discharge, into the atmosphere of any particulate matter which is greater
than twenty percent (20%) opacity
This heater is subject to the Colorado Regulation No. 1 Section II.A.1 20%
opacity requirement and the Section II.A_4 30% opacity requirement for
certain specific operational activities. The Section II.A.1 20% opacity
requirement applies at all times, except for certain specific operating
conditions under which the Section II_A.4 30% opacity requirement
applies. The heaters are also subject to the state -only Colorado
Regulation No. 6 Part B Section II.C.3 20% opacity requirement. Colorado
Regulation No. 6 Part B Section I.A, adopts, by reference, the 40 CFR
Part 60 Subpart A general provisions. 40 CFR Part 60 Subpart A §
60.11(c) specifies that the opacity requirements are not applicable during
periods of startup, shutdown and malfunction. The Colorado Regulation
No. 1 Section II.A.1 and II.A.4 20%/30% requirements are more stringent
than the Colorado Regulation 6 Part B Section II.C.3 opacity requirements
during periods of startup, shutdown and malfunction. However, the
Colorado Regulation No. 6 Part B Section II.C.3 20% opacity requirement
is more stringent during fire building, cleaning of fire boxes, soot blowing,
process modifications and adjustment or occasional cleaning of control
equipment. Therefore, since no one opacity requirement is more stringent
than the other at all times, all three opacity requirements are included in
the operating permit.
• Additional Monitoring
o Particulate matter emissions shall not exceed the limitation set forth in
Colorado Regulation No. 1, Section III.A.1.b.
■ Colorado Regulation No. 1, Section III.A.1.b. prescribes a
particulate matter limit based on the fuel input of the heater. When
using the design fuel input for P-138, a limitation of 0.205 lb/MMBtu
is obtained. It should be noted, however, that this limitation is
significantly higher than what the total PM emission factor from AP -
42 Chapter 1.4, Table 1.4-2 predicts for natural gas combustion.
Because combustion of natural gas results in significantly lower
actual emissions of total PM, the Division has determined that
compliance with this limit may be presumed at all times, provided
natural gas only is used as fuel for this heater. As such, this heater
is permitted to use natural gas only as fuel and the source shall
demonstrate compliance with this Colorado Regulation No. 1
123/0049 Page 64 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document— Renewal Operating Permit
requirement by maintaining records to verify natural gas only is
used.
o The heat content of the natural gas used to fuel heater P-138 shall be
verified semi-annually using the appropriate ASTM methods. The heating
value reported shall be the higher heating value (HHV) of the fuel gas.
This heating value is used to partition the fuel gas among users based on
the total facility fuel gas flowrate obtained from a meter.
o Hours of operation shall be monitored and recorded monthly. The hours
of operation are used to determine the monthly fuel gas consumption for
this heater.
o Records verifying the use of only natural gas as fuel shall be maintained
to demonstrate compliance with the opacity limitations.
• State Requirements
o Colorado Regulation No. 7 Section XVI.D
This section establishes the requirements for Combustion Process
Adjustment of affected unit operations. Affected operations, pursuant to
Section XVI.D.6.a., include process heaters with greater than or equal to
five (5) tons/year of actual uncontrolled NOx emissions. The requirements
set forth in this section include periodic maintenance, inspections and
recordkeeping.
Per the most recent APEN for P-138, received by the Division on
11/6/2015, actual uncontrolled emissions of NOx were below the 5
tons/year threshold. However, permitted emissions of NOx for this unit
exceed the 5 tons/year threshold (note that P-138 is an uncontrolled
emissions point). Because this unit could emit in excess of this threshold
without violating a permit limit, the combustion process analysis
requirements were included in the operating permit. However, it should be
noted that the requirements of Section XVI.D are not applicable until the
5 tons/year threshold is exceeded.
o Colorado Regulation No. 7 Section XVI.D
This section establishes the requirements for emission limitations,
compliance demonstrations, combustion process adjustments, reporting
and recordkeeping applying to stationary combustion equipment located
at major sources of NOx. In Section XVI.D.2., exemptions from the
requirements of Section XVI.D.4. (emission limitations), Section XVI.D.5.
(compliance demonstration), certain parts of Section XVI.D.7.
(recordkeeping) and Section XVI.D.8. (reporting) are listed. Hot oil heater
P-138 does not qualify for any of these exemptions. However, hot oil
heater P-138 is considered to be a process heater for the purposes of
Section XVI.D. Requirements for process heaters do not exist in Sections
XVI.D.4 or XVI.D.5 and, thus, neither of these sections, nor the associated
123/0049 Page 65 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
recordkeeping and reporting apply to this heater. However, process
heaters are affected equipment under the combustion process adjustment
requirements of Section XVI.D.6. and the associated recordkeeping under
Section XVI.D.7. Affected operations, pursuant to Section XVI.D.6.a.,
include process heaters with greater than or equal to five (5) tons/year of
actual uncontrolled NOx emissions. The requirements set forth in this
section include periodic maintenance, inspections and recordkeeping.
Per the most recent APEN for P-138, received by the Division on
11/6/2015, actual uncontrolled emissions of NOx were below the 5
tons/year threshold. However, permitted emissions of NOx for this unit
exceed the 5 tons/year threshold (note that P-138 is an uncontrolled
emissions point). Because this unit could emit in excess of this threshold
without violating a permit limit, the combustion process analysis
requirements were included in the operating permit. However, it should be
noted that the requirements of Section XVI.D are not applicable until the
5 tons/year threshold is exceeded.
o Additional recordkeeping — One additional recordkeeping requirement
was included in the operating permit to fill monitoring gaps left by Colorado
Regulation No. 7, Section XVI, as provided for under Colorado Regulation
No. 3, Part C, Section V.C.5.b. This additional requirement was clearly
denoted in the operating permit with italicized text and is summarized as
follows:
• The owner/operator shall maintain records of any alternative
combustion process adjustments performed under Colorado
Regulation No. 7, Section XVI.D.6.c. As written, Section XVI does
not include recordkeeping requirements sufficient to demonstrate
that a proper alternative combustion process adjustment was
performed. Because alternative combustion process adjustments
are allowed pursuant to Section XVI.D.6.c., proper documentation
is required to demonstrate compliance with the alternative
combustion process adjustment provisions, pursuant to Colorado
Regulation No. 3, Part C, Section V.C.5.b. Therefore, an explicit
requirement to keep records of any alternative combustion process
adjustments performed, the procedures used and what NSPS or
MACT (if any) applied, was included in the operating permit. It
should be noted that these requirements exactly mirror Colorado
Regulation No. 7, Section XVI.D.7.f.(i)(C), and these requirements
were present in the 11/17/2016 promulgation of Colorado
Regulation No. 7 Section XVI.
• Federal Requirements
o 40 CFR 60 Subpart Dc
P-138 only is subject to the requirements of NSPS Dc, as referenced in
construction permit 10WE1659. The heat input range for applicability
123/0049 Page 66 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
purposes of this subpart is between 10 MMBtu/hr and 100 MMBtu/hr. The
applicable requirements under NSPS Dc include maintaining records of
the amount of fuel combusted. It should be noted that:
■ The Notification of Startup requirements from §60.48c were not
included in the operating permit. The required notice for P-138 was
received by the Division on 7/15/2011, thereby fulfilling this
obligation
• This heater is subject only to recordkeeping requirements since
only natural gas is permitted to be used as fuel. The SO2 and
particulate matter requirements of §60.42c - §60.47c of NSPS Dc
were therefore not included in the operating permit.
2. Emission Factors
The emission factors used to calculate NOx and CO emissions were obtained from
AP -42 Chapter 1, Section 1.4, Table 1.4-1 Emission Factors for Nitrogen Oxides
(NOx) and Carbon Monoxide (CO) from Natural Gas Combustion:
Source
NOx
(lb/MMSCF)
CO
(lb/MMSCF)
P-138
50
84
These emission factors are applicable to natural gas fired "small boilers", which
are defined to have a design rating of less than 100 MMBtu/hr. Per the unit
description in construction permit 10WE1659, P-138 is equipped with low-NOx
burners, resulting in a lower emission factor for NOx for that unit.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Fuel Gas Consumption — Monthly monitoring required using the existing fuel gas
header meter and partition calculation to determine compliance with the rolling
twelve month emissions for NOx, CO and consumption
• Fuel Gas Analysis — Required semi-annually to verify the heat content, which is
used for the allocation of fuel gas to each user
• Hours of Operation — Monitored and recorded monthly; used in rolling twelve
month emissions calculations for NOx, CO and consumption
4. Compliance Status
According to the 6/2/2016 inspection, P-138 is in compliance with all applicable
conditions in Colorado Construction Permit 10WE1659.
E. P033 - Custom 4 MMSCFD TEG Dehydration Unit, AIRS ID: 130
P-136 — Evco Fabrication 85 MMSCFD TEG Dehydration Unit, AIRS ID: 136
123/0049 Page 67 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
1. Applicable Requirements
This operating permit condition encompasses the TEG dehydration units P033
(permitted under Colorado Construction Permit 01 WE0208) and P-136 (permitted under
Colorado Construction Permit 10WE1659). The applicable conditions identified in the
Construction Permit section above were included in the operating permit. Most
conditions in each construction permit were duplicative and, as such, were combined
into a single condition applicable to both dehydration units within the operating permit.
It should be noted that as of the permit issuance date of XX/XX/XXXX, 10WE1659 has
not yet obtained final approval to operate due to an outstanding stack test for the
regenerative thermal oxidizer, which was also permitted under 10WE1659. The
dehydration unit P-136 may be routed to this thermal oxidizer during normal operations,
and, as such, there are outstanding initial compliance requirements for this unit. The
initial compliance requirements for the RTO have been included within a separate
control device condition in the operating permit.
Calculation methods for monthly emissions of NOx, CO, VOC and HAP were included
in the operating permit, detailing the input parameters necessary to complete the
monthly GLYCaIc and/or ProMax runs, and the applicable control efficiency for each
dehydration unit operating mode. A conversion for daily gas throughput based on the
metered throughput to each dehydration unit and the recorded operating hours was
included to convert the monthly tracked throughput into a daily value. This daily gas
throughput is a required input to the GLYCaIc and/or ProMax process simulation to
determine compliance with the rolling twelve month NOx, CO, VOC and HAP limitations.
It should be noted that condensers were not considered when determining still vent
emissions from these dehydration units. The 7/25/2014 construction permit modification
application for P-130 did not utilize the condenser operation in the attached GLYCaIc
model runs. Similarly, the ProMax model submitted in the 11/13/2017 significant
modification application did not model a condenser for P-136. Condenser controls are
not claimed in the O&M plans for these units, nor are they indicated on the APENs. As
such, condenser monitoring conditions were not included in the operating permit for
either dehydration unit.
To more specifically address the control devices associated with the dehydration units,
a separate condition was included in the operating permit for the ECD and RTO. This
was done to consolidate limitations and requirements applicable to both the ECD and
RTO that would otherwise be duplicated in the dehydration unit and amine sweetening
unit conditions. NOx and CO limitations from each contributing unit, as well as
combustion emissions generated from pilot gas destruction, were reported in this control
device condition to accurately reflect the total amount of NOx and CO emissions
generated at each control device. The methodology used to monitor compliance with
the NOx and CO emission limitations for the dehydration units was retained in the
dehydration unit condition. The control device condition references these calculation
methods.
It should be noted that the NOx and CO emissions generated at the ECD from the
dehydration unit P033 still vent alone are below the reportable threshold for sources
123/0049 Page 68 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
operating in non -attainment areas. However, when combined with NOx and CO
emissions from other contributing units, NOx and CO emissions generated at the ECD
exceed the reportable threshold. As such, the NOx and CO emissions from dehydration
unit P033 were included in the NOx and CO limit reported in the control device condition.
The emission calculation methodology for NOx and CO, which is applicable to both
dehydration units P033 and P-136, was therefore included in the dehydration unit
condition and referenced in the control device condition to support calculation of the
NOx and CO limitations for the ECD.
It should be noted that these units are permitted to operate with 2% ECD downtime,
during which still vent emissions from each dehydration unit may be routed to
atmosphere. The intent of downtime is to allow for periods of ECD maintenance in
response to malfunctions, during which still vent emissions cannot be safely or
practicably destructed by the ECD, and are therefore routed to atmosphere. It has been
determined that downtime should be permitted as a function of actual operating time,
not a hard numerical limitation based on the maximum number of operational hours
and/or maximum throughput. Numerical limits on hours, throughput or VOC emissions
would necessarily be based on maximum operating parameters, or 2% of 8,760 hours
of operation and/or 2% of the maximum wet gas throughput. Permitting based on
maximum operational parameters would result in hard numerical limitations that would
seemingly allow the source to process that numerical amount wet gas, discharge that
numerical amount of pollutant or vent emissions to atmosphere for that numerical
quantity of hours, regardless of actual hours of operation. Therefore, operating over a
shortened timeframe and/or operating at less than maximum capacity could result in
actual downtime in excess of the allowable 2% (i.e., an hours limitation on downtime of
175.2 hours, or 2% of a maximum 8,760 hours of operation, would theoretically permit
the source to route still vent emissions to atmosphere for 175.2 hours, even if the source
only operates for 175.2 hours per year, effectively equating to 100% downtime). A
permit limitation of this type would allow the source to operate in direct violation of the
hydrocarbon and VOC emission reduction requirements of Colorado Regulation No. 7
Section XII.H and XVII.D for dehydration units. To ensure operating permit limitations
do not contradict the requirements of these state regulations and generate a non-
compliance situation for the source, the emission limitation for downtime was not based
on maximum hours of operation and maximum wet gas throughput to the dehydration
units. Instead, the limitation was based on a percentage of actual operating parameters,
which allows for a prorated amount of downtime based on actual hours of operation and
actual wet gas throughput to each dehydration unit. The applicable downtime limitation
was incorporated into the operating permit as a wet gas throughput limitation. Wet gas
throughput to each dehydration unit during periods of ECD downtime (defined as
periods of time when still vent emissions from either dehydration unit are routed to
atmosphere, pursuant to the 11/13/2017 permit modification) shall not exceed 2% of the
total wet gas throughput to the dehydration unit on a rolling twelve month basis.
Other Applicable Requirements
This section addresses applicable requirements to the TEG dehydration units that were
not explicitly defined in Colorado Construction Permit 01WE0208 or 10WE1659, but
were included in the operating permit.
123/0049 Page 69 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Permit Modification Received 7/10/2017 (for P033 only) & 11/13/2017 (for P-136
onl
o Uncontrolled Wet Gas Throughput — The amount of wet gas processed by
each dehydration while still vent emissions are routed to atmosphere shall
not exceed 2% of the annual total gas throughput to each dehydration unit
on a rolling 12 month basis. This throughput is equivalent to the amount
of wet gas throughput to each dehydration unit during periods of ECD
downtime when still vent emissions are routed to atmosphere. This is
determined by monitoring the wet gas throughput to each dehydration unit
using an inlet meter and determining the amount of wet gas throughput
during periods when the still vents from either dehydration unit were
routed to atmosphere, as monitored using control valve position indicators
for P-136 and daily valve alignment visual inspections for P033 (see Still
Vent Emissions Routing condition below). This calculated throughput is
used to monitor compliance with the aforementioned throughput
limitations.
It should be noted that this uncontrolled wet gas throughput is the amount
of pas processed by each dehydration unit during periods of control device
downtime when still vent emissions are routed to atmosphere. These
limitations apply to the inlet wet pas flowrate of each dehydration unit,
NOT to the still vent flowrate. The still vent is not metered directly — a
process model is used to estimate the still vent flowrate. Instead of placing
a limitation on a parameter that must be modeled, the limitation was
placed on a parameter that is directly metered. This metered inlet wet gas
flowrate is then used in the required monthly process model to determine
compliance with the emission limitations for NOx, CO, VOC and HAP.
o Controlled Hours of Operation — The total hours during which each
dehydration unit is controlled (i.e., routed to an operational combustion
device) shall be determined as follows:
■ P033 — Controlled hours of operation for P033 shall be determined
using the still vent emissions routing records required by the Still
Vent Emissions Routing condition (see below). Controlled hours
are defined as periods during which the P033 still vent is routed to
the ECD.
■ P-136 — Controlled hours of operation for P-136 shall be
determined using the still vent emissions routing records required
by the Still Vent Emissions Routing condition (see below).
Controlled hours are defined as the periods during which still vent
emissions from P-136 were controlled by either the RTO or ECD.
Controlled hours of operation are used to determine the length of time for
which each control device efficiency was applicable during each month.
This length of time, combined with the applicable control efficiency, is
123/0049 Page 70 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
used to determine compliance with the NOx, CO, VOC and HAP
limitations.
o Uncontrolled Hours of Operation — The total hours during which each
dehydration unit is uncontrolled (i.e., routed to atmosphere), shall be
determined as follows:
■ P033 — Uncontrolled hours of operation for P033 shall be
determined using the still vent emissions routing records required
by the Still Vent Emissions Routing condition (see below).
Uncontrolled hours are defined as the periods during which still
vent emissions from P033 were routed to atmosphere.
■ P-136 Uncontrolled hours of operation for P-136 shall be
determined using the still vent emissions routing records required
by the Still Vent Emissions Routing condition (see below).
Uncontrolled hours are defined as the periods during which still
vent emissions from P-136 were routed to atmosphere.
Uncontrolled hours of operation are used to determine the length of time
during which emissions are routed to atmosphere and are therefore
uncontrolled. This value is used to determine compliance with the VOC
and HAP emission limitations.
o Still Vent Emissions Routing — The routing of still vent emissions from
P033 and P-136 to the ECD or atmosphere (or, for P-136 only, to the RTO)
shall be monitored and recorded daily in a log to be made available to the
Division upon request. This record shall indicate the date and time at
which each new routing configuration commences. Valve position
indicators for P-136 and daily valve alignment visual inspections for P033
shall be used to determine the routing configuration and the duration for
which that routing configuration is applicable.
Pneumatic control valves are used to automatically direct the still vent
emissions from P033 and P-136 to the ECD or atmosphere (or, for P-136
only, to the RTO). These valves are controlled remotely, and are equipped
with position indicators to inform operations of the valve position (i.e.,
open/closed). These valves are interlocked with operational parameters
from each control device (combustion chamber temperature, operating
status, etc.), and are permitted to open only when these operational
parameter setpoints have been achieved by the control device. As such,
valve positioning may be used to determine where the still vent emissions
from P033 or P-136 are routed.
It should be noted that the control valve position was chosen as the
monitoring parameter for the control device downtime allowance because
valve position most accurately represents the duration of each routing
configuration for each still vent. ECD runtime status is an indication of
ECD operation only. ECD downtime, as it was defined in the 11/13/2017
modification application constitutes "periods when emissions from either
123/0049 Page 71 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
still vent are routed to the atmosphere instead of to the ECD". As such, it
is not the non -operation of the ECD that constitutes downtime, it is the
routing of still vent emissions to atmosphere. Therefore, the most direct
and accurate indication of downtime is the routing of emissions to
atmosphere, and the most appropriate downtime monitoring parameter is
the alignment of the control valve responsible for routing still vent
emissions to atmosphere. Pursuant to source comments received
11/2/2018, only the P-136 control valve position indicators can be
automatically trended in the plant historian. As such, the valve position
indication data stored in the plant historian will be used to determine the
routing configuration of the P-136 still vent. The valves that route P033
still vent emissions do not provide the signal necessary to trend valve
position. Therefore, daily visual inspection of the alignment of these valves
shall be conducted and recorded in a log to determine the routing of still
vent emissions from P033.
