1

Kelly, Shaheerah

From: Kelly, Shaheerah

Sent: Wednesday, October 15, 2014 10:10 PM

To: dmallory@ResoluteEnergy.com; pflynn@ResoluteEnergy.com

Cc: Rios, Gerardo; Mintz, Tom; Kelly, Shaheerah

Subject: Proposed Clean Air Act Prevention of Significant Deterioration Permit for McElmo 

Creek Unit Oil Production Facility (NU 05-01)

Attachments: EPA Transmittal Letter for MCU Proposed PSD Permit Amendment.PDF; Proposed MCU 

PSD Permit Amendment.pdf; Proposed MCU PSD Amendment Permit Appendix A - 

OM Plan.pdf; Proposed MCU PSD Permit Amendment Appendix B - RCFA.pdf; 

Proposed MCU PSD Permit Amendment Appendix B - RCFA.pdf; AAQIR-Fact Sheet for 

MCU PSD Permit Amendment.pdf; Public Notice for Proposed MCU PSD Permit 

Amendment.pdf

Good evening,

Please see the attached information regarding the proposed Clean Air Act Prevention of Significant Deterioration permit

for the McElmo Creek Unit Oil Production Facility.  

Regards,

************************************ 

Shaheerah Kelly 

U.S. Environmental Protection Agency, Region 9 

Permits Office, Air Division 

San Francisco, CA 94105 

Phone: 415-947-4156 

Fax: 415-947-3579 

Email: kelly.shaheerah@epa.gov
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION.IX 

75 Hawthorne Street 

San Francisco, CA 94105 

October 14, 2014 

Dwight E. Mallory 

Environmental/Regulatory Manager 

Resolute Natural Resources Company, LLC 

1700 Lincoln Street, Suite 2800 

Denver, CO 80203 

In Reply 

Refer To: 

AIR-3 

NU 05-01 

Subject: Proposed PSD Permit Amendment for the McElmo Creek Unit Oil 

Production Facility 

Dear Mr. Mallory: 

This letter and the enclosed materials are in response to your to the Clean Air Act Prevention of 

Significant Deterioration (PSD) permit application for the McElmo Creek Unit Oil Production 

Facility (MCU Facility). The application requests that the United States Environmental 

Protection Agency, Region 9 (EPA) incorporate into the MCU Facility's PSD permit the 

pollution limits, terms, and conditions of a federal Consent Decree (United States v. Mobil 

Exploration and Producing U.S. Inc., Case No. 2:05-CV-319, filed June 8, 2005) that apply to 

the Main Flare at the facility. The MCU Facility is an existing oil and gas production operation 

that is owned, in partnership with Navajo Nation Oil and Gas Company, and operated by the 

Resolute Natural Resources Company. The facility is located in.Section 31, Township 40 South, 

Range 25 East within the Four Comers Area on the Navajo Nation Indian Reservation near the 

town of Aneth, San Juan County, Utah. 

We have reviewed your application and supporting materials, based on the criteria in the EPA's 

PSD regulations at 40 CFR 52.21. Enclosed are the proposed PSD permit amendment, Ambient 

Air Quality Impact Report and Fact Sheet, and public notice. The public notice will also be 

published on Wednesday, October 15th through Friday, October 17th, 2014, depending on the 

publication date of the following newspapers in the Four Comers area: Navajo Times, 

Farmington Daily Times, Cortez Journal, and San Juan Record. We have scheduled a public 

hearing on November 20,2014, at the Aneth Chapter House in Aneth, Utah. The proposed PSD 

permit amendment and other documents related to the PSD permit application are also available 

on our website at: http://www.epa.gov/region9/air/permit/r9-permits-issued.html. 
If you have any questions, you may contact Shaheerah Kelly at ( 415) 94 7-4156 or 

kelly.shaheerah@epa.gov. 

Enclosures 

Sincerely, 

2/;;b 

Gerardo C. Rios 

Chief, Permits Office 

Air Division 

cc: Patrick E Flynn, Resolute Natural Resources Company (via email) 

Tom Hormell, McVehil-Monnett Associates, Inc (via email) 

Raju Bisht, Navajo Nation EPA (via email) 

Tennille Begay, Navajo Nation EPA (via email) 

2 
PROPOSED 

PREVENTION OF SIGNIFICANT DETERIORATION 

PERMIT ISSUED PURSUANT TO THE 

REQUIREMENTS AT 40 CFR § 52.21

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 9

PSD PERMIT NUMBER: NU 05-01 

PERMITTEE: Resolute Natural Resources Company 

1675 Broadway, Suite 1950 

Denver, Colorado 80202 

FACILITY NAME McElmo Creek Unit Oil Production 

Facility 

FACILITY LOCATION: Section 31, Township 40 South, Range 

25 East within the Four Corners Area 

on the Navajo Nation Indian 

Reservation near the city of Aneth, San 

Juan County, Utah

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C (42 U.S.C. § 7470, 

et. seq.), and the Code of Federal Regulations (CFR) Title 40, Section 52.21, the United States 

Environmental Protection Agency Region 9 (EPA) is issuing this amended Prevention of 

Significant Deterioration (PSD) air quality permit to Resolute Natural Resources Company 

(Resolute) for the McElmo Creek Unit Oil Production Facility as described herein, in accordance 

with the permit application (and plans submitted with the permit application), federal regulations 

governing the Prevention of Significant Deterioration of air quality (40 CFR § 52.21), and other 

terms and conditions set forth in this amended PSD Permit. 

Failure to comply with any condition or term set forth in this amended PSD Permit is subject to 

enforcement action pursuant to Section 113 of the Clean Air Act. This permit does not relieve 

Resolute from the responsibility to comply with any other applicable provisions of the CAA 

(including applicable implementing regulations in 40 CFR Parts 51, 52, 60, 61 and 63), or other 

federal, tribal, and local requirements. 

Per 40 CFR Section 124.15(b), this PSD Permit becomes effective 30 days after the service of 

notice of this final permit decision unless review is requested on the permit pursuant to 40 CFR 

Section 124.19. 

 

Deborah Jordan 

Director, Air Division 

 Date 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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ABBREVIATIONS & ACRONYMS 

Act Clean Air Act [42 U.S.C. § 7401 et seq.] 

Applicant Resolute Natural Resources Company 

BACT Best Available Control Technology 

BTU British thermal units 

CAA Clean Air Act [42 U.S.C. § 7401 et seq.] 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CMS Continuous Monitoring System 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

DSCFM Dry standard cubic feet per minute 

EPA United States Environmental Protection Agency 

H2S Hydrogen Sulfide 

HHV Higher Heating Value 

hr Hour 

lb, lbs Pound, pounds 

MCU Facility / 

Facility 

McElmo Creek Unit Oil Production Facility 

min Minute 

MMBTU Million British thermal units 

MMCFD Million cubic feet per day 

NAAQS National Ambient Air Quality Standards 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NNEPA Navajo Nation Environmental Protection Agency 

NOx Oxides of nitrogen 

O2 Oxygen 

Permittee / Owner or 

Operator 

Resolute Natural Resources Company, or the owner and/or operator 

of the McElmo Creek Unit Oil Production Facility 

ppm Parts per million 

PSD Prevention of Significant Deterioration 

PTE Potential to Emit 

SCF Standard cubic feet 

SCFM Standard cubic feet permit minute 

SO2 Sulfur Dioxide 

SOx Oxides of sulfur 

tpy Tons per year 

VOC Volatile Organic Compounds as defined in 40 CFR § 51.100(s) 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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MCELMO CREEK UNIT OIL PRODUCTION FACILITY 

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

PERMIT CONDITIONS 

PROJECT DESCRIPTION 

The McElmo Creek Unit Oil Production Facility (MCU Facility or Facility) is an existing oil and 

gas production operation located within the Four Corners Area on the Navajo Nation Indian 

Reservation near the city of Aneth, San Juan County, Utah. The Facility is owned, in partnership 

with the Navajo Nation Oil and Gas Company, and operated by the Resolute Natural Resources 

Company. The Facility is on the McElmo Creek Unit oilfield, which includes field operations 

and a gas compression plant. 

The field operations consist of approximately 90 producing wells where petroleum crude oil is 

recovered from producing strata, and brought to the surface to be stored at either a satellite or a 

tank battery. There are eleven satellites that function as testing facilities for producing wells and 

four tank batteries. 

The gas compression plant serves tertiary oil recovery operations for the McElmo Creek Unit 

oilfield. The gas compression plant receives produced gas through a gathering system, pressures 

the gas up to a suitable working pressure, and re-injects the gas to maintain reservoir pressure in 

the oilfield. The natural gas is injected with produced water in a dual injection system. Due to 

varying water injection demands in the field, and to the number of wells being serviced at any 

time, the gas compression plant inlet volume can vary between 10 and 18 million standard 

cubic feet per day (MMSCFD). The Main Flare is located at the gas compression plant. 

This PSD Permit amendment incorporates requirements of the federal Consent Decree that 

applies to the MCU Facility’s Main Flare (see United States v. Mobil Exploration and Producing 

U.S. Inc., Case No. 2:05–CV–319, filed June 8, 2005), which include Best Available Control 

Technology (BACT) emission limitations for emissions of sulfur dioxide (SO2), nitrogen oxides 

(NOx), carbon monoxide (CO), and volatile organic compounds (VOC). Air pollution emissions 

associated with this permit amendment will not cause or contribute to violations of any National 

Ambient Air Quality Standards (NAAQS) or any applicable PSD increments for the pollutants 

regulated under the PSD permit. 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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EQUIPMENT LIST 

The following devices and activities are subject to this PSD Permit.

Unit ID Description 

Main Flare One (1) air-assist flare, rated at 618,104 scf/hr, which combusts 

produced field gas in excess of the facility compression capacity 

TEG Reboiler 

One (1) TEG Reboiler rated at 0.75 MMBtu/hr, which combusts 

purchased pipeline quality natural gas to provide heat to the Glycol 

Heater 

Glycol Heater One (1) Glycol Heater (TEG regenerator), rated at 12 MMCFD, 

which provides inter-stage dehydration for the HOS-6 compressor 

Gasoline Storage 

Tank 

One (1) 10,000 gallon nominal capacity gasoline storage tank that is 

used for refueling of vehicles 

PERMIT CONDITIONS 

I. PERMIT EXPIRATION 

As provided in 40 CFR § 52.21(r), this PSD Permit shall become invalid if construction: 

A. is not commenced (as defined in 40 CFR § 52.21(b)(9)) within 18 months after 

the approval takes effect; or 

B. is discontinued for a period of 18 months or more; or 

C. is not completed within a reasonable time. 

II. PERMIT NOTIFICATION REQUIREMENTS 

The Permittee shall notify EPA Region IX by letter or by electronic mail of the: 

A. date construction is commenced, postmarked within 30 days of such date; 

B. actual date of initial startup, as defined in 40 CFR § 60.2, postmarked within 15 

days of such date; 

C. date upon which initial performance tests will commence postmarked not less 

than 30 days prior to such date. Notification may be provided with the submittal 

of the performance test protocol; and 

D. date upon which initial performance evaluation of the continuous emissions 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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monitoring system (CEMS) will commence in accordance with 40 CFR § 

60.13(c), postmarked not less than 30 days prior to such date. Notification may 

be provided with the submittal of the CEMS performance test. 

III. FACILITY OPERATION 

A. At all times, including periods of startup, shutdown, shakedown, and malfunction, 

the Permittee shall, to the extent practicable, maintain and operate the 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 EPA, which may include, but is not limited to, 

monitoring results, opacity observations, review of operating maintenance 

procedures, and inspection of the Facility. 

B. The operating staff with management authority at this Facility shall be advised of 

and be familiar with all the conditions of this PSD Permit. 

IV. GENERAL MALFUNCTION REPORTING 

A. The Permittee shall notify EPA at R9.AEO@epa.gov within two (2) working days 

following the discovery of any failure of air pollution control equipment or 

process equipment, or failure of a process to operate in a normal manner, which 

results in an increase in emissions above the allowable emission limits stated in 

Section IX of this permit. 

B. In addition, the Permittee shall provide an additional notification to EPA in 

writing or electronic mail within fifteen (15) days of any such failure described 

under Condition IV.A. This notification shall include a description of the 

malfunctioning equipment or abnormal operation, the date of the initial 

malfunction, the period of time over which emissions were increased due to the 

failure, the cause of the failure, the estimated resultant emissions in excess of 

those allowed in Section IX, and the methods utilized to mitigate emissions and 

restore normal operations. 

C. Compliance with this malfunction notification provision shall not excuse or 

otherwise constitute a defense to any violation of this permit or any law or 

regulation such malfunction may cause. 

V. RIGHT OF ENTRY 

A. EPA and its contractors, consultants, and agents shall have authority to enter the 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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Facility at all reasonable times, and upon presentation of credentials, shall be 

permitted to: 

1. Enter the premises where the Facility is located or where any records are 

required to be kept under the terms and conditions of this PSD Permit; 

2. During normal business hours, have access to and to copy any records 

required to be kept under the terms and conditions of this PSD Permit; 

3. Inspect any equipment, operation, or method subject to requirements in 

this PSD Permit; and 

4. Sample materials and emissions from the Facility. 

B. This provision in no way limits or otherwise affects any right of entry held by 

EPA pursuant to applicable federal, state, or local laws, regulations, or permits. 

VI. TRANSFER OF OWNERSHIP 

In the event of any changes in control or ownership of the Facility, this PSD Permit shall 

be binding on all subsequent owners or operators. Within 14 days of any such change in 

control or ownership, the Permittee shall notify the succeeding owner or operator of the 

existence of this PSD Permit and its conditions by letter. The Permittee shall send a copy 

of this letter to EPA Region IX within thirty (30) days of its issuance. 

VII. SEVERABILITY 

The provisions of this PSD Permit are severable, and, if any provision of the PSD Permit 

is held invalid, the remainder of this PSD Permit shall not be affected. 

VIII. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LAWS 

The Permittee shall construct in accordance with this PSD Permit, the application on 

which this permit is based, and all other applicable federal, state, and local air quality 

regulations. This PSD Permit does not release the Permittee from any liability for 

compliance with other applicable federal, state, and local environmental laws and 

regulations, including the Clean Air Act. 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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IX. SPECIAL CONDITIONS FOR THE MAIN FLARE 

A. Definitions 

1. “CO2 Breakthrough” shall mean an event where a gas or fluid injected in 

the Facility’s oil field for the purpose of promoting the production of oil 

contacts a producing well and results in an increase in gas volume to 

compressor station equipment. 

2. “Day” shall mean a calendar day, unless expressly stated to be a working 

day. In computing any period of time under Section IX of this PSD 

Permit, where the last day of such period would fall on a Saturday, 

Sunday, or federal holiday, the period shall run until the close of business 

on the next day that is not a Saturday, Sunday, or federal holiday. 

3. “Facility” shall mean the Permittee’s McElmo Creek Unit Oil Production 

Facility and associated oil fields, located near Aneth, Utah, on the Navajo 

Nation Indian Reservation. 

4. “Field Flares” shall mean the following flares at the Facility: (i) Tank 

Battery Flares at MCU Area 1 Battery, MCU Area 2 Battery, MCU Area 4 

Battery, and MCU Area 6 Battery; and (ii) Satellite Flares at MCU Section 

2, MCU Section 3, MCU Section 5, MCU Section 6, MCU Section 9, 

MCU Section 11, MCU Section 17, MCU Section 19, MCU Section 32, 

and MCU Section 33. 

5. “Flaring Incident” shall mean continuous or intermittent flaring at the 

Main Flare that results in the emissions of SO2 equal to, or greater than, 

five-hundred (500) pounds in any twenty-four (24) hour period; provided, 

however, that if five-hundred (500) pounds or more of SO2 have been 

emitted in a twenty-four (24) hour period and the flaring continues into 

subsequent, contiguous, non-overlapping twenty-four (24) hour period(s), 

each period of which results in emissions equal to, or greater than, five 

hundred (500) pounds of SO2, then only one Flaring Incident shall have 

occurred. Subsequent, contiguous, non-overlapping periods are measured 

from the initial commencement of flaring within the Flaring Incident. 

6. “Main Flare” shall mean the flare installed as part of the Facility’s former 

gas processing plant. 

7. “Main Flare Emissions” shall mean the emissions from the Main Flare at 

the Facility as well as all emissions that result from: (1) combustion of 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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fuel gas in the Main Flare’s pilot, (2) the closed drain and filter backwash 

operations, (3) CO2 Breakthroughs, (4) any Scheduled Maintenance, and 

(5) unscheduled maintenance of the Facility’s compressors. 

8. “Malfunction” shall mean, for the purposes of reporting under Condition 

IX.I.3 of this PSD Permit only, any sudden and unavoidable breakdown of 

process or pollution control equipment. CO2 Breakthroughs and 

Scheduled Maintenance of the Facility’s compressors are not 

Malfunctions. 

9. “Root Cause” shall mean the primary cause of a Flaring Incident as 

determined through a process of investigation; provided, however, that if a 

Flaring Incident encompasses multiple releases of SO2, the “Root Cause” 

may encompass multiple primary causes. 

10. “Scheduled Maintenance” shall mean work that is part of the routine work 

plan for the compressors located at the Facility's former gas processing 

plant. This work is typically planned and arranged on a set frequency, 

usually based on periods of time (e.g., daily, weekly or monthly) or on the 

operating hours of the equipment. Scheduled Maintenance shall not 

include work necessitated by the failure of a part of a compressor. 

B. Air Pollution Control Equipment 

1. The Main Flare shall be an automatic air-assisted flare system.

2. The Main Flare shall be operated with a variable speed fan.

C. Emission Limitations 

1. The Permittee shall not discharge or cause the discharge of emissions from 

the Main Flare into the atmosphere in excess of the following the emission 

limitations, based on a cumulative 365-day rolling total. 

SO2 NOx CO VOC 

60.0 tpy 13.4 tpy 73.0 tpy 95.4 tpy 

2. The Permittee shall calculate the 365-day rolling emissions totals for SO2, 

NOx, CO, and VOC each day for the Main Flare. 

3. The Permittee shall not use the Field Flares to circumvent the emission 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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limitations in Condition IX.C.1. 

4. All emissions during all modes of operation (including, but not limited to, 

emissions during periods of startup, shutdown, or malfunction) shall be 

used in determining compliance with the emission limitations in Condition 

IX.C.1. 

D. Main Flare Operational Requirements 

1. The Permittee shall install, operate and maintain an automatic air-assisted 

flare system on the Main Flare, pursuant to the provisions of 40 CFR § 

60.18(c)(5) and (f)(6). 

2. The Permittee shall operate and maintain the Main Flare in compliance 

with 40 CFR § 60.18(c)(l), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (f)(1) through 

(f)(4), and (f)(6). 

3. The Main Flare shall be operated with a flame present at all times when 

emissions may be vented to them. 

4. The Permittee shall comply with the following requirements for ensuring 

proper combustion efficiency: 

(a) The Main Flare shall be operated with a variable speed fan. 

(b) The net heating value air assist dilution parameter (NHVdil) shall be 

greater than or equal to 24.4 BTU/ft2

, calculated as follows: 

ܨܦ ൌ ܳ௩௚ ൈ ܦ݅ܽ݉

ܳ௩௚ ൅ ܳ௦ ൅ ܳ௣௥௘௠௜௫ ௔௜௥ ൅ ܳ௣௘௥௜௠௘௧௘௥	௔௜௥

(Eqn 1) 

ܰܪܸௗ௜௟ ൌ ܰܪܸ௩௚ ൈ ܨܦ) Eqn 2) 

where: 

DF = Dilution factor, feet (ft). 

Qvg = Volumetric flow rate of the flare vent gas, scfm. 

Qs = Cumulative volumetric flow of total steam, scfm. 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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Qpremix air = Cumulative volumetric flow of premix assist air, scfm

Qperimeter air = Cumulative volumetric flow of perimeter assist air, scfm. 

Diam = Diameter of the flare vent gas release stack, ft. 

NHVvg = Net heating value of flare vent gas, BTU/scf.

NHVdil = Net heating value air assist dilution parameter. 

5. The Permittee shall also perform any necessary operations to minimize 

emissions so that emissions are at or below the emission limits specified in 

this Permit. 

