HomeMy WebLinkAbout20201198.tiffCOLORADO
Department of Public
Health & Environment
Weld County - Clerk to the Board
1150 O St
PO Box 758
Greeley, CO 80632
March 25, 2020
Dear Sir or Madam:
RECEIVED
MAR 3 0 2020
WELD COUNTY
COMMISSIONERS
On March 26, 2020, the Air Pollution Control Division will begin a 30 -day public notice period for
Whiting Oil and Gas Corporation - Redtail Facility.
The draft permit and technical review document are located on the Division's website at
https: / /www.colorado.gov/pacific/cdphe/air-permit-public-notices. Additional associated
documents may be assessed by searching on the following record numbers in Colorado's
Environmental System located at Colorado Environmental Records or by using the direct links
provided below:
• Operating Permit Application: Record Number 123-9AD0-497
https: / /environmentalrecords.colorado.gov/HPRMWebDrawer/RecordView/1468768
• 2017 Revisions to Operating Permit Application: Record Number 123-9AD0-495
https: //envi ronmentalrecords.colorado.gov/ HPRMWebDrawer/ RecordView/1458218
• 2018 Revisions to Operating Permit Application: Record Number 123-9AD0-496
https: //environmentalrecords.colorado.gov/ HPRMWebDrawer/ RecordView/ 1468767
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: Public Notice Coordinator
4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe
Jared Polls, Governor I Jill Hunsaker Ryan, MPH, Executive Director
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2020-1198
40
Air Pollution Control Division
Notice Of A Proposed Title V Operating Permit Warranting
Public Comment
Website Title: Whiting Oil and Gas Corporation - Redtail Facility - Weld County
Notice Period Begins: March 26, 2020
NOTICE is hereby given that an Operating Permit application 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: Whiting Oil and Gas Corporation
1700 Broadway
Suite 2300
Denver, CO 80290
Facility: Redtail Facility
NE % of Section 21, T 10N, R 58W
Weld County, Colorado
Whiting Oil and Gas Corporation has applied for an Operating Permit for the Redtail Facility in Weld County,
CO. Natural gas liquids processing facility. A copy of the application, including supplemental information,
the Division's analysis, and a draft of Operating Permit 15OPWE394 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 operating permit for approval. Any interested person may contact Jaclyn
Zey of the Division at 303-692-3123 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.gov/pacific/cdphe/air-permit-public-notices. This page
also includes guidance for public participation
• Send an email to cdphe.commentsapcd@state.co.us
(COLORADO
Department at Public
Health b Environment
• Send comments to our mailing address:
Jaclyn Zey
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.
21
COLORADO
Department of Public
Health & Environment
Colorado Department
of Public Health
and Environment
OPERATING PERMIT
Whiting Oil and Gas Corporation
Redtail Facility
First Issued: DRAFT
AIR POLLUTION CONTROL DIVISION
COLORADO OPERATING PERMIT
FACILITY NAME:
FACILITY ID:
ISSUED:
EXPIRATION DATE:
MODIFICATIONS:
Redtail Gas Plant OPERATING PERMIT NUMBER
123/9AD0
DRAFT
DRAFT
See Appendix F of Permit
15OPWE394
Issued in accordance with the provisions of Colorado Air Pollution Prevention and Control Act, 25-7-101 et
sue. and applicable rules and regulations.
ISSUED TO:
PLANT SITE LOCATION:
Whiting Oil and Gas Corporation Redtail Facility
1700 Broadway, Suite 2300 NE 1/4 of Section 21, T ION, R 58W
Denver, CO 80290 Weld County, Colorado
INFORMATION RELIED UPON
Operating Permit Application Received:
And Additional Information Received:
Nature of Business: Natural Gas Liquids
Primary SIC: 1321
RESPONSIBLE OFFICIAL
Name: Shane Fross
Title: Sr. Vice President of Operations
Phone: (303) 390-1625
October 2, 2015
March 31, 2017 and October 12, 2018
FACILITY CONTACT PERSON
Name: Chenine Wozniak
Title: Environmental Professional III
Phone: (303) 837-4236
SUBMITTAL DEADLINES —
First Semi -Annual Monitoring Period: TBD based on issuance date
Subsequent Semi -Annual Monitoring Periods: TBD based on issuance date
Semi -Annual Monitoring Reports: TBD based on issuance date
First Annual Compliance Period: TBD based on issuance date
Subsequent Annual Compliance Periods: TBD based on issuance date
Annual Compliance Certification: TBD based on issuance date
Note that the Semi -Annual Monitoring Reports and 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.
Operating Permit 15OPWE394 First Issued: DRAFT
TABLE OF CONTENTS:
SECTION I - General Activities and Summary 4
1. Permitted Activities 4
2. Alternative Operating Scenarios (ver 10/12/2012 — Updated to reflect changes to Colorado
Regulation No.7, NSPS, and MACT rules) 5
3. Prevention of Significant Deterioration 12
4. Accidental Release Prevention Program (112(r)) 12
5. Compliance Assurance Monitoring (CAM) 12
6. Summary of Emission Units 13
SECTION II - Specific Permit Terms 15
1. 009 — Fugitive Volatile Organic Compounds from Equipment Leaks at the Redtail Gas Plant
(FUG -1) 15
2. 011 — Generac, Diesel -Fired, at or below 250 kW, Compression -Ignition Internal Combustion
Engine (GEN-2) 25
3. 013 — Plant Process Flare (FLR-1A) 33
4. 014 —Natural Gas -Fired Hot Oil Heater (reboiler for AMINE -1, Dehy-1, Dehy-2), rated at 43.64
MMBtu/hr 37
5. 015 — 35 MMscfd Ethylene Glycol Dehydration Unit (DEHY-1) & 016- 70 MMscfd Ethylene
Glycol Dehydration Unit (DEHY-2) 42
6. 017 — One Methyldethanolamine Natural Gas Sweetening System (AMINE -1) 48
7. 018 — Produced Water Tanks (PW-1 & PW-2) 56
8. 021 — 1,311 HP Caterpillar 4SLB Natural Gas Fired Internal Combustion Engine (RZ-ENG-1) 58
9. 023 — Eight (8) two-phase separators controlled by an open flare during gas -gathering system
downtime (RZ-SEP-1 through RZ-SEP-8, RZ-FLR-1) 67
10. 024 — Twenty -Two (22) 400 bbl Fixed -Roof Produced Water Storage Tanks (RZ-PW-1 through
RZ-PW-22) 70
11. 025 — Thirty-two 400 BBL fixed roof, Crude Oil Storage Tanks (RZ-TK-1 through RZ-RK-32)
72
12. Facility -Wide Requirements 76
13. Colorado Regulation No. 1 Opacity Standards 77
14. Additional Requirements: Colorado Regulation No. 7 79
15. Colorado Regulation No. 7, Part D, Section II.B — Flare Requirements (State -only enforceable)
94
16. Colorado Regulation No. 7, Part D, Section II.C — Storage Tanks Requirements 96
17. 40 CFR Part 60 Subpart A — General Provisions 108
18. 40 CFR Part 63 Subpart A — General Provisions 109
19. Portable Monitoring (6/26/2014 version) 110
SECTION III - Permit Shield 111
1. Specific Non -Applicable Requirements 111
2. General Conditions 112
3. Stream -lined Conditions 113
SECTION I - General Permit Conditions (ver 1/21/2020) 115
1. Administrative Changes 115
2. Certification Requirements 115
3. Common Provisions 115
Operating Permit 15OPWE394 First Issued: DRAFT
TABLE OF CONTENTS:
4. Compliance Requirements 119
5. Emergency Provisions 120
6. Emission Controls for Asbestos 120
7. Emissions Trading, Marketable Permits, Economic Incentives 120
8. Fee Payment 120
9. Fugitive Particulate Emissions 120
10. Inspection and Entry 121
11. Minor Permit Modifications 121
12. New Source Review 121
13. No Property Rights Conveyed 121
14. Odor 121
15. Off -Permit Changes to the Source 121
16. Opacity 122
17. Open Burning 122
18. Ozone Depleting Compounds 122
19. Permit Expiration and Renewal 122
20. Portable Sources 122
21. Prompt Deviation Reporting 122
22. Record Keeping and Reporting Requirements 123
23. Reopenings for Cause 124
24. Requirements for Major Stationary Sources 124
25. Section 502(b)(10) Changes 125
26. Severability Clause 125
27. Significant Permit Modifications 125
28. Special Provisions Concerning the Acid Rain Program 126
29. Transfer or Assignment of Ownership 126
30. Volatile Organic Compounds 126
31. Wood Stoves and Wood burning Appliances 127
APPENDIX A - Inspection Information 129
1. Directions to Plant: 129
2. Safety Equipment Required: 129
3. Facility Plot Plan: 129
4. List of Insignificant Activities- 129
Appendix B 134
Reporting Requirements and Definitions 134
APPENDIX C 144
Required Format for Annual Compliance Certification Reports 144
APPENDIX D 150
Notification Addresses (ver. 1/27/2020) 150
APPENDIX E 151
Permit Acronyms 151
APPENDIX F 153
Permit Modifications 153
Operating Permit 15OPWE394
First Issued: DRAFT
TABLE OF CONTENTS:
APPENDIX G 154
Engine AOS Applicability Reports 154
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
1. Permitted Activities
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 4
SECTION I - General Activities and Summary
1.1 The Redtail Facility is comprised of the Redtail Gas Plant and the co -located Razor 21 Central
Production Battery.
The Redtail Gas Plant processes gas from wells producing from the Niobrara and Codell/Ft. Hays
formations. The inlet gas to the plant is gathered in a low-pressure system and enters the plant at a
pressure of approximately 10 pounds per square inch gauge (psig). The gas travels through a series of
filters and an inlet slug catcher designed to remove slug liquids. The liquids removed are pumped to a
400 -barrel (bbl) atmospheric gunbarrel tank. The inlet gas goes through three stages of compression
where the pressure is boosted to approximately 400 — 475 psig. The compressed gas is then refrigerated
with a series of heat exchangers and propane refrigeration. An ethylene glycol (EG) system (DEHY-1
and DEHY-2) injects EG into the gas for additional gas dehydration and freeze protection. The EG is
regenerated, and the DEHY-1 and DEHY-2 still columns vent through their respective emissions control
devices. The hydrocarbon liquid that condenses in the refrigeration plant is sent to a deethanizer column
where a Y -grade natural gas liquid (NGL) product is produced. The NGL is stored in 90,000 -gallon
storage tanks from which it is shipped to market via pipeline. The vapors from the deethanizer column
are combined with the residue gas from the refrigeration cycle and sent to a third -party residue pipeline.
A portion of the residue gas is routed to an amine unit (AMINE -1) to remove carbon dioxide and then
recombined with the residue gas stream to meet the sales specifications for carbon dioxide. The heat for
the process is provided by a 43.64 MMBtu/hr hot oil heater (HTR-1A). In summary, the equipment at
the Redtail Gas Plant covered under this Operating Permit includes: fugitive VOC from equipment leaks
from the natural gas processing plant, one (1) diesel -fired 361 HP engine, one (1) process flare, one (1)
natural gas -fired hot oil heater, two (2) ethylene glycol natural gas dehydration units, one (1) MDEA
Natural gas sweetening unit, and two (2) produced water storage tanks.
At the Razor 21 Central Production Battery, a combined stream of liquids and natural gas is extracted
from the wells located at Razor 21A, Razor 21B, Razor 21C, and Razor 21D (future) and transferred to
2 -phase separators where the gas is separated from the liquids. The liquids are transferred to heater
treaters that are equipped with burners to facilitate further separation into streams of gas, crude oil, and
produced water. Some of the produced gas is sent to the gas lift engine where it is compressed and re-
injected into the wells, and the remainder of the produced gas is routed to the Redtail Gas Plant. When
the gas gathering system or Redtail Gas Plant is not available to receive produced gas, it is routed to the
Backup/Emergency Flare (RZ-FLR-1). The separated streams of crude oil and produced water are
transferred to storage tanks. Crude oil is subsequently transferred by pipeline using a lease automatic
custody transfer (LACT) unit, or by truck loadout when the pipeline is unable to receive oil. Produced
water is subsequently transferred offsite by pipeline or by truck when the pipeline is unable to receive
produced water. Vapors generated in the crude oil and produced water storage tanks are captured by
enclosed combustors (RZ-COMB-1, RZ-COMB-2). The CPB is powered by grid electricity. In
summary, the equipment at the Razor 21 Central Production Battery covered under this Operating
Permit includes: one (1) 4SLB 1311 HP engine, eight (8) separators controlled by a flare, and twenty-
two (22) produced water storage tanks and thirty-two (32) crude oil storage tanks controlled by enclosed
combustors.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 5
The Redtail Facility is located approximately 15 miles north of Raymer, Colorado in Weld County. The
area in which the facility operates is designated as attainment of all criteria pollutants.
Wyoming and Nebraska are affected states within 50 miles of the facility. There are no Federal Class 1
or Class II designated areas within 100 kilometers of the 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: 13WE3003, 13WE3004, 13WE3005, 13WE3006, 13WE3007, 13WE1130,
14WE0891, 14WE0892, 13WE1682, 14WE0889, 14WE0893, 13WE3008.
1.4 All conditions in this permit are enforceable by US Environmental Protection Agency, Colorado Air
Pollution Control Division (hereinafter Division) and its agents, and citizens unless otherwise specified.
State -only enforceable conditions are: Permit Condition Number(s): Section II — Conditions 3.8, 5.9,
7.4, 9.8, 9.9, 10.4, 11.7, 14, 15, and 16 & Section IV - Conditions 3.g (last paragraph), 14 & 18 (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
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 6
The following AOS is incorporated into this permit in order to deal with a compressor engine
breakdown or periodic routine maintenance and repair of an existing onsite engine that requires the use
of either a temporary or permanent replacement engine. "Temporary" is defined as in the same service
for 90 operating days or less in any 12 -month period. "Permanent" is defined as in the same service for
more than 90 operating days in any 12 -month period. The 90 days is the total number of days that the
engine is in operation. If the engine operates only part of a day, that day shall count as a single day
towards the 90 -day total. The compliance demonstrations and any periodic monitoring required by this
AOS are in addition to any compliance demonstrations or periodic monitoring required by this permit.
All replacement engines are subject to all federally applicable and state -only requirements set forth in
this permit (including monitoring and record keeping) 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, 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 emissions from the temporary replacement engine comply
with the emission limitations for the existing permitted engine as determined in section 2.2.
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 emissions from the permanent replacement engine
comply with 1) the permitted annual emission limitations for the existing engine, 2) any
permitted short-term emission limitations for the existing permitted engine, and 3) the applicable
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 7
emission limitations as set forth in Appendix G. Measurement of emissions from the permanent
replacement engine and compliance with the applicable emission limitations shall be made as set
forth in section 2.2.
An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and
serial number and horsepower of the permanent replacement engine shall be filed with the
Division for the permanent replacement engine within 14 calendar days of commencing
operation of the replacement engine. The APEN shall be accompanied by the appropriate APEN
filing fee, a cover letter explaining that the 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.
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 website at:
http://www.cdphe.state.co.us/ap/down/portanalyzeproto.pdf
Results of the portable analyzer tests shall be used to monitor the compliance status of this unit.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 8
For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of
the tests shall be converted to a lb/hr basis and multiplied by the allowable operating hours in the month
or year (whichever applies) in order to monitor compliance. If a source is not limited in its hours of
operation the test results will be multiplied by the maximum number of hours in the month or year
(8760), whichever applies.
For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or
concentration based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement
engine will be subject to, the results of the test shall be converted to the appropriate units as described in
the above -mentioned Portable Analyzer Monitoring Protocol document.
If the portable analyzer results indicate compliance with both the NOx and CO emission limitations, in
the absence of credible evidence to the contrary, the source may certify that the engine is in compliance
with both the NOx and CO emission limitations for the relevant time period.
Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if
the portable analyzer results fail to demonstrate compliance with either the NOx or CO emission
limitations, the engine will be considered to be out of compliance from the date of the portable analyzer
test until a portable analyzer test indicates compliance with both the NOx and CO emission limitations
or until the engine is taken offline.
2.3 Applicable Regulations for Permanent Engine Replacements
2.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § II.D.2
All permanent replacement engines that are located in an area that is classified as
attainment/maintenance or nonattainment must apply Reasonably Available Control Technology
(RACT) for the pollutants for which the area is attainment/maintenance or nonattainment. Note
that both VOC and NOx are precursors for ozone. RACT shall be applied for any level of
emissions of the pollutant for which the area is in attainment/maintenance or nonattainment,
except as follows:
In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PM10 at any
level of emissions and to NOx and SO2, as precursors to PM10, if the potential to emit of NOx or
SO2 exceeds 40 tons/yr.
For purposes of this AOS, the following shall be considered RACT for natural-gas fired
reciprocating internal combustion engines:
VOC: The emission limitations in NSPS JJJJ
CO: The emission limitations in NSPS JJJJ
NOx: The emission limitations in NSPS JJJJ
SO2: Use of natural gas as fuel
PM10: Use of natural gas as fuel
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 9
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 XVII.E
(State -Only conditions).
Control Requirements: Section XVI
Any permanent replacement engine located within the boundaries of an ozone nonattainment
area is subject to the applicable control requirements specified in Regulation No. 7, section XVI,
as specified below:
Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non -selective
catalyst and air fuel controller to reduce emission.
Lean burn engines with a manufacturer's design rate greater than 500 hp shall use an oxidation
catalyst to reduce emissions.
The above emission control equipment shall be appropriately sized for the engine and shall be
operated and maintained according to manufacturer specifications.
The source shall submit copies of the relevant Applicability Reports required under Condition
2.1.2.
Emission Standards: Section XVII.E — State -only requirements
Any permanent engine that is either constructed or relocated to the state of Colorado from
another state, after the date listed in the table below shall operate and maintain each engine
according to the manufacturer's written instructions or procedures to the extent practicable and
consistent with technological limitations and good engineering and maintenance practices over
the entire life of the engine so that it achieves the emission standards required in the table below:
Max Engine
HP
Construction or
Relocation Date
Emission Standards in G/hp-hr
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 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 10
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 40 CFR 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.B. that Relocation of a
source from outside of the State of Colorado into the State of Colorado is considered to be a new
source, subject to the requirements of Regulation No. 6 (i.e., the date that the source is first
relocated to Colorado becomes equivalent to the manufacture date for purposes of determining
the applicability of NSPS JJJJ requirements).
However, as of November 1, 2008 the Division has not yet adopted NSPS JJJJ. Until such time
as it does, any engine subject to NSPS will be subject only ender Federal law. Once the Division
adopts NSPS JJJJ, there will be an additional step added to the determination of the NSPS.
Under the provisions of Regulation No. 6, Part B, § I.B (which is referenced in Part A), any
engine relocated from outside of the State of Colorado into the State of Colorado is considered to
be a new source, subject to the requirements of NSPS JJJJ.
2.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ
2.3.4.1 Area Source for HAPs
A permanent replacement engine located at an area source that commenced
construction or reconstruction after June 12, 20015 as defined in § 63.2, will meet the
requirements of 40 CFR Part 63, Subpart ZZZZ by meeting the requirements of 40
CFR Part 60, Subpart JJJJ. 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 ADS. 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.
2.3.4.2 Major Source for HAPs
A permanent replacement engine that is located at major source is subject to the
requirements in 40 CFR Part 63 Subpart ZZZZ as follows:
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 11
Existing, new or reconstructed spark ignition 4 stroke rich burn engines with a site
rating of more than 500 hp are subject to the requirements in 40 CFR Part 63 Subpart
ZZZZ.
New or reconstructed (construction or reconstruction commenced after 12/19/02) 2
stroke and 4 stroke lean burn engines with a site rating of more than 500 hp are
subject to the requirements in 40 CFR Part 63 Subpart ZZZZ.
New or reconstructed (construction or reconstruction commenced after 6/12/06) 4
stroke lean burn engines with a site rating of greater than or equal to 250 but less or
equal to 500 hp and were manufactured on or after 1/1/08 are subject to the
requirements in 40 CFR Part 63 Subpart ZZZZ.
New or reconstructed (construction or reconstruction commenced after 6/12/06) 2
stroke lean burn or 4 stroke rich burn engines with a site rating of 500 hp or less will
meet the requirements of 40 CFR 63, Subpart ZZZZ by meeting the requirements of
40 CFR 60, Subpart JJJJ.
New or reconstructed (construction or reconstruction commenced after 6/12/06) 4
stroke lean burn engines with a site rating of less than 250 hp will meet the
requirements of 40 CFR 63, Subpart ZZZZ by meeting the requirements of 40 CFR
60, Subpart JJJJ.
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.
Table 1
Internal Combustion Engine Information for the AOS
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 12
Emission
Point
Replacement Engine
Periodic Monitoring?
Subject to CAM?
021
Caterpillar G3516 (1311 HP) with Oxidizing
Catalyst
Portable Monitoring
Quarterly
No
3. Prevention of Significant Deterioration
3.1 This facility is located in an area designated attainment for all pollutants. Based on the information
provided by the applicant, this source is categorized as a minor stationary source for PSD as of the issue
date of this permit. Any future modification which is major by itself (Potential to Emit > 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.
3.2 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:
None. This is the first issuance and no emission units have controlled emissions greater than
permitting thresholds.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
6. Summary of Emission Units
6.1 The emissions units regulated by this permit are the following:
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 13
Facility
ID
AIRS ID
Description
Pollution Control
Redtail Gas Plant
FUG -1
009
Equipment Leaks (fugitive VOCs) from a natural gas
processing plant.
None
GEN-2
011
One (1) Generac SD025OKG178.7D18HPYY3, diesel-
fired, reciprocating internal combustion engine, having a
site rated output at or below 361 I -1P or 250 kW, powering a
generator set. This engine is equipped with no controls.
This emission unit is used as an emergency generator,
running all electrical services at the office building. This
engine is subject to NSPS IIII Tier 3 Standards.
SN: 8608041
None
FLR-1A
013
Process flare (Tornado, Air -Assist, FL -8540) controlling
emissions from routine operations including: purge gas,
emissions from electric compressor and amine blowdowns,
and plant blowdowns. The flare has a minimum
combustion efficiency of 95%. The flare is not enclosed.
SN: 14180
None
HTR-1A
014
One (1) Zeeco hot oil heater, Model: GLSF14, with a total
design heat input rate of 43.64 MMBtu/hr. This heater is
fueled by natural gas. This heater is equipped with low
NOx burners.
Serial Number: J131132
None
DENY -1
015
One (1) Ethylene Glycol (EG), natural gas dehydration unit
(Alco, FAB38-20B) with a design capacity of 35.0 MMscf
per day. This emissions unit is equipped with two (2) Bear
CX-5H Duplex electric -glycol pumps with a design
capacity of 6 gal/min. This unit is equipped with a flash
tank, an oil -heated reboiler and still vent. The oil -heated
reboiler is covered under a separate point (AIRS 014)
SN: 2012-8390-12
Flash Tank:
Recycled to plant
inlet or plant flare
(AIRS 013) as
backup
Still Vent: Enclosed
Combustor or plant
flare (AIRS 013) as
backup
DENY -2
016
One (1) Ethylene Glycol (EG), natural gas dehydration unit
(Alco) with a design capacity of 70 MMscf per day. This
emissions unit is equipped with two (2) Bear CX-5H
Duplex electric -glycol pumps with a design capacity of 18
gal/min. This unit is equipped with a flash tank, an oil-
heated reboiler, and still vent. The oil heater for the reboiler
is covered under a separate point (AIRS 014)
SN: 2013-8482-12
Flash Tank:
Recycled to plant
inlet or plant flare
(AIRS 013) as
backup
Still Vent: Enclosed
Combustor or plant
flare (AIRS 013) as
backup
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 14
Facility
ID
AIRS ID
Description
Pollution Control
Redtail Gas Plant
AMINE -1
017
Methyldiethanolamine (MDEA) natural gas sweetening
system for acid gas removal with a design capacity of 45
MMSCF per day. This emissions unit is equipped with two
(2) electric amine recirculation pumps with a total design
capacity of 201 gallons per minute. This system includes a
natural gas/amine contactor, a flash tank, and an oil -heated
amine regeneration reboiler. The oil heater for the reboiler
is covered under a separate point (AIRS Point 014).
SN: 2007-7722-02
Flash: Recycled to
plant inlet or plant
flare (AIRS 013) as
backup
Still: Thermal
oxidizer or plant
flare (AIRS 013) as
backup
PW-1,
PW-2
018
Two (2) 400 BBL fixed roof storage tanks used to store
produced water.
Combustor
Razor 21 Central Production Battery
RZ-ENG-
0IA
021
One (1) Caterpillar, Model G3516, natural gas -fired, turbo-
charged, 4SLB reciprocating internal combustion engine,
site rated at 1311 horsepower
SN: JEF3168
Oxidation Catalyst
RZ-SEP-
1 through
RZ-SEP-
8, RZ-
FLR-1
023
Separators controlled by a 40' flare stack. Flare has a
minimum combustion efficiency of 95%. The flare is not
enclosed.
Open Flare
RZ-PW-1
through
RZ-PW-
22
024
Twenty-two (22) 400 BBL fixed roof storage tanks used to
store produced water.
Enclosed Combustor
RZ-TK-1
through
RZ-TK-
32
025
Thirty-two (32) 400 BBL fixed roof storage tanks used to
store crude oil.
Enclosed Combustor
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
SECTION II - Specific Permit Terms
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 15
1. 009 — Fugitive Volatile Organic Compounds from Equipment Leaks at the Redtail Gas Plant (FUG -
1)
1.1
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
VOC Emissions
1.1
74.0 tons/year
By Component Type —
HAP Emissions
1.2
See Condition 1.2
EPA Protocol for
Equipment Leak
Estimates
Recordkeeping and
Calculation
Monthly
Extended Wet Gas
Analysis
1.3
See Condition 1.3
40 CFR Part 60
Subpart OOOO
1.4
See Condition 1.4
40 CFR Part 60
Subpart A
1.5
See Condition 1.5
Emissions of Volatile Organic Compounds from equipment leaks must not exceed the limitations in
Summary Table 1 above (Colorado Construction Permit 13 WE1130, as modified under the provisions of
Section I, Condition 1.3 to removed monthly limits). Emissions must be calculated monthly using the
emission factors and equations below. Records of these calculations must be kept at the site or a local
field office with site responsibility and made available to the Division for review upon request.
Emission factors for individual types of components from the reference Protocol for Equipment Leak
Emission Estimates (EPA -453/R-95-017, Table 2-4, November 1999, converted to lbs/component-hr).
The most appropriate emissions factors from the EPA document shall be used:
Emission Factor (lb/component-hr)
Component Type
Gas
Service
Heavy Oil
Service
Light Oil Service
Water/Oil
Service
Connectors
9.07E-05
3.40E-06
9.53E-05
4.99E-05
Flanges
1.77E-04
1.77E-07
4.99E-05
1.32E-06
Open-ended Lines
9.07E-04
6.35E-05
6.35E-04
1.13E-04
Pump Seals
1.09E-03
N/A
5.90E-03
1.09E-05
Valves
2.04E-03
3.81E-06
1.13E-03
4.45E-05
Other*
3.99E-03
1.45E-05
3.40E-03
6.35E-03
* Other should be applied for any equipment type other than connectors, flanges, open-ended lines,
pumps, or valves.
Calculation of monthly emissions of VOC and HAPs per component shall use the following equation:
VOC or HAP emissions (lb) per Component Type (gas service):
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
lb)Emissions (—/ yr
lb hrs
= # of Components x EF x 8760—x VOC or HAP Fraction x Granted Control %
component — hr yr
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 16
VOC or HAP emissions (lb) per Component Type (light oil service):
lb\
Emissions (—)
— I
yr/
lb hrs
= # of Components x EF x 8760 —x VOC or HAP Fraction x Granted Control %
component — hr yr
Total fugitive VOC emissions shall be the sum of emissions for each component.
Presuming the Leak Detection and Repair Program monitoring requirements of Condition 1.4 are
satisfied, the permittee may calculate the monthly emissions required by this Condition 1.1 using the
control effectiveness percentages of Table 5-3 of EPA -453/R-95-017. The control effectiveness
percentages granted for the Redtail Gas Plant are as follows:
Fugitive Components
controlled
Control Percentage
Granted
Valves — Gas Service
70
Valves — Light Liquid
Service
61
Pumps — Light Liquid
Service
45
Monthly emissions must be used in a twelve-month rolling total to monitor compliance with the annual
emission limitations. Each month, a new twelve-month total must be calculated using the previous
twelve months' data. Records of calculations must be kept in a log to be made available to the Division
upon request.
The items below must be monitored, recorded, and utilized to calculation VOC and HAP emissions as
required by this Condition 1.1:
1.1.1 The most recent gas analysis as required by Conditions 1.3 of this permit must be used to
determine the appropriate VOC and HAP fractions to use in the above equation.
1.1.2 A component count must be conducted within one year of issuance of this permit (DRAFT) and
every five (5) years thereafter to verify existing components and inventory. The operator must
maintain records of the results of component counts used to calculate actual emissions and the
dates that these counts and event were completed. These records must be provided to the
Division upon request.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 17
1.1.3 A running total must be kept of all additions and subtractions to the component count. The most
recent extended gas analysis and count (as required by Conditions 1.1.1 and 1.1.2, respectively)
must be used for emission calculations and compliance purposes. Records of this running total
must be provided to the Division upon request.
1.2 Emissions of Hazardous Air Pollutants (HAPs) from this emission point are subject to the facility -wide
HAP limits of Condition 12.1 (Colorado Construction Permit 13WE1130, as modified under the
provisions of Section I, Condition 1.3 to add the individual and total HAP limits to 9 tpy and 24 tpy,
respectively for consistency with more recently issued construction permits: 13WE3003, 13WE3005,
13WE3006, 13WE3007, 14WE0891, 14WE0892, and 14WE0893). For the purposes of calculating
monthly HAP emissions as required by Condition 12.1, each HAP fraction from the most recent
extended gas analysis as required by Condition 1.3 must be utilized in the calculation methodology
indicated in Condition 1.1 (Colorado Construction Permit 13WE1130).
1.3 The permittee must conduct an extended gas analysis of gas samples that are representative of volatile
organic compounds (VOC) and hazardous air pollutants (HAPs) that may be released as fugitive
emissions (inlet gas and residue gas services) annually in accordance with the requirements of Condition
12.2. The most recent extended gas analysis must be used to monitor compliance with the annual
emission limits as required by Condition 1.1 (Colorado Construction Permit 13WE1130).
1.4 The fugitive VOC emissions from equipment at the Redtail Gas Plant are subject to the applicable
requirements of New Source Performance Standards of 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, 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 the 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.
What equipment leak standards apply to affected facilities at an onshore natural gas processing plant
060.5400)
This section applies to the group of all equipment, except compressors, within a process unit.
1.4.1 You must comply with the requirements of §§60.482-1a(a), (b), and (d), 60.482-2a, and 60.482-
4a through 60.482-1 la, except as provided in §60.5401 (§60.5400(a)).
1.4.2 You may elect to comply with the requirements of §§60.483-1a and 60.483-2a, as an alternative
(§60.5400(b)).
1.4.3 You may apply to the Administrator for permission to use an alternative means of emission
limitation that achieves a reduction in emissions of VOC at least equivalent to that achieved by
the controls required in this subpart according to the requirements of §60.5402 of this subpart
(§60.5400(c)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 18
1.4.4 You must comply with the provisions of §60.485a of this part except as provided in paragraph (f)
of this section (§60.5400(d)).
1.4.5 You must comply with the provisions of §§60.486a and 60.487a of this part except as provided
in §§60.5401, 60.5421, and 60.5422 of this part (§60.5400(e)).
1.4.6 You must use the following provision instead of §60.485a(d)(1): Each piece of equipment is
presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates
that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment
to be considered not in VOC service, it must be determined that the VOC content can be
reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be
considered in wet gas service, it must be determined that it contains or contacts the field gas
before the extraction step in the process. For purposes of determining the percent VOC content
of the process fluid that is contained in or contacts a piece of equipment, procedures that
conform to the methods described in ASTM E169-93, E168-92, or E260-96 (incorporated by
reference as specified in §60.17) must be used (§60.5400(f)).
What standards apply to reciprocating compressor affected facilities 060.5385)
The following requirements apply to all reciprocating compressors located at the Redtail Gas Plant and
grouped within the fugitive emissions addressed by AIRS 009.
1.4.7 You must replace the reciprocating compressor rod packing according to either paragraph (a)(1)
or (2) of this section or you must comply with paragraph (a)(3) of this section (§60.5385(a))
1.4.7.1 Before the compressor has operated for 26,000 hours. The number of hours of operation
must be continuously monitored beginning upon initial startup of you 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)).
1.4.7.2 Prior to 36 months from the date of the most recent rod packing replacement, or 36
months from the date of startup for a new reciprocating compressor for which the rod
packing has not yet been replaced (§60.5385(a)(2)).
1.4.7.3 Collect the emissions from the rod packing using a rod packing emissions collection
system which operated 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)
(§60.5385(a)(3)).
1.4.8 You must demonstrate initial compliance with standards that apply to reciprocating compressor
affected facilities as required by §60.5410 (§60.5385(b)).
1.4.9 You must demonstrate continuous compliance with standards that apply to reciprocating
compressor affected facilities as required by §60.5415 (§60.5385(c)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 19
1.4.10 You must perform the required notification, recordkeeping, and reporting as required by
§60.5420 (§60.5385(d)).
How do I demonstrate initial compliance with the standards for my gas well affected facility, my
centrifugal compressor affected facility, my reciprocating compressor affected facility, my pneumatic
controller affected facility, my storage vessel affected facility, and my equipment leaks and sweetening
unit affected facilities at onshore natural gas processing plants? (00.5410)
1.4.11 You must determine initial compliance with the standards for each affected facility using the
requirements in paragraphs (a) through (i) 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 not later than one year after October 15,
2012. The initial compliance period may be less than one full year.
1.4.11.1 To achieve initial compliance with the standards for each reciprocating compressor
affected facility you must comply with paragraphs (c)(1) through (4) of this section
(60.5410(c)).
a. If complying with §60.5385(a)(1) or (2), during 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), you must operate the rod packing replacement
emissions collection system under negative pressure and route emissions to a
process through a closed vent system that meets the requirements of §60.5420(b)
(§60.5410(c)(2)).
c. You must submit the initial annual report for your reciprocating compressor as
required in §60.5420(b) (§60.5385(c)(3)).
d. You must maintain the records as specified in §60.5420(c)(3)) for each reciprocating
compressor affected facility (§60.5410(c)(4)).
1.4.11.2 For affected facilities at onshore natural gas processing plants, initial compliance with
the VOC requirements is demonstrated if you are in compliance with the requirements
of §60.5400 (§60.5410(f)).
How do I demonstrate continuous compliance with the standards for my gas well affected facility, my
centrifugal compressor affected facility, my stationary reciprocating compressor affected facility, my
pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at
onshore natural gas processing plants? 060.5415)
1.4.12 For each reciprocating compressor grouped with the fugitive emissions addressed by AIRS 009
and complying with §60.5385(a)(1) or (2), you must demonstrate continuous compliance
according paragraphs (c)(1) through (3) of this section. For each reciprocating compressor
affected facility complying with §60.5385(a)(3), you must demonstrate continuous compliance
according to paragraph (c)(4) of §60.5415.
1.4.12.1 You must continuously monitor the number of hours of operation for each reciprocating
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 20
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)).
1.4.12.2 You must submit the annual report as required in §60.5420(b) and maintain records as
required in §60.5420(c)(3) (§60.5415(c)(2)).
1.4.12.3 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)).
1.4.12.4 You must operate the rod packing emissions collection system under negative pressure
and continuously comply with the closed vent requirements in §60.5416(a) and (b)
(§60.5415(c)(4)).
1.4.13 For affected facilities at onshore natural gas processing plants, continuous compliance with VOC
requirements is demonstrated if you are in compliance with the requirements of §60.5400
(§60.5415(f)).
What are the initial and continuous cover and closed vent system inspection and monitoring
requirements for my storage vessel, centrifugal compressor and reciprocating compressor affected
facilities? (60.5416)
For each closed vent system or cover at your storage vessel, centrifugal compressor and reciprocating
compressor affect facility, you must comply with the applicable requirements of paragraphs (a) through
(c) of this section.
1.4.14 Inspections for closed vent systems and covers on each centrifugal compressor or reciprocating
compressor affected facility. Except as provided in paragraphs (b)(11) and (12) of this section,
you must inspect each closed vent system according to the procedures and schedule specified in
paragraphs (a)(1) and (2) of this section, inspect each cover according to the procedures and
schedule specified in paragraph (a)(3) of this section, and inspect each bypass device according
to the procedures of paragraph (a)(4) of this section (§60.5416(a)).
1.4.14.1 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 or heard piping or
a bolted and gasketed ducting flange), you must meet the requirements specified in
paragraphs (a)(1)(i) and (ii) of this section (§60.5416(a)(1)).
1.4.14.2 For closed vent system components other than those specified in paragraph (a)(1) of
this section, you must meet the requirements of paragraphs (a)(2)(i) through (iii) of this
section (§60.5416(a)(2)).
1.4.14.3 For each cover, you must meet the requirements in paragraphs (a)(3)(i) and (ii) of this
section (§60.5416(a)(3)).
1.4.14.4 For each bypass device, except as provided for in §60.5411, you must meet the
requirements of paragraph (a)(4)(i) or (ii) of this section (§60.5416(a)(4)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 21
1.4.15 No detectable emissions test methods and procedures. If you are required to conduct an
inspection of a closed vent system or cover at you centrifugal compressor or reciprocating
compressor affected facility as specified in paragraphs (a)(1), (2), or (3) of this section, you must
meet the requirements of paragraphs (b)(1) through (14) of this section (§60.5416(b)).
What are my notification, reporting, and recordkeeping requirements (60.5420)
1.4.16 You must submit the notifications according to paragraphs (a)(1) and (2) of this section if you
own or operate one or more of the affected facilities in §60.5365 that was constructed, modified,
or reconstructed during the reporting period (§60.5420(a)).
1.4.16.1 If you own or operate a gas well, pneumatic controller, centrifugal compressor,
reciprocated compressor or storage vessel affected facility you are not required to
submit the notifications required in §60.7(a)(1), (3), and (4) (§60.5420(a)(1)).
1.4.17 Reporting requirements. You must submit annual reports containing the information specified in
paragraphs (b)(1) through (6) of §60.5420 to the Administrator and performance test reports as
specified in paragraph (b)(7) or (8) of §60.5420. 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.
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 the information required as specified in
paragraphs (b)(1) through (6) of §60.5420. 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)).
1.4.17.1 The general information specified in paragraphs (b)(1)(i) through (iv) (Conditions
1.4.17.1.a through 1.4.17.1.d) of §60.5420 (§60.5420(b)(1)).
a. The company name and address of the affected facility (§60.5420(b)(1)(i)).
b. An identification of each affected facility being included in the annual report
(§60.5420(b)(1)(ii)).
c. Beginning and ending dates of the reporting period (§60.5420(b)(1)(iii)).
d. A certification by a certifying official of truth, accuracy, and completeness. This
certification shall state that, based on information and belief formed after
reasonable inquiry, the statements and information in the document are true,
accurate, and complete (§60.5420(b)(1)(iv)).
1.4.17.2 For each reciprocating compressor affected facility, the information specified in
paragraphs (b)(4)(i) through (ii) (Conditions 1.4.17.2.a and 1.4.17.4.b) of
§60.5420(b)(4) (§60.5420(b)(4)).
a. The cumulative number of hours of operation or the number of months since initial
startup, since October 15, 2012, or since the previous reciprocating compressor rod
packing replacement, whichever is later (§60.5420(b)(4)(i)).
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b. Records of deviations specified in paragraph (c)(3)(iii) of this section that occurred
during the reporting period (§60.5420(b)(4)(ii)).
1.4.18 Recordkeeping requirements. You must maintain the records identified as specified in §60.7(f)
and in paragraphs (c)(1) through (14) 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)).
1.4.18.1 For each reciprocating compressors affected facility, you must maintain the records in
paragraph (c)(3)(i) through (iii) 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 pacing
replacement, or date of installation of a rod packing emissions collection system
and closed vent system as specified in §60.5385(a)(3) (§60.5420(c)(3)(ii)).
c. Records of deviation in cases where the reciprocating compressor was not operated
in compliance with the requirements specified in §60.5385 (§60.5420(c)(3)(iii)).
1.4.18.2 Records of each closed vent system inspection required under §60.5416(a)(1) and (2)
for centrifugal or reciprocating compressors or §60.5416(c)(1) for storage vessels
(§60.5420(c)(6)).
1.4.18.3 A record of each cover inspection required under §60.5416(a)(3) for centrifugal or
reciprocating compressors or §60.5416(c)(2) for storage vessels (§60.5420(c)(7)).
1.4.18.4 If you are subject to the bypass requirements of §60.5416(a)(4) for centrifugal or
reciprocating compressor or §60.5416(c)(3) for storage vessels, a record of each
inspection or a record of each time the key is checked out or a record of each time the
alarm is sounded (§60.5420(c)(8)).
1.4.18.5 If you are subject to the closed vent system no detectable emissions requirements of
§60.5416(b) for centrifugal or reciprocating compressor, a record of the monitoring
conducted in accordance with §60.5416(b) (§60.5420(c)(9)).
1.4.18.6 A log of records as specified in §§60.5412(d)(1)(iii) and 60.5413(e)(4) for all
inspection, repair, and maintenance activities for each control device filing the visible
emissions test (§60.5420(c)(14)).
What are my additional recordkeeping requirements for my affected facility subject to VOC
requirements for onshore natural gas processing plants? (60.5421)
1.4.19 You must comply with the requirements of paragraph (b) of §60.5421 in addition to the
requirements of §60.486(a) (§60.5421(a)).
1.4.20 The following recordkeeping requirements apply to pressure relief devices subject to the
requirements of §60.5401(b)(1) of this subpart (§60.5421(b)).
1.4.20.1 When each leak is detected as specified in §60.5401(b)(2), a weatherproof and readily
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1.4.20.2
visible identification, marked with the equipment identification number, must be
attached to the leaking equipment. The identification on the pressure relief device may
be removed after it has been repaired (§60.5421(b)(1)).
When each leak is detected as specified in §60.5401(b)(2), the following information
must be recorded in a log and shall be kept for 2 years in a readily accessible location
(§60.5421(b)(2)):
a. The instrument and operator identification numbers and the equipment identification
number (§60.5421(b)(2)(i)).
b. The date the leak was detected and the dates of each attempt to repair the leak
(§60.5421(b)(2)(ii)).
c. Repair methods applied in each attempt to repair the leak (§60.5421(b)(2)(iii)).
d. "Above 500 ppm" if the maximum instrument reading measured by the methods
specified in paragraph (a) of this section after each repair attempt is 500 ppm or
greater (§60.5421(b)(2)(iv)).
e. "Repair delayed" and the reason for the delay if a leak is not repaired within 15
calendar days after discovery of the leak (§60.5421(b)(2)(v)).
f. The signature of the owner or operator (or designate) whose decision it was that
repair could not be effected without a process shutdown (§60.5421(b)(2)(vi)).
The expected date of successful repair of the leak if a leak is not repaired within 15
days (§60.5421(b)(2)(vii)).
h. Dates of process unit shutdowns that occur while the equipment is unrepaired
(§60.5421(b)(2)(viii)).
i. The date of successful repair of the leak (§60.5421(b)(2)(ix)).
g.
J.
A list of identification numbers for equipment that are designated for no detectable
emissions under the provisions of §60.482-4a(a). The designation of equipment
subject to the provisions of §60.482-4a(a) must be signed by the owner or operator
(§60.5421(b)(2)(x)).
What are my additional reporting requirements for my affected facility subject to VOC requirements for
onshore natural gas processing plants? 060.5422)
1.4.21 You must comply with the requirements of paragraphs (b) and (c) of this section in addition to
the requirements of §60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii)
(§60.5422(a)).
1.4.22 An owner or operator must include the following information in the initial semiannual report in
addition to the information required in §60.487a(b)(1) through (4): Number of pressure relief
devices subject to the requirements of §60.5401(b) except for those pressure relief devices
designated for no detectable emissions under the provisions of §60.482-4a(a) and those pressure
relief devices complying with §60.482-4a(c) (§60.5422(b)).
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Whiting Oil and Gas Corporation
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1.4.23 An owner or operator must include the following information in all semiannual reports in
addition to the information required in §60.487a(c)(2)(i) through (vi) (§60.5422(c)):
1.4.23.1 Number of pressure relief devices for which leaks were detected as required in
§60.5401(b)(2) (§60.5422(c)(1)); and
1.4.23.2 Number of pressure relief devices for which leaks were not repaired as required in
§60.5401(b)(3) (§60.5422(c)(2)).
What part of the General Provisions apply to me? (60.5425)
1.4.24 Table 3 to Subpart OOOO shows which parts of the General Provisions in §§60.1 through 60.19
apply to you.
1.5 These fugitive emissions are subject to the applicable requirements of General Provisions of 40 CFR
Part 60 Subpart A (40 CFR 60.1 through 60.19, as adopted by reference in Colorado Regulation No. 6,
Part A, Subpart A) as incorporated in Condition 17.
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Colorado Operating Permit
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2. 011 — Generac, Diesel -Fired, at or below 250 kW, Compression -Ignition Internal Combustion
Engine (GEN-2)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
Emissions
Calculations
2.1
NOx - 4.0 g/kWh
CO - 3.5 g/kWh
PM - 0.2 g/kWh
VOC - 4.0 g/kWh
HAP Emissions
2.2
See Condition 2.2
SO2
2.3
0.8 lbs/MIVIBtu
Hours of Operation
2.4
300 hours/year,
except as provided in
Condition 2.6.10
Opacity
2.5
Not to Exceed 20%,
Except as Provided
for Below
For Start-up — Not to
Exceed 30% for a
Period or Periods
Aggregating More
than Six (6) Minutes
in any 60
Consecutive Minutes
Recordkeeping and
Calculation
Annually
Fuel Restriction
Only Diesel
Fuel is Used as
Fuel
Non-Resettable
Hour Meter
Annually
EPA Method 9
See Condition
2.5
40 CFR Part 60
Subpart IIII
2.6
40 CFR Part 60
Subpart A
2.7
40 CFR Part 63
Subpart ZZZZ
2.8
See Condition 2.6
See Condition 2.7
See Condition 2.8
Note that this engine is exempt from the construction permit requirements in Regulation No. 3, Part B,
II.D.1.c as long as actual emissions do not exceed the construction permitting de minimis level.
2.1 The emission factors listed above have been approved by the Division and shall be used to calculate
emissions from this engine (PM, NOx, VOC, CO: NSPS IIII, §60.4202(a)(2)). Annual emissions for the
purposes of APEN reporting and the payment of annual fees shall be calculated using the above
emission factors and the annual hours of operation, as monitored by the requirements of Condition 2.4,
in the following equation:
Tons _ EF (kWh xHours of Operation (Year x Engine Horsepower Rating (kW)
Year 453.59 —lb* 2000 tlon
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Whiting Oil and Gas Corporation
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2.2 Emissions of Hazardous Air Pollutants (HAPs) from this engine are subject to the facility -wide HAP
limits of Condition 12.1 (Colorado Construction Permit 13WE1 682). For the purposes of calculating
monthly emissions as required by Condition 12.1 the permittee must utilize the HAP emission factors in
AP -42, Table 3.3-2 and the calculation methodology outlined in Condition 2.1.
2.3 Sulfur Dioxide (SO2) emissions from this engine must not exceed the limitation in Summary Table 2
above (Colorado Regulation No. 1, Section VI.B.4.b.(i)). In the absence of credible evidence to the
contrary, compliance with the SO2 emission limitation shall be presumed since only diesel fuel is
permitted to be used as fuel in these engines. The permittee must maintain records that verify that only
diesel fuel is used as fuel in these engines.
2.4 Hours of operation of this engine must be monitored and recorded annually in a log (as required by
Condition 2.6.6) to be made available to the Division upon request. Recorded data must be used to
calculate emissions for the determination of annual fees as specified in Condition 2.1.
2.5 This engine is subject to the following opacity requirements:
2.5.1 Except as provided for in Condition 2.5.2, no owner or operator of a stationary source shall not
allow or cause to be emitted into the atmosphere any air pollutant which is in excess of 20%
opacity (Colorado Regulation No. 1, Section II.A.1).
2.5.1.1 A Method 9 opacity observation shall be performed on this engine at least once per
calendar year of operation when the engine is operating under load during conditions
suitable for properly performing a valid Method 9 observation.
2.5.1.2 In addition, a Method 9 observation shall be performed when non -routine visible
emissions, or visible emissions that appear to be greater than 20% opacity under normal
operating conditions are detected to persist for longer than sixty (60) consecutive
minutes.
2.5.1.3 If any Method 9 observation exceeds the applicable standard, additional observations
must be performed. 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 limit 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 in Condition 2.5.1. All Method 9 observations shall be performed by a certified
observer. A clear, readable copy of the opacity observer's certification shall be kept
with the records of the Method 9 observations. The records and the copy of the
certification shall be made available for Division review upon request.
2.5.2 No owner or operator of a source shall not allow or cause to be emitted into the atmosphere any
air pollutant resulting from start-up, any process modification, or adjustment or occasional
cleaning of control equipment which is in 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).
2.5.2.1 A Method 9 observation shall be performed any time an engine start-up requires longer
Operating Permit 15OPWE394 First Issued: DRAFT
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Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
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than ten (10) consecutive minutes.
2.5.2.2 If any Method 9 observation exceeds the applicable standard, additional observations
must be performed. 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 limit 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 in Condition 2.5.2. All Method 9 observations shall be performed by a certified
observer. A clear, readable copy of the opacity observer's certification shall be kept
with the records of the Method 9 observations. The records and the copy of the
certification shall be made available for Division review upon request.
2.6 This engine is subject to the requirements of 40 CFR Part 60 Subpart IIII, "Standards of Performance for
Stationary Compression Ignition Internal Combustion Engines". These requirements include, but are not
limited to, the following:
The requirements below reflect the current rule language as of the revisions to 40 CFR Part 60 Subpart
IIII published in the Federal Register on November 13, 2019. However, if revisions to the 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 IIII.
The D. C. Circuit Court issued a mandate on May 4, 2016 for vacatur for certain requirements allowing
emergency engines to operate for limited hours for demand response. Upon issuance of the mandate §
60.4211(f)(2)(ii)-(iii) (Conditions 2.6.10.2b and 2.6.10.2c) have no legal effect. Operation of emergency
engines is limited to emergency situations specified in 60.4211(O(1) (Condition 2.6.10.1); maintenance
checks and readiness testing for a limited number of hours per year as specified in 60.4211(O(2)(i)
(Condition 2.6.10.2a); and certain non -emergency situations for a limited number of hours per year as
specified in 60.4211(O(3) (Condition 2.6.10.3). See EPA memorandum dated April 15, 2016 regarding
"Guidance on Vacatur of RICE NESHAP and NSPS Provisions for Emergency Engines" for more
information.
It should be noted that additional revisions to the requirements in 40 CFR Part 60 Subpart IIII are
expected to be made in response to issues related to legal action associated with the allowable hours of
operation provisions for emergency engines regarding engines used for demand response. If such
revisions are finalized prior to issuance of the permit, they will be included in the permit.
These requirements included in this Condition 2.6 are only federally enforceable. As of the date of
permit issuance (DRAFT), the requirements in 40 CFR Part 60 Subpart IIII promulgated after July 1,
2015 have not been adopted into Colorado Regulation No. 6, Part B by the Division and are therefore
not state -enforceable. In the event that the Division adopts these requirements they will become state -
enforceable.