The still vent routing and duration is used to determine controlled and
uncontrolled hours of operation for P033 and P-136. Additionally, these
records shall be used to determine the Colorado Regulation No. 7
requirements that are applicable to the RTO. Colorado Regulation No. 7
has compliance requirements for dehydration units, but none for amine
sweetening units. As such, different Colorado Regulation No. 7
requirements apply when only the amine sweetening unit is routed to the
RTO than when the dehydration unit is also routed to the RTO. Please
refer to the Control Device Condition V.L for the specific applicable
regulations.
• Additional Monitoring
o Process Model Input Parameters — The following table presents various
parameters to be monitored and the associated frequency, pursuant to
the O&M plan for each dehydration unit. These parameters are used as
inputs to the process simulation models required to determine compliance
with the annual limitations of NOx, CO, VOC and HAP.
Parameter
Monitoring
Frequency
Inlet Wet Gas Temperature
Weekly
Inlet Wet Gas Pressure
Weekly
Flash Tank Operating Temperature
Weekly
Flash Tank Operating Pressure
Weekly
o Hours of Operation — Monitored and recorded monthly; used to determine
the average daily gas throughput
• State Requirements
123/0049 Page 72 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Colorado Regulation No. 7 Section XII
The TEG dehydration units at the Roggen Natural Gas Processing Plant
operate in a non -attainment area and as such, are subject to the following
applicable requirements of Colorado Regulation No. 7 Section XII. Please
note that all general requirements specific to control devices have been
moved to the Control Device condition (see Section V.L of this document).
• Section XI I.H.1 — Glycol Dehydrator Emissions Limitations — Actual
uncontrolled emissions of VOC shall be reduced by at least 90%
• Section XII.H.5 - Weekly inspections of air pollution control
equipment to verify pilot light presence, proper valve configuration
for fuel gas routing pilot, no smoke emanating from combustion
device and certification that operation of the control device is
consistent with manufacturer specifications
• Section XII.H.6 — Reports shall be submitted semi-annually
included a list of affected dehydration units, the air pollution control
equipment used to control those dehydrators and inspection dates
and results required under Section XII.H.
o Colorado Regulation No. 7 Section XVII
The TEG dehydration units at the Roggen Natural Gas Processing Plant
are subject to the following applicable requirements of Colorado
Regulation No. 7 Section XVII. Please note that all general requirements
specific to control devices have been moved to the Control Device
condition (see Section VI of this document).
• Section XVII.B.1.b (State -Only Enforceable) — General
Requirements — The facility and all air pollution control equipment
shall be maintained according to good air pollution control practices
for minimizing emissions.
• Section XVII.D (State -Only Enforceable) — Glycol Dehydrators —
Actual uncontrolled emissions of VOC shall be reduced by at least
90%, actual uncontrolled emissions of hydrocarbons shall be
reduced by at least 95%, and combustion devices shall have a
design destruction rating of at least 98%. Applicable records shall
be maintained.
• It should be noted that although the combustion devices
were authorized by permit prior to 2014 (exemption criterion
of Section XVII.D.3.a), there are multiple building units
within 1,320 feet of the Roggen Natural Gas Processing
Plant (exemption criterion of Section XVII.D.3.b). As such,
the requirement to operate a combustion device with a
design destruction efficiency of 98% was included in the
operating permit.
123/0049 Page 73 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Federal Requirements
o Compliance Assurance Monitoring (CAM)
Compliance Assurance Monitoring (CAM) requirements are set forth in 40
CFR 64. P-136 only is subject to CAM, as it is subject to emission
limitations, uses a control device to achieve compliance with those
limitations and has potential pre -control emissions that exceed major
source thresholds for VOC and HAP. It should be noted that even though
the HAP limit is facility -wide, it is an emission limitation to which P-136 is
subject and because the pre -control HAP emissions from this unit are
above the major source thresholds for HAP, P-136 is subject to CAM for
HAP. Pre -control emissions for P033 are below that of the major source
thresholds for all pollutants and, therefore, P033 is not subject to CAM.
O&M plan requirements for regenerative thermal oxidizers (RTO) include
daily temperature monitoring of the combustion chamber to ensure
efficient destruction of waste gas, which is dependent upon the
temperature at which the RTO is operated. The minimum combustion
chamber temperature required by Colorado Construction Permit
10WE1.659 is 1450°F. Additionally, the O&M plan specifies daily pilot light
monitoring for enclosed combustion devices (ECD). At the Roggen
Natural Gas Processing Plant, this monitoring is accomplished using a
thermocouple heat sensing device. As such, acceptable monitoring for the
RTO, for the purposes of CAM, has been determined to be a daily average
of the combustion chamber temperature readings taken by the Distributed
Control System (DCS). For the ECD, acceptable monitoring for the
purposes of CAM has been determined to be daily monitoring of the
thermocouple signal to determine whether or not the pilot light is present.
Pursuant to 64.3(b)(4), monitoring frequency is dependent upon the post -
control quantity of emissions. For pollutant -specific emission units with
post -control emissions of less than major source thresholds (i.e., small
PSEU), the monitoring frequency must be at least once every 24 hours.
Daily monitoring of the combustion chamber temperature of the RTO and
the presence of a pilot light for the ECD was included in the CAM plan for
this unit.
o 40 CFR 63 Subpart HH
Area source requirements set forth in MACT HH have been included in
this operating permit. These requirements include compliance with an
optimal glycol circulation rate, methods for the determination of gas
flowrate and various recordkeeping requirements.
It should be noted that both P033 and P-136 are subject to the MACT HH
subpart. However, due to the size of P033, some exemptions may apply
to this unit only. If the actual annual flowrate of natural gas to P033 is less
than 85,000 standard cubic meters per day (-3 MMSCFD), OR if the
actual average emissions of benzene from P033 is less than 0.9
123/0049 Page 74 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
megagrams per year (-1,984 lb/year), P033 is exempt from the optimal
glycol circulation rate and associated requirements set forth in MACT HH.
Because this TEG dehydration unit is rated at 4 MMSCFD and historically
operates well below its permitted limitations, it is possible that P033 can
meet one or both of the exemption criteria. Therefore, the exemption
language, calculation methods for the actual annual natural gas flowrate
and benzene/BTEX emissions, and the required recordkeeping
requirements demonstrating the applicability of these exemptions have
been included in the operating permit.
The Roggen Natural Gas Processing Plant was determined to not be
located near or within a UA plus offset and UC boundary. As such, the
source shall comply with the optimum glycol circulation rate requirements
if the exemption criteria listed above is not otherwise met.
2. Emission Factors
NOx and CO — Emissions of NOx and CO are generated from the destruction
of still vent emissions in either the regenerative thermal oxidizer (RTO) or
enclosed combustion device (ECD). Please refer to the Control Device
condition V.L in this document for a discussion of the applicable emission
factors.
• VOC and HAP — A specific emission factor was not developed for VOC or HAP
emissions. Instead, the GLYCaIc or ProMax process model shall be used to
determine the flowrate of VOC and HAP components from the still vent, using
the most recent wet gas analysis, average daily wet gas throughput, and
average monthly values for inlet wet gas pressure and temperature, the flash
tank operating temperature and pressure and the lean glycol circulation rate
as inputs to the process model. The uncontrolled and controlled hours of
operation shall be used to determine the appropriate control efficiency to apply
to the still vent emissions obtained from the model. A control efficiency of 95%
shall apply when the ECD is being used to destruct still vent emissions from
either P033 or P-136. A control efficiency of 97% shall apply when the RTO is
being used to destruct still vent emissions from P-136. A control efficiency of
0% shall apply during periods of combustion device downtime when emissions
are routed to atmosphere.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Total Wet Gas Throughput - The amount of wet gas processed by each
dehydration unit is monitored using existing meters at the inlet of each unit. The
monthly throughput is converted to a daily average and used as an input to the
GLYCaIc or ProMax process model to determine compliance with NOx, CO,
VOC, HAP and throughput limitations.
123/0049 Page 75 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating. Permit
Uncontrolled Wet Gas Throughput — The amount of wet gas processed by each
dehydration unit during periods of ECD downtime is monitored using the still vent
emission routing data in conjunction with the inlet gas throughput to each
dehydration unit, as metered at the unit inlet. Uncontrolled wet gas throughput is
defined as periods during which the still vent emission routing data indicates still
vent emissions from either dehydration unit were routed to atmosphere. It should
be noted that the downtime limitation applies to the inlet wet gas throughput, NOT
the still vent flowrate.
• Lean Glycol Circulation Rate Monitored daily and used as an input to the
GLYCaIc or ProMax process model to determine compliance with VOC and HAP
emission limitations. The glycol pump outlet for P-136 is equipped with a
flowmeter to directly measure the circulation rate. However, the glycol circulation
rate for P033 is not directly metered and requires a flowrate calculation based on
pump strokes and manufacturer data.
• Extended Analysis of Wet Gas - Performed annually to be used as an input to
the GLYCaIc or ProMax model to determine compliance with VOC and HAP
emission limitations. The analysis should identify the VOC and HAP components
present in the wet gas.
• Process Model Input Parameters — Process parameters including inlet wet gas
temperature and pressure and flash tank temperature and pressure are
monitored and averaged on a monthly basis to serve as inputs to the GLYCaIc
or ProMax process model.
• Total Hours of Operation — Monitored and recorded monthly; used to determine
uncontrolled and controlled hours of operation.
• Controlled Hours of Operation
o P033 — Monitored and determined monthly using the records required by
the Still Vent Emissions Routing condition (see below); used to determine
the length of time each month for which the ECD control efficiency of 95%
may be used to monitor compliance with VOC, HAP, NOx and CO
emission limitations. Controlled hours of operation are defined as times
when P033 was operational and still vent emissions were routed to the
ECD (i.e., controlled).
o P-136 — Monitored and determined monthly using the records required by
the Still Vent Emissions Routing condition (see below); used to determine
the length of time each month for which the ECD or RTO control efficiency
of 95% or 97%, respectively, may be used to monitor compliance with
VOC, HAP, NOx and CO emission limitations. Controlled hours of
operation are defined as times when P-136 was operational and still vent
emissions were routed to either the ECD or RTO (i.e., controlled).
• Uncontrolled Hours of Operation
123/0049 Page 76 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
o P033 — Monitored and determined monthly using the records required by
the Still Vent Emissions Routing condition (see below); used to determine
the length of time for which a control efficiency of 0% shall be used to
monitor compliance with VOC and HAP limitations. Uncontrolled hours of
operation are defined as times when P033 was operational and still vent
emissions were routed to atmosphere (i.e., uncontrolled).
o P-136 — Monitored and determined monthly using the records required by
the Still Vent Emissions Routing condition (see below); used to determine
the length of time for which a control efficiency of 0% shall be used to
monitor compliance with VOC and HAP limitations. Uncontrolled hours of
operation are defined as times when P-136 was operational and still vent
emissions were routed to atmosphere (i.e., uncontrolled).
• Still Vent Emissions Routing
o P033 — Both the routing configuration of still vent emissions and the
duration of that routing are monitored and recorded daily via visual
inspection of the alignment of the control valves used to direct the P033
still vent to the ECD or to atmosphere. The routing configuration and
duration are used to determine the hours of controlled and uncontrolled
operation for P033 and to determine the applicable Colorado Regulation
No. 7 requirements for the RTO (see Control Device Condition V.L of this
document)
o P-136 — Both the routing configuration of still vent emissions and the
duration of that routing are monitored and recorded daily, using valve
position indication from the control valves used to direct the P-136 still
vent to the ECD, RTO or to atmosphere. The routing configuration and
duration are used to determine the hours of controlled and uncontrolled
operation for P-136 and to determine the applicable Colorado Regulation
No. 7 requirements for the RTO (see Control Device Condition V.L of this
document)
4. Compliance Status
According to the 6/2/2016 inspection, P033 is in compliance with all applicable
conditions in Colorado Construction Permit 01WE0208. It should be noted,
however, that P033 did not operate during the 2015-2016 compliance period. P-
136 is in compliance with all applicable conditions in Colorado Construction Permit
10WE1659 EXCEPT as follows:
• Opacity: The ECD used to control emissions from P033 and P-136 had an
observed opacity of greater than 30% for 23 minutes during the compliance
period
This violation has been addressed within the Division's enforcement group and no
separate compliance schedule/plan is required for the purposes of the Title V
Operating Permit.
123/0049 Page 77 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No, 95OPWE055
Technical Review Document — Renewal Operating Permit
F. P-137 - Evco Fabrication 85 MMSCFD Amine Sweetening Unit, AIRS ID: 137
1. Applicable Requirements
This operating permit condition addresses the amine sweetening unit P-137, permitted
under Colorado Construction Permit 10WE1659. The applicable conditions from
10WE1659 have been incorporated in the operating permit as described above in the
Construction Permit section of this document.
It should be noted that as of the permit issuance date of XX/XX/ ';X, 10WE1659 has
not yet obtained final approval to operate due to an outstanding stack test for the
regenerative thermal oxidizer, which was also permitted under 10WE1659. The amine
sweetening unit emissions are routed exclusively to this thermal oxidizer during normal
operations, and, as such, there are outstanding initial compliance requirements for this
unit. The initial compliance requirements for the RTO have been included within a
separate control device condition in the operating permit.
Calculation methods for monthly emissions of NOx, CO, SO2, VOC and HAP were
included in the operating permit, detailing the input parameters necessary to complete
the monthly ProMax model run. A conversion for daily gas throughput based on the
metered throughput to the amine sweetening unit and the recorded operating hours was
included to convert the monthly tracked throughput into a daily value. The daily gas
throughput is a required input to the process simulation to determine compliance with
the rolling twelve month NOx, CO, S02, VOC and HAP limitations.
To more specifically address the control device for the amine sweetening unit, a
separate condition was included in the operating permit for the RTO, which also sets
forth requirements for the ECD, the control device for the dehydration units P033 and
P-136. This was done to consolidate limitations and requirements applicable to both the
ECD and RTO that would otherwise be duplicated in the dehydration unit and amine
sweetening unit conditions. NOx and CO limitations from each contributing unit, as well
as combustion emissions generated from pilot gas destruction, were reported in this
control device condition to accurately reflect the total amount of NOx and CO emissions
generated at each control device. The methodology used to monitor compliance with
the NOx and CO emission limitations for the amine sweetening unit was retained in the
amine sweetening unit condition. The control device condition references these
calculation methods. It should be noted that the NOx emissions generated at the RTO
from the amine sweetening unit acid gas vent alone are below the reportable threshold
for sources operating in non -attainment areas. However, when combined with NOx
emissions from other contributing units, NOx emissions generated at the RTO exceed
the reportable threshold. As such, the NOx emissions from the amine sweetening unit
were included in the NOx limit reported in the control device condition. The emission
calculation methodology for NOx was therefore included in the amine sweetening unit
condition and referenced in the control device condition to support calculation of this
limitation.
Other Applicable Requirements
123/0049 Page 78 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
This section addresses applicable requirements to the amine sweetening unit that were
not explicitly defined in Colorado Construction Permit 10WE1659, but were included in
the operating permit.
• Permit Modification Received 11/13/2017
This permit modification served to effectively nullify all modifications to P-137
requested by the source in the 7/10/2017, 7/31/2017 and 9/22/2017 permit
modification applications. Therefore, the applicable requirements to the amine
sweetening unit are those from the 3/18/2015 issuance of Colorado Construction
Permit 10WE1659. The requirements of this construction permit were
incorporated into the operating permit as outlined in Section IV above.
It should be noted that in the 11/13/2017 modification application, the source
submitted a new APEN for P-137 to effectively revert all requirements and permit
limitations that had been changed in the 7/10/2017, 7/31/2017 and 9/22/2017
modification applications back to those permitted in the 3/18/2015 issuance of
10WE1659. On this new APEN, the source had updated the AP -42 emission
factor for CO, which had changed in the December 2016 updates to AP -42
Section 13.5 Table 13.5-2 for industrial flares. As such, the emission limitation
for CO decreased from its original permitted value in the 3/18/2015 issuance of
10WE1659. This updated emission factor and CO limitation were included in the
operating permit renewal. In source correspondence received 1/31/2018, it was
requested that emissions contributions from the burner gas intermittently
required for RTO operation be included in the emission limitations for this unit.
As such, emission limitations for the amine unit were updated and calculation
methodologies were included for NOx and CO resultant from bumer gas
destruction. It should be noted that the calculation methods for NOx and CO
calculations were included in a separate control device condition created to
specifically address the RTO.
For a more detailed discussion regarding the 11/13/2017 permit modification,
please refer to Section XII of this document.
• Additional Monitoring
o Process Model Input Parameters — The following table presents various
parameters to be monitored and the associated frequency, pursuant to
the O&M plan for the amine sweetening unit. These parameters are used
as inputs to the process simulation model required to determine
compliance with the annual limitations of NOx, CO, SO2, VOC and HAP.
Parameter
Monitoring
Frequency
Inlet Sour Gas Temperature
Weekly
Inlet Sour Gas Pressure
Weekly
Flash Tank Operating Temperature
Weekly
Flash Tank Operating Pressure
Weekly
123/0049 Page 79 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
o Hours of Operation - Monitored and recorded monthly; used to determine
the average daily gas throughput and monitor compliance with the annual
throughput limitations
State Requirements
o Colorado Regulation No. 7 Section XV1I.B
The amine sweetening unit at the Roggen Natural Gas Processing Plant
is subject to the following general requirements of Colorado Regulation
No. 7 Section XVII.B:
■ Section XVII.B.1.b (State -Only Enforceable) — The facility and air
pollution control equipment shall be operated at all times using
good air pollution control practices
• Federal Requirements
o Compliance Assurance Monitoring (CAM)
Compliance Assurance Monitoring (CAM) requirements are set forth in 40
CFR 64. P-137 is subject to CAM, as it is subject to emission limitations,
uses a control device to achieve compliance with those limitations and has
potential pre -control emissions that exceed major source thresholds for
HAP. It should be noted that even though the HAP limit is facility -wide, it
is an emission limitation to which the amine sweetening unit is subject,
and because the pre -control HAP emissions from this unit are above the
major source thresholds for HAP, the amine sweetening unit must comply
with CAM requirements.
40 CFR 64 requires that the monitoring required by the CAM plan be
"presumptively acceptable". A presumptively acceptable monitoring
approach may be one which is acceptable to the administrating authority.
O&M plan requirements for regenerative thermal oxidizers (RTO) include
daily temperature monitoring of the combustion chamber to ensure
efficient destruction of waste gas, which is dependent upon the
temperature at which the RTO is operated. The minimum combustion
chamber temperature required by Colorado Construction Permit
10WE1659 is 1450°F. As such, presumptively acceptable monitoring for
the RTO has been determined to be a daily average of the combustion
chamber temperature readings taken by the Distributed Control System
(DCS).
Pursuant to §64.3(b)(4), monitoring frequency is dependent upon the
post -control quantity of emissions. For pollutant -specific emission units
with post -control emissions of less than major source thresholds (i.e.,
small PSEU), the monitoring frequency must be at least once every 24
hours. Daily monitoring of the combustion chamber temperature of the
RTO was included in the CAM plan for this unit.