E. Monitoring, Testing, and Emissions Calculations 

1. The Permittee shall use the following requirements to determine 

compliance with the emission limitations in Condition IX.C.1 for the Main 

Flare. 

(a) The Permittee shall measure and record the H2S concentration in the 

field gas at the Facility in each calendar month at the inlet to the 

Facility’s former gas processing plant where the Main Flare is located. 

(b) The Permittee shall continuously measure and record the volume of 

gas combusted in the Main Flare. 

(c) The Permittee shall install, operate and maintain continuous 

monitoring systems on the Main Flare for the usage of pilot gas and 

purge gas (other than nitrogen or other inert gas) by the Main Flare, in 

standard cubic feet per minute (SCFM). Readings shall be taken at 

least once every 5 minutes and the average hourly values shall be 

recorded on an hourly and daily basis. 

(d) Each and every calendar day, the Permittee shall calculate and record 

the daily emissions from the Main Flare based on the last recorded 

measurement of H2S concentration in the field gas at the Facility and 

that day’s recorded volume of gas combusted in the Main Flare. 

(e) Each and every calendar day, the Permittee shall calculate the 365-day 

rolling total of emissions of SO2, NOx, CO, and VOC for the Main 

Flare. Each 365-day rolling total shall be calculated using data from 

the previous 365 days. The Permittee shall maintain all records of 

actual operating data and calculations. 

(f) If the Permittee is unable to measure the volume of gas combusted in 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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the Main Flare on any day, the volume of gas for that day shall be 

deemed to be equal to the daily average volume of gas combusted in 

the Main Flare based on the previous 12 months’ emissions data. 

However, the use of this daily average as substitute data neither 

relieves nor excuses the Permittee from complying with the sampling, 

data collection, and monitoring requirements. 

2. The Permittee shall use the following requirements to determine 

compliance with the operating limitations in Condition IX.D.4 for the 

Main Flare. The Permittee shall calculate and record the net heating value 

air assist dilution parameter of the field gas being combusted in the Main 

Flare as follows. 

(a) The Permittee shall continuously measure and record the following in 

the Main Flare: 

(1) The volume of field gas combusted; 

(2) The volume of perimeter assist air used; and 

(3) If pre-mix assist air is used, the volume of premix assist air 

used. 

(b) The flow rate monitoring systems must be corrected for the 

temperature and pressure in standard conditions (i.e., a temperature of 

20 °C [68°F] and a pressure of 1 atm). 

(c) The Permittee shall automatically supply supplemental fuel to the 

Main Flare if the field gas does not have sufficient heating value. 

(d) Continuous pressure/temperature monitoring system(s) and 

appropriate engineering calculations may be used in lieu of a 

continuous volumetric flow monitoring systems provided the 

molecular weight of the gas is known. For assist air, use a molecular 

weight of 29 pounds per pound-mole. For flare vent gas, molecular 

weight must be determined using compositional analysis. 

(e) The Permittee shall install a monitoring system capable of calculating 

and recording the net heating value air assist dilution parameter of the 

field gas being combusted in the Main Flare in sixty-minute averages, 

rolled every five minutes. 

(f) The Permittee shall determine the net heating value of flare vent gas 

(NHVvg) using 40 CFR 60.18(f)(3). 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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3. The Permittee shall continuously monitor the Main Flare for the presence 

of a flare pilot flame using a thermocouple or any other equivalent device 

to detect the presence of a flame, which monitoring shall be conducted in 

accordance with 40 CFR 60.18(f)(2). The heat sensing monitoring device 

shall be operated at all times. The Main Flare shall be equipped with an 

alarm that informs Facility operators of any period when a pilot flame is 

not present in the flare and no gas shall be sent to the flare until a pilot 

flame is restored. 

4. The Permittee shall operate the Main Flare with no visible emissions, 

except for periods not to exceed a total of 5 minutes during any 2 

consecutive hours. EPA Test Method 22 in Appendix A of 40 CFR Part 

60 shall be used to determine the compliance of flares with the visible 

emission provisions. The observation period is 2 hours and shall be used 

according to Method 22. The Permittee shall perform monthly visible 

emissions tests during a flaring event using Method 22. 

F. Operation and Maintenance of Main Flare and Compressors 

1. The Permittee shall at all times and to the extent practicable, including 

during periods of startup, shutdown, Malfunction, CO2 Breakthrough, 

Scheduled Maintenance, or unscheduled maintenance of the Facility’s 

compressors, operate and maintain the compressor station equipment and 

Main Flare in a manner consistent with good air pollution control practices 

for minimizing emissions. 

2. The Permittee shall comply with the provisions of the Operations and 

Maintenance Plan in Appendix A of this PSD Permit. The Permittee’s 

failure to comply with any requirement of the Operations and Maintenance 

Plan shall constitute a violation. 

3. The Permittee shall follow the procedures for the inspection of the 

Facility’s compressors and associated equipment as set forth in the Life 

Cycle Maintenance Plan in the Operations and Maintenance Plan in 

Appendix A of this PSD Permit, and shall maintain inspection logs at the 

Facility documenting that these inspections have been conducted. 

4. The Permittee shall maintain daily records at the Facility regarding 

operation of the Facility’s compressors on a Daily Plant Reading Form in 

the Operations and Maintenance Plan in Appendix A of this PSD Permit. 

5. The Permittee shall maintain a supply of designated spare parts for the 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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Facility’s compressors and associated equipment that includes all of the 

equipment on the Spare Parts List in the Operations and Maintenance Plan 

in Appendix A of this PSD Permit. 

6. After using equipment on its Spare Parts List, the Permittee shall replace 

such equipment as expeditiously as possible. The Permittee shall place a 

purchase order for such equipment within 45 days after it is used. 

7. The Permittee shall conduct training of Facility operators in accordance 

with the Training Program for Plant Operators in Section IV of the 

Operations and Maintenance Plan in Appendix A of this PSD Permit. The 

Permittee shall maintain records documenting that the training has been 

conducted. 

8. The Permittee shall retain copies of inspection logs and other records 

required by Section IX.F (Operations and Maintenance of Main Flare and 

Compressors) of this PSD Permit. 

9. The Permittee shall maintain inspection, maintenance and repair log(s) or 

other similar records and identify any occasion when the Permittee was 

unable to carry out its established maintenance procedures, with 

explanation. 

G. Root Cause Analysis 

1. No later than 72 hours after an event first qualifies as a Flaring Incident, 

the Permittee shall notify by telephone, at (415) 947-8700, the Manager of 

the Air/TRI Enforcement Office, Enforcement Division of EPA Region 

IX, of such Flaring Incident. Telephone notification shall be followed by 

a detailed written notification to EPA, at the address in Condition X.C of 

this PSD Permit, made within seven (7) working days after the event first 

qualifies as a Flaring Incident. 

2. For a Flaring Incident caused by Scheduled Maintenance or a CO2

Breakthrough, the Permittee shall submit a report to EPA, at the address in 

Condition X.C of this PSD Permit, no later than sixty (60) days following 

the end of such a Flaring Incident that sets forth the following information 

listed below. Except for those Flaring Incidents caused by Scheduled 

Maintenance or a CO2 Breakthrough, the Permittee shall conduct a Root 

Cause Analysis in accordance with the Root Cause Failure Analysis 

Program in Appendix B of this PSD Permit to evaluate the cause of each 

Flaring Incident and shall submit a report to EPA, at the address in 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

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Condition X.C of this PSD Permit, no later than sixty (60) days following 

the end of a Flaring Incident, that sets forth all of the following: 

(a) The date and time that the Flaring Incident started and ended. To the 

extent that the Flaring Incident involved multiple releases either within 

a twenty-four (24) hour period or within subsequent, contiguous, nonoverlapping twenty-four (24) hour periods, the Permittee shall set forth 

the starting and ending dates and times of each release; 

(b) An estimate of the quantity of SO2 that was emitted and the 

calculations that were used to determine that quantity; 

(c) The steps, if any, that the Permittee took to limit the duration and/or 

quantity of SO2 emissions associated with the Flaring Incident; 

(d) Except for those Flaring Incidents caused by Scheduled Maintenance 

or a CO2 Breakthrough, a detailed analysis that sets forth the Root 

Cause and all contributing causes of that Flaring Incident, to the extent 

determinable; however, if a Flaring Incident is caused by Scheduled 

Maintenance or CO2 Breakthrough, then the Permittee need only 

identify the Root Cause as Scheduled Maintenance or CO2

Breakthrough (whichever is applicable), and either (i) describe the 

nature of the work done for Scheduled Maintenance or (ii) identify the 

specific wells that most likely experienced the CO2 Breakthrough; 

(e) An analysis of the measures, including possible design, operational, 

and maintenance changes, that are available to reduce the likelihood of 

a recurrence of a Flaring Incident resulting from the same Root Cause 

or contributing causes in the future. If the Permittee concludes that 

corrective action(s) is (are) required under Section IX.H (Corrective 

Action) of this PSD Permit, the report shall include a description of the 

action(s) and, if not already completed, a schedule for its (their) 

implementation, including proposed commencement and completion 

dates. If the Permittee concludes that corrective action is not required 

under Section IX.H (Corrective Action) of this PSD Permit, the report 

shall explain the basis for that conclusion; 

(f) To the extent that investigations of the causes and/or possible 

corrective actions still are under way on the due date of the report, a 

statement of the anticipated date by which a follow-up report fully 

conforming to the requirements of Conditions IX.G.2.d and IX.G.2.e 

of this PSD Permit will be submitted. Nothing in this Permit 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

15

Condition shall be deemed to excuse the Permittee from its 

investigation, notification, reporting, and corrective action obligations 

in this PSD Permit for any Flaring Incident that occurs after the 

Flaring Incident for which the Permittee has requested an extension of 

time under this Permit Condition.

(g) To the extent that completion of the implementation of corrective 

action(s), if any, is not finalized at the time of the submission of the 

report required under this Permit Condition, then, by no later than 

thirty (30) days after completion of the implementation of corrective 

action(s), the Permittee shall submit a report identifying the corrective 

action(s) taken and the dates of commencement and completion of 

implementation. 

H. Corrective Action 

1. In response to any Flaring Incident, the Permittee shall take, as 

expeditiously as practicable, such interim and/or long-term corrective 

actions, if any, as are consistent with good engineering practice to 

minimize the likelihood of a recurrence of the Root Cause and all 

contributing causes of that Flaring Incident. 

I. Compliance Reporting 

1. Within thirty (30) days following the end of each calendar semiannual 

period (i.e., January 1 to June 30, and July 1 to December 31), the 

Permittee shall submit to EPA a semiannual report. 

2. All semiannual reports shall be signed and affirmed by a responsible 

official, and bearing the certification statement as follows: 

“I certify under penalty of law that I have examined and am familiar with 

the information submitted in this document and all attachments and that 

this document and its attachments were prepared either by me personally 

or under my direction or supervision in a manner designed to ensure that 

qualified and knowledgeable personnel properly gathered and presented 

the information contained therein. I further certify, based on my personal 

knowledge or on my inquiry of those individuals immediately responsible 

for obtaining the information, that the information is true, accurate, and 

complete. I am aware that there are significant penalties for submitting 

false information, including the possibility of fines and imprisonment for 

knowing and willful submission of a materially false statement.” 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

16

3. All semiannual reports shall include the following information: 

(a) A list of the rolling 365-day cumulative Main Flare emissions for each 

day in that semiannual period; 

(b) A list of each day in the semiannual period when the emissions limits 

that apply to the Main Flare were exceeded and, for each such day, the 

limit(s) exceeded and the amount(s) of excess emissions; 

(c) A list of all emissions for the semiannual period that the Permittee 

claims are attributable to Malfunctions; 

(d) A list of all emissions for the semiannual period that may be 

attributable to CO2 Breakthroughs, Scheduled Maintenance, or 

unscheduled maintenance of the Facility’s compressors; 

(e) The date(s) and time(s) during the semiannual period when the 

thermocouple or flow meter associated with the Main Flare was 

inoperative; 

(f) The date(s) and time(s) during the semiannual period when the 

Permittee failed to measure or record the H2S concentration in the field 

gas at the Facility or failed to continuously measure or record the 

volume of gas combusted in the Main Flare; 

(g) A certification that during the semiannual period the Permittee 

operated and maintained the compressor station equipment and Main 

Flare in a manner consistent with good air pollution control practices 

for minimizing emissions, and performed all of the obligations 

(including, but not limited to, inspection and training obligations) 

contained in the Operations and Maintenance Plan in Appendix A of 

this PSD Permit; 

(h) A certification that the Field Flares have not been used to circumvent 

the emission limits that apply to the Main Flare; 

(i) A list of total emissions from the Field Flares and the reason for 

Flaring; and 

(j) Any and all reports generated from the root cause analysis and corrective 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

17

action program of Conditions IX.G and IX.H of this PSD Permit.

J. Recordkeeping Requirements 

1. The Permittee shall maintain a file of all records, data, measurements, 

reports, and documents related to operation of the Facility. All records 

shall be in a permanent form suitable for inspection. 

2. The Permittee shall retain the following records at the facility for a period 

of at least five (5) years from the date of monitoring, sampling, 

measurement, or reporting. All applicable records shall be maintained at 

the nearest manned facility and shall be readily accessible. 

(a) Each 365-day rolling total for SO2, NOx, CO, and VOC emissions; 

(b) Emissions calculations of SO2, NOx, CO, and VOC for the Main Flare, 

which shall include the emission factors, operating data and other 

supporting documentation that the Permittee used to calculate 

emissions of each pollutant; 

(c) Monthly H2S concentration in the field gas at the Facility; 

(d) Daily total volume of gas combusted in the Main Flare; 

(e) Gas throughput; 

(f) Records of gas analyses and testing; 

(g) Records of flare design for the Main Flare in accordance with 40 CFR 

60.18 (including whether the flare is steam-assisted, air-assisted, or 

non- assisted); 

(h) Semiannual reports required in Section IX.I (Compliance Reporting), 

of this PSD Permit; 

(i) A written log of the monthly inspections of the Main Flare containing 

the following information for each inspection: (i) the date and time of 

the inspection, and the name of the observer; (ii) a description of any 

corrective actions taken and repairs made; and (iii) the date(s) of 

corrective actions and repairs; 

(j) Visible emission readings, heat content determinations, flowrate 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

18

measurements, and exit velocity determinations made; 

(k) Periods when the pilot flame is absent or spark igniter(s) is inoperable; 

(l) Any and all reports generated from the root cause analysis and 

corrective action program, which shall include the following: 

(1) Date, time and duration of flaring; 

(2) Description of the event, including the flare(s) involved in the 

event and a discussion of the cause(s) and probable cause(s) of 

the event; 

(3) Confirmation that the flare(s) functioned properly, i.e., a flame 

was present and any visible emissions that occurred were in 

compliance with 40 CFR 60.18(f)(1); 

(4) Corrective actions taken during the event; and 

(5) A description of any actions taken to prevent or reduce the 

likelihood of similar future occurrences. 

(m)Inspection, maintenance and repair log(s) or other similar records; and 

(n) Any other records and reports required by this PSD permit. 

X. AGENCY NOTIFICATION 

A. Permit Applications & Permit-Related Requests. 

The owner or operator shall submit permit applications, permit amendments, and 

other applicable permit information, which includes but not limited to installation 

of control equipment, replacement of an emissions unit, and changes that 

contravene permit terms, to: 

Director, Air Division (Attn: AIR-3) 

U. S. Environmental Protection Agency Region 9 

75 Hawthorne Street 

San Francisco, CA 94105 
McElmo Creek Unit Oil Production Facility 

Proposed Amended PSD Permit No. NU 05-01 

October 2014 

19

B. Submittals to Navajo Nation Environmental Protection Agency. 

The owner or operator shall submit copies of all correspondence required by this 

PSD Permit to: 

Navajo Nation Environmental Protection Agency 

Air Quality Control Program and Operating Permits Program 

P.O. Box 529 

Fort Defiance, AZ 86504 

C. Compliance Reporting. 

Unless otherwise directed by the EPA or this PSD Permit, the owner or operator 

shall submit a copy of all test plans, reports, certifications, notifications, and other 

information pertaining to compliance with this PSD Permit to the following 

address. All notices and submissions shall be sent by certified mail, express mail, 

or similar overnight mail delivery with return receipt requested and addressed to: 

Director, Enforcement Division (Attn: ENF-2-1) 

U.S. Environmental Protection Agency, Region IX 

75 Hawthorne Street 

San Francisco, California 94105 

All notices and submission made in accordance to Condition X.C.1 shall be 

deemed submitted on the date postmarked. All notices and submissions made in 

accordance to Condition X.C.1 shall be signed and affirmed by a responsible 

official, and bearing the certification statement as follows: 

“I certify under penalty of law that I have examined and am familiar with the 

information submitted in this document and all attachments and that this 

document and its attachments were prepared either by me personally or under my 

direction or supervision in a manner designed to ensure that qualified and 

knowledgeable personnel properly gathered and presented the information 

contained therein. I further certify, based on my personal knowledge or on my 

inquiry of those individuals immediately responsible for obtaining the 

information, that the information is true, accurate, and complete. I am aware that 

there are significant penalties for submitting false information, including the 

possibility of fines and imprisonment for knowing and willful submission of a 

materially false statement.” 
APPENDIX A

MCELMO CREEK UNIT 

OPERATIONS & MAINTENANCE PLAN

McElmo Creek Unit Oil Production Facility

PSD Permit Number: NU 05-01

This document shall apply to and be binding upon the owner(s) and operator(s) of 

the McElmo Creek Unit Oil Production Facility, including the Resolute Natural 

Resources Company.
MCELMO CREEK UNIT OPERATIONS & MAINTENANCE PLAN

CONTENTS

I. Process Overview and Operating Procedures

II. Routine Monitoring / SurveiUance

III. Maintenance Plan

IV. Training Program for Plant Operators

V. Reference Documentation

VI. Appendices

I. Life Cycle Maintenance Plan McElmo Compressors

HOS 6. HOS 4. ACID GAS A&B

2. Daily Plant Reading Form

3. Isolation and Operating Procedures

HOS 6,11054, ACID GAS A&B

4. Compressor Troubleshooting Guide

5. Spare Parts List -HOS 4 and HOS 6
Process Overview and Operating Procedures

The McElmo Creek Compression Plant serves tertiary recovery operations for the

MeElmo Creek Field. The goal of the Plant is to receive produced gas through a

gathering system, pressure the gas up to a suitable working pressure then re-inject

the gas to maintain reservoir pressure. The natural gas is injected with produced

water in a dual injection system. Due to varying water injection demands in the

field, and to the number of wells being serviced at any time, the Plant inlet

volume can vary between 10 and 18 million standard cubic feet per day

(MSCFD).

To describe the plant process in more detail, the gas is processed in three main

steps: inlet separation, compression and re-injection.

Inlet Separation. The inlet separation consists of an inlet slug receiver which

collects free liquids. The gas then passes through filter vessels which collect any

incoming solids.

Compression. The Plant consists of four high-speed electrically-driven

reciprocating compressors which utilize 6300 Brake Horsepower (BHP). Each

compressor consists of four stages which raise the pressure of the incoming gas

from 40 psig to 2900 psig. Each stage has a dedicated aerial cooler and liquid

scrubber vessel. On the largest compressor, inter stage dehydration takes place to

remove water for corrosion mitigation.

Isolation and operating procedures for the Acid Gas A&B and HOS 4 and HOS 6

compressors are included in the appendix to this report.

Re-Injection. The four units discharge into a single header, where purchased CO2

is co-mingled to achieve a daily injection goal of 24 MSCFD. The gas is then

distributed to the field. During Plant upsets, additional CO2 is purchased to meet

the daily injection goal.

During Plant upsets or compressor downtime events, a portion or all of the inlet

volume to the Plant is automatically diverted to flare until the problem is

corrected.

II. Routine Monitoring / Surveillance

The plant is manned 24 hours a day by operators who work 12-hour shifts. The

operators make plant rounds each shift, during which key operating parameters of

the compressors and supporting equipment are monitored. The following are

examples of the parameters that are recorded during a shift:
r Overall Plant inlet and discharge volumes

> CO2 purchased volumes

> Flared volumes

r Discharge pressure

> Compressor run times

From the Operator’s daily run time report (example attached in appendix to this

report), a compressor reliability spreadsheet and flare volume report are updated.