Am I subject to this subpart? (63.4200)
2.6.1 The provisions of this subpart are applicable to manufacturers, owners, and operators of
stationary compression ignition (CI) internal combustion engines (ICE) and other persons as
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specified in paragraphs (a)(1) through (4) of §60.4200. For the purposes of Subpart IIII, the date
that construction commences is the date the engine is ordered by the owner or operator
(§60.4200(a)).
2.6.1.1 Owners and operators of stationary CI ICE that commence construction after July 11,
2005, where the stationary CI ICE are manufactured after April 1, 2006, and are not
fire pump engines (§60.4200(a)(2)(i)).
Emission Standards for Owners and Operators
2.6.2 Owners and operators of 2007 model year and later emergency stationary CI ICE with a
displacement of less than 30 liters per cylinder that are not fire pump engines must comply with
the emission standards for new nonroad CI engines in §60.4202, for all pollutants, for the same
model year and maximum engine power for their 2007 model year and later emergency
stationary CI ICE (§60.4205(b)).
2.6.3 The emission standards for new nonroad CI engines in §60.4202 are as follows:
2.6.3.1 Stationary CI internal combustion engine manufacturers must certify their 2007 model
year and later emergency stationary CI ICE with a maximum engine power less than or
equal to 2,237 KW (3,000 HP) and a displacement of less than 10 liters per cylinder
that are not fire pump engines to the emission standards specified in paragraph (a)(2)
(Condition 2.6.1) of §60.4202 (§60.4202(a)).
2.6.3.2 For engines with a maximum engine power greater than or equal to 37 KW (50 HP),
the certification emission standards for new nonroad CI engines for the same model
year and maximum engine power in 40 CFR §89.112 (Condition 2.1) and 40 CFR
§89.113 for all pollutants beginning in model year 2007 (§60.4202(a)(2)).
2.6.3.3 The certification emission standards for new nonroad CI engines in 40 CFR 89.112 are
as follows:
a. Exhaust emission from nonroad engines to which this subpart is applicable shall not
exceed the applicable exhaust emission standards contained in Table 1, as follows
(§89.112(a)):
The specific emissions limitations in Table 1 of 40 CFR 89.112 are as follows:
Rated Power 225<kW>450
Model Year 2006 and later
Tier 3 Emission Standards (g/kW-hr)
NMHC + NOx
CO
PM
4.0
3.5
0.20
2.6.4 Owners and operators of stationary CI ICE must operate and maintain stationary CI ICE that
achieve the emission standards as required in §§60.4204 and 60.4205 over the entire life of the
engine.
Fuel Requirements for Owners and Operators
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2.6.5 Beginning October 1, 2010, owners and operators of stationary CI ICE subject to Subpart IIII
with a displacement of less than 30 liters per cylinder that use diesel fuel must use diesel fuel that
meets the requirements of 40 CFR 80.510(b) for nonroad diesel fuel, except that any existing
diesel fuel purchased (or otherwise obtained) prior to October 1, 2010, may be used until
depleted (§60.4207(a)(b)).
The fuel requirements for nonroad diesel fuel listed in 40 CFR 80.510(b) are as follows:
2.6.5.1 Sulfur content of 15 ppm maximum (§80.510(b)(1)(i))
2.6.5.2 A minimum cetane index of 40 or maximum aromatic content of 35 volume percent
(§80.510(b)(2)(i), (ii))
Compliance with the above fuel use limitations must be demonstrated by maintaining records
from the vendor indicating the diesel fuel purchased for use in the engine has been tested
according to the appropriate ASTM methods, and meets the sulfur content and cetane
index/aromatic content as described.
Other Requirements for Owners and Operators
2.6.6 If you are an owner or operator of an emergency stationary CI internal combustion engine that
does not meet the standards applicable to non -emergency engines, you must install a non-
resettable hour meter prior to startup of the engine (§60.4209(a)).
2.6.7 If you are an owner or operator of a stationary CI internal combustion engine equipped with a
diesel particulate filter to comply with the emission standards in §60.4204, the diesel particulate
filter must be installed with a backpressure monitor that notifies the owner or operator when the
high backpressure limit of the engine is approached (§60.4209(b)).
Compliance Requirements
2.6.8 If you are an owner or operator and must comply with the emission standards specified in
Subpart IIII, you must do all of the following, except as permitted under paragraph (g) of this
section (§60.4211(a)):
2.6.8.1 Operate and maintain the stationary CI internal combustion engine and control device
according to the manufacturer's emission -related written instructions (§60.4211(a)(1));
2.6.8.2 Change only those emission -related settings that are permitted by the manufacturer
(§60.4211(a)(2)); and
2.6.8.3 Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you
(§60.4211(a)(3)).
2.6.9 If you are an owner or operator of a 2007 model year and later stationary CI internal combustion
engine and must comply with the emission standards specified in §60.4204(b) or §60.4205(b), or
if you are an owner or operator of a CI fire pump engine that is manufactured during or after the
model year that applies to your fire pump engine power rating in table 3 to Subpart IIII and must
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Whiting Oil and Gas Corporation
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comply with the emission standards specified in §60.4205(c), you must comply by purchasing an
engine certified to the emission standards in §60.4204(b), or §60.4205(b) or (c), as applicable,
for the same model year and maximum (or in the case of fire pumps, NFPA nameplate) engine
power. The engine must be installed and configured according to the manufacturer's emission -
related specifications, except as permitted in paragraph (g) of this section (§60.4211(c)).
2.6.10 If you own or operate an emergency stationary ICE, you must operate the emergency stationary
ICE according to the requirements in paragraphs (f)(1) through (3) of §60.4211. In order for the
engine to be considered an emergency stationary ICE under Subpart IIII, any operation other
than emergency operation, maintenance and testing, emergency demand response, and operation
in non -emergency situations for 50 hours per year, as described in paragraphs (f)(1) through (3)
of §60.4211), is prohibited. If you do not operate the engine according to the requirements in
paragraphs (f)(1) through (3) of §60.4211, the engine will not be considered an emergency
engine under Subpart IIII and must meet all requirements for non -emergency engines
(§60.4211(f)).
2.6.10.1 There is no time limit on the use of emergency stationary ICE in emergency situations
(§60.4211(f)(1)).
2.6.10.2 You may operate your emergency stationary ICE for any combination of the purposes
specified in paragraphs (f)(2)(i) through (iii) of §60.4211 for a maximum of 100 hours
per calendar year. Any operation for non -emergency situations as allowed by paragraph
(f)(3) of §60.4211 counts as part of the 100 hours per calendar year allowed by this
paragraph (f)(2) (§60.4211(f)(2)).
a. Emergency stationary ICE may be operated for maintenance checks and readiness
testing, provided that the tests are recommended by federal, state or local
government, the manufacturer, the vendor, the regional transmission organization
or equivalent balancing authority and transmission operator, or the insurance
company associated with the engine. The owner or operator may petition the
Administrator for approval of additional hours to be used for maintenance checks
and readiness testing, but a petition is not required if the owner or operator
maintains records indicating that federal, state, or local standards require
maintenance and testing of emergency ICE beyond 100 hours per calendar year
(§60.4211(f)(2)(i)).
b. Emergency stationary ICE may be operated for emergency demand response for
periods in which the Reliability Coordinator under the North American Electric
Reliability Corporation (NERC) Reliability Standard EOP-002-3, Capacity and
Energy Emergencies (incorporated by reference, see §60.17), or other authorized
entity as determined by the Reliability Coordinator, has declared an Energy
Emergency Alert Level 2 as defined in the NERC Reliability Standard EOP-002-3
(§60.4211(f)(2)(ii)).
c. Emergency stationary ICE may be operated for periods where there is a deviation of
voltage or frequency of 5 percent or greater below standard voltage or frequency
(§60.4211(f)(2)(iii)).
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2.6.10.3 Emergency stationary ICE may be operated for up to 50 hours per calendar year in non -
emergency situations. The 50 hours of operation in non -emergency situations are
counted as part of the 100 hours, per calendar year for maintenance and testing and
emergency demand response provided in paragraph (f)(2) of §60.4211. Except as
provided in paragraph (f)(3)(i) of §60.4211, the 50 hours per calendar year for non -
emergency situations cannot be used for peak shaving or non -emergency demand
response, or to generate income for a facility to an electric grid or otherwise supply
power as part of a financial arrangement with another entity (§60.4211(f)(3)).
a. The 50 hours per year for non -emergency situations can be used to supply power as
part of a financial arrangement with another entity if all of the following conditions
are met (§60.4211(f)(3)(i)):
(i) The engine is dispatched by the local balancing authority or local
transmission and distribution system operator
(§60.4211(f)(3)(i)(A));
(ii) The dispatch is intended to mitigate local transmission and/or
distribution limitations so as to avert potential voltage collapse or
line overloads that could lead to the interruption of power supply in
a local area or region (§60.4211(f)(3)(i)B)).
(iii)The dispatch follows reliability, emergency operation or similar
protocols that follow specific NERC, regional, state, public utility
commission or local standards or guidelines (§60.4211(f)(3)(i)(C)).
(iv)The power is provided only to the facility itself or to support the
local transmission and distribution system (§60.4211(f)(3)(I)(D)).
(v) The owner or operator identifies and records the entity that
dispatches the engine and the specific NERC, regional, state, public
utility commission or local standards or guidelines that are being
followed for dispatching the engine. The local balancing authority
or local transmission and distribution system operator may keep
these records on behalf of the engine owner or operator
(§60.4211(f)(3)(i)(E)).
2.6.11 If you do not install, configure, operate, and maintain your engine and control device according
to the manufacturer's emission -related written instructions, or you change emission -related
settings in a way that is not permitted by the manufacturer, you must demonstrate compliance in
accordance with the requirements of (g)(1) through (g)(3) of section §60.4211 (§60.4211(g)).
2.6.12 The requirements for operators and prohibited acts specified in 40 CFR 1039.665 apply to
owners or operators of stationary CI ICE equipped with AECDs for qualified emergency
situations as allowed by 40 CFR 1039.665 (§60.4211(h)).
Notification, Reports, and Records for Owners and Operators
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 32
2.6.13 If the stationary CI internal combustion engine is an emergency stationary internal combustion
engine, the owner or operator is not required to submit an initial notification. Starting with the
model years in table 5 to Subpart IIII, if the emergency engine does not meet the standards
applicable to non -emergency engines in the applicable model year, the owner or operator must
keep records of the operation of the engine in emergency and non -emergency service that are
recorded through the non-resettable hour meter. The owner must record the time of operation of
the engine and the reason the engine was in operation during that time (§60.4214(b)).
2.6.14 If the stationary CI internalcombustion engine is equipped with a diesel particulate filter, the
owner or operator must keep records of any corrective action taken after the backpressure
monitor has notified the owner or operator that the high backpressure limit of the engine is
approached (§60.4214(c)).
2.6.15 If you own or operate an emergency stationary CI ICE with a maximum engine power more than
100 HP that operates or is contractually obligated to be available for more than 15 hours per
calendar year for the purposes specified in §60.4211(f)(2)(ii) and (iii) or that operates for the
purposes specified in §60.4211(f)(3)(i), you must submit an annual report according to the
requirements in paragraphs (d)(1) through (3) of §60.4214 (§60.4214(d)).
2.6.16 Owners or operators of stationary CI ICE equipped with AECDs pursuant to the requirements of
40 CFR 1039.665 must report the use of AECDs as required by 40 CFR 1039.665(e)
(§60.4214(e)).
2.7 This engine is subject to the General Provisions of 40 CFR Part 60 Subpart A (40 CFR 60.1 through
60.19, as adopted by reference in Colorado Regulation No. 6, Part A, Subpart A) as specified in 40 CFR
Part 60 Subpart IIII §60.4218 and as incorporated in Condition 17.
2.8 This engine is subject to the National Emission Standards for Hazardous Air Pollutants requirements of
Regulation No. 8, Part E, Subpart ZZZZ (40 CFR Part 63, Subpart ZZZZ), 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 the Subpart are
published at a later date, the owner or operator is subject to eh requirements contained in the revised
version of 40 CFR Part 63 Subpart ZZZZ.
These requirements included in this Condition 2.8 are only federally enforceable. As of the date of
permit issuance (DRAFT), the requirements in 40 CFR Part 63 Subpart ZZZZ promulgated after July 1,
2007 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 state -
enforceable.
2.8.1 Stationary RICE subject to Regulations under 40 CFR Part 60. A new or reconstructed stationary
RICE located at an area source of HAP emissions must meet the requirements of this part by
meeting the requirements of 40 CFR part 60 subpart IIII, for compression ignition engines. No
further requirements apply for such engines under this part (§63.6590(c)(1)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 33
3. 013 — Plant Process Flare (FLR-1A)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
NOx
3.1
7.5 tons/year
0.068 lb/MMBtu
Recordkeeping and
Calculation
Monthly
CO
30.8 tons/year
0.31 lb/ MMBtu
VOC
3.2
21.2 tons/year
4388 lb/MMscf
HAP Emissions
3.3
See Condition 3.3
n -hexane: 8.92
lb/MMscf
benzene: 2.86
Ib/MMscf
Toluene: 4.3
lb/MMscf
Xylene: 1.52
lb/MMscf
Waste Gas
Throughput
3.4
193.1 MMscf/year
Recordkeeping and
Calculation
Monthly
y
Thermocouple
Monitoring
3.5
Recordkeeping
Continuous
Opacity
3.6
Not to Exceed 30%,
for a Period or
Periods Aggregating
More than Six (6)
Minutes in any 60
Consecutive Minutes
See Condition 3.6
No Visible Emissions
Control Equipment
Operation
3.7
See Condition 3.7
Statewide Controls
for Oil and Gas
Operations
3.8
See Condition 3.8
40 CFR 60 Subpart A
3.9
See Condition 3.9
3.1 Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from this flare must not exceed the
limitations stated in Summary Table 3 above (Colorado Construction Permit 13WE3003).
Monthly emissions of NOx and CO must be calculated by the end of the subsequent month using the
emission factors in Summary Table 3 above (AP -42, Table 13.5-1, dated February, 2018), the total
flowrate waste gas routed to the flare as monitored by Condition 3.4, the total heat content of the steam
routed to the process flare in the equation below:
MMSCF\ (MMBtu lb
tons ll _ FRTatat ( month ) x HCrotat MMSCF X EF (MMBtu)
NOx & CO emissions (-month 2000 lb
Unit Conversion ( ton
Where:
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 34
FRTotal = Uncontrolled Total Flowrate to Process Flare, MMSCF/month
HCTotat = Heat Content of Total Process Stream Routed to the Process Flare,MMBtu/MMscf
EF = NOx or CO Emission Factor, lb/MMBtu
This flare must be configured in a manner to serve as a backup control device for the thermal oxidizer
controlling the amine unit still vent and the combustors controlling the still vent from the dehydration
units, as required by Conditions 5.1.2.1 and 6.1.4.
Monthly emissions obtained from this calculation must be used in a twelve-month rolling total to
monitor compliance with the annual emission limitations. Each month, a new twelve-month total must
be calculated using the previous twelve months' data. Records of calculations must be maintained and
made available to the Division upon request.
3.2 Volatile Organic Compounds (VOC) emission must not exceed the limitation in Summary Table 3
above (Colorado Construction Permit 13WE3003). Monthly emissions of VOCs must be calculated by
the end of the subsequent month using an emission factor calculated from the results of the most recent
extended gas analysis, as required by Condition 12.2, and the total quantity of waste gas routed to the
flare, as monitored by Condition 3.4 in the equation below:
MMSCFl ( lb )
tons ll FRTotat ( month M J x EF Mscf
VOC and HAP emissions (monthl 2000 lb)x 0.05
Unit Conversion ( ton
Where:
FRTotat = Uncontrolled Total Flowrate to Process Flare, MMSCF/month
EF = NOx or CO Emission Factor, lb/MMBtu
A ninety-five percent (95%) control efficiency may be applied to VOC and HAP emissions from these
processes presuming the requirements of this Condition 3 are satisfied.
Monthly emission obtained from this calculation must be used in a twelve-month rolling total to monitor
compliance with the annual emission limitations. Each month, a new twelve-month total must be
calculated using the previous twelve months' data. Records of calculations must be maintained and
made available to the Division upon request.
3.3 Emissions of Hazardous Air Pollutants (HAPs) from this flare are subject to the facility -wide HAP
limits of Condition 12.1. For the purposes of calculating monthly HAP emissions as required by
Condition 12.1, the permittee must utilize the calculation methodology outlined in Condition 3.1 and the
site -specific HAP emissions factors (in units of lb/MMscf) outlined in Summary Table 3. A ninety-five
percent (95%) control efficiency may be applied to the calculated HAP emissions presuming the
requirements of this Condition 3 are satisfied.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 35
3.4 The quantity of gas combusted must not exceed the limitation in Summary Table 3 above (Colorado
Construction Permit 13WE3003). The quantity of total gas volume routed to the process flare (pilot gas,
purge gas, electric compressor blowdowns, amine unit blowdowns, plant blowdowns, residue gas, amine
still vent backup, and dehydration units still vent backup) must be continuously monitored and recorded
using a flow meter. The monthly recorded total quantity of gas must be kept in a log and made available
to the Division upon request. Monthly total gas combusted by the flare must 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. This monthly total volume of gas must be
used to calculate monthly emissions as specified in Condition 3.1.
3.5 The owner or operator must continuously monitor this process flare with a thermocouple to ensure the
continuous presence of a pilot flame (Colorado Construction Permit 13WE3003). Records of this
monitoring must be kept in a log to be made available to the Division upon request.
3.6 This flare is subject to the following opacity requirements:
3.6.1 This flare is subject to the opacity standards of Colorado Regulation No. 1, Section II.A.5 as
incorporated into Condition 13.2.
During all times not described in Condition 3.6.2, the permittee must monitor compliance with
opacity requirements of this Condition 3.6.1.1:
3.6.1.1 The permittee must conduct a daily inspection of this process flare to determine the
presence or absence of smoke (e.g., visible emissions) in any six (6) minute period of
normal operation when the air pollution control equipment is combusting waste gases.
The results of this daily visual emission observation must be kept of file and made
available the Division upon request. In the event that visible emissions are observed
the operator has the option to either:
a. Immediately conduct repairs and maintain records of the specific repairs completed,
or
b. Shut-in the equipment to investigate the cause of the smoke, conduct any necessary
repairs, and maintain records of the specific repairs completed, or
c. Conduct a formal Method 9 observation to determine the opacity of this visible
emissions and conduct repairs if necessary. An EPA Reference Method 9 opacity
observation must be performed as follows:
(i) The EPA Reference Method 9 opacity observations must 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 3.6.1 shall be considered to exist from the time a Method
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 36
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.
(iii)The result(s) of the visual observations and the Method 9
observations must be kept on file and made available for Division
review upon request.
3.6.2 Note that the no visible emissions requirement of Condition 3.8 also applies to this flare when
dehydration units DEHY-1 and DEHY-2 are routed to the flare during enclosed combustor
downtime, as monitored by Condition 5.1.2.1 (Colorado Construction Permits 13WE3005 and
13WE3006 and Colorado Regulation No. 7, Part D, Section II.B.2.b). During periods when
emissions from dehydration units DEHY-1 and DEHY-2 are routed to the flare compliance with
opacity requirements of this Condition 3.6 may be presumed as long as the permittee conducts
the visible inspections as required by Colorado Regulation No. 7, Part D, Section II.C.I .d as
incorporated into Condition 15.5 and the requirements are satisfied.
3.7 This flare must be operated at all times when emissions are routed to it.
3.8 This flare is subject to the applicable requirements of Statewide Controls for Oil and Gas Operations in
Colorado Regulation No. 7, Part D, Section II.B as stated in Condition 15 during periods of thermal
oxidizer downtime (as monitored by Condition 5.1.2.1) and emissions from dehydration units DEHY-1
and DEHY-2 are routed to the flare (State -only enforceable).
3.9 This flare is subject to the applicable requirements of General Provisions of 40 CFR Part 60 Subpart A
(40 CFR §§60.1 through 60.19, as adopted by reference in Colorado Regulation No. 6, Part A, Subpart
A) as incorporated in Condition 17.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 37
4. 014 — Natural Gas -Fired Hot Oil Heater (reboiler for AMINE -1, Dehy-1, Dehy-2), rated at 43.64
MMBtu/hr
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
PMio
2.5 ton/year
13.26 lb/MMscf
PM2 5
4.1
2.5 tons/year
13.26 lb/MMscf
NOx
12.7 tons/year
67.32 lb/MMscf
CO
7.9 tons/year
41.82 lb/MMscf
Recordkeeping and
Calculation
Monthly
VOC
4.2
3.7 tons/year
19.38 lb/MMscf
SOx
0.6 Ib/Mlvlscf
HAP Emissions
4.3
See Condition 4.3
Natural Gas
Consumption
4.4
375 MMscf/year
Recordkeeping and
Calculation
Monthly
Opacity
4.5
Not to Exceed 20%,
Except as Provided
for Below
Fuel Restriction — Only Natural Gas
is Used as Fuel
For Start-up — Not to
Exceed 30% for a
Period or Periods
Aggregating More
than Six (6) Minutes
in any 60
Consecutive Minutes
40 CFR Part 60
Subpart Dc
4.6
See Condition 4.6
40 CFR Part 60
General Provisions
4.7
See Condition 4.7
4.1 Particulate Matter (PMio and PM25) emissions from this hot oil heater must not exceed the limitations
listed in Summary Table 4 above (Colorado Construction Permit 13WE3004, as modified under the
provisions of Section I, Condition 1.3 to remove the monthly limits).
4.1.1 Compliance with the annual limitations must be monitored utilizing the emissions factors (from
manufacturer data) listed in Summary Table 4 above and the monthly natural gas consumption as
monitored by Condition 4.4 in the equation below:
lb ton Compliance EF (MMscf) x Monthly Recorded Fuel Use (MME)
Month
2000 lb/ton
Monthly emissions must be calculated by the end of the subsequent monthly. A twelve-month
rolling total of emissions must be maintained to monitor compliance with the annual emission
Operating Permit 15OPWE394 First Issued: DRAFT
(tons)
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 38
limitations. Each month a new twelve-month total must be calculated using the previous twelve
months' data.
4.1.2 The numeric short-term PM standard listed in Summary Table 4 above was determined using the
design heat input of the hot oil heater (43.64 MMBtu/hr) in the following equation (Colorado
Regulation No. 1, Section III.A.1.b):
Ibs
PE 0.5(FI)-o.26
(Mtu)
=
Where: PE = Particulate emissions in pounds per million Btu heat input
FI = Fuel input in million Btu per hour
In the absence of credible evidence to the contrary, compliance with the particulate emission limitations
shall be presumed since only natural gas is emitted to be used as fuel in the hot oil heater. The permittee
shall maintain records that verify that only natural gas is used as fuel.
4.2 Nitrogen Oxide (NOx), Carbon Monoxide (CO), and Volatile Organic Compound (VOC) emissions
from this hot oil heater must not exceed the limitations stated in Summary Table 4 above (Colorado
Construction Permit 13WE3004, as modified under the provisions of Section I, Condition 1.3 to remove
the monthly limits). Emissions must be calculated monthly using the emission factors listed in Summary
Table 4 above (emission factors for NOx, CO, and VOC are from manufacturer data; emission factor for
SOx is from AP -42, Table 1.4-2), and the quantity of natural gas consumption of this heater as
monitored by Condition 4.4 in the following equation:
Emissions
month
MMsc
Emissions Factor (MMscf ) x Fuel Use ( month )
Unit Conversion
(2000 lb
l ton
Monthly NOx, CO, and VOC emissions must be calculated at the end of each subsequent month. A
twelve-month rolling total must be maintained to monitor compliance with the annual emission
limitations. By the end of the subsequent month a new twelve-month total must be calculated using the
previous months' data.
4.3 Emissions of Hazardous Air Pollutants (HAPs) from this hot oil heater are subject to the facility -wide
HAP limits of Condition 12.1 (Colorado Construction Permit 13WE3004, as modified under the
provisions of Section I, Condition 1.3 to increase the individual and total HAP limits to 9 tpy and 24 tpy,
respectively for consistency with more recently issued construction permits: 13WE3003, 13WE3005,
13WE3006, 13WE3007, 14WE0891, 14WE0892, and 14WE0893). For the purposes of calculating
monthly emissions as required by Condition 12.1 the permittee must utilize the HAP emission factors in
AP -42, Table 1.4-3 and the calculation methodology outlined in Condition 4.1.
4.4 Natural Gas Consumption for this hot oil heater must not exceed the limitations in Summary Table 4
above (Colorado Construction Permit 13WE3004). Natural gas consumption must be monitored by fuel
use meter. Fuel use must be recorded within seven (7) days of each month. A twelve-month rolling total
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 39
must be maintained to monitor compliance with the annual limitation. Each month a new twelve-month
total must be calculated using the previous months' data.
4.5 This hot oil heater is subject to the opacity standards of Colorado Regulation No. 1, Section II.A.1 and 4
as incorporated into Condition 13.1. In the absence of credible evidence to the contrary, compliance with
the opacity requirement is presumed since only natural gas is permitted to be used as fuel. The permittee
shall maintain records that verify that only natural gas is used as fuel.
4.6 This source is subject to the applicable requirements of the Standards of Performance for New
Stationary Sources requirements of Regulation No. 6, Part A, Subpart Dc (40 CFR Part 60, Subpart Dc),
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.
Applicability and Delegation of Authority 060.40c)
4.6.1 Except as provided in paragraphs (d), (e), (f), and (g) of Subpart Dc, the affected facility to
which this subpart applies is each steam generating unit for which construction, modification, or
reconstruction is commenced after June 9, 1989 and that has a maximum design heat input
capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/h)) or less,
but greater than or equal to 2.9 MW (10 MMBtu/h) (§60.40c(a)).
4.6.2 Steam generating units that meet the applicability requirements in paragraph (a) of Subpart Dc
are not subject to the sulfur dioxide (SO2) or particulate matter (PM) emission limits,
performance testing requirements, or monitoring requirements under Subpart Dc (§§60.42c,
60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during periods of combustion research, as defined in
§60.41c (§60.40c(c)).
Reporting and recordkeeping requirements (O60.48c)
4.6.3 The owner or operator of each affected facility shall submit notification of the date of
construction or reconstruction and actual startup, as provided by §60.7 of this part. This
notification shall include (§60.48c(a)):
4.6.3.1 The design heat input capacity of the affected facility and identification of fuels to be
combusted in the affected facility (§60.48c(a)(1)).
4.6.3.2 If applicable, a copy of any federally enforceable requirement that limits the annual
capacity factor for any fuel or mixture of fuels under §60.42c, or §60.43c
(§60.48c(a)(2)).
4.6.3.3 The annual capacity factor at which the owner or operator anticipates operating the
affected facility based on all fuels fired and based on each individual fuel fired
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 40
(§60.48c(a)(3)).
4.6.3.4 Notification if an emerging technology will be used for controlling SO2 emissions. The
Administrator will examine the description of the control device and will determine
whether the technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of the affected
facility to submit additional information concerning the control device. The affected
facility is subject to the provisions of §60.42c(a) or (b)(1), unless and until this
determination is made by the Administrator (§60.48c(a)(4)).
4.6.4 Fuel supplier certification shall include the following information (§60.48c(f)):
4.6.4.1 For other fuels (§60.48c(f)(4)):
a. The name of the supplier of the fuel (§60.48c(f)(4)(i));
b. The potential sulfur emissions rate or maximum potential sulfur emissions rate of
the fuel in ng/J heat input (§60.48c)(f)(4)(ii)); and
c. The method used to determine the potential sulfur emissions rate of the fuel
(§60.48c(f)(4)(iii)).
4.6.5 Except as provided under paragraphs (g)(2) and (g)(3) 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)).
4.6.5.1 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)).
4.6.5.2 As an alternative to meeting the requirements of paragraph (g)(1) of this section, the
owner or operator of an affected facility or multiple affected facilities located on a
contiguous property unit where the only fuels combusted in any steam generating unit
(including steam generating units not subject to this subpart) at that property are natural
gas, wood, distillate oil meeting the most current requirements in §60.42C to use fuel
certification to demonstrate compliance with the SO2 standard, and/or fuels, excluding
coal and residual oil, not subject to an emissions standard (excluding opacity) may elect
to record and maintain records of the total amount of each steam generating unit fuel
delivered to that property during each calendar month (§60.48c(g)(3)).
4.6.6 All records required under this section shall be maintained by the owner or operator of the
affected facility for a period of two years following the date of such record (§60.48c(i)).
4.6.7 The reporting period for the reports required under this subpart is each six-month period. All
reports shall be submitted to the Administrator and shall be postmarked by the 30th day
following the end of the reporting period (§60.48c(j)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 41
4.7 This heater is subject to the applicable requirements in 40 CFR Part 60 Subpart A (§§60.1 through
60.19), "General Provisions", as adopted by reference in Colorado Regulation No 6, Part A, Subpart A
as specified in 40 CFR Part 60 Subpart Dc and as incorporated in Condition 17.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 42
5. 015 — 35 MMscfd Ethylene Glycol Dehydration Unit (DEHY-1) & 016- 70 MMscfd Ethylene Glycol
Dehydration Unit (DEHY-2)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
VOC Emissions
5.1
015: 1.4 tons/year
016: 1.0 tons/year
See Condition 5.1
Hazardous Air
Pollutants
5.2
See Condition 5.2
Recordkeeping and
Analysis
Monthly
Natural Gas
Throughput
5.3
Extended Gas
Analysis
5.4
Lean Glycol
Recirculation Rate
5.5
Wet Gas Inlet
Temperature &
Pressure
5.6
Cold Separator
Temperature &
Pressure
5.7
Flash Tank
Temperature &
Pressure
5.8
Statewide Controls
for Oil & Gas
Operations
5.9
015: 12,775
MMscf/year
016: 25,550
MMscf/year
015: 6.0 gal/min
016: 9.0 gal/min
Recordkeeping and
Calculation
Monthly
ASTM or Other
Division Approved
Method
Annually
Recordkeeping and
Calculation
Daily
Recordkeeping
Weekly
See Condition 5.9
5.1 Emissions of Volatile Organic Compounds from each dehydration unit must not exceed the limitations
in Summary Table 5 above (Colorado Construction Permits 13WE3005 and 13WE3006, as modified
under the provisions of Section I, Condition 1.3 to remove the monthly limits and change the
compliance monitoring method to reflect the method requested in the updated Operating Permit
application received March 31, 2017). Compliance with the emissions limitations must be monitored as
follows:
5.1.1 Monthly determinations of VOC and HAP emissions from each dehydration unit must be
conducted by the end of the subsequent month utilizing Virtual Materials Group Simulation
Software (VGM Sim), or other Division -approved modeling software if approved in advance by
the Division. The following parameters must be monitored and input into the VMG Simulation
model:
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 43
5.1.1.1 The inlet natural gas compositions obtained from the most recent extended gas analysis,
as required by Condition 5.4 (Colorado Construction Permit 13WE3005 and
13WE3006).
5.1.1.2 The average monthly value of the lean glycol recirculation rate, wet gas inlet
temperature and pressure, condenser outlet temperature, cold separator pressure and
temperature, and flash tank temperature and pressure as monitored by Conditions 5.5,
5.6, 5.7 and 5.8.
5.1.2 The permittee must operate and maintain the following control devices on each dehydration unit
capable of reducing VOC and HAP emissions (as monitored by Conditions 5.1 and 5.2) to the
levels listed in Summary Table 5 above (Colorado Construction Permits 13WE3005 and
13WE3006):
5.1.2.1 Each dehydrator still vent must be configured in such a way that vapors are routed to
an air-cooled condenser and then to an enclosed combustor (Colorado Construction
Permits 13WE3005 and 13WE3006). This combustion device is subject to the
provisions of Colorado Regulation No. 1, Section II.A.5 as incorporated into Condition
13.2 (Colorado Construction Permit 13WE3005 and 13WE3006 and Colorado
Regulation No. 1, Section II.A.5), compliance with this opacity requirement may be
presumed as long as the requirements of Condition 5.9.6 are satisfied. This combustion
device is subject to the Statewide Controls for Oil and Gas Operations in Colorado
Regulation No. 7, Part D, Section II.B as incorporated into Condition 5.9.6. When the
combustor is operational a 95% control efficiency may be applied to the uncontrolled
emissions presuming the requirements of Condition 5.9.6 are satisfied. When this
combustor is non -operational the permittee must meet the requirements of Condition
5.1.2.1.a.
a. Each dehydrator still vent must be configured in such a way that vapors are routed
to the plant flare (AIRS 013, Condition 3) during periods of combustor downtime
(Colorado Construction Permits 13WE3005 and 13WE3006). When emissions are
routed to the plant flare a 95% control efficiency may be applied to VOC and HAP
emissions (as monitored by Conditions 5.1 and 5.2) presuming the requirements of
Condition 3 are satisfied.
5.1.2.2 The permittee must operate and maintain these dehydration units flash tanks as a closed
loop system and must recycle 100% of emissions to the Redtail Gas Plant's inlet slug
catcher (Colorado Construction Permits 13WE3005 and 13WE3006). A control
efficiency of 100% may be presumed for flash gas emissions as long as the emission
routing requirements of this Condition 5.1.2.2 are met. When the facility is not able to
recycle emissions to the inlet slug catcher the permittee must meet the requirements of
Condition 5.1.2.2.a.
a. Each dehydrator flash tank must be configured in such a way that vapors are routed
to the plant flare (AIRS 013, Condition 3) during periods when emissions cannot
be recycled to the inlet slug catcher (Colorado Construction Permits 13WE3005
and 13WE3006). When emissions are routed to the plant flare a 95% control
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 44
efficiency may be applied to VOC and HAP emissions (as monitored by Conditions
5.1 and 5.2) presuming the requirements of Condition 3 are satisfied.
Monthly VOC and HAP emissions obtained from this calculation must be used in a twelve-month
rolling total to monitor compliance with the annual limitations. Each month, a new twelve-month total
must be calculated using the previous twelve months' data. Records of calculations must be maintained
and made available to the Division upon request.
5.2 These dehydration units are subject to the facility -wide HAP limitations incorporated in Condition 12.1
(Colorado Construction Permits 13WE3005 and 13WE3006). For the purposes of monitoring
compliance with the facility -wide HAP emission limits for these dehydration units' monthly emissions
must be calculated as indicated in Condition 5.1.
5.3 Natural gas processed by each glycol dehydration unit must not exceed the limitations listed in
Summary Table 5 above (Colorado Construction Permits 13GA3005 and 13WE3006). The gas
throughput to the dehydration unit shall be recorded monthly using existing gas meters or by assuming
the maximum design rate of each of the dehydration units (015: 35 MMscf/d and 016: 70 MMscf/d). A
twelve-month rolling total will be maintained to monitor compliance with annual limitations. Each
month a new twelve-month total must be calculated using the previous twelve months' data. Throughput
records and records of the rolling twelve-month total calculation must be maintained and made available
to the Division upon request.
5.4 Samples of inlet gas must be collected and analyzed (extended wet gas analysis) on an annual basis (per
calendar year), as required by Condition 12.2. Results of the wet gas analysis must be used to calculate
emissions as required by Conditions 5.1 and 5.2. The results of the wet gas analysis must be kept on file
and be made available to the Division upon request (Colorado Construction Permits 13WE3005 and
13WE3006).
In lieu of the requirements above, if the permittee samples and conducts an extended wet gas analysis of
a gas sample from a different process stream that is representative of volatile organic compounds
(VOCs) and hazardous air pollutants (HAPs) contents from these dehydration units the permittee may
choose not to sample prior to the dehydrator inlet and to utilize the extended wet gas analysis results
from the other process steam in the required monthly process model to calculate emissions.
5.5 The maximum pumping rate of lean glycol for each dehydration unit must not exceed the limitations in
Summary Table 5 above. The actual pumping rate shall be recorded on a daily basis by either assuming
maximum design pump rate, the glycol flow meter(s) including flow from all injection points and
pumps, or recording strokes per minute and converting to the circulation rate. Actual recorded daily
pumping rates shall be used to calculate a monthly average. Records shall be maintained and made
available to the Division upon request (Colorado Construction Permits 13WE3005 and 13WE3006).
5.6 The actual wet gas inlet temperature and pressure for each dehydration unit must be monitored and
recorded on a weekly basis (Colorado Construction Permits 13WE3005 and 13WE3006). Actual
recorded weekly values must be used to calculate a monthly average for use in the monthly process
model as required by Condition 5.1. Records of the weekly actual wet gas inlet temperature and pressure
must be maintained and made available to the Division upon request.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 45
5.7 The actual cold separator pressure and temperature for each dehydration unit must be monitored and
recorded on a weekly basis (Colorado Construction Permits 13WE3005 and 13WE3006). Actual
recorded weekly values must be used to calculate a monthly average for use in the monthly process
model as required by Condition 5.1. Records of the weekly actual cold separator pressure and
temperature must be maintained and made available to the Division upon request.
5.8 The actual flash tank temperature and pressure for each dehydration unit must be monitored and
recorded on a weekly basis (Colorado Construction Permits 13WE3005 and 13WE3006). Actual
recorded weekly values must be used to calculate a monthly average for use in the monthly process
model as required by Condition 5.1. Records of the weekly actual flash tank temperature and pressure
must be maintained and made available to the Division upon request.
5.9 These dehydration units are subject to the applicable requirements of Statewide Controls for Oil and Gas
Operations in Colorado Regulation No. 7, Part D, Section II as follows (State -only enforceable):
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.
The requirements below reflect the current rule language as of the revisions to Colorado Regulation No.
7 adopted December 19, 2019. However, if revisions to the regulation are published at a later date, the
owner or operator is subject to the requirements contained in the latest adopted version of Colorado
Regulation No. 7.
Control Requirements
5.9.1 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
II.D.2. (Condition 5.9.2), 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, Part D, Section II.D.1).
In absence of credible evidence to the contrary, compliance with the requirements VOC
reduction requirements of Condition 5.9.1 shall be presumed as long as the requirements in
Condition 5.9.4.2 are met.
5.9.2 The control requirements in Section II.D.1 (Condition 5.9.1) shall apply where:
5.9.2.1 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, Part D, Section II.D.2.a)
5.9.2.2 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
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 46
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, Part D, Section II.D.2.b).
5.9.3 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
II.D.4 (Condition 5.9.4), 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, Part D, Section II.D.3).
In absence of credible evidence to the contrary, compliance with the hydrocarbon reduction
requirements of Condition 5.9.3 shall be presumed as long as the requirements in Condition
5.9.4.2 are met.
If a combustion device is used (to meet the requirements of Condition 5.9.3), it shall have a
design destruction efficiency of at least 98% for hydrocarbons except where:
5.9.3.1 The combustion device has been authorized by permit prior to May 1, 2014; and
(Colorado Regulation No. 7, Part D, Section II.D.3.a)
5.9.3.2 A building unit or designated outside activity area (as defined in Section II.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, Part D, Section II.D.3.b)
In absence of credible evidence to the contrary, compliance with the design destruction
efficiency requirements of Condition 5.9.3 shall be presumed as long as the requirements in
Conditions 5.9.8 and 5.9.9 are met.
5.9.4 The control requirements in Section II.D.3 (Condition 5.9.3) shall apply where:
5.9.4.1 Uncontrolled actual emissions of VOCs from a glycol natural gas dehydrator
constructed on or after May 1, 2015, are equal to or greater than two (2) tons per year.
Such glycol natural gas dehydrators must be in compliance with Section II.D.3. by the
date that the glycol natural gas dehydrator commences operation (Colorado Regulation
No. 7, Part D, Section II.D.4.a).
5.9.4.2 Uncontrolled actual emissions of VOCs from a single glycol natural gas dehydrator
constructed before May 1, 2015, are equal to or greater than six (6) tons per year, or
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 (Colorado Regulation No. 7, Part D,
Section II.D.4.b).
5.9.5 These dehydrator(s) are subject to the general requirements of Condition 14.1.2. The air
pollution control device associated with these dehydrators is subject to the requirements of
Condition 15
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Monitoring Requirements - air pollution control device
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 47
5.9.6 Monitoring requirements for the air pollution control device associated with this dehydrator are
included in Condition 15.
Recordkeeping Requirements
5.9.7 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 5.9.1 or 5.9.3 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 5.9.1 or 5.9.3 that
increase uncontrolled actual emissions from the dehydrator and/or group of dehydrators at the
facility above the thresholds listed in Conditions 5.9.2 and/or 5.9.4 shall comply with the control
requirements of Conditions 5.9.1 and/or 5.9.3 within 60 days of discovery of the emission
increase.
5.9.8 If the owner or operator is claiming an exemption from the control requirements of Condition
5.9.3 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 the Division upon request.
Dehydrators that are not subject to the control requirements in Condition 5.9.3 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 5.9.3 within 60 days of
discovery of the changes.
5.9.9 The owner or operator shall maintain records that document the design efficiency of the
combustion device used to meet the requirements of Condition 5.9.3. Such records shall be
maintained and made available for Division review.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 48
6. 017 — One Methyldethanolamine Natural Gas Sweetening System (AMINE -1)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
VOC Emissions
10 tons/ ear
Y
VMG Simulation
Process Simulation
HAP Emissions
See Condition 6.1.2
Model or Division-
Approved Equivalent
and Calculation
Monthly
Extended Wet Gas
Analysis
6.1
See Condition 6.1.1.1
Equipment
Configuration
Thermal Oxidizer
Minimum
Combustion Chamber
Temperature: 1350°F
See Conditions 6.1.4 and 6.1.5
SO2 Emissions
6.2
25.3 tons/year
VMG Simulation
Model or Division-
Approved Equivalent
Process Simulation
and Calculation
Monthly
NOx Emissions
0.5 tons/year
0.068 lb/IVIIMBtu
Recordkeeping and
Monthly
CO Emissions
6.3
2.1 tons/year
0.31 lb/MMBtu
Calculation
Natural Gas
Throughput
16,425 MMScf/year
Recordkeeping and
Calculation
Monthly
Inlet Gas Sulfur
Concentration
6.4
ASTM Methods or
Equivalent
Annually
Lean Amine
Recirculation Rate
6.5
201 gallons/minute
Recordkeeping
Weekly
Amine Concentration
in Solution
6.6
55% Ucarsol AP -814
by weight
Recordkeeping
Weekly
Process Model Input
Parameters
6
Recordkeeping
Weekly
40 CFR Part 60
Subpart OOOO
6.1.3 & 6.8
See Condition 6.8
40 CFR Part 60
Subpart A
6.9
See Condition 6.9
6.1 Emissions of Volatile Organic Compounds (VOC) from the amine sweetening unit flash tank and
regenerator still vent must not exceed the limitation listed in Summary Table 6 above (Colorado
Construction Permit 13WE3007). Compliance with the emission limitations shall be monitored as
follows:
6.1.1 Monthly determination of VOC and HAP emissions must be conducted by the end of the
subsequent month utilizing VMG Simulation Model or other Division -approved modeling
software.
6.1.1.1 The following parameters must be input to the VMG Simulation Model:
Operating Permit 15OPWE394
First Issued: DRAFT
VOC or HAP emissions
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 49
a. The inlet natural gas composition obtained from the most recent extended gas
analysis, as required by Conditions 6.1.3 and 12.2.
b. The average monthly value of the inlet natural gas temperature and pressure, the
flash tank operating temperature and pressure, amine solution concentration, and
the lean amine circulation rate, as required by Conditions 6.5, 6.6, and 6.7.
6.1.1.2 Control Efficiencies
a. A control efficiency (CE) of 95% may be applied to the still vent emissions, when
the thermal oxidizer is utilized for control and provided the requirements of
Condition 6.1.4 are met.
b. A control efficiency (CE) of 100% may be applied to the flash gas emissions only,
when the emissions are routed to the plant's inlet slug catcher and provided the
requirements of Condition 6.1.5 are satisfied.
c. A control efficiency (CE) of 95% shall be applied to the still vent and flash gas
emissions, when the plant flare is utilized for control (as indicated in Condition
6.1.5.1) and provided the requirements of Condition 3 are satisfied.
6.1.1.3 Monthly emissions of VOC and HAPs must be monitored using the following equation:
lb hrs ( CE(%)1 Ib hrs ( CE(%)1
r tons l FGVOC/HAP (lb
X OHPlare (month x 1 — 100 J SVVOC/HAP (w.� x OH (month x 1 100
\month/ Unit Conversion (2000 lb\ 0 + n 1 Unit Conversion (20000 lb)
Where:
FGvoc/HAp = Uncontrolled Flash Gas Emissions of VOC or HAP, lb/hr
SVVOC/HAP = Uncontrolled Still Vent Emissions of VOC or HAP, lb/hr
OH Flare = Hours of Operation when flash gas is routed to the plant flare, hrs/month
OH = Hours of Operation, hrs/month
CE = Control Efficiency of plant inlet: 100%; plant flare or thermal oxidizer: 95%, as monitored by Conditions 6.1.1.2 and 6.1.5
Monthly emissions of VOC and HAPs obtained from this calculation must be used in a twelve-
month rolling total to monitor compliance with the annual limitations in Summary Table 6
above. Each month, a new twelve-month total must be calculated using the previous twelve
months' data. Records of calculations must be maintained and made available to the Division
upon request.
6.1.2 Emissions of Hazardous Air Pollutants (HAPs) from this amine unit are subject to the facility -
wide HAP limits of Condition 12.1. The calculation methodology described in Condition 6.1.1.3
must be utilized for the purposes of calculating monthly HAP emissions are required by
Condition 12.1.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 50
6.1.3 An extended natural gas analysis of the inlet to the amine unit must be conducted annually, using
ASTM Methods or equivalent, if approved in advance by the Division, as required by Condition
12.2. This analysis must include a determination of the concentration of hydrogen sulfide (H2S)
and total sulfur in the stream. Results of the extended gas analysis must be used as inputs to the
VMG Simulation Model to calculate emissions in accordance with Condition 6.1.1.3.
The results of the annual determination of the inlet concentration of hydrogen sulfide (H2S) in
the gas stream must be used to monitor that this amine unit qualifies for the exemption from 40
CFR Part 60 Subpart OOOO, as monitored by Condition 6.8.1.3 (Colorado Construction Permit
13WE3007). In the event that the results of the inlet gas sample do not qualify for the exemption
under 6.8.1.3 then this amine unit will be subject to the applicable provisions of 40 CFR Part 60
Subpart OOOO. Records of this sampling and analysis must be maintained in accordance with
the requirements of Condition 6.8.8 for Subpart OOOO. These records must be made available to
the Division upon request.
6.1.4 This unit must be configured in such a manner that the emission from the amine unit's
regenerator vent streams (CO2 vent) must be routed via the common header system to the
thermal oxidizer (Colorado Construction Permit 13WE3007).
6.1.4.1 The operating temperature of this thermal oxidizer must be greater than or equal to the
temperature listed in Summary Table 6 above at all times that any process stream
emissions are routed to the thermal oxidizer (Colorado Construction Permit
13WE3007). The operating temperature of the thermal oxidizer's combustion chamber
must be monitored and recorded daily and kept in a log to be made available to the
Division upon request.
6.1.4.2 This thermal oxidizer is subject to the opacity standards of Colorado Regulation No. 1,
Section II.A.1 and 4 (Colorado Construction Permit 13WE3007) and monitoring
requirements incorporated in Condition 13.1.
6.1.4.3 The hours of operation of still vent operation must be monitored and recorded on a
monthly basis. Monthly hours of operation must be utilized to calculate emissions as
required by Conditions 6.1 and 6.2. Additionally, the hours of operation when still vent
emissions are routed to the thermal oxidizer must be monitored and recorded on a
monthly basis and utilized to calculate emissions from the thermal oxidizer as required
by Condition 6.3. Records of all monthly hours of operation must be kept in a log to be
made available to the Division upon request.
6.1.4.4 Alternatively, the emissions from the still vent may be routed to the plant flare (AIRS
013, Condition 3) as a backup. The plant flare must reduce uncontrolled emissions of
VOCs and HAPs to the emissions levels listed in Summary Table 6 above. Parameters
associated with the flare must be monitored as required in Condition 3. Records of this
data must be maintained and provided to the Division upon request. The permittee must
monitor and record the hours of operation at all times, as monitored by Condition
6.1.4.3. When emissions are routed to this flare and the flare is operated as required by
Condition 3, a ninety-five (95%) control efficiency may be applied to the uncontrolled
emissions as calculated in Condition 6.1.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 51
6.1.5 This amine unit must be configured in such a way that 100% of emissions that result from the
flash tank associated with this amine unit must be recycled to the plant inlet (Colorado
Construction Permit 13WE3007).
6.1.5.1 Alternatively, the emissions from the flash tank may be routed to the plant flare (AIRS
013, Condition 3) as a backup. The plant flare must reduce uncontrolled emissions of
VOCs and HAPs to the emission levels listed in Summary Table 6 above. Parameters
associated with this flare must be monitored as required in Condition 3. Records of this
data must be maintained and provided to the Division upon request. The permittee must
monitor and record the hours of operation at all times when flash tank emissions are
routed to the plant flare, as monitored by Condition 6.1.5.2. When emissions are routed
to this flare and the flare is operated as outlined in Condition 3, a ninety-five percent
(95%) control efficiency may be applied to the uncontrolled emissions as calculated in
Conditions 6.1 and 6.2.
6.1.5.2 The hours of operation when flash tank emissions are routed to the plant flare must be
monitored and recorded on a monthly basis. Records of the monthly hours of operation
must be kept in a log to be made available to the Division upon request. Monthly hours
of operation must be utilized to calculate emissions as required by Conditions 6.1.
6.2 Emissions of Sulfur Dioxide (SO2) must not exceed the annual limitation in Summary Table 6 above
(Colorado Construction Permit 13WE3007). Compliance with the emission limitations must be
monitored as follows:
6.2.1 Monthly determination of SO2 emissions must 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 speciated sulfur analysis, as required by Condition 6.1.3.
6.2.1.1 The SO2 still vent emissions obtained from the most recent monthly process model run,
as required by Condition 6.1 must be used to monitor compliance with the SO2 emission
limit using the following equation. A control efficiency of 95% may be used when the
still vent emissions are routed to the thermal oxidizer or the plant flare, provided the
requirements of Condition 6.1.4 are satisfied.
lbsp2
( tons l _ SVHZs (Month) x CETo(/)
\month/ Unit Conversion (2000 lbso2)
tonso2
SO2 Emissions
Where:
SVH2s = Uncontrolled Still Vent Emissions of HZS, lb/hr
EF = Emission Factor,1.79 ton S02/ton HZS
OH = Hours of Still Vent Operation when Emissions Routed to RTO, hrs/month
CERro = Control Efficiency of TO, 95%
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 52
Monthly emissions of SO2 obtained from the preceding calculation must be used in a twelve-
month rolling total to monitor compliance with the annual emission limitation. Each month, a
new twelve-month total must be calculated using the previous twelve months' data.. Records of
calculations must be maintained and made available to the Division upon request.
6.3 Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from this thermal oxidizer must not
exceed the limitations stated in Summary Table 6 above (Colorado Construction Permit 13WE3007).
Monthly emissions of NOx and CO must be calculated by the end of the subsequent month using the
emission factors in Summary Table 6 above (AP -42, Tables 13.5-1 and 13.5-2, dated February, 2018),
the hours of operation during which the flash gas emissions are routed to the thermal oxidizer as
monitored by Condition 6.1.4.3, the flowrate and lower heat content of the still vent process stream
routed to the flare must be obtained from the most recent monthly process model run, as required by
Conditions 6.1 in the equation below:
MMSCFI hrs l MMBtu) lb l
( tons ll _ FRsv hr J x OH ( (month) x HCsv �MMSCFJ x EF (MMBtuI
NOx & CO emissions \monthl 2000 lb)
Unit Conversion ( ton )
Where:
FRsv = Uncontrolled Still Vent Flowrate, MMSCF/hr
HCsv = Heat Content of Still Vent, MMBtu/hr
OH = Hours of Operation, hrs/month
EF = NOx or CO Emission Factor, lb/MMBtu
6.4 Natural gas processed by this amine unit must not exceed the limitations listed in Summary Table 6
above (Colorado Construction Permit 13WE3007). The gas throughput to the amine unit must be
recorded monthly using existing flow meters in a log that is to be made available to the Division for
inspection upon request. A twelve (12) month rolling total will be maintained to monitor compliance
with the annual limitation.