123/0049 Page 80 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
o 40 CFR 60 Subpart LLL
The amine sweetening unit is subject to NSPS LLL. The applicable
requirements for sweetening units under this subpart are determined by
the design capacity of hydrogen sulfide for the subject facility. Facilities
that process less than two (2) long tons per day of H2S (expressed as
sulfur) are exempt from all requirements except for recordkeeping and
reporting. The facility design capacity for H2S at the Roggen Natural Gas.
Processing Plant is less than the two (2) long tons per day of H2S. The
only applicable requirement from this subpart is for the source to maintain
documentation that the design capacity of this unit is less than two (2) long
tons/day. This requirement only was included in the operating permit.
2. Emission Factors
Emission factors for this unit were established as follows:
• NOx and CO — Emissions of NOx and CO are generated from the destruction
of acid gas vent emissions in the regenerative thermal oxidizer (RTO). Please
refer to the Control Device Condition V.L for a discussion of the applicable
emission factors.
SO2 — Emissions of SO2 are based on the assumption that there is complete
conversion of all H2S present in the waste gas to SO2 via combustion. The
chemical reaction governing this conversion is as follows:
2H2S + 302 - 2H20 + 2S02
To obtain a mass -based emission factor, the molecular weight for each
species was multiplied by that species' required stoichiometric quantity
(determined by the coefficients of the above equation) and ratioed, as shown
below:
64.07 lb SO2 x 2 lbmol S02
(h102'\
lbmol SO2 lb 502
Emission Factor= = 1.88
lbH2sl 34.08 lb H2S lb H2S
lbmol H2S x 2 lbmol H2S
This emission factor was used to convert the H2S content in the acid gas vent
stream (obtained from the most recent ProMax model run) to S02.
• VOC and HAP — A specific emission factor was not developed for VOC or HAP
emissions for the destruction of acid gas vent emissions. Instead, the ProMax
process model was used to determine the flowrate of VOC and HAP
components from the acid gas vent, using the most recent sour gas analysis,
average daily sour gas throughput, and average monthly values for inlet sour
gas pressure and temperature, the flash tank operating temperature and
pressure and the lean amine circulation rate as inputs to the process model.
A control efficiency of 97% shall apply to the RTO.
3. Monitoring Plan
123/0049 Page 81 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document Renewal Operating Permit
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Sour Gas Throughput — The amount of sour gas processed by the amine
sweetening unit is monitored using an existing inlet meter. The monthly
throughput is converted to a daily average and used as an input ProMax process
model to determine compliance with VOC, HAP, S02, NOx, CO and throughput
limitations.
• Lean Amine Circulation Rate — The circulation rate of lean amine is monitored
daily and used as an input to the ProMax process model to determine compliance
with VOC, HAP, SO2 NOx and CO emission' limitations_ This circulation rate is
directly metered, as indicated in the source comments provided 11/2/2018. In the
event that the flowmeter cannot be used, the lean amine circulation rate is
assumed to be the design rate of the circulation pump.
• Extended Analysis of Sour Gas - Performed annually to be used as an input to
the ProMax model to determine compliance with VOC, HAP, S02, NOx and CO
emission limitations. The analysis should identify the VOC and HAP components,
as well as any H2S present in the sour gas.
• Process Model Input Parameters — Process parameters including inlet sour gas
temperature and pressure and flash tank temperature and pressure are
monitored and averaged on a monthly basis to serve as inputs to the ProMax
process model.
• Hours of Operation — Monitored and recorded monthly; used to determine
average daily gas throughput.
4 Compliance Status
According to the 6/2/2016 inspection, P-137 is in compliance with all applicable
conditions in Colorado Construction Permit 10WE1659. It should be noted,
however, that P-137 did not operate during the 2015-2016 compliance period.
Upon startup, this unit is required to undergo initial compliance testing for the RTO
associated with it (see Control Device Condition V.L for requirements).
It should be noted that no separate compliance schedule/plan is required for the
purposes of the Title V Operating Permit.
G. P025 — Fugitive Emissions from Equipment Leaks, AIRS ID: 122
1. Applicable Requirements
This operating permit condition addresses the fugitive equipment leaks for the Roggen
Natural Gas Plant, P025, permitted under Colorado Construction Permit 10WE1659.
The applicable conditions from 10WE1659 have been incorporated in the operating
permit as described above in the Construction Permit section of this document.
It should be noted that as of the permit issuance date of )O(/ )OOO(, 10WE1659 has
not yet obtained final approval to operate due to an outstanding stack test for the
123/0049 Page 82 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
regenerative thermal oxidizer, which was also permitted under 10WE1659. However,
all compliance certification documentation pertinent to P025 was received by the
Division on 9/14/2015. There are no further final approval requirements for the fugitive
emissions point at this facility.
Calculation methods for monthly emissions of VOC and HAP were included in the
operating permit, as well as the service -specific emission factors for each component
type identified in the reference document EPA -453/R 95-017, "EPA's Protocol for
Equipment Leak Emission Estimates", Table 2.4: The Division -approved control factors
for each component were also listed in this condition.
Other Applicable Requirements
This section addresses applicable requirements to the fugitive emissions point P025
that were not explicitly defined in Colorado Construction Permit 10WE1659, but were
included in the operating permit.
• Additional Monitoring
o Component Count — Although a representative component count is
required in Condition 6 of 10WE1659 (see Construction Permit section
above), the construction permit does not specify a required frequency and
omits recordkeeping instructions. The operating permit has expanded
upon this condition to include Division standard language requiring a
facility -wide component hard -count once every five (5) years and a
running total tracking the additions and subtractions of the components as
they occur.
o Extended Gas Analysis — Colorado Construction Permit 10WE1659 does
require this analysis of process gas pursuant to Conditions 6 and 36 (see
Construction Permit section above). However, based on source
calculations, clarifications regarding the use of the extended gas analysis
in calculation of emissions were added to this condition as follows:
• For light liquid service, it is permissible to assume 100% VOC. The
light liquid (i.e. condensate) at the facility should have minimal
quantities of highly volatile gases such as methane and ethane
and, due to the three-phase separation occurring at either
upstream operations or the inlet slug catcher at Roggen, the water
content should be negligible as well. Therefore, this assumption
should be valid, albeit slightly conservative.
• For light liquid service, it is permissible to assume the HAP content
of the vapor is the same as the HAP content of the light liquid.
Although the light liquid itself should have more HAP than the
processed vapor stream since most HAP constituents are liquid at
normal temperatures and pressures, much of the liquid service
components at gas plants operate at elevated pressures.
Equipment leaks occurring through components at elevated
pressure will therefore flash to atmospheric pressure as they are
123/0049 Page 83 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
released. This flashed material will most likely have a composition
more similar to the gas stream subject to the extended analysis
requirement at Roggen, since lighter materials vaporize more
easily than heavier ends. A liquids analysis of, for example,
stabilized condensate will have a much higher concentration of
HAP than what is most likely released into the atmosphere as
fugitive emissions throughout the facility, resulting in an artificially
high HAP estimation for this point. Therefore, it is considered
acceptable to assume the HAP concentration in the sampled gas
stream applies to the components in light liquid service for the
calculation of HAP emissions.
• State Requirements
o Colorado Regulation No. 7 Section XII.G
■ Section XII.G.1 — This section requires that fugitive emissions from
gas processing plants operating in non -attainment locations
comply with the LDAR requirements of NSPS OOOO, regardless
of the date of construction of the plant, unless otherwise subject to
the LDAR requirements of NSPS OOOOa. The Roggen Natural
Gas Processing Plant, except for Process Units RC (Roggen
Compression), RP (Roggen Plant) and RTF (Roggen Tank Farm),
is subject to NSPS KKK on a federal level, based on the plant's
construction date (see Section III of this document). For the
purposes of the Roggen Natural Gas Processing Plant, compliance
with NSPS KKK shall be presumed, provided the requirements of
NSPS OOOO are met.
■ Section XII.G.3 — This section requires compliance with Section
XII.G.1 (which became effective 12/30/2017) by 1/1/2019 for
sources constructed prior to 1/1/2018. Since the Roggen Natural
Gas Processing Plant was constructed well before this date, the
facility has until 1/1/2019 to comply with the aforementioned
requirements.
• Federal Requirements
o 40 CFR 60 Subpart KKK
The fugitive emissions point P025 is subject to the requirements of NSPS
KKK, as referenced in construction permit 10WE1659. It should be noted,
however, that pursuant to Colorado Regulation No. 7, Section XII.G.1, the
Roggen Natural Gas Processing Plant is subject to NSPS OOOO (see
above discussion). As such, compliance with NSPS KKK is presumed,
provided the requirements of NSPS OOOO are met. The operating permit
was updated to reflect this presumption.
o 40 CFR 60 Subpart OOOO
123/0049 Page 84 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Process Units RC (Roggen Compression), RP (Roggen Plant) and RTF
(Roggen Tank Farm) only, contained within the fugitive emissions point
P025, are subject to the requirements of NSPS OOOO, as noted in the
significant modification received 9/11/2017. The applicable requirements
under NSPS OOOO include complying with general good engineering
practices, the Leak Detection and Repair (LDAR) requirements set forth
in NSPS Wa, recordkeeping requirements and reporting requirements.
It should be noted that the entire Roggen Natural Gas Processing Plant
as a whole is now subject to the applicable LDAR requirements of Subpart
OOOO, pursuant to Colorado Regulation No. 7, Section XII.G.1 (see
above discussion). Therefore, all process units, not just those that
underwent a qualifying modification (i.e., RC, RP and RTF) are subject to
the LDAR requirements of NSPS OOOO.
2. Emission Factors
The service -dependent emission factors for each component type were obtained from
the document EPA -453/R 95-017, "EPA's Protocol for Equipment Leak Emission
Estimates", specifically, Table 2.4:
Component
Emission Factors (Ib/component-hr)
Gas Service
Light Liquid
Heavy Liquid
Connectors
4.41 x 10-4
4.63 X 10-4
1.65 x 10-5
Flanges
8.60 x 10-4
2.43 X 10-4
8.60 x 10-'
Open -Ends
4.41 x 10-3
3.09 X 10-3
3.09 x 10-4
Pump Seals
5.29 x 10-3
2.87 X 10-2
N/A
Valves
9.92 x 10-3
5.51 X 10-3
1.85 x 10-5
Other*
1.94 x 10-2
1.65 X 10-2
7.05 x 10-5
It should be noted that "other" component types, per the EPA document, are meant to
include compressors, pressure relief valves, relief valves, diaphragms, drain, dump
arms, hatches, instrument meters, polish rods and vents.
The most recent component count for the Roggen Natural Gas Processing Facility was
reported on the APEN received by the Division on 4/28/2017. The count is as follows:
Component
Component Count
Gas Service
Light Liquid
Heavy Liquid
Connectors,
2,398
2,937
0
Flanges
2,137
1,082
0
Open -Ends
0
0
0
Pump Seals
N/A
27
0
Valves
2,239
2,164
0
123/0049
Page 85 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Component
Component Count
Gas Service
Light Liquid
Heavy Liquid
Other*
115
44
0
Control factors for each component type were agreed upon by the source and the
Division. These factors are used at all Title V facilities owned and operated by this
source. The established control factors are as follows:
Component
Control Factor
Connectors
30%
Flanges
30%
Open -Ends
N/A
Pump Seals
75%
Valves
75%
Other*
75%
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Component Count — Facility -wide hard count required within ninety (90) days of
permit issuance and every five (5) years thereafter, as well as a running tally of
additions and subtractions for each component type, to be used when
determining compliance with the monthly VOC and facility -wide HAP limitations
• Extended Analysis of Process Gas — Performed annually to be used in
determining VOC concentrations for the fugitive emissions from gas -service
components and HAP concentrations for the fugitive emissions for gas and light
liquid service components.
4. Compliance Status
According to the 6/2/2016 inspection, P025 is in compliance with all applicable
conditions in Colorado Construction Permit 10WE1659.
H. P039 - Eight (8) 300 -bbl Stabilized Condensate Storage Tanks, AIRS ID: 125
1. Applicable Requirements
This operating permit condition addresses P039, permitted under Colorado
Construction Permit 12WE1242. The applicable conditions from 12WE1242 have been
incorporated in the operating permit as described above in the Construction Permit
section of this document.
Calculation methods for monthly emissions of VOC were included in the operating
permit.
123/0049 Page 86 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Other Applicable Requirements
This section addresses applicable requirements to the stabilized condensate tanks that
were not explicitly defined in Colorado Construction Permit 12WE1242, but were
included in the operating permit.
• Additional Monitoring
o Inspections — Pursuant to the terms of the O&M plan, thief hatches and
PRVs shall be weighted so they seat properly, and inspected annually.
o Combustion Device — Pursuant to the terms of the O&M plan, the enclosed
combustion device (ECD):
• Shall be operated at all times when emissions are routed to it
• Shall have a pilot light present at all times, verified by an auto -
igniter signal and/or thermocouple.
• Shall undergo Method 22 inspections daily
• Added monitoring requirement to conduct Method 9
observations in the event visual emissions are detected via
Method 22. The Method 9 observations were included as a
way to demonstrate compliance with the Colorado
Regulation No. 1 Section II.A.5 opacity standard. EPA
Method 9 observations shall be conducted by a certified
observer. If an opacity exceedance is observed, it shall be
considered to exist until another Method 9 reading is taken
which demonstrates compliance with the opacity standards
of Colorado Regulation No. 1, Section II.A.5.
• State Requirements
o Colorado Regulation No. 7 Section XII
The condensate storage tanks at the Roggen Natural Gas Processing
Plant operate in a non -attainment area and as such, are subject to the
following applicable requirements of Colorado Regulation No. 7 Section
XII:
• Section XII.C.1.a — General Requirements — All emission control
equipment shall be operated and maintained consistent with
manufacturer specifications and good engineering and
maintenance practices
• Section XII.C.1.b — All collection, storage, processing and handling
of condensate shall be designed to minimize VOC leakage
o Colorado Regulation No. 7 Section XVII
123/0049 Page 87 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
The condensate storage .tanks at the Roggen Natural Gas Processing
Plant are subject to the applicable requirements of Colorado Regulation
No. 7 Section XVII:
■ Section XVII.B (State -Only Enforceable) - General Conditions for
the operation of air pollution control equipment including:
• Section XVII.B.1.a, b and B.2.a — Good engineering
practices
• Section XVII.B.2.b — Zero visible emissions for enclosed
combustion devices
• Section XVII.B.2.d — Auto -igniter requirements for enclosed
combustion devices
■ Section XVII.C (State -Only Enforceable) — Storage tank
requirements
• Section XVII.C.1.a — The air pollution control device for
storage tanks with actual uncontrolled emissions of VOC
greater than twenty (20) tons/year must achieve a 95%
control efficiency for VOC. It should be noted that this
condition only applies if actual uncontrolled emissions of
VOC from the tank battery exceeds twenty (20) tons/year.
On the most recent APEN received 5/2/2016, actual
uncontrolled VOC emissions were below this threshold,
however, permitted uncontrolled emissions for this tank
battery exceed this threshold. Because this unit could emit
in excess of the threshold, this control efficiency requirement
of 95% was included in the operating permit, with the caveat
that the requirements are not applicable until the twenty (20)
tons/year threshold is exceeded. The source is allotted 60
days to comply with these requirements upon determination
of the threshold exceedance. This timeline was adopted
from a similar requirement for Section XVII.C.1.b.
• Section XVII.C.1.b — The air pollution control device for
storage tanks with actual uncontrolled emissions of VOC
greater than six (6) tons/year must achieve a 95% control
efficiency for hydrocarbons.
• Section XVII.C.1.d — Audio, Visual and Olfactory (AVO)
inspections for thief hatches, PRVs, auto -igniters, pilot gas
piping, process gas piping and combustor smoking
• Section XVII.C.2.a — Capture requirements including the
routing of emissions at all times to a control device and
operating the tank batteries such that venting from the thief
hatches and PRVs does not normally occur
123/0049 Page 88 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Section XVII.C.2.b and C.3 AIMM inspection
requirements, including periodic monitoring via EPA Method
21 and recordkeeping, to monitor compliance with the
capture requirements of Section XVII.C.2.a
2. Emission Factors
• VOC and HAP — The VOC and HAP emission factors set forth in the
operating permit were established under Colorado Construction Permit
12WE1242. These emission factors were developed using EPA TANKS
version 4.0.9d in conjunction with a stabilized condensate sample from
5/26/2011. It should be noted that the condensate stored in this tank is
stabilized to a sub -atmospheric vapor pressure prior to storage. As such,
flash emissions do not occur within these storage vessels. Because the
condensate is stabilized to meet a Reid vapor pressure (RVP) specification,
the composition of this condensate does not fluctuate appreciably. For
these reasons, static emission factors for VOC and HAP are appropriate for
these stabilized condensate storage tanks. The HAP emission factors are
presented in the facility -wide HAP emission limitation condition (discussed
in Section VI below).
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Condensate Throughput — Monitored monthly by summing the recorded volume
on all sales tickets from that month. This is used to monitor compliance with the
VOC and facility -wide HAP limits
• Inspections — Performed annually to ensure proper operation and maintenance
of the PRVs and thief hatches
• Pilot Light — Auto -igniter status, thermocouple temperature or visual inspections
completed daily
• Smoke — EPA Method 22 daily observations. In the event visual emissions are
observed, a Method 9 reading shall be performed by a certified observer to
determine compliance with the Colorado Regulation No. 1 Section II.A.5 opacity
requirement.
• AVO Inspections — Inspection of thief hatches, PRVs, access points, and
combustor operation during each loading event, or not more than once every
seven (7) days, and at least once every 31 days
• AIMM Inspections — Required at annually, quarterly or monthly, depending on
actual uncontrolled emissions
4. Compliance Status
123/0049 Page 89 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document = Renewal Operating Permit
According to the 6/2/2016 inspection, P039 is in compliance with all applicable
conditions in Colorado Construction Permit 12WE1242 EXCEPT as follows:
• Self -certification for this construction permit was received outside of the 180 day
window
This violation has been addressed within the Division's enforcement group and no
separate compliance schedule/plan is required for the purposes of the Title V
Operating Permit.
I. F029 — Stabilized Condensate Truck Loadout, AIRS ID: 126
1. Applicable Requirements
This operating permit condition addresses F029, permitted under the 5/1/2001 issuance
of the operating permit. The following requirements have been retained in the operating
permit and modified as follows:
Condition 8.1 — VOC emissions shall not exceed the annual limitations set forth in this
permit
• This condition was revised to update the VOC limitation as requested in the minor
modification application received 4/2/2007
• Calculation methods for monthly emissions of VOC were added to this condition.
Condition 8.2 — Condensate throughput shall not exceed the annual limitations set forth
in this permit
• This condition was revised to update the condensate throughput limitation as
requested in the minor modification application received 4/2/2007
2. Emission Factors
• VOC and HAP — The VOC and HAP emission factors set forth in the
operating permit were established in the 4/2/2007 minor modification and
updated in 2011 to reflect compositional changes. The VOC emission factor
was developed using an EPA TANKS version 4.0.9d simulation for
stabilized condensate. HAP emission factors were developed later using a
condensate sample from 5/26/2011 (this condensate sample was also used
to permit the stabilized condensate storage tanks under Colorado
Construction Permit 12WE1242). It should be noted that the condensate
loaded is stabilized to a sub -atmospheric vapor pressure. As such, this
liquid does not volatilize significantly during atmospheric loading operations.