The Operators monitor key operating parameters for the compressors to ensure

the units are operating within prescribed operating limits based on ExxomMobil

andoriginal equipment manufacturer (OEM) standards. Examples of parameters

that the Operators record include:

> Compressor suction and discharge temperatures and pressures

> Scrubber liquid levels

The detailed parameters that are checked during the shift are included in the

maintenance plan and operating procedures included in the appendix to this

report.

The operators are very familiar with prescribed operating limits, as this is part of

their training. Should the operator observe a parameter that is out of specification,

appropriate corrective action is taken. For example, if compressor suction

temperature is too low, the operator will open cooler louvers to adjust. If the

Operator cannot resolve the issue through organized troubleshooting, he then

contacts Plant Engineering, Maintenance and Reliability (M&R) Supervisor

andlor the contract mechanic to resolve the problem.

III. Maintenance Plan

ExxonMobil utilizes an Equipment Strategies Program (ESP) approach to

ongoing reliability improvements. The ESP includes the following items:

1. Periodic maintenance that will be performed on the equipment.

2. Predictive maintenance that is to be done on the equipment.

3. Equipment life cycle

4. Overhaul schedule

5. Spare parts inventory

The appendix to this report contains the specific steps in the Life Cycle Maintenance Plan

for the McElmo equipment strategy developed for these types of compressor units. The

ESP is applied to the compression equipment and the reliability efficiency ofthe

compressors is measured. The process consists of Periodic Maintenance, Predictive
Maintenance. Equipment Life Cycle and Overhaul Schedule and the Life Cycle

Maintenance Model which describes the various levels within the program and how they

are applied.

A. Periodic Maintenance (PM’S)

Periodic maintenance begins with daily inspections of the compressors, which are

performed by the Plant Operator. In addition to monitoring process parameters,

the following daily equipment checks are made:

> The compressor piping, inter stage coolers and block valves and compression

valves are inspected for fluid leaks

> Oil and water levels are monitored

> Vibration levels on the motors and compressor frames are monitored

> General observations of physical conditions (i.e., unusual sounds) of the

compressor and electric motor are noted.

Additional periodic maintenance includes:

> Compressor performance analysis (Beta)

> Lube oil analysis data to determine the condition of the electric motor,

compressor and all of the auxiliary equipment.

> Foundations and equipment mounts are checked for cracks and correct make

up torque.

> Compressor Piping is inspected for external damage

> Corrosion coupons are pulled and monitored

Annual Inspections involve performing functional tests on the instrument and

controls systems. This includes testing safety devices, vibration probes, safety

alarms and safety shutdowns. There are PM’s frequencies that extend past a year,

such as coolant replacement and lube oil replacement. The predictive

maintenance is the tool that is used to decide ifthis work is required.

B. Predictive Maintenance

Predictive maintenance involves performing detailed inspections for internal

wear. The inspections reveal the remaining life of a compressor component.

Some examples ofthe predictive maintenance include inspecting the compressor

main bearings, compressor cylinder and piston inspections, electric motor

winding/insulation inspection, crankshaft web deflections and electric motor

bearing inspection.

The results of predictive maintenance inspections are recorded, trended and used

to determine when the next major maintenance is due.
C. Equipment Life Cycle and Overhaul Schedule

The Equipment Strategy Program assists in determining the life cycle for the

compressors. This life cycle information and the data taken during the predictive

maintenance helps us determine when the electric motor and compressor should

be overhauled. An overhaul involves opening up the machine and replacing all

worn parts with new or refurbished parts. Overhauls can take up to one month or

more to complete. The compressor is restored as much as possible and another life

cycle begins. The common practice is to hire additional contract mechanics to

perform this work. A normal life cycle for a McElmo compressor is 40,000

hours. This equates to the compressor and electric motor being overhauled about

every 5 to 6 years. Overhauls are recorded and all of the data and measurements

kept on file. These files are kept on site and with the contractor that performed

the work.

D. Life Cycle Maintenance Model

The section below provides a description of the type of activities planned for each Level.

Note Levels 5 and 6 are subject to the Risk Based Work Selection process prior to

committing to the work. The Risk Based Work Selection process is based on earlier and

ongoing data obtained and analyzed during the maintenance cycles.

LEVEL 1 OPERATIONS SURVEILLANCE AUTONOMOUS MAINTENANCE

Collection and review of process parameters along with routine observation of machinery

operations.

LEVEL 2 RUNTIME BASED TESTING PREDICTIVE MAINTENANCE

Scheduled collection and monitoring of both crankcase lubricant for effects of

degradation.

LEVEL 3 CONDITION MONITORING PREDICTIVE MAINTENANCE

Scheduled analysis of the engine and compressor performance, vibration profile, and

energy utilization.

LEVEL 4 INTERMEDIATE INTERVENTION PREVENTIVE MAINTENANCE

Scheduled driver tune-up and testing !reconditioning of safety devices. Minimally

invasive, downtime required.

LEVELS PREEMINENT INTERVENTION PREVENTIVE MAINTENANCE

Scheduled inspection / reconditioning of minor wear components in both the driver and

driven equipment. A suite of maintenance task considerations and milestone targets that

are subject to Risk Based Work Selection review prior to execution.

LEVEL 6 ZERO HOUR TURNAROUND PREVENTIVE MAINTENANCE

Scheduled overhaul of driver and replacement of major wear components. A suite of

maintenance task considerations and milestone targets that are subject to Risk Based

Work Selection review prior to execution.
IV. Training Program for Plant Operators

NEW OPERATIONS PERSONNEL - NO PRIOR MCELMO PLANT

EXPERIENCE

The plant training for new operations persons with no prior McElmo Relnjection Plant

experience consists of the following:

Training for one month with another Plant Operator in the Reinjection Plant. Trainee

must be scheduled for only day shifts until qualified.

Training will be conducted on the following:

• Plant operation, start up, shutdown and emergency procedures

• Surveillance requirements for plant operations personnel

• First line maintenance responsibilities

• Regulatory requirements, such as upset reporting and regulatory

documentation

• Required safe work practices, permits and methods used

• Required communication procedures, including handling of community

inquiries

• The Plant Supervisor will evaluate the individual’s performance and is required to

approve the trainee for release from the training program

• Following the training program the first shifts must be scheduled during day shift

OPERATOR WITH PRIOR PLANT EXPERIENCE (Out of the Plant >1 year)

• Ensure all ongoing required training has been completed and reviewed

• Review all procedures, including plant operation, start up, shutdown and emergency

procedures

• Work with another Operator for one week during day shift

• The Plant Supervisor will evaluate the individual’s performance and is required to

approve the trainee for release from the training program

OPERATOR TRAINING ON CONSENT DECREE

Following the effective date of the Consent Decree existing operators will be trained on the

following sections of the Consent Decree. New operators will be trained on these sections as part

of their overall plant training while the consent decree is in effect:

• Paragraph 9a - Emission Limits as it relates to their duties

• Paragraph 10 -Monitoring as it relates to their duties

• Paragraph 11 -Contents of the O&M plan as it relates to their duties

• Paragraph 12- Root Cause Analysis as it relates to their duties

• Paragraph 31 -Right of Entry as it relates to their duties
V. Reference Documentation

The following documentation is readily available at the facility:

> Startup and isolation procedures for each unit (copies included in the appendix

of this report)

> Original Equipment Manufacturer (OEM) maintenance manuals for each unit

> Piping and instrument diagrams (P&ID’s) for the plant, updated to reflect

DESOP review in May 2003

> Operating limits tables for each compressor, compiled from OEM

recommendations and ExxonMobil practices (copies included in the operating

procedures in the appendix of this report)

> All operator log sheets

> Compressor Troubleshooting Guide (copies included in the appendix of this

report)
VI. Appendices

1. Life Cycle Maintenance Plan McElmo Compressors

HOS 6, HOS 4, ACID GAS A&B

2. Daily Plant Reading Form

3. Isolation and Operating Procedures

HOS 6. HOS 4, ACID GAS A&B

4. Compressor Troubleshooting Guide

5. Spare Parts List -HOS 4 and HOS 6
APPENDIX 1

Life Cycle Maintenance Plan

McElmo Compressors

HOS 6, HOS 4, ACID GAS A&B
The following pages describe the Level I tasks performed by the plant operators during

each shift.

Critical monitoring devices for pressure. temperature, level, and vibration are equipped

with High and High High alarms. High alarms warn operators of a process malfunction

allowing operators to troubleshoot the process for operational or mechanical

malfunctions. Operational problems are corrected by an operator allowing equipment to

continue operating. Mechanical problems that can be easily repaired by the operator are

repaired. Mechanical problems that cannot be repaired by the operator are communicated

to the supervisor on duty and a decision is made to either shut down that piece of

equipment or to continue running, depending on the criticality of the equipment andlor

the severity of the malfunction, until repairs can be made. Monitoring frequency of the

equipment will be increased, again depending on the criticality of the equipment or the

severity of the malfunction until repairs can be made.

High High alarms will automatically shutdown equipment ensuring the safety of

personnel, preventing damage to equipment, and minimizing impact on the environment.

The supervisor on duty is notified of a shutdown and a decision is made whether to repair

immediately, depending on day (weekend, weekday), time of day(night tour or day tour)

availability of parts and personnel necessary to perform repairs, in order to minimize

impact on the environment.
Routine Monitoring I Preventative Maintenance Plan

EMAINTENANCE PLAN I I

HOS6

LEVEL I OPERATION SURVEILLANCE —

TASK rAsKDEscR1pT1oN- - t4k ACTIVITYL’ FREQUENCYjSKILV

COMPRESSOR - Z

Li-Ti 1ST SUCTION CHECK 12 HOURS 1OPERATIONS

TEMP &

PRESSURE

L1-T2 1STDISCHARGE CHECK 12HOURS OPERATIONS

TEMP &

PRESSURE

L1-T3 2ND SUCTION CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T4 2ND DISCHARGE CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

Li-T5 3RDSUCTION CHECK 12HOURS OPERATIONS

TEMP &

PRESSURE

L1-T6 3RD DISCHARGE CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T7 4TH SUCTION CHECK 12 HOURS OPERATIONS

TEMP&

PRESSURE

L1-T8 14TH DISCHARGE CHECK 12 HOURS OPERATIONS

TEMP&

PRESSURE

L1-T9 JACKET WATER LEVEL CHECK 12 HOURS OPERATIONS ; LEVEL I

Li-Tb JACKET WATER PRESSURE CHECK 12 HOURS OPERATIONS

PRESSURE

L1-T11 JACKET WATER TEMP IN lOUT CHECK TEMP 12 HOURS OPERATIONS

L1-T12 FRAME OIL LEVEL CHECK 12 HOURS OPERATIONS

LEVEL

L1-T13 COMP OIL PRESSURE CHECK 12 HOURS OPERATIONS

PRESSURE

L1-T14 LUBE OIL LEVEL UCON - 1 CHECK 12 HOURS OPERATIONS

LEVEL

L1-T15 HI/LOLUBEOILPRESSURE(FOR CHECK 12HOURS OPERATIONS

CYLINDERS) PRESSURE

L1-T16 VIBRATION ON ISTSTAGEWEST/EAST CHECK 12 HOURS OPERATIONS

VIBRATION

L1-T17 VIBRATION ON 2ND STAGE WEST/EAST CHECK :12 HOURS OPERATIONS

! VIBRATION

L1-T18 VIBRATION ON 3RD STAGE CHECK 12 HOURS OPERATIONS

! VIBRATION

L1-T19 VIBRATION ON 4TH STAGE CHECK 12 HOURS OPERATIONS : VIBRATION

L1-T20 VIBRATION ON MOTOR WEST! EAST CHECK 12 HOURS OPERATIONS

(GEARBOX) VIBRATION
L1-T21 VIBRATION ON MOTOR (GEAIBOX) CHECK 12 HOURS OPERATIONS

VIBRATION k SCRUBBERS# 4 t’ k

L1-T22 1ST/2NDSTAGESCRUBBERS CHECK 12HOURS OPERATIONS

LEVEL

L1-T23 3RD/4THSTAGESCRUBBERS CHECK 12HOURS OPERATIONS

LEVEL
MAINTENANCE PLAN

HOS4

LEVEL I OPERATION SURVEILLANCE - ti-At

TASK TASKEDESCRjPTION ACTIVITY FREQUENC’( SKILL!.

COMPRESSOR .-sa

Li-TI 1ST SUCTION CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T2 1ST DISCHARGE CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T3 2ND SUCTION CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T4 .2ND DISCHARGE CHECK 12 HOURS OPERATIONS

: . 1EMP&

PRESSURE

L1-T5 3RDSUCTION CHECK 12HOURS OPERATIONS

•TEMP &

PRESSURE

L1-T6 3RD DISCHARGE CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T7 4TH SUCTION CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T8 4TH DISCHARGE CHECK 12 HOURS OPERATIONS

TEMP &

PRESSURE

L1-T9 JACKET WATER LEVEL CHECK 12 HOURS OPERATIONS

LEVEL

LI-Tb JACKET WATER PRESSURE CHECK 12 HOURS OPERATIONS

PRESSURE

Li-Ti 1 JACKET WATER TEMP IN / OUT CHECK TEMP 12 HOURS OPERATIONS

L1-T12 FRAME OIL LEVEL CHECK 12 HOURS OPERATIONS

LEVEL

L1-T13 COMP OIL PRESSURE (OFF CONTROL CHECK 12 HOURS OPERATIONS

PANEL) PRESSURE

Li-T14 LUBE OIL LEVEL UCON - 1 CHECK 12 HOURS OPERATIONS

LEVEL

L1-T15 HI/LO LUBE OIL PRESSURE (FOR CHECK 12 HOURS OPERATIONS

CYLINDERS)

L1-T16 AFTERCOOLER FAN ON HI / LO CHECK TEMP 12 HOURS OPERATIONS

Li-T17 VIBRATION ON MOTOR NW & SW CHECK 12 HOURS OPERATIONS

VIB RATION

Li-Tb 8 VIBRATION ON MOTOR NE & SE CHECK 12 HOURS OPERATIONS

VIBRATION

L1-T19 VIBRATION ON 1ST/2ND STAGE CHECK 12 HOURS OPERATIONS

VI B RATION

L1-T20 [VIBRATION ON 3RD / 4TH STAGE CHECK 12 HOURS OPERATIONS

VIBRATION
L1-T21 VIBRATION ON COMPRESSOR WEST CHECK 12 HOURS OPERATIONS

VIBRATION

SCRUBBERS

L1-T22 1ST/2NDSTAGESCRUBBERS CHECK 12HOURS OPERATIONS

LEVEL

L1-T23 3RD/4THSTAGESCRUBBERS CHECK 12HOURS OPERATIONS

LEVEL
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NOTE LEVELS 2 THROUGH 6 ARE THE SAME FORALL COMPRESSORS

TASK

LEVEL 2tIrsaVicIMEBASED

$TASKDESCRIPTION

TESTING (**R-

.ACTIVITY

1n

FREQIJENCV1SKIP

L2-T1 LUBE OIL ANALYSIS TEST 740 HOURS MECHANICAL

L2-T2 JACKET WATER ANALYSIS TEST 4000 HOURS MECHANICAL

LEVEL 3 CONDITIONMONITORING

TASK TASK DESCRIPTION ACTIVITY FREQUENCY

L3-T1 MOTOR-COMPRESSOR PERFORMANCE ANALYZE QUARTERLY MECHANICAL

ANALYSIS

L3-T2 HORSE POWER UTILIZATION RATIO ANALYZE QUARTERLY MECHANICAL

L3-T3 VIBRATION COMPRESSOR DRIVE ANALYZE QUARTERLY MECHANICAL

MOTOR BEARINGS

L3-T4 VIBRATION PRE I POST LUBE OIL PUMP ANALYZE QUARTERLY MECHANICAL

L3-T5 LOOSE FOUNDATION FASTENERS / VISUAL QUARTERLY MECHANICAL

CHOCKS INSPECTION

L3-T6 PRESSURE CASE VENT PIPING VISUAL QUARTERLY MECHANICAL

INSPECTION

L3-T7 COMPRESSOR JACKET WATER PIPING VISUAL QUARTERLY MECHANICAL

INSPECTION
LEVEL 4 INTERMEDIATE INTERVENTION

TASKSS.g TASIDESGRJPTION • %t4t ACTiVITY FREQUENC.* SKILI*L

L4-T1 COMPRESSOR CRITICAL SAFETY TEST QUARTERLY INSTRUMENT

DEVICES

L4-T2 MOTOR BEARING GREASE LUBRICATE QUARTERLY MECHANCIAL

L4-T3 CRANKCASE AND DRIVE TRAIN VISUAL QUARTERLY MECHANICAL

INSPECTION

L4-T4 JACKET WATER-LUBE OIL COOLER REPLACE QUARTERLY MECI-iANLCAL

BANK_FAN_BELT

L4-T5 LUBE OIL FILTERS REPLACE REPLACE AS MECHANICAL

NEEDED

I PER

ANALYSIS

L4-T6 CRANKCASE LUBE OIL REPLACE REPLACE AS MECHANICAL

NEEDED

PER

ANALYSIS

L4-T7 CRANKCASE LUBE OIL SUMP CLEAN AS NEEDED MECHANICAL

P ER

ANALYSIS

L4-T8 CRANKCASE LUBE OIL FEED LINES VISUAL AS NEEDED MECHANICAL

INSPECTION

L4-T9 JACKET WATER-LUBE OIL COOLER CLEAN AS NEEDED MECHANICAL

BANK (EXTERNAL)

L4-T1O GAS COMPRESSOR ROD (SCORING) VISUAL ANNUAL MECHANICAL

INSPECTION

L4-T1 1 ‘GAS COMPRESSOR PACKING CASE VISUAL ANNUAL [MECHANICAL

(ROD CENTERING) ‘INSPECTION

L4-T12 GAS COMPRESSOR WIPER PACKING VISUAL ANNUAL MECHANICAL

(LEAKAGE) INSPECTION

L4-T13 GAS COMPRESSOR PACKING CASE VISUAL ANNUAL MECHANICAL

(LUBE CONNECTIONS) INSPECTION

L4-T14 CROSSHEAD SHOE CLEARANCE CHECK & ANNUAL MECHANICAL

RECORD

L4-T15 TORQUE COMPRESSOR CRANK FRAME CHECK & ANNUAL MECHANICAL

FOUNDATION FASTENERS RECORD

L4-T16 TORQUE COMPRESSOR CYLINDER CHECK & ANNUAL MECHANICAL

DISTANCE PIECE FASTENERS RECORD

L4-T17 TORQUE CRITICAL CRANKCASE CHECK & ANNUAL MECHANICAL

FASTENERS RECORD

L4-T18 GAS COMPRESSOR ROD RUNOUT CHECK & ANNUAL MECHANICAL

RECORD

L4-T19 MOTOR WINDING POLARIZATION INDEX TEST& 250O0 VENDOR

RECORD HOURS SERVICE

L4-T20 MOTOR LEAD CONNECTIONS INSPECT & 25000 VENDOR

TORQUE HOURS SERVICE

L4-T21 MOTOR CONTACTOR TEST & 25000 VENDOR

INSPECT HOURS SERVICE
LEVEL 4 INTERMEDIATE INTERVENTION : ,te4J::

TASK: TASKOESCRIPTION: 7 ACTJVITYa% REQUENC S$JrflfiJCZJ

L4-T22 MOTOR CONTACTOR BUS STAB INSPECT & 25000 VENDOR

LUBRICATE HOURS SERVICE

L4-T23 SUPERVISORY RELAYS CALIBRATE & 25000 VENDOR

INSPECT HOURS SERVICE

L4-T24 MOTOR GROUND WIRE! CONNECTIONS INSPECT & 25000 MECHANICAL

TORQUE HOURS

LEVEL 5 PREEMINENTINTERVENTION.