6.5 This amine unit's lean amine recirculation rate must not exceed the limitation in Summary Table 6
above (Colorado Construction Permit 13WE3007). The lean amine circulation rate must be recorded
weekly (as required by Condition 6.1.1.1b) in a log maintained on site and to be made available to the
Division for inspection upon request. A pump stroke correlation may be used to monitor compliance
with this condition.
6.6 The concentration of Ucarsol AP -814 solvent in the lean amine stream must not exceed the limitation
listed in Summary Table 6 above on a monthly average (Colorado Construction Permit 13WE3007). The
permittee must measure and record the solvent concentration in the lean amine stream each week and
calculate and record a calendar monthly average solvent concentration to monitor compliance. Records
of weekly solvent concentrations and monthly average solvent concentrations must be maintained and
be made available to the Division for inspection upon request.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 53
6.7 The following operating parameters for this amine unit must be monitored and recorded at the intervals
specified in the table below. Values of the parameters monitored must be representative of the unit's
operation for the duration of the monitoring period.
Parameter
Monitoring Frequency
Inlet Natural Gas Temperature
Weekly
Inlet Natural Gas Pressure
Weekly
Flash Tank Operating Pressure
Weekly
Flash Tank Operating Temperature
Weekly
Monthly averages of the inlet natural gas temperature and pressure must be obtained by averaging the
operating values recorded for week. These monthly averages must be used as inputs to the monthly
process model run, as required by Condition 6.1.
6.8 This amine unit is subject to the applicable requirements of 40 CFR Part 60, Subpart OOOO, "Standards
of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution" as adopted in
Colorado Regulation No. 6, Part A (adopted July 1, 2017), 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 the 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.
Am I subject to this subpart? 063.5365)
6.8.1 Sweetening units located at onshore natural gas processing plants that process natural gas
produced from either onshore or offshore wells (§60.5365(g)).
6.8.1.1 Each sweetening unit that processes natural gas is an affected facility (§60.5365(g)(1));
and
6.8.1.2 Each sweetening unit that processes natural gas followed by a sulfur recovery unit is
an affected facility (§60.5365(g)(2)).
6.8.1.3 Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen
sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply with
recordkeeping and reporting requirements specified in §60.5423(c) but are not required
to comply with §§60.5405 through 60.5407 and §§60.5410(g) and 60.5415(g) of this
subpart (§60.5365(g)(3)).
When must I comply with this subpart? 060.5370)
6.8.2 You must be in compliance with the standards of this subpart no later than October 15, 2012 or
upon startup, whichever is later (§60.5370(a)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 54
6.8.3 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)).
6.8.4 You are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71,
provided you are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40
CFR 71.3(a). Notwithstanding the previous sentence, you must continue to comply with the
provisions of this subpart (§60.5370(c)).
6.8.5 You are deemed to be in compliance with this subpart if you are in compliance with all
applicable provisions of subpart 0000a of this part (§60.5370(d)).
What additional recordkeeping and reporting requirements apply to my sweetening unit affected
facilities at onshore natural gas processing plants? 060.5423)
6.8.6 You must retain records of the calculations and measurements required in §60.5405(a) and (b)
and §60.5407(a) through (g) for at least 2 years following the date of the measurements. This
requirement is included under §60.7(d) of the General Provisions (0.5423(a)).
6.8.7 You must submit a report of excess emissions to the Administrator in your annual report if you
had excess emissions during the reporting period. For the purpose of these reports, excess
emissions are defined as (§60.5423(b)):
6.8.7.1 Any 24 -hour period (at consistent intervals) during which the average sulfur emission
reduction efficiency (R) is less than the minimum required efficiency (Z)
(§60.5423(b)(1)).
6.8.7.2 For any affected facility electing to comply with the provisions of §60.5407(b)(2), any
24 -hour period during which the average temperature of the gases leaving the
combustion zone of an incinerator is less than the appropriate operating temperature as
determined during the most recent performance test in accordance with the provisions
of §60.5407(b)(2). Each 24 -hour period must consist of at least 96 temperature
measurements equally spaced over the 24 hours (§60.5423(b)(2)).
6.8.8 To certify that a facility is exempt from the control requirements of these standards, for each
facility with a design capacity less than 2 LT/D of H2S in the acid gas (expressed as sulfur) you
must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity
is less than 2 LT/D of H2S expressed as sulfur (§60.5423(c)).
6.8.9 If you elect to comply with §60.5407(e) you must keep, for the life of the facility, a record
demonstrating that the facility's design capacity is less than 150 LT/D of H2S expressed as sulfur
(§60.5423(d)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 55
6.8.10 The requirements of paragraph (b) of this section remain in force until and unless the EPA, in
delegating enforcement authority to a state under section 111(c) of the Act, approves reporting
requirements or an alternative means of compliance surveillance adopted by such state. In that
event, affected sources within the state will be relieved of obligation to comply with paragraph
(b) of this section, provided that they comply with the requirements established by the state
(§60.5423(e)).
What part of the General Provisions apply to me? 060.5425)
6.8.11 Table 3 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19
apply to you.
6.9 This amine unit is subject to the applicable requirements of the General Provisions of 40 CFR Part 60
Subpart A (40 CFR §§60.1 through 60.19, as adopted by reference in Colorado Regulation No. 6, Part
A, Subpart A) as specified in 40 CFR Part 60 Subpart OOOO §60.5425 and as incorporated in Condition
17.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
7. 018 — Produced Water Tanks (PW-1 & PW-2)
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 56
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
VOC Emissions
0.2 ton/year
0.262 lb/bbl
Recordkeeping and
Calculation
Monthly
Opacity (Control
Equipment)
7.1
Not to Exceed 30%,
for a Period or
Periods Aggregating
More than Six (6)
Minutes in any 60
Consecutive Minutes
See Condition 7.1
No Visible Emissions
HAP Emissions
7.2
See Condition 7.2
Recordkeeping and
Calculation
Monthly
Produced Water
Throughput
7.3
29,200 bbl/year
Recordkeeping and
Calculation
Monthly
Statewide Controls
for Oil and Gas
Operations
7.4
See Condition 7.4
7.1 Emissions of Volatile Organic Compounds (VOC) must not exceed the limitation listed in Summary
Table 7 above (Colorado Construction Permit 13WE3008, as modified under the provisions of Section I,
Condition 1.3 to remove the monthly limits). Compliance with the annual emission limit must be
monitored on a rolling twelve (12) month basis. By the end of each subsequent month a new twelve-
month total must be calculated based on the previous twelve months' data. Records of the actual
emissions must be maintained and made available to the Division upon request.
Emissions for each month must be calculated using the above emission factor (Permit Section Memo 14-
05, Section 5.3, dated May 1, 2017) and the monthly produced water throughput, as monitored by
Condition 7.3. Records of the actual emissions must be maintained and made available to the Division
upon request.
These tanks must meet the following control requirements:
7.1.1 These tanks must be configured in a manner that the vapor stream is routed to a combustor
(Colorado Construction Permit 13WE3008). The combustor must be capable of reducing VOC
and HAP emissions to the levels listed in Summary Table 7 above. This combustor must meet
the requirements statewide control requirements for oil and gas operations as incorporated into
Condition 15 and a ninety-five (95%) percent control efficiency may be applied to uncontrolled
VOC and HAP tank emission (as calculated in Condition 7.1 and 7.2) presuming the
requirements of Condition 15 are satisfied.
7.1.1.1 This combustor is subject to the following opacity requirements:
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 57
a. This combustor is subject to the opacity standards of Colorado Regulation No. 1,
Section II.A.5 as incorporated into Condition 13.2.
In the absence of credible evidence to the contrary, compliance with this opacity
limitation shall be presumed as long as the provisions of Condition 15 are satisfied.
b. Note that the no visible emissions requirement of Condition 15.2 also applies to this
combustor (Colorado Construction Permit 13WE3008 and Colorado Regulation
No. 7, Part D, II.B.2.b).
In the absence of credible evidence to the contrary, compliance with this opacity
limitation shall be presumed as long as the provisions of Condition 15 are satisfied.
7.1.2 The combustor must be operated at all times when emissions are routed to it.
7.2 Emissions of Hazardous Air Pollutants (HAPs) from these tanks are subject to the facility -wide HAP
limits of Condition 12.1 (Colorado Construction Permit 13WE3008, as modified under the provisions of
Section I, Condition 1.3 to remove the monthly limits and to update the annual facility -wide individual
and total HAP limits to be consistent with recently issued permits for the Redtail Gas Plant). For the
purposes of calculating monthly HAP emissions as required by Condition 12.1 the permittee must utilize
the HAP emission factors from Permit Section Memo 14-03, Section 5.3 for state emission factors for
produced water storage tanks in Weld County (May 1, 2017 version) and a ninety-five percent (95%)
control efficiency for times when the combustor is in operation as monitored by Conditions 7.1.1 and
7.1.2.
7.3 The quantity of produced water processed through these tanks must not exceed the limitation in
Summary Table 7 above (Colorado Construction Permit 13WE3008, as modified under the provisions of
Section I, Condition 1.3 to remove the monthly limits). The quantity of produced water processed
through these tanks must be monitored and recorded monthly utilizing throughput sales records of haul
tickets. Monthly produced water throughput must be used to calculate emissions as required by
Conditions 7.1 and 7.1.1. Compliance with the annual throughput limits shall be determined on a rolling
twelve-month total. By the end of each month a new twelve-month total shall be calculated based on the
previous twelve months' data. The permittee shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility for Division review upon
request.
7.4 This tank battery is subject to the applicable requirements of Statewide Controls for Oil and Gas
Operations in Colorado Regulation No. 7, Part D, Section II.C as incorporated into Condition 16 (State -
only enforceable).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 58
8. 021 —1,311 HP Caterpillar 4SLB Natural Gas Fired Internal Combustion Engine (RZ-ENG-1)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
NOx
8.1
6.3 tons/year
0.13 lb/MMBtu
Recordkeeping and
Calculation
Portable Analyzer
Monthly
Quarterly
CO
6.2 tons/year
0.76 lb/MMBtu
VOC
8.2
8.9 tons/year
0.22 Ib/MMBtu
Recordkeeping and
Calculation
Monthly
HAPs
8.3
See Condition 8.3
See Condition 8.3
Natural Gas
Consumption
8 4
83.31 MMscf/year
Recordkeeping and
Calculation
Monthly
Hours of Operation
8.5
Recordkeeping
Monthly
Heat Content of
Natural Gas
8.6
See Condition 8.6
Opacity
8.7
Not to Exceed 20%,
Except as Provided
for Below
Fuel Restriction — Only Natural Gas
is Used as Fuel
For Start-up — Not to
Exceed 30% for a
Period or Periods
Aggregating More
than Six (6) Minutes
in any 60
Consecutive Minutes
Oxidizing Catalyst
Parameters
8.8
See Condition 8.8
Control of Emission
from Engines
(Colorado Regulation
No. 7, Part E, Section
I)
8.9
NOX: 1.0 G/hp-hr
CO: 2.0 G/hp-hr
VOC: 0.7 G/hp-hr
Portable
Analyzer
Quarterly
40 CFR 60 Subpart
JJJJ
8.10
See Condition 8.10
40 CFR Part 60
Subpart A
8.11
See Condition 8.11
40 CFR 63 Subpart
ZZZZ
8.12
See Condition 8.12
8.1 Emissions of Nitrogen Oxidizes (NOx) and Carbon Monoxide (CO) from this engine must not exceed
the limitations stated in Summary Table 8 above (Colorado Construction Permit 14WE0889).
Compliance with the emission limitations must be monitored as follows:
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 59
8.1.1 Except as provided for below, the emission factors listed above have been approved by the
Division and must be used to calculate emissions from this engine.
Monthly emissions for the engine must be calculated by the end of the subsequent month using
the above emission factors, the natural gas consumption (as required by Condition 8.4), and the
heat content of the natural gas (as required by Condition 8.6) in the equation below:
EF lb Btu Fuel Use (MMscfx Heat Content of Fuel MMBtu
Tons _ (MMBtu� Month) (MMscf)
Month 2000 ( lb )
Ton)
Monthly emissions must be used in a twelve (12) month rolling total to monitor compliance with
the annual limitations. Each month a new twelve-month total must be calculated using the
previous twelve months' data. Records of calculations must be made available to the Division for
inspection upon request.
The source must retain records of all required monitoring data and support information for the
most recent twelve (12) month periods, as well as compliance certifications for the past five (5)
years on site at all times (Colorado Regulation No. 3, Part C, Section V.C.6.b).
If the results of the portable analyzer testing conducted under the provisions of Condition 19
show that either the NOx or CO emission rates/factors are greater than the emission rates/factors
listed in Summary Table 8 above, and in the absence of subsequent testing to the contrary (as
approved by the Division), the permittee must apply for a modification to this permit to reflect, at
a minimum, the higher emission rates/factors within sixty (60) days of the completion of the test.
8.1.1.1 Portable monitoring must be conducted quarterly in accordance with the requirements
in Condition 19.
8.2 Emissions of Volatile Organic Compounds (VOC) from this engine must not exceed the limitation stated
in Summary Table 8 above (Colorado Construction Permit 14WE0889). Monthly emissions must be
calculated by the end of the subsequent month using the above emission factor (manufacturer's emission
factor, converted from g/HP-hr to lb/MMBtu, based on an engine fuel consumption of 8,328 Btu/HP-hr),
the monthly fuel consumption (as monitored by Condition 8.4), and the heat content of the fuel (as
monitored by Condition 8.6) in the equation below:
EF lb x Fuel Use MMscf x Heat Content of Fuel MMBtu
Tons _ (MMBtu) ( Month ) (MMscf )
Month
2000(lb
Ton)
Monthly emissions must be used in a twelve (12) month rolling total to monitor compliance with the
annual emissions limitations. Each month a new twelve-month total must be calculated using the
previous twelve months' data. Records of calculations must be kept in a log to be made available to the
Division for inspection upon request.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 60
8.3 This engine is subject to the facility -wide HAP requirements of Condition 12.1 (Colorado Construction
Permit 14WE0889, as modified under the provisions of Section I, Condition 1.3 to remove the monthly
limits and to update the annual facility -wide individual and total HAP limits to be consistent with
recently issued permits for the Redtail Gas Plant). For the purposes of calculating monthly emissions as
required by Condition 12.1 the permittee must utilize the HAP emission factors n AP -42, Table 3.2-2
and the calculation methodology outlined in Condition 8.1.
8.4 Natural Gas consumption for this engine must not exceed the limitations in Summary Table 8 above
(Colorado Construction Permit 14WE0889). Natural gas use must be recorded monthly using existing
facility fuel meter(s). Allocation of natural gas to this engine must be based on the engine fuel design
rate, engine hours of operation (as required by Condition 8.5), and the monitored facility -wide fuel
consumption and calculated utilizing the equation below:
For Each Piece of Equipment, Fuel Use
(Fuel Design Rate)x(Hours of Operation)
x Facility fuel use per Month
Sum of Numerator for Each Piece of Equipmnet
Calculated monthly natural gas use must be used in a rolling twelve-month total to monitor compliance
with the annual limitations. Each month a new twelve-month total must be calculated using the previous
month's data. Records of calculations must be kept in a log to be made available to the Division for
inspection upon request.
8.5 Hours of operation for this engine must be monitored and recorded monthly. Records of the hours of
operation must be maintained and made available the Division upon request. Monthly hours of operation
must be utilized to determine the engine's natural gas consumption from the facility -wide fuel meter as
required by Condition 8.4.
8.6 The heat content of the natural gas used to fuel this engine must be verified annually using the residue
gas sample from the Redtail Gas Plant. The heat content of the natural gas shall be based on the lower
heating value of the fuel. Monthly emissions calculations, as required by Conditions 8.1, 8.2, and 8.3,
must be made using the heat content derived from the most recent required analysis.
8.7 This engine is subject to the opacity standards of Colorado Regulation No. 1, Section II.A.1 and 4 as
incorporated into Condition 13.1 (Colorado Construction Permit 14WE0889). In the absence of credible
evidence to the contrary, compliance with the opacity limit of this Condition 8.7 shall be presumed since
only natural gas is permitted to be used as fuel.
8.8 This engine must be equipped with a selective oxidation catalyst (Colorado Construction Permit
14WE0889) capable of reducing the VOC, CO, and HAP emissions to the levels listed in Summary
Table 8 above. Parameters associated with this oxidation catalyst unit must be monitored as follows.
Records of the data must be maintained and made available to the Division for inspection upon request.
8.8.1 The inlet temperature to the catalyst must be maintained within the range of 450°F and 1350°F.
Catalyst inlet temperature must be monitored on a daily basis.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 61
If the temperature is outside of this range, except during startup or shutdown, then appropriate
maintenance activities must be performed.
8.8.2 The pressure drop across the catalyst must be monitored and recorded monthly. The pressure
drop across the catalyst must 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 must be established by the source during each portable monitoring event
required by Condition 8.1.1.1 or as noted below.
If the pressure is outside this range, except during startup or shutdown, then the appropriate
maintenance must 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. If the test demonstrates that the engine is in compliance with its emission limits, the
pressure drop value at which the engine is tested must become the new baseline.
8.8.3 When portable monitoring is scheduled, the above parameters in Conditions 8.8.1 through 8.8.2
must be recorded during the portable monitoring event.
8.8.4 The engine exhaust oxygen content must be monitored and recorded during the portable
monitoring events required by Condition 8.1.1.1.
8.8.5 The catalyst must be cleaned, reconditioned, and replaced per the manufacturer's recommended
schedule and a copy of maintenance report must be kept. If the catalyst cleaning, reconditioning,
and replacement depends on hours of operation then the source must track the hour of operation
for the engine.
8.8.5.1 For new, cleaned (washed), or reconditioned catalyst on an existing engine, the new
pressure drop baseline must be established within the first fourteen (14) days of
engine/catalyst operation via portable analyzer test or appropriate reference method test
that demonstrates compliance with the engine's permitted NOx and CO emissions, and
re-established during the next regularly scheduled portable analyzer test.
8.8.5.2 For new, cleaned, or reconditioned catalyst on a new engine, the pressure drop baseline
must be established within the first 180 days of engine operation.
8.9 This engine is subject to the applicable requirements of Colorado Regulation No. 7, Part E, Section I,
"Control of Emissions from Engines". These requirements include, but are not limited to the following:
The requirements below reflect the current rule language as of the revisions to Colorado Regulation No.
7 adopted December 19, 2019. However, if revisions to the regulation are published at a later date, the
owner or operator is subject to the requirements contained in the latest adopted version of Colorado
Regulation No. 7.
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.
Operating Permit I5OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 62
8.9.1 (State Only) New, Modified and Relocated Natural Gas Fired Reciprocating Internal
Combustion Engines (Colorado Regulation No. 7, Part E, Section I.D).
8.9.1.1 Except as provided in Section I.D.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 Table 1 shall operate
and maintain each engine according to the manufacturer's written instruction 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 Section I.D.2.b. Table 1 (Colorado
Regulation No. 7, Part E, Section I.D.2.a).
8.9.1.2 Actual emissions from natural gas fired reciprocating internal combustion engines shall
not exceed the emission performance standards in Table 1 as expressed in units of
grams per horsepower -hour (G/hp-hr) (Colorado Regulation No. 7, Part E, Section
I.D.2.b)
Maximum
Engine Hp
Construction or
Relocation Date
Emission Standard in g/hp-hr
NOx
CO
VOC
≥ 100 Hp and
< 500 Hp
On or after Jan 1, 2008
2.0
4.0
1.0
On or after Jan 1, 2011
1.0
2.0
0.7
≥ 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
Compliance with the NOx and CO emission limitations shall be monitored by
conducting portable monitoring quarterly as specified in Condition 8.1.1.1. 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 8.9.1.2.
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 8.9.1.2.
8.10 This engine is subject to the applicable requirements in 40 CFR Part 60, Subpart JJJJ, "Standards of
Performance for Stationary Spark Ignition Internal Combustions Engines". These requirements include,
but are 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 the 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.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 63
These requirements have not been adopted into Colorado Regulation No. 8, Part E as of the date of this
permit issuance (DRAFT), and are therefore not state -enforceable. In the event that these requirements
are adopted into Colorado Regulations, they will become state -enforceable.
Am I subject to this subpart? 060.4230)
8.10.1 The provisions of this subpart are applicable to owners and operators of stationary SI ICE that
commence construction after June 12, 2006, where the stationary SI ICE are manufactured on or
after January 1, 2008, for lean burn engines with a maximum engine power greater than or equal
to 500 HP and less than 1,350 HP (§60.4230(a)(4)(ii)).
What emission standards must I meet if I am an owner or operator of a stationary SI internal
combustion engines? 060.4233)
8.10.2 Owners and operators of stationary SI ICE with a maximum engine power greater than or equal
to 75KW (100 HP) (except gasoline and rich burn engines that use LPG) must comply with the
emission standards in Table 1 to Subpart JJJJ for their Stationary SI ICE (§60.4233(e)).
Applicable Emission Standards for non -emergency SI lean burn natural gas ICE with a
maximum engine power 500 < HP < 1,350, manufactured on or after 7/1/2010 (Table 1 to
Subpart JJJJ)
8.10.2.1 NOx — 1.0 g/HP-hr
8.10.2.2 CO — 2.0 g/HP-hr
8.10.2.3 VOC — 0.7 g/HP-hr
How long must I meet the emission standards if I am an owner or operator of a stationary SI internal
combustion engine? 060.4234)
8.10.3 Owners and operators of stationary SI ICE must operate and maintain stationary SI ICE that
achieve the emission standards as required in §60.4233 over the entire life of the engine
(§60.4234(a)).
What are my compliance requirements if I am an owner or operator of a stationary SI internal
combustion engine? 060.4243)
8.10.4 If you are an owner or operator of a stationary SI internal combustion engine that is
manufactured after July 1, 2008, and must comply with the emission standards specified in
§60.4233(a) through (c), you must comply by purchasing an engine certified to the emission
standards in §60.4231(a) through (c), as applicable, for the same engine class and maximum
engine power. In addition, you must meet one of the requirements specified in (a)(1) and (2) of
this section (§60.4243(a)).
8.10.4.1 If you operate and maintain the certified stationary SI internal combustion engine and
control device according to the manufacturer's emission -related written instructions,
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 64
you must keep records of conducted maintenance to demonstrate compliance, but no
performance testing is required if you are an owner or operator. You must also meet
the requirements as specified in 40 CFR Part 1068 Subpart A through D, as they apply
to you. If you adjust engine settings according to and consistent with the manufacturer's
instructions, your stationary SI internal combustion engine will not be considered out
of compliance (§60.4243(a)(1)).
8.10.4.2 If you do not operate and maintain the certified stationary SI internal combustion
engine and control device according to the manufacturer's emission -related written
instructions, your engine will be considered a non -certified engine, and you must
demonstrate compliance according to (a)(2)(i) through (iii) as follows
(§60.4243(a)(2)).
a. If you are the 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 testing 1 year of
engine startup and conduct subsequent performance testing every 8,760 hours or 3
years, whichever comes first, thereafter to demonstrate compliance
(§60.4243(a)(2)(iii)).
8.10.5 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(d) or (e), you must demonstrate compliance
according to one of the methods specified in paragraphs (b)(1) and (2) of §60.4243
(§60.4243(b)).
8.10.5.1 Purchasing an engine certified according to procedures specified in Subpart JJJJ, for
the same model year and demonstrating compliance according to one the methods
specified in paragraph (a) of §60.4243 (§60.4243(b)(1)).
8.10.5.2 Purchasing a non -certified engine and demonstrating compliance with the emission
standards specified in §60.4233(d) or (e) and according to the requirements specified
in §60.4244, as applicable, and according to paragraphs (b)(2)(i) and (ii) of §60.4243
(§60.4243(b)(2)).
8.10.6 Owners and operators of stationary SI natural gas fired engines may operate their engines using
propane for a maximum of 100 hours per year as an alternative fuel solely during emergency
operations, but must keep records of such use. If propane is used for more than 100 hours per
year in an engine that is not certified to the emission standards when using propane, the owners
and operators are required to conduct a performance test to demonstrate compliance with the
emission standards of §60.4233 (§60.4243(e)).
8.10.7 It is expected that air -to -fuel ratio controllers will be used with the operation of three-way
catalysts/non-selective catalytic reduction. The AAFR 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)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 65
What are my notification, reporting, and recordkeeping requirements if I am an owner or operator of a
stationary SI internal combustion engine? 060.4245)
8.10.8 Owners and operator of all stationary SI ICE must keep records of the following information
(§60.4245(a)):
8.10.8.1 All notifications submitted to comply with this subpart and all documentation
supporting any notification (§60.4245(a)(1)).
8.10.8.2 Maintenance conducted on the engine (§60.4245(a)(2)).
8.10.8.3 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(a)(3)).
8.10.8.4 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)).
What parts of the General Provisions apply to me? 060.4246)
8.10.9 Table 3 to Subpart JJJJ shows which parts of the General Provisions in §§60.1 through 60.19
apply to you (§60.4246).
8.11 This engine is subject to the applicable requirements of General Provisions of 40 CFR Part 60 Subpart A
(40 CFR §§60.1 through 60.19, as adopted by reference in Colorado Regulation No. 6, Part A, Subpart
A) as specified in Subpart JJJJ §60.4246 (Condition 8.10.9) and as incorporated in Condition 17.
8.12 This engine is subject to the applicable requirements of National Emission Standards for Hazardous Air
Pollutants requirements of Regulation No. 8, Part E, Subpart ZZZZ (40 CFR Part 63, Subpart ZZZZ),
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 the 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.
These requirements have not been adopted into Colorado Regulation No. 8, Part E as of the date of this
permit issuance (DRAFT), and are therefore not state -enforceable. In the event that these requirements
are adopted into Colorado Regulations, they will become state -enforceable.
What parts of my plant does this subpart cover? 063.6590)
8.12.1 Stationary RICE subject to Regulations under 40 CFR Part 60. An affected source that a new or
reconstructed stationary RICE located at an area source of HAP emissions must meet the
requirements of this part by meeting the requirements of 40 CFR part 60 subpart JJJJ, for spark
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 66
ignition engines. No further requirements apply for such engines under this part
(§63.6590(c)(1)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 67
9. 023 — Eight (8) two-phase separators controlled by an open flare during gas -gathering system
downtime (RZ-SEP-1 through RZ-SEP-8, RZ-FLR-1)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
NOx
CO
9.1
1.3 tons/year
0.068 lb/Mils Btu
5.3 tons/year
0.31 lb/ MMBtu
VOC
9.2
17.3 tons/year
25,000 lb/MMscf
HAP Emissions
9.3
See Condition 9.3
Recordkeeping and
Calculation
Monthly
Natural Gas
Throughput
9.4
Extended Gas
Analysis
9.5
Opacity
9.6
27.7 MMscf/year
Not to Exceed 30%,
for a Period or
Periods Aggregating
More than Six (6)
Minutes in any 60
Consecutive Minutes
No Visible Emissions
Recordkeeping and
Calculation
Monthly
ASTM or Other
Division Approved
Method
Annually
See Condition 9.6
Control Requirements
9.7
See Condition 9.7
Statewide Controls
for Oil and Gas
Operations
9.8 & 9.9
See Conditions 9.8 & 9.9
9.1 Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from this flare shall not exceed the
limitations in Summary Table 9 above (Colorado Construction Permit 14WE0891). Compliance with the
emission limitations must be monitored on a monthly basis using the total monthly volume of natural
gas vented from the separators (as monitored by Condition 9.4), the appropriate heating value of the
vented gas as determined by the most recent annual extended gas analysis (as monitored by Condition
9.5), and the emission factors (NOx emission factor from AP -42, Table 13.5-1 and CO emission factor
from AP -42, Table 13.5-2 and) listed in Summary Table 9 above in the following equation:
CO & NOx Emissions (tpy)
Total Vented Gas Throughput (MMscf ) * EF * Gas Heating Value
lb (MMBtu)
Month (MMBtu) MMscf
2000 (ton
)
ton
Monthly emissions shall be calculated by the end of the subsequent month, which shall be used in a
twelve (12) month rolling total to monitor compliance with the annual limitations. By the end of the
subsequent month a new total shall be calculated using the previous month's data.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 68
9.2 Emissions of Volatile Organic Compounds (VOC) from the separators must not exceed the limitation in
Summary Table 9 above (Colorado Construction Permit 14WE0891). Monthly emissions of VOCs must
be calculated by the end of the subsequent month utilizing a site -specific emission factor (in units of
lb/MMscf vented) obtained from the most recent extended gas analysis as required by Condition 9.5, the
monthly quantity of natural gas as monitored by Condition 9.4 in the following equation:
MMscfTotal Natural Gas Vented (Month) * EF (MMscf)
VOC Emissions (tpy) = lb * 0.05
2000 (tn)l
During periods of gas -gathering system downtime emissions from these separators must be routed to an
open flare capable of reducing emissions of VOCs and HAPs to less than or equal to the emission limits
in Summary Table 9 above. A ninety-five percent (95%) control efficiency may be applied to VOC
emissions from these separators when emissions are routed to the flare during gas -gathering system
downtime and presuming the requirements of Conditions 9.7, 9.8, and 9.9 are satisfied.
If any site -specific emission factor developed through this analysis is greater than the emission factor
listed in Summary Table 9 above the permittee must submit to the Division within sixty (60) days a
request for permit modification to, at a minimum, update the emission factor to the higher site -specific
factor and update the emission limits accordingly (Colorado Construction Permit 14WE0891).
9.3 Emissions of Hazardous Air Pollutants (HAPs) from this emission point are subject to the facility -wide
HAP limits of Condition 12.1 (Colorado Construction Permit 14WE0891). For the purposes of
calculating monthly HAP emissions as required by Condition 12.1, each HAP fraction from the most
recent extended gas analysis as required by Condition 9.5 must be utilized in the calculation
methodology indicated in Condition 9.2. A ninety-five percent (95%) control efficiency may be applied
to HAPs associated with process streams controlled by this flare during periods when the flare is
operational presuming the requirements of Condition 9.8 are satisfied.
9.4 The quantity of gas combusted must not exceed the limitation in Summary Table 9 above (Colorado
Construction Permit 14WE0891, as modified under the provisions of Section I, Condition 1.3). The
quantity of waste gas combusted by this flare (natural gas vented from the separators during gas -
gathering system downtime) must be calculated and recorded monthly. This combusted gas throughput
must be used to calculate monthly emissions to be using in rolling twelve-month totals as specified in
Conditions 9.1, 9.2, and 9.3.
In order to quantify the amount of gas combusted by this process flare, the owner or operator must
continuously monitor and record the volumetric flow rate of natural gas vented from the separator(s)
using a flow meter (Colorado Construction Permit 14WE0891). The quantity of gas combusted must be
kept in a log and made available to the Division upon request. Monthly total gas combustion by the flare
must be used in a twelve-month rolling total to monitor compliance with the annual limitation. Each
month a new twelve month total must be calculated using the previous twelve months' data.
9.5 The permittee must conduct an annual extended gas analysis of the process streams routed to this flare
(Colorado Construction Permit 14WE0891). The extended gas analysis must be conducted as required
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 69
by Condition 12.2 and the results of the analysis must be utilized to calculate emissions as required by
Conditions 9.2 and 9.3.
9.6 This flare is subject to the following opacity requirements:
9.6.1 This flare is subject to the opacity standards of Colorado Regulation No. 1, Section II.A.5 as
incorporated into Condition 13.2.
In the absence of credible evidence to the contrary, compliance with the opacity limitation shall
be presumed as long as the requirements of Condition 9.6.2 are met.
9.6.2 Note that the no visible emissions requirement of Colorado Regulation No. 7, Part D, Section
II.B.2.b (Condition 15.2) also applies to this flare.
Note: This open flare has been approved as an alternative emission control device under
Colorado Regulation Number 7, Part D, Section II.B.2.e. This open flare must meet the
requirements specified in Colorado Regulation No. 7, Section Part D, II.B.2.b (Condition 15.2).
9.7 This flare shall be configured, operated, and maintained in such a way as to reduce emissions from the
separators (RZ-SEP-1 through RZ-SEP-8) to the less than or equal to the levels listed in Summary Table
9 above (Colorado Construction Permit 14WE0891, as modified under the provisions of Section I,
Condition 1.3). This flare must be operated at all times when emissions are routed to it.
9.8 This flare is subject to the applicable requirements of the Statewide Controls for Oil and Gas Operations
in Colorado Regulation No. 7, Part D, Section II.B as incorporated in Condition 15. (State -only
enforceable).
9.9 The separators at the Razor 21 CPB are subject to the applicable requirements of Colorado Regulation
No. 7, Part D, Section II.F (State -only enforceable) these requirements include, but are not limited to the
following:
The requirements below reflect the current rule language as of the revisions to Colorado Regulation No.
7 adopted December 19, 2019. However, if revisions to the regulation are published at a later date, the
owner or operator is subject to the requirements contained in the latest adopted version of Colorado
Regulation No. 7.
9.9.1 Well Operation and Maintenance: On or after August 1, 2014, gas coming off a separator,
produced during normal operation from any newly constructed, hydraulically fractured, or
recompleted oil and gas well, must either be routed to a gas gathering line or controlled from
commencement of operation by air pollution control equipment that achieves an average
hydrocarbon control efficiency of 95%. If a combustion device is used, it must have a design
destruction efficiency of at least 98% for hydrocarbons. (Colorado Regulation No. 7, Part D,
Section II.F).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 70
10. 024 — Twenty -Two (22) 400 bbl Fixed -Roof Produced Water Storage Tanks (RZ-PW-1 through RZ-
PW-22)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
VOC Emissions
10.1
Opacity (Control
Equipment)
0.3 tons/year
0.0241 lb/bbl
Recordkeeping and
Calculation
Monthly
Not to Exceed 30%,
for a Period or
Periods Aggregating
More than Six (6)
Minutes in any 60
Consecutive Minutes
No Visible Emissions
Hazardous Air
Pollutants
10.2
See Condition 10.2
Produced Water
Throughput
10.3
Statewide Controls
for Oil & Gas
Operations
10.4
547,500 bbl/year
See Condition 10.1
See Condition 10.2
Recordkeeping and
Calculation
Monthly
See Condition 10.4
10.1 Emissions of Volatile Organic Compounds (VOC) must not exceed the limitation listed in Summary
Table 10 above (Colorado Construction Permit 14WE0892). Compliance with the annual emission limit
must be monitored on a rolling twelve (12) month basis. By the end of each subsequent month a new
twelve-month total must be calculated based on the previous twelve months' data. Records of the actual
emissions must be maintained and made available to the Division upon request.
Emissions for each month must be calculated using the site -specific emission factor and the monthly
produced water throughput, as monitored by Condition 10.3. Records of the actual emissions must be
maintained and made available to the Division upon request.
These tanks must meet the following control requirements:
10.1.1 These tanks must be configured in a manner that the vapor stream is routed to an enclosed
combustor (Colorado Construction Permit 14WE0892). The enclosed combustor must be capable
of reducing VOC and HAP emissions to the levels listed in Summary Table 10 above. This
enclosed combustor must meet the requirements statewide control requirements for oil and gas
operations as incorporated into Condition 15 and a ninety-five (95%) percent control efficiency
may be applied to uncontrolled VOC and HAP tank emission (as calculated in Condition 10.1
and 10.2) presuming the requirements of Colorado Regulation No. 7, Part D, Section II.B (as
incorporated in Condition 15) are satisfied.
10.1.1.1 This enclosed combustor is subject to the following opacity requirements:
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 71
a. This enclosed combustor is subject to the opacity standards of Colorado Regulation
No. 1, Section II.A.5 as incorporated into Condition 13.2.
In the absence of credible evidence to the contrary, compliance with this opacity
limitation shall be presumed as long as the provisions of Condition 15 are satisfied.
b. Note that the no visible emissions requirement of Condition 15.2 also applies to this
enclosed combustor (Colorado Construction Permit 14WE0892 and Colorado
Regulation No. 7, Part D, II.B.2.b).
In the absence of credible evidence to the contrary, compliance with this opacity
limitation shall be presumed as long as the provisions of Condition 15 are satisfied.
10.1.2 The enclosed combustor must be operated at all times when emissions are routed to it.
10.2 Emissions of Hazardous Air Pollutants (HAPs) from these tanks are subject to the facility -wide HAP
limits of Condition 12.1 (Colorado Construction Permit 14WE0892). For the purposes of calculating
monthly HAP emissions as required by Condition 12.1 the permittee must utilize the HAP emission
factors derived from the annual liquids analysis as required by Condition 12.2 and a ninety-five percent
(95%) control efficiency for times when the enclosed combustor operated as monitored by Conditions
10.1.1 and 10.1.2.
10.3 The quantity of produced water processed through these tanks shall not exceed the limitation in
Summary Table 10 above (Colorado Construction Permit 14WE0892). The quantity of produced water
processed through the tanks shall be monitored and recorded monthly and used to calculate emissions as
required by Conditions 10.1 and 10.2. Compliance with the annual throughput limits shall be determined
on a rolling twelve-month total. By the end of each month a new twelve-month total shall be calculated
based on the previous twelve months' data. The permittee shall calculate throughput each month and
keep a compliance record on site or at a local field office with site responsibility for Division review
upon request.
10.4 This tank battery is subject to the applicable requirements of Statewide Controls for Oil and Gas
Operations in Colorado Regulation No. 7, Part D, Section II.C as incorporated into Condition 16 (State -
only enforceable).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 72
11. 025 — Thirty-two 400 BBL fixed roof, Crude Oil Storage Tanks (RZ-TK-1 through RZ-RK-32)
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
VOC Emissions
Opacity (Control
Equipment)
45.0 tons/year
See Condition 11.1
Recordkeeping and
Calculation
Monthly
Not to Exceed 30%,
for a Period or
Periods Aggregating
More than Six (6)
Minutes in any 60
Consecutive Minutes
No Visible Emissions
Hazardous Air
Pollutants
11.2
See Condition 11.2
0.013 lb/bbl
See Condition 11.1
See Condition 11.2
NOx
CO
11.3
1.4 tons/year
5.8 tons/year
0.053 lb/bbl
Recordkeeping and
Calculation
Monthly
Crude Oil Throughput
11.3
Site -Specific
Sampling
11.5
Operation
Configuration
Requirements
11.6
Statewide Controls
for Oil & Gas
Operations
11.7
219,000 bbl/year
Recordkeeping and
Calculation
Monthly
See Condition 11.5
See Condition 11.6
See Condition 11.7
Emissions of Volatile Organic Compounds (VOC) must not exceed the limitation listed in Summary
Table 11 above (Colorado Construction Permit 14WE0893). Compliance with the annual emission limit
must be monitored on a rolling twelve (12) month basis. By the end of each subsequent month a new
twelve-month total must be calculated based on the previous twelve months' data. Records of the actual
emissions must be maintained and made available to the Division upon request.
VOC Emissions
(Tons"
\Month)
— Total Crude Throughput (Month)* EF \obl� * Combustor Hours of Operation (month)
2000 (lb 1 Hours in Month
ton)
* 0.95
The owner or operator may utilize the site -specific emission factor of 8.122 lb/bbl in the above equation
to calculate monthly VOC emissions provided the monitoring and validation requirements below are
satisfied.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 73
If the annual liquids analysis and other monitoring required by Condition 11.5, or any operational
change occurs that would affect the site -specific emission factor indicated above the owner or operator
must document the change in a log to be made available the division. The log must indicate the date of
the analysis or change, a description of the analysis or operational change, and the effect the change has
on the site -specific emission factor. If any liquids analysis or operational changes occur that would result
in a higher emission factor, the owner or operator must re -calculate the site -specific emission factor
utilizing the method specified in current division guidance and submit a modification to the division
with thirty (30) days of discovery to, at a minimum, modify the emission factor listed in this permit and,
if necessary, modify the annual VOC emission limit (Colorado Regulation No. 3, Part C, Section V.C.5).
These tanks must meet the following control requirements:
11.1.1 These tanks must be configured in a manner that the vapor stream is routed to an enclosed
combustor (Colorado Construction Permit 14WE0893). The enclosed combustor must be capable
of reducing VOC and HAP emissions to the levels listed in Summary Table 11 above.
11.1.1.1 This enclosed combustor must meet the requirements statewide control requirements
for oil and gas operations as incorporated into Condition 15 and a ninety-five (95%)
percent control efficiency may be applied to uncontrolled VOC and HAP tank emission
(as calculated in Condition 11.1 and 11.2) presuming the requirements of Condition 15
are satisfied.
11.1.1.2 This enclosed combustor is subject to the following opacity requirements:
a. This flare is subject to the opacity standards of Colorado Regulation No. 1, Section
II.A.5 as incorporated into Condition 13.2.
In the absence of credible evidence to the contrary, compliance with this opacity
limitation shall be presumed as long as the provisions of Condition 15 are satisfied.
b. Note that the no visible emissions requirement of Condition 15.2 also applies to this
enclosed combustor (Colorado Construction Permit 14WE0893 and Colorado
Regulation No. 7, Part D, II.B.2.b).
In the absence of credible evidence to the contrary, compliance with this opacity
limitation shall be presumed as long as the provisions of Condition 15 are satisfied.
11.1.2 The enclosed combustor must be operated at times when emissions are routed to it. The owner or
operator must monitor the hours of tank operation during any periods of combustor downtime for
use in the emission calculations as required by Condition 11.1 (Colorado Regulation No. 3, Part
C, Section V.C.5). Records of tank operation during combustor downtime must be kept in a log
to be made available to the Division upon request.
11.2 Emissions of Hazardous Air Pollutants (HAPs) from these tanks are subject to the facility -wide HAP
limits of Condition 12.1 (Colorado Construction Permit 14WE0893). For the purposes of calculating
monthly HAP emissions as required by Condition 12.1 the owner or operator may utilize the HAP
emission factors listed in the table below and a ninety-five percent (95%) control efficiency for times
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 74
when the flare is operated as monitored by Conditions 11.1.1 and 11.1.2 provided the monitoring and
validation criteria of Condition 11.1 are satisfied.
Pollutant
Uncontrolled Emission Factors
(lb/bbl)
Benzene
0.019
Toluene
0.012
Ethylbenzene
0.002
Xylenes
0.005
n -Hexane
0.189
2, 2, 4-Trimethylpentane
0.015
11.3 Emissions of Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from the enclosed combustor
controlling emissions from these tanks must not exceed the limitations in Summary Table 11 above
(Colorado Construction Permit 14WE0893). Compliance with the emission limitations must be
monitored monthly using the monthly quantity of condensate throughput (as required by Condition 11.4)
and the emission factors in Summary Table 11 above (NOx and CO emission factors from Colorado
Construction Permit 14WE0893) in the equation below:
Total Crude Throughput (Month] * EP lbbl�
CO & NOx Emissions (tpy) = lb
2000 (ton)
Monthly emissions must be calculated by the end of the subsequent month, which must be used in a
rolling twelve month total to monitor compliance with the annual limitations. Each month a new twelve
month total must be calculated using the previous twelve months' data. Records of these calculations
must be maintained and made available to the Division upon request.
11.4 The quantity of condensate processed through these tanks shall not exceed the limitation in Summary
Table 11 above (Colorado Construction Permit 14WE0893). The quantity of condensate processed
through the tanks shall be monitored and recorded monthly though sales or haul tickets. Monthly
throughput values must be used to calculate emissions as required by Conditions 11.1 and 11.2.
Compliance with the annual throughput limits shall be determined on a rolling twelve-month total. By
the end of each month a new twelve-month total shall be calculated based on the previous twelve
months' data. The permittee shall calculate throughput each month and keep a compliance record on site
or at a local field office with site responsibility for Division review upon request.
11.5 On an annual basis, the owner of operator shall complete site specific sampling including a
compositional analysis of the pre -flash pressurized crude oil routed to these storage tanks and, if
necessary for emission factor development, a sales oil analysis to determine RVP and API gravity.
Testing shall be in accordance with the guidance current Division guidance. Results of the analysis shall
be used to calculate site -specific emission factors for the pollutants referenced in the Condition (in units
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 75
of lb/bbl) using Division -approved methods. Results of the analysis shall be used to demonstrate that the
emission factors established through the analysis are less than or equal to the emission factor listed in
Summary Table 11 above. If any site specific emission factors developed through this analysis is greater
than the emission factors listed in Summary Table 11 above the owner or operator must submit to the
Division within thirty (30) days a request for permit modification to address at a minimum the new
emission factors (Colorado Construction Permit 14WE0893, as modified under the provisions of Section
I, Condition 1.3).
11.6 The tanks grouped under this emission unit must be operated in parallel to meet the exemption for
storage tanks with the potential to emit VOC emissions less than six tons per year or 40 CFR Part 60
Subpart OOOO (§60.5365(e)). If these storage tanks are not operated in parallel these emission units
will be subject to the applicable requirements of 40 CFR Part 60 Subpart OOOO. Records of the
operational configuration must be maintained and made available to the Division upon request.
11.7 This tank battery is subject to the Statewide Controls for Oil and Gas Operations in Colorado Regulation
No. 7, Part D, Section II as incorporated into Condition 16 (State -only enforceable).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
12. Facility -Wide Requirements
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 76
Parameter
Permit
Condition
Number
Limitation
Compliance Emission
Factor
Monitoring
Method
Interval
HAP Emissions
12.1
Extended Gas
Analysis
12.2
Insignificant Tracking
12.3
Any Single HAP: 9.0
tons/year
Total HAPs: 24.0
tons/year
See Condition 12.1
Recordkeeping and
Calculation
Monthly
See Condition 12.2
See Condition 12.3
12.1 Facility -wide total Hazardous Air Pollutants (HAP) emissions must not exceed the limitations stated in
Summary Table 12 above (Colorado Construction 14WE0893).
Compliance with the facility -wide HAP limits must be monitored by calculating HAP emissions in
accordance with the provisions of Conditions 1.2, 2.2, 3.3, 4.3, 5.2, 6.1.1, 7.2, 8.3, 9.2, 10.2, and 11.2.
Monthly emissions of each individual reportable HAP for each emission unit must be summed with the
monthly individual reportable HAP emissions from the other emission units and twelve-month rolling
totals of facility -wide individual HAP emissions will be maintained to monitor compliance with the
annual single HAP emission limit above. Each month a new twelve-month total must be calculated using
the previous twelve months' data.
Monthly emissions of total reportable HAPs must be summed with the monthly total reportable HAP
emissions from the other emission units and a twelve-month rolling total of facility -wide total HAP
emissions will be maintained to monitor compliance with the annual total HAP emissions limit. Each
month a new twelve-month total must be calculated using the previous twelve months' data.
Monthly emissions of each individual HAP above de-minimis reporting levels from each emission unit,
must be calculated by the end of the subsequent month on a rolling twelve (12) month basis. A twelve-
month rolling total of emissions must be maintained in order to monitor compliance with the previous
twelve months' data. Records of calculations must be maintained on site or at a local field office with
site responsibility and made available to the Division for inspection upon request.
12.2 On an annual basis, the permittee must complete an extended gas analysis of the gas samples that are
representative of volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) as required
by Conditions 1.3, 3.2, 5.4, 6.1.3, and 9.5 according to the appropriate ASTM Methods, or equivalent, if
approved in advance by the Division (Colorado Construction Permits 13WE1130, 13WE3005,
13WE3006, and 14WE0891)
AIRS 017: The speciated sulfur analysis must identify the concentration of hydrogen sulfide (H2S) and
total sulfur in the gas fed into the amine unit as required by Condition 6.1.3.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 77
The results of the extended gas and speciated sulfur analysis must be retained according to the schedule
in Section IV, Condition 22.b and be made available to the Division upon request.
The compositions indicated by the most recent extended gas analysis must be used in the monthly
process models or emissions calculations as required by Conditions 1.1, 5.1, 6.1, 7.1, 10.1, and 11.1.
12.3 The permittee must track all insignificant activities at the facility on an annual basis to monitor
compliance with the facility potential emission limitations (PTE) as indicated in Conditions 12.3.1
through 12.3.2. Compliance with the limitation must be monitored by conducting a PTE analysis of
HAP and VOC emissions from all insignificant activities, permitted points and grandfathered points.
This PTE analysis must be completed within 60 days of this permit issuance. The PTE for insignificant
activities 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 must be updated if any new insignificant activities
that can potentially emit HAP or VOC are added to this facility. In addition, the PTE analysis must 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, must 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 or VOC 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.
12.3.1 The PTE of each individual HAP from all insignificant activities and permitted points combined
must not exceed 10 tons per year.
12.3.2 The PTE of total HAP emissions from all insignificant activities and permitted points combined
must not exceed 25 tons per year.
13. Colorado Regulation No. 1 Opacity Standards
13.1 Requirements for equipment and air pollution control equipment except as provided for in Condition
13.2:
13.1.1 No owner or operator of a source shall allow or cause to be emitted into the atmosphere 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 startup, process modification, or adjustment of control equipment which
is in 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 The owner or operator must complete a daily visual inspection of the air pollution control
equipment to ensure that the valves for the piping from the units routed to the air pollution
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 78
control equipment are open. The results of this daily visual inspection must be kept on file and
made available to the Division upon request.
13.1.4 The permittee must conduct a daily inspection of this thermal oxidizer to determine the presence
or absence of visible emissions in any five (5) minute period of normal operation when the air
pollution control equipment is combusting waste gases. The results of this daily visual emission
observation must be kept of file and made available the Division upon request. In the event that
visible emissions are observed, an EPA Reference Method 9 opacity observation must be
performed to monitor compliance with the opacity standard, as follows:
13.1.4.1 The EPA Reference Method 9 opacity observations must 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.
13.1.4.2 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 limit (Condition 13.1.1 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.
13.1.4.3 The result(s) of the visual observations and the Method 9 observations must be kept on
file and made available for Division review upon request.
13.1.5 This air pollution control equipment must be operated at all times when emissions are routed to
it.
13.2 Requirements for smokeless flares or other flares for the combustion of waste gases:
13.2.1 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 thirty
percent (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.5).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
14. Additional Requirements: Colorado Regulation No. 7
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 79
The requirements below reflect the current rule language as of the revisions to Colorado Regulation No.
7 adopted December 19, 2019. However, if revisions to the regulation are published at a later date, the
owner or operator is subject to the requirements contained in the latest adopted version of Colorado
Regulation No. 7.
14.1 General Provisions (State Only)
14.1.1 All hydrocarbon liquids and produced water collection, storage, processing, and handling
operations, regardless of size, must be designed, operated, and maintained so as to minimize
emission of VOCs and other hydrocarbons to the atmosphere to the extent reasonably practicable
(Colorado Regulation No. 7, Part D, Section II.B.1.a).
14.1.2 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, Part D, Section II.B.1.b).
14.2 General requirements for air pollution control equipment used to comply with Section II (State Only)
14.2.1 All air pollution control equipment must 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 must keep manufacturer specifications or equivalent on file. In addition, all such air
pollution control equipment must 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, Part D,
Section II.B.2.a).
14.3 Razor 21 CPB only: Requirements for leak detection and repair program for well production facilities
(Colorado Regulation No. 7, Part D, Section II.E) (State Only)
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.