In addition, because the condensate is stabilized to meet a Reid vapor
pressure (RVP) specification, the composition of this condensate does not
fluctuate appreciably. For these reasons, static emission factors for VOC
and HAP are appropriate for this stabilized condensate loadout. The HAP
emission factors are presented in the facility -wide HAP emission limitation
condition (discussed in Section VI below).
3. Monitoring Plan
123/0049 Page 90 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Condensate Throughput — Required monthly by summing the volume recorded
on all sales tickets from that month. This is used to determine compliance with
the VOC and facility -wide HAP limits
4 Compliance Status
According to the 6/2/2016 inspection, F029 is in compliance with all applicable
conditions in the previous revision of the operating permit.
J. F031 — Pressurized Liquids Loadout, AIRS ID: 133
1. Applicable Requirements
This operating permit condition addresses F031, permitted under the 5/1/2001
issuance of the operating permit. The following requirements have been retained
in the operating permit and modified as follows:
Condition 10.1 - VOC emissions shall not exceed the annual limitations set forth
in this permit
• Calculation methods for monthly emissions of VOC and HAP were added to this
condition, outlining the specific inputs required for compliance calculations
• Emission factors were updated to reflect the hose lengths identified on the APEN
and supporting information received 12/14/2018.
• Assumptions regarding the VOC and HAP content of the three species loaded
from the pressurized loadout point were identified as follows:
o Propane: 100% VOC, 0% HAP
o Butane: 100% VOC, 0% HAP
o Natural Gasoline: Requires gas chromatography (GC) analysis
Other Applicable Requirements
This section addresses applicable requirements to the pressurized liquids loadout
point that were not addressed in the 5/1/2001 issuance of the operating permit:
• Additional Monitoring
Propane, Butane and Natural Gasoline Throughput — Required monthly using all
sales tickets from that month to determine compliance with the VOC and facility -
wide HAP limits
GC Analysis for Natural Gasoline — Required to determine the quantity of VOC and
HAP in the natural gasoline to be used in the compliance determination calculation
for the VOC and facility -wide HAP limits
2. Emission Factors
123/0049 Page 91 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 950PWE055
Technical Review Document - Renewal Operating Permit
VOC Emissions of VOC from the pressurized loadout are a result of the liquids
that remain in the loading lines flashing to atmospheric pressure after the'fruck
has been disconnected. It is assumed that the entire volume of liquid held within
the loading line will volatilize upon exposure to atmospheric pressure.. The
following emission factors were developed based on the dimensions of the liquid
and vapor lines used during loading/unloading operations and the density of the
materials loaded:
Species
VOC Emission Factor for
Loading Operations
Propane
0.79 lb/load
Butane
0.90 lb/load
Natural Gasoline
1.15 lb/load
• HAP — It should be noted that neither propane nor butane are considered to be
a HAP. As such, all HAP emissions generated at the pressurized liquids loadout
point are from the loading of natural gasoline. In source comments received
11/2/2018, it was indicated that a gas chromatograph (GC) is used to determine
the composition of the natural gasoline. However, the gas chromatograph cannot
distinguish between individual HAP species, and instead reports an aggregated
"hexanes+" species. To be conservative, 100% of the hexanes+ component
reported in the GC analysis shall be assumed to be n -hexane. Because the HAP
content is directly measured from the natural gasoline loadout, this measurement
was utilized in lieu of an emission factor.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Propane, Butane and Natural Gasoline Throughput - Required monthly for each
species using all sales tickets from that month, used to determine compliance
with the VOC and facility -wide HAP limits
• Natural Gasoline Composition — Gas chromatograph required annually for years
when natural gasoline loading occurs. The composition indicated may be used
for all natural gasoline loading events occurring within one year of the analysis.
4 Compliance Status
According to the 6/2/2016 inspection, F031 is in compliance with all applicable
conditions in the previous revision of the operating permit. It should be noted,
however, that F031 did not operate during the 2015-2016 compliance period.
K. FLARE — Plant Emergency Flare, AIRS ID: 141
1. Applicable Requirements
123/0049
Page 92 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
This operating permit condition addresses the plant emergency flare, which was
incorporated into the operating permit pursuant to the significant modification requests
received on 9/11/2017 and 11/8/2018. It should be noted that these requests were
processed as a combined Construction Permit / Operating Permit. As such, no
construction permit was issued for this point — it is permitted solely via the operating
permit.
The applicable requirements for the flare are as follows:
• VOC Emission Limitations & Compliance Monitoring
o Emissions of VOC shall not exceed 17.2 tons/year.
o Emissions of VOC resulting from pilot gas combustion shall be determined
via calculation using the monthly pilot gas flowrate and the AP -42 Chapter
1.4 Natural Gas Combustion emission factors.
o Emissions of VOC resulting from purge and waste gas combustion shall
be determined via calculation using the monthly purge and waste gas
flowrates, molecular weights, VOC and HAP content (mass fraction) and
an assumed control efficiency of 95%.
o Total VOC emissions shall be the sum of the contributions from the pilot,
purge and waste gases. Monthly VOC emissions shall be used in a twelve
month rolling total to monitor compliance with the VOC limitations.
o HAP emissions shall not exceed the facility -wide emission limitations of 8
tons/year individual HAP and 22.9 tons/year total HAP. HAP emissions
shall be calculated in the same manner as the VOC emissions and shall
be used to demonstrate compliance with the facility -wide emission
limitations. Please refer to Section VI of this document for a more detailed
discussion regarding the facility -wide HAP limitations.
• NOx & CO Emission Limitations & Compliance Monitoring
o Emissions of NOx shall not exceed 3.6 tons/year. Emissions of CO shall
not exceed 15.9 tons/year.
o Emissions of NOx and CO resulting from pilot gas combustion shall be
determined via calculation using the monthly pilot gas flowrate and the
AP -42 Chapter 1.4 Natural Gas Combustion emission factors.
o Emissions of NOx and CO resulting from purge and waste gas combustion
shall be determined via calculation using the monthly purge and waste
gas flowrates, heat content and the AP -42 Chapter 13.5 Industrial Flares
emission factors.
o Total NOx and CO emissions shall be the sum of the contributions from
the pilot, purge and waste gases. Monthly NOx and CO emissions shall
be used in a 12 month rolling total to monitor compliance with the NOx
and CO limitations.
123/0049 Page 93 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Flare Gas Throughput Limitations & Compliance. Monitoring
o The amount of each gas stream sent to the plant emergency flare shall
not exceed the following limitations:
• Pilot Gas: 1.31 MMSCF/year
■ Purge/Waste Gas: 86.75 MMSCF/year
o The flowrate of each gas stream shall be determined monthly as follows:
■ The pilot gas throughput is a constant value of 150 SCFH. Monthly
throughput shall be determined by multiplying this static throughput
specification by the monthly hours of flare operation.
■ The purge gas and waste gas are measured with a single flare
header flowmeter, as these streams are comingled in the flare
header. As such, a combined limitation of purge and waste gas was
included in the operating permit. Monthly throughput for the purge
and waste gas shall be determined using the reading from this flare
header flowmeter.
• It should be noted that flare header meter sensitivity at low
flowrates may result in inaccurate measurement. As such,
during times when the flare header meter cannot detect a
minimum flowrate, a purge rate of 5,417 SCFH shall be
assumed, as requested in the source correspondence
received 12/14/2018.
The monthly throughputs of the pilot, purge and waste gases shall be used
in a twelve month rolling total to monitor compliance with the throughput
limitations.
• Extended Gas Analysis of Flare Gases
o An extended analysis of the inlet and residue gases shall be completed
annually to identify the relevant VOC and HAP constituents of the inlet
and residue gases. It should be noted that the pilot and purge gas is taken
directly from the residue gas stream and, as such, will have an identical
composition. The waste gas is assumed to be a mixture of the inlet and
residue gases.
• Hours of Operation — Hours of operation of the plant emergency flare shall be
monitored and recorded monthly. The hours of operation are used to monitor
compliance with the pilot and purge gas throughput limitations.
• Opacity
o Colorado Regulation No. 1, Section II.A.5 - No owner or operator of a
smokeless flare or other flare for the combustion of waste gases shall
allow or cause emissions into the atmosphere of any air pollutant which is
123/0049 Page 94 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
in excess of 30% opacity for a period or periods aggregating more than
six minutes in any sixty consecutive minutes
• Control Device Requirements
o . The plant emergency flare shall be operated at all times when emissions
are routed to it
o The flare shall be operated with the pilot present at all times. A flame
detector shall continuously monitor the presence of the pilot light. If the
presence of a flame cannot be detected, an auto -igniter shall
automatically re -light the pilot. The pilot light shall be monitored as follows:
■ Visual inspection of the pilot light shall be completed daily to verify
pilot light presence. A daily log with the results from the visual
inspection shall be maintained and made available to the Division
upon request.
■ Records of pilot light outage events and the duration of such events
shall be maintained and made available to the Division upon
request.
o EPA Method 22 observations shall be conducted daily to determine
whether visible emissions are present for a period of at least one (1)
minute in any fifteen (15) minute period of normal operation. The results
of the daily visual observations shall be kept on file and made available to
the Division upon request.
• Added monitoring requirement to conduct Method 9
observations in the event visual emissions are detected via
Method 22. The Method 9 observations were included as a
way to demonstrate compliance with the Colorado
Regulation No. 1 Section II.A.5 opacity standard. EPA
Method 9 observations shall be conducted by a certified
observer. If an opacity exceedance is observed, it shall be
considered to exist until another Method 9 reading is taken
which demonstrates compliance with the opacity standards
of Colorado Regulation No. 1, Section II.A.5.
• Initial Compliance Requirements
o Colorado Regulation No. 3, Part B, Section III.G.2 — Within one hundred
and eighty days (180) of the latter of commencement of operation or
issuance of this permit, compliance with the conditions contained in this
permit shall be demonstrated to the Division. The initial compliance
demonstration shall be submitted with the next required semi-annual
monitoring report.
o Colorado Regulation No. 3, Part B, Section III.E (State -Only
Enforceable) — The permit number and AIRS ID point number shall be
marked on the subject equipment for ease of identification.
123/0049 Page 95 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
o The operator shall complete an initial extended gas analysis of the inlet
and residue gas within one hundred and eighty days (180) after issuance
of this permit to verify the heat content and VOC and HAP components.
The volume from the flare meter, VOC content indicated by the extended
analysis, along with a 95% DRE, shall be used to demonstrate compliance
with the VOC emission limitations set forth in this permit. The heat content
and applicable AP -42 Section 1.4 and 13.5 emission factors shall be used
to demonstrate compliance with the NOx and CO emission limitations set
forth in this permit. The results of this extended gas analysis and
compliance calculation shall be submitted to the Division as part of the,
Self -Certification.
• Statewide Controls for Oil and Gas Operations
o Colorado Regulation No. 7 Section XVII.B
The plant emergency flare at the Roggen Natural Gas Processing Plant is
subject to the following general requirements of Colorado Regulation No.
7 Section XVII.B:
■ Section XVII.B.1.b (State -Only Enforceable) — The facility and air
pollution control equipment shall be operated at all times using
good air pollution control practices
• 40 CFR Part 60, Subpart A §60.18 NSPS
o The plant emergency flare is subject to the federal requirements set forth
in 40 CFR Part 60, Subpart A §60.18 "General Control Device and Work
Practice Requirements". The applicable requirements from §60.18 were
included in the operating permit as follows:
• (§60.18(c)(1) & §60.18(f)(1) - Smokeless operation verified by
Method 22
■ §60.18(c)(2) & §60.18(f)(2) — Continuous pilot light presence,
detected by a thermocouple or equivalent
■ §60.18(d) — Monitoring to ensure operational conformance with
intended design and use
• §60.18(e) — Continuous operation when emissions are routed to
the flare
Please note the following in regards to the permit modification application received
9/11/2017:
• Suggested conditions were provided based on a construction permit issued by the
Division for a separate DCP facility. All requested conditions were incorporated
EXCEPT for the following:
123/0049 Page 96 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
o Emission factors — Instead of developing a static emission factor, the source
will base their monthly calculations of NOx, CO, VOC and HAP emissions
off of the most recent extended gas analysis for the inlet and residue gases.
This method more accurately captures fluctuations in gas composition and
provides a more realistic emissions estimate
o Colorado Regulation No. 7, Section XII.C.1 and XVII.B.2.b These
conditions are required for air pollution control equipment used to comply
with Sections XII and XVII. The plant emergency flare is for use in
emergency and blowdown situations only, neither of which are subject to
control requirements set forth in Colorado Regulation No. 7. As such, these
conditions were not included in the operating permit. However, the general
facility -wide requirement to adhere to good air pollution control practices
(Colorado Regulation No. 7 Section XVII.B.1.b) was included in the
operating permit since the Roggen Natural Gas Processing Plant is a
regulated oil and gas facility under Colorado Regulation No. 7.
o Notice of Startup — The requirement to notify the Division within 15 days of
the startup of a new unit has been waived. Typically, this condition is
included for newly constructed sources. The plant emergency flare is an
existing piece of equipment that has operated since 2010 (per the APEN
received 9/11/2017). Therefore, a notice of startup is not necessary.
• Additional Requirements
It should be noted that the permit modification application received 9/11/2017 did
not request monitoring for the pilot gas. Pursuant to source comments received
11/2/2018, the pilot gas does not have a dedicated flowmeter. As such, the pilot
gas flowrate will be assumed to be the manufacturer specified value of 150 SCFH.
Requirements to calculate a monthly flowrate using this static value and the flare
hours of operation, and to perform an extended analysis on the residue gas, which
is equivalent in composition to the pilot gas, were included in the operating permit
since throughput limitations for the pilot gas was requested, and the NOx, CO and
VOC emission limitations include contributions from this source.
• The suggested O&M Plan submitted by DCP requires the following monitoring:
o Pilot light
• Operated with a flame detector to continuously monitor presence
• Equipped with an auto -igniter that, upon loss of flame, automatically
relights the pilot
• Presence is monitored daily by visual inspection
o Opacity
• Visually monitored daily
123/0049 Page 97 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Method 22 readings are taken consistent with 40 CFR Part 60
Subpart A §60.18
o Flare gas
• Metered at the inlet to the flare
All O&M plan conditions were incorporated into the operating permit as requested.
2. Emission Factors
Emission factors for this unit were established as follows:
• NOx & CO — Emissions of NOx and CO are generated from pilot gas, purge
gas and waste gas destruction. The emission factor used to calculate NOx and
CO emissions based off of the heat content of the waste and purge gas burned
was obtained from AP -42 Chapter 13, Section 13.5 for Industrial Flares, Table
13.5-1 and Table 13.5-2, respectively. Additionally, NOx and CO is generated
via pilot gas combustion. The governing emission factors for this method of
combustion were obtained from AP -42 Chapter 1, Section 1.4, Table 1.4-1.
• VOC and HAP — VOC and HAP emissions from pilot gas destruction were
calculated using the emission factor obtained from AP -42 Chapter 1, Section
1.4, Tables 1.4-2 and 1.4-3, respectively. Emission factors were not developed
for the calculation of VOC and HAP emissions resultant from purge and waste
gas destruction. Instead, VOC and HAP content (in wt%) is obtained from the
most recent extended analysis for the inlet and residue gases. The purge gas
is equivalent in composition to the residue gas, and the waste gas is a
combination of the inlet and residue gases. This VOC and HAP content is used
in conjunction with the purge and waste gas flowrates and heat contents (also
obtained from the most recent extended analysis) to obtain monthly actual
VOC and HAP emissions.
3. Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Flare Gas Throughput — The amount of pilot, purge and waste gases processed
by the plant emergency flare shall be determined as follows:
o The pilot gas throughput is a constant value of 150 SCFH. Monthly
throughput shall be determined by multiplying this static throughput by the
monthly hours of flare operation.
o The purge and waste gas is measured with a single flowmeter, as these
streams are comingled in the flare header. Monthly throughput shall be
determined from this metered rate.
• For periods during which the flare header meter cannot detect a
minimum flow, the full purge gas flowrate of 5,417 SCFH shall be
123/0049 Page 98 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating. Permit No. 95OPWE055
Technical Review Document Renewal Operating Permit
assumed, as requested in the source correspondence received
12/14/2018.
Extended Analysis of Flare Gas - Performed annually on the inlet gas and residue
gas streams to be used to determine compliance with NOx, CO, VOC and. HAP
emission limitations. The analysis should identify the VOC and HAP components.
This analysis is also used to determine the heat content of the inlet and residue
gas. The pilot and purge gases are derived from the residue gas and are
therefore equivalent in composition and heat content. The waste gas is assumed
to be a combination of the inlet and residue gases.
• Pilot Light — Presence verified via daily visual inspection
• Smoke — Method 22 observations required daily to ensure visible emissions are
not present at the flare. In the event visual emissions are observed, a Method 9
reading shall be performed by a certified observer to determine compliance with
the Colorado Regulation No. 1 Section II.A.5 opacity requirements.
4. Compliance Status
The plant emergency flare has never been a permitted point previous to this
operating permit issuance. As such, there is no compliance status to report.
L. Control Devices — Enclosed Combustion Device (ECD)
Regenerative Thermal Oxidizer (RTO)
1. Applicable Requirements
This operating permit condition addresses the enclosed combustion device (ECD) and
regenerative thermal oxidizer (RTO) used to control the dehydration units P033 and P-
136, and the amine sweetening unit P-137.
This condition was created specifically to address the overlapping requirements of the
ECD and RTO that would otherwise be duplicated in the dehydration unit and amine
sweetening unit conditions. Requirements specific to each control device from State
regulations, the construction permits 01WE0208 and 10WE1659 and the operation and
maintenance (O&M) plans for the dehydration units and amine sweetening unit were
addressed in this condition. NOx and CO limitations from each contributing unit, as well
as combustion emissions generated from pilot and burner gas destruction, were
reported in this control device condition to accurately reflect the total amount of NOx
and CO emissions generated at each control device. The combined NOx and CO
limitations for each control device are defined in the following table:
Control
Device
Source
Scenario Description
NOx
CO
tons/year
tons/year
ECD
P033 Still Vent
0% ECD Downtime
0.04
0.2
P-136 Still Vent
0% ECD Downtime
Emissions Routed to ECD Only
0.9
4.0
123/0049
Page 99 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Pilot Gas
0% ECD Downtime
0.05
0.05
Total
Controlled PTE
1.0
4.3
RTO
P-136 Still Vent
0% RTO Downtime
Emissions Routed to RTO Only
0.9
4.0
P-137 Acid Gas Vent
0% RTO Downtime
0.9
3.9
Burner Gas
0% RTO Downtime
2.1
1.8
Total
Controlled PTE
3.9
9.7
It should be noted that the NOx and CO emissions resultant from the combustion of the
pilot gas for the ECD were included in the APEN addendum for dehydration unit P033
received on 9/22/2017. As such, a pilot gas throughput limitation was included in the
operating permit, to be determined based on the manufacturer -specified hourly pilot gas
flowrate and ECD hours of operation.