TASK TASIQDESCRIPTION ‘ 1ACTIVIrnt4! IFREQUENG4jSKIPIr

L5T1 MAIN BEARING CLEARANCE CHECK & 36000 MECHANICAL

RECORD HOURS

L5-T2 CONNECTING ROD BEARING CHECK & 36000 MECHANICAL

CLEARANCE RECORD HOURS

L5-T3 CROSSHEAD PIN CLEARANCE CHECK & 36000 MECHANICAL

RECORD HOURS

L5-T4 GAS COMPRESSOR ROD PRESSURE INSPECT & 36000 MECHANICAL

PACKING CASE RECONDITION HOURS

L5-T5 GAS COMPRESSOR WIPER PACKING INSPECT & 36000 MECHANICAL

RECONDITION HOURS

L5-T6 GAS COMPRESSOR ROD PROFILE CHECK & 36000 MECHANICAL

RECORD HOURS

L5-T7 PROFILE COMPRESSOR CYLINDER CHECK & ‘36000 MECHANICAL

LINER RECORD HOURS

L5-T8 COMPRESSOR VALVES AND CAGES INSPECT & 36000 MECHANICAL

RECONDITION HOURS

L5-T9 FORCE FEED LUBRICATOR SYSTEM INSPECT & 36000 MECHANICAL

SERVICE HOURS

L5-T10 CRANKCASE RELIEF DOORS RECONDITION 36000 MECHANCIAL

HOURS

L5-T1 I COMPRESSOR ROD RUNOUT CHECK & 36000 MECHANICAL

RECORD HOURS

L5-T12 CRANKSHAFT WEB DEFLECTION CHECK & 36000 MECHANICAL

RECORD HOURS

L5-T13 DRIVE MOTOR BASE BOLT TORQUE CHECK & 36000 ‘MECHANICAL __________ RECORD HOURS

L5-T14 CRANKSHAFT THRUST BEARING CHECK & 36000 MECHANICAL ‘ RECORD HOURS

L5-T15 GAS COMPRESSOR PISTON, ROD, WEIGHT & 36000 MECHANICAL

NUT (BALANCE) RECORD HOURS

L5-T16 MOTOR DRIVE COUPLING CHECK & 36000 MECHANICAL

RECORD HOURS
I LEVEL 6;* ZERHOURIOVERHAUL

LTASK .1TASKZDESCRIPTION AaIvnv,.> FREQUENCY’ SKILL

IL6T1 MAIN BEARINGS REPLACE 72000 MECHANICAL

HOURS

L6-T2 CONNECTING ROD BEARINGS REPLACE 72000 MECHANICAL

HOURS

L6-T3 CONNECTING ROD BUSHINGS REPLACE 72000 VENDOR

HOURS SERVICE

L6-T4 CROSSHEAD PIN INSPECT 72000 MECHANICAL

HOURS

L6-T5 CROSSHEAD SHOES INSPECT 72000 MECHANICAL

HOURS

L6-T6 JACKET WATER PUMP RECONDITION 72000 MECHANICAL

HOURS

L6-T7 MAIN OIL PUMP RECONDITION 72000 VENDOR

HOURS SERVICE

L6-T8 CRANKSHAFT OIL SEAL REPLACE 72000 MECHANICAL

HOURS

L6-T9 MAIN LUBE OIL PUMP COUPLING INSPECT 72000 MECHANICAL

HOURS

LB-Tb CRANKSHAFT THRUST BEARING CHECK 72000 MECHANICAL

HOURS

LB-Tb I OIL THERMOSTAT ELEMENTS CHECK 72000 MECHANICAL

. HOURS

L6-T12 JACKET WATER THERMOSTAT REPLACE 72000 MECHANICAL

ELEMENTS HOURS I

L6-T1 3 GAS COMPRESSOR VALVE COVER INSPECT 72000 MECHANICAL

STUDS HOURS

L6-T14 GAS COMPRESSOR HEAD STUDS INSPECT 72000 MECHANICAL

HOURS
APPENDIX 2

Daily Plant Reading Form
EzinWEl-ftráncr

&

H. NAME:

DATE: I DATEREPORTING FOR:

yB PD72 Dji

4245 (HOSS-6)

4246 (AG.C-A)

4247(AGC.-B)

4249 (HOSS-4}

McuCO2’ruRcAsssMkT,Mothy2zi4l,ii*

TODAY’S Readings

YES TERDA I’S Readings

TOTAL

TOTAL COMPRESSOR VOL —

TOTAL INJECTION 4

DISCHARGE PRESSURE

YES TERDA Y’S Readings

(Øfl#J&arkrowq..,,.

TODA Y’S Readings

P3201 YESTERDA I’S P-9202 YESTERDA Y’S

CUMUL4 TIVE FLOW CUMULATIVE FLOW

YESTERDArSI’Boosw,stafion) TODAY’S t’BooSTaSWUOn) TOTAL MAKE UP TOTAL PRODUCED

MAKE UP READING MAKE UP READING

F&’tr

-J’a,

YESTERDA I’S TODAY’S TOTAL RUNTJME

RUNTIME P-9201 RUNTIME P-9201 P-9201

YESTERDAY’S TODAY’S TOTAL RUNTIME DISCHARGE

RUNTIME P-9202 RUNTIME P-9202 P-9202 PRESSURE

HEADER PRESSURE

APPENDIX 3

Isolation and Operating Procedures for:

HOS 6, HOS 4, ACID GAS A&B
ExxonMobil Production Isolation Procedure -

Aneth Operations File Name I-IOS6ISO

McElmo HOS$ COMPRESSOR Authorized Creek Unit ISOLATION PROCEDURE Gas Reinjecuon Facility Page 1 of 4

Equipment. # CM-12W

SCOPE This procedure describes the isolation, depressurization and returning of the

HOS-6 Compressor back to service.

REQUIREMENTS None

APPLICABLE HOS-6 Compressor Opearting Procedure

DOCUMENTS Pre-Start Safety Review Checklist (See Attachment)

SPECIAL None

EQUIPMENT

ENVIRONMENTAL For environmental concerns, contact the Field Foreman and the Operations

Compliance Technician.

SAFETY Locks must be used by Operations and Maintenance Personal

For applicable safety requirements, refer to the ExxonMoibl Production Safety Manual

and Material Safety Data Sheets (MSDS).

Care must be taken to completely depressure the compressor which may contain

explosive or sour gas.

Safety devices taken out of service or being returned to service MUST be logged in the Critical

Safety Device (CSD) log book in the Control Room.
Isolate the compressor for maintenance.

NOTE Refer to the HOS-6 Operating procedure for requirements to shutdown the compressor.

This procedure is for total compressor isolation. Dependant upon the maintenance work

required, specific cylinders or utilities may be isolated separately, while leaving the

remaining cylinders or utilities in service.

1.1 Ensure that the pre-lube oil pump is not running.

1 .2 De-energize the electrical breaker for the motor in the MCC building.

1.3 Close the 4th stage discharge isolation block valve.

1 .4 Close the 3rd stage suction valve downstream of the Glycol Contactor.

1.5 Close the 4th stage intercooler discharge block valve.

1.6 Close the 1st stage suction isolation block valves ( SDC-1 700)

• Change setpoint to zero on DCS PCV-1 700,

1.7 Close all isolation block valves on the PSV’s rack for the (1st, 2nd, 3rd and 4th

stages,etc)

1.6 Close the isolation block valve on the 1st Stage Suction Scrubber.

1.9 Close all isolation block valves for the closed drain

1.10 Close all isolation block valve for the open drain.

1.11 Place the H2S and LEL Detection system in the “calibration” mode in the Control Room.

NOTE While the 1125 and LEL Detection system is in the “calibration” mode, the sensors are still

active and MUST be monitored from the Control Room. Tag it with Pink BYPASS tag and

Log in the LOG BOOK.

ExxonMobii Production Isolation Procedure

Aneth Operations I File Name HDS6ISO

MeElmo Creek HOS-6 COMPRESSOR Authorized Umt

Gas Reinjecuon Facilit 3’ ISOLATION PROCEDURE Pane 2 of 4

Equipment. CM-1210

j All valves, switches and breakers referenced in this procedure MUST BE LOCKED

AND TAGGED per the Lock-out I Tag-out guidelines. I

I
n

ExxonMobil Production Isolation Procedure

I File Name HOS6ISO Aneth Operations HOS-6 COMPRESSOR Authorized MeElmo Creek Unit ISOLATION PROCEDURE Page 3 of 4 Gas Reinjection Facility

Equipment. # CM-1210

2. Depressurize the compressor for maintenance.

Ii WARNING Atmospheric vents will release process gas that contains LEL and H2S. ii

2.1 Open the blowdown valves on all stages to the Flare header to depressure the

compressor.

2.2 Close the blowdown valves on all stages to the Flare header.

2.3 Open the atmospheric vent valves on all 4 cylinder stages to verify depressurization.

2.4 Open the cylinder head and crank end vent valves to verify that the cylinders to be worked

on are depressured.

2.5 Notify maintenance that they may begin their work.

3. Pressure check compressor.

WARNING Make sure all maintenance work is completed before returning the compressor to

service.

3.1. Pressure check compressor with process gas.

3.1.1 Close the atmospheric vent valves on all 4 cylinder stages.

3.1.2 Open all isolation block valves on the PSV’s for the (1 st, 2nd, 3rd and 4th

stages,etc.)

3.1.3 Open all isolation block valve for the closed drain.

3.1.4 Open all isolation block valve for the open drain.

WARNING Make sure atmospheric vents are closed before pressurizing compressor with

process gas.

3.1.5 Open the 4th stage discharge isolation block valve.

3.1.6 Open the 3rd stage suction valve downstream of the Glycol Contactor.

3.1.7 Open the 4th stage intercooler discharge block valve.

3.1.8 Open the 1st stage suction isolation block valves (PCV-1 700, SDV-1 700).
ExxonMobil Production Isolation Procedure

File Name HOS6ISO Aneth Operations

McElmo HOS-6 COMPRESSOR Authorized Creek Unit ISOLATION PROCEDURE Page 4 of 4 Gas Reinjection Facility

______________________________

Egwpment. CM-l210

3.1.9 Verify pressures across compressor.

3.1.10 Verify that no teaks are detected on all items worked.

4. Return compressor to service.

4.1. Refer to the HOS-6 Operating procedure for requirements on returning the compressor

back into service
ExxomMobi( Production [ Operating Procedure

i File Name HOSCCOMP Aneth Operations

McEImo

HOS-6 COMPRESSOR Authorized -

Creek Unit I OPERATING PROCEDURE Page 1 of 10 Gas Reinjection Facility I

Equipment. CM-1210 I

SCOPE This procedure describes the startup and shutdown of the HOS-6 compressor.

Applicable steps are initial startup, normal startup, normal operation, temporary

operation, emergency operation, normal shutdown, Emergency Shutdown (ESD),

safety shutdown, problems and solutions, and operating limits.

REQUIREMENTS None

APPLICABLE HOS-6 Compressor Isolation Procedure

DOCUMENTS

SPECIAL None

EQUIPMENT

ENVIRONMENTAL For environmental concerns, contact the Field Foreman and the Operations

Compliance Technician.

SAFETY For applicable safety requirements, refer to the ExxonMobil Production Safety Manual

and Material Safety Data Sheets (MSDS).
ExxonMobil Production Operating Procedure

File Name HOS6COMP Aneth Operations HOS-6 COMPRESSOR Authorized McElmo Creek Unit OPERATING PROCEDURE Page 2 of 10 Gas Reinjecton Facility

Equipment. CM- 1210

Initial Startup.

j NOTE Initial startup is performed following an extended compressor shutdown cue to

‘ maintenance or turnaround.

1.1. Check that the compressor is ready for start.

Li Maintenance work complete

Temporary blinds removed and equipment restored

J Oxygen purged frorn compressor and piping

Li Compressor and piping pressure checked using process gas

U Compress& piping rechecked for leaks

Li Compressor isolation valves returned to service

Li Safety devices, vents, and PRVs returned to service

J Instruments, controls, and electrical power returned to service

Li Lock-out/Tag-out rernoved

1.2. Start compressor using normal startup procedure.

2. Normal Startup.

NOTE Normal startup is performed following a brief compressor shutdown due or following an

extended shutdown after performing the initial startup checks.

2.1. Prepare the compressor for start.

2.1.1. Check compressor is ready for start.

Li Plant ESD and local panel shutdowns are reset

J Verify that the LEL, H2S and Fire systerns are in normal operation

Li Motor electrical breaker is reset and in service in the MCC building

Li Control panel power on

Li Control panel lights working

Li Crankcase oil level okay

Li Lubricator oil reservoir level okay
Ensure that the manual block valves on the 1st stage suction and 4th

stage discharge lines are in the open position

J Ensure that all kiene valves and bleeder valves are closed

Li The 1st Stage Suction Pressure Controller (PIC-1700) resets

automatically to 10.4%

Start and load compressor,

CAUTION The compressor should not have more than 10 psi 9on the 1st stage suction.

Depressure as needed to prevent overloading the compressor motor.

2.2.1 Start the pre-lube oil pump.

( NOTE The pre-lube oil pump switch is located at the southwest corner of the compressor skid.

2.2.2 Start the 1st, 2nd, 3rd and 4th stage cooler fans.

2.2.3 Start the lube oil cooler fans.

2.2.4 Start the jacket water cooler fans.

2.2.5 Stan the jacket water pump.

2.2.6 Press the Nredn electrical reset button by Control Panel

2.2.7 Turn the bypass timer clockwise to 5 minutes.

NOTE Allow the indicators to sequence to “green.” The indicators that are bypassed by the timer

will not sequence until after startup and the first indicator in the series clears.

2.2.8 Verify discharge valve is open on the 4th stage discharge

WARNING If the panel indicator does not rotate from “clear” to “red” indicating that the

I discharge valve is open, visually inspect the valve position to ensure it is opened,

ExxonMobil Production Operatmg Procedure

McEhno Creek Umt

File Name HOS6cO 1

OPEIt4TING PROCEDURE Page 3 of 10

Aneth Operanons HOS-6 COMPRESSOR Authorized

Gas Reinjection Facility

Equipment. # CM-12 10

J Jacket water level okay

Visually verify that all Suction scrubbers are empty

J Ensure that the compressor is depressurized

Li

2.2
ExxonMobil Production Operatmg Proceduie

Aneth File Name HOS6COMP Operations

McElmo HOS-6 COMPRESSOR Authorized Creek Umt OPERATING PROCEDURE Gas Reinjection Page 4 of 10 Facilit

Equipment. 4 CM-1210

Warning: Ensure that all personnel are clear and free of the electrical power supply

system components immediately prior to starting motor. In particular do not stand

in front of motor starter, near motor transformer or under aerial fuses. A

minimum distance of 25 feet should be maintained for unqualified personnel.

Rationale: Across the line motor starting creates approximately 6X full load current.

Consequently the electrical system is stressed during starting and the probability

of failure is greater.

2.2.9 Press and hold the ‘green” start button and the “Lube” pump will run for 1 minute

before the compressor starts.

CAUTION After 2 unsuccessful starts; the compressor motor starter will trip a time delay in

the MCC building and prevent you from restarting the compressor. Verify the time

delay duration in the MCC building.

2.2.10 Verify that the compressor oil pressure is above 45 psig.

2.2.11 When the compressor starts ups, the suction valve should open automatically

and the indicator will show open.

2.2.12 Close the 2nd stage discharge to flare valve (PCV-1 746).

CAUTION Ensure that the Contactor back pressure control valve (PCV-1 637) is open before

you begin to close the 3rd stage discharge to flare pressure controller (PlC-I 747).

2.2.13 Close the 3rd stage discharge to flare valve (PCV-1 747).

2.2.14 The 1st Stage Suction Pressure Controller (PIC-1700) in the “auto” mode with a

setpoint 15 psig on the Rosemont OCS.

2.2.15 Reset the bypass timer back to zero.

2.2.16 Start the glycol pumps and place the Dehydration system in service.

3. Normal Operation.

3.1. See tables at end of procedure for normal operating parameters. (Page 9 of 10)

3.2. Perform daily rounds, including but not limited to the items below:

• Troubleshoot, acknowledge, reset, and clear compressor alarms

• Check compressor normal operating parameters

• Suction and discharge pressures

• Suction and discharge temperatures

• Cylinder temperatures
ExxonMobil Production Operating Procedure

Aneth Operanons File Name FIOS6CDMP

McElmo l-Ios-6 COMPRESSOR Authorized Creek Umt OPERATING PROCEDURE Gas Renijection Page 5 of 10 Facility

Equipment. 4 CM-1210

• Cylinder vibration

• Motor Vibration

• Crankcase and lubricator lube oil pressure

• Crankcase and lubricator lube oil temperature

• Crankcase lube oil filter dp, and change as necessary

• Crankcase oil level

• Oil consumption

• Lubricator oil level

• Jacket water pressure

• Jacket water temperature

• Check compressor crankcase and lubricator lube oil level and fill as needed

• Check pulsating bottle supports

• Check vibration and temperature monitors

• Clean oil off skid and foundation

• Check packing vent temperatures

• Check crankcase pressure

• Check all gauges

• Check for lose bolting

• Check Jacket water tank level and fill as needed

• Check Jacket water pump and cooler fans for proper operation

• Check suction scrubber levels and drain manually if needed

• Drain suction and discharge pulsating bottles

• Check distance piece purge or vent system

• Check interstage cooler delta pressure and temperature

• Check motor bearing oil sump level and sight level condition

• General housekeeping duties
ExxonMobil Procjucnon Operatmg Procedure

File Name HOS6COMP Aneth Operations I-iOs-6 COMPRESSOR Authothed McElmo Creek Unit OPERATING PROCEDURE Page 6 0110 Gas Reinjecuon Facility

Equipment. # CM-1210

• Check compressor aftercooler fans operation

4. Temporary Operation.

NOTE Use of temporary operating procedures must be approved by the Field foreman.

4.1. Document any temporary procedure changes with a Management of Change (MOC) work

order, and a procedure revision request form.

4.2 Follow up on temporary procedures when the system is returned to normal operation or

when a temporary procedure becomes permanent. Complete all documentation required.

5. Emergency Operation.

5.1. Refer to Emergency Response Plan for emergency response instructions.

6. Normal Shutdown.

NOTE Normal shutdown is usually done for compressor maintenance or when inlet gas rates

decrease. Control Room operator will coordinate any normal shutdown.

6.1. Shut down compressor.

6.2.1. Press the Motor stop button.

6.2.2 Ensure suction valve is closed since this valve closes automatically.

6.2.3 Open the 3rd stage discharge to flare valve (PCV-1 747).

6.2.4 Open the 2nd stage discharge to flare valve at (PCV-1 746).

NOTE Turn off the associated pumps and cooler fans if the compressor will be down for an

extended period.

7. Emergency Shutdown (ESD)

NOTE ESD of the Gas Reinjection Facility can be initiated from any of the 7 pull stations located

throughout the facility or from 1 push button station located in the Control Room. The

Fire, H2S and LEE. detection systems will also initiate an ESD. Both systems will

shutdown all the reinjection compressors, isolate the inlet area and depressure the facility.

NOTE The ESD pull stations located throughout the facility are easily identified by the red and

white stripes painted on the building or pipe rack support beams.

7.1. Reinjection Facility ESD:

7.1.1. ESD Station One push button station is located inside the Control Room above

the Fire, H2S and LEE. Detection System’s readout panel and a pull station is

located on the southeast wall inside the MCC building (beside the Control Room).
ExxonMobjj Production Operatmg Procedure

File Name HOS6COMP Aneth Operations [[OS-a COMPRESSOR Authorized McElmo Creek Unit OPERATING PROCEDURE Page 7 of 10 Gas Remjecuon Facility

Equipment. # CM-1210

7.1.2. ESD Station Located on a pipe rack support beam on the southeast corner of the

Acid Gas compressor building.

7.1.3. ESD Station Located outside between the Control Room and the MCC building.

7.14. ESD Station Located on the north wail outside of the Inlet Area’s Air Compressor

building.

7.1.5. ESD Station Located on a building support beam on the northwest corner of the

HOS-6 Compressor building.

7.1.6. ESD Station: Located on a building support beam on the northwest corner of the

HOS-4 Compressor building.

7.1.7. ESD Station: Located on cooler fan support beam on the southeast corner of the

HOS-4 Compressor’s Cooler Fan bay.