14.3.1 Owners or operators of well production facilities or natural gas compressor stations that monitor
components as part of Section II.E. may estimate uncontrolled actual emissions from
components for the purpose of evaluating the applicability of component fugitive emissions to
Regulation Number 3 by utilizing the emission factors defined as less than 10,000 ppmv of Table
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 80
2-8 of the 1995 EPA Protocol for Equipment Leak Emission Estimates (Document EPA -453/R-
95-017). (Colorado Regulation No. 7, Part D, Section II.E.2).
14.3.2 Requirements for well production facilities (Colorado Regulation No. 7, Part D, Section II.E.4)
14.3.2.1 Owners or operators of well production facilities constructed before October 15, 2014,
must identify leaks from components using an approved instrument monitoring method
within ninety (90) days of the Phase -In Schedule in Table 4; within thirty (30) days for
well production facilities subject to monthly approved instrument monitoring method
inspections; or by January 1, 2016, for well production facilities subject to a one time
approved instrument monitoring method inspection. Thereafter, approved instrument
monitoring method and AVO inspections must be conducted in accordance with the
inspection frequencies in Table 3 (Colorado Regulation No. 7, Part D, Section II.E.4.b).
*For the purposes of this condition, approved instrument monitoring method means
an infra -red camera, or EPA Method 21.
14.3.2.2 Beginning calendar year 2020, owners or operators of well production facilities with
estimated uncontrolled actual VOC emissions greater than or equal to two (2) but less
than or equal to twelve (12) tons per year, based on a rolling twelve-month total, must
inspect components for leaks using an approved instrument monitoring method at least
semi-annually (Colorado Regulation No. 7, Part D, Section II.E.4.c).
14.3.2.3 Beginning calendar year 2020, owners or operators of well production facilities with
estimated uncontrolled actual VOC emissions greater than or equal to tow (2) tons per
year, based on a rolling twelve-month total, and located within 1,000 feet of an
occupied area must inspect components for leaks using an approved instrument
monitoring method in accordance with the inspection frequency in Table 3.II.E.4.e.
The estimated uncontrolled actual VOC emissions from the highest emitting storage
tank at the well production facility determines the frequency at which inspections must
be performed. If no storage tanks storing oil or condensate are located at the well
production facility, owners or operator must rely on the facility emission s(controlled
actual VOC emissions from all permanent equipment, including emissions from
components determined by utilizing the emission factors defined as less than 10,000
ppmv of Table 2-8 of the 1995 EPA Protocol for Equipment Leak Emission Estimates)
(Colorado Regulation No. 7, Part D, Section II.F.4.d).
Table 3 — Well Production Facility Component Inspections
Thresholds (per II.F.4.d)
Well
production
facilities
without storage
Well
production
facilities with
storage tanks
Approved
Instrument
Monitoring
Method
AVO
Inspection
Frequency
Phase -In
Schedule
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 81
tanks (rolling
12 -month tpy)
(rolling 12-
month tpy)
Inspection
Frequency
> 0 and < 2
> 0 and < 2
One time
Monthly
January
1, 2016
> 2 and < 12
> 2 and < 12
Semi-annually
Monthly
*begins
in 2020
> 2 and < 12,
located within
1,000 feet of an
occupied area
> 2 and < 12,
located within
1,000 feet of an
occupied area
Quarterly
Monthly
*begins
in 2020
> 12 and < 20
> 12 and < 50
Quarterly
Monthly
January
1, 2015
> 12, located
within 1,000
feet of an
occupied area
> 12, located
within 1,000
feet of an
occupied
Monthly
*begins
in 2020
> 20
> 50
Monthly
January
1, 2015
14.3.2.4 If a component is unsafe, difficult, or inaccessible to monitor, the owner or operator is
not required to monitor the component until it becomes feasible to do so (Colorado
Regulation No. 7, Part D, Section II.E.5).
a. Difficult to monitor components are those that cannot be monitored without
elevating the monitoring personnel more than two (2) meters above a supported
surface or are unable to be reached via a wheeled scissor -lift or hydraulic type
scaffold that allows access to components up to 7.6 meters (25 feet) above the
ground (Colorado Regulation No. 7, Part D, Section II.E.5.a).
b. Unsafe to monitor components are those that cannot be monitored without exposing
monitoring personnel to an immediate danger as a consequence of completing the
monitoring (Colorado Regulation No. 7, Part D, Section II.E.5.b).
c. Inaccessible to monitor components are those that are buried, insulated, or
obstructed by equipment or piping that prevents access to the components by
monitoring personnel (Colorado Regulation No. 7, Part D, Section II.E.5.c).
14.3.2.5 Leaks requiring repair: Leaks must be identified utilizing the methods listed in Section
II.E.6 (Conditions 17.3.2.4.a through 17.3.2.4.d). Only leaks from components
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 82
exceeding the thresholds in Section II.E.6 (Conditions 17.3.2.4.a through 17.3.2.4.d)
require repair under Section II.E.7 (Condition 14.3.2.6) (Colorado Regulation No. 7,
Part D, Section II.E.6).
a. For EPA Method 21 monitoring, at facilities constructed before May 1, 2014, repair
is required for leaks with any concentration of hydrocarbon above 2,000 parts per
million (ppm) not associated with normal equipment operation, such as pneumatic
device actuation and crank case ventilation, except for well production facilities
where a leak is defined as any concentration of hydrocarbon above 500 ppm not
associated with normal equipment operation, such as pneumatic device actuation
and crank case ventilation (Colorado Regulation No. 7, Part D, Section II.E.6.a).
b. For infra -red camera and AVO monitoring, repair is required for leaks with any
detectable emissions not associated with normal operation, such as pneumatic
device actuation and crank case ventilation (Colorado Regulation No. 7, Part D,
Section II.E.6.c).
c. For other Division approved instrument monitoring methods or programs, leak
identification requiring repair will be established as set forth in the Division's
approval (Colorado Regulation No. 7, Part D, Section II.E.6.d).
d. For leaks identified using an approved non -quantitative instrument monitoring
method or AVO, owners or operators have the option of either repairing the leak in
accordance with the repair schedule set forth in in Section II.E.7 or conducting
follow-up monitoring using EPA Method 21 within five (5) working days of the
leak detection. If the follow-up EPA Method 21 monitoring shows that the emission
is a leak requiring repair as set forth in Section II.E.6, the leak must be repaired and
remonitored in accordance with Section II.E.7 (Colorado Regulation No. 7, Part D,
Section II.E.6.e).
14.3.2.6 Repair and remonitoring (Colorado Regulation No. 7, Part D, Section II.E.7).
a. First attempt to repair a leak must be made no later than five (5) working days after
discovery and repair of the leak discovered on or after January 1, 2018, completed
no later than thirty (30) working days after discovery, unless parts are unavailable,
the equipment requires shutdown, or other good cause exists (Colorado Regulation
No. 7, Part D, Section II.E.7.a).
(i) If parts are unavailable, they must be ordered promptly and the
repair must be made within fifteen (15) working days of receipt of
the parts (Colorado Regulation No. 7, Part D, Section II.E.7.a.(i)).
(ii) 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, Part D, Section
II.E.7.a.(ii)).
(iii)If delay is attributable to other good cause, repairs must be
completed within fifteen (15) working days after the cause of delay
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 83
14.3.2.7
ceases to exist (Colorado Regulation No. 7, Part D, Section
II.E.7.a.(iii)).
b. Within fifteen (15) working days of completion of a repair, the leak must be
remonitored using an approved instrument monitoring method to verify that the
repair was effective (Colorado Regulation No. 7, Part D, Section II.E.7.b).
c. Leaks discovered pursuant to the leak detection methods of Section II.E.6 are not
subject to enforcement by the Division unless the owner or operator fails to perform
the required repairs in accordance with Section II.E.7 or keep required records in
accordance with Section II.E.8 (Colorado Regulation No. 7, Part D, Section
II.E.7.c).
Recordkeeping: The owner or operator of each facility subject to the leak detection and
repair requirements in Section II.E must maintain the following records and make them
available to the Division upon request (Colorado Regulation No. 7, Part D, Section
II.E.8). Note that in accordance with the requirements in Section IV, Conditions 22.b
and c, records shall be kept for a period of five (5) years.
a. Documentation of the initial approved instrument monitoring method inspection for
new well production facilities (Colorado Regulation No. 7, Part D, Section
II.E.8.a);
b. The date, facility name, and facility AIRS ID or facility location if the facility does
not have an AIRS ID for each inspection (Colorado Regulation No. 7, Part D,
Section II.E.8.b);
c. A list of the leaking component requiring repair and the monitoring method(s) used
to determine the presence of the leak (Colorado Regulation No. 7, Part D, Section
II.E.8.c);
d. The date of first attempt to repair the leak and, if necessary, any additional attempt
to repair the leak (Colorado Regulation No. 7, Part D, Section II.E.8.d).;
e. The date the leak was repaired and for leaks discovered and repaired on or after
January 1, 2018, the type of repair method applied (Colorado Regulation No. 7,
Part D, Section II.E.8.e);
f. The delayed repair list, including the basis for placing leaks on the list (Colorado
Regulation No. 7, Part D, Section II.E.8.f);
For leaks discovered on or after January 1, 2018, the delayed repair list must include
the date and duration or any period where the repair of a leak was delayed due to
unavailable parts, required shutdown, or delay for other good cause, the basis for
the delay, and the schedule for repairing the leak. Delay of repair beyond thirty (30)
days after initial discovery due to unavailable parts must be reviewed, and a record
kept of that review, by a representative of the owner of operator with responsibility
for leak detection and repair compliance functions. This review will not be made
by the individual making the initial determinations to place a part on the delay
repair list (Colorado Regulation No. 7, Part D, Section II.E.8.g);
g.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 84
h. The date the leak was remonitored and the results of the remonitoring (Colorado
Regulation No. 7, Part D, Section II.E.8.h);
i. A list of components that are designated as unsafe, difficult, or inaccessible to
monitor, a described in Section II.E.5, an explanation stating why the component
is so designated, and the schedule for monitoring such component(s) (Colorado
Regulation No. 7, Part D, Section II.E.8.i).
14.3.2.8 The owner or operator shall maintain records that document the categories of
equipment operation that may result in emission but are not considered to the leaks
under Colorado Regulation No. 7, Section II.E.6 (Condition 14.3.2.5) because they
qualify as "normal equipment operation ". This requirement shall not apply to
pneumatic device actuation and crankcase ventilation, which are already explicitly
defined in the rule as normal equipment operation. The records shall include a
description of each category or type of "normal equipment operation" and a
description of the component or equipment type associated with that category.
14.3.2.9 Reporting: The owner or operator of each facility subject to the leak detection and
repair requirements in Section II.E must submit a dingle annual report on or before
May 31St of each year that includes, at a minimum, the following information regarding
leak detection and repair activities at their subject facilities conducted for calendar
years prior to January 1, 2018 (Colorado Regulation No. 7, Part D, Section II.E.9):
a. The total number of well production facilities and total number of natural gas
compressor stations inspected (Colorado Regulation No. 7, Part D, Section
II.E.9.a);
b. The total number of inspections performed per inspection frequency tier of well
production facilities and inspection frequency tier of natural gas compressor
stations (Colorado Regulation No. 7, Part D, Section II.E.9.b);
c. The total number of leaks identified, broken out by component type, monitoring
method, and inspection frequency tier of well production facilities, as reported in
Section II.E.9.b, or inspection frequency tier of natural gas compressor stations
(Colorado Regulation No. 7, Part D, Section II.E.9.c);
d. The total number of leaks repaired for each inspection frequency tier of well
production facilities, as reported in Section II.E.9b, or inspection frequency tier of
natural gas compressor stations (Colorado Regulation No. 7, Part D, Section
II.E.9.d);
e. The total number of leaks on the delayed repair list as of December 31St broken out
by component type, inspection frequency tier of well production facilities, as
reported in Section II.E.9.b, or inspection frequency tier of natural gas compressor
stations, and the basis for each delay of repair (Colorado Regulation No. 7, Part D,
Section II.E.9.e);
f. The record of all reviews conducted for delayed repairs due to unavailable parts
extending beyond 30 days for the previous calendar year (Colorado Regulation No.
7, Part D, Section II.E.9.f); and
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 85
g. Each report shall be accompanied by a certification by a responsible official that,
based on information and belief formed after reasonable inquiry, the statements and
information in the document are true, accurate, and complete (Colorado Regulation
No. 7, Part D, Section II.E.9.g).
14.3.2.10 This facility is subject to the general requirements of Condition 14.1.
14.4 Requirements for compressor seals and open-ended lines at Razor 21 Central Production Battery
14.4.1 Beginning January 1, 2015, each open-ended valve or line at well production facilities and
natural gas compressor stations must be equipped with a cap, blind flange, plug, or a second
valve that seals the open end at all times except during operations requiring process fluid flow
through the open-ended valve or line. Open-ended valves or lines in an emergency shutdown
system which are designed to open automatically in the event of a process upset are exempt from
the requirement to seal the open end of the valve or line. Alternatively, an open- ended valve or
line may be treated as if it is a "component" as defined in Section II.A.7., and may be monitored
under the provisions of Section II.E (Colorado Regulation No. 7, Part D, Section II.B.3.a).
The owner or operator of affected operations shall maintain records documenting the location of
each open-ended valve or line and whether each is: (1) capped, blind flanged, plugged or
equipped with a second valve, (2) exempt due to location in an emergency shutdown system, or
(3) treated as a "component" and subject to the Leak Detection and Repair Program
requirements in Condition 14.5. These records shall be updated on an annual basis. Such
records shall be maintained and made available for Division review.
14.4.2 Beginning January 1, 2015, uncontrolled actual hydrocarbon emissions from wet seal fluid
degassing systems on wet seal centrifugal compressors must be reduced by at least 95%, unless
the centrifugal compressor is subject to 40 CFR Part 60, Subpart OOOO (February 23, 2014) on
that date or thereafter. (Colorado Regulation No. 7, Part D, Section II.B.3.b).
14.4.3 Beginning January 1, 2015, the rod packing on any reciprocating compressor located at a natural
gas compressor station must be replaced every 26,000 hours of operation or every thirty six (36)
months, unless the reciprocating compressor is subject to 40 CFR Part 60, Subpart OOOO
(February 23, 2014) on that date or thereafter. The measurement of accumulated hours of
operation (26,000) or months elapsed (36) begins on January 1, 2015. (Colorado Regulation No.
7, Part D, Section II.B.3.c).
The owner or operator shall record:
• the number of hours of operation for each reciprocating compressor on a
monthly basis and maintain a total of hours of operation for each
reciprocating compressor since initial startup, January 1, 2015, or the date of
the most recent reciprocating compressor rod packing replacement,
whichever is later,
OR
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 86
• the number of months since initial startup, January 1, 2015, or the date of the
most recent reciprocating compressor rod packing replacement, whichever is
later.
Such records shall be maintained and made available to the Division for review.
14.5 Razor 21 CPB only: Natural Gas -Actuated Pneumatic Controllers Associated with Oil and Gas
Operations (Colorado Regulation No. 7, Part D, Section III)
14.5.1 (State Only) Owners and operators of all pneumatic controllers placed in service on or after May
1, 2014, must (Colorado Regulation No. 7, Part D, Section III.C.3.a):
14.5.1.1 Utilize no -bleed pneumatic controllers where on -site electrical grid power is being used
and use of a no -bleed pneumatic controllers is technically and economically feasible
(Colorado Regulation No. 7, Part D, Section III.C.3.a.(i)).
14.5.1.2 If on -site electoral grid power is not being used or a no -bleed pneumatic controller is
not technically and economically feasible, utilize pneumatic controllers that emit
natural gas emissions in an amount equal to or less than a low -bleed pneumatic
controllers, unless allowed pursuant to Section III.C.3.c (Condition 14.5.1) (Colorado
Regulation No. 7, Part D, Section III.C.3.a.(ii)).
14.5.1.3 For purposes of Section III.C.3.a.(ii) (Condition 14.5.1.2), instead of a low -bleed
pneumatic controller, owners or operators may utilize a natural gas driven intermittent
pneumatic controller (Colorado Regulation No. 7, Part D, Section III.C.3.a.(iii)).
14.5.1.4 Utilizing self-contained pneumatic controllers satisfies Section III.C.3.a.(i) (Condition
14.5.1.1) (Colorado Regulation No. 7, Part D, Section III.C.3.a.(iv)).
14.5.2 Recordkeeping — This section applies to pneumatic controllers identified in Sections III.C.1.c
and III.C.2.c (State Only: and in Section III.C.3.c) (Colorado Regulation No. 7, Part D, Section
III.E.2)
14.5.2.1 The owner or operator must maintain a log of the total number of pneumatic controllers
and their associated controller numbers per facility, the total number of pneumatic
controllers per company and the associated justification that the pneumatic controllers
must be used pursuant to Sections III.C.1.c. and III.C.2.c. (State Only: and in Section
III.C.3.c.). The log shall be updated on a monthly basis (Colorado Regulation No. 7,
Part D, Section III.E.2.a).
14.5.2.2 The owner or operator must maintain a log of necessary maintenance which shall
include, at a minimum, inspection dates, the date of the maintenance activity,
pneumatic controller number, description of the maintenance performed, results and
date of any corrective action taken, and the printed name and signature of the individual
performing the maintenance. The log shall be updated on a monthly basis. (Colorado
Regulation No. 7, Part D, Section III.E.2.b).
14.5.2.3 Records of maintenance of pneumatic controllers must be maintained according the
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 87
schedule in Section IV, Condition 22. b and made available to the Division upon
request.
14.5.3 (State Only) Pneumatic Controller Inspection and Enhanced Response (Colorado Regulation No.
7, Part D, Section III.F)
14.5.3.1 General Requirements (Colorado Regulation No. 7, Part D, Section III.F.1)
a. Beginning May 1, 2020, owners or operators of natural gas -driven pneumatic
controllers state-wide must operate and maintain pneumatic controllers consistent
with manufacturer's specifications, if available, or good engineering and
maintenance practices (Colorado Regulation No. 7, Part D, Section III.F.1.b).
14.5.3.2 Pneumatic controller inspection (Colorado Regulation No. 7, Part D, Section III.F.2)
a. Beginning calendar year 2020, owners or operators of natural gas -driven pneumatic
controllers at well production facilities must inspect pneumatic controllers using an
approved instrument monitoring method at least (Colorado Regulation No. 7, Part
D, Section III.F.2.b):
(i) Semi-annually at well production facilities statewide with
uncontrolled actual volatile organic compound emissions greater
than or equal to two (2) tons per year and less than or equal to twelve
(12) tons per year, based on a rolling twelve-month total (Colorado
Regulation No. 7, Part D, Section III.F.2.b.(ii)).
(ii) Quarterly at well production facilities statewide with uncontrolled
actual volatile organic compound emissions greater than twelve (12)
tons per year and less than or equal to twenty (20) tons per year,
based on a rolling twelve-month total, or fifty (50) tons per year if
no storage tanks storing oil or condensate are located at the well
production facility, based on a rolling twelve-month total (Colorado
Regulation No. 7, Part D, Section III.F.2.b.(iii)).
(iii)Monthly at well production facilities statewide with uncontrolled
actual volatile organic compound emissions greater than twenty (20)
tons per year, based on a rolling twelve-month total, or fifty (50)
tons per year if no storage tanks storing oil or condensate are located
at the well production facility, based on a rolling twelve-month total
(Colorado Regulation No. 7, Part D, Section III.F.2.b.(iv)).
b. For purposes of Sections III.F.2.a. and III.F.2.b., the estimated uncontrolled actual
VOC emissions from the highest emitting storage tank at the well production
facility determines the frequency at which inspections must be performed. If no
storage tanks storing oil or condensate are located at the well production facility,
owners or operators must rely on the facility emissions (controlled actual VOC
emissions from all permanent equipment, including emissions from components
determined by utilizing the emission factors defined as less than 10,000 ppmv of
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 88
Table 2-8 of the 1995 EPA Protocol for Equipment Leak Emission Estimates)
(Colorado Regulation No. 7, Part D, Section III.F.2.c).
c. Where detectable emissions from the pneumatic controller are observed, owners or
operators must determine whether the pneumatic controller is operating properly
within five (5) working days after detecting emissions. In making this
determination, owners or operators may use techniques other than approved
instrument monitoring methods (Colorado Regulation No. 7, Part D, Section
III.F.2.g).
d. For pneumatic controllers not operating properly, the owner or operator must
conduct enhanced response or follow manufacturer specifications to return the
pneumatic controller to proper operation (Colorado Regulation No. 7, Part D,
Section III.F.2.h).
14.5.3.3 Enhanced response and remonitoring (Colorado Regulation No. 7, Part D, Section
III.F.3)
a. Enhanced response must begin no later than five (5) working days and the pneumatic
controller returned to proper operation no later than thirty (30) working days after
determining the pneumatic controller is not operating properly, unless parts are
unavailable, the equipment requires shutdown to complete enhanced response, or
other good cause exists. If parts are unavailable, they must be ordered promptly and
enhanced response conducted within fifteen (15) working days of receipt of the
parts. If shutdown is required, enhanced response must be conducted during the
next scheduled shutdown. If delay is attributable to other good cause, enhanced
response must be completed within fifteen (15) working days after the cause of
delay ceases to exist (Colorado Regulation No. 7, Part D, Section III.F.3.a).
b. Within fifteen (15) working days of completion of enhanced response, the owner or
operator must verify the pneumatic controller is operating properly. In verifying
proper operation, owners or operators may use techniques other than approved
instrument monitoring methods (Colorado Regulation No. 7, Part D, Section
III.F.3.b).
c. Pneumatic controllers found emitting detectable emissions are not subject to
enforcement by the Division unless the owner or operator fails to determine
whether the pneumatic controller is operating properly in accordance with Section
III.F.2., perform any necessary enhanced response in accordance with Section
III.F.3., keep records in accordance with Section III.F.4., or submit reports in
accordance with Section III.F.5 (Colorado Regulation No. 7, Part D, Section
III.F.3.c).
14.5.3.4 Owners or operators must maintain the following records according the schedule in
Section IV, Condition 22. b and made available to the Division upon request.
a. The date, facility name, facility AIRS ID or facility location if the facility does not
have an AIRS ID, and approved instrument monitoring method used for each
inspection (Colorado Regulation No. 7, Part D, Section III.F.4.a);
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 89
b. A list of pneumatic controllers, including type, determined to be not operating
properly (Colorado Regulation No. 7, Part D, Section III.F.4.b);
c. For intermittent pneumatic controllers observed to have detectable emissions but
determined to be operating properly, a brief explanation of the basis for concluding
that the intermittent pneumatic controller was operating properly. The explanation
can include, but is not limited to, an owner or operator's standard operating
procedure detailing how to determine whether an intermittent pneumatic controller
is operating properly, or an individual explanation (Colorado Regulation No. 7, Part
D, Section III.F.4.c);
d. The date(s) of enhanced response and a description of the actions taken to return the
pneumatic controller to proper operation (Colorado Regulation No. 7, Part D,
Section III.F.4.d);
e. The date the owner or operator verified the pneumatic controller was returned to
proper operation (Colorado Regulation No. 7, Part D, Section III.F.4.e); and
f. The delayed repair list, including the date and duration of any period where the
enhanced response was delayed beyond thirty (30) days after determining the
pneumatic controller is not operating properly due to unavailable parts, required
shutdown, or delay for other good cause, the basis for the delay, and the schedule
for returning the pneumatic controller to proper operation. Delay of enhanced
response due to unavailable parts must be reviewed, and a record kept of that
review, by a representative of the owner or operator with responsibility for
pneumatic controller inspection and enhanced response compliance functions. This
review will not be made by the individual making the initial determination to place
a part on the delayed repair list (Colorado Regulation No. 7, Part D, Section
III.F.4.fj.
14.5.3.5 Owners or operators of pneumatic controllers at well production facilities or natural
gas compressor stations must submit a single annual report on or before May 31st of
each year (beginning May 31st, 2019 for facilities in the 8 -Hour Ozone Control Area
and May 31st, 2021, for facilities outside the 8 -Hour Ozone Control Area) that
includes, at a minimum, the following information regarding pneumatic controller
inspection and enhanced response activities at their subject facilities conducted the
previous calendar year (Colorado Regulation No. 7, Part D, Section III.F.5):
a. The total number and type of pneumatic controllers returned to proper operation, the
types of actions taken to return the pneumatic controllers to proper operation, and
the facility type (by inspection frequency tier of well production facility or natural
gas compressor station) (Colorado Regulation No. 7, Part D, Section III.F.5.a);
b. The number and type of pneumatic controllers on the delayed repair list as of
December 31st broken out by the facility type (by inspection frequency tier of well
production facility or natural gas compressor station), and the basis for each delay
(Colorado Regulation No. 7, Part D, Section III.F.5.b); and
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 90
c. The record of all reviews conducted for delayed repairs due to unavailable parts
extending beyond 30 days for the previous calendar year (Colorado Regulation No.
7, Part D, Section III.F.5.c).
14.5.4 This equipment is subject to the General Provisions of Condition 14.1.
14.6 Emissions during downhole well maintenance, well liquids unloading events, and well plugging at the
Razor 21 Central Production Battery (State Only)
14.6.1 Beginning May 1, 2014, owners or operators must use best management practices to minimize
hydrocarbon emissions and the need for emissions from the well associated with downhole well
maintenance, well liquids unloading, and well plugging (beginning January 31, 2020), unless
emitting is necessary for safety (Colorado Regulation No. 7, Part D, Section II.G.1).
14.6.1.1 During liquids unloading events, any means of creating differential pressure must first
be used to attempt to unload the liquids from the well without emitting. If these methods
are not successful in unloading the liquids from the well, the well may emit in order to
create the necessary differential pressure to bring the liquids to the surface (Colorado
Regulation No. 7, Part D, Section II.G.1.a).
14.6.1.2 The owner or operator must be present on -site during any planned downhole well
maintenance, well liquids unloading, or well plugging event and must ensure that any
emissions from the well associated with the event are limited to the maximum extent
practicable (Colorado Regulation No. 7, Part D, Section II.G.1.b).
14.6.2 Recordkeeping (Colorado Regulation No. 7, Part D, Section II.G.2)
14.6.2.1 Through January 31, 2020, the owner or operator must keep records of the cause, date,
time, and duration of venting events under Section II.G (Colorado Regulation No. 7,
Part D, Section II.G.2.a). Records must be kept according to the schedule in Section IV,
Condition 22. b and made available to the Division upon request.
14.6.2.2 Beginning January 31, 2020, or the date specified in Section II.G.2.b.(iii) (Colorado
Regulation No. 7, Part D, Section II.G.2.b), the owner or operator must keep the
following records according to the schedule in Section IV, Condition 22. b and make
records available to the Division upon request.
a. The cause of emissions (i.e., downhole well maintenance, well liquids unloading,
well plugging), date, time, and duration of emissions under Section II.G (Colorado
Regulation No. 7, Part D, Section II.G.2.b.(i)).
b. The best management practices used to minimize hydrocarbon emissions or the
safety needs that prevented the use of best management practices (Colorado
Regulation No. 7, Part D, Section II.G.2.b.(ii)).
c. Beginning July 1, 2020, the emissions associated with well liquids unloading,
downhole well maintenance, and well plugging (Colorado Regulation No. 7, Part
D, Section II.G.2.b.(iii)).
14.6.3 Reporting (Colorado Regulation No. 7, Part D, Section II.G.3)
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 91
14.6.3.1 The owner or operator must submit a single annual report using a Division -approved
format on or before June 30th of each year (beginning June 30th, 2021) that includes
the following information regarding each downhole well maintenance, well liquids
unloading, and well plugging event conducted the previous calendar year that resulted
in emissions (Colorado Regulation No. 7, Part D, Section II.G.3.a).
a. The API number of the well and the AIRS number of any associated storage tanks
(Colorado Regulation No. 7, Part D, Section II.G.3.a.(i)).
b. Whether the emissions occurred due to downhole well maintenance, well liquids
unloading, or well plugging (Colorado Regulation No. 7, Part D, Section
II.G.3.a.(ii)).
c. The date, time, and duration of the downhole well maintenance, well liquids
unloading, or well plugging event (Colorado Regulation No. 7, Part D, Section
II.G.3.a.(iii)).
d. The best management practices used to minimize emissions (Colorado Regulation
No. 7, Part D, Section II.G.3.a.(iv)).
e. Safety needs that prevented the use of best management practices to minimize
emissions, if applicable (Colorado Regulation No. 7, Part D, Section II.G.3.a.(v)).
f. An estimate of the volume of natural gas, VOC, NOx, CO, ethane, and methane
emitted from the well associated with well liquid unloading activities, downhole
well maintenance, and well plugging event and the emission factor or calculation
methodology used to determine the volume of natural gas and emissions (Colorado
Regulation No. 7, Part D, Section II.G.3.a.(vi)).
14.7 (State Only) Oil and Natural Gas Operations Emissions Inventory (Colorado Regulation No. 7, Part D,
Section V)
14.7.1 On or before June 30th, 2021 (and on June 30th each year thereafter), the owner or operator of oil
and natural gas operations and equipment at or upstream of a natural gas processing plant in
Colorado must submit a single annual report that includes actual emissions and specified
information in the Division -approved report format (Colorado Regulation No. 7, Part D, Section
V.A).
14.7.2 General reporting requirements (Colorado Regulation No. 7, Part D, Section V.B)
14.7.2.1 The following information must be reported in accordance with Section V.A (Colorado
Regulation No. 7, Part D, Section V.B.1).
a. Company name, physical street address, and name and contact information of the
company representative, for reporting purposes (Colorado Regulation No. 7, Part
D, Section V.B.1.a).
b. The date of submittal and the year covered by the report (Colorado Regulation No.
7, Part D, Section V.B.1.b).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 92
c. A list of the activities or equipment, as specified in Section V.C., for which
emissions are reported (Colorado Regulation No. 7, Part D, Section V.B.1.c).
d. The company's monthly actual emissions of volatile organic compounds (VOC),
oxides of nitrogen (NOx), carbon monoxide (CO), methane, and ethane for each
month of May through September (Colorado Regulation No. 7, Part D, Section
V.B.1.d).
e. The company's annual actual emissions of VOCs, NOx, CO, methane, and ethane
for the entire calendar year (Colorado Regulation No. 7, Part D, Section V.B.1.e).
f. The actual emissions of VOCs, NOx, CO, methane, and ethane for each activity or
equipment listed in Section V.C. per facility, or per pipeline between facilities
where the pipeline is not located at a stationary source (Colorado Regulation No. 7,
Part D, Section V.B.I.f).
(i) The report must include the actual emissions from each activity or
equipment per month for each month of May through September
(Colorado Regulation No. 7, Part D, Section V.B.1.f.(i)).
(ii) The report must include the actual emissions from each activity or
equipment for the entire calendar year (Colorado Regulation No. 7,
Part D, Section V.B.1.f.(ii)).
A certification by the company representative that supervised the development and
submission of the inventory report that, based on information and belief formed
after reasonable inquiry, the statements and information in the document are true,
accurate, and complete (Colorado Regulation No. 7, Part D, Section V.B.1.g).
14.7.2.2 The owner or operator must submit a revised annual report after discovering that an
annual report submitted within the previous two (2) years contained one or more
substantive errors. A substantive error is a mass of emissions of any individual pollutant
subject to reporting under Section V. that is at least 10% higher or lower than the mass
of emissions of the pollutant reported across the owner or operator's activity or
equipment, as listed in Section V.C., in Colorado. A refinement of or improvement to
an emissions estimation technique or emission factor is not a substantive error but must
be noted in the subsequent annual report after the refinement or improvement. Revised
annual reports must be submitted by August 31 if the substantive error is discovered
between January 1 and June 30, and by February 28 if the substantive error is
discovered between July 1 and December 31 of the preceding calendar year (Colorado
Regulation No. 7, Part D, Section V.B.2).
14.7.3 Beginning July 1, 2020, and each calendar year thereafter, owners or operators must maintain the
following information for inclusion in the annual report (Colorado Regulation No. 7, Part D,
Section V.C).
g.
14.7.3.1 AIRS number of the activity or equipment and associated facility or pipeline (if a
pipeline between facilities) location, including latitude and longitude coordinates. If
the activity or equipment does not have an AIRS number, a description of the activity
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
14.7.3.2
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 93
or equipment (Colorado Regulation No. 7, Part D, Section V.C.1).
Actual emissions from each activity or equipment listed in Colorado Regulation No. 7,
Part D, Section V.C.2.a through V.C.2.ee, unless otherwise specified in the Division -
approved report format, and the emission factor(s), assumptions, and calculation
methodology used to calculate the emissions (Colorado Regulation No. 7, Part D,
Section V.C.2).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 94
15. Colorado Regulation No. 7, Part D, Section II.B — Flare Requirements (State -only enforceable)
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.
The requirements below reflect the current rule language as of the revisions to Colorado Regulation No.
7 adopted December 19, 2019. However, if revisions to the regulation are published at a later date, the
owner or operator is subject to the requirements contained in the latest adopted version of Colorado
Regulation No. 7.
15.1 This flare must meet the general requirements of Conditions 14.1 and 14.2.
15.2 If a combustion device is used to control emissions of VOCs and other hydrocarbons, it must 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, Part
D, Section II.B.2.b).
In the absence of credible evidence to the contrary, compliance with the no visible emissions
requirement is presumed provided the monitoring in Condition 15.5 indicates no visible emissions.
Note: The open flare permitted under AIRS 023 (Condition 9) has been approved as an alternative
emission control device under Regulation Number 7, Part D, Section II.B.2.e. The open flare must meet
the no visible emission requirements of Condition 15.2 (as defined under Colorado Regulation No. 7,
Part D, Section II.A.23) and be designed so that an observer can, by means of visual observation from
the outside of the open flare, or by other convenient means approved by the Division, determine whether
it is operating properly. This open flare must be equipped with an operational auto -igniter according to
the schedule in Condition 15.3 (Colorado Construction Permit 14WE0891).
15.3 Any of the effective dates for installation of controls on storage tanks, dehydrators, and/or internal
combustion engines may be extended at the Division's discretion for good cause shown (Colorado
Regulation No. 7, Part D, Section II.B.2.c).
15.4 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, Part D, Section II.B.2.d):
15.4.1 All combustion devices installed on or after May 1, 2014, must be equipped with an operational
auto -igniter upon installation of the combustion device (Colorado Regulation No. 7, Part D,
II.B.2.d.(i)).
15.4.2 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, Part D, Section II.B.2.d.(ii)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 95
15.5 The owner or operator shall complete the following visual inspections. The frequency of these
inspections shall be daily. The result(s) of the visual inspections shall be kept on file and made available
15.5.1 [The owner or operator shall complete a] 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, Part D, Section
II.C.1.d.(ii)).
15.5.2 [The owner or operator shall complete a] visual inspection of the auto- igniter and valves for
piping of gas to the pilot light to ensure they are functioning properly (Colorado Regulation No.
7, Part D, Section.C.1.d.(iii)).
15.5.3 [The owner or operator shall complete a] 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, Part D, Section II.C.1.d.(iv)).
15.5.4 [The owner or operator shall complete an] 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, Part D, Section II.C.1.d.(v)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 96
16. Colorado Regulation No. 7, Part D, Section II.C — Storage Tanks Requirements
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.
The requirements below reflect the current rule language as of the revisions to Colorado Regulation No.
7 adopted December 19, 2019. However, if revisions to the regulation are published at a later date, the
owner or operator is subject to the requirements contained in the latest adopted version of Colorado
Regulation No. 7.
16.1 Control Requirements:
16.1.1 (State Only) 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 collect
and control emissions from each storage tank by routing emissions to and operating air pollution
control equipment that achieves a hydrocarbon control efficiency of 95%. (Colorado Regulation
No. 7, Part D, Section II.C.1.b).
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
Condition 16.1.3 are met.
AIRS IDs 018, 024, and 025: (State Only) If a combustion device is used (to meet the
requirements of this Condition 16.1.1), it must have a design destruction efficiency of at least
98% for hydrocarbons except where the combustion device has been authorized by permit prior
to May 1, 2014 (Colorado Regulation No. 7, Part D, Section II.C.1.b).
In the absence of credible evidence to the contrary, compliance with the 98% average
hydrocarbon design destruction efficiency requirement shall be presumed as long as the records
maintained in accordance with Condition 16.4.5 indicate compliance.
16.1.1.1 (State Only) Control requirements of Section II.C.1.b (Condition 16.1.1) must be
achieved in accordance with the following schedule (Colorado Regulation No. 7, Part
D, Section II.C.1.b.(i)):
a. AIRS IDs 018, 024 and 025: A storage tank constructed before May 1, 2014, must
be in compliance by May 1, 2015 (Colorado Regulation No. 7, Part D, Section
II.C.1.b.(i)(B))
b. Storage tank not otherwise subject to Sections II.C.1.b.(i)(A) or II.C.1.b.(i)(B)
(Condition a) 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, Part D, Section II.C.1.b.(i)(C)).
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 97
16.1.2 (State Only) Owners or operators of storage tanks with uncontrolled actual emissions of VOCs
equal to or greater than two (2) tons per year based on a rolling twelve-month total must collect
and control emissions from each storage tank by routing emissions to and operating air pollution
control equipment that achieves a hydrocarbon control efficiency of 95%. If a combustion device
is used, it must have a design destruction efficiency of at least 98% for hydrocarbons, except
where the combustion device has been authorized by permit prior to March 1, 2020 (Colorado
Regulation No. 7, Part D, Section II.C.1.c).
16.1.2.1 Control requirements of Section II.C.1.c. must be achieved in accordance with the
following schedule (Colorado Regulation No. 7, Part D, Section II.C.1.c.(i))
a. A storage tank constructed before March 1, 2020, that is not already controlled under
Sections I.D. or II.C.1.b. must be in compliance by May 1, 2021 (Colorado
Regulation No. 7, Part D, Section II.C.1.c.(i)(B)).
b. A storage tank not otherwise subject to Sections II.C.1.c.(i)(A) or II.C.1.c.(i)(B) that
increases uncontrolled actual emissions above the applicable threshold in Section
II.C.1.c.(i)(B) after the applicable date in Section II.C.1.c.(i)(B) must be in
compliance within sixty (60) days of the first day of the month after which the
storage tank emissions exceeded the applicable threshold based on a rolling twelve-
month basis (Colorado Regulation No. 7, Part D, Section II.C.1.c.(i)(C)).
The December 19, 2019 version of Regulation No. 7 includes an error in the
above requirement, the correct citation for the uncontrolled actual emissions
threshold should be Section II.C.1.c.
16.1.2.2 If air pollution control equipment is not installed by the applicable compliance date in
Sections II.C.1.c.(i)(A), II.C.1.c.(i)(B), or II.C.1.c.(i)(C), compliance with Section
II.C.1.c. may alternatively be demonstrated by shutting in all wells producing into that
storage tank by the date in Sections II.C.1.c.(i)(A), II.C.1.c.(i)(B), or II.C.1.c.(i)(C) so
long as production does not resume from any such well until the air pollution control
equipment is installed and operational (Colorado Regulation No. 7, Part D, Section
II.C.1.c.(ii)).
16.1.2.3 Owners or operators of storage tanks for which the use of air pollution control
equipment would be technically infeasible without supplemental fuel may apply to the
Division for an exemption from the control requirements of Section II.C.1.c. Such
request must include documentation demonstrating the infeasiblity of the air pollution
control equipment. The applicability of this exemption does not relieve owners or
operators of compliance with the storage tank monitoring requirements of Section
II.C.1.d (Colorado Regulation No. 7, Part D, Section II.C.1.c.(iii)).
16.1.3 These tank(s) are subject to the general requirements of Condition 14.1.1. The flare associated
with these tanks is subject to the requirements of Condition 15.
16.2 Visual Inspection Requirements:
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 98
16.2.1 (State Only) Beginning May 1, 2014, or the applicable compliance date in Sections II.C.1.b.(i)
(Condition 16.1.1.1) or II.C.1.c.(i), whichever comes later, owners or operators of storage tanks
subject to Section II.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 equipment that are unsafe, difficult, or inaccessible to
monitor, as defined in Section II.C.1.e (Condition 16.2.2). The additional visual inspections must
include, at a minimum (Colorado Regulation No. 7, Part D, Section II.C.1.d):
16.2.1.1 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, Part D,
Section II.C.1.d.(i));
16.2.1.2 The visual inspection requirements for the flare are included in Condition 15.5;
16.2.1.3 Beginning May 1, 2020, or the applicable compliance date in Section II.C.1.c.(i),
whichever comes later, visual observation of the dump valve(s) of the last separator(s)
before the storage tank(s) to ensure the dump valve is free of debris and not stuck open.
The owner or operator is not required to observe the actuation of the dump valve during
this inspection; however, if a dump event occurs during the inspection, the owner or
operator must confirm proper operation of the valve (Colorado Regulation No. 7, Part
D, Section II.C.1.d.(vi)).
16.2.1.4 Beginning May 1, 2020, or the applicable compliance date in Section II.C.1.c.(i),
whichever comes later, a check for the presence of liquids in liquid knockout vessels
that do not drain automatically, underground lines, and aboveground piping (Colorado
Regulation No. 7, Part D, Section II.C.1.d.(vii)).
a. For liquid knockout vessels for which a procedure exists to check liquid level, check
for the presence of liquids. If liquids are present above the low level indication
point, drain liquids (Colorado Regulation No. 7, Part D, Section II.C.1.d.(vii)(A)).
b. For liquid knockout vessels for which no procedure exists to check liquid level, drain
liquids (Colorado Regulation No. 7, Part D, Section II.C.1.d.(vii)(B)).
c. For underground lines and aboveground piping that is not sloped to a liquid
knockout or tank and for which a procedure exists to check for the presence of
liquids accumulation, check for the presence of liquids and drain liquids as needed
(Colorado Regulation No. 7, Part D, Section II.C.1.d.(vii)(C)).
d. For underground lines and aboveground piping that is not sloped to a liquid
knockout vessel or tank and for which no written procedure exists to check for the
presence of liquids accumulation, drain liquids quarterly (Colorado Regulation No.
7, Part D, Section II.C.1.d.(vii)(D)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 99
16.2.2 (State Only) 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, Part D, Section II.C.1.e).
16.2.2.1 Difficult to monitor means it cannot be monitored without elevating the monitoring
personnel more than two meters above a supported surface or is unable to be reached
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, Part D, Section II.C.I .e.(i)).
16.2.2.2 Unsafe to monitor means it cannot be monitored without exposing monitoring
personnel to an immediate danger as a consequence of completing the monitoring
(Colorado Regulation No. 7, Part D, Section II.C.1.e.(ii)).
16.2.2.3 Inaccessible to monitor means buried, insulated, or obstructed by equipment or piping
that prevents access by monitoring personnel (Colorado Regulation No. 7, Part D,
Section II.C.1.e.(iii)).
16.3 Capture Requirements:
16.3.1 Capture requirements for storage tanks that are fitted with air pollution control equipment as
required by Sections II.C.1. (Conditions 16.1.1 and 16.1.1.1):
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 (unless the use of a storage tank
measurement system is required pursuant to and the operator compiles with Section II.C.4.), or
safety of personnel and equipment. Compliance must be achieved in accordance with the
schedule in Section II.C.2.b.(ii) (Condition 16.4.1.2) (Colorado Regulation No. 7, Part D, Section
II.C.2.a).
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 16.4.2.2
and 16.4.2.6 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.
16.3.1.1 Venting is emissions from a controlled storage tank thief hatch, pressure relief device,
or other access point to the storage tank, which (Colorado Regulation No. 7, Part D,
Section II.C.2.a.(i)):
a. Are primarily the result of over -pressurization, whether related to design, operation,
or maintenance (Colorado Regulation No. 7, Part D, Section II.C.2.a.(i)(A)); or
b. 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, Part D, Section
II.C.2.a.(i)(B)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 100
16.3.1.2 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 II.C.2.a (Colorado Regulation No.
7, Part D, Section II.C.2.a.(ii)).
16.3.1.3 When venting is observed, the owner or operator must confirm within twenty-four (24)
hours of taking action to return the storage tank to operation without venting that the
action(s) taken was effective. If the venting was observed using an approved instrument
monitoring method, the confirmation must be made using an approved instrument
monitoring method (Colorado Regulation No. 7, Part D, Section II.C.2.a.(iii)).
16.4 Storage Tank Emission Management System ("STEM") Plan Requirements:
16.4.1 Owners or operators of storage tanks subject to the control requirements of Sections II.C.1.a,
II.C.1.b., or II.C.1.c. (Conditions 16.1.1 and 16.1.1.1) must develop, certify, and implement a
documented Storage Tank Emission Management System (STEM) plan to identify, evaluate, and
employ appropriate control technologies, monitoring practices, operational practices, and/or
other strategies designed to meet the requirements set forth in Section II.C.2.a (Condition
16.3.1). Owners or operators must update the STEM plan as necessary to achieve or maintain
compliance. Owners or operators are not required to develop and implement STEM for storage
tanks containing only stabilized liquids. The minimum elements of STEM are listed (Colorado
Regulation No. 7, Part D, Section II.C.2.b):
16.4.1.1 STEM plans must include selected control technologies, monitoring practices,
operational practices, and/or other strategies; an analysis of the engineering design of
the storage tank and air pollution control equipment; procedures for evaluating ongoing
storage tank emission capture performance; and monitoring in accordance with
approved instrument monitoring methods* following the applicable schedule in
Section II.C.2.b.(ii) (Condition 16.4.1.2) (Colorado Regulation No. 7, Part D, Section
II.C.2.b.(i)).
*For the purposes of this condition, approved instrument monitoring method means
an infra -red camera, or EPA Method 21.
All monitoring specified in the STEM plan, including monitoring associated with
ongoing storage tank emission capture performance, shall comply with the
recordkeeping requirements of Condition 16.4.2
16.4.1.2 Owners or operators must achieve the requirements of Sections II.C.2.a. (Condition
16.3.1) and II.C.2.b. (Condition 16.4.1) and begin implementing the required approved
instrument monitoring method in accordance with the following schedule (Colorado
Regulation No. 7, Part D, Section II.C.2.b.(ii)):
Initial Compliance Dates for Capture Requirements, STEM Plan Requirements, and
AIMM Inspections
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 101
a. AIRS IDs 018, 024, and 025: A storage tank subject to Sections II.C.1.a. (Condition
16.3.1) or II.C.1.b. (Condition 16.4.1) and constructed before May 1, 2014, must
comply with the requirements of Sections II.C.2.a. and II.C.2.b. by May 1, 2015
(Colorado Regulation No. 7, Part D, Section II.C.2.b.(ii)(B)).
b. A storage tank subject to Sections II.C.1.c. and I.D.3. and constructed before March
1, 2020, that is not subject to the control requirements of the system -wide control
strategy in Section I.D.1. must comply with the requirements of Sections II.C.2.a.
and II.C.2.b. by May 1, 2020, or by commencement of operation of the storage
tank, whichever comes later (Colorado Regulation No. 7, Part D, Section
II.C.2.b.(ii)(D)).
c. A storage tank subject to Section II.C.1.c. and constructed before March 1, 2020,
that is not subject to the control requirements of the system -wide control strategy
in Section I.D.1. must comply with the requirements of Sections II.C.2.a. and
II.C.2.b. by May 1, 2021. Approved instrument monitoring method inspections of
the storage tank must begin in 2021 (Colorado Regulation No. 7, Part D, Section
II.C.2.b.(ii)(E)).
d. A storage tank with uncontrolled actual emissions of VOCs equal to or greater than
six (6) and less than or equal to twelve (12) tons per year must begin semi-annual
approved instrument monitoring method inspections in 2020 (Colorado Regulation
No. 7, Part D, Section II.C.2.b.(ii)(F)).
e. A storage tank not otherwise subject to Sections II.C.2.b.(ii)(A) or II.C.2.b.(ii)(B) (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 Sections II.C.2.a. (Condition 16.3.1) and II.C.2.b. (Condition
16.4.1) and implement the required approved instrument monitoring method
inspections within sixty (60) days of the first day of the month after which the
storage tank emissions exceeded the applicable threshold based on a rolling twelve-
month basis (Colorado Regulation No. 7, Part D, Section II.C.2.b.(ii)(G)).
f. A storage tank not otherwise subject to Sections II.C.2.b.(ii)(A) through
II.C.2.b.(ii)(F) that increases uncontrolled actual emissions above the applicable
threshold in Section II.C.1.c.(i)(B) after the applicable . date in Section
II.C.1.c.(i)(B), must comply with the requirements of Sections II.C.2.a. and
II.C.2.b. and implement the required approved instrument monitoring method
inspections within sixty (60) days of the first day of the month after which the
storage tank VOC emissions exceeded the applicable threshold based on a rolling
twelve-month basis (Colorado Regulation No. 7, Part D, Section II.C.2.b.(ii)(H)).
AIMM Inspection Frequency
g. Following the first approved instrument monitoring method inspection, owners or
operators must continue conducting approved instrument monitoring method
inspections in accordance with the inspection frequency in Table 1 (Colorado
Regulation No. 7, Part D, Section II.C.2.b.(ii)(i)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 102
16.4.1.3
Storage Tank Inspections
Threshold: Storage Tank
Uncontrolled Actual
VOC Emissions (tpy)
Approved Instrument
Monitoring Method
Inspection Frequency
> 2 and < 12
Semi-annually
> 12 and < 50
Quarterly
>50
Monthly
For the purposes of this condition 16.4.1.2g, 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.
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 II.C.1.e
(Colorado Regulation No. 7, Part D, Section II.C.2.b.(iii)).
Other STEM Requirements
16.4.1.4 STEM must include a certification by the owner or operator that the selected STEM
strategy(ies) are designed to minimize emissions from storage tanks and associated
equipment at the facility(ies), including thief hatches and pressure relief devices
(Colorado Regulation No. 7, Part D, Section II.C.2.b.(iv)).
16.4.1.5 The owner or operator must review the STEM plan annually and complete updates as
necessary. Records of the review shall be maintained and made available to the
Division upon request.
Recordkeeping
16.4.2 (State Only) Recordkeeping: The owner or operator of each storage tank subject to Sections I.D.
or II.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 (Colorado Regulation No. 7,
Part D, Section II.C.3). In addition, according to the schedule in Section IV, Condition 22.b, the
owner or operator must maintain records of any required monitoring and make them available
to the Division upon request, including:
16.4.2.1
16.4.2.2
The AIRS ID for the storage tank (Colorado Regulation No. 7, Part D, Section II.C.3.a).
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
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 103
that is reasonably required for maintenance, gauging (unless use of a storage tank
measurement system is required pursuant to and the operator complies with Section
II.C.4.), or safety of personnel and equipment (Colorado Regulation No. 7, Part D,
Section II.C.3.b).
16.4.2.3 The date and duration of any period where the air pollution control equipment is not
operating (Colorado Regulation No. 7, Part D, Section II.C.3.c).
16.4.2.4 Records of the inspections required in Sections II.C.1.d. and II.C.2.b.(ii), including the
time and date of each inspection and a description of any problems observed,
description and date of any corrective action(s) taken, and name of employee or third
party performing corrective action(s) (Colorado Regulation No. 7, Part D, Section
II.C.3.d).
16.4.2.5 Where a combustion device is being used, the date and result of any EPA Method 22
test or investigation pursuant to Section II.C.1.d.(v) (Colorado Regulation No. 7, Part
D, Section II.C.3.e).
16.4.2.6 The timing of and efforts made to eliminate venting, restore operation of air pollution
control equipment, and mitigate visible emissions, including the dates and results of
action(s) taken and the monitoring used to confirm the action(s) were successful
(Colorado Regulation No. 7, Part D, Section
16.4.2.7 A list of equipment associated with the storage tank that is designated as unsafe,
difficult, or inaccessible to monitor, as described in Section II.C.1.e., an explanation
stating why the equipment is so designated, and the plan for monitoring such equipment
(Colorado Regulation No. 7, Part D, Section II.C.3.g).