The RTO is also equipped with a burner, which, similar to a traditional thermal oxidizer,
allows the RTO to achieve combustion using a flame (i.e., "burner mode"). Per
manufacturer literature, this burner is significantly oversized to maintain the combustion
chamber temperatures required for autoignition of the waste gases when only air is
flowing through the RTO. In source correspondence received 1/31/2018, it was
requested that the NOx and CO emissions resultant from burner mode operation be
included in the permit limitations for the amine sweetening unit. Therefore, the emission
limitations in the permit include both the NOx and CO resultant from combustion of the
amine sweetening unit P-137 acid gas vent (and, if routed to the RTO, the TEG
dehydration unit P-136 still vent), as well as the NOx and CO emissions from the
combustion of burner gases in burner mode. The permitted emissions for burner mode
were very conservatively based on year-round (8,760 hour) operation of the burner at
its full rated capacity of 5 MMBtu/hr.
As of the permit issuance date of XX/XX/XXXX, 10WE1659 has not yet obtained final
approval to operate due to an outstanding stack test for the regenerative thermal
oxidizer (RTO), which was permitted under 10WE1659. The outstanding initial
compliance requirements for this unit have been included within this control device
condition.
Calculation methods for monthly emissions of NOx and CO generated via pilot gas and
burner gas combustion were included in this condition, pursuant to AP -42 Chapter 1.4
Natural Gas Combustion. The methods to calculated NOx and CO emissions generated
by destructing still vent emissions from the dehydration units and acid gas vent
emissions from the amine sweetening unit were retained in the conditions specifically
addressing these units. A reference to these methods was inserted in this control device
condition. Compliance with the NOx and CO limitations for the ECD shall be determined
123/0049 Page 100 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
based on the sum of actual NOx and CO emissions generated from the combustion of
the pilot gas and still vents from the dehydration units P033 and, when routed to the
ECD, P-136. Compliance with the NOx and CO limitations for the RTO shall be
determined based on the sum of actual NOx and CO emissions generated from the
combustion of the burner gas and acid gas vent from the amine sweetening unit P-137,
and, when routed to the RTO, the still vent from dehydration unit P-136.
Other Applicable Requirements
This section addresses applicable requirements to the ECD and RTO that were not
explicitly defined in Colorado Construction Permit 01WE0208 or 10WE1659, but were
included in the operating permit.
• Additional Monitoring
o Pilot Gas NOx and CO (ECD only) — The pilot gas required for ECD
operation produces both NOx and CO. Emissions of these pollutants are
calculated using the pilot gas flowrate and the AP -42 Chapter 1.4
emission factors for natural gas combustion.
o Burner Gas NOx and CO (RTO only) — The burner gas that intermittently
assists RTO operation produces both NOx and CO. Emissions of these
pollutants are calculated using the burner gas flowrate and the AP -42
Chapter 1.4 emission factors for natural gas combustion.
o Burner Gas Extended Gas Analysis — An extended analysis of the residue
gas shall be completed annually to determine the heat content of the
residue gas.
o Hours of Operation — Hours of operation of the ECD and RTO shall be
monitored and recorded monthly. The hours of operation are used to
monitor compliance with the pilot gas throughput limitation for the ECD
and the burner gas throughput limitation for the RTO.
o Enclosed Combustion Device Operation —The Enclosed Combustion
Device (ECD):
■ Shall be operated at all times when emissions are routed to it
■ Shall have a pilot light present at all times, verified by thermocouple
signal or, if the thermocouple is malfunctioning, daily visual
inspection (O&M Plan submitted 11/13/2017).
■ Shall be inspected daily to ensure pilot gas and P033/P-136
dehydration unit still vent valving is appropriately configured to
ensure destruction of emissions.
■ Shall undergo daily Method 22 observations to detect visible
emissions (O&M Plan submitted 11/13/2017; also required by
Colorado Construction Permit 10WE1659)
123/0049 Page 101 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• Added monitoring requirement to conduct Method 9
observations in the event visual emissions are detected via
Method 22. The Method 9 observations were included as a
way to demonstrate compliance with the Colorado
Regulation No. 1 Section II.A.5 opacity standards. EPA
Method 9 observations shall be conducted by a certified
observer. If an opacity exceedance is observed, it shall be
considered to exist until another Method 9 reading is taken
which demonstrates compliance with the opacity standards
of Colorado Regulation No. 1, Section II.A.5.
o Regenerative Thermal Oxidizer Operation — The Regenerative Thermal
Oxidizer (RTO):
• Shall be operated at all times when emissions are routed to it
• Shall maintain a minimum operating combustion chamber
temperature of 1450°F.
• Shall be inspected daily to ensure dehydration unit P-136 and
amine sweetening unit P-137 still vent valving is appropriately
configured to ensure destruction of emissions.
• Shall undergo daily Method 22 observations to detect visible
emissions (O&M Plan submitted 11/13/2017; also required by
Colorado Construction Permit 10WE1659)
• Added monitoring requirement to conduct Method 9
observations in the event visual emissions are detected via
Method 22. The Method 9 observations were included as a
way to demonstrate compliance with the Colorado
Regulation No. 1 Section II.A.1 & 4 opacity standards. EPA
Method 9 observations shall be conducted by a certified
observer. If an opacity exceedance is observed, it shall be
considered to exist until another Method 9 reading is taken
which demonstrates compliance with the opacity standards
of Colorado Regulation No. 1, Section II.A.1 & 4.
• State Requirements
o Colorado Regulation No. 7 Section XII
The ECD and RTO at the Roggen Natural Gas Processing Plant operate
in a non -attainment area and as such, are subject to the following
applicable requirements of Colorado Regulation No. 7 Section XII as
noted:
• Section XII.C.1.a — General Requirements — All emission control
equipment shall be operated and maintained consistent with
manufacturer specifications and good engineering and
maintenance practices
123/0049 Page 102 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• This requirement is applicable to the ECD at all times and
the RTO only if P-136 is routed to it. Section XII is only
applicable to control devices being used to comply with
Section XII requirements. Section XII does not regulate
amine sweetening units. In the event that the RTO is only
being used to control the amine sweetening unit, this
requirement shall not apply.
Colorado Regulation No. 7 Section XVII
The ECD and RTO at the Roggen Natural Gas Processing Plant are
subject to the following applicable requirements of Colorado Regulation
No. 7 Section XVII as noted:
■ Section XVII.B.1.b (State -Only Enforceable) — The facility and air
pollution control equipment shall be operated at all times using
good air pollution control practices
• This requirement is applicable to the operation of the ECD
and RTO at all times. Section XVII.B.1 applies to "all oil and
gas exploration and production operations, well production
facilities, natural gas compressor stations, and natural gas
processing plants". Roggen is considered to be a natural
gas processing plant and, therefore, this section is
applicable to all control devices at the facility.
■ Section XVII.B.2.a & b (State -Only Enforceable) —All air pollution
control equipment shall be maintained according to good air
pollution control practices and manufacturing specifications. Each
combustion device shall be enclosed, have no visual emissions
and must be equipped with an auto -igniter.
• This requirement is applicable to the ECD at all times and
the RTO only if P-136 is routed to it. Section XVII.B.2 is
only applicable to control devices being used to comply with
Section XVII requirements. Section XVII does not regulate
amine sweetening units. In the event that the RTO is only
being used to control the amine sweetening unit, this
requirement shall not apply.
2. Emission Factors
Emission factors for these control devices were established as follows:
• NOx and CO — Emissions of NOx and CO are generated from the destruction
of still vent emissions in either the RTO or ECD. The emission factor used to
calculate NOx and CO was obtained from AP -42 Chapter 13, Section 13.5 for
Industrial Flares, Table 13.5-1 and Table 13.5-2, respectively. These emission
factors are used in conjunction with the still vent gas flowrates and heat
contents from the dehydration units P033 and P-136 and the amine
123/0049 Page 103 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
sweetening unit P-137 to calculate monthly emissions of NOx and CO.
Additionally, NOx and CO is generated via pilot gas combustion for the ECD
and burner combustion for the RTO. The governing emission factors for this
method of combustion were obtained from AP -42 Chapter 1, Section 1.4,
Table 1.4-1.
Monitoring Plan
The following parameters shall be monitored at the prescribed frequency to ensure
compliance with the annual limitations set forth in the permit:
• Pilot Gas Throughput (ECD only) — Calculated monthly using the manufacturer
specified throughput of 50 SCFH and the monthly hours of ECD operation; used
to determine compliance with the NOx and CO emission limitations
• Burner Gas Throughput (RTO only) — Calculated monthly using the manufacturer
specified burner rating of 5 MMBtu/hr, the heat content of the burner gas and the
monthly hours of RTO operation; used to determine compliance with the NOx
and CO emission limitations
• Extended Analysis Burner Gas - Performed annually on the residue gas stream
to be used to determine the heat content of the burner gas for the RTO to monitor
compliance with the burner throughput limitation. The burner gas is derived from
the residue gas and is therefore equivalent in heat content.
• RTO Combustion Chamber Temperature — Monitored daily to ensure proper
combustion
• Pilot Light for ECD — Monitored daily to ensure presence during operation
• Auto -igniter — Verification of functionality daily to ensure proper operation
• Piping to RTO and ECD — Verification of routing of emissions from each
dehydration unit to the operating emission control device
• Smoke for RTO and ECD — Method 22 observations required daily to ensure
visible emissions are not present at either the RTO or ECD. In the event visual
emissions are observed, a Method 9 reading shall be performed by a certified
observer to determine compliance with the Colorado Regulation No. 1 Section
II.A.5 opacity requirement for the ECD and Section II.A.1 and 4 opacity
requirements for the. RTO.
4. Initial Testing Requirements (RTO only)
The initial compliance testing requirements relevant to the verification of
regenerative thermal oxidizer (RTO) operation set forth in Colorado Construction
Permit 10WE1659 have been retained in the operating permit. Initial compliance
testing was first performed on this RTO 12/20/2011. However, the RTO failed to
achieve the 99% destruction efficiency necessary to comply with the VOC
emission limits set forth in 10WE1659. The destruction efficiency of this unit was
revised to 97% in a subsequent modification to 10WE1659. The second initial
123/0049 Page 104 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
compliance testing was completed on 3/12/2013. This time, the required
destruction efficiency was achieved and the stack test demonstrated compliance
with the VOC limitations of 10WE1659. However, this same stack test
demonstrated non-compliance with the SO2 limit for the amine sweetening unit, set
forth in 10WE1659. As such, a third initial compliance stack test is required.
However, the amine sweetening unit has not been in operation since 5/8/2013.
Since the RTO is only operational if the amine sweetening unit is routed to it, the
RTO has also not been operated since 5/8/2013. As such, there has not been an
opportunity to perform the initial compliance testing required in 10WE1659.
Therefore, the applicable requirements for initial compliance testing related to the
RTO have been included in the operating permit as follows:
• The owner or operator shall demonstrate compliance with opacity standards
using EPA Method 22 to determine the presence or absence of visible emissions.
"Visible Emissions" means observations of smoke for any period or periods of
duration greater than or equal to one (1) minute in any fifteen (15) minute period
during normal operation (Colorado Construction Permit 10WE1659 Condition 34)
• A source initial compliance test shall be conducted on the combined emission
streams being routed to the RTO to measure the emission rate(s) for the
pollutants listed below in order to demonstrate compliance with the emissions
limits contained in this permit. The test shall include inlet and outlet testing for
VOC in order to demonstrate compliance with the minimum destruction efficiency
of 97% for the RTO in addition to outlet testing for sulfur dioxide. Any compliance
test conducted to show compliance with a monthly or annual emission limitation
shall have the results projected up to the monthly or annual averaging time by
multiplying the test results by the allowable number of operating hours for that
averaging time (Colorado Construction Permit 10WE1659 Condition 35) .
o This condition was expanded upon to require the following:
• The performance test must be conducted at the permitted minimum
combustion chamber temperature of 1450°F. This requirement
ensures that at this minimum temperature, which should
theoretically yield the lowest destruction efficiency, the required
destruction efficiency of 97% can be achieved.
■ The following parameters shall be recorded during the performance
testing and shall be reported to the Division. These parameters are
necessary to ensure that the stack test was completed during
representative unit operations and is therefore a reasonable
indicator of compliance during normal operations:
• For Dehydration Unit P-136: Inlet wet gas throughput, lean
glycol circulation rate, inlet temperature, inlet pressure, flash
tank operating temperature and flash tank operating
pressure
• For Amine Sweetening Unit P-137: Inlet sour gas
throughput, lean amine circulation rate, inlet temperature,
123/0049 Page 105 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
inlet pressure, flash tank operating temperature and flash
tank operating pressure
• For RTO: Combustion chamber temperature, supplemental
fuel throughput and burner throughput
• Within one hundred eighty (180) days after startup of the RTO, compliance with
the conditions contained in this section shall be demonstrated to the Division.
The operator shall complete all initial compliance testing and sampling as
required in this condition and submit the results to the Division (Colorado
Construction Permit 10WE1659, Conditions 1 and 3).
o This condition was modified slightly to specify that the initial testing results
shall be submitted with the next required semi-annual monitoring report
required by the operating permit.
5. Compliance Status
According to the 6/2/2016 inspection, the control devices were in compliance with
the requirements of Construction Permits 01 WE0208 and 1 0WE1659 EXCEPT as
follows:
• Opacity: The ECD used to control emissions from P033 and P-136 had an
observed opacity of greater than 30% for 23 minutes during the compliance
period
This violation has been addressed within the Division's enforcement group and no
separate compliance schedule/plan is required for the purposes of the Title V
Operating Permit.
M. Kohler Model CV15S Methanol Pump
1. Applicable Requirements
This operating permit condition addresses the Kohler Model CV15S Methanol Pump,
used for hydrate inhibition.
Although this engine meets insignificant activity criterion of Colorado Regulation No. 3,
Part C, Section II.E.3.nnn.(iii) by having "uncontrolled actual emissions less than five
tons per year or manufacturer's site -rated horsepower of less than fifty', it cannot be
considered to be an insignificant activity pursuant to Section II.E., which prohibits such
exemptions from being taken if a federal or state rule would be avoided by taking that
exemption. This engine is an existing SI 4SRB engine located at an area source of
HAP emissions, and is therefore subject to 40 CFR 63 Subpart ZZZZ. Because this
engine is subject to requirements in a federal rule, the insignificant activity exemption
cannot be taken. As such, the applicable MACT ZZZZ requirements were incorporated
into the body of the operating permit for this engine, as discussed below. It should be
noted that this engine is exempt from the APEN reporting requirements of Colorado
Regulation No. 3, Part A, Section II.D.1.a, as it has uncontrolled actual emissions of
less than 1 ton/year VOC and NOx (2 tons/year CO).
123/0049 Page 106 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
State Requirements
o Colorado Regulation No. 1, Section II.A.1 and II.A.4 Opacity
This engine shall not emit in excess of 20% opacity, except for certain
operational activities, where 30% opacity is permitted. Compliance with
this condition shall be monitored by performing an annual Method 9
observation.
• Federal Requirements
o_ 40 CFR 63 Subpart ZZZZ
For applicability purposes of Subpart ZZZZ, this engine is considered to
be an existing, non -emergency, non -black start 4 -stroke rich burn
stationary RICE ≤ 500 hp located at an area source of HAP emissions. As
such, this engine is required to comply with work practice, maintenance
and recordkeeping requirements only.
2. Emission Factors
As noted above, this engine produces actual uncontrolled emissions below the
APEN reporting thresholds set forth in Colorado Regulation No. 3, Part A. As such,
this engine is considered to be APEN-exempt and has no associated limitations.
3. Monitoring Plan
• Smoke — Method 9 observations required annually by a certified observer to
monitor compliance with the Colorado Regulation No. 1 Section II.A.1 and 4
opacity requirements.
4. Compliance Status
This engine was not included in a permit previous to this XX/XX/X)O( issuance,
and, as such, there is no compliance status to report.
VI. FACILITY -WIDE HAZARDOUS AIR POLLUTANT LIMITATIONS
A separate condition was added within Section II of the operating permit to address the
synthetic minor HAP limits required for the Roggen Natural Gas Processing Plant,
pursuant to Colorado Construction Permits 01WE0208, 07WE0988, 10WE1659,
12WE1193 and 12WE1242. The applicable conditions from each of these construction
permits have been incorporated into the operating permit as described above in the
Construction Permit section of this document.
Calculation methods for monthly emissions of HAP were included in the operating
permit. For those points which the calculation methods of VOC and HAP were identical,
the HAP calculation methodology was included in the point -specific condition,
referencing the HAP condition for determining compliance with the annual limitations.
For points requiring a different calculation than what was contained in the point -specific
123/0049 Page 107 of 132
DCP Operating Company, LP - Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
condition, the appropriate calculation methodology was included in the HAP condition.
These calculation methods are outlined as follows:
• Reciprocating Internal Combustion Engines — C-154, 155, 159, 157, 161, 158,
160, 156, 223, 225, 227, 181 and 192
o Method: Monthly emissions of each HAP are calculated using the
emission factors and control efficiencies described below, the monthly
natural gas consumption for the engine and the heat content of the natural
gas fueling the engine
o Emission Factors: The emission factors set forth in AP -42 Chapter 3,
Section 3.2, Table 3.2-3 were used to calculate the uncontrolled
emissions of each species of HAP typically produced via internal
combustion. It should be noted that these factors is only applicable to 4 -
Stroke Rich Burn Reciprocating Internal Combustion Engines. Each
engine at the Roggen Natural Gas Processing Plant are of this
configuration and therefore, these emission factors are applicable to all
engines at Roggen.
o Control Efficiencies: The control efficiencies assumed to be achieved by
Non -Selective Catalytic Reduction (NSCR) systems are as follows:
Hazardous Air Pollutant
Control Efficiency
Formaldehyde
76%
Other HAP
50%
These emission factors were applied to the uncontrolled HAP emissions
to determine actual HAP emissions from each engine. Please note that
the control efficiency for formaldehyde is congruous with the efficiency
required by MACT ZZZZ.
Process Heaters H037 and P-138
o Method: Monthly emissions of each HAP are calculated using the
emission factors described below and the monthly natural gas
consumption for the heater.
o Emission Factors: The emission factors set forth in AP -42 Chapter 1,
Section 1.4, Table 1.4-3 were used to calculate the uncontrolled
emissions of each species of HAP typically produced via natural gas
combustion.
• Stabilized Condensate Storage Tanks
o Method: Monthly emissions of each HAP are calculated using the
emission factors described below and the monthly condensate
throughput.
o Emission Factors: The emission factors used in the operating permit were
derived from EPA TANKS 4.0.9d and a stabilized condensate sample
123/0049 Page 108 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
from 5/26/2011 (as set forth in Colorado Construction Permit 12WE1242).