7.2 Fire, H2S and LEL Detection Systems ESD:

7.2.1. Fire: There are 10 Fire Detection sensors located throughout the facility. Any

detection by either of these sensors will initiate an audible alarm and a shutdown

of all reinjection compressors, isolate the inlet area and depressure the facility.

7.2.2. H25: There are 23 H2S Detection sensors located throughout the facility. Any

detection by either of these sensors at 10 PPM H23 will initiate an audible alarm

and illuminate a “blue” beacon light. Any detection by either of these sensors at

50 PPM H2S will initiate an audible alarm, illuminate a “blue” beacon light and

shutdown all reinjection compressors, isolate the inlet area and depressure the

facility

7.2.3. LEL: There are 8 LEL Detection sensors located throughout the facility. Any

detection by either of these sensors at 30 % LEL will initiate an audible alarm.

Any detection by either of these sensors at 50 % LEL will initiate an audible alarm

and shutdown all reinjection compressors, isolate the inlet area and depressure

the facility

7.3 HOS-6 Compressor ESD.

7.3.1 Local ESD. Trip individual compressor ESD by pressing ‘Stop’ button on local

control panel to shut down that compressor only.

8. Safety Shutdown.

8.1 Any condition below causes a safety shutdown of the compressor:
ExxonMobil Production Operating Procedure

File Name HQS6COMP Aneth Operations HOS-6 COMPRESSOR Authorized McElmo Creek Unit OPERATING PROCEDURE Page 8 of 10 Gas Reinjection Facility

Equipment. 4 CM-1210

• Plant ESD

• Fire! H2S, and LEL Detection systems

• Low instrument air pressure

• Electrical power failure

• Low discharge pressure

• Low pressure suction

• High discharge pressure on either of the 2nd or 4th stage cylinders

• High level in either of the 1st, 2nd, 3rd or 4th stage suction scrubbers

• Low pressure suction on either of the 2nd, 3rd or 4th stage

• Low compressor oil pressure

• Low compressor oH level

• No flow compressor cylinder oil

• Low pressure Jacket Water

• Cooler failure

• Vibration Compressor

• Compressor manual shutdown

8.3. See critical operating limits tab’es at end of procedure for safety shutdown trip points.

9. Problems and Solutions.

I NOTE Refer to the Compressor Troubleshooting guide located in the Control Room. I
ExxonMobil Production Operating Procedure

File Name HOS6COMP Aneth Operanons HOS-6 COMPRESSOR Authorized McElmo Creek Umt OPERATING PROCEDURE I Page 9 of 10 Gas Reinjection Facility

Equipment. 4 CM-1210

10. Operating Limits.

10.1. Shutdown resets:

Local Shutdown Resets and Permissive

Tag Description Position Setpoint

Reinjection Plant Total Reinjection Plant ESD Reset N/A

ESD

Fire Detection Fire Detection Reset N/A

H2S Detection H2S Detection Reset 50 PPM

LEL Detection LEL Detection Reset 50 %

Remote Shutdown Resets

Tag Description Position Setpoint

__Manual_Shutdown Local panel shutdown Reset N/A

10.2. Normal operating parameters:

NOTE The following parameters are only guidelines. Certain conditions may call for you to

operate outside them.
ExxonMobii Production Operating Procedure

File Name HOS6COMP Aneth Operations

McElmo

BOS-6 COMPRESSOR Authorized Creek Unit OPERATING PROCEDURE Page 10 of 10 Gas Reinjection Facility I________________________________________________

Equipment. CM-I 210

HOS-6 Compressor Normal Operating Parameters

Description Operating Range

Crankcase Oil Pressure 50 to 65 psig

Crankcase Oil Temperature 150 to 170°F

Oil Filter Differential Pressure 0 to 5 psig

Jacket Water Temperature 100 to 110°F

Jacket Water Temperature Change 10 °F

i Stage Suction Temperature 45 to 100 degrees F

1st Stage Discharge Temperature 250 to 280 degrees F

2 Stage Suction Temperature 80 to 110 degrees F

2’ Stage Discharge Temperature 250 to 250 degrees F

3’° Stage Suction Temperature 100 to 120 degrees F

3rd Stage Discharge Temperature 250 to 280 degrees F

4 Stage Suction Temperature 100 to 120 degrees F

4tfl Stage Discharge Temperature 240 to 280 degrees F

i’ Stage Suction Pressure 14 to 16 psig

i’ Stage Discharge Pressure 95 to 105 psig

2 Stage Suction Pressure I 90 to 105 psig 20d Stage Discharge Pressure 370 to 380 psig

3(0 Stage Suction Pressure 350 to 380 psig 31d Stage Discharge Pressure 1000 to 1050 psig

4fl Stage Suction Pressure 1000 to 1040 psig 4tfl Stage Discharge Pressure 2750 to 2950 psig

151 Stage Vibration (Cyl #1) 0.38 to 0.40 in/s

1 Stage Vibration (Cyl #3) 0.36 to 0.40 in/s

2° Stage Vibration (Cyl #2) 0.38 to 0.44 in/s

2 Stage Vibration (Cyl #4) 0.38 to 0.44 in/s

3(0 Stage Vibration (Cyl #5) 0.34 to 0.38 in/s

4U1 Stage Vibration (C #6) 0.35 to 0.40 in/s

Motor Vibration (Al Bearings) 2.0 to 3.0 in/s
ExxonMobif Production Isolation Procedure

FLIC Name HOS4ISO Aneth Operations

McElmo Creek Unit HOS- 4 COMPRESSOR ISOLATION Authorized

Page lofJ Gas Remjection Facility

Equipment. # CM-3400

SCOPE This procedure describes the isolation, depressurization and returning of the

HOS-4 Compressor back to service.

REQUIREMENTS None

APPLICABLE HOS-4 Compressor Operating Procedure

DOCUMENTS Pre-Start Safety Review Checklist

SPECIAL None

EQUIPMENT

ENVIRONMENTAL For environmental concerns, contact the Field Foreman and the Operations

Compliance Technician.

SAFETY Locks must be used by Operations and Maintenance Personal (Two Sets)

For applicable safety requirements, refer to the ExxonMobil Production Safety Manual

and Material Safety Data Sheets (MSDS).

Care must be taken to completely depressure the compressor which may contain

explosive or sour gas.

Safety devices taken out of service or being returned to service MUST be logged in

the Critical Safety Device (CSD) log book in the Control Room.
WARNING All valves, switches and breakers referenced in this procedure MUST BE LOCKED

AND TAGGED per the Lock-out I Tag-out guidelines.

1. Isolate the compressor for maintenance.

NOTE Refer to the HOS-4 Operating procedure for requirements to shutdown the compressor.

1.1 Ensure that the lube oil pump is not running.

1 .2 De-energize the electrical breaker for the motor in the MCC building.

1.3 Place the local control panel power switch in the “off’ position.

1.4 Close the 4th stage discharge isolation block valve.

1.5 Close the 1st stage suction isolation block valve.

1.6 Close the isolation block valves for the closed drain

1.7 Close the isolation block valve for the open drain.

1.8 Place the H2S and LEL Detection system in the ucalibrationK mode in the Control Room.

[iiãThE While the H25 and LEL Detection system is in the calibration Mmode, the sensors are still

active and MUST be monitored from the Control Room.

2. Depressurize the compressor for maintenance.

j jWARNING Atmospheric vents will release process gas that contain LEL and H2S. ii

2.1 Open the 1/2 blowdown valve to the Flare header to depressure the compressor.

2.2 Open the 3)4 blowdown valve to the Flare header to depressure the compressor.

2.3 Close the 1/2 blowdown valve to the Flare header after depressurizing the compressor.

2.4 Close the 3/4 blowdown valve to the Flare header after depressuring the compressor.

2.5 Close the main isolation block valve to the Flare header.

2.6 Open the atmospheric vent valves on all 4 cylinder stages to verify depressurization.

2.7 Open the cylinder head and crank end vent valves to verify that the cylinders to be worked

on are depressured.

ExxonMobil Production Isolation Procedure I

Aneth Operations File Name HOS4ISO

McElmo Creek Unit HOS- 4 COMPRESSOR ISOLATION i Authorized

GasReinjectionFacility

_________

Page 2 of 3

I Equipment. 4 CM-3400
ExxonMobil Production I Isolation Procedure

Aneth operations File Name HOS4JSO

McElmo Creek Unit HOS- 4 COMPRESSOR ISOLATION i Authorized

Gas Reinjection Facility Page 3 of 3

Equipment. # CM-3400

2.8 Notify maintenance that they may begin their work.

3. Pressure check compressor.

WARNING Make sure all maintenance work is completed before returning the compressor to

service.

3.1. Pressure check compressor with process gas.

3.1.1 Open the main isolation block valve to the Flare header.

3.1.2 Close the atmospheric vent valves on all 4 cylinder stages.

3.1.3 Open the isolation block valve for the close drain.

3.1.4 Open the isolation block valve for the open drain.

WARNING Make sure atmospheric vents are closed before pressurizing compressor with

process gas.

3.1.5 Open the isolation block valve for the 1st stage suction.

3.1.6 Open the 1st stage suction valve from the local control panel to pressurize the

compressor.

3.1.7 Verify pressures across compressor.

3.1.8 Verify that no leaks are detected on all items worked.

4. Return compressor to service.

4.1. Refer to the HOS-4 Operating procedure for requirements on returning the compressor

back into service
ExxonMobil Production Operatmn Procedure -

File Name HOS4COMP Aneth Operations -

McElmo Creek Unit HOS-4 COMPRESSOR Authonzed

Page lofIl Gas Rerniecnori Facility

I I Equipment. U CM-3400

SCOPE This procedure describes the startup and shutdown of the HOS-4 compressor.

Applicable steps are initial startup, normal startup, normal operation, temporary

operation, emergency operation, normal shutdown, Emergency Shutdown (ESD),

safety shutdown, problems and solutions, and operating limits.

REQUIREMENTS None

APPLICABLE HOS-4 Compressor Isolation Procedure

DOCUMENTS

SPECIAL None

EQUIPMENT

ENVIRONMENTAL For environmental concerns, contact the Field Foreman and the Operations

Compliance Technician.

SAFETY For applicable safety requirements, refer to the ExxonMobil Production Safety Manual

and Material Safety Data Sheets (MSDS).

Care must be taken to completely purge out a compressor which may contain an

explosive mixture of gas.
ExxonMol,jl Production I Operating Procedure

Aneth Operations File Name HOS4COMP

McElmo Creek Unit 1-LOS-I COMPRESSOR Authorized

Gas Reinjection Facility Page 2 of 11

. Equipment. CM-3400

1. Initial Startup.

NOTE Initial startup is performed following an extended compressor shutdown due to

maintenance or turnaround.

1.1. Check that the compressor is ready for start.

Li Maintenance work complete

Li Temporary blinds removed and equipment restored

Li Oxygen purged from compressor and piping

J Compressor and piping pressure checked using process gas

Li Compressor piping rechecked for leaks

Li Compressor isolation valves returned to service

Li Safety devices, vents, and PRVs returned to service

J Instruments, controls, and electrical power returned to service

Li Lock-out/Tag-out removed

1.2. Start compressor using normal startup procedure.

2. Normal Startup.

NOTE Normal startup is performed following a brief compressor shutdown due or following an

extended shutdown after performing the initial startup checks.

2.1. Prepare the compressor for start.

2.1.1. Check compressor is ready for start.

Li Plant ESO and local panel shutdowns are reset

Li Verify that the LEL, H2S and Fire systems are in normal operation

Motor electrical breaker is reset and in service in the MCC building

Li Control panel power on

Li Manual switch is in the “on” position for the Murphy Mark Ill annunciator
2.2 Start

2.2.1

2.2.3

2.2.4

ExxonMobil Production Operanng Procedure

File Name I-IOS4COMP Aneth Operanons

McElmo Creek Unit HOS4 COMPRESSOR Auth0t

Page 3ofIl Gas Reiniection Facihtv

______________________________

I Equipment. if CM-3400 I

J Reset the Bentley-Nevada vibration monitors

J Control panel lights working

U Enclosure pressure indicator for the Control panel is in the safe zone

Crankcase oil level okay

Lubricator oil reservoir level okay

IJ Jacket water level okay

J Verify that all Suction scrubbers are empty, both visually and on the

Rosemont DCS

J Ensure that the compressor is depressurized

J Ensure that the manual block valves on the 1st stage suction and 4th

stage discharge lines are in the open position

Ensure that all kiene valves and bleeder valves are closed

LI Permissive to startup HOS-4 on the Rosemont DCS

J The 1st Stage Suction Pressure Controller (PIC-341 1)is placed in

manual with an output of 9.4% open on the Rosemont DCS

and load compressor.

Open the 1 / 2 bypass valve by turning the VO-3412 controller counter-clockwise

for a zero psig output.

2.2.2 Open the 3 / 4 bypass valve by turning the VO-3414 controller counter-clockwise

for a zero psig output.

NOTE The 1 I 2 blowdown valve (VO-3462) automatically opens when the compressor is

shutdown.

Press the reset button on the Murphy Mark Ill (timer is for 5 minutes).

Open the 3 I 4 blowdown valve by turning the VO-3424 controller counter

clockwise for a zero psig output.

2.2.5 Press the “lube oil pump on” button.
ExxonMobil Production Operatmg Procedure 1

Aneth Operations File Name HOS4COMP

F McElmo Creek Unit HOS-4 COMPRESSOR Authonzcd

Gas Reinjecrion Facility I

____________________________

Page 4 of 11

Equipment. I 4 CM-3400

2.2.6 Press the “Jacket water pump on” button.

2.2.7 Press the “Fan 4 1 on” button

2.2.8 Press the “Fan #2 on” button

NOTE Fan #2 can be started on either low or high speed based on ambient temperature. Use

low speed if the ambient temperature is below 75 degrees F. Use high speed if the

ambient temperature is above 75 degrees F.

2.2.9 Press the “open discharge valve” button.

WARNING If the panel light does not come on indicating that the discharge valve is open,

visually inspect the valve position to ensure it is opened.

2.2.10 Press and hold the “open suction valve” button until the “open” indication light

comes on.

2.2.11 Allow the compressor to purge for a minimum of 30 seconds.

2.2.12 Press the “close suction valve” button.

2.2.13 Press the “close 1 / 2 blowdown valve” (VO-3462) button.

2.2.14 Close the 3/4 blowdown valve by turning the VO.3424 controller clockwise for at

least a 40 psig output.

2.2.15 Press and hold the “Yellow PPS-3416” button.

NOTE This will complete the start permissive sequence and illuminate the “Ready to Start” light.

2.2.16 Press the “motor start” button while still pressing the “Yellow PPS-3416” button.

I NOTE You have 5 minutes to place the 1st Stage Suction Pressure Controller (PIC-341 1) in

auto” on the Rosemont DCS or the compressor will shutdown.

CAUTION After 2 unsuccessful starts; the compressor motor starter will trip a time delay in

the MCC building and prevent you from restarting the compressor. Verify the time

delay duration in the MCC building.

2.2.17 Verify that the compressor oil pressure is above 45 p51g.

2.2.18 Press and hold the “open suction valve” button until the “open” indication light

comes on.

2.2.19 Close the I / 2 bypass valve by turning the VO-3412 controller clockwise for at

least a 40 psig output.
ExxonMobil Production Operatmg Procedure

Aneth Operations File Name HOS4COMP 1

Gas Reinjection Facility Page 5 of I I

McElmo Creek Unit 110S4 COMPRESSOR Authorized

j

Equipment. ft CM-3400

2.2.20 Close the 3 / 4 bypass valve by turning the VO-3414 controller clockwise for at

least a 40 psig output.

2.2.21 Press the ‘Timer 0 button on the Murphy Mark Ill annunciator.

2.2.22 Set the 1st Stage Suction Pressure Controller (PIC-341 1) in the “auto’ mode with

a setpoint between 22 to 27 psig on the Rosemont DCS.

3. Normal Operation.

3.1. See tables at end of procedure for normal operating parameters.

3.2. Perform daily rounds, including but not limited to the items below:

• Troubleshoot, acknowledge, reset, and clear compressor alarms

• Check compressor normal operating parameters

• Suction and discharge pressures

• Suction and discharge temperatures

• Cylinder temperatures

• Lube oil pressure

• Lube oil filter dp

• Lube oil temperature

• Crankcase oil level

• Lubricator oil level

• Jacket water pressure

• Jacket water temperature

• Check compressor lube oil level and fill as needed

• Check Jacket water tank level and fill as needed

• Check Jacket water pump and cooler fans for proper operation

• Check suction scrubber levels and drain manually if needed

• General housekeeping duties

• Check compressor aftercooler fans operation
ExxomMobil Production Operaimg Procedure

Aneth Operations File Name HOS4COMP

McElmo Creek Unit HOS-.4 COMPRESSOR Authorized

Gas Reinjecton Facility

______________________________

Page 6 of II

Equipment. # CM-3400

4. Temporary Operation.

NOTE Use of temporary operating procedures must be approved by the Field foreman.

4.1. Document any temporary procedure changes with a Management of Change (MOC) work

order, and a procedure revision request form.

4.2 Follow up on temporary procedures when the system is returned to normal operation or

when a temporary procedure becomes permanent. Complete all documentation required.

5. Emergency Operation.

5.1. Refer to Emergency Contingency Plan for emergency response instructions.

6. Normal Shutdown.

NOTE Normal shutdown is usually done for compressor maintenance or when inlet gas rates

decrease. Control Room operator will coordinate any normal shutdown.

6.1. Shut down compressor.

6.2.1. Press main motor ‘stop’ button.

6.2.2 Press the “close suction valve” button.

6.2.3 Press the “close discharge valve” button.

6.2.4 Open the 1 / 2 bypass valve by turning the VO-3412 controller counter-clockwise

for a zero psig output.

6.2.5 Open the 3/4 bypass valve by turning the vO-3414 controller counter-clockwise

for a zero psig output.

6.2.6 Open the 3 / 4 blowdown valve by turning the VO-3424 controller counter

clockwise for a zero psig output.

NOTE Turn off the associated pumps and cooler fans if the compressor will be down for an

extended period.
ExxonMobil Production Operating Procedure

Aneth Operations I File Name HOS4COMP

McElmo Creek Unit l-IOS-4 COMPRESSOR Authorized

Gas Reinjection Facility Page 7 of 11

Equipment. # CM-3400

7. Emergency Shutdown (ESD)

NOTE ESD of the Gas Reinjection Facility can be initiated from any of the 7 pull stations located

throughout the facility or from 1 push button station located in the Control Room. The

Fire, H2S and LEL detection systems will also initiate an ESO. Both systems will

shutdown all the reinjection comQressors, isolate the inlet area and depressure the facility.

NOTE The ESD pull stations located throughout the facility are easily identified by the red and

white stripes painted on the building or pipe rack support beams.

7.1. Reinjection Facility ESD:

7.1.1. ESD Station One push button station is located inside the Control Room above

the Fire, H2S and LEL Detection System’s readout panel and another pull station

is located on the southeast wall inside the MCC building (beside the Control

Room).

7.1.2. ESD Station Located on a pipe rack support beam on the southeast corner of the

Acid Gas compressor building.

7.1.3. ESD Station Located outside between the Control Room and the MCC building.

7.1.4. ESD Station Located on the north wall outside of the Inlet Building Air

Compressor building.

7.1.5. ESD Station Located on a building support beam on the northwest corner of the

HOS-6 Compressor building.

7.1.6. ESO Station Located on a building support beam on the northwest corner of the

HOS-4 Compressor building.

7.1.7. ESD Station Located on cooler fan support beam on the southeast corner of the

HOS-4 Compressor’s Cooler Fan bay.

7.2 Fire, H2S and LEL Detection Systems ESD:

7.2.1, Fire: There are 10 Fire Detection sensors located throughout the facility. Any

detection by either of these sensors will initiate an audible alarm and a shutdown

of all reinjection compressors, isolate the inlet area and depressure the facility.