16.4.2.8 Records of any exemption, and associated documentation, applied for under Section
II.C.1.c.(iii) (Colorado Regulation No. 7, Part D, Section II.C.3.h).
16.4.3 (State Only) Storage tank measurement system requirements at well production facilities, natural
gas compressor stations, and natural gas processing plants (Colorado Regulation No. 7, Part D,
Section II.C.4)
16.4.3.1 Applicability (Colorado Regulation No. 7, Part D, Section II.C.4.a)
a. The owners or operators of controlled storage tanks at well production facilities,
natural gas compressor stations, or natural gas processing plants constructed on or
after May 1, 2020, and at any facilities that are modified on or after May 1, 2020,
such that an additional controlled storage vessel is constructed to receive an
anticipated increase in throughput of hydrocarbon liquids or produced water, must
use a storage tank measurement system to determine the quantity of liquids in the
storage tank(s) (Colorado Regulation No. 7, Part D, Section II.C.4.a.(i)).
16.4.3.2 Owner or operators subject to the storage tank measurement system requirements in
Section II.C.4.a., must keep thief hatches (or other access points to the tank) and
pressure relief devices on storage tanks closed and latched during activities to
determine the quality and/or quantity of liquids in the storage tank(s) (Colorado
Regulation No. 7, Part D, Section II.C.4.b).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 104
16.4.3.3 Operators may inspect, test, and/or calibrate the storage tank measurement system
semi-annually, or as directed by the Bureau of Land Management (see 43 CFR Section
3174.6(b)(5)(ii)(B) (November 17, 2016)) or system manufacturer. Opening the thief
hatch if required to inspect, test, or calibrate the system is not a violation of Section
II.C.4.b (Colorado Regulation No. 7, Part D, Section II.C.4.c).
16.4.3.4 The owner or operator must install signage at or near the storage tank that indicates
which equipment and method(s) is used and the appropriate and necessary operating
procedures for that system (Colorado Regulation No. 7, Part D, Section II.C.4.d).
16.4.3.5 The owner or operator must develop and implement an annual training program for
employees and/or third parties conducting activities subject to Section II.C.4. that
includes, at a minimum, operating procedures for each type of system (Colorado
Regulation No. 7, Part D, Section II.C.4.e).
16.4.3.6 Owner or operators must retain records according to the schedule in Section IV,
Condition 22. b and make such records available to the Division upon request,
including
a. Date of construction of the storage vessel or facility (Colorado Regulation No. 7,
Part D, Section II.C.4.f.(i)).
b. Description of the storage tank measurement system used to comply with Section
II.C.4.a (Colorado Regulation No. 7, Part D, Section II.C.4.f.(ii)).
c. Date(s) of storage tank measurement system inspections, testing, and/or calibrations
pursuant to Section II.C.4. c (Colorado Regulation No. 7, Part D, Section
II.C.4.f.(iii)).
d. Manufacturer specifications regarding storage tank measurement system
inspections, and/or calibrations, if followed pursuant to Section II.C.4.c (Colorado
Regulation No. 7, Part D, Section II.C.4.f.(iv)).
e. Records of the annual training program, including the date and names of persons
trained (Colorado Regulation No. 7, Part D, Section II.C.4.f.(v)).
16.4.4 (State Only) Storage tank hydrocarbon liquids loadout requirements at well production facilities,
natural gas compressor stations, and natural gas processing plants (Colorado Regulation No. 7,
Part D, Section II.C.5)
16.4.4.1 Owners or operators of well production facilities, natural gas compressor stations, and
natural gas processing plants with a hydrocarbon liquids loadout to transport vehicles
throughput of greater than or equal to 5,000 barrels per year on a rolling 12 -month basis
must control emissions from the loadout of hydrocarbon liquids from controlled storage
tanks to transport vehicles by using (a) submerged fill and (b) a vapor collection and
return system and/or air pollution control equipment (Colorado Regulation No. 7, Part
D, Section II.C.5.a).
a. Compliance with Section II.C.5. must be achieved in accordance with the following
schedule (Colorado Regulation No. 7, Part D, Section II.C.5.a.(i))
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 105
(i) Facilities constructed before May 1, 2020, must be in compliance by
May 1, 2021 (Colorado Regulation No. 7, Part D, Section
II.C.5.a.(i)(B)).
(ii) Facilities not subject to Sections II.C.5.a.(i)(A) or II.C.5.a.(i)(B) that
exceed the hydrocarbon liquids loadout to transport vehicles
throughput of greater than or equal to 5,000 barrels per year on a
rolling 12 -month basis must control emissions from loadout upon
exceeding the loadout threshold (Colorado Regulation No. 7, Part
D, Section II.C.5.a.(i)(C)).
b. Storage tanks must operate without venting at all times during loadout (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(ii)).
c. The owner or operator must, as applicable (Colorado Regulation No. 7, Part D,
Section II.C.5.a.(iii)):
(i) Install and operate the vapor collection and return equipment to
collect vapors during the loadout of hydrocarbon liquids to tank
compartments of outbound transport vehicles and to route the vapors
to the storage tank or air pollution control equipment (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(iii)(A)).
(ii) Include devices to prevent the release of vapor from vapor recovery
hoses not in use (Colorado Regulation No. 7, Part D, Section
II.C.5.a.(iii)(B)).
(iii)Use operating procedures to ensure that hydrocarbon liquids cannot
be transferred to transport vehicles unless the vapor collection and
return system is in use (Colorado Regulation No. 7, Part D, Section
II.C.5.a.(iii)(C)).
(iv)Operate all recovery and disposal equipment at a back -pressure less
than the pressure relief valve setting of transport vehicles (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(iii)(D)).
(v) The owner or operator must inspect onsite loading equipment to
ensure that hoses, couplings, and valves are maintained to prevent
dripping, leaking, or other liquid or vapor loss during loadout. These
inspections must occur at least monthly, unless loadout occurs less
frequently, then as often as loadout is occurring (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(iii)(E)),
d. Loadout observations and operator training (Colorado Regulation No. 7, Part D,
Section II.C.5.a.(iv))
(i) The owner or operator must observe loadout to confirm that all
storage tanks operate without venting when loadout operations are
active. These inspections must occur at least monthly, unless
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 106
loadout occurs less frequently, then as often as loadout is occurring
(Colorado Regulation No. 7, Part D, Section II.C.5.a.(iv)(A)),
(ii) If observation of loadout is not feasible, the owner or operator must
document the annual loadout frequency and the reason why
observation is not feasible and inspect the facility within 24 hours
after loadout to confirm that all storage tank thief hatches (or other
access point to the tank) are closed and latched (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(iv)(B)).
(iii)The owner or operator must install signage at or near the loadout
control system that indicates which loadout control method(s) is
used and the appropriate and necessary operating procedures for that
system (Colorado Regulation No. 7, Part D, Section
II.C.5.a.(iv)(C)).
(iv)The owner or operator must develop and implement an annual
training program for employees and/or third parties conducting
loadout activities subject to Section II.C.5. that includes, at a
minimum, operating procedures for each type of loadout control
system (Colorado Regulation No. 7, Part D, Section
II.C.5.a.(iv)(D)).
e. Owners or operators must retain records according to the schedule in Section IV,
Condition 22.b and make such records available to the Division upon request.
(i) Records of the annual facility hydrocarbon liquids loadout to
transport vehicles throughput (Colorado Regulation No. 7, Part D,
Section II.C.5.a.(v)(A)).
(ii) Inspections, including a description of any problems found and their
resolution, required under Sections II.C.5.a.(iii) and II.C.5.a.(iv)
must be documented in a log (Colorado Regulation No. 7, Part D,
Section II.C.5.a.(v)(B)).
(iii)Records of the infeasibility of observation of loadout (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(v)(C)).
(iv)Records of the frequency of loadout (Colorado Regulation No. 7,
Part D, Section II.C.5.a.(v)(D)).
(v) Records of the annual training program, including the date and
names of persons trained (Colorado Regulation No. 7, Part D,
Section II.C.5.a.(v)(E)).
f. Air pollution control equipment used to comply with this Section II.C.5. must
comply with Section II.B., be inspected in accordance with Sections II.C.1.d.(ii)
through (v), and achieve a hydrocarbon control efficiency of 95% (Colorado
Regulation No. 7, Part D, Section II.C.5.a.(vi)).
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 107
16.4.5 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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
17. 40 CFR Part 60 Subpart A — General Provisions
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 108
17.1 The emission units indicated in this Section II of this operating permit are subject to the applicable
requirements of 40 CFR Part 60 Subpart A, General Provisions requirements (40 CFR 60.1 through
60.19, as adopted by reference in Colorado Regulation No. 6, Part A, Subpart A). Specifically, these
units are subject to the following:
17.1.1 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. (40 CFR § 60.12, as adopted by reference in Colorado Regulation No. 6, Part A,
Subpart A, and Part B, Section I.A).
17.1.2 Records of startups, shutdowns, and malfunctions shall be maintained, as required under 40 CFR
§ 60.7.
17.1.3 Records shall be maintained of the occurrence and duration of any startup, shutdown, or
malfunction in the operating of the source; any malfunction of the air pollution control
equipment; or any periods during which a continuous monitoring system or monitoring device is
inoperative (40 CFR Part 60 Subpart A §60.7(b), as adopted by reference in Colorado Regulation
No. 6, Part A, Subpart A and Part B, Section I.A).
17.1.4 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 Division which may
include, but is not limited to, monitoring results, opacity observations, review of operating and
maintenance procedures, and inspection of the source. (40 CFR § 60.11(d) , as adopted by
reference in Colorado Regulation No. 6, Part A, Subpart A and Part B, Section I.A).)
17.1.5 Written notification of construction and initial startup dates shall be submitted to the Division as
required by 40 CFR Part 60 Subpart A §60.7(a)
17.1.6 Required performance tests shall be conducted as required under 40 CFR Part 60 Subpart A
§60.8.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 109
18. 40 CFR Part 63 Subpart A — General Provisions
18.1 The emission units indicated in this Section II of the operating permit are subject to the applicable
requirements of 40 CFR Part 63 Subpart A, General Provisions requirements (as adopted by reference in
Colorado Regulation No. 8, Part E, Section I). Specifically, these units are subject to the following:
18.1.1 Prohibited activities and circumvention in §63.4
18.1.2 Performance testing in §63.7
18.1.3 Monitoring in §63.8
18.1.4 Notification in §63.9
18.1.5 Recordkeeping and reporting in §63.10
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 110
19. Portable Monitoring (6/26/2014 version)
19.1 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 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.co lorado.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 shows 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 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.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
SECTION III - Permit Shield
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 111
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
AMINE -1
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart LLL
Affected facilities under this regulation are those
that commenced constructed, reconstruction, or
modification after January 20, 1984 and on or
before August 23, 2011. Construction of the
Redtail plant commenced in May 2013;
therefore the amine unit at this facility is exempt
from the requirements of 40 CFR Part 60
Subpart LLL.
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart OOOO
Per §60.5365(g)(3), facility that have a design
capacity less than 2 LT/D of H2S in the acid gas
(expressed as sulfur) are not required to comply
with §60.5405 through §60.5410(g) and
§60.5415(g). This amine unit has a design
capacity less than 2 LT/D; therefore, is exempt
from these provisions.
HTR-1A
Colorado Reg 8 & (40 CFR Part 63) NSPS
Subpart JJJJJJ
Per 40 CFR 63.11195(e) a gas -fired boiler is not
subject to the provisions of this regulation. This
unit is gas -fired and therefore, exempt from
these provisions.
Colorado Reg 8 & (40 CFR Part 63) NSPS
Subpart DDDDD
The hot oil heater at the Redtail Gas Plant
(HTR-1A) meets the definition of a process
heater. However, it is located at an area source
of HAP emissions; therefore, this regulation
does not apply.
FLR-1A
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart A §60.18
This flare does not control equipment subject to
the provisions of 40 CFR Part 60; therefore, is
not regulated under Colorado Reg 6 nor §60.18
DEHY-0J &
DEHY-02
Colorado Reg 8 & (40 CFR Part 63) NSPS
Subpart HI -I
The Redtail Gas Plant is designated as an area
source of HAP emissions, and the two
dehydration units are ethylene glycol (EG) units
and not TEG units. Therefore, this regulation
does not apply.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 112
RZ-ENG-1A
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart OOOO
Per 40 CFR 60.5365(c), a reciprocating
compressor located at a well site, or adjacent
well site and servicing more than one well site is
not an affected facility under this subpart. Well
site means one or more areas that are directly
disturbed during the drilling and subsequent
operation of, or affected by, production facilities
directly associated with any oil well, gas well, or
injection well and its associated well pad. Under
this definition the Razor 21 CPB is a well sit;
therefore, the gas lift engine is not subject to the
provisions of this regulation.
Separators, Flare
RZ-FLR-1
Colorado Regulation No. 7, Part D, II.B.2.b
The high flare pressure is used as back up
control and therefore can be an open flare. This
shield only applies to the requirement for the
combustion device to be enclosed, the flare must
operate with no visible emissions and be
designed so that an observer can by means of
visual observation from the outside or by other
means approved by the Division, determine
whether it is operating properly as required by
this permit.
Oil & Produced
Water Tanks,
Enclosed
Combustor
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart Kb
Two 400 -bbl (47.696 m3) condensate tanks, one
400 -bbl gunbarrel tank, and two 400 -bbl
produced water tanks. Each of these atmospheric
storage tanks are smaller than 19,800 gal;
therefore, are not subject to Subpart Kb.
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart OOOO
Whiting operates two condensate storage tanks,
one gunbarrel tank, and two produced water
tanks. The permitted controlled emissions per
tank do not exceed the 6-tpy threshold;
therefore, this regulation does not apply.
Facility -wide
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart KKK
Affected facilities under this regulation are those
that commenced construction, reconstruction, or
modification after January 20, 1984 and on or
before August 23, 2011. Construction of the
Redtail plant commenced in May 2013;
therefore the provisions of this regulation do not
apply.
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;
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 113
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;
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(s)
Streamlined (Subsumed) Requirements
Section IV — General
Conditions 22.b and c
Colorado Regulation No. 7, Part D, Section II.C.3 [only the requirement to maintain records for
two years] — State Only Requirement
Colorado Regulation No. 7, Part D, Section II.C.4.f [only the requirement to maintain records
for two years] — State Only Requirement
Colorado Regulation No. 7, Part D, Section II.C.5.a.(v) [only the requirement to maintain
records for two years] — State Only Requirement
Colorado Regulation No. 7, Part D Section III.E.2.c [only the requirement to maintain records
for three years] — state only requirement
Colorado Regulation No. 7, Part D, Section III.F.4 [only the requirement to maintain records
for three years] — state only requirement
Colorado Regulation No. 7, Part D, Section II.G.2.a & b [only the requirement to maintain
records for three years] — state only requirement
Section II, Condition
2.5.1
40 CFR Part 60 Subpart IIII §60.4202(a)(2) [only the requirement for 50 opacity during the
peaks in either the acceleration or lugging modes (§89.113(a)(3)]
Section II, Condition
4.1.2
Colorado Regulation No. 6, Part B, Section II.C.2 [particulate matter emissions shall not exceed
0.5(FI)-°26 lbs/IVIMBtu] - State Only Requirement
Section II, Condition
4.5
Colorado Regulation No. 6, Part B, Section II.C.3 [opacity of emissions shall not exceed 20%] —
State Only Requirement
Section II — Condition
15.5
Condition 15, Colorado Construction Permit 13WE3008 [only the requirement for control
devices to be adequately designed, maintained, and able to handle reasonably foreseeable
fluctuations in VOCs]
Section II — Condition
15.5
Colorado Regulation No. 7, Part D, Section II.C.1.d.(ii) through (vii) [only with respect to the
inspection frequency requirements] — State Only Requirement
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 114
Permit Condition(s)
Streamlined (Subsumed) Requirements
Section II — Condition
14.3.2 and 16.4.1.1
Colorado Regulation No. 7, Part D, Section II.A.2. [definition of Approved Instrument
Monitoring Method — only with respect to other Division -approved alternatives] — State Only
Requirement.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 115
SECTION I - General Permit Conditions (ver 1/21/2020)
1, Administrative Changes
Regulation No. 3, 5 CCR 1001-5, Part A, § III.
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., II.C., II.E., II.F., II.I, and II.J
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.
b. Emission Monitoring Requirements
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 116
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.
Nothing in this section shall abrogate the Division's authority to conduct its own performance test(s) if so warranted.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
d. Affirmative Defense Provision for Excess Emissions during Malfunctions
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 117
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.
e. Circumvention Clause
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
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 118
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
g.
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.
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:
(i)
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.
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
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 119
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, §§ III.C.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:
g.
(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.
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.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
5. Emergency Provisions
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 120
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.
9. Fugitive Particulate Emissions
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 121
Regulation No. 1, 5 CCR 1001-3, III.D.1.
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, § III.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, § 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.
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.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
16. Opacity
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 122
Regulation No. 1, 5 CCR 1001-3, §§ I., II.
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., III. 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, $ II.D.
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:
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;
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 123
(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 sped 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 art 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.
d. 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.
e. 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 or as provided
for in Regulation No. 3, Part A, § II.A.2 for oil and gas well production facilities. A revised APEN shall be filed
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 124
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,
except an APEN shall be filed once per year for control equipment at condensate storage tanks located at oil and gas
exploration and production facilities subject to Regulation No. 7, Part D § I. 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, § III., 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.c & d, 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, § II.A.
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;
(ii) identification of the emissions unit(s) whose emissions of a regulated NSR pollutant could be affected by
the project; and
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 125
(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.
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.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 126
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, §§ 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, § 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, Part B, §§ I & III.
The requirements in paragraphs a, b and e apply to sources located in the Denver 1 -hour ozone attainment/maintenance area,
any nonattainment area for the 1 -hour ozone standard and to the 8 -hour Ozone Control Area and on a state -only basis to sources
located in any ozone nonattainment area, which includes areas designated nonattainment for either the 1 -hour or 8 -hour ozone
standard, unless otherwise specified in Regulation No. 7, Part A, Section I.A.1.c. 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, Part B, Section VI.C.3.
b. Except as 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
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. No person shall dispose of volatile organic compounds by evaporation or spillage unless Reasonably Available
Control Technology (RACT) is utilized.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 127
d. No owner or operator of a bulk gasoline terminal, bulk gasoline plant, or gasoline dispensing facility as defined in
Colorado Regulation No. 7, Part B, Sections IV.C.2., IV.C.3. and VII.A.3., 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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit #15OPWE394
Whiting Oil and Gas Corporation
Redtail Gas Plant and Razor 21 Pad
Page 128
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
*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 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Inspection Information
APPENDIX A - Inspection Information
1. Directions to Plant:
Appendix A
Page 129
From Denver, CO:
Take I-25 North towards Ft. Collins
Exit 216A to merge onto I-76 East towards Fort Morgan, travel 74.5 miles
Take Exit 80 and turn left onto CO -52 towards New Raymer and travel 42.1 miles
Turn left onto Co Rd 14 and then turn right onto Co Rd 127 in Weld County and Travel 15.7 miles
2. Safety Equipment Required:
Eye Protection; Hard Hat; Safety Shoes; Hearing Protection; Fire Retardant Clothing
3. Facility Plot Plan:
The attached Figure (following page) shows the plot plan as submitted in the October 2, 2015 Title V
Operating Permit Application.
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 from the 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 X, Section II.E).
Insignificant activities and/or sources of emissions identified by the permittee are as follows:
Fuel -Burning Equipment, other than internal combustion engines ≤ 5 MMBtu/hour (Reg 3, Part C,
II. E.3 j) *:
• Eight burners on heater treaters (four rated at 0.75 MMBtu/hr & four rated at 0.5
MBtu/hr)
• Four amine thermal oxidizer heaters
Air Pollution emission units, operations, or activities with emissions less than the appropriate de
minimis reporting level (Reg 3, Part C, ILE.3.a) *:
• Fugitive emissions from equipment leaks (Razor 21 CPB)
• Fugitive emissions from produced water loadout (Redtail Gas Plant and Razor 21 CPB)
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Inspection Information
Appendix A
Page 130
• Pneumatic valves (Razor 21 CPB)
• Crude oil loadout (formally AIRS 026)
• Condensate Loadout (formally AIRS 019)
• Fugitive Dust from Haul Roads (formally AIRS 020)
• Fugitive dust emissions from haul roads from crude oil and produced water truck
loadouts. (formally AIRS 028)
• DEHY-1 and DEHY-2 combustor assist gas
Chemical storage areas where chemicals are stored enclosed containers, and where total storage
capacity does not exceed 5000 gallons. This exemption applies solely to storage of such chemicals. This
exemption does not apply to transfer of chemicals from, to, or between such containers (Reg 3, Part C,
IIE.3.mm)*:
Redtail Gas Plant
• AST -02 — 24.8 bbl steel diesel storage tank
• AST -03 — 24.8 bbl steel diesel storage tank
• AST -06 — 3.45 bbl steel oil storage tank in transformer
• AST -08 — 11.9 bbl steel oil storage tank in transformer
• AST -09 — 23.8 bbl steel propane storage tank
• AST -10 — 23.8 bbl steel propane storage tank
• AST -11 — 1.32 bbl steel therminol-55 storage tank
• TK-8941 — 150 bbl steel therminol-55 hot oil relief tank
• TK-9923 — 11.9 bbl steel methanol storage tank
• TK-9930 - Steel chemical pH buffer tank
• TK-9941 — 90 bbl steel amine storage tank
• T-9943 — 90 bbl steel amine storage tank
• TK-9948 — 11.9 bbl steel methanol storage tank
Razor 21 CPB
• AST -02
• AST -03
• AST -04
• AST -08
• AST -09 -
• AST -10 -
• AST -11 -
• AST -12 -
• AST -14 —
• AST -15 —
— 11.9 bbl steel antifreeze storage tank
— 3.1 bbl plastic methanol storage tank
— 3.1 plastic methanol storage tank
— 5.23 bbl plastic chemical storage tank
7.85 bbl plastic chemical storage tank
5.23 bbl plastic chemical storage tank
5.23 bbl plastic chemical storage tank
6.42 bbl ENTEGRATE HS 7542 storage tank
11.9 bbl steel antifreeze storage tank
5.5 bbl plastic methanol storage tank
Storage tanks of capacity < 40,000 gallons of lubricating oils (Reg 3, Part C, II. E. 3. aaa):
• TK-9950 - 150 bbl steel lube oil storage tank (Redtail Gas Plant)
• AST -01 — 11.9 bbl steel lube oil store tank (Razor 21 CPB)
• AST -13 — 11.9 bbl steel lube oil storage tank (Razor 21 CPB)
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit Appendix A
Inspection Information Page 131
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Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Reporting Requirements and Definitions
with codes ver 8/20/14
Please note that, pursuant to 113(c)(2) of the federal Clean Air Act, any person who knowingly:
Appendix B
Page 134
(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.
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,
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Page 135
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:
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
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.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Page 136
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 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.
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 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Startup, Shutdown, Malfunctions and Emergencies,
Appendix B
Page 137
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 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
APPENDIX B: Monitoring and Permit Deviation Report - Part I
Appendix B
Page 138
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: Whiting Oil and Gas Corporation - Redtail Facility
OPERATING PERMIT NO: 15OPWE394
REPORTING PERIOD: (see first page of the permit for specific reporting period and dates)
Operating Permit Unit
ID
Unit Description
Deviations noted
During Period?'
Deviation Code z
Malfunction/Emergency
Condition Reported
During Period?
YES
NO
YES
NO
009
Equipment Leaks (fugitive VOCs) from a
natural gas processing plant.
011
One (1) Generac
SD0250KG178.7DI8HPYY3, diesel -fired,
compression ignition, reciprocating internal
combustion engine, having a site rated output
at or below 361 HP or 250 kW, powering a
generator set. This engine is equipped with
no controls. This emission unit is used as an
emergency generator, running all electrical
services at the office building.
013
Process flare (Air -Assist, FL -8540)
controlling emissions from routine
operations including: purge gas, emissions
from electric compressor and amine
blowdowns, and plant blowdowns, as well as
providing backup control to the thermal
oxidizer associated with point 017 (AMINE -
1) and the combustors associated with point
015 (DEHY-1) and point 016 (DEHY-2).
The flare has a minimum combustion
efficiency of 95%. The flare is not enclosed.
014
One (1) Zeeco hot oil heater, Model:
GLSF14, Serial Number: J131132, with a
total design heat input rate of 43.64
MMBtu/hr. This heater is fueled by natural
gas. This heater is equipped with low NOx
burners.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Page 139
Operating Permit Unit
ID
Unit Description
Deviations noted
During Period?1
Deviation Code 2
Malfunction/Emergency
Condition Reported
During Period?
YES
NO
YES
NO
015
One (1) Ethylene Glycol (EG), natural gas
dehydration unit (Alco, FA138-20B, serial
number: 2012-8390-12) with a design
capacity of 35.0 MMscf per day. This
emissions unit is equipped with two (2) Bear
CX-5H Duplex electric -glycol pumps with a
design capacity of 6 gal/min. This unit is
equipped with a flash tank, reboiler and still
vent. Emissions from the flash tank are
routed to the plant inlet for the facility or
plant flare as backup. Emissions from the still
vent are controlled by an enclosed combustor
or plant flare as backup.
016
One (1) Ethylene Glycol (EG), natural gas
dehydration unit (Alco, serial number: 2013-
8482-12) with a design capacity of 70
MMscf per day. This emissions unit is
equipped with two (2) Bear CX-5H Duplex
electric -glycol pumps with a design capacity
of 18 gal/min. This unit is equipped with a
flash tank and still vent. Emissions from the
flash tank are routed to the plant inlet for the
facility or plant flare as backup. Emissions
from the still vent are controlled by an
enclosed combustor or plant flare as backup.
017
Methyldiethanolamine (MDE.A) natural gas
sweetening system for acid gas removal with
a design capacity of 45 MMSCF per day.
This emissions unit is equipped with two (2)
electric amine recirculation pumps with a
total design capacity of 204 gallons per
minute. This system includes a natural
gas/amine contactor, a flash tank, and an oil -
heated amine regeneration reboiler. The oil
heater for the reboiler is covered under a
separate point (AIRS Point 014). Flash tank
emissions are re-routed to a plant inlet or
plant flare as backup. The still vent stream is
controlled by a thermal oxidizer or plant flare
as backup.
018
Two (2) 400 BBL fixed roof storage tanks
used to store produced water. Emissions
from these tanks are controlled by a
combustor.
021
One (1) Caterpillar, Model G3516, Serial
Number JEF03168, natural gas -fired, turbo-
charged, 4SLB reciprocating internal
combustion engine, site rated at 1311
horsepower. This engine shall be equipped
with an oxidation catalyst. This emission unit
is used as a gas lift compressor engine.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Page 140
Operating Permit Unit
ID
Unit Description
Deviations noted
During Period?'
Deviation Code 2
Malfunction/Emergency
Condition Reported
During Period?
YES
NO
YES
NO
023
Eight (8) two-phase separators controlled by
an open flare during gas -gathering system
downtime.
024
Twenty-two (22) 400 BBL fixed roof storage
tanks used to store produced water.
Emissions from these tanks are controlled by
an enclosed combustor.
025
Thirty-two (32) 400 BBL fixed roof storage
tanks used to store crude oil. Emissions from
these tanks are controlled by an enclosed
combustor.
Facility -Wide Requirements
Colorado Regulation No. 1 Opacity Standards
Additional Requirements: Colorado Regulation No. 7 (State -Only
Enforceable)
Colorado Regulation No. 7, Part D, Section II.B — Flare Requirements
(State -only enforceable)
Colorado Regulation No. 7, Part D, Section II.C — Storage Tanks
Requirements
40 CFR Part 60 Subpart A
40 CFR Part 63 Subpart A
Portable monitoring
General Conditions
Insignificant Activities
' 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 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
APPENDIX B: Monitoring and Permit Deviation Report - Part II
FACILITY NAME: Whiting Oil and Gas Corporation — Redtail Facility
OPERATING PERMIT NO: 15OPWE394
REPORTING PERIOD:
Appendix B
Page 141
Is the deviation being claimed as an: Emergency Malfunction N/A
(For NSPS/MACT) Did the deviation occur during: Startup Shutdown Malfunction
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:
SEE EXAMPLE ON THE NEXT PAGE
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Page 142
FACILITY NAME: Acme Corp.
OPERATING PERMIT NO: 96OPZZXXX
REPORTING PERIOD: 1/1/04 - 6/30/06
Is the deviation being claimed as an:
EXAMPLE
Emergency Malfunction XX N/A
(For NSPS/MACT) Did the deviation occur during: Startup
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
Shutdown
Malfunction
Division Code QA:
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix B
Page 143
APPENDIX B: Monitoring and Permit Deviation Report - Part III
REPORT CERTIFICATION
SOURCE NAME: Whiting Oil and Gas Corporation — Redtail Facility
FACILITY IDENTIFICATION NUMBER: 123-9AD0
PERMIT NUMBER: 15OPWE394
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 25-7 122.1,
C.R.S.
Printed or Typed Name Title
Signature of Responsible Official Date Signed
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 144
APPENDIX C
Required Format for Annual Compliance Certification Reports
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: Whiting Oil and Gas Corporation — Redtail Facility
OPERATING PERMIT NO: 15OPWE394
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.
Per mptrUni�ID
Unit Description
Deviations
Reported I
Monitoring
Method per
Permit
Was compliance continuous or
intermittent?3
Previous
Current
YES
NO
Continuous
Intermittent
009
Equipment Leaks
(fugitive VOCs) from a
natural gas processing
plant.
011
One (1) Generac
SD0250KG178.7DI8HP
YY3, diesel -fired,
compression ignition,
reciprocating internal
combustion engine,
having a site rated output
at or below 361 HP or
250 kW, powering a
generator set. This engine
is equipped with no
controls. This emission
unit is used as an
emergency generator,
running all electrical
services at the office
building.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 145
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
013
Process flare (Air -Assist,
FL -8540) controlling
emissions from routine
operations including:
purge gas, emissions
from electric compressor
and amine blowdowns,
and plant blowdowns, as
well as providing backup
control to the thermal
oxidizer associated with
point 017 (AMINE -1)
and the combustors
associated with point 015
(DEHY-1) and point 016
(DEHY-2). The flare has
a minimum combustion
efficiency of 95%. The
flare is not enclosed.
014
One (1) Zeeco hot oil
heater, Model: GLSF14,
Serial Number: J131132,
with a total design heat
input rate of 43.64
MMBtu/hr. This heater is
fueled by natural gas.
This heater is equipped
with low NOx burners.
015
One (1) Ethylene Glycol
(EG), natural gas
dehydration unit (Alco,
FAB38-20B, serial
number: 2012-8390-12)
with a design capacity of
35.0 MMscf per day.
This emissions unit is
equipped with two (2)
Bear CX-5H Duplex
electric -glycol pumps
with a design capacity of
6 gal/min. This unit is
equipped with a flash
tank, reboiler and still
vent. Emissions from the
flash tank are routed to
the plant inlet for the
facility or plant flare as
backup. Emissions from
the still vent are
controlled by an enclosed
combustor or plant flare
as backup.
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 146
Operating
Permit Unit ID
Unit Description
Deviations
Reported I
Monitoring
Method per
Permit. 2
Was compliance continuous or
intermittent?3
Previous
Current
YES
NO
Continuous
Intermittent
016
One (1) Ethylene Glycol
(EG), natural gas
dehydration unit (Alto,
serial number: 2013-
8482-12) with a design
capacity of 70 MMscf per
day. This emissions unit
is equipped with two (2)
Bear CX-5H Duplex
electric -glycol pumps
with a design capacity of
18 gal/min. This unit is
equipped with a flash
tank and still vent.
Emissions from the flash
tank are routed to the
plant inlet for the facility
or plant flare as backup.
Emissions from the still
vent are controlled by an
enclosed combustor or
plant flare as backup.
017
Methyldiethanolamine
(MDEA) natural gas
sweetening system for
acid gas removal with a
design capacity of 45
MMSCF per day. This
emissions unit is
equipped with two (2)
electric amine
recirculation pumps with
a total design capacity of
201 gallons per minute.
This system includes a
natural gas/amine
contactor, a flash tank,
and an oil -heated amine
regeneration reboiler.
The oil heater for the
reboiler is covered under
a separate point (AIRS
Point 014). Flash tank
emissions are re-routed
to a plant inlet or plant
flare as backup. The still
vent stream is controlled
by a thermal oxidizer or
plant flare as backup.
018
Two (2) 400 BBL fixed
roof storage tanks used to
store produced water.
Emissions from these
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 147
PermptrUniiID
iPrevious
Unit Description
Deviations
Reported I
Monitoring
Method per
Permit
Was compliance continuous or
intermittent?3
Current
YES
NO
Continuous
Intermittent
tanks are controlled by a
combustor.
021
One (1) Caterpillar,
Model G3516, Serial
Number JEF03168,
natural gas -fired, turbo-
charged, 4SLB
reciprocating internal
combustion engine, site
rated at 1311
horsepower. This engine
shall be equipped with an
oxidation catalyst. This
emission unit is used as a
gas lift compressor
engine.
023
Eight (8) two-phase
separators controlled by
an open flare during gas -
gathering system
downtime.
024
Twenty-two (22) 400
BBL fixed roof storage
tanks used to store
produced water.
Emissions from these
tanks are controlled by an
enclosed combustor.
025
Thirty-two (32) 400 BBL
fixed roof storage tanks
used to store crude oil.
Emissions from these
tanks are controlled by an
enclosed combustor.
Facility -Wide Requirements
Colorado Regulation No. 1 Opacity
Standards
Additional Requirements: Colorado
Regulation No. 7 (State -Only Enforceable)
Colorado Regulation No. 7, Part D, Section
II.B — Flare Requirements (State -only
enforceable)
Colorado Regulation No. 7, Part D, Section
ILC — Storage Tanks Requirements
40 CFR Part 60 Subpart A
40 CFR Part 63 Subpart A
Portable monitoring
General Conditions
Insignificant Activities 4
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 148
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 the compliance 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.
° 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.
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
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Compliance Certification Report
Appendix C
Page 149
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Notification Addresses
Appendix D
Page 150
APPENDIX D
Notification Addresses (ver. 1/27/2020)
1. Air Pollution Control Division
Colorado Department of Public Health and Environment
Air Pollution Control Division
Operating Permits Unit
APCD-SS-BI
4300 Cherry Creek Drive S.
Denver, CO 80246-1530
ATTN: Title V Unit Supervisor
2. United States Environmental Protection Agency
Compliance Notifications:
Enforcement and Compliance Assurance Division
Air and Toxics Enforcement Branch
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:
Air and Radiation Division
Air Permitting and Monitoring Branch
Mail Code 8ARD-PM
U.S. Environmental Protection Agency, Region VIII
1595 Wynkoop Street
Denver, CO 80202-1129
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit Acronyms
Appendix E
Page 151
APPENDIX E
Permit Acronyms
Listed Alphabetically:
AIRS - Aerometric Information Retrieval System
AP -42 - EPA Document Compiling Air Pollutant Emission Factors
APEN - Air Pollution Emission Notice (State of Colorado)
APCD - Air Pollution Control Division (State of Colorado)
ASTM - American Society for Testing and Materials
BACT - Best Available Control Technology
BTU - British Thermal Unit
CAA - Clean Air Act (CAAA = Clean Air Act Amendments)
CCR - Colorado Code of Regulations
CEM - Continuous Emissions Monitor
CF - Cubic Feet (SCF = Standard Cubic Feet)
CFR - Code of Federal Regulations
CO - Carbon Monoxide
COM - Continuous Opacity Monitor
CRS - Colorado Revised Statute
EF - Emission Factor
EPA - Environmental Protection Agency
FI - Fuel Input Rate in MMBtu/hr
FR - Federal Register
G - Grams
Gal - Gallon
GPM - Gallons per Minute
HAPs - Hazardous Air Pollutants
HP - Horsepower
HP -HR - Horsepower Hour (G/HP-HR = Grams per Horsepower Hour)
LAER - Lowest Achievable Emission Rate
LBS - Pounds
M - Thousand
MM - Million
MMscf - Million Standard Cubic Feet
MMscfd - Million Standard Cubic Feet per Day
N/A or NA - Not Applicable
NOx - Nitrogen Oxides
NESHAP - National Emission Standards for Hazardous Air Pollutants
NSPS - New Source Performance Standards
P - Process Weight Rate in Tons/Hr
PE - Particulate Emissions
PM - Particulate Matter
PMKo - Particulate Matter Under 10 Microns
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit Acronyms
Appendix E
Page 152
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Permit Modifications
Appendix F
Page 153
APPENDIX F
Permit Modifications
DATE OF
REVISION
TYPE OF
REVISION
SECTION NUMBER,
CONDITION NUMBER
DESCRIPTION OF REVISION
Operating Permit 15OPWE394
First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 154
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.co lorado.gov/pacific/cdphe/alternate-operating-scenario-aos-reporting-forms
DISCLAIMER:
These are only example reports and do not cover all possible requirements.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 155
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 156
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 157
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 158
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.1.a.
NSPS Subpart JJJJ: Standards of Performance for Stationary Spark Ignition Internal Combustion
Engines
Company:
Source ID:
Permit #:
Date:
Manufacturer:
Model:
Nameplate HP:
Engine Type:
Manufacture Date:
Date Engine Ordered:
Acme Gas Processing
9991234
93OPXX999
October 1, 2008
BestEngineCompany
777 LowNox
1340
2 Stroke Lean Burn
July 1, 2007
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 159
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
NO, 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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 160
(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)
(c)
N/A — For emergency engines only.
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 161
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: 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/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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 162
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 la 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)
(b)
The engine will comply with the emission and operating limitations at all times, except
during periods of startup, shutdown and malfunction (SSM)
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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 163
(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) 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).
(b) Pressure differential will be established during the initial performance test.
(c) 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 (0(6), 63.9(b) thru (e) & (g) &
(h) that apply by dates specified.
Operating Permit 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 164
(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 (f) 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.
63.6650 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 15OPWE394 First Issued: DRAFT
Air Pollution Control Division
Colorado Operating Permit
Engine AOS Applicability Reports
Appendix G
Page 165
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 15OPWE394 First Issued: DRAFT
TECHNICAL REVIEW DOCUMENT
For
DRAFT OPERATING PERMIT 15OPWE394
Whiting Oil and Gas Corporation — Redtail Gas Plant & Razor 21 Central Production Battery
Weld County
Source ID 1239AD0
DRAFT
Operating Permit Engineer:
Operating Permit Supervisor review:
Field Sen/ices Unit review:
I. Purpose
Jaclyn Zey
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 Operating Permit for the Redtail Gas Plant and Razor 21 Central
Production Battery.
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 updated application submitted on October
March 31, 2017, comments on the draft permit submitted on January 31, 2019,
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 www.colorado.gov/cdphe/airTitleV.
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.
II. Description of Source
The Redtail Gas Plant processes gas from wells producing from the Niobrara and
Codell/Ft. Hays formations. The inlet gas to the plant is gathered in a low-pressure
system and enters the plant at a pressure of approximately 10 pounds per square inch
gauge (psig). The gas travels through a series of filters and an inlet slug catcher
123/9AD0 Page 1 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
designed to remove slug liquids. The liquids removed are pumped to a 400 -barrel (bbl)
atmospheric gunbarrel tank. The inlet gas goes through three stages of compression
where the pressure is boosted to approximately 400 — 475 psig. The compressed gas
is then refrigerated with a series of heat exchangers and propane refrigeration. An
ethylene glycol (EG) system (DENY -1 and DEHY-2) injects EG into the gas for
additional gas dehydration and freeze protection. The EG is regenerated, and the
DEHY-1 and DEHY-2 still columns vent through their respective emissions control
devices. The hydrocarbon liquid that condenses in the refrigeration plant is sent to a
deethanizer column where a Y -grade natural gas liquid (NGL) product is produced.
The NGL is stored in 90,000 -gallon storage tanks from it is shipped to market via
pipeline. The vapors from the deethanizer column are combined with the residue gas
from the refrigeration cycle and sent to a third -party residue pipeline. A portion of the
residue gas is routed to an amine unit (AMINE -1) to remove carbon dioxide and then
recombined with the residue gas stream to meet the sales specifications for carbon
dioxide. The heat for the process is provided by a 43.64 MMBtu/hr hot oil heater
(HTR-1A). In summary, the equipment at the Redtail Gas Plant covered under this
Operating Permit includes: fugitive VOC from equipment leaks from the natural gas
processing plant, one (1) diesel -fired 361 HP engine, one (1) process flare, one (1)
natural gas -fired hot oil heater, two (2) ethylene glycol natural gas dehydration units,
one (1) MDEA Natural gas sweetening unit, and two (2) produced water storage tanks.
At the Razor 21 Central Production Battery, a combined stream of liquids and natural
gas is extracted from the wells located at Razor 21A, Razor 21 B, Razor 21 C, and
Razor 21 D (future) and transferred to 2 -phase separators where the gas is separated
from the liquids. The liquids are transferred to heater treaters that are equipped with
burners to facilitate further separation into streams of gas, crude oil, and produced
water. Some of the produced gas is sent to the gas lift engines where it is compressed
and re -injected into the wells, and the remainder of the produced gas is routed to the
Redtail Gas Plant. When the gas gathering system or Redtail Gas Plant is not
available to receive produced gas, it is routed to the Backup/Emergency Flare (RZ-
FLR-1). The separated streams of crude oil and produced water are transferred to
storage tanks. Crude oil is subsequently transferred by pipeline using a lease
automatic custody transfer (LACT) unit, or by truck loadout when the pipeline is unable
to receive oil. Produced water is subsequently transferred offsite by pipeline or by
truck when the pipeline is unable to receive produced water. Vapors generated in the
crude oil and produced water storage tanks are captured by enclosed combustors
(RZ-COMB-1, RZ-COMB-2). The CPB is powered by grid electricity. In summary, the
equipment at the Razor 21 Central Production Battery covered under this Operating
Permit includes: one (1) 4SLB 1311 HP engine, eight (8) separators controlled by a
flare, and twenty-two (22) produced water storage tanks and thirty-two (32) crude oil
storage tanks controlled by enclosed combustors.
Additionally, insignificant activities at the combined Redtail facility include: condensate
loadout, fugitive dust from haul roads, a tank vapor flare, eight (8) burners on heater
treaters, one (1) emergency generator (included in Section II of the operating permit
as 011), fugitive VOC from equipment leaks at the Razor 21 CPB, fugitive VOC
emissions from produced water loadout, pneumatic values at the Razor 21 CPB,
crude oil loadout, and various storage tanks.
123/9AD0 Page 2 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Aggregation Determination for Redtail, Razor 21, and Surrounding Production
Pads
Per 40 CFR Part 70.2 the definition of a major source is any stationary source (or
group of stationary sources that are located on one or more continuous or adjacent
properties and are under common control of the same persons (or persons under
common control) belonging to a single major industrial grouping. Additionally, for
onshore activities under the SIC major group 13 — Oil and Gas Extraction, pollutant
emitting activities are considered adjacent if they are located on the same surface site
or are located on surface sites that are located within a quarter mile of one another (as
measured from the center of equipment on the surface site) and they share
equipment. This definition also goes on to exclude any oil or gas exploration or
production well (with its associated equipment) and emissions from any pipeline
compressor or pump station from aggregation from similar units, whether or not the
units are in a contiguous are or under common control.
As the Redtail Gas Plant and Razor 21 CPB are located on adjacent properties under
common control and share equipment the facilities are aggregated into a single source
for the purposes of Title V permitting.
Additionally, there are several well production facilities surrounding the Redtail Gas
Plant and Razor 21 central production battery, however, given the definition outlined
above excludes natural gas exploration and production well sites, the oil and gas
production facilities surrounding the Redtail Gas Plant and Razor 21 CPB are not
aggregated for the purposes of Title V permitting.
The facility is located approximately 15 miles north of Raymer, Colorado in Weld
County. This facility is located in an areas designated attainment for all pollutants.
Wyoming and Nebraska are affected states within 50 miles of the facility. There are no
Federal Class I or Class II designated areas within 100 kilometers of the facility.
Based on the information provided by the applicant, this source is categorized as a
minor stationary source for PSD as of the issue date of this permit. Any future
modification which is major by itself (Potential to Emit ≥ 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.
Emissions (in tons/year) at the facility are as follows:
Pollutant
PTE (tpy)
Actual (tpy)
NOx
41.5
13.5
CO
76.7
27.9
VOC
119.2
104.2
SO2
25.4
0.0
PM2.5
0.3
0.1
123/9AD0 Page 3 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
PMio
6.8
0.1
HAPs
16.0
13.0
Actual emissions of criteria and HAP pollutants are based on the emissions reported
to the Division during the 2017 inventory year. See Attachment A for information
regarding emission factors and potential to emit calculations.
Ill. Applicable 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
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).
40 CFR Part 60 Subpart Dc
Subpart Dc applies to each steam generating unit for which construction, modification,
or reconstruction is commenced after June 9, 1989 that has a maximum design heat
input capacity of 29 megawatts (MW) (100 MMBtu per hour) or less, but greater than
or equal to 2.9 MW (10 MMBtu/h).
Sulfur dioxide standards of this subpart are applicable only to coal-fired units and units
where coal is combusted in conjunction with other fuels. Likewise, the particulate
matter standards are applicable to units that combust coal or mixtures of coal with
other fuels and has a heat input capacity of 30 MMBtu/hr or greater. As the hot oil
heater (AIRS 014) is only permitted to combust natural gas, the SO2 and PM
standards of this subpart do not apply to this unit.
All other heaters are rates less than 10 MMBtu/hr; therefore, the provisions of this
Subpart are not applicable to the other stream generating units located at the Redtail
facility.
40 CFR Part 60 Subpart GG
This subpart applies to all stationary gas turbines which commenced construction,
modification, or reconstruction after October 3, 1977 with a heat input at peak load
equal to or greater than 10 MMBtu per hour, based on the lower heating value of the
fuel fired.
Per the Preliminary Analysis written for Construction Permit 13WE1681 indicates the
gas turbine (AIRS 010) was manufactured prior to the applicability date for 40 CFR
Part 60 Subpart KKKK (February 18, 2005).
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Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
UPDATE: The permittee indicated in a communication to the division that this turbine
had been disconnected and the permittee subsequently submitted a cancellation
notice for the turbine on July 10. 2017. This emission unit was removed from this
operating permit.
40 CFR Part 60 Subpart 1111
Subpart 1111 established standards of performance for Stationary Compression Ignition
Internal Combustion engines for which construction commenced after July 11, 2005
and where the CI ICE was manufactured after April 1, 2006. AIRS 011 is an
emergency diesel -fired CI ICE that commenced operation on March 27, 2014 and is
subject to the provisions of this Subpart, including, but not limited to: emergency
engine emission standards, fuel requirements, deadlines for importing or installing
previous model years, monitoring requirements, compliance requirements, notification,
reporting, and recordkeeping requirements, and the specified general provisions of 40
CFR Part 60 Subpart A.
AIRS 021 is a spark ignition ICE; are therefore exempt from the requirements of this
Subpart.
40 CFR Part 60 Subpart JJJJ
Subpart JJJJ applies to owner and operators of stationary spark ignition internal
combustion engines, for which construction commenced after June 12, 2006 and the
engine was manufactured:
• On or after July 1, 2007 for engines with a maximum engine power greater than
or equal to 500 HP (except lean burn engines with a maximum engine power
greater than or equal to 500 HP and less than 1,350 HP);
• On or after January 1, 2008 for lean burn engines with a maximum engine
power greater than or equal to 500 HP and less than 1,350 HP;
• On or after July 1, 2008, for engines with a maximum engine power less than
500 HP;
• On or after January 1, 2009 for emergency engines with a maximum engine
power greater than 25 HP.
For the purposes of this subpart the date construction commences is the date the
engine is ordered.
Facility
Equipment ID
AIRS ID
HP
Type
Order Date
Manufacture
Date
RZ-ENG-1
021
1380
4SLB
2/14/2014
7/21/2011
This engine was manufactured and ordered after the applicability dates of this
Subpart; therefore, these engines are subject to the provisions of this Subpart,
including, but not limited to: emission standards, compliance requirements,
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Technical Review Document — Initial Operating Permit
notification, reporting, and recordkeeping requirements, and the specified sections of
the general provisions of 40 CFR Part 60 Subpart A.
UPDATE: The permittee removed the engine associated with AIRS ID 032 and
submitted a cancellation request received by the Division on April 9, 2019. The
requirements associated with this emission unit were removed from the operating
permit.
40 CFR Part 60 Subpart Kb
This subpart applies to each storage vessel with a capacity greater than or equal to 75
cubic meters that is used to store volatile organic liquids (VOL) for which construction,
reconstruction, or modification is commenced after July 23, 1984. This subpart does
not apply to storage vessels with a capacity greater than or equal to 151 m3 storing a
liquid with a maximum true vapor pressure less than 3.5 kilopascals (kPa) or with a
capacity greater than or equal to 75 m3 but less than 151 m3 storing a liquid with a
maximum true vapor pressure less than 15.0 kPa.
This subpart does not apply to vessels with a design capacity less than or equal to
1,589.874 m3 used for petroleum or condensate stored, processed, or treated prior to
custody transfer.
Seventy-five cubic meters is equivalent to 19,813 liquid gallons, all storage tanks
(AIRS 007, 018, 024, & 025) at this facility are 400 bbl (16,800 gallons) and less than
the applicability threshold of this subpart. The requirements of this subpart do not
apply.
40 CFR Part 60 Subpart KKK
Subpart KKK applies to affected facilities at onshore natural gas processing plants
that commenced construction, reconstruction, or modification after January 20, 1984
and on or before August 23, 2011.
The operating permit application received by the Division on October 2, 2015 indicates
that none of the equipment located at the Redtail Gas Plant or the Razor 21 CPB
commenced construction after August 23, 2011; therefore, the requirements of this
subpart do not apply at this facility.
40 CFR Part 60 Subpart KKKK
This subpart applies to owners and operators of stationary combustion turbines with
heat inputs at peak load equal to or greater than 10 MMBtu per hour, based on the
higher heating value of the fuel, which commenced construction, modification, or
reconstruction after February 18, 2005.
40 CFR Part 60 Subpart LLL
This subpart establishes 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. The Redtail
facility was constructed in May 2013; therefore the provisions of this subpart are not
applicable.
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Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
40 CFR Part 60 Subpart OOOO
40 CFR Part 60, Subpart OOOO established emission standards and compliance
schedules for the control of volatile organic compounds (VOC) and sulfur dioxide
(S02) emissions from affected facilities that commence construction, modification, or
reconstructed after August 23, 2011. The Redtail facility consists of a natural gas
processing plant and a co -located well pad.
For the purposes of this Subpart the Redtail Natural Gas Processing Plant and the
Razor 21 CPB, although co -located for the purposes of Title V and PSD applicability,
are considered two separate facilities. Under this Subpart a natural gas processing
plant is defined as, "any processing site engaged in the extraction of natural gas
liquids from field gas, fractionation of mixed natural gas liquids to natural gas products,
or both. A Joule -Thompson valve, a dew point depression valve, or an isolated or
standalone Joule -Thompson skid is not a natural gas processing plant". The Razor 21
CPB does not fit into this definition of a natural gas processing plant as this portion of
the facility is not engaged in the processing activities described in definition.
With respect to fugitive emissions requirements, Subpart OOOO applies to the group
of all equipment, except compressors, within a process unit. A process unit is defined
as, "components assembled for the extraction of natural gas liquids from field gas, the
fractionation of the liquids into natural gas products, or other operations associated
with the processing of natural gas products. A process unit can operate independently
if supplied with sufficient feed or raw materials and sufficient storage facilities for the
products".