These factors are summarized in the following table:
Hazardous Air Pollutant
Emission Factor (lb/bbl)
n -Hexane
0.0010
Benzene
0.0002
Toluene
0.0005
Ethylbenzene
0.0001
Xylene
0.0004
• Stabilized Condensate Truck Loading
o Method: Monthly emissions of each HAP are calculated using the
emission factors described below and the monthly condensate
throughput.
o Emission Factors: The emission factors used in the operating permit were
derived from and EPA TANKS 4.0.9d analysis included in the 4/2/2007
permit modification application and a stabilized condensate sample from
5/26/2011. These factors are summarized in the following table:
Hazardous Air Pollutant
Emission Factor (lb/1,000 gal)
n -Hexane
0.51
Benzene
0.08
Toluene
0.23
Ethylbenzene
0.03
Xylene
0.18
• Pilot Gas for Plant Emergency Flare
o Method: Monthly emissions of each HAP are calculated using the
emission factors described below and the monthly pilot gas throughput to
the Plant Emergency Flare. To determine total HAP emissions from the
Plant Emergency Flare, the pilot gas HAP emissions are added to the
waste and purge gas HAP emissions, calculated using the same
methodology for VOC emission calculations. Calculations for the purge
and waste gas emissions were therefore retained in the Plant Emergency
Flare condition (see Section V.K of this document).
o Emission Factors: The emission factors set forth in AP -42 Chapter 1,
Section 1.4, Table 1.4-3 were used to calculate the uncontrolled
emissions of each species of HAP typically produced via natural gas
combustion.
To determine compliance with the facility -wide emission limitations for individual HAP,
emissions from each point were totaled for all points emitting that HAP. Compliance with
123/0049 Page 109 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
the facility -wide emission limitations for total HAP were determined by summing all HAP
species from all points from which HAP is emitted.
It should be noted that with the permit modifications received 7/10/2017 and 11/13/2017,
total HAP was calculated to be greater than the 20 ton/year permit limit applicable to
synthetic minor sources of HAP. Once HAP emissions exceed this value, it is the
Division's standard practice to require insignificant activity monitoring to ensure the
source retains its synthetic minor status and does not exceed the major source
threshold of 10 tons/year individual HAP and 25 tons/year total HAP. Insignificant
activity monitoring was therefore included in the operating permit.
VII. STATEWIDE CONTROLS FOR OIL AND GAS OPERATIONS - COMPRESSORS
A separate condition was included to address the compressor requirements set forth in
Colorado Regulation No. 7, Section XII.J (effective 12/30/2017), and the required
associated general requirements of Section XII.C.1.c, d, and e. All compressors at the
Roggen Natural Gas Processing Plant are reciprocating compressors. The following
requirements specific to reciprocating compressors have therefore been included in the
operating permit:
• General Requirements
o Section XII.C.1.c — Requirement for control devices used to comply with
the compressor emissions of Section XII.J to achieve a 95% control
efficiency
■ It should be noted that although Section XII.J.2 for reciprocating
compressors does not explicitly require the use of a control device
to achieve compliance, the applicability requirements Section
XII.A.6 mandate that Section XII.C.1.c be complied with for
reciprocating compressors. As such, this condition was included in
the operating permit.
o Section XII.C:1.d — Requirement for combustion devices used to comply
with Section XII.J to be enclosed and have no visible emissions
• It should be noted that although Section XII.J.2 for reciprocating
compressors does not explicitly require the use of a control device
to achieve compliance, the applicability requirements Section
XII.A.6 mandate that Section XII.C.1.d be complied with for
reciprocating compressors. As such, this condition was included in
the operating permit.
o Section XII.C.1.e — Requirement for combustion devices used to comply
with Section XII.J to operate with an autoigniter
• It should be noted that although Section XII.J.2 for reciprocating
compressors does not explicitly require the use of a control device
to achieve compliance, the applicability requirements Section
XII.A.6 mandate that Section XII.C.1.e be complied with for
123/0049 Page 110 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
reciprocating compressors. As such, this condition was included in
the operating permit.
• Control Requirements
o Section XII.J.2.a — Beginning 1/1/2018, the rod packing on reciprocating
compressors at natural gas processing plants shall be replaced every
26,000 hours of operation, or every 36 monaths (whichever comes first)
■ Gas plants shall begin monitoring hours of operation on 1/1/2018
and shall complete the first packing replacement no later than
1/1/2021
o Section XII.J.2.b — As an alternative to the rod packing replacement, rod
packing emissions may be routed back to process via a closed vent
system operating under negative pressure. The packing system shall be
inspected annually for defects and use EPA Method 21 to verify VOC
leakages are less than 500 ppm. If a leak in excess of this threshold is
detected, it shall be repaired unless technically infeasible or unsafe
o Section XII.J.2.c — Records shall be kept of the reciprocating compressor
identity, hours of operation/number of months since last packing
replacement, date of packing replacement or installation of closed vent
system, each inspection resulting in responsive actions and a list of each
delay of repair or inspection
o Section XII.J.2.d — Option to comply with the LDAR requirements of
Section XII.L in lieu of the inspection, repair and recordkeeping provisions
of Sections XII.J.2.b and c
o Section XII.J.2.e — Option to comply with a federal NSPS in lieu of the
entire Section XII.J.2
VIII. INSIGNIFICANT ACTIVITIES
The following list of insignificant activities was provided by the source in the permit
modification application received 11/8/2018 to assist in the understanding of the facility
layout. The insignificant activities are categorized below pursuant to the applicable
exemption:
Colorado Regulation No. 3, Part C, Section II.E.3.a: Individual emission points in
nonattainment areas having uncontrolled actual emissions. of any criteria pollutant (as
defined in Section I.B.17. of Part A of this Regulation Number 3) of less than one ton per
year
• One (1) Tank Combustor Pilot Emissions
• One (1) C-154 Maintenance Blowdown Vent
• One (1) C-155 Maintenance Blowdown Vent
• One (1) C-156 Maintenance Blowdown Vent
• One (1) C-157 Maintenance Blowdown Vent
• One (1) C-158 Maintenance Blowdown Vent
123/0049 Page 111 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• One (1) C-159 Maintenance Blowdown Vent
• One (1) C-160 Maintenance Blowdown Vent
• One (1) C-161 Maintenance Blowdown Vent
• One (1) C-181 Maintenance Blowdown Vent
• One (1) C-223 Maintenance Blowdown Vent
• One (1) C-225 Maintenance Blowdown Vent
• One (1) C-22; Maintenance Blowdown Vent
• One (1) C-192 Maintenance Blowdown Vent
• Atmospheric Blowdowns
• One (1) 500 gal Kerosene Tank
• One (1) 500 gal Diesel Tank
• One (1) 500 gal Dyed Diesel Tank
• One (1) 80 bbl Wastewater Tank (Sump 8)
• One (1) 80 bbl Stormwater Tank (Sump 5)
• Two (2) 80 bbl Slop Oil Tanks (Sump 5 & 9)
• Two (2) 10 bbl Slop Oil Tanks (Sump 7 & 10)
• One (1) 210 bbl Slop Oil Tank (Sump 12)
• One (1) 30 bbl Slop Oil Tank (Sump 4)
• One (1) 220 gal Slop Oil Tank/Air Compressor Sump
• Three (3) 1,000 gal Norkool Tanks (AST 7, 8 & 19)
• One (1) 100 gal Portable Methanol Tank
• One (1) 500 gal Methanol Tank (Randel)
• One (1) 500 gal Methanol Tank (Petro Frac)
• One (1) 500 gal Methanol Tank (212)
• One (1) 500 gal Methanol Tank (CIG)
• Two (2) 1,000 gal Methanol Tanks (AST 9 & 20)
• One (1) 4,000 gal TEG Tank (Tank 7210)
• One (1) 500 gal TEG Tank (AST 28)
• Two (2) 80,000 gal Pressurized Butane Storage Tanks
• One (1) 18,000 gal Pressurized Methanol Storage Tank
• One (1) 300 gal Unleaded Gasoline Tank
NOTE: It should be noted that Colorado Regulation No. 7, Section XVII.C.1.b.
requires control devices for storage tanks with uncontrolled actual emissions of
VOC greater than or equal to 6 tons/year. Pursuant to the insignificant activities
summary provided with the 11/8/2018 significant modification application, all listed
storage tanks in aggregate produce VOC emissions of 0.22 tons/year. At the time
of permit issuance on XX/XX/XXX, these tanks are not subject to the
requirements of Colorado Regulation No. 7, Section XVII.C.1.b.
NOTE: It should be noted that in the insignificant activities list provided in the
11/8/2018 permit modification application that the pilot emissions from the
dehydration unit were listed as an insignificant activity. These emissions are
accounted for in the control device requirements (Condition 12) of the operating
permit. Because these emissions are accounted for within the operating permit,
these emissions are not required to be tracked separately as an insignificant
123/0049 Page 112 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
activity. As such, the pilot emissions from the dehydration unit combustor were
removed from the insignificant activities list.
Colorado Regulation No. 3, Part C, Section II.E.3.k: Each individual piece of fuel
burning equipment, other than smokehouse generators and internal combustion
engines, that uses gaseous fuel, and that has a design rate less than or equal to five
million British thermal units per hour.
• One (1) 2.5 MMBtu/hr Broach Regen Heater
• One (1) 0.038 MMBtu/hr Hot Water Heater
Colorado Regulation No. 3, Part C, Section II.E.3.uu: Oil production wastewater
(produced water tanks), containing less than one percent by volume annual average
crude oil, except for commercial facilities that accept oil production wastewater for
processing.
• Five (5) 80 bbl Produced Water Tanks (Sump 1, 2, 6, 14 and Tank 7213)
• Two (2) 200 bbl Produced Water Tanks (Tank 7209 & 7214)
Colorado Regulation No. 3, Part C, Section II.E.3.zz: Storage of butane, propane, or
liquefied petroleum gas in a vessel with a capacity of less than sixty thousand gallons,
provided the requirements of Regulation Number 7, Section IV. are met, where
applicable.
• Four (4) 30,000 gal Pressurized NGL Storage Tanks
• One (1) 30,000 gal Pressurized Propane Storage Tank
Colorado Regulation No. 3, Part C, Section II.E.3.aaa: Storage tanks of capacity less
than forty thousand gallons of lubricating oils or waste lubricating oils.
• One (1) 500 gal Scavenger Tank (AST -27)
• One (1) 240 bbl Lube Oil Tank (805 Central)
• One (1) 6,000 gal Lube Oil Tank (805 West)
• One (1) 500 gal Lube Oil Tank (AST -24)
• One (1) 500 gal Portable Used Oil Tank
• Three (3) 225 gal Used Oil Tanks (#1, #2 & #3)
• One (1) 110 bbl Used Oil Tank (AST -13)
Colorado Regulation No. 3, Part C, Section II.E.3.ggg: Each individual piece of fuel
burning equipment that uses gaseous fuel, and that has a design rate less than or equal
to ten million British thermal units per hour, and that is used solely for heating buildings
for personal comfort.
• Two (2) 0.115 MMBtu/hr Office Heaters
• One (1) 0.02 MMBtu/hr Shop Heater
• One (1) 385,000 Btu/hr Hotsy Heater
• One (1) 12,000 Btu/hr Catco Heater (CIG Meter Shed)
• One (1) 12,000 Btu/hr Catco Heater (Excel Meter Shed)
• One (1) 12,000 Btu/hr CataDyne Heater (Box Elder Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (Bypass Gas Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (North Inlet Meter Shed)
123/0049 Page 113 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document - Renewal Operating Permit
• One (1) 6,000 Btu/hr CataDyne Heater (South Inlet Meter Shed)
• One (1) 6,000 Btu/hr CataDyne Heater (Low Pressure Inlet Meter Shed)
Colorado Regulation No. 3, Part C, Section II.E.3.nnn (iii): Stationary Internal
Combustion Engines that have uncontrolled actual emissions less than five tons per year
or manufacturer's site -rated horsepower of less than fifty.
• One (1) 16 hp Briggs & Stratton Vangaurde Hotsy Pump
NOTE: In source correspondence received 12/14/2018, it was indicated that the
16 hp natural gas fired Hotsy pump driver engine is considered to be a non -road
engine, as it never on -site for more than one continuous year and is considered
to be portable and transferrable, pursuant to the non -road engine definition set
forth in 40 CFR 1068.30. As such, the engine driving this pump is not subject to
the stationary source requirements of MACT ZZZZ or NSPS JJJJ. Although the
insignificant activity list provided in Colorado Regulation No. 3, Part C, Section
II.E.3 is meant to apply to stationary sources only, the Hotsy pump was retained
in the insignificant list in the operating permit to indicate that this pump is allowed
to be on -site and is not regulated under any federal or state rule applicable to
owners or operators of such equipment.
IX. ALTERNATIVE OPERATING SCENARIOS (AOS)
The most current version (ver. 10/12/2012, updated to reflect citations) of the Division's
standard language for temporary and permanent replacements under the Alternative
Operating Scenario provision was included in the operating permit. Additionally, an
example of the required AOS applicability report was included in Appendix G.
It should be noted that this facility is a major source for the purposes of NANSR and
PSD. Permanent replacement of engines under AOS provisions is not allowed unless
the replaced units have emission limits or potential to emit (PTE) below the significance
thresholds of NANSR (40 tons/year VOC and NOx only) and PSD (40 tons/year any
regulated NSR pollutant).
X. PERMIT SHIELD
The source requested a permit shield for multiple regulations in the renewal application
submitted on 4/29/2005. Each request was reviewed and the shield was either granted
or denied pursuant to the reasoning outlined in this section.
• The following requests for permit shield were granted pursuant to the justification
given:
o Colorado Regulation No. 1 Section III.A.1.b — for engines only
• Colorado Regulation No. 1 Section III.A.1.b sets the particulate
matter standards for fuel burning equipment. Engines, pursuant to
the Colorado Common Provisions Regulation, are not considered
fuel burning equipment and are therefore not subject to the
Colorado Regulation No. 1 PM standards. As such, the permit
123/0049 Page 114 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
shield for these requirements for the engines only has been
granted.
o Colorado Regulation No. 7 Section VI.B.1 — Storage of Petroleum
Distillates
• The Roggen Natural Gas Processing Plant is not subject to any
part of Colorado Regulation No. 7 Section VI, as these
requirements were not intended to apply to liquids stored at gas
processing plants (see discussion in Applicable Requirements
Section III of this document). Therefore, the permit shield has been
granted for this section.
o Colorado Regulation No. 7 Section VI.B.2 — Storage of Petroleum
Distillates
• The Roggen Natural Gas Processing Plant is not subject to any
part of Colorado Regulation No. 7 Section VI, as these
requirements were not intended to apply to liquids stored at gas
processing plants (see discussion in Applicable Requirements
Section III of this document). Therefore, the permit shield has been
granted for this section.
o Colorado Regulation No. 7 Section VII.C — Crude Oil Storage
■ This requirement subjects crude oil storage tanks in excess of
40,000 gallons to comply with selected requirements from
Colorado Regulation No. 7, Section VI. The Roggen Natural Gas
Processing Plant is not subject to any part of Colorado Regulation
No. 7 Section VI, as these requirements were not intended to apply
to liquids stored at gas processing plants (see discussion in
Applicable Requirements Section III of this document). Therefore,
the permit shield has been granted for this section.
• The following requests for permit shield were denied pursuant to the justification
given:
o Colorado Regulation No. 1 Section VI.B.5.a — for engines only
• These requirements set forth the SO2 emission limitations for "any
new source of sulfur dioxide not specifically regulated above".
Engines are not "regulated above" in Colorado Regulation No. 1
Section VI. While engines are not considered fuel burning
equipment for the purposes of the Colorado Regulation No. 1
particulate matter standard (see above), the SO2 requirements in
Colorado Regulation No. 1 are applicable to new and existing S02 -
emitting equipment, regardless of whether or not that equipment is
classified as "fuel burning" under the Common Provisions
Regulation. Therefore, since these engines could be subject to this
SO2 limitation, the permit shield was not granted.
123/0049 Page 115 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
It should be noted, however, that the engines at the Roggen
Natural Gas Processing Plant are natural gas fired. As such,
emissions of SO2 are significantly below the 2 tons/day
requirement in Colorado Regulation No. 1 Section VI.B.5.a.
Because it is highly unlikely that these engines will operate
anywhere near this 2 tons/day limitation, this requirement was not
included in the operating permit.
o Colorado Regulation No. 3 Section B.IV.D.2 — Non -Attainment area
requirements
It should be noted that the condition number referenced for this
permit shield request has been updated to Colorado Regulation
No. 3 Part D. This source is currently operating in a non -attainment
area and is classified as a major stationary source for the purposes
of NANSR. Because a future modification to this source could
trigger NANSR review, the source may become subject to the
NANSR requirements of this section. Therefore, the permit shield
was not granted for this regulation.
o Colorado Regulation No. 3 Section B.IV.D.3 — PSD Review Requirements
■ It should be noted that the condition number referenced for this
permit shield request has been updated to Colorado Regulation
No. 3 Part D. This source is classified as a major stationary source
for the purposes of PSD. Because a future modification to this
source could trigger PSD review, the source may become subject
to the PSD requirements of this section. Therefore, the permit
shield was not granted for this regulation.
o Colorado Regulation No. 3 Section B.X — Air quality modeling
■ It should be noted that the condition number referenced for this
permit shield request no longer exists in the current form of the
regulation. However, a future modification to this source may
trigger the modeling requirements set forth in Colorado Regulation
No. 3. Therefore, the permit shield was not granted.
o Colorado Regulation No. 3 Section B.XI — Visibility requirements
• The referenced section no longer exists in Colorado Regulation No.
3. As such, the permit shield was not granted.
o Colorado Regulation No. 4 — Wood -burning stoves
• The requirements of Colorado Regulation No. 4 are not addressed
by the operating permit program. Therefore, the permit shield has
not been granted.
o Colorado Regulation No. 6 Part A — Federal NSPS requirements
123/0049 Page 116 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
• The Roggen Natural Gas Processing Plant is subject to the
requirements of NSPS Dc, KKK, LLL, JJJJ and OOOO. Therefore,
the permit shield has not been granted.
o Colorado Regulation No. 6 Part B — State -only NSPS requirements
■ The Roggen Natural Gas Processing Plant is subject to the
requirements of NSPS Dc, KKK, LLL, JJJJ and OOOO. Therefore,
the permit shield has not been granted.
o Colorado Regulation No. 7 Section V.C — Disposal of Volatile Organic
Compounds
• Since the submittal of this application, Section V.C has been
removed from Colorado Regulation No. 7. Therefore, this permit
shield request is not applicable and the permit shield has not been
granted.
o Colorado Regulation No. 8 Section El — NESHAPs
■ At the time of this permit application, the area source MACT
requirements of subparts HH and ZZZZ had not yet been
promulgated. The Roggen Natural Gas Processing Plant includes
unit operations that are subject to the area requirements of
subparts HH and ZZZZ. Therefore, this permit shield has not been
granted.
o Colorado Regulation No. 8 Section E.11l — NESHAPs
• At the time of this permit application, the area source MACT
requirements of subparts HH and ZZZZ had not yet been
promulgated. The Roggen Natural Gas Processing Plant includes
unit operations that are subject to the area requirements of
subparts HH and ZZZZ. Therefore, this permit shield has not been
granted.
o Colorado Regulation No. 10 — Criteria for Analysis of Transportation
Conformity
• The requirements of Colorado Regulation No. 10 do not apply to
stationary sources. Therefore, this permit shield has not been
granted.