7.2.2. H2S: There are 23 H2S Detection sensors located throughout the facility. Any

detection by either of these sensors at 10 PPM H2S will initiate an audible alarm
ExxonMobil Production Operating Procedure - I

Aneth Operanons File ?same HOS4COMP t

McElmo Creek Unit HOS-4 COMPRESSOR Authorized

Page Sofll Gas Remjection Facility i I

Equipment. # CM-3400

and illuminate a “blue’ beacon light. Any detection by either of these sensors at

50 PPM H2S will initiate an audible alarm, illuminate a “blue” beacon light and

shutdown all reinjection compressors, isolate the inlet area and depressure the

facility

7.2,3. LEL: There are S LEL Detection sensors located throughout the facility. Any

detection by either of these sensors at 30 % LEL will initiate an audible alarm.

Any detection by either of these sensors at 50 % LEL wdl initiate an audible alarm

and shutdown all reinjection compressors, isolate the inlet area and depressure

the facility

7.3. HQS-4 Compressor ESD.

7.3.1. Local ESD. Trip individual compressor ESD by pressing ‘Stop’ button on local

control panel to shut down that compressor only.

7.3.2. Remote ESD. Trip compressor ESD on the Rosemont DCS in the Control Room.

8. Safety Shutdown.

8.1. Any condition below causes a safety shutdown of the compressor:

• ESD pull stations

• Fire, H2S, and LEL Detection systems

• Low instrument air header pressure

• Electrical power failure

• Low discharge pressure on either the 1st, 2nd, or 3rd stage cylinders

• High discharge pressure on either the 1st, 2nd, 3rd, or 4th stage cylinders

• High discharge temperature on either of the 1st, 2nd, 3rd or 4th stage cylinders

• High level in either of the 1st, 2nd, 3rd or 4th stage suction scrubbers

• Low 1st stage suction pressure

• High 1st stage suction pressure

• Low compressor oil pressure

• Low compressor oil level

• No flow cylinder lubricator
Aneth erations File Ne HOS4COMP

romMobil

Production i Operating Procedure I

McElmo Creek Unit HOS4 COMPRESSOR Authorized

Gas Renijecuon Faci1i

Equipment. # CM-3400

Page 9 of II

J • Low cylinder tube oil Level

• Low water level surge tank

• Cooler fan ‘A” vibration

• Cooler fan “B’ vibration

• Vibration Compressor motor

• Manual shutdown

8.3. See critical operating limits tables at end of procedure for safety shutdown trip points.

9. Problems and Solutions.

NOTE Refer to the Compressor Troubleshooting guide located in the Control Room.
ExxonMobil Production Operating Procedure I

Aneth Operations File Name HOS4CDMP

McEImo Creek Unit 1-105-4 COMPRESSOR Authorized

Gas Reinjection Facility Page 10 of 11

Equipment. # CM-3400 I

10. Operating Limits.

10.1. Shutdown resets:

Local Shutdown Resets and Permissives

Tag Description Position Setpoint

Reinjection Plant Total Reinjection Plant ESD Reset N/A

ESD

Bentley-Nevada Compressor motor and frame excessive Reset N/A

Vibration Monitor vibration

Fire Detection Fire Detection Reset N/A

H2S Detection H2S Detection Reset 50 PPM

LEL Detection LEL Detection Reset 50 %

Remote Shutdown Resets

Tag Description Position Setpoint

Manual Shutdown Local panel shutdown Reset N/A

Rosemont DCS HOS-4 Run/Stop Run N/A

10.2. Normal operating parameters:

NOTE The following parameters are only guidelines. Certain conditions may call for you to

operate outside them.

HOS-4 Compressor Normal Operating Parameters

Description Operating Range

1st stage suction pressure 20 to 27 psig

1st stage discharge pressure 65 to 78 psig

2nd stage suction pressure 60 to 78 psig

2nd stage discharge pressure 300 to 330 psig

3rd stage suction pressure 295 to 330 psig

3rd stage discharge pressure 1 150 to 1260 psi 9

4th stage suction pressure 1145 to 1260 psig

4th stage discharge pressure 2750 to 2950 psi 9

1st stage suction temperature 45 to 105 degrees F

1st stage discharge temperature 250 to 290 degrees F

2nd stage suction temperature 90 to 120 degrees F

2nd stage discharge temperature 275 to 315 degrees F

3rd stage suction temperature 100 to 120 degrees F

3rd stage discharge temperature 275 to 315 degrees F

4th stage suction temperature 105 to 110 degrees F

4th stage discharge temperature 225 to 260 degrees F

Lube oil pressure 45 to 55 psig
ExxomMobil Production

Aneth Operations

McElmo Creek Unit

Gas Reinjecrion Facility

Operatin2 Procedure

HOS-4 COMPRESSOR

Equipment.

m CM-3400

Aui

Page 11 of 11
ExxonMobil Production Isolation Procedvse

File Name AGISO Aneth Operations

McElnio Creek Unit ACID GAS COMPRESSOR ISOLATION Authorized

Gas Reinjection Facility Page 1 of 3

Equipment # CM-l201 A/B

SCOPE This procedure describes the isolation, depressurization and returning of the Acid

Gas compressor back to service.

REQUIREMENTS None

APPLICABLE Acid Gas Compressor Operating Procedure

DOCUMENTS Pre-Start Safety Review Checklist

SPECIAL None

EQUIPMENT

ENVIRONMENTAL For environmental concerns, contact the Field Foreman and the Operations

Compliance Technician.

SAFETY Locks must be used bV Operations and Maintenance Personal (Two Sets)

For applicable safety requirements, refer to the ExxonMobil Production Safety Manual

and Material Safety Data Sheets (MSDS).

Care must be taken to completely depressure the compressor which may contain

explosive or sour gas.

Safety devices taken out of service or being returned to service MUST be logged in

the Critical Safety Device (CSD) log book in the Control Room.
Exxon.MobiI Production isolation Procedure

Aneth Operations File Name AGISO

McElmo Creek Unit ACID GAS COMPRESSOR ISOLATION Authonzed

Gas Remjeccion facility Page 2 of 3

I Equipment # CM-1201 A/B

WARNING All valves, switches and breakers referenced in this procedure MUST BE LOCKED

AND TAGGED per the Lock-out / Tag-out guidelines.

Isolate the compressor for maintenance.

NOTE Refer to the Acid Gas Compressor Operating procedure for requirements to shutdown the

compressor. J

1.1 Ensure that the lube oil pump is not running.

1.2 De-energize the electrical breaker for the motor in the MCC building.

1.3 Place the local control panel power switch in the “off’ position.

1.4 Close the 4th stage discharge isolation block valve.

1.5 Close the 1st stage suction isolation block valve.

1.6 Close the isolation block valves on the PSV’s for the 1st, 2nd, 3rd and 4th stages.

1.7 Close the isolation block valves for the closed drain

1.8 Close the isolation block valve for the open drain.

1.9 Place the H2S and LEL Detection system in the “caIibration mode in the Control Room.

‘NOTE While the H2S and LEL Detection system is in the “calibration” mode, the sensors are still

active and MUST be monitored from the Control Room.

2. Depressurize the compressor for maintenance.

Ii WARNING Atmospheric vents will release process gas that contain LEL and H2S. ii

2.1 Open the blowdown valves on all stages to the Flare header to depressure the

compressor.

2.2 Close the blowdown valves on all stages to the Flare header.

2.3 Open the atmospheric vent valves on all 4 cylinder stages to verify depressurization.

2.4 Open the cylinder head and crank end vent valves to verify that the cylinders to be worked

on are depressured.

2.5 Notify maintenance that they may begin their work.
ExxonMobil Production Isolation Procedure

Aneth Operations File Name AGISO

McElmo Creek Unit ACID GAS COMPRESSOR ISOLATION Authorized

Gas ReinjectionFacilitv Page 3 of3

Equipment 4 CM-1201 A/B

3. Pressure check compressor.

WARNING Make sure all maintenance work is completed before returning the compressor to

service.

3.1. Pressure check compressor with process gas.

3.1.1 Close the atmospheric vent valves on all 4 cylinder stages.

3.1.2 Open the isolation block valves on the PSV 1sfor the 1st, 2nd, 3rd and 4th stages.

3.1.3 Open the isolation block valve for the closed drain.

3.1.4 Open the isolation block valve for the open drain.

WARNING Make sure atmospheric vents are closed before pressurizing compressor with

process gas.

Open the isolation block valve for the 1st stage suction.

Open the 1st stage suction pressure controller to pressurize the compressor.

Verify pressures across compressor.

Verify that no leaks are detected on all items worked.

3.1.5

3.1.6

3.1.7

3,1.8

compressor to service.

Refer to the Acid Gas Compressor Operating procedure for requirements on returning the

compressor back into service

4. Return

4.1.
ExxonMobil Production Operating Procedure

Aneth Oceranons File Name AGCOMP

McElmo Creek Unit ACID GAS COMPRESSORS “A” and ,,‘, Authonzed

Gas Remjecnon Page 1 of9 Facility

Eguipment#CM-l201 A/B

SCOPE This procedure describes the startup and shutdown of the Acid Gas Compressors

“A” and B” (CM-12Q1NB). Applicable steps are initial startup, normal startup,

normal operation, temporary operation, emergency operation, normal shutdown,

emergency shutdown, safety shutdown, problems and solutions, and operating

limits.

REQUIREMENTS None

APPLICABLE Acid Gas Compressors “A” and “B” (CM-12O1NB) Isolation Procedure

DOCUMENTS

SPECIAL None

EQUIPMENT

ENVIRONMENTAL For environmental concerns, contact the Field Foreman and the Operations

Compliance Technician.

SAFETY For applicable safety requirements, refer to the ExxonMobil Production Safety Manual

and Material Safety Data Sheets (MSDS).

Care must be taken to completely purge out a compressor which may contain an

explosive mixture of gas.
ExxonMobil Production Qerating Procedure

Aneth Operations I File Name AGCOMP

McEhno Creek Unit ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjection Facility Page 2 of 9

Equipment # CM-1201 AfB

Initial Startup.

‘NOTE Initial startup is performed following an extended compressor shutdown due to

maintenance or turnaround. Refer to the Acid Gas Compressor isolation procedure when

the compressor will be returned to service.

1 .1 Check that the compressor is ready for start.

Li Maintenance work complete

Li Temporary blinds removed and equipment restored

Li Oxygen purged from compressor and piping

Li Compressor and piping pressure checked using process gas

U Compressor piping rechecked for leaks

Li Compressor isolation valves returned to service

J Safety devices, vents, and PRVs returned to service

Li Instruments, controls, and electrical power retume to service

Li Lock-out/Tag-out removed

1.2. Start compressor using normal startup procedure.

2. Normal Startup.

NOTE Normal startup is performed following a brief compressor shutdown due or following an

extended shutdown after performing the initial startup checks.

_____ ______

2.1. Prepare the compressor for start.

2.1.1. Check compressor is ready for start.

Li Plant ESD and local panel shutdowns are reset

Li Verify that the LEL, H25 and Fire systems are in normal operation

Li Motor electrical breaker is reset and in service in the MCC building under

the Control Room.

Li Control panel power on
ExxonMobil Production Operating Procedure

Meth Operations File Name AGCOMP

McEhno Creek Unit ACID GAS COMPRESSORS “A” and “B” I Authonzed

Gas Reinjecüon Facility Page 3 of 9

Equipment CM-1201 AIR

J Manual switch is in the “run’ position for the Murphy Mark III annunciator

‘j Electrical motor oil level

LI Crankcase oil level okay

J Lubricator oil reservoir level okay

J Jacket water level okay

Visually verify that all Suction scrubbers are empty

U Ensure that the compressor is depressurized

J Ensure that all kiene valves and bleeder valves are closed

2.2 Start and load compressor.

NOTE The compressor should not have more than 10 psig of suction pressure on the 1st stage.

It there is more than 10 psig, the pressure should be bled off. This is to prevent

overloading the compressor driver.

__________

2.2.1 Start the motor cooling fan (CM-1203).

2.2.2 Start the aftercooler fans (HT-1 603, HT-1 604, HT-1 605, and HT-1 606).

2.2.3 Ensure the 1st stage suction valve is manually closed.

2.14 Reset the Murphy switch gauges high/low shut down. Turn the Murphy switch

qauge (low) to zero setting.

2.2.5 Zero out the timer on the Murphy Mark Ill on the annunciator panel.

2.2.6 Verify and manually opens the 4th stage discharge valves.

NOTE Ensure that the 4th Stage discharge isolation block valve located on the south side of the

compressor building is open.

2.2.7 Press the main motor ‘start button,

2.2.8 1 minute Pre-Lube

CAUTION After 2 unsuccessful starts; the compressor motor starter will trip a time delay in

the MCC building and prevent you from restarting the compressor.

2.2.9 Manually open the 1st stage suction valve.
ExxonMobil Production Operatmg Procedure

Aneth Operations File Name AGCOMP

McElmo Creek Urüt ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjection Facility Page 4 of 9

I Eguipment#CM-1201 AID

NOTE At 200 psig, the 4th stage blowdown valve to flare will close automatically.

Reset all murphy switches shut down setpoint to normal shut down setting on

panel.

NOTE Murphy switch gauges on local panel not to exceed the PSV’s setting

3. Normal Operation.

3.1. See tables at end of procedure for normal operating parameters.

3.2. Perform daily rounds, including but not limited to the items below:

• Troubleshoot, acknowledge, reset, and clear compressor alarms

• Check compressor normal operating parameters

• Suction and discharge pressures

• Suction and discharge temperatures

• Cylinder temperatures

• Lube oil pressure

• Lube oil filter dp

• Lube oil temperature

• Crankcase oil level

• Lubricator oil level

• Jacket Water Pressure (3)

• Jacket Water temperature

• Check compressor lube oil level and fill as needed

• Check Jacket Water tank level and fill as needed

• Check Jacket Water pump and coaler for proper operation

• Check suction scrubber levels and drain level as needed

• General housekeeping duties

• Check aftercooler fans operation
ExxonMobil Production Opemtmg Procedure

Aneth Operations File Name AGCOMP

McEhno Creek Unit ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjection Facility

_____________________

Page 5 of 9

Equipment # CM-1201 A/B

• Check all 4-skies electrical motor oil level

4. Temporary Operation.

NOTE Use of temporary operating procedures must be approved by the Field foreman.

4.1. Document a temporary procedures with a management of change (MOC) work order,

procedure revision request, and/or safety devices jumpering log book.

4.2 Follow up on temporary procedures when the system is retumed to normal operation or

when a temporary procedure becomes permanent. Complete all documentation required.

5. Emergency Operation.

5.1. Refer to Emergency Contingency Plan for emergency response instructions.

5.2. See this procedure for emergency shutdown (ESD) instructions.

6. Normal Shutdown.

NOTE Normal shutdown is usually done for compressor maintenance or when inlet gas rates

decrease. Control Room operator will coordinate any normal shutdown.

6.1. Shut down compressor.

6.2.1. Press main motor ‘stop’ button.

NOTE On any Acid Gas compressor shutdown, the blowdown valves to flare will open and

depressure the compressor.

6.2.2 Manually block in the 1st stage suction valve.

6.2.3 Manually block in the 4th stage discharge valve. (Maintenances)

6.2.4 Wait 1010 15 minutes, then tum off the motor cooling fan.
ExxonMobjl Production Operatmg Procedure

Aneth Operations File Name AGCOMP

McEhno Creek Unit ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjecnon Facility Page 6 of 9

EguipmentCM-l2Ol A8

7. Emergency Shutdown (ESD)

NOTE ESD of the Gas Reinjection Facility can be initiated from any of the 7 ESD pull stations

located throughout the facility or from 1 push button station located in the Control Room.

The Fire, H2S and LEL detection systems will also initiate an ESD. Both systems will

shutdown all the reinjection compressors, isolate the inlet area and depressure the facility.

NOTE The ESD pull stations located throughout the facility are easily identified by the red and

white stripes painted on the building or pipe rack support beams.

7.1. Reinjection Facility ESD:

7.1.1. ESO Station One push button station is located inside the Control Room above

the Fire, H2S and LEL Detection System’s readout panel and a pull station is

located on the southeast wall inside the MCC building (beside the Control Room).

7.1.2. ESD Station Located on a pipe rack support beam on the southeast corner of the

Acid Gas compressor building.

7.1.3. ESD Station Located outside between the Control Room and the MCC building.

7.1.4. ESD Station Located on the north wall outside of the Inlet Building of Air

compressor.

7.1.5. ESD Station Located on a building support beam on the northwest corner of the

HOS-6 Compressor building.

7.1.6. ESD Station: Located on a building support beam on the northwest corner of the

HOS-4 Compressor building.

7.1.7. ESD Station: Located on cooler fan support beam on the southeast corner of the

HOS-4 Compressor’s Cooler Fan bay.

7.2 Fire, H2S and LEL Detection Systems ESD:

7.2.1. Fire: There are 10 Fire Detection sensors located throughout the facility Any

detection by either of these sensors will initiate an audible alarm and a shutdown

of all reinjection compressors, isolate the inlet area and depressure the facility.

7.2.2. H2S: There are 23 H2S Detection sensors located throughout the facility. Any

detection by either of these sensors at 10 PPM H2S will initiate an audible alarm

and illuminate a “blue” beacon light. My detection by either of these sensors at
ExxonMobil Production Operating Procedure

Aneth Operations File Name AGCOMP

McElmo Creek Unit ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjection Facility Page 7 of 9

Eguipment# CM-1201 AJB

50 PPM H2S will initiate an audible alarm, illuminate a “blue” beacon light and

shutdown all reinjection compressors, isolate the inlet area and depressure the

facility

7.2.3. LEL: There are 8 LEL Detection sensors located throughout the facility. Any

detection by either of these sensors at 30 % LEL will initiate an audible alarm.

Any detection by either of these sensors at 50 % LEL will initiate an audible alarm

and shutdown all reinjection compressors, isolate the inlet area and depressure

the facility

7.3. Acid Gas Compressor ESD.

7.3.1. Local ESD. Trip individual compressor ESD by pressing ‘Stop’ button on local

control panel to shut down that compressor only.

8. Safety Shutdown.

8.1. Any condition below causes a safety shutdown of the compressor:

• ESD pull stations

• Fire, H25, and LEL Detection systems

• Low instrument air header pressure

• Electrical power failure

• Low discharge pressure on either the 1st, 2nd, 3rd or 4th stage cylinders

• High discharge pressure on either the 1st, 2nd, 3rd, or 4th stage cylinders

• High discharge temperature on either of the 1st, 2nd, 3rd or 4th stage cylinders

• High level in either of the 1st, 2nd, 3rd or 4th stage suction scrubbers

• Low 1st stage suction pressure

• High 1st stage suction pressure

• Crank case oil pressure

• Oil level low

• No flow cylinder lubricator on either of the 1st, 2nd, or 3rd stage cyiinders

• No flow cylinder lubricator on the 4th stage cylinder

• Low cylinder lube oil level
!

ExxonMobil Production Operating Procedure

Aneth Operations I File Name AGCOMP

McElmo Creek Unit ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjection Facility Page 8 of 9

, Eguipment#CM-1201 AJB 1

• Jacket Water 1st, 2nd, 3rd low pressure

• Jacket Water pressure

• Low Jacket Water Tank level 4 1

• Low Jacket Water Tank level 4 2

• Vibration

• Manual shutdown

9. Problems and Solutions.

NOTE Refer to the Compressor Troubleshooting guide located in the Control Room.

10. Operating Limits.

10.1. Shutdown resets:

Local Shutdown Resets and Permissives

Tag Description Position Setpoint

Reinjection Plant Total Reinjection Plant ESD Reset N/A

ES D

Fire Detection Fire Detection Reset N/A

H2S Detection H2S Detection Reset 50 PPM

LEL Detection LEL Detection Reset 50 %

Remote Shutdown Resets

Tag Description Position Setpoint

Manual Shutdown Local panel shutdown Reset T N/A

10.2. Normal operating parameters:

NOTE The following parameters are only guidelines. Certain conditions may call for you to

operate outside them.