Based on the definitions provided in this Subpart the Division believes that the fugitive
requirements of this Subpart (§60.5365(f)) would not apply to Razor 21 CPB portion of
the facility as this pad does not meet the definitions for any of the facilities listed in
§60.5365(f)(2). Therefore, any fugitives at the Redtail Gas Plant and Razor 21 CPB
are considered to be separate. The Redtail Gas Plant is subject to equipment leak
standards applicable to onshore natural gas processing plants (§60.5400).
Additionally, the Redtail Gas Plant fugitive emission point (AIRS 009) covers the
reciprocating compressors located at the gas plant (with emissions below reporting
thresholds); the applicable requirements from this subpart for these compressors have
been incorporated into the operating permit.
In addition, for the purposes of pneumatic affected facility applicability, the provisions
of this Subpart are applicable to each single continuous bleed natural gas -driven
pneumatic controller operating at either a natural gas processing plant or in the natural
gas production segment (between the wellhead and the point of custody transfer to
the natural gas transmission and storage segment and not including natural gas
processing plants). The Division's 2017 inspection report indicates that all pneumatic
controllers located at the facility are intermittent bleed; therefore, since they are not
continuous bleed (as defined in this Subpart) the provisions of this subpart are not
applicable to the pneumatics at this facility.
Subpart OOOO applies to storage vessel affected facilities, which are defined as a
single storage vessel located in the oil and natural gas production segment, natural
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Technical Review Document — Initial Operating Permit
gas processing segment, or natural gas transmission and storage segment with the
potential for VOC emissions equal to or greater than six (6) tpy. This Subpart specifies
that the determination may take into consideration requirements under a legally and
practically enforceable limit. Storage tanks grouped under AIRS points 007, 018, and
024 have VOC limits for each tank grouping incorporated into the operating permit that
are less than six tons per year; therefore, are exempt from the provisions of this
subpart. Additionally, the storage tanks covered under AIRS 025, while having a
permit limit exceeding six tons per year (45 tpy) are grouped into an emission unit
consisting of thirty-two tanks for permitting purposes. However, the VOC PTE of a
single tank is less than the applicability threshold (1.4 tpy); therefore these tanks are
also exempt from the provisions of this subpart.
Subpart OOOO also applies to each sweetening unit located at onshore natural gas
processing plants that process natural gas from either onshore or offshore wells. As
this sweetening unit (AIRS 017) is located at the Redtail Gas Plant and processes
natural gas from the surrounding wells, it is subject to the requirements of this
Subpart. However, the design capacity is less than 2 LT/D of H2S; therefore, only the
recordkeeping and reporting requirements of this subpart are applicable.
40 CFR Part 60 Subpart 0000a
Subpart 0000a established emission standards and compliance schedules for the
control of the pollutant greenhouse gases from affected facilities in the crude oil and
natural gas source category that commence construction, modification, or
reconstruction after September 18, 2015. This subpart also establishes emission
standards and compliance schedules for the control of volatile organic compounds
and sulfur dioxide emissions from affected facilities in the crude oil and natural gas
source category that commence construction, modification, or reconstruction after
September 18, 2015. None of the potentially applicable equipment at the Redtail
facility were constructed nor reconstruction on or after the applicability date of this
subpart.
A modification, as defined in 40 CFR Part 60 Subpart A, is "any physical change in, or
change in the method of operation of, an existing facility which increases the amount
of any air pollutant (to which a standard applies) emitted into the atmosphere by that
facility or which results in the emission of any air pollutant (to which a standard
applies) into the atmosphere not previously emitted."
The construction permit modification submitted on January 26, 2016 requested the
replacement of previously permitted thermal oxidizer controlling the dehydration units
to condensers followed by enclosed combustors. This change did not modify the
emissions originating from this facility; therefore, is not considered a modification as
defined in 40 CFR Part 60 Subpart A.
The construction permit modification application submitted on July 28, 2017 resulted in
the incorporation of new emission factors based on site -specific sampling and
analysis; the Division does not consider updating emission factors to more
representative values to be modifications as defined in Part 60.
Hazardous Air Pollutants (HAPs)
123/9AD0 Page 8 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The Redtail facility is a synthetic minor source of Hazardous Air Pollutant emissions
with a facility -wide HAP emission limit of 9.0 tpy for each individual HAP and 24 tpy for
total HAPs.
The facility was previously oonsidered a major source of HAP emissions due to
methanol emissions exceeding the previously permitted limits. However, the EPA
repealed their "once in always in policy" on January 25, 2018 and facilities that were
considered major sources of HAP emissions and subsequently lower their emissions
to below major source thresholds are no longer required to comply with the major
source requirements indefinitely.
40 CFR Part 63 Subpart EEEE
Subpart EEEE establishes emission limitations, operating limits, and work practice
standards for organic hazardous air pollutants (HAPs) emitted from organic liquids
distribution (non -gasoline) operations at major source of HAP emissions. The Redtail
Gas Plant and Razor 21 CPB have synthetic minor limits incorporated into this
operating permit; therefore, the provisions of this Subpart are not applicable.
40 CFR Part 63 Subpart DDDDD
Subpart DDDDD establishes emission limitations and work practice standards for
HAPs emitted from industrial, commercial, or institutional boilers or process heaters
located at a major source of HAP emissions. The Redtail facility has synthetic minor
HAP limits incorporated into the operating permit; therefore, is an area source for the
purposes of this subpart. The provisions of this subpart are not applicable.
40 CFR Part 63 Subpart H
Subpart H establishes emission standards for organic hazardous air pollutants for
equipment leaks at facilities where equipment required by this Subpart that are
intended to operate in organic hazardous air pollutant service 300 hours or more
during the calendar year with a source subject to the provisions of a specific subpart in
40 CFR Part 63 that references Subpart H. None of the equipment at this facility is
subject to a subpart in Part 63 that references Subpart H; therefore, no provisions of
this subpart do not apply to this facility.
40 CFR Part 63, Subpart 1*1
Subpart HH establishes national emission standards for HAPs emitted from oil and
natural gas production facilities. For facilities that are located after the point of custody
transfer (the point where natural gas enters a processing plant), HAP emissions from
all emission units are aggregated for major source determinations. Controlled HAP
emissions from the Redtail Gas Plant do not exceed major source thresholds
(individual HAPs < 10 tpy; total HAPs < 25 tpy; see Attachment A for emission
calculations) and the facility is subject to facility -wide synthetic minor HAP limits
incorporated in the operating permit. Therefore, the Redtail Gas Plant is considered
an area source of HAP emissions. This facility is not located in any UA or UC
boundaries. For area sources under this Subpart only triethylene glycol dehydration
units are considered affected sources.
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Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The Razor 21 CPB is located prior to the point of custody transfer (point where natural
gas enters the processing plant) it is considered a production field facility under this
subpart, only emissions from glycol dehydration units and storage vessels were
aggregated for a major source determination. Since the Redtail Gas Plant and the
Razor 21 CPB are co -located for the purposes of Title V permitting applicability the
facility -wide synthetic minor HAP limits also apply to the Razor 21 CPB; therefore, this
portion of the facility is also considered an area source.
As the Redtail Gas Plant and Razor 21 CPB are both considered area sources due to
the synthetic minor HAP limits incorporated into the operating permit, monitoring of
facility -wide HAPs against this synthetic minor limit will serve to monitor compliance
with the area source status of this facility.
40 CFR Part 63 Subpart HHH
Subpart HHH establishes emission standards for HAPs emitted from natural gas
transmission and storage facilities that are major sources of HAP emissions. The
Redtail Gas Plant and Razor 21 CPB are not a major source of HAPs nor are they
located within the transmissions and storage segment; therefore, these provisions are
not applicability this this facility.
40 CFR Part 63 Subpart JJJJJJ
Subpart JJJJJ establishes national emission standards for hazardous air pollutants
(HAP) for industrial, commercial, and institutional boilers located at area sources of
HAP emissions. For the purposes of this subpart 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. Controlled flame combustion refers to a
steady-state, or near steady state, process wherein fuel and/or oxidizer feed rates are
controlled... Waste heat boilers, process heaters, and autoclaves are excluded from
the definition of Boiler." There are several reboilers (dehydration units and amine unit)
and process heaters (on separators and the hot oil heater — AIRS point 014) located at
the Redtail facility, however, per this definition they are exempt as processes heaters;
therefore, the provisions of this subpart are not applicable.
40 CFR Part 63 Subpart SS
Subpart SS establishes national emission standards for closed vent systems, control
devices, recovery devices, and routing to a fuel gas system or a process at facilities
that are subject to a Subpart which references Subpart SS for such air emission
control. None of the applicable provisions of subparts of 40 CFR Part 63 specifically
reference Subpart SS for control requirements; therefore, the provisions of this
Subpart are not applicable to this facility.
40 CFR Part 63 Subpart YYYY
Subpart YYYY establishes emission and operating limitations for HAP emissions from
stationary combustion turbines located at major sources of HAP emissions. There is
one simple cycle turbine located at the Redtail Gas Plant, however, the facility is an
area source with facility -wide synthetic minor total and individual HAP limits, which are
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
monitored on a rolling twelve-month basis. Therefore, the provisions of this Subpart
are not applicable to the turbine located at this facility.
40 CFR Part 63 Subpart ZZZZ
Subpart ZZZZ establishes emission and operating limitations for HAPs emitted from
stationary reciprocating internal combustion engines located at major and area
sources of HAP emissions. The Redtail facility has synthetic minor HAP emission
limits established in the operating permit; therefore, is considered to be an area
source under this Subpart.
Facility ID
Construction
Commencement
ZZZZ Applicability
GEN-2 (AIRS 011)
2013
New, Emergency,
Complies with
Subpart ZZZZ by
meeting
requirements of 40
CFR Part 60 Subpart
1111
RZ-ENG-1 (AIRS 021)
2015
New, Complies with
Subpart ZZZZ by
meeting
requirements of 40
CFR Part 60 Subpart
JJJJ
For the purposes of this subpart, "construction" means the on -site fabrication,
erection, or installation of an affected source and does not include the removal of all
equipment comprising an affected source from an existing location and reinstallation
of such equipment at a new location.
Colorado Regulation No. 7, Part C, Section ll
The provisions of this section apply to industrial cleaning solvent operation with total
combined uncontrolled actual VOC emissions equal to or greater than three (3) tons
per calendar year (excluding VOC emissions from solvents used for cleaning
operations that are exempt under Section X.E.4). Emissions from cleaning solvents at
the Redtail facility are less than three tons per year; therefore, the provisions of this
section are not applicable.
Colorado Regulation No. 7, Part E, Section ILA
Section II.A outline the requirements for combustion equipment that existed at a major
source of NOx as of June 3, 2016 located in the 8 -hour ozone control area. The
Redtail facility is not located in the 8 -hour ozone control area; therefore, the provisions
of this section are not applicable.
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Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Colorado Regulation No. 7, Part D, Section I
Colorado Regulation No. 7, Part D, Section I applies to oil and gas exploration and
production operations, natural gas compressor stations, and natural gas drip stations
that collect, store, or handle condensate in the 8 -hour Ozone Control Area (or any
ozone nonattainment or attainment/maintenance area). As of this issuance of this
permit the Redtail facility is located in an area designed as attainment for all criteria
pollutants; therefore, the requirements of Section I are not applicable to this facility.
Colorado Regulation No. 7, Part D, Section II.C
Section II.C contains requirements applicable to storage tanks located at natural gas
processing plants and compressor stations.
The condensate storage tanks located at the Redtail facility have an uncontrolled
potential to emit VOCs in excess of 20 tons per year, which subjects these tanks to
both the 95% VOC control efficiency and the average hydrocarbon control efficiency of
95%. These tanks and associated air pollution control equipment were permitted prior
to May 1, 2014; therefore, are not subject to the 98% hydrocarbon design destruction
efficiency.
All other storage tanks at the Redtail facility have an uncontrolled potential to emit
VOCs in excess of six tons per year, which subjects these tanks to a 95% average
hydrocarbon control efficiency. These tanks and associated air pollution control
equipment were permitted after May 1, 2014; therefore, are subject to the 98%
hydrocarbon design destruction efficiency.
The following recordkeeping and reporting provisions were added to this operating
permit to address monitoring gaps identified in the regulation in accordance with the
provisions of Colorado Regulation No. 3, Part C, Section V.C.5.b and current Division
standards:
• Reg 7 Section II.C does not specify a compliance schedule for inspections of
tanks with actual uncontrolled emissions below control thresholds that
subsequently increase emissions above control thresholds; language was
added to require inspections within 30 days of discovery of the emission
increase, or at the time that the next inspection was schedules as per the
previous inspection frequency, whichever occurs first.
• Reg 7 Section II.C requires STEM plans to be updated "as necessary" but does
not include a requirement to review the plans on a regular basis; a requirement
to conduct an annual review was added.
Colorado Regulation No. 7, Part D, Section II.D
Section II.D outlines the requirements for emission reductions from glycol dehydration
units located at oil and gas exploration and production operations and natural gas
processing plants. The dehydration units located at the Redtail facility are subject to
the provisions of this section; the following recordkeeping and reporting requirements
were added to this operating permit to address monitoring gaps identified in the
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
regulation in accordance with the provisions of Colorado Regulation No. 3, Part C,
Section V.C.5.b and current Division standards:
• Reg 7, Part D, Section II.D does not contain monitoring and recordkeeping
requirements that would establish whether and when the equipment is subject
to control requirements based on emission thresholds; a condition has been
added to address this deficiency.
• Reg 7, Part D, Section II.D allows exemptions from certain requirements based
on the distance to certain categories of off -site activities, the nature of which
can change over time. The rule is missing a requirement to re-evaluate whether
these activities exist; a requirement to complete a review annually was
included.
• Reg 7, Part D, Sections II.D.3 and II.C.1.b include requirements for a minimum
design destruction efficiency but no methods to monitor compliance; a condition
requiring that records be maintained was added.
Colorado Regulation No. 7, Part D, Section II.E
This section of Regulation No. 7 applies to fugitive emissions for well production
facilities and natural gas compressor stations. Since this portion of the regulation is
not applicable to natural gas processing plants, the Redtail Gas Plant and the Razor
21 Central Production Battery were not aggregated to determine applicability. The
Division allows for the use of the emission factors from Table 2-8 of the EPA EPA -
453/R -95-017 to determine permitting requirements from these facilities. Using the
emission factors from Table 2-8 the VOC emissions are below APEN de minimus
levels. However, the requirements for fugitives from well production facilities and for
compressor seals and open-ended lines of Section XVII.F are applicable to the Razor
21 CPB and have been included in the Operating Permit.
Colorado Regulation No. 7, Part D, Section II.F
This section applies to gas coming off separators, produced during normal operation
from well production facilities. Under Section II a well production facility is defined as,
"all equipment at a single stationary source directly associated with one or more oil
wells or gas wells. This equipment includes, but is not limited to, equipment used for
storage, separation, treating, dehydration, artificial lift, combustion, compression,
pumping, metering, monitoring, and flowline." As separators at the Razor 21 CPB
serve multiple natural gas wells this section is applicable to the separators at the
Razor 21 CPB.
Colorado Regulation No. 7, Part D, Section lI.G
This section applies to emissions generated during downhole well maintenance, well
liquids unloading events, and well plugging. This section is applicable to any well
liquids unloading at the facility and was therefore incorporated into the operating
permit.
Colorado Regulation No. 7, Part D, Section 111
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Technical Review Document — Initial Operating Permit
This section applies to pneumatic controllers that are actuated by natural gas, and
located at, or upstream of natural gas processing plants (upstream activities include:
oil and gas exploration and production operations and natural gas compressor
stations). This section requires that owners or operators of all pneumatic controllers
(statewide, III.C.3.a) placed in service on or after May 1, 2014 at facilities that do not
utilize grid power either utilize pneumatic controls that emit natural gas in quantities
less than or equal to low -bleed pneumatic controllers or utilize intermittent pneumatic
controllers. Per the Division's 2017 inspection report the Redtail facility complies with
this section utilizing intermittent pneumatic controllers. Pneumatic controllers located
at the Redtail facility are subject to the recordkeeping requirements of Section III.E.2.
UPDATE: The revisions to Regulation No. 7 adopted on December 19, 2019 add
requirements for pneumatic controller inspection and enhanced response
requirements (Section III.F) beginning on May 1, 2020 for owners and operator of
natural gas -driven pneumatic controller state-wide. This section applies to the
intermittent pneumatic controllers located at the Razor 21 CPB and were incorporated
into the operating permit.
Colorado Regulation No. 7, Part D, Section V
Section V requires owners or operator of oil and natural gas operations and equipment
at or upstream of a natural gas processing plant to submit a single annual report that
includes actual emissions and other specified information. The provisions of this
section are applicable to the Razor 21 CPB and Redtail facility and were incorporated
into the operating permit.
Colorado Regulation No. 7, Part E, Section l.D
This section of Regulation No. 7 is applicable to natural gas fired reciprocating internal
combustion engines that are either constructed or relocated to Colorado from another
state on or after the applicability date. In the revisions to Regulation No. 7 that were
adopted on December 19, 2019 the exemption for engines subject to a MACT or
NSPS (formerly Section XVII.B.5) was removed. Under Regulation No. 7, the engine
denoted by AIRS ID 021 is considered to be new, lean burn engine and is subject to
the emission standards and work practice standards of Section I.D.2, which were
incorporated into the operating.
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:
None, none of the emissions units at the Redtail facility have controlled emissions
greater than thresholds. However, CAM will apply on renewal for all units with pre -
control emissions greater than major source thresholds.
123/9AD0 Page 14 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Compliance Order on Consent Case No. 2016-236
As a result of a request for Self -Audit penalty immunity submitted by Whiting on
August 29, 2014 and supplemented through a series of letters submitted from October
10, 2014 through July 1, 2015, the Division was informed of violations at Redtail/Razor
21 CPB that included exceeding the monthly condensate throughput limit for the
storage tanks under Construction Permit 13WE1450, exceeding the monthly
throughput limit and VOC, NM0x, and CO emission limits for the Main Plant Flare under
Construction Permit 13WE1129, and exceeding the annual throughput limit and VOC
and CO emission limits for the separators under Construction Permit 14WE0891. The
Division issued a Compliance Advisory (CA) to Whiting on February 26, 2016 that
included additional reported violations from the Self -Audit Request at other Whiting
facilities (Case Nos. 2016-021 through -072). A CA meeting between the Division and
Whiting occurred on June 28, 2016. The case remains open.
The Division and Whiting entered into a compliance advisory on October 13, 2016. A
Consent Order was issued on June 12, 2018, the compliance requirements included:
• Effective immediately, and without limitation, Whiting shall comply with the Act,
the Regulations, and all relevant permit conditions in the regulation and control
of air pollutants applicable to the facility.
• Whiting shall, within one hundred and eighty (180) days of the effective date of
this Consent Order, either (1) replace the Redtail shrouded flare with an
enclosed flare to meet the requirements of Permit Number 13WE1450,
Issuance 2, Conditions 2, 7, 11, 12, and 13 or (2) perform a compliance test of
the shrouded flare to demonstrate compliance with the permit emission limits
and the required contol efficiency of 95%. The compliance test shall be
conducted pursuant to the Division's Compliance Test Manual. No compliance
test shall be conducted without prior approval from the Division and the protocol
shall be submitted to the Division for review and approval at least thirty (30)
days prior to testing. Whiting shall submit the results of the compliance test to
the Division within thirty (30) days of test completion.
To address this issue of non-compliance, this requirement was incorporated
into the operating permit.
UPDATE: This requirement was fulfilled prior to this operating permit
commencing the public notice period; therefore, was not included.
• All documents submitted under this Consent Order shall use the same titles as
stated in this Consent Order, and shall reference both the case number and the
number of the paragraph pursuant to which the document is required. Unless
otherwise specifically provided herein, no. document submitted for Division
approval under this Consent Order may be implemented unless and until
written approval is received from the Division. Any approval by the Division of a
document submitted under this Consent Order is effective upon receipt by
Whiting. All approved documents, including all procedures and schedules
contained in the documents, are hereby incorporated into this Consent Order,
and shall constitute enforceable requirements under the Act.
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Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Compliance Order on Consent Case Nos, 2015-101 and -102
A review of the results of compliance testing completed on the Redtail compressor
engines (AIRS Points 001 - 006) between September 24, 2014 and January 20, 2015
and on the EG Dehydrator (DEHY-1; AIRS Point 015) on July 21, 2015 showed non-
compliance with permitted emission limits under General Permit GP02 (engines) and
Construction Permit 13WE3005 (DEHY-1), as well as failure to complete the tests in a
timely manner. The Division issued a Compliance Advisory (CA) to Whiting on
December 17, 2015 and a CA meeting was held on January 19, 2016. An Early
Settlement Agreement (ESA) was issued on August 23, 2016. The case is considered
closed.
Source Determination
With this permit action, the Division revisited the source determination in regards to
the natural gas operations in the area surrounding the Redtail Gas Plant and Razor 21
Pad to verify that the proper pollutant emitting activities are included in this permit as
part of the Redtail Gas Plant and Razor 21 Pad. The applicant did not identify any
other pollutant emitting activities in the vicinity of the Redtail Gas Plant and Razor 21
Pad on that are dependent upon the Redtail Gas Plant and Razor 21 Pad 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.
IV. Emission Sources
A. 007 — Condensate Storage Tank (13WE1450) — Redtail Gas Plant
1. Applicable Requirements
Three (3) 400 BBL fixed roof storage tanks used to store condensate. Emissions
from these tanks are controlled by an enclosed flare. According to the Notice of
Startup (received April 18, 2014), these storage tanks commenced operation on
April 6, 2014.
Colorado Construction Permit 13WE1450 was issued for these tanks on October
8, 2014 as an initial approval permit. A final approval permit was issued for
Colorado Construction Permit 13WE1450 on December 9, 2014. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit
UPDATE: The VOC emissions from this emission source fell below the reporting
and permitting thresholds of Colorado Regulation No. 3 and the permittee
submitted a cancellation request, received by the Division on January 24, 2019.
The requirements of Colorado Construction Permit 13WE1450 were not
incorporated into the operating permit. If, in the future, these tanks exceed the
reporting thresholds of Colorado Regulation No. 3, Part A or the permitting
thresholds of Colorado Regulation No. 3, Parts B or C the permittee will be
required to submit an APEN and/or a permit modification application to the
Division prior to changing the units operations that would cause these tanks to
emit at a level greater than permitting thresholds. Additionally, it should be noted
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Technical Review Document — Initial Operating Permit
that if these tanks exceed the thresholds listed in Colorado Regulation No. 7,
Section XVII the permittee will be required to comply with required provisions of
that section.
2. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Requirement for these tanks to be controlled by an enclosed flare.
Inspection confirmed that the flare controlling the tanks is the same
shrouded open flare that the Division identified during the previous
inspection. This issue is being resolved with the provision of Case #2016-
236 to either replace the flare with an enclosed flare or to perform a
compliance test on the shrouded flare to demonstrate compliance with the
permitted emission limits and the required control efficiency (95%). The
requirement to either replace or conduct compliance testing on this flare
was incorporated into the operating permit; therefore, no compliance plan
is necessary.
• The requirement for the existing open flare controlling the condensate
tanks covered by this permit shall be replaced with an enclosed flare upon
startup of Train 2, but no later than May 1, 2015. As of the 2017 inspection
the flare controlling these tanks was a shrouded open flare (see above).
This issue is being resolved with the provision of Case #2016-236 to either
replace the flare with an enclosed flare or to perform a compliance test on
the shrouded flare to demonstrate compliance with the permitted emission
limits and the required control efficiency (95%). The requirement to either
replace of conduct compliance testing on this flare was incorporated into
the operating permit; therefore, no compliance plan is necessary.
• The requirement to follow the most recent operating and maintenance
plan and recordkeeping format approved by the Division, namely the
requirements for thief hatch seals and pressure relief valves to be
inspected for integrity annually. During the 2017 inspection the permittee
provided AIMM inspection results of the PRVs and thief hatches. The
inspections did not include any documentation regarding physical
inspection results. This issue is being resolved through the requirement of
Case #2016-236 for the permittee to comply with the Act, the Regulations,
and all relevant permit conditions regarding the regulation and control of
air pollutant applicable to the facility, and all monitoring requirements are
directly incorporated into the operating permit; therefore, no compliance
plan is necessary.
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Technical Review Document — Initial Operating Permit
• Requirement to demonstrate compliance with the no visible emissions
requirement using EPA Method 22 to determine the presence of visible
emissions. The results of September 21, 2014 observations showed
accumulated emissions of one minute and thirty-four seconds. Failing to
operate the AIRS Point 007 flare with no visible emissions based on the
September 21, 2014 EPA Method 22 observation results (noncompliance
with Condition 11 of Issuance 1 permit that was in effect at the time of the
Method 22 observation) source is not in compliance. This issue is being
resolved via the requirement to either replace or conduct compliance
testing on the flare as required by Case #2016-236; therefore, a
compliance plan is unnecessary.
B. 009 — Fugitive VOC from Equipment Leaks from Redtail Gas Plant
(13WE1130)
1. Applicable Requirements
Equipment Leaks (fugitive VOCs) from a natural gas processing plant. According
to the Title V permit application, the fugitive emissions commenced operation on
April 6, 2014.
Colorado Construction Permit 13WE1130, Issuance 4 was issued for the unit on
March 2, 2017 as a final approval permit. The appropriate provisions of the final
approval construction permit have been directly incorporated into this operating
permit
The appropriate applicable requirements from Colorado Construction Permit
13WE1130 for the fugitive VOCs are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source (Regulation 3, Part B, Section III.G.5).
This is a Construction Permit only condition; therefore, was not
incorporated into the Operating Permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Monthly Limits:
Facility
Equipment ID
AIRS
Point
Pounds per Month
Emission Type
VOC
FUG -1
009
12570
Fugitive
(Note: Monthly limits are based on a 31 -day month.)
The owner or operator shall calculate monthly emissions based on the
calendar month.
Annual Limits:
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Technical Review Document — Initial Operating Permit
Facility
Equipment ID
AIRS
Point
Tons per Year
Emission Type
VOC
FUG -1
009
74.0
Fugitive
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
During the first twelve (12) months of operation of point 017 (Amine Unit),
compliance with both the monthly and annual emission limitations is
required. After the first twelve (12) months of operation, compliance with
only the annual limitation is required.
Compliance with the annual limits shall be determined by recording the
facility's annual criteria pollutant emissions, (including all HAPs above the
de-minimis reporting level) from each emission unit, on a rolling twelve
(12) month total. By the end of each month a new twelve-month total shall
be calculated based on the previous twelve months' data. The permit
holder shall calculate emissions each month and keep a compliance
record on site or at a local field office with site responsibility, for Division
review. This rolling twelve-month total shall apply to all permitted
emission units, requiring an APEN, at this facility.
This condition was modified upon incorporation into the Operating Permit
to remove the monthly limits. Per the Notice of Startup received by the
Division on November 3, 2015 the amine unit (point 017) commenced
operation on October 23, 2015 and therefore, has been in operation
longer than twelve (12) months prior to this draft permit. Additionally, the
individual and total HAP emission limits incorporated into the recently
issued construction permits 13WE3003, 13WE3005, 13WE3006,
13WE3007, 14WE0891, 14WE0892, and 14WE0893 (facility -wide total
HAPs < 9.0 tons/year and facility -wide individual HAP limits < 24.0
tons/year) were incorporated into the operating permit.
• The emission points in the table below shall be operated and maintained
with the emissions control method as listed in order to reduce emissions to
less than or equal to the limits established in this permit. (Regulation
Number 3, Part B, Section III.E.)
The operator or owner must perform leak detection and monitoring and
associated recordkeeping as specified in 40 CFR Part 60, subpart NSPS
OOOO
Facility
Equipment
ID
AIRS
Point
Control Method
Pollutants
Controlled
Fugitive
Components
controlled
Control
Percentag
e Granted
FUG -1
009
Leak Detection
and Repair
Program
VOC and
HAPs
Valves - Gas
Service
70
Valves - Light
Liquid Service
61
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Technical Review Document — Initial Operating Permit
Pumps - Light
Liquid Service
45
This condition was incorporated into the Operating Permit.
• The operator shall calculate actual emissions from this emissions point
based on representative component counts for the facility with the most
recent gas analyses for inlet gas and residue gas services, as required in
the Compliance Testing and Sampling section of this permit. The operator
shall maintain records of the results of component counts and sampling
events used to calculate actual emissions and the dates that these counts
and events were completed. These records shall be provided to the
Division upon request.
This condition was incorporated into the Operating Permit.
• Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process
modification, or adjustment of control equipment visible emissions shall
not exceed 30% opacity for more than six minutes in any sixty consecutive
minutes. Emission control devices subject to Regulation 7, Sections
XII.C.1.d or XVII.B.2.b shall have no visible emissions. (Reference:
Regulation No. 1, Section II.A.1. & 4.)
This emission point is a VOC only source; it is Division standard not to
include opacity limits in permits for VOC sources. This condition has not
been incorporated into the operating permit.
• 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 Redtail facility was subject to the major source requirements of
Subpart HH due to an exceedance of the facility -wide HAP limits that
occurred from the period of May 2014 through April 2015, which subjected
the facility to the EPA's "once in always in" policy. The facility was
subsequently considered a major source of HAPs and required to comply
with the major source provisions of the MACT rules. The EPA withdrew
their "once in always in" policy on January 25, 2018 allowing facilities that
had once been considered major sources of HAP emissions to take
synthetic or true minor HAP limits and subsequently be considered area
sources for the purposes of the MACT rules. This operating permit
includes facility -wide HAP limits and the applicable area source
requirements of Subpart HH. The area source requirements are only
applicable to TEG dehydration units; therefore, the above provisions
applicable to equipment leaks were not incorporated into the operating
permit.
• The fugitive emissions addressed by AIRS ID 009 are subject to the New
Source Performance Standards requirements of Regulation No. 6, Part A,
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Technical Review Document — Initial Operating Permit
Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas
Production, Transmission and Distribution.
The applicable provisions of 40 CFR Part 60 Subpart OOOO were
incorporated into the operating permit, including, but not limited to: leak
standards at affected facilities at on onshore natural gas processing
plants, initial compliance demonstration requirements, continuous
compliance demonstration requirements, notification, reporting, and
recordkeeping requirements, and general provisions.
• The reciprocating compressors grouped with the fugitive emissions
addressed by AIRS ID 009 are subject to the New Source Performance
Standards requirements of Regulation No. 6, Part A, Subpart OOOO,
Standards of Performance for Crude Oil and Natural Gas Production,
Transmission and Distribution
The appropriate provisions of 40 CFR Part 60 Subpart OOOO applicable
to the reciprocating compressors grouped under the fugitive emissions
point were incorporated into the operating permit, including, but not limited
to: standards for reciprocating compressor facilities, initial compliance
demonstration requirements, continuous compliance demonstration
requirements, notification, reporting, and recordkeeping requirements, and
general provisions.
• On an annual basis, the owner or operator 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 for the inlet gas and residue gas streams.
This extended gas analysis shall be used in the compliance demonstration
as required in the Emission Limits and Records section of this permit.
This condition was incorporated into the operating permit.
2. Emission Factors
The primary pollutant of concern is Volatile Organic Compounds.
Colorado Construction Permit 13WE1130 utilized the emission factors from the
EPA 's Protocol for Equipment Leak Emission Estimates, Table 2-4 with the
control percentages from Table 5-3.
Per EPA -453/R95-017, the key parameters for estimating the control
effectiveness of an LDAR program are the leak definition, the initial leak
frequency, and the final leak frequency.
Table 5-3 of EPA -453/R95-017 provides control percentages for fugitive VOC
emissions based on the implementation of a Leak Detection and Repair (LDAR)
program. LDDAR programs are designed to identify pieces of equipment that are
emitting sufficient amounts of emissions to warrant reduction of the emissions
through repair. Per EPA guidance, these programs are best suited for equipment
that can be repaired on-line and/or to equipment types for which equipment
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Technical Review Document — Initial Operating Permit
modifications are not feasible. These equipment types include, but are not
necessary limited to, valves, pumps, and connectors.
Equipment that cannot be repaired while online or cannot be bypassed are not
suited for control percentage reductions through a LDAR program. These
equipment types typically include compressors, open-ended lines (most easily
controlled by equipment modifications), and sampling connections.
3. Monitoring Requirements
The extended gas analysis, which is conducted on an annual basis, is utilized to
determine the VOC fraction of emissions from components in gas service. A
component count is required every five years upon issuance of this permit. The
facility is required to maintain a running total of additions/subtractions to the
required component count. The permittee is also required to meet the monitoring
and recordkeeping requirements of 40 CFR Part 60 Subpart OOOO.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
C. 010 — Gas Turbine (13WE1681) — Redtail Gas Plant
1. Applicable Requirements
One (1) Solar Turbine, Model: Saturn 1-1201 MKII, SN: TBD, Simple cycle,
natural gas -fired, combustion turbine rated at 11.2 MMBtu/hr heat input (HHV)
based on 100% load and 59.0 degrees Fahrenheit ambient temperature. Carbon
monoxide emissions from the turbine are controlled by a selective catalytic
oxidation unit. According to the Notice of Startup (received May 6, 2014), this
turbine commenced operation on April 21, 2014.
A cancellation notice was received for the APEN and permit associated with this
unit on October 8, 2014; therefore, none of the conditions from the Construction
Permit (13WE1681) were incorporated into the Operating Permit. This unit was
originally permitted with two different operating scenarios to account for the
turbine being used for prime power (Case 1) and for backup power (Case 2).
These operational cases are no longer valid as the unit provides emergency
electric power to the facility (per APEN received May 7, 2014).
Per this unit's exemption letter the permittee is required to calculate emissions on
an annual basis for the purposes of APEN reporting and the payment of annual
fees using the facility -wide fuel consumption as allocated using the turbine hours
of hours of operation. Requirements for the permittee to monitor the units hours
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Technical Review Document — Initial Operating Permit
or operation, natural gas consumption, and calculate emissions on an annual
basis have been incorporated into the Operating Permit.
This unit is subject to the requirements of 40 CFR Part 60 Subpart GG,
"Standards of Performance for Stationary Gas Turbines"; therefore, the
applicable requirements from this subpart have been incorporated into Section II
of the operating permit. In addition, the APEN exemption letter sent by the
Division on October 8, 2014, requires the source to maintain annual records of
fuel consumption, hours of operation, and emissions to verify the exemption — all
of these requirements have been incorporated into the Operating Permit.
UPDATE: Per communication from the permittee on January 24, 2019 this
turbine was disconnected in February 2015 and is no longer used at the site. The
requirements relevant to this turbine were removed from the operating permit.
2. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the turbine
was in of compliance with the requirements applicable to this turbine at the time
of the inspection.
D. 011 — Emergency Generator (13WE1682) — Redtail Gas Plant
1. Applicable Requirements
One (1) Generac SD0250KG178.7DI8HPYY3, diesel -fired, compression ignition,
reciprocating internal combustion engine, having a site rated output at or below
361 HP or 250 kW, powering a generator set. This engine is equipped with no
controls. This emission unit is used as an emergency generator, running all
electrical services at the office building. This engine is subject to NSPS IIII Tier 3
Standards. According to the Notice of Startup (received May 22, 2014), this
generator commenced operation on March 27, 2014.
This unit is permit exempt, APEN required under Colorado Regulation No. 3, Part
A, ll.d.1.a; a permit cancellation request was submitted to the Division on
October 2, 2015. Since the permit associated with this engine (13WE1682) was
cancelled prior to issuance of this Operating Permit the conditions contained
within construction permit have not been incorporated into the Operating Permit.
However, since this unit is subject to the requirements of 40 CFR Part 60
Subpart 1111, the appropriate provisions from that Subpart have been incorporated
into the Operating Permit.
The applicable requirements from Subpart 1111 include:
• Emission standards for emergency engines (§60.4202 and §60.4205)
• Duration of compliance with emission standards (§60.4206)
• Fuel requiremerrts (§60.4207)
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• Deadlines for importing or installing stationary CI ICE produced during
previous model years (§60.4208)
• Monitoring requirements (§60.4209)
• Compliance requirements (§60.4211)
• Notification, reporting, and recordkeeping requirements (§60.4214)
This unit is also subject to the requirements of 40 CFR Part 63 Subpart ZZZZ,
which includes only the requirement for new or reconstructed emergency or
limited use stationary RICE with a site rating of less than or equal to 500 brake
HP located at a major source of HAP emission to comply with Subpart ZZZZ by
meeting the requirements of 40 CFR Part 60 Subpart 1111 (§63.6590(c)(6)). See
the major source discussion under Section III, 40 CFR Part 63 Subpart ZZZZ for
the major source applicability determination of this engine.
In addition to the above outlined applicable federal requirements, the following
monitoring requirements have also been incorporated into the Operating Permit.
Requirements to calculate emissions from the engine annually for APEN
reporting and fee determination purposes, to monitor fuel consumption for the
purposes of calculating annual emissions, and the Colorado Regulation No. 1
opacity requirements (20% at all time and 30% during periods of start-up,
process modification, and occasional adjustment and cleaning of control
equipment).
2. Emission Factors
The emission factors used to determine the unit is permit exempt, APEN required
are from AP -42, Table 3.3-2 for all HAPs. PMio, PM2.5, NOx, CO, and VOC
emission factors are from NSPS 1111 (referenced to 40 CFR 89.112) and
converted from g/HP-hr to lb/MMBtu based on an engine fuel use rate of 17
gal/hr, a site rating of 250 kW, and a diesel fuel heating value of 139,000 Btu/gal.
3. Monitoring Requirements
The source is required to monitor the engine's diesel fuel consumption on an
annual basis utilizing the engine's fuel meter for the purposed of calculating the
emissions for use in the annual APEN reporting and fee determinations.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the Redtail Gas Plant and Razor 21 Central Production Battery on August 10,
2017. The inspection report did not identify any non-compliance issues for this
engine.
E. 013 — Process Flare (13WE3003) — Redtail Gas Plant
1. Applicable Requirements
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Technical Review Document — Initial Operating Permit
Process flare (Tornado, SL 16-72-16-0.375-12-316L and serial number: 14180)
controlling emissions from routine operations including: purge gas, emissions
from electric compressor and amine blowdowns, and plant blowdowns, as well as
providing backup control to the thermal oxidizer associated with point 017
(AMINE -1) and the combustors associated with point 015 (DEHY-1) and point
016 (DEHY-2). The flare has a minimum combustion efficiency of 95%. The flare
is not enclosed. According to the Notice of Startup (received July 17, 2015), this
flare commenced operation on July 1, 2015.
The source has demonstrated compliance under the provisions of Regulation No.
3, Part B, Section III.G.2 for initial approval construction permit 13WE3003 but
not yet received a final approval construction permit. Under the provisions of
Regulation No. 3, Part C, Section V.A.3., the Division will not issue a final
approval construction permit and is allowing the initial approval construction
permit to continue in full force and effect. The appropriate provisions of the initial
approval construction permit have been directly incorporated into this operating
permit
The appropriate applicable requirements from Colorado Construction Permit
13WE3003 for the flare are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation 3, Part B, Section III.G.5).
This is a construction permit only condition; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
FLR-1A
013
7.5
21.2
30.8
Point
See "Notes to Permit Holder #4" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
Compliance with the annual limits shall be determined by recording the
facility's annual criteria pollutant emissions, (including all HAPs above the
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de-minimis reporting level) from each emission unit, on a rolling twelve
(12) month total. By the end of each month a new twelve-month total shall
be calculated based on the previous twelve months' data. The permit
holder shall calculate emissions each month and keep a compliance
record on site or at a local field office with site responsibility, for Division
review. This rolling twelve-month total shall apply to all permitted emission
units, requiring an APEN, at this facility.
This condition was incorporated into the operating permit.
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
Facility
Equipment
ID
AIRS
Point
Control Device
Pollutants
Controlled
FLR-1A
013
Continuous- Pilot Flare
VOC,
HAPs
This condition was incorporated into the Operating Permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the throughput shall be maintained by the
applicant and made available to the Division for inspection upon request.
(Reference: Regulation 3, Part B, II.A.4)
Facility
Equipment
ID
AIRSnnual
Point
Process Parameter
ALimit
FLR-1A
013
Natural gas flaring
193.1
MMscf/yr
The owner or operator shall calculate monthly process rates based on the
calendar month.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the operating permit.
• 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
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Technical Review Document — Initial Operating Permit
not exceed 30% opacity for more than six minutes in any sixty consecutive
minutes. (Reference: Regulation No. 1, Section I I.A.1. & 4.)
This opacity requirement is not applicable to flares for the combustion of
waste gases; therefore, has not been incorporated into the Operating
Permit. The Reg 1, Il.A.5 opacity requirement for smokeless flare was
incorporated, see below. Additionally, this flare is the backup control
device for the facility's dehydration units during periods of thermal oxidizer
downtime, during periods when the dehydration units process vent
streams are controlled by the flare the Colorado Regulation No. 7 no
visible emissions requirement applies to this flare and has been
incorporated into the operating permit.
• No owner or operator of a smokeless flare or other flare for the
combustion of waste gases shall allow or cause emissions into the
atmosphere of any air pollutant which is in excess of 30% opacity for a
period or periods aggregating more than six minutes in any sixty
consecutive minutes. (Reference: Regulation No. 1, Section II.A.5.)
This condition was incorporated into the Operating Permit.
• The owner or operator shall continuously monitor the process flare with a
thermocouple to ensure the continuous presence of a pilot flame.
This condition was incorporated into the Operating Permit.
• The owner or operator shall continuously monitor and record the total gas
volume routed to the process flare using a flow meter to demonstrate
compliance with the throughput and emission limits contained in this
permit.
This condition was incorporated into the Operating Permit.
• 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. (Reference: Regulation No. 3,
Part B, Section III.G.7.)
This flare is subject to the provisions of Colorado Regulation No. 7, Part D,
Section 11.8; therefore, the requirements contained in the current version
of the O&M Plan (approved June 25, 2014) were not incorporated into the
operating permit.
Additional Requirements:
• A requirement for the permittee to submit for a modification to the
operating permit with sixty days if any site -specific HAP emission factors
exceed those listed in the operating permit.
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• This flare controls emissions units subject to the provisions of Colorado
Regulation No. 7, Part D, Section II when utilized as a control device for
the amine and dehydration units still vents; therefore, this flare is subject
to the air pollution control devices requirements of Section II, which were
incorporated into the operating permit.
2. Emission Factors
Emissions factors for FLR-1A are from AP -42, Section 13.5, Table 13.5-2. The
facility submitted an APEN on August 9, 2016 requesting to update the emission
limits of the flare and included the updated AP -42 CO emissions factor (0.31
lb/MMBtu). The NOx emissions are based on the emission factor represented in
AP -42, Section 13.5, Table 13.5-1 (0.068 lb/MMBtu), a reported natural gas heat
value of 1,145 Btu/scf (as reported on the APEN received August 9, 2016), and a
requested annual fuel permit limit of 193.1 MMscf/yr.
3. Monitoring Requirements
In addition to the monitoring required to calculate monthly emissions, the
permittee must monitor compliance with the opacity requirements by completing
a daily visible emission observation for the presence or absence of emissions
and subsequent EPA Method 9 observations if emissions are observed.
Additionally, the permittee is required to meet the requirements of Colorado
Regulation No. 7, Section II when process streams from the facility's dehydration
units are routed to the flare.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Requirement to submit a Notice of Startup fifteen days after
commencement of operation. Per the Division's 2017 inspection report this
flare commenced operation July 1, 2015 and the NOS was received by the
Division on July 16, 2015. This issue is being resolved through an
administrative penalty via Case #2016-236; therefore, no compliance plan
is necessary.
F. 014 — Natural Gas -Fired Hot Oil Heater (13WE3004) — Redtail Gas Plant
1. Applicable Requirements
One (1) Zeeco hot oil heater, Model: GLSF14, Serial Number: J131132, with a
total design heat input rate of 43.64 MMBtu/hr. This heater is fueled by natural
gas. This heater is equipped with low NOx burners. According to the Notice of
Startup (received September 18, 2015), this hot oil heater commenced operation
on September 2, 2015.
123/9AD0 Page 28 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Colorado Construction Permit 131 WE3004 was issued for the heater on May 4,
2014 as an initial approval permit. A final approval permit was issued for
Colorado Construction Permit 13WE3004 on December 14, 2017. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit
The appropriate applicable requirements from Colorado Construction Permit
13WE3004 for the hot oil heater are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation 3, Part B, Section III.G.5).
This is a construction permit only condition; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
PMio
PM2.5
HTR-1A
014
12.7
3.7
7.9
2.5
2.5
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.
Compliance with the annual limits shall be determined by recording the
facility's annual criteria pollutant emissions, (including all HAPs above the
de-minimis reporting level) from each emission unit, on a rolling twelve
(12) month total. By the end of each month a new twelve-month total shall
be calculated based on the previous twelve months' data. The permit
holder shall calculate emissions each month and keep a compliance
record on site or at a local field office with site responsibility, for Division
review. This rolling twelve-month total shall apply to all permitted emission
units, requiring an APEN, at this facility.
This condition was modified upon incorporation into the Operating Permit
to incorporate the facility -wide HAP limits of Colorado Construction Permit
13WE3003, 13WE3005, 13WE3006, 13WE3007, 14WE0891, 14WE0892,
and 14WE0893 (facility -wide total HAPs < 9.0 tons/year and facility -wide
individual HAP limits < 24.0 tons/year).
123/9AD0 Page 29 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• This source shall be limited to the following maximum consumption,
processing and/or operational rates as listed below. Monthly records of the
actual process rate shall be maintained by the applicant and made
available to the Division for inspection upon request. (Reference:
Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment ID
AIRS Point
Process Parameter
Annual
Limit
HTR-1 A
014
Combustion of
natural gas as a fuel
375
MMscf/yr
The owner or operator shall calculate monthly process rates based on the
calendar month.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the operating permit.
• 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.1.c shall have no visible emissions. (Reference:
Regulation No. 1, Section II.A.1. & 4.)
This condition was modified upon incorporation into the operating permit
to remove the reference to the Colorado Regulation No. 7 no visible
emissions requirements. This heater is not an emission control device
under the provisions of Reg 7, Part D, Section II.B (formerly Section
XVIl.B.1.c); therefore the requirements for air pollution control devices
under that section are not applicable. Additionally, Colorado Regulation
No. 7, Part D, Section II (formerly Section XII. C.1. d) do not apply as this
facility is not located in the non -attainment area.
• 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 including, but not limited to, the following:
123/9AD0 Page 30 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
o The owner or operator of the facility shall record and
maintain records of the amount of fuel combusted during
each month (40 CFR Part 60.48c(g)).
o Monthly records of fuel combusted required under the
previous condition shall be maintained by the owner or
operator of the facility for a period of two years following the
date of such record (40 CFR Part 60.48c(i)).
The appropriate provisions of 40 CFR Part 60 Subpart Dc were
incorporated including, but not limited to: reporting and recordkeeping
requirements.
In addition, the requirements of Regulation No. 6, Part A, Subpart A,
General Provisions, apply.
The appropriate general provisions of 40 CFR Part 60 were incorporated
into the operating permit.
• Particulate matter emissions shall be limited as per: Regulation 6, Part B,
II.C.2.
The Colorado Regulation No. 6, Part B particulate matter emission limit for
this hot oil heater are the same as the Colorado Regulation No. 1
emission limitations. These requirements have been streamlined out in
favor of the Colorado Regulation No. 1 requirements.
Additionally, this heater would be subject to the Colorado Regulation No.
6, Part B, Section II. C.3 20% opacity standard, which was not
incorporated into Colorado Construction Permit 13WE3004. The Colorado
Regulation No. 1 20% opacity requirement applies at all times, except for
certain specific operating conditions under which the Reg 1 30% opacity
requirement applies. Regulation No. 6, Part B, Section l.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 Reg
1 20% and 30% opacity requirements are therefore more stringent than
the Reg 6, Part B opacity requirement during periods of startup, shutdown,
and malfunction. While the Reg 6, Part B 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. However, the Division considers that for the turbine the only
specific activity under which the 30% opacity standard would apply is
startup. Therefore, since the Regulation 1 opacity standards are more
stringent than the Reg 6, Part B requirements the Reg 6, Part B
requirements have been streamlined out of the operating permit.
• See Subpart DDDDD—National Emission Standards for Hazardous Air
Pollutants for Major Sources: Industrial, Commercial, and Institutional
Boilers and Process Heaters 40 C.F.R Part 63, Subpart DDDDD. Process
123/9AD0 Page 31 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
heaters not already associated with glycol dehydrators regulated by 40
CFR § 63 Subpart HH are subject to Subpart DDDDD. Applicable
requirements of Subpart DDDDD to HTR-1A are limited to work practice
standards (i.e., annual tune-up), annual reporting, and maintenance of
compliance records. As point 014 (HTR-1A) burns only natural gas, no
fuel analysis is required
This condition was not incorporated into the operating permit. As the
EPA's "once -in always -in" policy with withdrawn on January 25, 2018 and
this permit include synthetic minor limits, the Redtail Gas Plant is
considered an area source of HAP emissions and is no longer subject to
the Subpart DDDDD requirements.
Additional Requirements:
In addition to the above conditions of Colorado Construction Permit 13WE3004,
the following regulations are also applicable to this unit.
• Colorado Regulation No. 1, Section VI.B.5 for sulfur dioxide emissions
from new sources to either limit emissions to not more than two tons per
day of SO2 or utilize BACT.
2. Emission Factors
Emissions factors for PMio, PM2.5, NOx, CO, and VOC are from the
manufacturer. SO2 and HAP emissions are calculated using the factors
represented in AP -42, Chapter 1, Tables 1.4-2 and 1.4-3.
3. Monitoring Requirements
In addition to the monitoring required to calculate monthly emissions, the
operating permit requires the permittee meet the reporting and recordkeeping
requirements of 40 CFR Part 60 Subparts A and Dc.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the facility -wide methanol limit for the rolling twelve
month period ending December, 2015 (see Section IV.P.2 of this Technical
Review Document for discussion). Additionally, the inspection report indicates
that the permittee was in compliance with the applicable requirements of the
version of Construction Permit 13WE3004 that was current at the time of the
inspection and all applicable state and federal regulatory requirements to this
emission unit.
G. 015 — 35 MMscfd EG Dehydration Unit (13WE3005) — Redtail Gas Plant
1. Applicable Requirements
123/9AD0 Page 32 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
One (1) Ethylene Glycol (EG), natural gas dehydration unit (Alco, FAB38-20B,
serial number: 2012-8390-12) with a design capacity of 28.5 MMscf per day. This
emissions unit is equipped with two (2) Bear CX-5H Duplex electric -glycol pumps
with a design capacity of 6 gal/min. This unit is equipped with a flash tank,
reboiler and still vent. Emissions from the flash tank are recycled to the plant inlet
or plant flare (AIRS 013) as backup. Emissions from the still vent are controlled
by an enclosed combustor or plant flare (AIRS 013) as backup. According to the
Notice of Startup (received October 23, 2014), this dehydration unit commenced
operation on April 6, 2014.
Colorado Construction Permit 13WE3005 was issued for this dehydration unit on
October 8, 2014 as an initial approval permit. A final approval permit was issued
for Colorado Construction Permit 13WE3005 on December 14, 2017. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit
The appropriate applicable requirements from Colorado Construction Permit
13WE3005 for the EG Dehydration unit are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation Number 3, Part B, Section III.G.5.)
This is a construction permit only condition; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
DEHY-1
015
--
1.4
--
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
The facility -wide emissions limitation for hazardous air pollutants shall
apply to all permitted emission units at this facility.
123/9AD0 Page 33 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Compliance with the annual limits, for criteria and hazardous air pollutants,
shall be determined on a rolling twelve (12) month total. By the end of
each month a new twelve month total is calculated based on the previous
twelve months' data. The permit holder shall calculate actual emissions
each month and keep a compliance record on site or at a local field office
with site responsibility for Division review.