XI. STREAMLINING OF APPLICABLE REQUIREMENTS
This section addresses the conditions streamlined from this permit:
• Colorado Regulation No. 7, Section XVII.B.2.a
The Colorado Regulation No. 7, Section XVII.B.2.a general good operation and
maintenance practices has been streamlined out of the operating permit for all
engines except C-181 in favor of the federally enforceable general good
123/0049 Page 117 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
operation and maintenance requirements of MACT ZZZZ (§63.6605(b)). The
requirements of these two conditions are functionally identical. Since the MACT
ZZZZ requirement is federally enforceable, the state -only enforceable Colorado
Regulation No. 7, Section XVII.B.2.a was streamlined out of the operating permit.
It should be noted that C-181 is subject to NSPS JJJJ numerical emissions
standards and is therefore not subject to any part of Colorado Regulation No. 7,
including Section XVII.B.2.a.
• Colorado Regulation No. 6, Part B, Section II.C.2
The Colorado Regulation No. 6, Part B, Section II.C.2 requirement has been
streamlined out in favor of Colorado Regulation No. 1, Section III.A.1.b. These
requirements set forth the equation to calculate allowable particulate emissions
for fuel burning equipment generating between 1 MMBtu/hr and 250 MMBtu/hr.
Since Colorado Regulation No. 1 is federally enforceable, and Colorado
Regulation No. 6 is state -only enforceable, the state -only enforceable
requirement has been streamlined out in favor of the federally enforceable
requirement. This requirement is applicable to heaters H037 and P-138, which
are considered fuel burning equipment pursuant to the Colorado Regulation
Common Provisions.
• Colorado Construction Permit 07WE0988 Condition 3
The Colorado Construction Permit 07WE0988 Condition 3 formaldehyde limit of
0.52 tons/year was streamlined from the operating permit in favor of the facility -
wide HAP limits of 8 tons/year individual HAP and 22.9 tons/year total HAP. The
Division has determined that it is appropriate to include a point -specific individual
HAP limitation within the aggregated facility -wide HAP limitations. As such, this
construction permit condition with respect to formaldehyde only was streamlined
from the operating permit.
• Colorado Regulation No. 7 Section XVII.C.3
The Colorado Regulation No. 7 Section XVII.C.3 requirement to maintain records
of storage tank parameters for 2 years only has been streamlined out in favor of
the federally -enforceable Colorado Regulation No. 3 record retention
requirement of five years. Because the five year period is more stringent and
Colorado Regulation No. 3 is federally enforceable, the state -only enforceable
records retention requirement of Section XVII.C.3 was streamlined out in favor
of the five year requirement from Colorado Regulation No. 3, Part A, Section II
and Part C, Sections V.C.6 and V.C.7.
• 40 CFR Part 60 Subpart Dc §60.48c(i)
The NSPS Dc requirement to maintain records for a period of 2 years only has
been streamlined out of the operating permit, in favor the more stringent Title V
operating permit records retention requirement of 5 years, as required by
Colorado Regulation No. 3. Because the five year retention period is more
stringent than the NSPS Dc 2 year requirement, §60.48c(i) of NSPS Dc was
123/0049 Page 118 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
streamlined out in favor of the 5 year requirement from Colorado Regulation No.
3, Part A, Section II and Part C, Sections V.C.6 and V.C.7.
XII. MODIFICATIONS REQUESTED BY THE SOURCE
In their modification applications submitted on since the last revision of the operating
permit on 8/29/2005, the source requested that the permit be revised to reflect the
changes described in each application. In these applications, the source indicated that
each modification met the requirements for a minor permit modification and requested
that the minor permit modification procedures in Colorado Regulation No. 3, Part C,
Section X be used. Colorado Regulation No. 3, Part C, Section X.A identifies those
modifications that can be processed under the minor permit modification procedures.
Specifically, minor permit modifications "are not otherwise required by the Division to be
processed as a significant modification" (Colorado Regulation No. 3, Part C, Section
X.A.6). A summary of the applications received, along with the Division's determination
of minor modification applicability, is as follows:
• Application Received 4/2/2007 - Request to increase stabilized condensate tank
(P039) and condensate truck loadout (F029) VOC and throughput limits.
Implementation of this request effectively results in an increase in emissions that
is less cumulatively less than the significance threshold that necessitates a
significant modification.
It should be noted that a modification of this nature in a non -attainment area would
trigger reasonably available control technology (RACT) requirements, which the
Division considers to be a modification requiring a case -by -case determination.
Pursuant to Colorado Regulation No. 3, Part C, Section X.A.3, this modification could
not have been processed as a minor modification. However, at the time of the
application request, the area in which the Roggen Natural Gas Processing Plant
operates was not yet classified as an ozone non -attainment area. The ozone non -
attainment classification became effective on 11/20/2007, several months after this
minor modification was submitted. As such, RACT was not triggered for this modification
and no case -by -case determination was required. Because the aforementioned
modification does not: result in an increase in emissions above the significance
threshold (40 tons/year), add or change applicable NANSR, PSD, MACT or NSPS
requirements, require a case -by -case determination of emission limitations, require
determinations for temporary sources, require or change a visibility or increment
analysis, alter monitoring requirements, establish a limit with the purpose of avoiding an
otherwise applicable requirement, or establish a plant -wide emission limitations, this
modification is considered minor in nature and may be processed under the Colorado
Regulation No. 3, Part C, Section X provisions for minor modifications.
The renewal application received on 4/29/2005 requested the following
modifications:
• Relaxing the extended gas analysis frequency required for TEG dehydration unit
P033 from semi-annual to annual
123/0049 Page 119 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
o This annual sampling request was incorporated into Colorado
Construction Permit 01WE0208. This specific requirement within the
construction permit was absorbed into the operating permit.
• Increase the daily gas throughput to TEG dehydration unit P033 from 2.5
MMSCFD to 3.0 MMSCFD
o This request has been superseded by a construction permit modification
to 01WE0208, which resulted in a permitted daily gas throughput rate of
4.0 MMSCFD. This is the limit reflected in this issuance of the operating
permit
• Change the design heat rating of H037 from 7.55 MMBtu/hr to 8.735 MMBtu/hr
to correct an error in previously reported data for this heater
o Per the APEN received by the Division on 2/19/2015, the 7.55 MMBtu/hr
design heat rating is the correct duty for H037. This is reflected in the
operating permit.
• Remove the following non -operational equipment from the permit: Engine P012,
depropanizer heater H022, fractionator plant fugitives F030
o All of these points have been removed from the operating permit
The permit modification received on 7/10/2017 requested the following changes:
• Amend NOx and CO limitations and emission factors for engines C-154, C-159,
C-161, C-156, C-225, C-227 and C-181 to match those requested via APENs
received for AOS execution
• Permit 4% downtime for the RTO and 2% downtime for the ECD, during which
emissions from the amine and dehydration units' still vents are routed to
atmosphere
• Remove the RTO as a permitted control device for dehydration unit P033
It should be noted that this application was submitted by the source as a minor
modification. However, upon review, it was not immediately clear that these changes
could be processed under the provisions of a minor modification. The 5/1/2001
issuance of the operating permit did not include dehydration unit P-136 or amine
sweetening unit P-137, nor the associated control devices. A significant modification
to incorporate these points was received by the Division on 3/21/2016 and would
have needed to be processed prior to incorporating the 7/10/2017 changes under
minor modification provisions. This significant modification has been integrated into
the renewal of the operating permit, since significant modifications have the same
review requirements as renewals. In order to issue the changes requested in both
modifications concurrently, the 7/10/2017 modification was treated as a significant
modification and incorporated into the renewal of the operating permit.
It should be noted that parts of this application were nullified with the submittal of the
11/13/2017 permit modification (see discussion below). All modifications requested
123/0049 Page 120 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
for P-136 and P-137 were completely revoked with the 11/13/2017 permit
modification. Therefore, only the requirements related to P033 and engines C-154,
C-159, C-161, C-156, C-225, C-227 and C-181 were incorporated into the operating
permit as requested in this 7/10/2017 modification application.
The permit modification amendment received on 7/31/2017 requested the following
changes:
• Permit 2% downtime for the RTO instead of the 4% downtime requested in the
7/10/2017 application
It should be noted that this modification application was completely nullified by the
11/13/2017 permit modification (see discussion below). Therefore, no part of this
modification was incorporated into the operating permit renewal.
The source correspondence received via email on 9/7/2017 and APEN Updates
received 9/22/2017 requested the following changes:
• Modify the NOx and CO limits for the dehydration unit P033 to account for the pilot
gas required by the enclosed combustion device (ECD) operation.
It should be noted that the NOx and CO emissions resultant from ECD pilot gas
combustion are, by themselves, below APEN thresholds, and therefore do not
require a permit limit. However, in this revision of the operating permit, NOx and
CO emissions from the destruction of the dehydration units P033 and P-136, as
well as from the pilot gas, were aggregated for the purposes of the new control
device condition. As such, these relatively small emissions from the pilot gas and
dehydration unit P033 were taken into account when determining the NOx and CO
limitations for the ECD in the operating permit. Please refer to the Control Device
Condition V.L of this document for further discussion.
• Add a new limit for H2S for the amine sweetening unit P-137 per the ProMax model
run from 3/26/2013
• Establish scenario -specific limits for the various operating efficiencies for the
control devices associated with the dehydration units P033 and P-136 and the
amine sweetening unit P-137, based on control device downtime.
It should be noted that parts of this modification were nullified with the 11/13/2017
modification application (see below discussion) and confirmatory source
correspondence received 12/29/2017. As such, only the P033 NOx and CO emission
updates were incorporated into the operating permit.
The permit modification received on 9/11/2017 requested the following changes:
• Permit the plant emergency flare (FLARE, AIRS 141), which is no longer
considered to be an insignificant source of emissions
• Update permit to include NSPS OOOO requirements for fugitive emissions from
the process units RC (Roggen Compression), RP (Roggen Plant) and RTF
(Roggen Tank Farm). These process units underwent a qualifying modification
123/0049 Page 121 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
within the applicability dates specified for NSPS OOOO, and are now subject to
the fugitive requirements. Process Unit RC triggered NSPS OOOO requirements
in the 2nd quarter of 2013 and Process Units RP and RTF triggered NSPS OOOO
requirements in the 1st quarter of 2015.
It should be noted that the NOx, CO, VOC and throughput limitations requested for
the plant emergency flare were updated in the 11/8/2018 significant modification
application (see below discussion). As such, all parts of this 9/11/2017 modification
application were incorporated into the operating permit renewal, except for the
limitations for the plant emergency flare, which were superseded by those requested
in the 11/8/2018 application.
The permit modification received on 11/13/2017 requested the following changes:
• Cancel all previously submitted modifications to P-136 and replace with this
11/13/2017 modification
This modification effectively cancels the modification requests related to P-136 in
the permit modification application received 7/10/2017 and the APEN updates
received 9/22/2017. This 11/13/2017 modification revised P-136 VOC emissions
based on a ProMax model run from 11/9/2017. Still vent emissions P-136 are to
be primarily controlled with an ECD, permitted 2% annual downtime and a control
efficiency of 95%. This ECD also controls the still vent emissions from P033.
Alternatively, if the amine sweetening unit is operational, the still vent emissions
from P-136 may be routed to the RTO as a backup control device. The RTO is not
permitted any downtime and is allowed a control efficiency of 97%.
It should be noted that scenario -specific limits (as requested in the 9/22/2017
APEN updates) were not re -developed for P-136. The operating permit limitations
for P-136 were obtained from the operating scenario in which the maximum
amount of emissions are generated (see discussion below). Additionally, downtime
was permitted on a wet gas throughput basis, as opposed to developing numerical
emissions limitations for each pollutant or basing downtime on hours of ECD
inoperation (see discussion in Section V.E above). This was done to ensure that
still vent emissions are routed to atmosphere for a maximum of 2% of the time the
dehydration unit is actually operating, thus ensuring compliance with the Colorado
Regulation No. 7 Section XVII.D.3 requirement to reduce uncontrolled actual
hydrocarbon emissions by 95%.
• Cancel all previously submitted modifications to P-137 and revert to the
requirements set forth in Colorado Construction Permit 10WE1659 issued on
3/18/2015
This modification effectively cancels the RTO downtime requested in the permit
modifications received on 7/10/2017 and 7/31/2017, as well as the APEN updates
received 9/22/2017 and returns the amine unit VOC, NOx and CO limitations to
the values set forth in Colorado Construction Permit 10WE1659. It should be
noted, however, that the emission factor for CO from EPA's AP -42 Section 13.5
Table 13.5-2 for Industrial Flares was updated in December 2016. The 11/13/2017
modification requested the P-137 emissions be updated to reflect this new
123/0049 Page 122 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
emission factor. This alteration was incorporated into the operating permit,
resulting in a decrease in CO emissions from P-137.
Scenario -specific limitations (as requested in the 9/22/2017 modification
application) were not re -developed for P-137 since there is now only a single mode
of operation for P-137 (there is no longer any permitted downtime for the RTO).
The H2S emission limitation (as requested in the 9/22/2017 APEN updates) was
not re -incorporated into this 11/13/2017 modification since the RTO is not
permitted any downtime. Therefore, all H2S is converted to SO2 via combustion.
The SO2 limit, as set forth in Colorado Construction Permit 10WE1659, was
incorporated into the operating permit.
In source correspondence received 1/31/2018, it was requested that burner mode
emissions be permitted for the RTO. Fuel gas is sent to the RTO burner on an as -
needed basis to maintain combustion chamber temperatures above the
autoignition temperature of the still vent and acid gas vent vapors, in the event the
still gas combustion alone produces insufficient heat to maintain these required
temperatures. This operation is typically intermittent and actual emissions
contributed by this burner mode of RTO operation are expected to be low.
However, the emissions reflected in the permit limitations were based on
continuous operation (8,760 hours) and the full rated capacity of the RTO burner
of 5 MMBtu/hr, resulting in a conservative emissions profile. Because the RTO
serves as the primary control device for the amine sweetening unit, these
emissions associated with the RTO are reported on the amine sweetening unit
APEN.
• Incorporate the 7/10/2017 modification as it relates to P033
This modification removes the RTO as a permitted control device for P033
(previously allowed under Colorado Construction Permit 01WE0208), reduces the
control efficiency of the ECD to 95% (previously 97% under Colorado Construction
Permit 01WE0208) and permits 2% annual downtime for the ECD. As a result,
VOC emissions increase with this modification. Additionally, it was requested that
the new CO emission factor from the December 2016 revision to EPA's AP -42
Section 13.5 Table 13.5-2 for Industrial Flares be used in the calculation of CO
emissions. This alteration results in a decrease in emissions of CO from P033.
Source correspondence received 12/29/2017 clarified that the NOx and CO
emissions related to the ECD pilot gas reported on the APEN update for P033
received 9/22/2017 should NOT be cancelled (as requested in the 11/13/2017
permit modification application). This APEN update was therefore included in the
operating permit. It should be noted, however, that the scenario -specific limits (also
requested in the 9/22/2017 APEN updates) were not re -developed for P033. The
operating permit limitations for P033 were obtained from the operating scenario in
which the maximum amount of emissions are generated (see discussion below).
Additionally, downtime was permitted on a wet gas throughput basis, as opposed
to developing numerical emissions limitations for each pollutant (see discussion in
123/0049 Page 123 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Section V.E above). This was done to ensure that still vent emissions are routed
to atmosphere for a maximum of 2% of the time the dehydration unit is operating.
This modification was submitted to correct a relaxation issue for VOC emissions
created by the 7/10/2017 and 7/31/2017 modifications. Pursuant to Colorado
Regulation No. 3, Part D, Section V.A.7 for non -attainment areas, "the requirements
of Section V.A. [i.e., Non -Attainment New Source Review for major stationary sources]
shall apply at such time that any stationary source or modification becomes a major
stationary source or major : modification solely by virtue of a relaxation in any
enforceable limitation that was established after August 7, 1980 on the capacity of the
source or modification to otherwise emit a pollutant, such as a restriction on hours of
operation" (Colorado Regulation No. 3, Part D, Section V.A.7.b). The Roggen Natural
Gas Processing Plant is a major stationary source of VOC and NOx for the purposes
of NANSR (see Section II of this document for a general emissions summary and
Section XIV for a more detailed emissions report). As such, a modification to this
source in excess of the significance threshold of 40 tons/year (Colorado Regulation
No. 3, Part D, Section II.A.44.a) for NOx or VOC would constitute a major modification
subject to the requirements of NANSR, provided the relaxed limit was established after
August 7, 1980. In 2010, it was requested that the Roggen Natural Gas Processing
Plant be modified to increase processing capacity. This modification was permitted
under Colorado Construction Permit 10WE1659. The original issuance of 10WE1659
on 11/8/2010 permitted facility wide fugitive emissions P025, two compressor
engines, dehydration unit P-136, amine sweetening unit P-137 and hot oil heater P-
138. Uncontrolled emissions from this project were in excess of the 40 tons/year
threshold for VOC. Limitations were taken on the fugitive emissions, compressor
engines, dehydration unit and amine sweetening unit to reduce the emissions below
the 40 tons/year significance threshold for VOC (the hot oil heater P-138 is an
uncontrolled emissions point). Therefore, the project permitted under 10WE1659 was
a minor modification with respect to NANSR. However, since these limitations ensured
this modification did not trigger NANSR at the time of initial permitting, and these
limitations were put in place after August 7, 1980, these limitations are subject to the
relaxation rule of Colorado Regulation No. 3, Part D, Section V.A.7.b, which states
that NANSR requirements shall apply if these original permit limitations are relaxed
with future modifications in such a way that the major modification threshold of 40
tons/year for VOC is exceeded. This requirement was included as Condition 46 in the
original issuance of 10WE1659.
Subsequent modifications to the permit limitations in 10WE1659 further relaxed these
limitations, but never in excess of the 40 tons/year significance threshold. However,
in the permit modifications received 7/10/2017 and 7/31/2017 for P-136 and P-137,
the control efficiency of the ECD was decreased from 97% to 95% and downtime for
the ECD (2% under 7/10/2017) and RTO (4% in 7/10/2017; modified to 2% in
7/31/2017) was requested. The combined effect of a lower control efficiency for the
ECD and increased VOC emissions to atmosphere due to downtime resulted in a
relaxation in the permitted VOC limits of 10WE1659 in excess of the 40 tons/year
significance threshold, thereby triggering NANSR. However, because these
modifications were conservative in nature, the 11/13/2017 modification was submitted
to request new, less conservative downtime limitations while ensuring emission
123/0049 Page 124 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
increases remained below the 40 tons/year significance threshold for NANSR.
Because the amine sweetening unit is rarely used, it was determined that no permitted
downtime was required for this unit. Therefore, all modifications regarding P-137
subsequent to the 3/18/2015 issuance of 10WE1659 were cancelled with this
11/13/2017 modification, returning permitted operation of P-137 to the requirements
of 1 0WE1659 Issuance 5. Additionally, the P-136 VOC emission limitation was revised
based on a new ProMax model run, a 95% control efficiency for the ECD and 2%
permitted downtime for the ECD. Together, these changes in the permitted operation
of P-136 and P-137 resulted in an increase in VOC emissions that fell below the
NANSR threshold of 40 tons/year. Therefore, this modification is not subject to
NANSR requirements.