Acid Gas Compressor Normal Operating Parameters

Description Operating Range

1st stage suction pressure 18 to 20 psi 9

1st stage discharge pressure 90 to 100 psig
ExxonMobjl Production Operatmg Procedure

Aneth Operations File Name AGCOMP

McElmo Creek Unit ACID GAS COMPRESSORS “A” and “B” Authorized

Gas Reinjection Facility Page 9 of 9

Equipment # CM-1201 A/B

2nd stage suction pressure 85 to 100 psig

2nd stage discharge pressure 400 to 410 psig

3rd stage suction pressure 395 to 410 psig

3rd stage discharge pressure 1150 to 1250 psig

4th stage suction pressure 1145 to 1250 psig

4th stage discharge pressure 2750 to 2950 psig

1st stage suction temperature 45 to 100 degrees F

1st stage discharge temperature 230 to 250 degrees F

2nd stage suction temperature 90 to 100 degrees F

2nd stage discharge temperature 270 to 280 degrees F

3rd stage suction temperature 110 to 125 degrees F

3rd stage discharge temperature 270 to 280 degrees F

4th stage suction temperature 110 to 125 degrees F

4th stage discharge temperature 270 to 280 degrees F

Lube oil pressure 45 to 55 psig

Jacket water pressure 20 to 25 psig

Crankcase lube oil pressure 60 to 90 psig
APPENDIX 4

Compressor Troubleshooting Guide
COMPRESSOR TROUBLESHOOTING GUIDE

ENGINE & FRAME SHUTDOWNS

Low Engine/Frame Oil Pressure

High Engine/Frame Oil Temperature 3

High/Low Intake Manifold Pressure 4

High Manifold Temperature 6

Lubricator No Flow 7

High Main Bearing Pressure/Temperature 8

Engine Overspeed 9

High Engine/Frame Vibration 10

II. COOLING SYSTEM SHUTDOWNS

Low Auxiliary Water Pressure 11

Low Coolant Level 12

Low Jacket Water Pressure 3

High Jacket Water Temperature 14

High Cooler Vibration 15

III. GAS CIRCUIT SYSTEM SHUTDOWS

High/Low Suction Pressure 16

High Scrubber Level 17

High/Low Interstage Pressure 19

HighlLow Discharge Pressure 20

High Discharge Pressure 21

IV. IGNITION & PANEL BOARD

Altronic Ignition 22

CEC Ignition 23

Ignition System 24

Panel Board Components 25
Shutdown on Low Engine/Frame Oil Pressure

Troubleshooting Guide

POSSLE CAUSE CORRECJVE ACTIONS

Low Oil Level (High I. Check oil level.

level can cause foaming, 2. Add oil as needed.

resulting in low 3. Restart unit.

pressure.)

Dirty Filters 1. Check differential pressure across filters, strainer and

cooler.

2. If differential pressure is high, replace filters and strainer;

clean cooler.

Oil Pump Malfunction 1. Stan unit.

2. Check for normal oil pressure at pumpout.

3. If oil pressure at pump out is low, oil pump is faulty;

• repair or replace as needed.

4. If air is present, change pump.

5. If oil pressure at header is normal, continue

F troubleshooting.

6. Check pump suction screen for obstruction.

• 7. If clogged. clean or replace screen.

Gauge Malfunction I. Use manometer (test gauge) to check panel gauges for

malfunction.

2. Check wiring and tattle tale; repair or replace as needed.

3. Calibrate or replace gauges as needed.

4. Check oil sensing line for pluggage.

Engine is Misfiring 1. Load unit.

• 2. Use digital or hand-held pyrometer (test gauge) to check

for misfires causing unit to bog down. (Statiscope or

timing light can be used, if pyrometer is not available.)

3. Check ignition: replace plugs or wire if necessar.

4. Check fuel system; adjust to specs.

Relief Valve Stuck I. Check relief valve setting and position.

Open or Set Too Low 2. Correct as needed,

High Oil Level Caused I. Check day tank water levels to see if there is a leak in

by Water/Liquid head, gasket or liner.

Dilution 2. Call Mechanic.
POSSIBLECAUSE•IZ

Low Oil Viscosity I. Change oil.

2. Check recent oil sample analysis results.

Unit Bogging Down I. Check chart or meters to verify that suction and discharge

are normal.

2. Check for proper oil level in governor.

3. Check for broken or loose linkage; repair or replace as

needed.

If low engine/frame oil pressure continues and you have taken all corrective steps,

call Mechanic.

2
Shutdown on High Engine/Frame Oil Temperature

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS

High Oil Level I. Check oil level.

2. Adjust oil level as needed.

Binding or Tightness in f 1. Roll engine and compressor by hand.

Compressor Engine 2. Check for binding or tightness.

3. If binding or tightness exist, notify Mechanic

immediately. Do NOT start unit.

4. If no binding or tightness is found, sian engine.

Dirty Oil Filters 1. Check differential pressure across filters.

;

2. Change filter if pressure drop exceeds ExxonMobil

parameters.

Clogged or Blocked Oil I. Check auxiliary water level.

Cooler 2. Add coolant as needed.

3. Check pressure and temperature differentials across

cooler.

4. Clean or replace oil cooler as needed.

Faulty Gauge I. Use test gauge or pyrometer to compare pressure and

temperature panel gauges.

2. Calibrate or replace gauge as needed.

3. Ensure kill setpoint is set to ExxonMobil parameters.

Amot Valve Not Letting 1. Replace amot valve.

Oil Into Cooler

t Broken Thermostat I. Scan piping for temperature variances.

2. Replace thermostat.

Engine Overload 1. Check engine load.

2. Check for misfires.

3. Check timing; adjust to engine specs.

Stuck Oil Thermostat I. Check for bypass around oil cooler.

2. Replace thermostat.

If high engine/frame oil temperature continues and you have taken all corrective

steps, call Mechanic.

3
Shutdown on High /Low Intake Manifold Pressure

Troubleshooting Guide

--POSSmLECAUSE CORRECTIVE ACTIONS

Faulty Timing 1. Start unit.

2. Use timing light to check timing.

3. Adjust magneto as needed to adjust timing.

4. Check drive for wear.

• Damaged Drive ii. Inspect drive coupling or figure 8 for damage.

: Coupling or Figure 8 2. Repair or replace drive coupling or figure 8 as needed.

Engine is Misfiring 1. Load unit.

2. Use digital pyrometer to check for cyLinder temperature

variances.

3. Check rpm and engine fuel pressure.

4. Use timing light to check plug firing.

. If plug is not firing, refer to “Panel Component

Troubleshooting Guide.”

• If plug is firing, continue to next step.

5. Tap on emission valve to see if it is stuck.

6. Use volt meter to check magneto voltage.

7. Check cannon plug and wiring harness.

8. Repair or replace parts as needed.

9. Check for liquid in fuel.

Ignition Problem I. Use volt ohm meter to check magneto voltage.

Note: Voltage should be 150-190 DC (Altronic III) or

120-125 DC (cm.

2. If you have an Aitronic III ignition, refer to “Altronic III

Ignition Troubleshooting Guide.”

3. If you have a CEC ignition, refer to “CEC Ignition

Troubleshooting Guide.”

Insufficient Fuel Supply I. Check fuel pressure at Fisher 99 and prechamber pressure

on Fisher 95.

2. Set pressure to ExxonMobil parameters or factory specs

as needed.

• 3. Check for liquid in fuel; drain fuel scrubbers or fuel

supply lines.

4. Check carburetors; repair or clean diaphragms.

5. Check complete fuel system; set to specs.

Faulty Wires or Coils I. Check plug wires, coils and all wiring.

2. Replace as needed.

4
POSSIBLE CAUSE CORRECTIVE ACTIONS

Engine Overload 1. Check chart or meter for engine overload (caused by

excess suction).

2. Start and load unit.

3. Check suction control valve for malfunction, causing

sudden increase in suction gas flow.

4. Contact client as needed.

‘ Gauge Malfunction 1. Use manometer to check panei gauges for malfunction.

2. Calibrate or replace gauges as needed.

!

Load Changes 1. Check meters or chart for flow changes.

(SuctionlDischarge 2. Check recycle and control valves; adjust if possible or

Pressure) notify client of possible problems.

Governor I. Check oil in governor; replace or add oil as needed.

MalfunctionlFaultv p 2. Check governor linkage and rod ends: repair or replace as

Linkage needed.

Panel Malfunction I Check panel gauges and tubing to panel for accuracy.

2. Check tubing for obstruction or leak.

3. Replace gauges/tubing as needed.

! Turbo Malfunction I. Check thrust by hand: measure turbo output and balance

banks.

I 2. Replace turbo if thrust is out.

Compressor Packing 1. Check packing.

Leaks 2. Replace packing if leaks are present.

If high/low intake manifold pressure continues and you have taken all corrective

steps, call Mechanic.

5
Shutdown on High Manifold Temperature

Troubleshooting Guide

POSSIBLE CAUSE COU1ECT1VE ACTIONS

Low Auxiliary Water L Check auxiliary water level.

Level 2. Add coolant as needed.

3. Check for water on skid, indicating cracked pipe/hose or

loose connection.

4. Check louvers; adjust as needed.

Belt/Pump Malfunction I. Check auxiliary water pump and belts.

2. Repair or replace as needed.

Auxiliary Water High I. Start and load unit.

F Temperature or Low 2. Check gauge for auxiliary water pressure.

Pressure 3. If there is low pressure, replace water pump.

4. Use pyro scarmer to check differential temperature across

intercooler.

• If differential temperature is high, inspect and clean

intercooler.

5. Check for air lock in system; bleed air from system.

6. Check main cooler system; check for proper valve

position; clean cooler as needed.

Gauge Malfunction I. Use manometer (test gauge) to check panel gauges for

malfunction.

2. Calibrate or replace gauges as needed.

Fuel is Too Rich I. Adjust fuel system using oxygen meter.

2. Check for liquid.

Engine is Overloaded I. Check manifold pressure with engine running.

2. Check for gas flow changes.

Wrong Timing Setting I I. Check timing and adjust if needed.

Intake Valve Leak I. Check individual inlet temperatures to check for leaks.

2. Repair leaks as needed.

Mechanic.

If high manifold temperature continues and you have taken all corrective steps, call

6
Shutdown on Lubrication No Flow

Troubleshooting Guide

. POSSIBLE CAUSE CORRECTIVE ACTIONS

Insufficient Oil in 1. Check oil in lube box.

Lubricator Box 2. Check oil regulator supply to lube box.

3. Repair or replace oil regulator supply in lube box as

needed.

Broken Lubricator I. Ensure gear drive and all couplings are not broken or

Drive stripped.

2. Replace drive coupling or chain as needed.

Faulty Lubricators l. Ensure all lubricators are pumping the proper amount of

I I lubrication drops per minute.

2. Prime or replace lubricator as needed.

Blown Rupture Disc 1. Disconnect lubricator lines at cylinders.

2. Prime Lubricator System with Trebon Gun.

I 3. If rupture disc continues to blow, replace distribution

block and cylinder check valves.

Faulty No-Flow Switch I Check lubricator no-flow switch for sensitivity.

, 2. Adjust sensitivity setting to manufacturer’s

specifications.

3. Use volt ohm meter to inspect no-flow switch for wiring

short.

4. Replace wiring as needed.

5. If grounded wire cannot be found, refer to “Panel

j Component Troubleshooting Guide.”

If no lube flow continues and you have taken all corrective steps, call Mechanic.

7
Shutdown on High Main Bearing Pressure/Temperature

Troubleshooting Guide

POSSIBLE CAUSE COIU{EC’TDTE ACTIONS I Main Bearing Switch 1 Use Trebon gun to pressure probe header at switch to 25Z

Malfunction 45 psi. Hold 30 seconds.

• If pressure does not hold, do NOT start unit; skip to

the main bearing probe rupture (below).

i • If pressure holds, inspect switch for wiring short or

proper contact.

2. Adjust setpoint of main bearing switch.

3. Start unit panel should clear immediateiy.

Main Bearing Probe I. Do NOT stan unit.

Rupture 2. Notify Mechanic immediately for probe replacement and

bearing inspection.

Engine Bogging Down 1. Check setpoint on switch; set to specs or ensure setpoint

is lower than engine oil pressure kill setpoint.

2. Check’ignition and fuel settings; set to specs.

3. Check timing and set to specs.

If high main bearing temperature continues and you have taken all corrective steps, call Mechanic.

8
Shutdown on Engine Overspeed

Troubleshooting Guide

POSSIBLE CAUSE CORRECTWE ACTIONS

Tachometer 1 Start engine and idle.

Malfunction 2. Cheek magneto voltage with volt ohm meter.

3. If voltage is high or low, inspect magneto for possible

malfunction.

4. If magneto is malfunctioning, repair or replace as needed.

5. If voltage is normal, load unit.

6. Use timing light with digital display to determine

tachometer accuracy.

7. Replace tachometer if accuracy is still in doubt.

8. Check cannon plug in mag back.

Speed Controller I. Inspect speed controller gauges for proper supply and

Malfunction output.

2. If low supply or output, inspect, repair and/or replace

gauges or regulator.

Governor Malfunction 1. Check oil level in governor.

2. Add oil as necessary.

3. Check governor linkage. !

4. Replace governor rod ends as needed.

5. Bleed governor or adjust compensating needle to

eliminate engine surge.

Old Style Overspeed 1. Inspect wiring with volt ohm meter.

Switch Malfunction 2. Replace wiring as needed.

3. Inspect overspeed switch for malfunction or short.

4. Replace switch.

Load Reduction 1. Ensure suction/discharge pressures are within normal

ranges. -

2. If reduced load is present and unit is running too fast,

slow unit to proper rpm; determine cause of load change;

inspect pressure kills for proper setting.

If engine ovenpeed continues and you have taken all corrective steps, call Mechanic.

9
Shutdown on High Engine/Frame Vibration

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVEACTIONS

Loose Mounting Bolts I. Check bolts.

2. Tighten as needed.

3. If engine or frame mounts are Loose, call Mechanic for

alignmentldeflection checks.

Vibration Switch I. Roll unit over by hand 4-5 revolutions.

Tripped 2. Check for binding or noise.

3. Ensure start switch and fuel are off.

4. Roll engine over with starter.

; 5. Listen for unusual knocking or noise.

6. Reset vibration switch. : 7 Ensure no liquid is present in fuel to cause detonation: .

drain fuel scrubber and check carburetor as needed.

8. Clear panel.

9. Start up unit.

Vibration Switch to Set 1. Check-sensitivity setting.

Too Sensitive 2. Adjust as needed.

Short in Wire to Panel I. Check panel:

. If panel clears, load unit and monitor closely.

! • If panel does not clear, continue to next step.

2. Use volt meter to located grounded wire.

3. Replace wire.

4. If grounded wire carmot be found, refer to “Panel

Component Troubleshooting Guide.”

Broken Valve, Piston or I. Pull valve caps and inspect or replace valves as

Piston Rod necessary.

2. Pull head and inspection doors; inspect crosshead, rod,

rod nut and piston.

3. Repair or replace parts as needed.

‘ High Scrubber Level I. Check scrubber for high liquid level.

2. If liquid is found, replace level controller and repair

dump valves.

If high engine/frame vibration continues and you have taken all corrective steps, call

Mechanic.
Shutdown on Low Auxiliary Water Pressure

Troubleshooting Guide

If low auxiliary water pressure continues and you have taken all corrective steps,

call Mechanic.

. POSSIBLE CAUSE CORRECTIVE ACTIONS

[ Low Coolant Level 1. Check coolant level; add coolant as needed.

2. Check for leak on skid; repair leak as needed.

EWater Pump/Belt 1. Visually inspect auxiliary water pump and belt for wear

Failure and leaks.

2. Replace pump and/or belt as needed.

Blockage in Intercooler I. Start engine. !

2. Check differential temperature and pressure across

intercooler.

• If temperature differential is high or pressure

differential is low, inspect intercooler for possible

blockage.

Faulty Gauge 1. Use test gauge to test auxiliary water pressure.

2. Verify pressure on panel board gauge.

3. Calibrate or replace gauge as needed.

Air in System 1. Bleed out on highest point of system and at the top of

pump.

2. Check seal in water pump; replace pump as needed.

II
Shutdown on Low Coolant Level

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS..

Gauge Cocks on Sight 1. Ensure gauge cocks on sight glass are open and you have

Glass are Closed true coolant tank reading.

Coolant Leaks I. Check for loose hoses, fittings or piping causing coolant

leaks; repair or replace as needed.

2. Check for leak on skid; repair leak as needed.

3. Check for leaking water ump seal; change water pump if

seal is leaking.

Malfunctioning Level 1. Check level controller float.

Controller on Surge • If floatis not intact, replace.

• Tank 2. Check micro-switch on level controller.

• Replace micro-switch if defective.

3. Use volt ohm meter to check for shorts in wire.

• Replace wire as needed.

Internal Leaks I. Check crankcase for coolant.

2. Check for head gasket or liner leaking into base.

3. Repair leaks as needed.

If low coolant level continues and you have taken all corrective steps, call Mechanic.

12
Shutdown on Low Jacket Water Pressure

Troubleshooting Guide

POSSIBLE CAUSE CO1U{ECTWE ACTIONS

Low Coolant Level 1. Check coolant level. El

2. Add coolant to proper level as needed.

3. Check for leak on skid; repair leak as needed.

r

4. Check hoses; repair or replace as needed.

Water Pump/Belt fl I. Visually inspect water pump and belts for wear or leaks.

Failure 2. Replace pump/belts as needed.

3. Check for coolant leak; check engine base for coolant

leak.

4. Repair any leaks found.

5. Start unit.

6. Check jacket water pressure.

. If pressure is low, use test gauge to verify panel gauge

accuracy.

• If pressure is low, replace water pump or belts as

needed.

7. Check hoses/couplings on pump inlets.

. Repair/Replace parts as needed.

Faulty Gauge I. Use test gauges to check panel gauges for accuracy.

2. If panel gauge is inaccurate, calibrate or replace gauge.

Faulty Valve Position I. Ensure proper inlet/outlet valve position.

Cracked Head, Head I. Check crankcase oil level.

Gasket or Liner 2. Check for water in crank case.

3. Drain oil and check for leaking liner.

• If leak is found, repair/replace parts as needed.

Air Trapped in System 1. Bleed air at highest point on system.

2. Replace radiator cap with new one.

Plugged/Dirty Cooler 1. Clean cooler coils as needed.

If low jacket water pressure continues and you have taken all corrective steps, call

Mechanic.

13
Shutdown on High Jacket Water Temperature

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS

Low Coolant 1. Check coolant level.

2. Add coolant to proper level as needed.

3. Check for leak on skid; repair leak as needed.

Water Pump or Belt 1. Visually inspect water pump, water belts and cooler fan

Failure, belts for wear or leaks.

2. Replace pump or belts as needed.

Faulty Gauge 1. Start engine.

2. Use test gauges or pyro scanner to check water pressure

and temperature gauges.

3. Calibrate or replace gauge as needed.

Low Temperature I. Ensure proper louver position.

Differential on Cooler 2. Check cooler fins for possible blockage.

Caution: Use proper lock/tag procedures if you must

enter cooler.

3. Remove blockage or wash cooler fins.

4. Check tubes for scale obstructions; clean as needed.

Incorrect Ignition I. Check ignition timing.

Timing 2. Advance or retard timing to ExxonMobil parameters as

necessary.

Overload Detonation I. Check manifold pressure.

2. Check oxygen setting.

3. Check suctionidischarge pressures for changes in load or

‘ gas flow.

Sticking Thermostats I. Use pyro scanner on each side of thermostat if possible.

2. Remove thermostats and test in hot water.

: 3. Repair/replace thermostats as needed.

Fan Blades Need I. Check pitch on fan blades: torque to specs.

Adjustment

Incorrect Antifreeze I. Determine if antifreeze is mixed correctly.

Mixure 2. Check freeze point and pH levels; drain/replace

antifreeze as needed.

If high jacket water temperature continues and you have all corrective steps, call

Mechanic.

14
Shutdown on High Cooler Vibration

Troubleshooting Guide

POSSIBLECAUSE [ CORRECTIVE ACTIONS

Loose Mounting Bolts fl. Check bolts.

• 2. Tighten as needed.

Vibration Switch 1. Roll unit over by hand 4— 5 revolutions.

Tripped 2. Cheek for binding or noise.

3. Ensure start switch and fuel are off.

j 4. Roll engine over with starter.