This condition was incorporated into the operating permit.
• The owner or operator shall track emissions from all insignificant activities
at the facility on an annual basis to demonstrate compliance with the
facility potential emission limitations as indicated below. An inventory of
each insignificant activity and associated emission calculations shall be
made available to the Division for inspection upon request. For the
purposes of this condition, insignificant activities shall be defined as any
activity or equipment, which emits any amount but does not require an Air
Pollution Emission Notice (APEN) or is permit exempt. (Reference:
Regulation 3, Part C. II.E.)
Total potential emissions from the facility, including all permitted emissions
and potential to emit from all insignificant activities, shall be less than:
o 250 tons per year of VOC; and
o 10 tons per year of any individual hazardous air pollutant (HAP);
and
o 25 tons per year of total hazardous air pollutants (HAP).
The standard operating permit insignificant activity tracking language was
incorporated into the operating permit. The insignificant activity tracking for
VOC emissions was removed since total facility wide VOC emissions are
not greater than 225 tpy.
• Compliance with the emission limits in this permit shall be demonstrated
by running the VMG Sim, or another Division -approved model on a
monthly basis using the most recent extended wet gas analysis and
recorded operational values, including: gas throughput, lean glycol
recirculation rate, chiller temperature and pressure, condenser
temperature, flash tank temperature and pressure, wet gas inlet
temperature, and wet gas inlet pressure. Recorded operational values,
except for gas throughput, shall be averaged on a monthly basis for input
into the model and be provided to the Division upon request.
This condition was incorporated into the operating permit.
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
123/9AD0 Page 34 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
DEHY-1
(Still Vent)
015
Primary: Enclosed
Combustor
Secondary: Point 013
(FLR-1A)
VOC, HAPs
This condition was incorporated into the operating permit.
• The owner or operator shall operate and maintain the emission points in
the table below as a closed loop system and shall recycle 100% of
emissions as described in the table below. (Regulation Number 3, Part B,
Section III.E.)
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
DEHY-1
(Flash Tank)
015
Primary: recycled to
plant's inlet slug catcher
Secondary: Point 013
(FLR-1A)
VOC, HAPs
This condition was incorporated into the operating permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the actual processing rate shall be
maintained by the owner or operator and made available to the Division
for inspection upon request. (Reference: Regulation 3, Part B, II.A.4)
Facility
Equipment ID
AIRS Point
Process Parameter
Annual Limit
DEHY-1
015
Natural gas throughput
12,775
MMscf/yr
The owner or operator shall monitor monthly process rate based on the
calendar month. The volume of gas processed shall be measured by gas
meter or by assuming the maximum design rate of the dehydrator unit of
35.0 MMscf/d.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the operating permit.
123/9AD0 Page 35 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• This unit shall be limited to the maximum lean glycol circulation rate of 6.0
gallons per minute. The lean glycol recirculation rate shall be recorded
daily in a log maintained on site and made available to the Division for
inspection upon request. Glycol recirculation rate shall be monitored by
one of the following methods: assuming maximum design pump rate,
using glycol flow meter(s), or recording strokes per minute and converting
to circulation rate. This maximum glycol circulation rate shall not preclude
compliance with the optimal glycol circulation rate, if applicable, (Lopt)
provisions under MACT HH, whichever is more stringent. (Reference:
Regulation Number 3, Part B, II.A.4)
This condition was modified upon incorporation into the Operating Permit
to remove the reference to the Lopt MACT HH requirement. This facility
has synthetic minor HAP limits and the EPA "once -in always -in" policy was
withdrawn January 25, 2018. The provisions of 40 CFR Part 63 Subpart
HH only apply to TEG dehydration units at area sources; there are no
TEG dehys located onsite. Therefore, this provision is not applicable.
• On a weekly basis, the owner or operator shall monitor and record
operational values including: chiller temperature and pressure, flash tank
temperature and pressure, wet gas inlet temperature and pressure. These
records shall be maintained for a period of five years.
This condition was incorporated into the operating permit.
• No owner or operator of a smokeless flare or other flare for the
combustion of waste gases shall allow or cause emissions into the
atmosphere of any air pollutant which is in excess of 30% opacity for a
period or periods aggregating more than six minutes in any sixty
consecutive minutes. (Regulation Number 1, Section II.A.5.)
This condition was incorporated into the operating permit.
• The combustion device covered by this permit is subject to Regulation
Number 7, Section XVII.B.2 General Provisions (State only enforceable). If
a flare or other combustion device is used to control emissions of volatile
organic compounds to comply with Section XVII, it shall be enclosed; have
no visible emissions during normal operations, as defined under
Regulation Number 7, XVII.A.16; and be designed so that an observer
can, by means of visual observation from the outside of the enclosed flare
or combustion device, or by other convenient means approved by the
Division, determine whether it is operating properly. The combustion
device must be equipped with an operational auto -igniter according to the
following schedule:
o All combustion devices installed on or after May 1, 2014, must be
equipped with an operational auto -igniter upon installation of the
combustion device;
123/9AD0 Page 36 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
o 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.
The applicable Colorado Regulation No.7, Part D, Section 11.8 (formerly
Section XVII. B) requirements applicable to air pollution control equipment
were incorporated into the operating permit.
• The glycol dehydration unit covered by this permit is subject to the
emission control requirements in Regulation Number 7, Section XVII.D.3.
Beginning May 1, 2015, still vents and vents from any flash separator or
flash tank on a glycol natural gas dehydrator located at an oil and gas
exploration and production operation, natural gas compressor station, or
gas -processing plant subject to control requirements pursuant to Section
XVII.D.4., shall reduce uncontrolled actual emissions of hydrocarbons by
at least 95% on a rolling twelve-month basis through the use of a
condenser and/or air pollution control equipment.
The applicable Colorado Regulation No. 7, Part D, Section II. D (formerly
Section XVII.D) requirements were incorporated into the operating permit.
• The glycol dehydration unit at this facility is subject to National Emissions
Standards for Hazardous Air Pollutants for Source Categories from Oil
and Natural Gas Production Facilities, Subpart HH. This facility shall be
subject to applicable major source provisions of this regulation, as stated
in 40 C.F.R Part 63, Subpart A and HH. (Regulation Number 8, Part E,
Subpart A and HH)
Requirements from 40 CFR Part 63 Subpart HH were not incorporated
into the operating permit. The Redtail Gas Plant is an area source of HAP
emissions (see discussion under 40 CFR Part 63 Subpart HH in Section Ill
of this document for further discussion); only TEG dehydration units are
the only affected sources at area sources. There are no TEG dehydration
units located at the Redtail Gas Plant.
• The owner or operator shall follow the most recent operating and
maintenance (O&M) plan and record keeping format approved by the
Division, in order to demonstrate compliance on an ongoing basis with the
requirements of this permit. Revisions to the O&M plan are subject to
Division approval prior to implementation. (Regulation Number 3, Part B,
Section III.G.7.)
The applicable requirements from the current O&M Plan (March 29, 2017)
include: daily pilot light and auto -igniter monitoring and visible emissions
observations. These requirements have been streamlined out of the
operating permit in favor of the Colorado Regulation No. 7, Part D, Section
11.8 (formerly Section XVII.B) air pollution control equipment, which
includes daily visual inspections for emissions, auto -igniter and valves for
123/9AD0 Page 37 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
the piping of gas to the pilot light functionality, pilot light, and inspection of
valves and piping from emission unit to control device.
• The owner or operator shall complete an extended wet gas analysis prior
to the inlet of the dehydration unit on an annual basis per calendar year.
Results of the wet gas analysis shall be used to calculate emissions of
criteria pollutants and hazardous air pollutants per this permit and be
provided to the Division upon request.
This condition was incorporated into the operating permit.
2. Emission Factors
Uncontrolled emission factors are based on VMG Simulation Model. The
controlled VOC and HAP emission factors for this point are based on the thermal
oxidizer or facility process flare (during thermal oxidizer downtime) control
efficiency of 95%
3. Monitoring Requirements
In addition to the monitoring required to calculate monthly emissions, the
operating permit requires an annual extended gas analysis, weekly monitoring of
the actual wet gas inlet temperature and pressure, weekly monitoring of the
actual cold separator pressure and temperature, weekly monitoring of the actual
flash tank temperature and pressure, daily monitoring of the actual lean glycol
pumping rate, and completion of the monitoring required by Colorado Regulation
No. 7, Part D, Sections II.B and II.D.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Annual permitted VOC limit of 1.5 tons per year. Per the 2017 inspection
report the permittee exceeded this annual limit for the rolling twelve month
period December, 2015 through April, 2016. This issue is being resolved
through the requirement of Case #2016-236 for the permittee to comply
with the Act, the Regulations, and all relevant permit conditions regarding
the regulation and control of air pollutant applicable to the facility;
therefore, no compliance plan is necessary.
• Requirements to operate and maintain a thermal oxidizer capable of
reducing emissions to less than or equal to the limits established in the
permit. In the June 11, 2015 voluntary self -disclosure, the permittee
reported that this dehydration unit operated without a thermal oxidizer
from startup (April 6, 2014) through June 4, 2015 when a thermal oxidizer
was installed and commenced operation. Additionally, due to operational
issues with the thermal oxidizer, it was replaced with an enclosed
123/9AD0 Page 38 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
combustor on February 10, 2016. A modified construction permit reflecting
the change in control equipment was issued on May 16, 2016. The
inspection report indicates that the permittee is only considered out of
compliance for operating the dehydration unit without a thermal oxidizer
from October 8, 2014 through Jun 4, 2015. The permittee is currently
permitted for and operating this unit with an enclosed combustor and is in
compliance with these requirements per the Division's 2017 inspection
report; therefore, no compliance plan is necessary.
• Requirement to demonstrate compliance with the no visible emissions
requirement using EPA Method 22 to determine the presence of visible
emissions within 180 days after issuance of this permit. The permittee
conducted the required EPA Method 22 evaluation on July 21, 2015,
which was more than 180 days after issuance of this construction permit.
It should be noted that this version of the construction permit was issued
on October 8, 2014 and the thermal oxidizer did not commence operation
until June 4, 2015. This thermal oxidizer was replaced with an enclosed
combustor on February 10, 2016 and a modified construction permit was
issued on May 16, 2016, which requires an EPA Method 22 evaluation of
the combustor be completed within 180 days after permit issuance. Per
the 2017 inspection report this dehydration unit has yet to commence
operation under the new configuration (controlled by the enclosed
combustor); the self -certification submittal (requiring initial testing for
visible emissions) is required within 180 days of operation
commencement. This unit was issued a revised construction permit
requiring a Method 22 be conducted; therefore, no compliance plan is
necessary.
H. 016 — 70 Mscfd EG Dehydration Unit (13WE3006) — Redtail Gas Plant
1. Applicable Requirements
One (1) Ethylene Glycol (EG), natural gas dehydration unit (Alco, serial number:
2013-8482-12) with a design capacity of 70 MMscf per day. This emissions unit
is equipped with two (2) Bear CX-5H Duplex electric -glycol pumps with a design
capacity of 18 gal/min. This unit is equipped with a flash tank and still vent.
Emissions from the flash tank are routed to common fuel header for the facility.
Emissions from the still vent are sent to an enclosed combustor. According to the
Notice of Startup (received October 2, 2015), this dehydration unit commenced
operation on September 17, 2015.
Colorado Construction Permit 13WE3006 was issued for this dehydration unit on
October 8, 2014 as an initial approval permit. A final approval permit was issued
for Colorado Construction Permit 13WE3006 on December 14, 2017. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit
The appropriate applicable requirements from Colorado Construction Permit
13WE3006 for the EG Dehydration unit are as follows:
123/9AD0 Page 39 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation Number 3, Part B, Section III.G.5.)
This is a construction permit only condition; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
DEHY-2
016
--
1.0
--
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
The facility -wide emissions limitation for hazardous air pollutants shall
apply to all permitted emission units at this facility
Compliance with the annual limits, for criteria and hazardous air pollutants,
shall be determined using VMG Sim or other Division -approved model on
a rolling twelve (12) month total. By the end of each month a new twelve
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate actual emissions each month and keep a
compliance record on site or at a local field office with site responsibility
for Division review. For purposes of demonstrating compliance with annual
emissions limits during the first 12 months of this permit, permit holder
shall calculate emissions for periods preceding issuance of this permit
using VMG Sim.
This condition was incorporated into the operating permit.
• The owner or operator shall track emissions from all insignificant activities
at the facility on an annual basis to demonstrate compliance with the
facility potential emission limitations as indicated below. An inventory of
each insignificant activity and associated emission calculations shall be
made available to the Division for inspection upon request. For the
123/9AD0 Page 40 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
purposes of this condition, insignificant activities shall be defined as any
activity or equipment, which emits any amount but does not require an Air
Pollution Emission Notice (APEN) or is permit exempt. (Reference:
Regulation 3, Part C. II.E.)
Total potential emissions from the facility, including all permitted emissions
and potential to emit from all insignificant activities, shall be less than:
o 250 tons per year of VOC; and
o 10 tons per year of any individual hazardous air pollutant (HAP);
and
o 25 tons per year of total hazardous air pollutants (HAP)
The standard operating permit insignificant activity tracking language was
incorporated into the operating permit. The insignificant activity tracking for
VOC emissions was removed since total facility wide VOC emissions are
not greater than 225 tpy.
• Compliance with the emission limits in this permit shall be demonstrated
by running the VMG Sim, or other Division -approved model, on a monthly
basis using the most recent extended wet gas analysis and recorded
operational values, including: gas throughput, lean glycol recirculation
rate, chiller temperature and pressure, condenser temperature, flash tank
temperature and pressure, wet gas inlet temperature, and wet gas inlet
pressure. Recorded operational values, except for gas throughput, shall
be averaged on a monthly basis for input into the model and be provided
to the Division upon request
This condition was incorporated into the operating permit.
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
y
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
DEHY-2
(Still Vent)
016
Primary: Enclosed
Combustor
Secondary: Point 013
(FLR-1A)
VOC, HAPs
This condition was incorporated into the operating permit.
• The owner or operator shall operate and maintain the emission points in
the table below as a closed loop system and shall recycle 100% of
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Technical Review Document — Initial Operating Permit
emissions as described in the table below. (Regulation Number 3, Part B,
Section III.E.)
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
DEHY-2
(Flash Tank)
016
Primary: recycled to
plant's inlet slug catcher
Secondary: Point 013
(FLR-1A)
VOC, HAPs
This condition was incorporated into the operating permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the actual processing rate shall be
maintained by the owner or operator and made available to the Division
for inspection upon request. (Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment
ID
AIRS
Point
Process Parameter
Annual
Limit
DEHY-2
016
Natural gas
throughput
25,550
MMscf/yr
The owner or operator shall monitor monthly process rates based on the
calendar month. The volume of gas processed shall be measured by gas
meter or by assuming the maximum design rate of the dehydrator unit of
70.0 MMscf/d.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the operating permit.
• This unit shall be limited to the maximum lean glycol circulation rate of 9.0
gallons per minute. The lean glycol recirculation rate shall be recorded
daily in a log maintained on site and made available to the Division for
inspection upon request. Glycol recirculation rate shall be monitored by
one of the following methods: assuming maximum design pump rate,
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Technical Review Document — Initial Operating Permit
using glycol flow meter(s), or recording strokes per minute and converting
to circulation rate. This maximum glycol circulation rate does not preclude
compliance with the optimal glycol circulation rate (Lopt) provisions under
MACT HH, whichever is more stringent. (Reference: Regulation Number
3, Part B, II.A.4)
This condition was modified upon incorporation into the Operating Permit
to remove the reference to the Lopt MACT HH requirement. This facility
has synthetic minor HAP limits and the EPA "once -in always -in" policy was
withdrawn January 25, 2018. The provisions of 40 CFR Part 63 Subpart
HH only apply to TEG dehydration units at area sources; there are no
TEG dehys located onsite. Therefore, this provision is not applicable.
• On a weekly basis, the owner or operator shall monitor and record
operational values including: chiller temperature and pressure, flash tank
temperature and pressure, wet gas inlet temperature and pressure. These
records shall be maintained for a period of five years.
This condition was incorporated into the operating permit.
• No owner or operator of a smokeless flare or other flare for the
combustion of waste gases shall allow or cause emissions into the
atmosphere of any air pollutant which is in excess of 30% opacity for a
period or periods aggregating more than six minutes in any sixty
consecutive minutes. (Regulation Number 1, Section II.A.5.)
This condition was incorporated into the operating permit.
• The combustion device covered by this permit is subject to Regulation
Number 7, Section XVII.B.2 General Provisions (State only enforceable). If
a flare or other combustion device is used to control emissions of volatile
organic compounds to comply with Section XVII, it shall be enclosed; have
no visible emissions during normal operations, as defined under
Regulation Number 7, XVII.A.16; and be designed so that an observer
can, by means of visual observation from the outside of the enclosed flare
or combustion device, or by other convenient means approved by the
Division, determine whether it is operating properly. The combustion
device must be equipped with an operational auto -igniter according to the
following schedule:
o All combustion devices installed on or after May 1, 2014, must be
equipped with an operational auto -igniter upon installation of the
combustion device;
o 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.
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Technical Review Document — Initial Operating Permit
The applicable Colorado Regulation No.7, Part D, Section II.B (formerly
Section XVII. B) requirements applicable to air pollution control equipment
were incorporated into the operating permit.
• The glycol dehydration unit covered by this permit is subject to the
emission control requirements in Regulation Number 7, Section XVII.D.3.
Beginning May 1, 2015, still vents and vents from any flash separator or
flash tank on a glycol natural gas dehydrator located at an oil and gas
exploration and production operation, natural gas compressor station, or
gas -processing plant subject to control requirements pursuant to Section
XVII.D.4., shall reduce uncontrolled actual emissions of hydrocarbons by
at least 95% on a rolling twelve-month basis through the use of a
condenser and/or air pollution control equipment.
The applicable Colorado Regulation No. 7, Part D, Section II.D (formerly
Section XVII.D) requirements were incorporated into the operating permit.
• The glycol dehydration unit at this facility is subject to National Emissions
Standards for Hazardous Air Pollutants for Source Categories from Oil
and Natural Gas Production Facilities, Subpart HH. This facility shall be
subject to applicable major source provisions of this regulation, as stated
in 40 C.F.R Part 63, Subpart A and HH. (Regulation Number 8, Part E,
Subpart A and HH)
Requirements from 40 CFR Part 63 Subpart HH were not incorporated
into the operating permit. The Redtail Gas Plant is an area source of HAP
emissions (see discussion under 40 CFR Part 63 Subpart HH in Section III
of this document for further discussion); only TEG dehydration units are
the only affected sources at area sources. There are no TEG dehydration
units located at the Redtail Gas Plant.
• The owner or operator shall follow the most recent operating and
maintenance (O&M) plan and record keeping format approved by the
Division, in order to demonstrate compliance on an ongoing basis with the
requirements of this permit. Revisions to the O&M plan are subject to
Division approval prior to implementation. (Regulation Number 3, Part B,
Section III.G.7.)
The applicable requirements from the current O&M Plan (March 29, 2017)
include: daily pilot light and auto -igniter monitoring and visible emissions
observations. These requirements have been streamlined out of the
operating permit in favor of the Colorado Regulation No. 7, Part D, Section
II. B (formerly Section XVII. B) air pollution control equipment, which
includes daily visual inspections for emissions, auto -igniter and valves for
the piping of gas to the pilot light functionality, pilot light, and inspection of
valves and piping from emission unit to control device.
• The owner or operator shall complete an extended wet gas analysis prior
to the inlet of the dehydration unit on an annual basis per calendar year.
Results of the wet gas analysis shall be used to calculate emissions of
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Technical Review Document — Initial Operating Permit
criteria pollutants and hazardous air pollutants per this permit and be
provided to the Division upon request.
This condition was incorporated into the operating permit.
2. Emission Factors
Uncontrolled emission factors are based on VMG Simulation Model. The
controlled VOC and HAP emission factors for this point are based on the thermal
oxidizer or facility process flare (during thermal oxidizer downtime) control
efficiency of 95%
3. Monitoring Requirements
In addition to the monitoring required to calculate monthly emissions, the
operating permit requires an annual extended gas analysis, weekly monitoring of
the actual wet gas inlet temperature and pressure, weekly monitoring of the
actual cold separator pressure and temperature, weekly monitoring of the actual
flash tank temperature and pressure, daily monitoring of the actual lean glycol
pumping rate, and completion of the monitoring required by Colorado Regulation
No. 7, Part D, Sections II.B and II.D.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Requirement to self -certify within 180 days after commencement of
operation. This dehydration unit commenced operation on September 17,
2015; an incomplete (missing required initial compliance testing) permit
self -certification was submitted on Mary 16, 2016. The 2017 inspection
report indicates that the permittee did not demonstrate compliance for this
dehydration unit within 180 days after commencement of operation as a
result of failing to complete the initial compliance test for the unit. This
issue was addressed via Case #2016-236; a final approval construction
permit for this unit was subsequently issued on December 14, 2017;
therefore, no compliance plan is necessary.
• Requirement to complete all initial compliance testing and sampling and
submit the results to the Division as part of the self -certification process.
See above bullet.
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Requirement for 100% of emission that result from the flash tank
associated with this dehydrator to be recycled to the common fuel header.
During the initial records response associated with the Division's 2017
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Technical Review Document — Initial Operating Permit
inspection report, the permittee stated that, "flash tank emission have only
one flow route during normal operations: to the inlet slug catcher where
they are re -introduced to the process. During upset or malfunction events,
a process safety pressure relief device can route the dehydrator unit flash
emissions to the main plant flare FLR-1A. An upset or malfunction
requiring the combustion of the dehydration unit flash emissions has not
yet occurred, so there are no periods of combustion emissions recorded."
Furthermore, during communications involved with the permittee
associated with the 2017 inspection report, the permittee stated that, "we
used more template language stating that the flash emissions would be
routed to the fuel header, which is the same as saying we route them to
process. We have been clear in all discussions with the Division, including
in the self -certification for Dehy-2 that the flash tank are routed to the inlet
slug catcher. Since the inlet slug catcher and common fuel header are
both `routed to process' we did not end up changing the language, but
have tried to be clear that when we say that we mean routed to the inlet
slug catcher." The inspection report goes on to state that the modified
permit for this unit, issued May 16, 2016 has the same requirement and
the permit condition does not specify that the flash emissions shall be
"routed to process" nor provide a definition about what that means, the
permittee is not in compliance with the condition. The permit should
accurately reflect or specify the actual control configuration for the flash
tank emissions.
A final approval construction permit for this unit was subsequently issued
on December 14, 2017, which reflects that the flash tank emissions are
routed to the plant's inlet slug catcher as a primary means of control. This
requirement was incorporated into the operating permit; therefore, no
compliance plan is necessary.
• Requirement to follow the most recent operation and maintenance plan
and recordkeeping format approved by the Division, specifically: flash tank
emission will be recycled to the plant fuel header or the reboiler burner.
Flash tank emissions will be routed only to the plant fuel header once
Train 2 is operational. In the event that a valve is inadvertently shut not
allowing the flash gas to be burned, the safety relief valve on the flash
tank will open, sending the stream to the plant flare. See above bullet; no
compliance plan is necessary.
• Requirement to demonstrate compliance with the opacity requirement
using EPA Method 22 observations and requirement to measure the
emissions rate of VOCs within 180 days of operation commencement. The
permittee failed to provide records of an EPA Method 22 evaluation on the
thermal oxidizer controlling this dehydrator with the required self -
certification submitted to the Division. Note, this dehydrator and thermal
oxidizer commenced operation on September 17, 2015 and the thermal
oxidizer was replaced with an enclosed combustor on January 29, 2016,
which is less than 180 days after commencement of operation. Because
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Technical Review Document — Initial Operating Permit
there was no change in the process or emission limits for this dehydrator
with the installation of the new control equipment, the permittee should
have conducted an EPA Method 22 evaluation on the enclosed combustor
within 180 days after the dehydrator's commencement of operation (By
March 17, 2016). The modified permit for this dehydration unit (issued on
May 16, 2016) has the same Method 22 requirement within 180 days of
operation commencement.
The requirements to conduct an EPA Method 22 and complete
compliance testing was completed on August 16, 2016 (results sent to the
Division on September 6, 2016) and a final approval construction permit
for this unit was issued on December 14, 2017; therefore, no compliance
plan necessary.
I. 017 — MDEA Amine Unit (13WE3007) — Redtail Gas Plant
1. Applicable Requirements
Methyldiethanolamine (MDEA) natural gas sweetening system for acid gas
removal with a design capacity of 35 MMSCF per day (make, model, serial
number: TBD). This emissions unit is equipped with two (2) make, model: TBD,
electric OR gas -injection amine recirculation pumps with a total design capacity
of 201 gallons per minute. This system includes a natural gas/amine contactor, a
flash tank, and an oil -heated amine regeneration reboiler. The oil heater for the
reboiler is covered under a separate point (AIRS Point 014). Flash tank
emissions are re-routed to a common fuel header that feeds the entire facility.
The still vent stream is controlled by a thermal oxidizer. According to the Notice
of Startup (received November 3, 2015), this amine unit commenced operation
on October 23, 2015.
Colorado Construction Permit 13WE3007 was issued for this amine unit on
October 8, 2014 as an initial approval permit. A final approval permit was issued
for Colorado Construction Permit 13WE3006 on December 14, 2017. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit.
The appropriate applicable requirements from Colorado Construction Permit
13WE3007 for the DEA amine unit are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation 3, Part B, Section III.G.5).
This is a construction permit only condition; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, II.A.4)
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Annual limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
SO2
NOx
VOC
CO
AMINE -1
001
25.3
0.5
10.0
2.1
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
Compliance with the annual limits shall be determined by recording the
facility's annual criteria pollutant emissions, (including all HAPs above the
de-minimis reporting level) from each emission unit, on a rolling twelve
(12) month total. By the end of each month a new twelve-month total shall
be calculated based on the previous twelve months' data. The permit
holder shall calculate emissions each month and keep a compliance
record on site or at a local field office with site responsibility, for Division
review. This rolling twelve-month total shall apply to all permitted emission
units, requiring an APEN, at this facility.
This condition was incorporated into the operating permit.
• 100% of emissions that result from the flash tank associated with this
amine unit shall be recycled to the plant inlet. Emissions from the flash
tank can be routed as a backup control to the plant flare (point 013: FLR-
1 A).
This condition was incorporated into the operating permit.
• This concentration of Ucarsol AP -814 solvent in the lean amine stream
shall not exceed 55% by weight on a monthly average basis. The operator
shall measure and record the solvent concentration in the lean amine
stream each week and calculate and record a calendar monthly average
solvent concentration to demonstrate compliance with this condition.
This condition was incorporated into the Operating Permit.
• The emission points in the table below shall be operator 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 (Reference:
Regulation No. 3, Part B, Section III.E).
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Facility
Equipment ID
AIRS
Point
Control Device
Pollutants
Controlled
AMINE -1
017
Primary: Thermal
Oxidizer
Secondary: Point 013
(FLR-1 A)
VOC and HAPs
This condition was incorporated into the Operating Permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the actual natural gas processing rates
shall be maintained by the owner or operator and made available to the
Division for inspection upon request (Reference: Regulation 3, Part B,
II.A.4).
Process/Consumption Limits:
Facility
Equipment ID
AIRS
Point
Process
Parameter
Annual Limit
AMINE -1
017
Natural gas
throughput
16,425
MMscf/yr
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the operating permit.
• This unit shall be limited to the maximum lean amine recirculation pump
rate of 201 gallons per minute. The lean amine recirculation rate shall be
recorded weekly in a log maintained on site and made available to the
Division for inspection upon request. A pump stroke correlation may be
used to demonstrate compliance with this condition. (Reference:
Regulation No. 3, Part B, II.A.4).
This condition was incorporated into the Operating Permit.
• 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.1.c shall have no visible emissions. (Reference:
Regulation No. 1, Section II.A.1. & 4.)
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Technical Review Document — Initial Operating Permit
This condition is applicable to the thermal oxidizer controlling the
emissions generated by the still vent and was incorporated into the
operating permit.
• 40 CFR Part 60 Subpart OOOO requirements
The applicable requirements from 40 CFR Part 60 Subpart OOOO have
been incorporated into the Operating Permit, including, but not limited to:
compliance dates, additional recordkeeping and reporting requirements for
sweetening units located at natural gas processing plants, and general
provisions.
• 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. (Reference: Regulation No. 3,
Part B, Section III.G.7.)
The applicable requirements of current O&M Plan (submitted April 28,
2016) were incorporated into the operating, including, but not limited to:
daily monitoring of the lean amine circulation rate utilizing amine flow
meter(s), weekly monitoring of the inlet gas temperature and pressure,
monthly monitoring of the volume of gas processed, and daily thermal
oxidizer combustion temperature monitoring.
• The operator shall sample the inlet gas to the plant on an annual basis per
calendar year to determine the concentration of hydrogen sulfide (H2S) in
the gas stream. The sample results shall be monitored to demonstrate that
this amine unit qualifies for the exemption from the Standards of
Performance for Crude Oil and Natural Gas Production, Transmission and
Distribution (§60.5365(g)(3)).
This condition was incorporated into the Operating Permit.
Additional Requirements
In addition to the conditions from Colorado Construction 13WE3007 outlined
above, the following requirements applicable to this amine unit were incorporated
into the operating permit:
• A requirement to conduct an annual extended gas analysis for input into
the process model and a speciated sulfur analysis for the purposes of
monitoring compliance with the 40 CFR Part 60 Subpart OOOO
exemption.
• A requirement for the permittee to monitor and record the hours of still
vent operation for the purposes of calculating monthly emissions from the
amine unit and thermal oxidizer.
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Technical Review Document — Initial Operating Permit
• A requirement for the permittee to monitor the hours of operation when the
flash tank are routed to the plant flare on a monthly basis and to utilize the
hours of operation to calculate emissions.
2. Emission Factors
From the amine unit, the VOC, Benzene, Toluene, n -Hexane, and H2S emission
factors are from VMG Simulation. The SO2 emission factor is from mass balance
calculation. The controlled emission factors for this process are based on a
thermal oxidizer (still vent) or flare (flash gas) control efficiency of 95%.
From the thermal oxidizer controlling the regenerator emissions, the CO and NOx
emission factors are from AP -42, Chapter 13.5, Table 13.5-1 and 13.5-2, based
on the higher heating value of NOx and the lower heating value for CO (as
indicated in footnote f to Table 13.5-2 and footnote k to Table 13.5-1, higher
heating value was reported as 29 Btu/scf, lower heating value reported as 27
Btu/scf), vent gas flow rate of 54633.33 scf/hr, and 8,760 hrs/year.
Note: It is typical for the Division to utilize the emission factors in AP -42, Table
1.4-1 to calculate emission limits and for the permittee to monitor compliance
with for thermal oxidizers because typically the heat value of the vent stream
routed to the thermal oxidizer cannot meet the minimum presumed heat value
used to develop the emission factors in AP -42, 13.5-1 and 13.5-2 (300 Btu/scf
lower heating value). However, these emissions were not updated to the AP -42,
Table 1.4-1 factors for NOx and CO because when the emission factors from 1.4-
1 are converted to lb/MMBtu (the same units as 13.5-1 and 13.5-1) based on a
heating value of 1,020 Btu/scf (as indicated in footnote a to Table 1.4-1) and
calculated utilizing a vent gas flow rate of 54633.33 scf/hr, 8,760 hrs/yr, and the
vent gas heat values of 29 Btu/scf and 27 Btu/scf (higher and lower, respectively;
for NOx and CO, respectively) the Table 13.5-1 and 13.5-2 values create a more
conservative (higher) emission limit.
3. Monitoring Requirements
In addition to the monitoring required to monitor compliance with the annual
emission limitations (monthly emission calculation and rolling twelve-month
totals), the permittee is required to monitor and record the monthly quantity of
natural gas processed by this amine unit, lean amine recirculation rate, amine
solution concentration, annual sampling for total inlet sulfur concentration.
In addition to the monitoring required to calculate the required monthly thermal
oxidizer emissions, the permittee is required to monitor and record the hours of
operation waste gas is vented from the amine unit flash tank and combusted by
the thermal oxidizer, monitor the internal combustion chamber temperature on a
daily basis, operate the thermal oxidizer at all times that emissions are routed to
it, and conduct daily visible emission observations and subsequent EPA Method
9 observations if emission are observed.
4. Compliance Status
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Requirement for 100% of emissions that result from the flash tank
associated with this amine unit to be recycled to the common fuel header.
The 2017 inspection report indicates that flash tank emissions have two
flow routes during normal operations: the primary is to the inlet slug
catcher where they are re -introduced to the process and the secondary is
to the main plant flare; since the permittee did not send 100% of the
emission from the flash tank to the fuel header they were considered in
violation of this permit condition. A final approval construction permit for
this unit was issued on December 14, 2017, which corrects the control
configuration language indicating that 100% of plant emissions are to be
sent to the plant inlet; therefore, a compliance plan is not necessary.
• Requirement to follow the most recent operating and maintenance plan
and recordkeeping format approved by the Division, specifically, the
requirement to operate the thermal oxidizer at a minimum combustion
temperature of 1350°F. The temperature issues were caused by failure of
the pilot light or plant failures. During these times emissions were routed
to the facility flare. Since these time when the minimum combustion
temperature was not met were due to periods of pilot light or plant failures,
which are one-off malfunction issues that have been addressed and is
addressed by the CoC requirement to comply with the Act, the
Regulations, and all relevant permit conditions regarding the regulation
and control of air pollutants applicable to the facility, no compliance plan is
warranted.
J. 018 — Produced Water Tanks (13WE3008) — Redtail Gas Plant
1. Applicable Requirements
Two (2) 400 BBL fixed roof storage tanks used to store produced water.
Emissions from these tanks are controlled by a combustor. According to the
Notice of Startup (received October 2, 2015), these storage tanks commenced
operation on September 17, 2015.
The source has demonstrated compliance under the provisions of Regulation No.
3, Part B, Section III.G.2 for initial approval construction permit 13WE3008 but
not yet received a final approval construction permit. Under the provisions of
Regulation No. 3, Part C, Section V.A.3., the Division will not issue a final
approval construction permit and is allowing the initial approval construction
permit to continue in full force and effect. The appropriate provisions of the initial
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Technical Review Document — Initial Operating Permit
approval construction permit have been directly incorporated into this operating
permit
The appropriate applicable requirements from Colorado Construction Permit
13WE3008 for the produced water tanks are as follows:
• Requirements to self -certify for final approval
As of the date of this draft the source has completed the self -certification
requirements; therefore, these conditions were not incorporated into the
operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Monthly Limits:
Facility
Equipment
ID
AIRS
Point
Pounds per Month
Emission
Type
NOx
VOC
CO
PW-1, PW-
2
018
--
34
--
Point
(Note: Monthly limits are based on a 31 -day month.)
The owner or operator shall calculate monthly emissions based on the
calendar month.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 1,359 lb/month.
Facility -wide emissions of total hazardous air pollutants shall be less than
3,398 lb/month.
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
PW-1, PW-
2
018
--
0.2
--
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
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.
During the first twelve (12) months of operation, compliance with both the
monthly and annual emission limitations is required. After the first twelve
(12) months of operation, compliance with only the annual limitation is
required.
Compliance with the annual limits shall be determined by recording the
facility's annual criteria pollutant emissions, (including all HAPs above the
de-minimis reporting level) from each emission unit, on a rolling twelve
(12) month total. By the end of each month a new twelve-month total shall
be calculated based on the previous twelve months' data. The permit
holder shall calculate emissions each month and keep a compliance
record on site or at a local field office with site responsibility, for Division
review. This rolling twelve-month total shall apply to all permitted emission
units, requiring an APEN, at this facility.
This condition was modified upon incorporation into the Operating Permit
to remove the monthly VOC and HAP limits. The permittee was no longer
required to comply with the monthly emissions limits as of October 2015.
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
PW-1, PW-2
018
Enclosed Flare
VOC, HAPs
This condition was revised during incorporation into the operating permit
to change the enclosed flare to a combustor based on comments received
during source review.
• This source shall be limited to the following processing rate as listed
below. Monthly records of the actual processing rate shall be maintained
by the owner or operator and made available to the Division for inspection
upon request. (Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
AIRS
Annual
Monthly
Equipment
ID
Point
Parameter
Limit
Limit (31
days)
Y)
123/9AD0 Page 54 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
PW-1, PW-2
018
Produced water
throughput
29,200
BBL/yr
2480
BBL/month
The owner or operator shall calculate monthly process rates based on the
calendar month.
During the first twelve (12) months of operation, compliance with both the
monthly and annual throughput limitations shall be required. After the first
twelve (12) months of operation, compliance with only the annual limitation
shall be required.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was modified upon incorporation into the Operating Permit
to remove the monthly limits. The permittee was no longer required to
comply with the monthly emissions limits as of October 2015.
• Records shall be kept in either an electronic file or hard copy provided that
they can be promptly supplied to the Division upon request. All records
shall be retained for a consecutive period of three years.
This condition was streamlined out of the operating permit in favor of the
Division's standard recordkeeping requirements incorporated into Section
IV of the operating permit.
• 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.1.c shall have no visible emissions. (Reference:
Regulation No. 1, Section II.A.1. & 4.)
These produced water tanks are a VOC only source; it is Division
standard not to include opacity limits in permits for VOC sources. This
condition has not been incorporated into the operating permit. The flare
associated with these tanks is subject to the no visible emissions
requirement of Colorado Regulation No. 7, Part D, Section 11.8 (formerly
Section XVII.B) and the 30% opacity requirement of Colorado Regulation
No. 1, which have been incorporated into the Operating Permit.
• Upon startup of these points, the owner or operator shall follow the most
recent operating and maintenance (O&M) plan and record keeping format
approved by the Division, in order to demonstrate compliance on an
ongoing basis with the requirements of this permit. Revisions to your O&M
123/9AD0 Page 55 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
plan are subject to Division approval prior to implementation. (Reference:
Regulation No. 3, Part B, Section III.G.7.)
The O&M Plan approved by the Division (approved August 6, 2014)
required monthly monitoring of above parameters, which was based on
the permitted facility -wide VOC emissions less than 80 tpy. These
frequencies have been revised upon incorporation into the Operating
Permit to weekly (for separator temperature and pressure) based on
permitted facility -wide above 80 tpy as indicated in the current version of
the O&M Plan. The monitoring requirements incorporated include:
• Condensate throughput for each tank on a monthly basis
• Separator feed tank temperature on a weekly basis
• Separator tank pressure on a weekly basis
In addition, the following requirements from the current O&M Plan were
streamlined out in favor of the audio, visual, olfactory (AVO) requirements
of Colorado Regulation No. 7, Section XVII. C.1. d:
• Thief hatch seals shall be inspected for integrity annually and
replaced as necessary;
• Thief hatch covers shall be weighted and properly seated;
• Pressure relief valves (PRV) shall be inspected annually for proper
operation and replacement as necessary;
• 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 conditions;
• Annual inspections shall be documented with an indication of
status, a description of any problems found, and their resolution.
• Visible combustor inspection monitoring and recordkeeping
requirements.
2. Emission Factors
Emission factors for the produced water tanks are from Permit Section Memo 14-
03, Section 5.3 (May 1, 2017 version) for produced water tanks located in Weld
County.
3. Monitoring Requirements
In addition to the monitoring to establish emission factors, monthly monitoring of
the condensate throughput is required. Additionally, the permittee is required to
meet the requirements of Colorado Regulation No. 7, Part D, Section II.C for the
storage tanks and Section II.B for the air pollution control equipment.
123/9AD0 Page 56 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Requirements to submit an NOS 15 days after operation commencement
and to demonstrate compliance with the permit conditions within 180 days.
The 2017 inspection report indicates that at least one of these tanks
commenced operation in July 2014; the self -certification was submitted on
October 2, 2015. This issue is being addressed through Case 2016-236;
therefore, no compliance plan is necessary.
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Requirement for the permittee to operate and maintain an enclosed flare
in order to reduce emissions to less than or equal to the limits established
in the permit. The 2017 inspection report indicates that these tanks are
controlled by a shrouded open flare. This issue is being resolved with the
provision of Case #2016-236 to either replace the flare with an enclosed
flare or to perform a compliance test on the shrouded flare to demonstrate
compliance with the permitted emission limits and the required control
efficiency (95%).
• The requirement to follow the most recent operating and maintenance
plan and recordkeeping format approved by the Division, specifically, the
requirements for thief hatch seals and pressure relief valves to be
inspected for integrity annually and the requirement to control leakage of
VOCs to the atmosphere (thief hatch integrity, PRV proper operation, and
annual inspections of thief hatches). During the 2017 inspection the
permittee provided AIMM inspection results of the PRVs and thief hatches.
The inspections did not include any documentation regarding physical
inspection results. This issue is being resolved through the requirement of
Case #2016-236 for the permittee to comply with the Act, the Regulations,
and all relevant permit conditions regarding the regulation and control of
air pollutant applicable to the facility.
K. 021 —1,311 HP G3516 4SLB Internal Combustion Engine (14WE0889) —
Razor 21 CPB
1. Applicable Requirements
One (1) Caterpillar, Model G3516, Serial Number JEF01264, natural gas -fired,
turbo -charged, 4SLB reciprocating internal combustion engine, site rated at 1311
horsepower. This engine shall be equipped with an oxidation catalyst and air -fuel
ratio control. This emission unit is used as a gas lift compressor engine.
According to the APEN for the permanent engine replacement through the AOS
123/9AD0 Page 57 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
(received April 13, 2015), this engine commenced operation on April 4, 2015.
According to the Razor 21 Central Production Battery APENs and Permit
Application (received on April 24, 2014) this engine was manufactured on July
21, 2011.
The source has demonstrated compliance under the provisions of Regulation No.
3, Part B, Section III.G.2 for initial approval construction permit 14WE0889 but
not yet received a final approval construction permit. Under the provisions of
Regulation No. 3, Part C, Section V.A.3., the Division will not issue a final
approval construction permit and is allowing the initial approval construction
permit to continue in full force and effect. The appropriate provisions of the initial
approval construction permit have been directly incorporated into this operating
permit
The appropriate applicable requirements from Colorado Construction Permit
14WE0889 for the natural gas -fired engine are as follows:
• Requirements to self -certify for final authorization
As of the date of this draft the source has completed the self -certification
requirements; therefore, these conditions were not incorporated into the
operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
RZ-ENG-1
021
6.3
8.9
6.2
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.
Compliance with the annual limits shall be determined by recording the
facility's annual criteria pollutant emissions, (including all HAPs above the
de-minimis reporting level) from each emission unit, on a rolling twelve
(12) month total. By the end of each month a new twelve-month total shall
be calculated based on the previous twelve months' data. The permit
holder shall calculate emissions each month and keep a compliance
record on site or at a local field office with site responsibility, for Division
123/9AD0 Page 58 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
review. This rolling twelve-month total shall apply to all permitted emission
units, requiring an APEN, at this facility.
This condition was modified upon incorporation into the Operating Permit
to incorporate the facility -wide HAP limits of Colorado Construction Permit
13WE3003, 13WE3005, 13WE3006, 13WE3007, 14WE0891, 14WE0892,
and 14WE0893 (facility -wide total HAPs < 9.0 tons/year and facility -wide
individual HAP limits < 24.0 tons/year).
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
RZ-ENG-1
021
SCO
VOC, CO, and
HAPs
This condition was incorporated into the operating permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the actual processing rate shall be
maintained by the owner or operator and made available to the Division
for inspection upon request. (Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment ID
AIRS
Point
Process Parameter
Annual Limit
RZ-ENG-1
021
Consumption of natural gas
as a fuel
83.31
MMscf/yr
The owner or operator shall calculate monthly process rates based on the
calendar month.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance on site or at a local field office with site responsibility, for
Division review.
This condition was incorporated into the operating permit.
• Visible emissions shall not exceed twenty percent (20%) opacity during
normal operation of the source. During periods of startup, process
123/9AD0 Page 59 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
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.1.c shall have no visible emissions. (Reference:
Regulation No. 1, Section II.A.1. & 4.)
This condition was incorporated into the Operating Permit. The regulation
No. 7 citations were updated to reflect the reorganization adopted
December 19, 2019.
• Upon startup of these points, the owner or operator shall follow the most
recent operating and maintenance (O&M) plan and record keeping format
approved by the Division, in order to demonstrate compliance on an
ongoing basis with the requirements of this permit. Revisions to your O&M
plan are subject to Division approval prior to implementation. (Reference:
Regulation No. 3, Part B, Section III.G.7.)
The O&M Plan submitted to the Division on July 14, 2016 indicated
facility -wide emissions of CO to be less than 80 tons per year and the
appropriate monitoring frequencies were identified to be: semi-annual
portable analyzer testing, weekly catalyst inlet temperature monitoring,
and monthly catalyst differential pressure monitoring. However, the
emission calculations provided by the permittee with the revised operating
permit application (March 31, 2017) and the Division calculated permitted
emissions indicate controlled facility -wide CO emissions to be over 80
tons per year; therefore, the following monitoring requirements were
incorporated into the operating permit daily catalyst inlet temperature
monitoring, weekly catalyst differential pressure monitoring, and quarterly
portable analyzer monitoring, which is consistent with the monitoring
frequencies required for facilities that emit more than 80 tons per year of
either NOx or CO as indicated in the O&M Plan template.
• Initial compliance test for oxides of nitrogen, carbon monoxide and
formaldehyde
This condition was not incorporated into the operating permit. The initial
performance test was not conducted within the specified timeframe;
however, the requirements of this initial compliance test were completed
on April 26, 2016 and the test results were approved by the Division on
October 18, 2016. This non-compliance issue is being resolved through an
administrative penalty via CoC Case #2016-236.
• 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 as Alternative Operating Scenarios
may be subject to additional testing requirements as specified in
Attachment A.
123/9AD0 Page 60 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The appropriate requirements from the O&M Plan were incorporated into
the operating permit, including, but not limited to: monthly fuel
consumption and hours of operation monitoring. Additionally, the O&M
Plan requires portable analyzer testing based on facility -wide NOX or CO
emissions. The O&M Plan indicates that the permitted facility -wide NOx or
CO emissions are less than 80 tpy, however, the emission calculations
submitted with the revised operating permit application (March 31, 2017)
and the Division calculated emissions indicate that permitted CO
emissions are greater than 80 tpy; therefore, portable analyzer testing will
be required to be conducted on a quarterly basis. The frequency of
monitoring for the pre -catalyst temperature was also updated to daily
based on the monitoring frequency for facilities with permitted NOX or CO
emissions greater than 80 tpy.
Additional Applicable Requirements:
• This engine is subject to the requirements of 40 CFR Part 60 Subpart
JJJJ, "Standards of Performance for Stationary Spark Ignition Internal
Combustion Engines", from which the appropriate provisions have been
incorporated into the Operating Permit, including, but not limited, to:
emission standards, compliance requirements, notification, reporting, and
recordkeeping requirements, and general provisions.
• This unit is also subject to the provisions of 40 CFR Part 63 Subpart
ZZZZ, "National Emission Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines", from which the
appropriate provisions have been incorporated into the Operating Permit.
In general, the applicable requirements of Subpart ZZZZ include, but are
not limited to: emission and operating limitations, general requirements,
initial performance testing and compliance demonstrations, continuous
compliance demonstration requirements, monitoring, installation,
collection, operating, and maintenance requirements, notification
reporting, and recordkeeping requirements.
• A requirement to conduct an extended gas analysis on an annual basis on
the process stream routed to the flare controlling the separators for the
purposes of calculating emissions from the flare was added to the
operating permitting.
2. Emission Factors
Emission factors for NOx, CO, VOC, and formaldehyde are from the
manufacturer and have been converted from g/HP-hr to Ib/MMBtu per Division
standard and based on an engine fuel consumption of 8,328 Btu/HP-hr. All other
emissions factors are from AP -42, Table 3.2-2.
3. Monitoring Requirements
4. Compliance Status
123/9AD0 Page 61 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Requirement to provide the manufacture date, construction date, order
dare, and date of relocation into Colorado. Per the 2017 the outlined
information was not provided with the Notice of Startup. This information
was provided in a submittal on April 13, 2015; therefore, a compliance
plan is not necessary.
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Requirement to conduct an initial compliance test of this engine to
measure the emission rate(s) for NOx, CO, and formaldehyde. According
to the 2017 inspection report the permittee failed to conduct the initial
required performance test within the required time period. This
requirement was fulfilled by testing conducted on April 26, 2016 and the
test results were approved by the Division on October 18, 2016. Since this
requirement has been fulfilled no compliance plan is necessary.
L. 023 — Flare for Gas Separators (14WE0891) — Razor 21 CPB
1. Applicable Requirements
Eight (8) two-phase separators controlled by an open flare during gas -gathering
system downtime. Open flare. According to the Notice of Startup (received
December 26, 2014), this flare commenced operation on June 10, 2014.
Colorado Construction Permit 14WE0891 was issued for the unit on December
19, 2014 as an initial approval permit. A final approval permit was issued for
Colorado Construction Permit 14WE0891 October 26, 2017. The appropriate
provisions of the final approval construction permit have been directly
incorporated into this operating permit
The appropriate applicable requirements from Colorado Construction Permit
14WE0891 for the open flare are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation Number 3, Part B, Section III.G.5.)
This is a construction permit only condition; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
123/9AD0 Page 62 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
RZ-SEP1
thru RZ-
SEP-8, RZ-
FLR-1
023
1.3
17.3
5.3
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
The facility -wide emissions limitation for hazardous air pollutants shall
apply to all permitted emission units at this facility.
Compliance with the annual limits, for both criteria and hazardous air
pollutants, shall be determined on a rolling twelve (12) month total. By the
end of each month a new twelve month total is calculated based on the
previous twelve months' data. The permit holder shall calculate actual
emissions each month and keep a compliance record on site or at a local
field office with site responsibility for Division review.
This condition was incorporated into the operating permit.
• The owner or operator shall track emissions from all insignificant activities
at the facility on an annual basis to demonstrate compliance with the
facility potential emission limitations as seen below. An inventory of each
insignificant activity and associated emission calculations shall be made
available to the Division for inspection upon request. For the purposes of
this condition, insignificant activities shall be defined as any activity or
equipment, which emits any amount but does not require an Air Pollution
Emission Notice (APEN) or is permit exempt.
Total potential emissions from the facility, including all permitted emissions
and potential to emit from all insignificant activities, shall be less than:
o 10 tons per year of any individual hazardous air pollutant (HAP);
and
o 25 tons per year of total HAPs.
123/9AD0 Page 63 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The current standard operating permit insignificant tracking language was
incorporated into the operating permit.
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
Facility
' Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
RZ-SEP1
thru RZ-SEP-
8, RZ-FLR-1
023
Emissions from the
Separators are routed to
an Open Flare during
gas -gathering system
downtime
VOC and
HAPs
This condition was incorporated into the Operating Permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the throughput shall be maintained by the
applicant and made available to the Division for inspection upon request.
(Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment ID
AIRS
Point
Process Parameter
Annual Limit
RZ-SEP1
thru RZ-SEP-
8, RZ-FLR-1
023
Natural gas venting
27.7 MMscf/yr
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the operating permit.
• The owner or operator shall continuously monitor and record the
volumetric flow rate of natural gas vented from the separator(s) using the
flow meter. The owner or operator shall use monthly throughput records to
demonstrate compliance with the process limits contained in this permit
and to calculate emissions as described in this permit.
This condition was incorporated into the operating permit.
123/9AD0 Page 64 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• The open flare covered by this permit has been approved as an alternative
emissions control device under Regulation Number 7, Section XVII.B.2.e.