It should be noted that the requested permit limitations were based on the permitted
operating scenario yielding the largest amount of each pollutant, as summarized
below:
• VOC — Emissions of VOC are at a maximum when the ECD experiences the
maximum allowable 2% downtime. During periods of downtime, VOC emissions
are not combusted, but are routed directly to atmosphere. As such, permitted VOC
emissions for dehydration units P033 and P-136 were based on the scenario in
which the a ECD experiences the maximum allowable 2% annual downtime,
resulting in the maximum amount of VOC emissions routed to atmosphere. It
should be noted that the VOC emission limitations for P-136 were based on the
scenario in which the ECD controls still vent emissions and the ECD experiences
the maximum allowable downtime of 2%. The control efficiency of the ECD is 95%,
whereas the control efficiency of the RTO is 97%. Therefore, the more
conservative emissions profile results from the scenario in which the P-136 still
vent is controlled by the ECD and the ECD experiences all 2% of the permitted
downtime.
• NOx & CO — These pollutants are products of combustion, and are therefore
produced only when emissions are routed to a control device. Emissions are
therefore maximized when the ECD does not experience any downtime. As such,
permitted NOx and CO emissions for P033 and P-136 were based on 8,760 hours
of operation of the ECD. It should be noted that the exact same AP -42 emission
factors are applicable to the ECD and RTO. Therefore, identical amounts of NOx
and CO are generated for P-136 on an annual basis, regardless of which control
device is used.
The permit modification received on 11/8/2018 requested the following changes:
• Increase the purge gas and waste gas throughputs to the plant emergency flare
(FLARE, AIRS 141). Increase the NOx, CO and VOC emission limitations for the
plant emergency flare to correspond to the increased throughputs requested.
• Update list of insignificant activities.
This permit application was treated as a significant modification and incorporated in
its entirety into the operating permit renewal.
123/0049 Page 125 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Other source -requested modifications were addressed as follows:
Page Following Cover Page
• Updated company information to reflect name change requested in 3/2/2017
source correspondence.
• Updated responsible official and permit contact requested in 3/2/2017 source
correspondence.
Section III — Permit Shield
• Updated table to include shields that were granted (see discussion in Section X
of this document)
XIII. OTHER MODIFICATIONS
In addition to the source requested modifications, the Division has included changes to
make the permit more consistent with recently issued permits, include comments made
by EPA on other Operating Permits, as well as correct errors or omissions identified
during inspections and/or discrepancies identified during review of this renewal. These
changes are as follows:
Page Following Cover Page
• Modified the language concerning postmarked dates for report submittals to
reflect the Division's current standard language.
• Updated Information Relied Upon section
Section I — General Activities and Summary
• Updated Permitted Activities section to reflect current operations at the Roggen
Natural Gas Plant (Condition 1.1)
• Amended list of construction permits to identify those incorporated in the
operating permit (Condition 1.3)
• Revised the language in Condition 1.4 include conditions that are state -only
enforceable.
• Updated AOS language to current version (10/12/2012 w/ updated citations)
Section II — Specific Permit Terms
• Created a new condition to specifically address the control devices for the
dehydration units P033 and P-136 and the amine sweetening unit P-137. All NOx
and CO limitations from each of these units were consolidated in the control
device condition, along with contributions from combusted pilot gas for the ECD
and burner gas for the RTO. All control -device specific state regulations were
combined into this condition, as well as any construction permit/O&M
123/0049 Page 126 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
requirements. Created subcondition to address the outstanding initial testing
requirements for the RTO from Colorado Construction Permit 10WE1659.
• Consolidated all HAP emission calculations and facility -wide limitation
requirements in a separate condition
Updated CAM condition to reflect the most current language (ver. 4/16/2009)
Section III— Permit Shield
• Updated the Reg 3 Citation for the permit shield
• Amended streamlined requirements table to include all applicable conditions
Section IV General Permit Conditions
• Updated the general permit conditions to the current version (8/28/2018)
Appendices
• Appendix A — Inspection Information
o Updated directions to plant and safety equipment based on renewal
application.
o Updated facaity plot plan to the most recent version submitted with the
significant modification received 3/21/2016.
o Amended list of insignificant activities to include those indicated on a list
received from the source in the permit modification application received
on 11/8/2018. Re -formatted section to identify the applicable exemptions
from Colorado Regulation No. 3, Part C, Section II.E.3, and identify those
exemptions that require recordkeeping to maintain the exemption.
• Appendix B — Monitoring and Permit Deviation Report
o Updated to the most current version (8/20/2014 w/ codes)
o Revised unit descriptions to reflect the point summary table in Section I
Condition 6.1
o Updated company information to reflect name change
• Appendix C — Compliance Certification Report
o Updated to the most current version (8/20/2014 w/ codes)
o Revised unit descriptions to reflect the point summary table in Section I
Condition 6.1
o Updated company information to reflect name change
• Appendix D — Notification Addresses
123/0049 Page 127 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
o Updated to the most current version (2/5/2014)
• Appendix F — Permit Modifications
o Cleared all modifications related to the previous issuance of this permit
• Appendix G — Engine AOS Applicability Reports
o Updated to the most current version (10/12/2012 w/ updated citations)
• Appendix H - Compliance Assurance Monitoring Plan
o Added CAM plan for affected engines
o Added CAM plan for affected TEG dehydration unit based on the draft
CAM plan submitted with the 11/13/2017 permit modification and source
comments received 11/2/2018.
o Added CAM plan for amine sweetening unit based on the draft CAM plan
submitted with the 11/13/2017 permit modification and source comments
received 11/2/2018.
123/0049 Page 128 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
XIV. Facility -Wide Emission Details
Pollutant Summary
AIRS ID
Facility ID
Source
Controlled Emissions (tons/year)
Uncontrolled Emissions (tons/year)
NOx
CO
VOC
Fugitive
VOC
Total
HAP
Reportable
HAP
NOx
CO
VOC
Fugitive
VOC
Total
HAP
Reportable
HAP
101
C-154
VRU Compressor
21.24
21.24
10.62
--
0.40
0.18
116.84
84.98
15.93
--
1.20
0.76
102
C-155
Residue Compressor
16.34
16.34
7.78
--
0.34
0.16
85.61
62.62
11.67
--
1.02
0.65
103
C-159
Residue Compressor
26.07
27.38
13.04
--
0.53
0.44
169.47
117.32
26.07
--
1.57
1.41
107
C-157
Residue Compressor
16.34
16.34
7.78
--
0.34
0.16
85.61
62.26
11.67
--
1.02
0.65
108
C-161
Residue Compressor
13.04
26.07
9.13
--
0.53
0.44
143.40
104.29
19.55
--
1.57
1.41
110
C-158
Box Elder Compressor
18.57
18.57
8.85
--
0.37
0.17
97.30
70.76
13.27
--
1.11
0.70
113
C-160
Propane Compressor
16.34
16.34
7.78
--
0.34
0.16
85.61
62.26
11.67
--
1.02
0.65
114
C-156
Residue Compressor
7.78
15.57
5.45
--
0.34
0.16
85.61
62.62
11.67
--
1.02
0.65
115
C-223
Inlet Compressor
14.60
14.60
6.95
--
0.30
0.13
61.64
101.02
9.72
--
0.88
0.56
117
C-225
Inlet Compressor
7.73
15.45
5.41
--
0.30
0.14
63.63
104.28
10.04
--
0.91
0.57
119
C-227
Inlet Compressor
13.90
14.60
7.00
--
0.30
0.13
104.30
101.00
9.70
--
0.88
0.56
122
P025
Fugitive Emissions
--
--
-
33.54
0.43
0.39
--
--
--
114.07
1.48
1.34
125
P039
Stabilized Condensate Tanks
--
--
1.50
--
0.28
0.28
--
--
28.80
--
5.52
5.58
126
F029
Stabilized Condensate Loadout
--
--
30.84
--
6.10
5.97
--
--
30.84
--
6.10
5,97
129
H037
Hot Oil Heater
3.45
2.90
--
--
--
--
3.45
2.90
--
--
0.07
--
130
P033
TEG Dehydration Unit
--
--
1.05
--
0.30
0.30
--
--
49.10
--
4.84
4.77
133
F031
Pressurized Liquids Loadout
--
--
5.00
--
--
--
--
--
5.00
--
--
--
134
C-181
Residue Compressor
14.27
28.54
9.99
--
0.55
0.46
156.99
114.18
21.41
--
1.64
1.46
136
P-136
TEG Dehydration Unit
--
4.04
23.74
--
8.36
8.36
--
4.04
663.37
--
130.24
130.24
137
P-137
Amine Sweetening Unit
2.93
5.61
2.43
--
1.34
1.34
2.93
5.61
282.69
--
48.85
48.85
138
P-138
Hot Oil Heater
7.02
11.79
--
--
0.30
0.25
7.02
11.79
--
--
0.30
0.25
140
C-192
Box Elder Compressor
14.30
28.60
10.00
--
0.82
0.73
156.99
114.18
21.41
--
1.64
1.47
141
FLARE
Plant Emergency Flare
3.55
15.93
17.19
--
0.08
0.08
3.55
15.93
343.78
--
1.66
1.64
Total Permitted Facility Emissions (tons/year)
217.47
299.91
191.53
33.54
22.67
20.45
1429.95
1202.04
1597.36
114.07
214.54
210.13
123/0049
Page 129 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Calculation Basis
Facility ID
Information Source
C-154
APEN rec'd 8/12/2016; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-155
APEN rec'd 1/19/2017; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled 5O2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-159
APEN rec'd 2/15/2017; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-157
APEN rec'd 1/22/2016; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-161
APEN rec'd 4/30/2015; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-158
APEN rec'd 4/28/2017; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-160
APEN rec'd 4/30/2015; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-156
APEN rec'd 7/27/2018; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled 5O2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-223
APEN rec'd 11/13/2017; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-225
APEN rec'd 6/20/2013; mfg. LF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled 5O2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
C-227
APEN rec'd 1/29/2015; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled 5O2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
P025
APEN rec'd 7/25/2014; 12/4/2012 Gas Sample from 7/25/2014 CP 10WE1659 Mod App; EPA 453 Table 2-4 for component -specific EF's; DCP/Division agreed -upon CE's
P039
APEN rec'd 5/2/2016; composition from 5/26/2011 CP 12WE1242 Mod App; 95% CE for combustor, per Colorado Regulation No. 7 Section XVII
F029
APEN rec'd 5/2/2016; composition from 5/26/2011 CP 12WE1242 Mod App; Loading Loss equation from AP -42 Chapter 5.2 Eqn. 1
H037
APEN rec'd 2/19/2015; AP -42 Table 1.4-1 for NOx & CO EF's, Table 1.4.2 for PM, 5O2 and VOC EF's, Table 1.4-3 for HAP EF's
P033
APEN rec'd 9/22/2017; 4/8/2014 GLYCalc run from 01WE0208 Mod App; NOx EF from AP -42 Tables 1.4-1 (pilot) & 13.5-1 (still vent), CO EF from AP -42 Tables 1.4-1 (pilot) & 13.5-2 (still vent); 95% CE &
2% DT for ECD
F031
APEN rec'd 12/14/2018; 12/14/2018 APEN supporting documents
C-181
APEN rec'd 8/18/2015; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
P-136
APEN rec'd 11/13/2017; Compositions from 11/13/2017 Mod App; NOx EF from AP -42 Table 13.5-1, CO EF from AP -42 Table 13.5-2; 97% CE & 0% DT for RTO, 95% CE & 2% DT for ECD
P-137
APEN recd 11/13/2017; Compositions from 5/14/2015 CP Mod App; NOx & CO EF from AP -42 Tables 1.4-1 (burner) & 13.5-1 / 2 (acid gas vent); 97% CE & 0% DT for RTO
P-138
APEN rec'd 11/16/2015; AP -42 Table 1.4-1 for NOx & CO EF's, Table 1.4.2 for PM, 5O2 and VOC EF's, Table 1.4-3 for HAP EF's
C-192
APEN rec'd 4/30/2015; mfg. EF's for NOx, CO, VOC; AP -42 Table 3.2-3 for uncontrolled SO2, PM and HAP EF's; MACT ZZZZ for CH2O CE, assume 50% CE for all other HAP
FLARE
APEN rec'd 11/8/2018; Compositions from 9/11/2017 Sig Mod App; NOx, CO & VOC EF's for pilot from AP -42 Table 1.4-1 & 1.4-2, NOx & CO EF's for purge/waste gas from AP -42 Table 13.5-1 & 13.5-2
123/0049
Page 130 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Controlled HAP Emissions
AIRS ID
Facility ID
Source
Calculated Controlled HAP Emissions (tpy)
Acetaldehyde
Acrolein
Methanol
Formaldehyde
n-
Hexane
2 2 4-
TMP
Benzene
Toluene
Ethyl
benzene
Xylenes
Other
HAP
101
C-154
VRU Compressor
0.05
0.05
0.06
0.18
--
--
0.03
0.01
0.00
0.00
0.02
102
C-155
Residue Compressor
0.04
0.04
0.05
0.16
--
--
0.02
0.01
0.00
0.00
0.02
103
C-159
Residue Compressor
0.07
0.06
0.07
0.24
--
--
0.04
0.01
0.00
0.00
0.02
107
C-157
Residue Compressor
0.04
0.04
0.05
0.16
--
--
0.02
0.01
0.00
0.00
0.02
108
C-161
Residue Compressor
0.07
0.06
0.07
0.24
--
--
0.04
0.01
0.00
0.00
0.02
110
C-158
Box Elder Compressor
0.05
0.04
0.05
0.17
--
--
0.03
0.01
0.00
0.00
0.02
113
C-160
Propane Compressor
0.04
0.04
0.05
0.16
--
--
0.02
0.01
0.00
0.00
0.02
114
C-156
Residue Compressor
0.04
0.04
0.05
0.16
--
--
0.02
0.01
0.00
0.00
0.02
115
C-223
Inlet Compressor
0.04
0.04
0.04
0.13
--
--
0.02
0.01
0.00
0.00
0.01
117
C-225
Inlet Compressor
0.04
0.04
0.04
0.14
--
--
0.02
0.01
0.00
0.00
0.01
119
C-227
Inlet Compressor
0.04
0.04
0.04
0.13
--
--
0.02
0.01
0.00
0.00
0.01
122
P025
Fugitive Emissions
--
--
--
--
0.26
--
0.13
0.03
0.00
0.01
--
125
P039
Stabilized Condensate Tanks
--
--
--
--
0.14
0.01
0.02
0.06
0.00
0.05
--
126
F029
Stabilized Condensate Loadout
--
-
--
--
3.01
0.17
0.42
1.39
0.11
1.00
--
129
H037
Hot Oil Heater
--
--
--
0.00
0.06
--
0.00
0.00
130
P033
TEG Dehydration Unit
--
--
--
--
0.02
--
0.11
0.13
0.00
0.04
--
133
F031
Pressurized Liquids Loadout
--
--
--
--
--
--
134
C-181
Residue Compressor
0.07
0.07
0.08
0.25
--
--
0.04
0.01
0.00
0.00
0.02
136
P-136
TEG Dehydration Unit
--
--
--
--
1.68
--
3.37
2.69
0.07
0.55
--
137
P-137
Amine Sweetening Unit
--
--
--
--
0.05
-
0.72
0.47
0.02
0.09
--
138
P-138
Hot Oil Heater
--
--
--
0.01
0.25
--
0.00
0.00
--
--
--
140
C-192
Box Elder Compressor
0.07
0.07
0.08
0.52
--
--
0.04
0.01
0.00
0.00
0.03
141
FLARE
Plant Emergency Flare
0.00
0.00
0.00
0.00
0.07
0.00
0.01
0.01
0.00
0.00
0.00
Total Permitted Facility Emissions (tons/year)
0.67
0.63
0.73
2.63
5.54
0.17
5.16
4.91
0.21
1.78
0.24
2016 Actual Facility Emissions (tons/year)
0.04
0.04
0
1.65
0.44
NR
1.43
1.3
0
0.38
NR
123/0049
Page 131 of 132
DCP Operating Company, LP — Roggen Natural Gas Processing Plant
Operating Permit No. 95OPWE055
Technical Review Document — Renewal Operating Permit
Uncontrolled HAP Emissions
AIRS ID
Facility ID
Source
Calculated Uncontrolled HAP Emissions (tons/year)
Acetaldehyde
Acrolein
Methanol
Formaldehyde
n-
Hexane
2,2 4-
TMP
Benzene
Toluene
Ethyl
benzene
Xylenes
Other
HAP
101
C-154
VRU Compressor
0.10
0.10
0.11
0.76
--
--
0.06
0.02
0.00
0.01
0.04
102
C-155
Residue Compressor
0.09
0.08
0.10
0.65
--
--
0.05
0.02
0.00
0.01
0.03
103
C-159
Residue Compressor
0.14
0.13
0.15
1.00
--
--
0.08
0.03
0.00
0.01
0.05
107
C-157
Residue Compressor
0.09
0.08
0.10
0.65
--
--
0.05
0.02
0.00
0.01
0.03
108
C-161
Residue Compressor
0.14
0.13
0.15
1.00
--
--
0.08
0.03
0.00
0.01
0.05
110
C-158
Box Elder Compressor
0.10
0.09
0.10
0.70
--
--
0.05
0.02
0.00
0.01
0.03
113
C-160
Propane Compressor
0.09
0.08
0.10
0.65
--
--
0.05
0.02
0.00
0.01
0.03
114
C-156
Residue Compressor
0.09
0.08
0.10
0.65
--
--
0.05
0.02
0.00
0.01
0.03
115
C-223
Inlet Compressor
0.08
0.07
0.08
0.56
--
--
0.04
0.02
0.00
0.01
0.03
117
C-225
Inlet Compressor
0.08
0.07
0.09
0.57
--
--
0.04
0.02
0.00
0.01
0.03
119
C-227
Inlet Compressor
0.08
0.07
0.08
0.56
--
--
0.04
0.02
0.00
0.01
0.03
122
P025
Fugitive Emissions
--
--
--
--
0.89
--
0.45
0.11
0.00
0.03
--
125
P039
Stabilized Condensate Tanks
--
--
--
--
2.81
0.16
0.39
1.30
0.10
0.93
--
126
F029
Stabilized Condensate Loadout
--
--
--
--
3.01
0.17
0.42
1.39
0.11
1.00
--
129
H037
Hot Oil Heater
--
--
--
0.00
0.06
--
0.00
0.00
--
--
--
130
P033
TEG Dehydration Unit
--
--
--
0.58
--
1.69
1.88
0.07
0.62
--
133
F031
Pressurized Liquids Loadout
-
--
--
--
--
--
--
--
134
C-181
Residue Compressor
0.14
0.13
0.15
1.04
--
--
0.08
0.03
0.00
0.61
0.05
136
P-136
TEG Dehydration Unit
--
--
--
--
32.37
--
49.58
39.28
0.98
8.03
--
137
P437
Amine Sweetening Unit
--
--
--
--
3.29
--
25.40
16.61
0.54
3.01
138
P-138
Hot Oil Heater
--
--
--
0.01
0.25
--
0.00
0.00
--
--
--
140
C492
Box Elder Compressor
0.14
0.13
0.15
1.04
--
--
0.08
0.03
0.00
0.01
0.05
141
FLARE
Plant Emergency Flare
0.00
0.00
0.00
0.00
1.28
0.00
0.24
0.13
0.00
0.02
0.00
Total Permitted Facility Emissions (tons/year)
1.33
1.26
1.46
9.81
44.53
0.32
78.91
60.95
1.82
13.73
0.47
123/0049
Page 132 of 132
Hello