The open flare must have no visible emissions during normal operations,
as defined under Regulation Number 7, XVII.A.16, and be designed so
that an observer can, by means of visual observation from the outside of
the open flare, or by other convenient means approved by the Division,
determine whether it is operating properly. This open flare must be
equipped with an operational auto -igniter according to the following
schedule:
o All combustion devices installed on or after May 1, 2014, must be
equipped with an operational auto -igniter upon installation of the
combustion device;
o 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.
This condition was incorporated into the operating permit.
• The separator covered by this permit is subject to Regulation 7, Section
XVII.G. (State Only). On or after August 1, 2014, gas coming off a
separator, produced during normal operation from any newly constructed,
hydraulically fractured, or recompleted oil and gas well, must either be
routed to a gas gathering line or controlled from the date of first production
by air pollution control equipment that achieves an average hydrocarbon
control efficiency of 95%. If a combustion device is used, it must have a
design destruction efficiency of at least 98% for hydrocarbons.
This condition was incorporated into the operating permit as Colorado
Regulation No. 7, Part D, Section II.F based on the December 19, 2019
revisions to Colorado Regulation No. 7.
• Upon startup of these points, the owner or operator shall follow the most
recent operating and maintenance (O&M) plan and record keeping format
approved by the Division, in order to demonstrate compliance on an
ongoing basis with the requirements of this permit. Revisions to the O&M
plan are, subject to Division approval prior to implementation. (Regulation
Number 3, Part B, Section III.G.7.)
The current O&M Plan required that the following items be monitored on a
daily basis: pilot light, auto -igniter, and visible emissions. These
requirements have been streamlined out in favor of the Colorado
Regulation No. 7 monitoring requirements.
• On an annual basis, the owner/operator shall complete a site -specific
extended gas analysis ("Analysis") of the natural gas vented from this
emissions unit in order to verify the VOC content (weight fraction) of this
emission stream. Results of the Analysis shall be used to calculate site-
123/9AD0 Page 65 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
specific emission factors for the pollutants referenced in this permit (in
units of lb/MMscf vented) using Division -approved methods. Results of the
analysis shall be used to demonstrate that the emissions factor
established through the Analysis are less than or equal to, the emission
factor submitted with the permit application and established herein in the
"Notes to Permit Holder" for this emissions point. If any site specific
emissions factor developed through this Analysis is greater than the
emissions factor submitted with the permit application and established in
the "Notes to Permit Holder" the operator shall submit to the Division
within 60 days, or in a timeframe as agreed to by the Division, a request
for permit modification to address this/these inaccuracy(ies).
This condition was incorporated into the operating permit.
2. Emission Factors
Combustion emission factors for this flare are from AP -42, Table 13.5-1 for NOx
and Table 13.5-2 for CO. The AP -42 NOx emission factor was developed based
on the higher heating value of the vent gas and is represented in units of
lb/MMBtu. Colorado Construction Permit 14WE0891 represents both NOx and
CO emission factors in lb/MMscf. During the process of drafting the operating
permit the Division recalculated the emission factors based on the AP -42 factors
and the higher and lower heating values represented in 14WE0891 Preliminary
Analysis, which resulted in different emission factors (NOx = 87.788 lb/MMscf
and CO = 363.63 lb/MMscf) since the emissions factors in the construction permit
are conservative (higher) the Division will not update the emissions factors to the
calculated values indicated unless the permittee submits an APEN to request this
change.
3. Monitoring Requirements
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Requirement for maximum annual processing limits. Per the 2017
inspection report the quantity of gas routed to this flare is tracking
utilizing an in -line fuel meter and the permittee reported exceeding
their permitted combustion limit for the rolling twelve-month period
ending December 2015. This issue is being resolved through the
requirement for the permittee to comply with the Act, the
regulations, and all relevant permit conditions regarding the
regulation and control of pollutants applicable to the facility in Case
#2016-236.
123/9AD0 Page 66 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• Requirement for the separators to be designed, operated, and
maintained to minimize leakage of VOCs to the atmosphere to the
maximum extent practicable. The 2017 inspection report indicates
that the permittee provided monthly AIMM inspection results of the
PRVs. The inspections did not include any documentation
regarding physical inspection results and what actions were taken
to repair/stop venting emissions. The permittee believes that AIMM
inspections are sufficient to meet this requirement. This issue is
being resolved through the requirement for the permittee to comply
with the Act, the regulations, and all relevant permit conditions
regarding the regulation and control of pollutants applicable to the
facility in Case #2016-236. Additionally, the appropriate Colorado
Regulation No. 7, Section XVII requirements and additional
monitoring requirements identified by the Division to address
monitoring gaps were incorporated into the operating permit;
therefore, a compliance plan is not necessary.
M. 024 — Produced Water Tanks (14WE0892) — Razor 21 CPB
1. Applicable Requirements
Twenty-four (24) 400 BBL fixed roof storage tanks used to store produced water.
Emissions from these tanks are controlled by an enclosed combustor. According
to the Notice of Startup (received December 26, 2014), these tanks commenced
operation on June 10, 2014.
Colorado Construction Permit 14WE0893 was issued for the unit on December
19, 2014 as an initial approval permit. A final approval permit was issued for
Colorado Construction Permit 14WE0893 no on October 26, 2017. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit
The appropriate applicable requirements from Colorado Construction Permit
14WE0892 for the produced water storage tanks are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation Number 3, Part B, Section III.G.5.)
This is a construction permit condition only; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Tons per Year
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Facility
Equipment
ID
AIRS
Point
NOx
VOC
CO
Emission
Type
RZ-PW-1
through RZ-
PW-24
024
---
0.3
---
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
The facility -wide emissions limitation for hazardous air pollutants shall
apply to all permitted emission units at this facility.
Compliance with the annual limits, for both criteria and hazardous air
pollutants, shall be determined on a rolling twelve (12) month total. By the
end of each month a new twelve month total is calculated based on the
previous twelve months' data. The permit holder shall calculate actual
emissions each month and keep a compliance record on site or at a local
field office with site responsibility for Division review.
This condition was incorporated into the Operating Permit.
• The owner or operator shall track emissions from all insignificant activities
at the facility on an annual basis to demonstrate compliance with the
facility potential emission limitations as indicated below. An inventory of
each insignificant activity and associated emission calculations shall be
made available to the Division for inspection upon request. For the
purposes of this condition, insignificant activities shall be defined as any
activity or equipment, which emits any amount but does not require an Air
Pollution Emission Notice (APEN) or is permit exempt. (Reference:
Regulation 3, Part C. II.E.)
Total emissions from the facility, including all permitted emissions and
potential to emit from all insignificant activities, shall be less than:
o 10 tons per year of any individual hazardous air pollutant
(HAP); and
o 25 tons per year of total HAPs.
The current standard operating permit insignificant tracking language was
incorporated into the operating permit.
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
RZ-PW-1
through RZ-
PW-24
024
Enclosed Combustor
VOC and
HAPs
This condition was incorporated into the Operating Permit.
• This source shall be limited to the following processing rate as listed
below. Monthly records of the actual processing rate shall be maintained
by the owner or operator and made available to the Division for inspection
upon request. (Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment ID
AIRS
Point
Process Parameter
Annual Limit
RZ-PW-1
through RZ-
PW-24
024
Produced water throughput
547,500 bbl/yr
The owner or operator shall calculate monthly process rates based on the
calendar month.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the Operating Permit.
• The flare covered by this permit is subject to Regulation No. 7, Section
XVII.B General Provisions (State only enforceable).
The Colorado Regulation No 7, Part D, Section 11.8 (formerly Section XVII)
requirements that apply to the flare were incorporated into the Operating
Permit.
• The storage tanks covered by this permit are subject to Regulation 7,
Section XVII.C emission control requirements.
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
The applicable requirements of Colorado Regulation No. 7, Part D,
Section II. C (formerly Section XVII. C) were incorporated into the operating
permit.
• The storage tanks covered by this permit are subject to the venting and
Storage Tank Emission Management System ("STEM") requirements of
Regulation Number 7, Section XVII.C.2.
The appropriate STEM requirements of Colorado Regulation No. 7, Part
D, Section II. C (formerly Section XVII. C.2) were incorporated into the
operating permit.
• Upon startup of these points, the owner or operator shall follow the most
recent operating and maintenance (O&M) plan and record keeping format
approved by the Division, in order to demonstrate compliance on an
ongoing basis with the requirements of this permit. Revisions to the O&M
plan are subject to Division approval prior to implementation. (Regulation
Number 3, Part B, Section III.G.7.)
The appropriate requirements from the O&M Plan approved by the
Division (submitted September 24, 2014) were incorporated into the
operating permit. These monitoring requirements incorporated include:
o Condensate throughput for each tank on a monthly basis
o Separator feed tank temperature on a weekly basis
o Separator tank pressure on a weekly basis
In addition, the following requirements from the current O&M Plan were
streamlined out in favor of the audio, visual, olfactory (AVO) requirements
of Colorado Regulation No. 7, Section XVII. C.1. d:
o Thief hatch seals shall be inspected for integrity annually
and replaced as necessary;
o Thief hatch covers shall be weighted and properly seated;
o Pressure relief valves (PRV) shall be inspected annually for
proper operation and replacement as necessary;
o 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
conditions;
o Annual inspections shall be documented with an indication of
status, a description of any problems found, and their
resolution.
o Visible combustor inspection monitoring and recordkeeping
requirements.
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
2. Emission Factors
Emission factors for the tanks are to be re-established annually based on site
specific sampling and analysis and monitored temperature and pressure data, as
described above.
3. Monitoring Requirements
In addition to the monitoring to establish emission factors, monthly monitoring of
the condensate throughput is required. Additionally, the permittee is required to
meet the requirements of Colorado Regulation No. 7, Section II.C for the storage
tanks and Section II.B for the air pollution control equipment.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Colorado Regulation No. 7, Section XVII storage tank requirements. The
Division's 2017 inspection report indicates that the permittee failed to
provide records of the efforts made to eliminate venting, restore operation
of air pollution control equipment, and mitigate visible emissions as
required under Colorado Regulation No. 7, Section XVII.C.3.a. This issue
is being resolved through the requirement of Case #2016-236 for the
permittee to comply with the Act, the Regulations, and all relevant permit
conditions regarding the regulation and control of air pollutant applicable
to the facility. Additionally, the appropriate requirements of Section XVII.C
and provisions to address monitoring gaps identified by the Division in
XVII.C were incorporated into the operating permit; therefore, a
compliance plan is not necessary to address this issue.
• Requirement for the separators to be designed, operated, and maintained
to minimize leakage of VOCs to the atmosphere to the maximum extent
practicable. The 2017 inspection report indicates that the permittee
provided monthly AIMM inspection results of the PRVs. The inspections
did not include any documentation regarding physical inspection results
and what actions were taken to repair/stop venting emissions. The
permittee believes that AIMM inspections are sufficient to meet this
requirement. This issue is being resolved through the requirement of Case
#2016-236 for the permittee to comply with the Act, the Regulations, and
all relevant permit conditions regarding the regulation and control of air
pollutant applicable to the facility.
N. 025 — Oil Storage Tanks (14WE0893) - Razor 21 CPB
123/9AD0 Page 71 of 93
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
1. Applicable Requirements
Thirty-two (32) 400 BBL fixed roof storage tanks used to store crude oil.
Emissions from these tanks are controlled by a VRU. During VRU downtime
emissions are routed to an open flare. According to the Notice of Startup
(received December 26, 2014), these tanks commenced operation on June 10,
2014.
Colorado Construction Permit 14WE0893 was issued for the unit on December
19, 2014 as an initial approval permit. A final approval permit was issued for
Colorado Construction Permit 14WE0893 no on October 26, 2017. The
appropriate provisions of the final approval construction permit have been directly
incorporated into this operating permit
The appropriate applicable requirements from Colorado Construction Permit
14WE0893 for the oil storage tanks are as follows:
• This construction permit represents final permit approval and authority to
operate this emissions source. Therefore, it is not necessary to self -certify.
(Regulation Number 3, Part B, Section III.G.5.)
This is a construction permit condition only; therefore, was not
incorporated into the operating permit.
• Emissions of air pollutants shall not exceed the following limitations (as
calculated in the Division's preliminary analysis). (Reference: Regulation
No. 3, Part B, Section II.A.4)
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
NOx
VOC
CO
RZ-TK-1
through RZ-
TK-32
025
1.4
45.0
5.8
Point
See "Notes to Permit Holder" for information on emission factors and
methods used to calculate limits.
Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy.
Compliance with the annual limits, for both criteria and hazardous air
pollutants, shall be determined on a rolling twelve (12) month total. By the
end of each month a new twelve month total is calculated based on the
123/9AD0 Page 72 of 93
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
previous twelve months' data. The permit holder shall calculate actual
emissions each month and keep a compliance record on site or at a local
field office with site responsibility for Division review.
This condition was incorporated into the Operating Permit.
• The owner or operator shall track emissions from all insignificant activities
at the facility on an annual basis to demonstrate compliance with the
facility potential emission limitations as indicated below. An inventory of
each insignificant activity and associated emission calculations shall be
made available to the Division for inspection upon request. For the
purposes of this condition, insignificant activities shall be defined as any
activity or equipment, which emits any amount but does not require an Air
Pollution Emission Notice (APEN) or is permit exempt. (Reference:
Regulation 3, Part C. II.E.)
Total emissions from the facility, including all permitted emissions and
potential to emit from all insignificant activities, shall be less than:
• 10 tons per year of any individual hazardous air pollutant (HAP);
and
• 25 tons per year of total HAPs.
The current standard operating permit insignificant tracking language was
incorporated into the operating permit.
• 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 (Reference:
Regulation No.3, Part B, Section III.E.)
Facility
Equipment ID
AIRS Point
Control Device
Pollutants
Controlled
RZ-TK-1
through RZ-
TK-32
025
Open Combustor
o
VOC and
HAPs
This condition was incorporated into the Operating Permit.
• This source shall be limited to the following maximum processing rates as
listed below. Monthly records of the actual processing rates shall be
maintained by the owner or operator and made available to the Division
for inspection upon request. (Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment ID
AIRS
Point
Process Parameter
Annual Limit
123/9AD0 Page 73 of 93
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
RZ-TK-1
through RZ-
025
Crude oil throughput
219,000 bbl/yr
TK-32
The owner or operator shall calculate monthly process rates based on the
calendar month.
Compliance with the annual throughput limits shall be determined on a
rolling twelve (12) month total. By the end of each month a new twelve-
month total is calculated based on the previous twelve months' data. The
permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility,
for Division review.
This condition was incorporated into the Operating Permit.
• The combustion device covered by this permit is subject to Regulation
Number 7, Section XVII.B.2. General Provisions (State only enforceable).
The Colorado Regulation No 7, Part D, Section II (formerly Section XVII)
requirements that apply to the flare were incorporated into the Operating
Permit.
• The storage tanks covered by this permit are subject to Regulation 7,
Section XVII.C emission control requirements.
The applicable requirements of Colorado Regulation No. 7, Part D,
Section 11.C (formerly Section XVII. C) were incorporated into the operating
permit.
• The storage tanks covered by this permit are subject to the venting and
Storage Tank Emission Management System ("STEM") requirements of
Regulation Number 7, Section XVII.C.2.
The appropriate STEM requirements of Colorado Regulation No. 7, Part
D, Section II. C (formerly Section XVII. C. 2) were incorporated into the
operating permit.
• Upon startup of these points, the owner or operator shall follow the most
recent operating and maintenance (O&M) plan and record keeping format
approved by the Division, in order to demonstrate compliance on an
ongoing basis with the requirements of this permit. Revisions to your O&M
plan are subject to Division approval prior to implementation. (Reference:
Regulation No. 3, Part B, Section III.G.7.)
The appropriate requirements from the O&M Plan (approved by the
Division on September 24, 2014) were incorporated into the Operating
Permit. These provisions include:
123/9AD0 Page 74 of 93
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• Condensate throughput tracked/recorded monthly through sales or
haul tickets
• Separator temperature and pressure monitored/recorded weekly
• Daily monitoring and documentation of the combustor/flare pilot
light operating and presence of visible emissions from the flare
(Method 22 performed if visible'emissions observed). The auto -
igniter signal will be primary means of verifying pilot light operation
and visual inspection will be the backup
• A rotary screw vapor recovery unit (VRU) will be used to draw
vapors from the tanks and loadout operations and routed them to
the Redtail Gas Plant. When the high pressure set point for the
VRU is reached, flow is diverted to the flare.
The above requirements were incorporated into the operating permit.
Additionally, the O&M Plan requires the following, which was streamlined
out of the operating permit in favor of the Colorado Regulation No. 7,
Section XVII. C requirements applicable to these tanks.
• Thief hatch seals shall be inspected for integrity annually and
replaced as necessary. Thief hatch covers shall be weighted and
properly seated. Pressure relief valves (PRV) shall be inspected
annually for proper operation and replaced as necessary. 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 conditions. Annual
inspections shall be documented with an indication of status, a
description of any problems found, and their resolution.
• The operator shall complete site specific sampling including a
compositional analysis of the pre -flash pressurized condensate routed to
these storage tanks and a sales oil analysis to determine RVP and API
gravity. Testing shall be in accordance with the guidance contained in PS
Memo 05-01. Results of testing shall be used to determine a site -specific
emissions factor using Division approved methods. Results of site -specific
sampling and analysis shall be submitted to the Division as part of the
self -certification and used to demonstrate compliance with the emissions
factors chosen for this emissions point.
This condition was incorporated into the Operating Permit.
2. Emission Factors
Emission factors for the tanks are to be re-established annually based on site
specific sampling and analysis and monitored temperature and pressure data, as
described above.
3. Monitoring Requirements
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
In addition to the monitoring to establish emission factors, monthly monitoring of
the condensate throughput is required. Additionally, the permittee is required to
meet the requirements of Colorado Regulation No. 7, Section II.C for the storage
tanks and Section II.B for the air pollution control equipment.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was out of compliance with the following applicable requirements at the time of
the inspection:
• Facility -wide methanol limit (see Section IV.P.2 of this Technical Review
Document).
• Colorado Regulation No. 7, Section XVII storage tank requirements. The
Division's 2017 inspection report indicates that the permittee failed to
provide records of the efforts made to eliminate venting, restore operation
of air pollution control equipment, and mitigate visible emissions as
required under Colorado Regulation No. 7, Section XVII.C.3.a. This issue
is being resolved through the requirement of Case #2016-236 for the
permittee to comply with the Act, the Regulations, and all relevant permit
conditions regarding the regulation and control of air pollutant applicable
to the facility. Additionally, the appropriate requirements of Section XVII.C
and provisions to address monitoring gaps identified by the Division in
XVII.C were incorporated into the operating permit; therefore, a
compliance plan is not necessary to address this issue.
O. 032 — Caterpillar G3508B Internal Combustion Engine
1. Applicable Requirements
One (1) Caterpillar, Model G3508B, Serial Number TBD, natural gas -fired, turbo-
charged, 4SLB reciprocating internal combustion engine, site rated at 677
horsepower. This engine is equipped with an oxidation catalyst. This emissions
unit will be used as a gas lift compressor engine. According to Division records,
this engine commenced operation on January 10, 2017
UPDATE: The permittee removed the engine associated with AIRS ID 032 and
submitted a cancellation request received by the Division on April 9, 2019. The
requirements associated with this emission unit were removed from the operating
permit.
2. Emission Factors
Emission factors for NOx, CO, VOC, and formaldehyde are from the
manufacturer and have been converted from g/HP-hr to lb/MMBtu per Division
standard and based on an engine fuel consumption of 8,247 Btu/HP-hr. All other
emissions factors are from AP -42, Table 3.2-2.
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
3. Monitoring Requirements
In addition to the monitoring required to calculate monthly emissions, the
permittee is required to monitor the heat content of the natural gas on an annual
basis, perform monitoring associated with the oxidation catalyst (inlet
temperature, pressure drop, portable analyzer monitoring, and catalyst cleaning,
reconditioning, and replace in accordance with the manufacturer's
specifications), and is subject to the monitoring requirements of 40 CFR Part 60
Subpart JJJJ.
4. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was in of compliance with the applicable federal, state, and permit conditions of
Colorado Construction Permit 14WE0844 applicable at the time of the inspection.
P. Facility -wide requirements
1. Applicable Requirements
• Facility -wide emissions of each individual hazardous air pollutant shall be
less than 9.0 tpy.
Facility -wide emissions of total hazardous air pollutants shall be less than
24.0 tpy
This condition was incorporated into the Operating Permit. Note, there are
previously issued construction permits with 8.0 and 20.0 facility -wide HAP
limits, which were not incorporated into the operating permit in favor of the
HAP limits incorporated in the more recently issued construction permits
(listed above) for the Redtail Gas Plant.
• These sources are subject to the odor requirements of Regulation No. 2.
(State only enforceable)
This condition is incorporated into the General Requirements of the
Operating Permit.
• APEN filing requirement
This condition is incorporated into the General Requirements of the
Operating Permit.
• This source is subject to the provisions of Regulation No. 3, Part C,
Operating Permits (Title V of the 1990 Federal Clean Air Act
Amendments). The provisions of this construction permit must be
incorporated into the Operating Permit. The application for the
modification to the Operating Permit is due within one year of the issuance
of this permit.
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Technical Review Document — Initial Operating Permit
A modification to the operating permit application was submitted on
October 11, 2016 to incorporate the changes addressed by these
construction permits (14WE0893, 14WE0844), which fulfills the
requirements of this condition. Therefore, this condition was not
incorporated into the operating permit.
• Federal regulatory program requirements (i.e. PSD, NANSR) 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 Federal program threshold will
require a full review of the source as though construction had not yet
commenced on the source. The source shall not exceed the Federal
program threshold until a permit is granted. (Regulation No. 3 Part D).
This requirement is evaluated on a case -by -case basis that is dependent
on specific parameters of undefined future modifications, and the
requirement will be evaluated at that time; the condition is therefore not
included.
• Construction Permit General Conditions
These conditions were exchanged for the current version of the Operating
Permit General Conditions (ver 8/28/2018).
2. Compliance Status
The applicant certified compliance with all applicable requirements in the
operating permit application. The Division completed a full compliance evaluation
at the facility on August 10, 2017. According to the inspection report, the facility
was in of compliance with the applicable federal, state, and permit conditions of
Colorado Construction Permit 14WE0844 applicable at the time of the inspection,
except for the following:
• Facility -wide methanol limit for the rolling 12 -month period ending
December, 2015. The permittee exceeded this limit due to dehydration
unit venting methanol. This issue is being resolved via Case #2016-236.
V. Streamlining of Applicable Requirements
• Colorado Construction Permit 13WE3008 Condition 15 requiring control devices to
be adequately designed, operated, maintained, and able to handle reasonably
foreseeable fluctuations in VOCs (including separator dumps into the tank) was
streamlined out in favor of Colorado Regulation No. 7, Part D, II.B.2.a.
• AIRS 014 — Natural Gas Heater: Colorado Regulation No. 6, Part B, Section II.C.2 is
a state -only requirement for PM standards applicable to fuel burning equipment
between 1 MMBtu/hour and 250 MMBtu/hour. Colorado Regulation No. 1 Section
III.a.1.b includes the same standard for fuel burning equipment between 1
MMBtu/hour and 500 MMBtu/hour. The Regulation No. 6 standard does not apply
during startup, shutdown, nor malfunction while the Regulation No. 1 standard
123/9AD0 Page 78 of 93
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
applies at all times. Therefore, the Regulation No. 1 requirement is considered to be
more stringent than the Regulation No. 6 requirement, which was streamlined out
the operating permit.
• AIRS 014 — Natural Gas Heater: Colorado Regulation No. 6, Part B, Section II.C.3
opacity standards, which adopts by reference (Colorado Regulation No. 6, Part B,
Section I.A) 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, nor malfunction. The turbine located at the
Redtail facility are also subject to the opacity requirements of Colorado Regulation
No. 1, Section II.A.1, which include 20% opacity at all times, except for certain
specific operating conditions under which a 30% opacity requirement applies
(Colorado Regulation No. 1, Section II.A.4). The only likely operating condition for
these turbines when the 30% opacity standard applies is startup; therefore, the
Colorado Regulation No. 1 opacity standards are more stringent than the Colorado
Regulation No. 6 standards, which were streamlined out of the operating permit.
• AIRS 011 — Engine: This engine is subject to both the 20% opacity limit of Colorado
Regulation No. 1, Section II.A.1 at all times except as specified in Colorado
Regulation No. 1, Section II.A.4 and the 50% opacity limit during peaks in either the
acceleration or lugging modes as specified in §89.113(a)(3) (incorporated by
reference into 40 CFR Part 60 Subpart 1111, §60.4202(a)(2)). The Colorado
Regulation No. 1 opacity limits are more stringent; therefore, the §89.113(a)(3)
requirement was streamlined out the operating permit.
• FLR-2: The inspection frequency requirement for control devices controlling tanks
subject to II.C was increased from between 7 and 31 days in the rule to daily in
accordance with current Division practices.
• AIRS 007, 018, 024, & 025 — Tanks: Regulation No. 7, Part D, Section II requires
use of approved instrument monitoring methods (AIMM) with respect to tanks and
fugitive emissions, and defines AIMM to be EPA Method 21, infra -red camera, or
other Division -approved methods. Due to the monitoring requirements for Title V
permitting, as -yet unspecified future methods cannot be permitted in all cases;
therefore "other Division -approved methods" has been streamlined out.
• Regulation No. 7, Part D, Section II.C requireS that records be kept for 2 years; this
is streamlined out in favor of the five year requirement applicable to Title V facilities.
• Regulation No. 7, Part D, Sections III.F &III.G require that records be kept for 3
years; this is streamlined out in favor of the five year requirement applicable to Title
V facilities.
VI. Insignificant Activities
General categories and specific insignificant activities identified by the permittee
include:
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Fuel -Burning Equipment, other than internal combustion engines ≤ 5 MMBtu/hour (Reg
3, Part C, II. E. 3. i) *:
• Eight burners on heater treaters (four rated at 0.75 MMBtu/hr & four rated at 0.5
MBtu/hr)
• Four amine thermal oxidizer heaters
Air Pollution emission units, operations, or activities with emissions less than the
appropriate de minimis reporting level (Reg 3, Part C, Il. E. 3. a) *:
• Fugitive emissions from equipment leaks (Razor 21 CPB)
• Fugitive emissions from produced water loadout (Redtail Gas Plant and Razor 21
CPB)
• Pneumatic valves (Razor 21 CPB)
• Crude oil loadout (formally AIRS 026)
• Condensate Loadout (formally AIRS 019)
• Fugitive Dust from Haul Roads (formally AIRS 020)
• Fugitive dust emissions from haul roads from crude oil and produced
water truck loadouts. (formally AIRS 028)
• DEHY-1 and DEHY-2 combustor assist gas
Chemical storage areas where chemicals are stored enclosed containers, and where
total storage capacity does not exceed 5000 gallons. This exemption applies solely to
storage of such chemicals. This exemption does not apply to transfer of chemicals
from, to, or between such containers (Reg 3, Part C, II. E. 3. mm) *:
Redtail Gas Plant
• AST -02 — 24.8 bbl steel diesel storage tank
• AST -03 — 24.8 bbl steel diesel storage tank
• AST -06 — 3.45 bbl steel oil storage tank in transformer
• AST -08 — 11.9 bbl steel oil storage tank in transformer
• AST -09 — 23.8 bbl steel propane storage tank
• AST -10 — 23.8 bbl steel propane storage tank
• AST -11 — 1.32 bbl steel therminol-55 storage tank
• TK-8941 — 150 bbl steel therminol-55 hot oil relief tank
• TK-9923 — 11.9 bbl steel methanol storage tank
• TK-9930 — Steel chemical pH buffer tank
• TK-9941 — 90 bbl steel amine storage tank
• T-9943 — 90 bbl steel amine storage tank
• TK-9948 — 11.9 bbl steel methanol storage tank
Razor 21 CPB
• AST -02 — 11.9 bbl steel antifreeze storage tank
• AST -03 — 3.1 bbl plastic methanol storage tank
• AST -04 — 3.1 plastic methanol storage tank
• AST -07 — Steel propane storage tank
• AST -08 — 5.23 bbl plastic chemical storage tank
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Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
• AST -09 — 7.85 bbl plastic chemical storage tank
• AST -10 — 5.23 bbl plastic chemical storage tank
• AST -11 — 5.23 bbl plastic chemical storage tank
• AST -12 — 6.42 bbl ENTEGRATE HS 7542 storage tank
• AST -14 — 11.9 bbl steel antifreeze storage tank
• AST -15 — 5.5 bbl plastic methanol storage tank
Storage tanks of capacity < 40,000 gallons of lubricating oils (Req 3, Part C,
II. E. 3. aaa):
• TK-9950 - 150 bbl steel lube oil storage tank (Redtail Gas Plant)
• AST -01 — 11.9 bbl steel lube oil store tank (Razor 21 CPB)
• AST -13 — 11.9 bbl steel lube oil storage tank (Razor 21 CPB)
VII. Alternative Operating Scenarios
The current versions of the engine and turbine AOS were incorporated into the
Operating Permit.
VIII. Permit Shield
The permittee requested the following permit shields for specific non -applicable
requirements:
Emission Unit
Description &
Number
Applicable Requirement
Justification
AMINE -1
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart LLL
Affected facilities under this regulation are
those that commenced constructed,
reconstruction, or modification after January
20, 1984 and on or before August 23, 2011.
Construction of the Redtail plant
commenced in May 2013; therefore the
amine unit at this facility is exempt from the
requirements of 40 CFR Part 60 Subpart
LLL.
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart OOOO
Per §60.5365(g)(3), facility that have a
design capacity less than 2 LT/D of H2S in
the acid gas (expressed as sulfur) are not
required to comply with §60.5405 through
§60.5410(g) and §60.5415(g). This amine
unit has a design capacity less than 2 LT/D;
therefore, is exempt from these provisions.
HTR-1A
Colorado Reg 8 & (40 CFR Part 63) NSPS
Subpart JJJJJJ
Per 40 CFR 63.11195(e) a gas -fired boiler is
not subject to the provisions of this
regulation. This unit is gas -fired and
therefore, exempt from these provisions.
123/9AD0
Page 81 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Colorado Reg 8 & (40 CFR Part 63) NSPS
Subpart DDDDD
The hot oil heater at the Redtail Gas Plant
(HTR-1A) meets the definition of a process
heater. However, it is located at an area
source of HAP emissions; therefore, this
regulation does not apply.
FLR-1A
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart A §60.18
This flare does not control equipment
subject to the provisions of 40 CFR Part 60;
therefore, is not regulated under Colorado
Reg 6 nor §60.18
DEHY-01 &
DEHY-02
Colorado Reg 8 & (40 CFR Part 63) NSPS
Subpart HH
The Redtail Gas Plant is designated as an
area source of HAP emissions, and the two
dehydration units are ethylene glycol (EG)
units and not TEG units. Therefore, this
regulation does not apply.
RZ-ENG-1A
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart OOOO
Per 40 CFR 60.5365(c), a reciprocating
compressor located at a well site, or adjacent
well site and servicing more than one well
site is not an affected facility under this
subpart. Well site means one or more areas
that are directly disturbed during the drilling
and subsequent operation of, or affected by,
production facilities directly associated with
any oil well, gas well, or injection well and
its associated well pad. Under this definition
the Razor 21 CPB is a well sit; therefore, the
gas lift engine is not subject to the
provisions of this regulation.
Separators, Flare
RZ-FLR-1
Colorado Regulation No. 7, Part D, II.B.2.b
The high flare pressure is used as back up
control and therefore can be an open flare.
This shield only applies to the requirement
for the combustion device to be enclosed,
the flare must operate with no visible
emissions and be designed so that an
observer can by means of visual observation
from the outside or by other means approved
by the Division, determine whether it is
operating properly as required by this
permit.
Oil & Produced
Water Tanks,
Enclosed
Combustor
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart Kb
Two 400 -bbl (47.696 m3) condensate tanks,
one 400 -bbl gunbarrel tank, and two 400 -bbl
produced water tanks. Each of these
atmospheric storage tanks are smaller than
19,800 gal; therefore, are not subject to
Subpart Kb.
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart OOOO
Whiting operates two condensate storage
tanks, one gunbarrel tank, and two produced
water tanks. The permitted controlled
emissions per tank do not exceed the 6-tpy
threshold; therefore, this regulation does not
apply.
Facility -wide
Colorado Reg 6 & (40 CFR Part 60) NSPS
Subpart KKK
Affected facilities under this regulation are
those that commenced construction,
reconstruction, or modification after January
20, 1984 and on or before August 23, 2011.
Construction of the Redtail plant
commenced in May 2013; therefore the
provisions of this regulation do not apply.
123/9AD0
Page 82 of 93
Appendix A
Facility -Wide Criteria Emission Summary
Facility -Wide Controlled HAP Emission Summary
Facility -Wide Uncontrolled HAP Emission Summary
Regulatory Applicability Summary Table
123/9ADO Page 83 of 93
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Controlled Emissions
POINT
Facility ID
Description
TSP
PM,o
PM2.5
H2S
SO2
NOx
VOC
Fug
VOC
CO
Repor
table
HAPs
009
FUG -1
Fugitive VOCs from Equipment Leaks
--
--
--
--
--
--
--
74.0
--
1.3
011
GEN-2
361 HP, CI Emergency Engine
--
--
--
--
--
0.3
0.3
--
0.3
0.0
013
FLR-1A
Process Flare
--
--
--
--
--
7.5
21.2
--
30.8
0.0
014
HTR-1A
43.64 MMBtu/hr Hot Oil Heater
2.5
2.5
--
--
0.1
12.7
3.7
--
7.9
0.3
015
DEHY -1
EG Dehy Unit
--
--
--
--
--
--
1.4
--
--
1.2
016
DEHY-2
EG Dehy Unit
--
--
--
--
--
--
1.0
--
--
0.7
017
MDEA Sweetening Unit
--
--
--
--
25.3
0.5
10.0
--
2.1
5.7
018
PW-1'
PW-2
2-400 BBL Produced Water Tanks
--
--
--
--
0.2
--
--
0.0
021
RZ-ENG-1
1311 HP, 4SLB Engine
0.5
0.5
--
--
--
6.3
8.9
--
6.2
1.3
023
RZ-SEP-1
through
RZ-SEP-
8, RZ-
FLR-1
Separators controlled by Flare
--
--
--
--
--
1.3
17.3
--
5.3
0.2
024
RZ-PW-1
through
RZ-PW-24
24-400 BBL Produced Water Tanks
--
--
--
--
--
--
0.3
--
--
0.0
025
RZ-TK-1
through
RZ-TK-32
32-400 BBL Crude Oil Tanks
--
--
--
--
--
1.4
45.0
--
5.8
1.0
Insignificant Activities
3-400 BBL Condensate Tanks
--
--
--
--
--
--
0.1
--
--
0.0
Produced Water Loadout LOAD -2
--
--
--
--
--
--
1.1
--
--
0.0
DEHY-1 Combustor Assist Gas
--
--
--
--
--
--
--
--
--
0.0
DEHY-2 Combustor Assist Gas
--
--
--
--
--
--
--
--
--
0.0
(4) Amine Thermal Oxidizer Heaters
0.1
0.1
0.1
--
--
1.3
0.1
--
1.1
0.0
Produced Water Loadout
--
--
--
--
--
--
1.1
--
--
0.0
Crude Oil Loadout
--
--
--
--
--
--
--
--
--
0.0
Fugitive Dust
0.5
0.1
--
--
--
--
--
--
--
0.0
Pneumatic valves
--
--
--
--
--
--
0.3
--
--
0.0
Fugitives
--
--
--
--
--
--
--
0.3
--
0.0
Heater Treaters FlameCo Burner
0.2
0.2
0.2
--
--
2.6
0.1
--
2.2
0.0
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
TOTAL
I 3.8 I 3.4 I 0.3 I 0.0 I 25.4 I 33.9 1112.1 I 74.3 1 61.7 I 11.7
Notes: HAP emissions shown above are total Reportable HAP emissions (i.e., uncontrolled emissions are greater than de minimis Reg 3, Part A reporting
thresholds.
Uncontrolled Emissions
POINT
Facility ID
Description
TSP
PM,o
PM2.5
H2S
SO2
NOx
VOC
Fun
VOC
CO
Report
able
HAPs
009
FUG -1
Fugitive VOCs from Equipment Leaks
--
--
--
--
--
--
--
125.4
--
13.5
011
GEN-2
361 HP, CI Emergency Engine
--
--
--
--
--
0.3
0.3
--
0.3
0.0
013
FLR-1A
Process Flare
--
--
--
--
--
7.5
423.6
--
30.8
1.8
014
HTR-1A
43.64 MMBtu/hr Hot Oil Heater
2.5
2.5
--
--
0.1
12.7
3.7
--
7.9
0.3
015
DEHY -1
EG Dehy Unit
--
--
--
--
--
--
29.5
--
--
27.8
016
DEHY-2
EG Dehy Unit
--
--
--
--
--
--
19.7
--
--
14.5
017
MDEA Sweetening Unit
--
--
--
--
25.3
0.5
320.9
--
2.1
116.0
018
PW-1'
PW-2
2-400 BBL Produced Water Tanks
--
--
--
--
--
--
3.8
--
--
0.3
021
RZ-ENG-1
1311 HP, 4SLB Engine
0.5
0.5
--
--
--
6.3
10.5
--
36.5
6.0
023
RZ-SEP-1
through
RZ-SEP-8,
RZ-FLR-1
Separators controlled by Flare
--
--
--
--
--
1.3
346.8
--
5.3
11.7
024
RZ-PW-1
through
RZ-PW-24
24-400 BBL Produced Water Tanks
--
--
--
--
--
--
6.6
--
--
0.7
025
RZ-TK-1
through
RZ-TK-32
32-400 BBL Crude Oil Tanks
--
--
--
--
--
1.4
900.1
--
5.8
26.4
Insignificant Activities
3-400 BBL Condensate Tanks
--
--
--
--
--
--
1.5
--
--
0.0
Produced Water Loadout LOAD -2
--
--
--
--
--
--
1.1
--
--
0.0
DEHY-1 Combustor Assist Gas
--
--
--
--
--
--
--
--
--
0.0
DEHY-2 Combustor Assist Gas
--
--
--
--
--
--
--
--
--
0.0
Amine Thermal Oxidizer Heaters (each)
0.1
0.1
0.1
--
--
1.3
0.1
1.1
0.0
Produced Water Loadout
--
--
--
--
--
--
1.1
--
--
0.0
Crude Oil Loadout
--
--
--
--
--
--
--
--
--
0.0
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Fugitive Dust
0.5
0.1
0.0
Pneumatic valves
0.3
0.0
Fugitives
0.3
0.0
Heater Treaters FlameCo Burner*
0.2
0.2
0.2
2.6
0.1
2.2
0.0
TOTAL
3.8 I 3.4 0.3 I 0.0 I 25.4 133.9 2,069.7 I 125.7 92.0 1219.0
*If uncontrolled actual emissions exceed two tons per year the permittee will be required to hold an APEN with the Division as required by Colorado
Regulation No. 3, Part A, 11.8.3.a (for facilities located in the attainment/maintenance area).
Emission Factor Data Sources:
Fugitive VOCs
Emission factors are from EPA -453/R-95-017, Table 2-4. Controlled percentages are from EPA -453/R-95-017, Table 5.3.
Other equipment type category includes: compressors, pressure relief valves, relief values, diaphragms, drains, dump
arms, hatches, instrument meters, polish rods, and vents. Compliance with emission limits in this permit will be
demonstrated by using the TOC emission factors listed in the table with representative component counts, multiplied by the
VOC content from the most recent gas analysis.
Emergency Generator
(AIRS 011)
The emission factors used to determine the unit is permit exempt, APEN required are from AP -42, Table 3.3-2 for all HAPs.
PM,o, PM25, NOx, CO, and VOC emission factors are from NSPS 1111 (referenced to 40 CFR 89.112) and converted from
g/HP-hr to lb/MMBtu based on an engine fuel use rate or 17 gal/hr, a site rating of 250 kW, and a diesel fuel heating value
of 139,000 Btu/gal.
Flares
AIRS 013: Emissions factors for FLR-1A are from AP -42, Section 13.5, Table 13.5-2. The facility submitted an APEN on
August 9, 2016 requesting to update the emission limits of the flare and included the updated AP -42 CO emissions factor
(0.31 lb/MMBtu). The NOx emissions are based on the emission factor represented in AP -42, Section 13.5, Table 13.5-1
(0.068 lb/MMBtu), a reported natural gas heat value of 1,145 Btu/scf (as reported on the APEN received August 9, 2016),
and a requested annual fuel permit limit of 193.1 MMscf/yr.
AIRS 023: NOx emission factor from AP -42, Table 13.5-1 and converted lb/MMBtu to lb/MMscf based on a heating value of
1,291 Btu/scf (higher heating value as indicated in AP -42, Table 13.5-1, footnote k)
FLR-2 (insignificant): Emissions factors for FLR-1A are from AP -42, Section 13.5, Table 13.5-2
Natural Gas -Fired Hot Oil
Heater (AIRS 014)
Emissions factors for PM,o, PM2.5, NOx, CO, and VOC are from the manufacturer. SO2 and HAP emissions are calculated
using the factors represented in AP -42, Chapter 1, Tables 1.4-2 and 1.4-3. For consistency, the SO2 emission factor has
been converted from lb/MMscf to lb/MMBtu based on a fuel heating value of 1020 Btu/scf.
Dehys (AIRS 015 & 016)
Uncontrolled emission factors are based on VMG Simulation Model. The controlled VOC and HAP emission factors for this
point are based on the thermal oxidizer or facility process flare (during thermal oxidizer downtime) control efficiency of 95%
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Amine Unit (AIRS 017)
From the amine unit, the VOC, Benzene, Toluene, n -Hexane, and H2S emission factors are from VMG Simulation. The SO2
emission factor is from mass balance calculation. The controlled emission factors for this process are based on a thermal
oxidizer (still vent) or flare (flash gas) control efficiency of 95%.
From the thermal oxidizer controlling the regenerator emissions, the CO and NOx emission factors are from AP -42, Chapter
13.5, Table 13.5-1 and 13.5-2, based on the higher heating value of NOx and the lower heating value for CO (as indicated
in footnote f to Table 13.5-2 and footnote k to Table 13.5-1, higher heating value was reported as 29 Btu/scf, lower heating
value reported as 27 Btu/scf), vent gas flow rate of 54633.33 scf/hr, and 8,760 hrs/year.
Produced Water Tanks
(AIRS 018 & 024)
AIRS 018: VOC, benzene, and n -hexane emission factors from division guidance, PS Memo 14-03, Section 5.3 for state
emission factors for produced water tanks in Weld county (May 1, 2017 version).
AIRS 024: Developed site -specific VOC, benzene, and toluene emission factor as incorporated into Colorado Construction
Permit 14WE0892.
Crude Oil Tanks (AIRS
025)
VOC site -specific emission factor, to be verified annually.
Fugitive VOCs
(insignificant)
Emission factors are from EPA -453/R-95-017, Table 2-4. Other equipment type category includes: compressors, pressure
relief valves, relief values, diaphragms, drains, dump arms, hatches, instrument meters, polish rods, and vents. Compliance
with emission limits in this permit will be demonstrated by using the TOC emission factors listed in the table with
representative component counts, multiplied by the VOC content from the most recent gas analysis.
Truck Tank Loading
The VOC emission factor is from AP -42, Section 5.2. Benzene, Toluene, Ethylbenzene, Xylene, and n -Hexane emission
factors are based on mass balance calculations
Fugitive Dust
(insignificant)
Emission factors are based on the calculation methodology of AP -42, Chapter 13.2.2 and as calculated by the permittee
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
HAP Emission Details:
Controlled Emissions (lb/year
POINT
Facility ID
Form
aldehyde
Acet
aldehyde
Acrolein
Benzene
Toluene
Ethyl
benzene
Xylenes
n-
Hexane
McOH
224
TMP
H2S
TOTAL
(tpy)
TOTAL
REPORTABLE
(tpY)
009
FUG -1
--
--
--
117
364
178
185
1582
745
--
--
1.6
1.3
011
GEN-2
1
1
--
1
--
--
--
--
--
--
--
0.0
0.0
013
FLR-1A
--
--
--
28
42
2
15
86
12
--
--
0.1
0.0
014
HTR-1A
28
--
--
--
--
--
--
675
--
--
--
0.4
0.3
015
DEHY -1
--
--
--
221
7
--
49
--
2480
--
30
1.4
1.2
016
DEHY-2
--
--
--
380
14
1
84
--
960
--
--
0.7
0.7
017
AMINE -1
--
--
--
1344
469
35
69
49
8121
--
1420
5.8
5.7
018
PW-1, PW-
2
--
--
--
10
--
--
--
32
--
--
--
0.0
0.0
021
RZ-ENG-1
1276
800
492
42
--
--
--
106
--
239
--
1.5
1.3
023
RZ-SEP-1
through
RZ-SEP-8,
RZ-FLR-1
--
--
--
139
208
166
166
485
--
7
--
0.6
0.2
024
RZ-PW-1
through
RZ-PW-24
--
--
--
43
29
3
7
5
--
1
--
0.0
0.0
025
RZ-TK-1
through
RZ-TK-32
--
--
--
208
135
18
56
2066
--
159
--
1.3
1.0
Insignificant Activities
3-400 BBL Condensate
Tanks
Produced Water
Loadout LOAD -2
_
__
__
__
__
__
0.0
DEHY-1 Combustor
Assist Gas
DEHY-2 Combustor
Assist Gas
(4) Amine Thermal
Oxidizer Heaters
8
--
--
--
--
--
--
186
--
--
--
0.1
0.0
Produced Water
Loadout
__
_
__
__
0.0
Crude Oil Loadout
--
--
--
2
2
--
--
12
--
--
--
0.0
0.0
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Pneumatic valves
0.0
0.0
Fugitives
1
5
0.0
0.0
Heater Treaters
FlameCo Burner
4
93
0.0
0.0
TOTAL
0.7
0.4
0.2
1.3
0.6
0.2
0.3
2.7
6.2
0.2
0.7 13.5
11.7
Uncontrolled Emissions (lb/year
POINT
Facility ID
Form
aldehyde
Acet
aldehyde
Acrolein
Benzene
Toluene
Ethyl
benzene
Xylenes
n-
Hexane
McOH
224
TMP
r120(tpy)
TOTAL
TOTAL
REPORTABLE
(tpy)
009
FUG -1
--
--
--
950
3139
1486
1547
13316
6625
--
--
13.5
13.5
011
GEN-2
1
1
--
1
--
--
--
--
--
--
--
0.0
0.0
013
FLR-1A
--
--
--
552
830
36
293
1722
250
--
--
1.8
1.8
014
HTR-1A
28
--
--
--
--
--
--
675
--
--
--
0.4
0.3
015
DENY -1
--
--
--
4410
148
8
974
4
49609
--
594
27.9
27.8
016
DEHY-2
--
--
--
7723
278
19
1674
13
19356
--
14.5
14.5
017
AMINE -1
--
--
--
27207
9497
705
1390
2322
162568
--
28400
116.0
116.0
018
PW-1,
PW-2
--
--
--
204
--
--
--
642
--
--
--
0.4
0.3
021
RZ-
ENG-1
10634
800
492
42
--
--
--
106
--
239
--
6.2
6.0
023
RZ-
SEP-1
through
RZ-
SEP-8,
RZ-FLR-
1
--
--
--
2774
4161
3329
3329
9709
--
138
--
11.7
11.7
024
RZ-PW-
1
through
RZ-PW-
24
--
--
--
866
578
56
141
98
--
18
--
0.9
0.7
025
RZ-TK-1
through
RZ-TK-
32
--
--
--
4161
2694
350
1117
41325
--
-
3175
--
26.4
26.4
Whiting Oil and Gas Corporation — Redtail Facility
Operating Permit No. 15OPWE394
Technical Review Document — Initial Operating Permit
Insignificant Activities
3-400 BBL
Condensate Tanks
--
--
--
--
--
--
--
--
--
--
--
0.0
0.0
Produced Water
Loadout LOAD -2
--
--
--
""
--
--
--
0.0
0.0
DEHY-1
Combustor Assist
Gas
--
--
--
--
--
--
--
--
--
--
--
0.0
0.0
DEHY-2
Combustor Assist
Gas
--
--
--
--
--
--
--
--
--
--
--
0.0
0.0
(4) Amine Thermal
Oxidizer Heaters
8
--
--
--
--
--
--
186
--
--
--
0.1
0.0
Produced Water
Loadout
__
__
__
__
Crude Oil Loadout
--
--
--
2
2
--
--
12
--
--
--
0.0
0.0
Pneumatic valves
--
--
--
--
--
--
--
--
--
--
--
0.0
0.0
Fugitives
--
--
--
1
--
--
--
5
--
--
--
0.0
0.0
Heater Treaters
FlameCo Burner
4
--
--
--
--
--
--
93
--
--
--
0.0
0.0
TOTAL (tpy) 5.3 0.4
0.2 24.4 10.7 3.0 5.2
35.1 119.2 1.8 14.5 219.8 219
*Total Reportable = all HAPs where uncontrolled emissions > de minimis values (250 Ibs/yr)
Italic Text: uncontrolled emissions < de minimus
CAM and Colorado Regulation No. 7 Regulatory Applicability Summary Table
AIRS ID
CAM
Reg 17'
XII
Reg 7, Part D, II
009
011
013
II.B
014
015
016
N/A, 1st
017
issuance
II.D
018
II.C
021
023
II.G
024
025
II.C
40 CFR Part 60 Regulatory Applicability Summary Table
AIRS ID
NSPS Dc
NSPS GG
NSPS IIII
NSPS JJJJ
NSPS
Kb2
NSP
KKK3
NSPS
KKKK4
NSPS
LLL
NSPS
OOOO5
NSPS
000Oa
009
Equipment
leak
standards &
reciprocating
compressor
affected
facility
011
Stationary CI,
constructed
1 Not applicable, the Redtail Gas Plant is not in the non -attainment area.
2 Not applicable, all of the tanks at the Redtail facility have a storage capacity less than seventy-five cubic meters
3 Not applicable, none of the equipment located at the Redtail Gas Plant or the Razor 21 CPB commenced construction prior to August 23, 2011
4 Not applicable, the turbine located at the Redtail facility was constructed prior to the applicability date of this subpart (February 18, 2005)
5 Not applicable, no construction, modification, nor reconstruction occurred at the Redtail facility after the applicability date of this Subpart (September 18, 2015)
AIRS ID
NSPS Dc
NSPS GG
NSPS 1111
NSPS JJJJ
NSPS
Kb2
NSP
KKK3
NSPS
KKKKS4
NSPS
LLL
NSPS
OOOO
NSPS
0000a
5
March 27, 2014
& manufactured
after April 1,
2006
013
014
Reporting
Requirements
015
016
017
Design
capacity <
2LT/D
018
021
4SLB, ordered
2/14/2014,
manufactured
7/21/2011
023
024
025
40 CFR Part 63 Regulatory Applicability Summary Table
AIRS
ID
MACT
HH6
MACT
DDDDD7
MACT
JJJJJJ8
MACT
YYYY9
MACT ZZZZ
009
011
New,
Emergency,
6 Not applicable, area source; therefore, only TEG dehydrators are affected sources — No TEG dehydrators are located at the facility
Not applicable, the Willow Creek Gas Plant is an area source of HAP emissions
8 Not applicable, there are no boilers located at the Willow Creek Gas Plant
9 Not applicable, area source
AIRS
ID
MACT
HH6
MACT
DDDDD7
MACT
JJJJJJB
MACT
YYYY6
MACT ZZZZ
Complies
with Subpart
ZZZZ by
meeting
requirements
of 40 CFR
Part 60
Subpart IIII
013
014
015
016
017
018
021
New,
Complies
with Subpart
ZZZZ by
meeting
requirements
of 40 CFR
Part 60
Subpart JJJJ
023
024
025
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