5. Listen for unusual knocking or noise.

6. Reset vibration switch.

7. Clear panel.

8. Start up unit.

Vibration Switch is Set fl. Check sensitivity setting.

Too Sensitive 2. Adjust as needed.

Mechanical 1. Visually inspect belts and cooler blades to see ifthey are

Malfunction loose or damaged.

Caution: To prevent injury, use lock-out/tag-out

procedure ifyou must enter cooler.

2. Tighten. repair or replace belts, bearings or blades.

Wiring or Vibration 1. Start unit.

Switch Malfunction 2. Check panel.

3. If panel does not clear, use volt meter to locate grounded

wr

4. Replace wire as needed.

5. If grounded wire cannot be found, refer to “Panel

Component Troubleshooting Guide.”

Loose Fan Blades I. Replace fan blades as needed.

2. Check torque; retorque bolts and check blades for proper

angle.

If high cooler vibration continues and you have taken all corrective steps, call

Mechanic.

15
Shutdown on High/Low Suction Pressure

Troubleshooting Guide

POSSIBLE. CAUSE CORRECHVE ACTIONS.

Suction Control Valve 1. Start and load unit.

Malfunction 2. Compare suction pressure to reading on previous

Operator Report.

3 Check custody charts for high or low suction condition.

4. Adjust control valve or notify client of control valve

problem.

Faulty Gauges 1. Use test gauges to check panel gauges for accuracy.

2. Calibrate or replace gauges as needed.

Frozen, Plugged or I. Thaw sensing lines with methanol.

Broken Lines Use extreme caution when using methanoL Wear

appropriate ppe.

2. Replace broken tubing.

Dump Valve Hung 1. Check scrubber dumps.

Open 2. Reset dump controller.

Recycle Malfunction 1. Check recycle valve operation.

2. Adjust as needed for proper setting.

Client Production 1. Check separator pressure.

Equipment Problems 2. Look for possible equipment problems; notify Field

Reliability Specialist as needed.

Intake Screen or Filter 1. Check differential pressure across filter/screen.

Plugged 2. Change/Clean filter/screen as needed.

If highilow suction pressure continues and you have taken all corrective steps, call

Mechanic.

16
Shutdown on High Scrubber Level

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS

Closed Sight Glass I. Ensure sight glass gauge cDcks are open.

Gauge Cocks 2. Check for level in sight glass.

3. If there is no level, adjust controller as needed to

maintain level.

Level Controller I. Ensure level controller has adequate air supply and

Malfunction gas/air output pressure to dump valve.

2. Check supply regulator for malfunction.

. Repair or replace regulator if necessary.

3. Ensure level controller is working properly.

4. Check controller pans; tighten or replace as needed.

Blockage in Dump I. Check output to dump valve.

Valve 2. Ensure dump valve is operational.

3. Remove any blockage in valve.

4. Check for trapped pressure; relieve trapped pressure

SLOWLY if possible.

Frozen Dump Lines I. Check dump line for freezing.

2. Warm lines as needed.

: Caution: Use extreme caution when warming lines as

high pressure is trapped in lines.

3. Check for trapped pressure; relieve trapped pressure

SLOWLY if possible.

High Level Shutdown 1. Ensure float on high level shutdown is intact.

Malfunction • If flowat is not thtacL replace float.

2. Inspect micro-level switch in high level shut-down

switch.

• Replace shut-down switch as needed.

Short in Wiring 1. Reset panel.

2. If panel will not clear, check for short in wire; replace

wire from high level shut-down switch.

3. If grounded wire cannot be found, refer to “Panel

Component Troubleshooting Guide.”

‘7
POSSIBLE CAUSE CORRECTIVE ACTIONS

Valve Off Skid is Closed 1. Trace piping off skid to find possible closed valve.

2. Open valve if closed.

3. Check for trapped pressure; relieve trapped pressure

SLOWLY if possible.

Plugged Dump Line 1. Unscrew piping and remove obstruction if possible.

2. Run coiled cleaner in line.

3. Check for trapped pressure; relieve trapped pressure

! SLOWLY if possible.

Liquid Carryover in I. Drain customer’s air or supply gas.

Scrubber

High Pressure in IL. Ensure pressure of vessel being dumped into is lower

Customer Tank or than pressure of fluid being dumped.

Scrubber

If high scrubber level

Mechanic.

continues and you have taken all corrective steps, call

18
Shutdown on High/Low Interstage Pressure

Troubleshooting Guide

I POSSIBLE CAUSE CORRECTIVE ACTIONS

Faulty Valve or Rings I. Start and load unit.

2. Use pyro scanner to check for hot valves or rings.

3. Repair or replace as needed.

Gas Leak 1. Check for relief valve venting.

2. Ensure relief valve socks are in place.

3. Inspect relief valves for possible malfunction.

j

4. Reset or replace relief valves as needed.

: Frozen Cooler or 1. Adjust louvers to waun gas.

Tubing to Panel Gauges 2. Inject methanol into tubing lines.

Caution: Use extreme caution with methanol; high

pressure may be trapped in tubing; wear appropriate

ppe.

Faulty Gauges I. Use test gauge on interstage scrubber to test accuracy

:• against panel board gauge.

2. Calibrate or replace gauges and set kill.

Dump Valves Hung in I. Ensure dump valves ae in closed position.

Open Position 2. Set dump controller for proper.

Load Change 1. Check reycle valve for proper operation; reset as needed.

2. Check meters for flow changes; set kill switch to proper

setting.

If high/low interstage pressure continues and you have taken all corrective steps,

call Mechanic.

19
Shutdown on High/Low Discharge Pressure

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS

High Dehy or Rack 1. Check chart or meter run for discharge pressure.

Pressure 2. If high pressure, contact client to determine cause.

Frozen Pipes or 1. Open blowdown to release discharge pressure to

Equipment atmosphere.

2. If nothing exits blowdown, close louvers as needed to

warm the cooler.

3. Check pressure on panel gauge to ensure pressure is

released.

4. Check for frozen tubing lines:

• Disconnect tubing.

• Inject methanol into line.

Caution: Use extreme caution with methanol; high

pressure may be trapped in tubing.

5. Warm pipes as needed.

Relief Valve I. Check relief valve setting.

Malfunction 2. Ensure relief valve socks are in place.

3. Repair or replace relief valve or socks as needed.

Gauge Malfunction I. Use manometer (test gauge) to check panel gauges for

malfunction.

2. Calibrate or replace gauges as needed

Short in Wire in Panel I. Check panel:

• If panel clears, load unit and monitor closely.

. If panel does not clear, continue to next step.

2. Use volt meter to locate grounded wire.

3. Replace wire.

Bad Valves or 1. Ensure temperatures and pressures are within normal

Compressor Ring ranges.

2. If temperatures and pressures are abnormal, inspect for

bad valves, piston rings or piston.

3. Repair/replace parts as needed.

Broken Piping 1. Inspect piping for leaks; repair/replace piping as needed.

Recycle/Dump Valve I. Check recycle/dump valves; adjust as needed.

Malfunction

If high/low discharge pressure continues and you have taken all corrective steps, call

Mechanic.

20
Shutdown on High Discharge Temperature

Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS

Hot Valves 1. Load unit.

2. Pyro scan valve caps.

3. Repair or replace valves as needed.

High Interstage 1. Check louver position on cooler.

Temperature 2. Open louvers as needed to cool gas.

3. Check cooler fins for dirt, dust or other obstructions.

Faulty Gauges I. Use test gauges on suction/discharge pressure.

2. Calculate suction/discharge temperatures.

3. Calibrate or replace gauges as needed.

Inadequate Lubrication I. Check lubricator for proper cyliner lubrication.

2. Increase output or replace lubricator as needed.

Cylinder Piston Ring I. Inspect cylinder piston rings.

Damage 2. Replace piston rings as needed.

Low Suction Pressure 1. Check recycle load changes; reset recycle valve.

2. Check suction pressure; calibrate discharge temperature

and set kill to proper setting.

High Recycle Rate 1. Check recycle valve and flow.

2. Make adjustments as needed.

If high discharge temperature continues and you have taken all corrective steps, call

Mechanic.

21
Altronic III Ignition Troubleshooting Guide

POSSIBLE CAUSE CORRECTIVE ACTIONS

Faulty Harness Wire 1. Set volt ohm meter to ohms.

2. Disconnect power harness from ignition module.

3. Thoroughly check each harness wire for continuity.

• If wires are good, skip to “Faulty Mag Back.”

• If bad wire is found, change cannon Plug and harness.

4. Start Unit. If unit will not start, continue.

5. Check all terminals for proper grounding.

6. Replace bad electrical connections.

Faulty Mag Back (Back I. Set volt ohm meter to DC and check voltage.

Plates) Nose: Vollage should be 150-190 DC

a If voltage does not meet requirements, change mag

back (back plates).

2. Start Unit. If unit will not start, call Mechanic.

Bad Mag Back Drive 1. Check condition of drive gear teeth.

Gear 2. If teeth are missing, change figure 8.

3. Change coupling disc.

Broken Roll Pin in 1. Replace roll pin and damaged parts.

Figure 8 or Flange 2. Change mad drive adapter.

Mount

Oil in Magneto 1. Change seal or magneto (bad mag drive seal on flange

mount).

Faulty Wires, Plug or I. Visually inspect all wires, plugs and coils.

Coils 2. Replace any that are damaged.

Faulty Mag 1. Check for proper mag and backs.

2. Check mag drive.

3. Repair or replace as needed.

22
CEC Ignition Troubleshooting Guide

POSSIBLE CAUSE- COREECTIVEACTIONS

Faulty Generator or I. Disconnect generator wires to regulator.

Magneto Discs 2. Set volt ohm meter to volts AC and check voltage.

• If voltage meets requirements, skip to “Faulty

Regulator.”

3. Check condition of drive discs.

• Replace discs as needed.

• If discs are okay, replace generator.

4. Start unit. If engine will not start, continue to

troubleshoot.

Faulty Regulator 1. Reconnect wires from generator to regulator.

2. Disconnect -f/_ wires from regulator to ignition module.

3. Roll engine over.

4. Set volt ohm meter to volts DC and check voltage out of

regulator.

Note: Voltage should be 10-32 DC

. If voltage does not meet requirements ,change

regulator.

5. Start unit. If engine will not start, continue to

troubleshoot.

Faulty Harness Wire I. Set meter to ohms.

2. Disconnect power harness from ignition module.

3. Thoroughly check each harness wire for continuity.

• If wires are good. skip to “Faulty Harness or Ignition

Module.”

• If bad wire is found, change cannon Plug and harness.

4. Start unit.

• If engine will not start, continue to troubleshoot.

Faulty Harness or I. Set meter to volts DC and check voltage.

Ignition Module Note: Voltage should be at least 120 volts DC

2. If voltage doen not meet requirements, change ignition

module.

3. Start unit. If engine will not start, notify Mechanic.

Connection Box Wire I. Inspect for loose wires or connections.

are Loose 2. Tighten or replace wires as needed.

23
APPENDIX 5

Spare Parts List - HOS 4

Spare Parts List - HOS 6
SPARE PARTS LIST

MeElmo Creek

Spare Critical Machinery Equipment

MeElmo Creek Unit HOS 4 Spare Parts List

Compressor f Compressor Suction/Discharge Valves

Ldi Filters

Lubricator Parts

Electric Motor Driver Thermocouples

Vibration Probes

Cooler V-Belts

Pulleys

: Gaskets and Seal Pins

Instruments and Controls Temperature Switches

Pressure Switches

Instrument Tubing

Position Indicators

Pressure Gauges

Thermometers

* These parts are housed in a multipurpose building on site. The inventory of spares is

maintained by logging any part removed arid initiating a purchase requisition to replace

the part.
SPARE PARTS LIST

MeElmo Creek Unit HOS 6 Spare Parts List

Compressor Compressor Suction/Discharge Valves

Piston Rings

Piston Rods

Gaskets

Packing Gland Assembly

Crosshead Assembly

Oil Filters

Lubricator Parts

Electric Motor Driver Thermocouples

Vibration Probes

Cooler V-Belts

Pulleys

Gaskets and Seal Pins

; Instruments and Controls Temperature Switches

Pressure Switches

Instrument Tubing

Position Indicators

Pressure Gauges

Thermometers

* These parts are housed in a multipurpose building on site. The inventory of spares is maintained

by logging any part removed and initiating a purchase requisition to replace the part.
APPENDIX B

MCELMO CREEK UNIT 

ROOT CAUSE FAILURE ANALYSIS 

PROGRAM

McElmo Creek Unit Oil Production Facility

PSD Permit Number: NU 05-01

This document shall apply to and be binding upon the owner(s) and operator(s) of 

the McElmo Creek Unit Oil Production Facility, including the Resolute Natural 

Resources Company.
McElmo Creek Unit Root Cause Failure Analysis

PSD Permit No. NN 05-01

Root Cause Failure Analysis Program

Root Cause Failure Analysis

Root cause failure analysis (RCFA) methodology is incorporated into the standard operating 

procedures in the McElmo Creek Unit field area. It provides a structured format in analyzing an 

event and helps to determine necessary measures to prevent future occurrences. The RCFA 

program includes the following components:

Step 1 – Notification

Field supervisor determines that an investigation is warranted and appoints personnel to 

conduct a root cause failure analysis for each Flaring Incident, except for those Flaring 

Incidents caused by scheduled maintenance or a CO2 breakthrough.

Step 2 – Plan Investigation

Once the decision is made to investigate a Flaring Incident, the investigator develops an 

investigation strategy. To do this an investigator can use the information initially available to 

develop a preliminary Snap Chart (see attachment). This will help the investigator understand 

what happened, identify areas where more information is needed, and identify conflicting 

information.

For each of the causal factors (problems) on the Snap Chart, the investigator can rapidly 

consider the questions that need to be answered to identify root causes using the Root 

Cause Tree.

With insight gained from using these two techniques, the investigator or the investigation 

team can plan the initial investigation strategy by:

• Identifying the key plant parameters and event times that need to be checked to verify the 

incident's sequence of events and technical accuracy.

• Identifying key pieces of evidence (broken parts, logbooks, chart recorders, computer 

printouts, etc.) that need to be collected and preserved.

• Requesting copies of the applicable procedures that should have been used during the 

incident.

• Selecting an initial group of individuals for interviews to fill in gaps in the information or to 

resolve conflicting information.

Step 3 – Collect Information

Collecting information (interviewing people and analyzing physical evidence) is an ongoing 

process throughout the investigation and crucial to understanding the incident and why it 

occurred. The investigator(s) are instructed to consult the TapRoot User Guides for each 

technique.
McElmo Creek Unit Root Cause Failure Analysis

PSD Permit No. NN 05-01

Step 4 – Determine Sequence of Events

An investigator or team collects several people's perceptions of what happened during an 

incident and the problems that were associated with the activities and equipment during an 

incident. The investigator has to blend these various perceptions into the story of what 

happened. The best technique for doing this is the Snap Chart.

A Snap Chart is an excellent graphic tool. In developing the Snap Chart, the investigator 

organizes the information being collected on a graphical chart to better understand it. This 

organization of the information often causes the re-evaluation of assumptions or facts that 

conflict with other information. This organization also helps the investigator identify gaps in 

logic of what happened.

When you have team investigations or if you are interviewing several people at one time, 

drawing a Snap Chart together helps facilitate gathering everyone's information and increases 

the effectiveness of meetings or group interviews. During individual interviews, the investigator 

may find it helpful to sketch a Snap Chart with the interviewee to verify their verbal 

communication. The investigator should keep a master Snap Chart updated as "facts" are 

verified.

Step 5 – Identify Incident's Causal Factors

Once the sequence of the incident is thoroughly understood, the investigator needs to identify all 

the factors that, if eliminated, would have prevented the incident from occurring or would have 

significantly mitigated its consequences. These factors are called causal factors.

Often investigators can identify the causal factors by simply inspecting the Snap Chart and 

asking, "If I could remove or correct the problems identified on this chart, which ones would 

prevent this incident from occurring or make it less severe?" A more formal technique is called 

Barrier Analysis and is used as an optional approach to identifying the causal factors (which in 

barrier analysis would be called broken barriers). In the next step, the investigator analyzes 

each causal factor for its root cause(s) using the Root Cause Tree.

Step 6 – Identify Root Causes

Once the causal factors are identified, the next step is to identify the root causes. This is done 

using the Root Cause Tree. The Root Cause Tree User's Manual provides questions that help 

the investigator pinpoint the incident's root causes.

The Human Performance Troubleshooting Guide on the Root Cause Tree helps an investigator 

decide which human performance related causes need further investigation. It also ensures 

that experienced investigators consider all potential causes of human performance difficulties 

(rather than just concentrating on the ones that they understand the best).

In some cases, the root causes of an incident are impossible to identify. When the Root 

Cause Tree is used to analyze these difficult cases, the failure to identify the root cause is 

clear because the investigation stops before the lowest level on the Root Cause Tree is 

reached.

A particular incident's specific root causes identified using the Root Cause Tree are used in the 

next two steps to identify programmatic causes and to develop/evaluate corrective actions.
McElmo Creek Unit Root Cause Failure Analysis

PSD Permit No. NN 05-01

Step 7 – Identify Generic (Programmatic) Causes

The specific causes for a particular incident may stem from more pervasive problems -

generic or programmatic causes. For example, if a particular incident is caused by a valve 

not having a label plate, other incidents may occur because of similar valve labeling 

problems with different valves. Therefore, the investigator needs to look at each specific 

cause for a particular incident and decide if a more program-wide weakness exists that 

needs broader corrective action.

Generic causes can be identified by investigating the pervasive nature of the problem. The 

pervasive nature of the problem can be determined by the investigator's experience, 

performing a special programmatic evaluation, or by reviewing previous incident statistics.

Correcting generic problems can have a much broader impact on safety, environmental 

performance, and reliability since they address whole classes of problems rather than just 

the specific causes of an incident.

Step 8 – Develop Corrective Action

The specific and generic causes that are identified in steps 6 and 7 provide a list of problems 

that require corrective action implemented in a timely manner. No matter what corrective 

action is proposed, there is always a chance to somehow circumvent the intent of the 

corrective action. Therefore, proposing corrective actions for each cause identified (that is, 

multiple corrective actions) provides a defense-in-depth to preventing the incident from 

recurring. In some cases, correcting a particular root cause may be too difficult. In these 

cases, the investigator should ensure that there are sufficient other corrective actions 

proposed to reduce the likelihood of the incident's recurrence.

If the root cause level was reached in the incident investigation, the corrective actions are 

usually fairly straightforward to identify. If the investigator could not reach the root cause 

level, he/she will still need to develop ideas for corrective actions. If the incident has been 

identified as a repeat of a similar past incident, the investigator should ask if the corrective 

actions proposed are different from the corrective actions previously tried and why the 

previous corrective actions failed.

Investigators should work with line management as much as possible when developing 

corrective actions. They should have thoughtful consideration to ensure the corrective 

actions recommended are SMART:

S - Specific

M - Measurable 

A - Accountable

R - Reasonable 

T - Timely

The investigator should develop a Corrective Actions Matrix Table to use in conjunction with 

the Snap Chart for effective management presentations. The Corrective Actions Matrix 

should have headings as shown below:

Causal Factors Root Causes &

Generic Causes

Corrective

Actions

Responsible 

Department & 

Person to 

Implement

Due Date For

Corrective 

Actions 

Completion
McElmo Creek Unit Root Cause Failure Analysis

PSD Permit No. NN 05-01

Step 9 – Report

All of the information and analysis performed up to this point allows the investigator to write a 

clear, complete incident report describing what happened, why it happened, and what needs to 

be corrected to prevent the incident (or similar incident), and make effective management 

presentations. Reports and presentations are extremely important because the case made 

therein often determines whether the recommended corrective action is expeditiously 

implemented or is given a low priority and delayed indefinitely.

An important part of incident reporting communication is the Snap Chart. A Snap Chart can be 

particularly helpful in providing an organized display of what happened and why it happened. 

When used with the Corrective Actions Matrix described in step 8, these two tools make a 

powerful presentation of much information in a short time to provide management with 

knowledge needed to make the best decisions about using resources to improve performance.
ATTACHMENT
Develop SnapCharT®

Get Started

- Determme what you are investigating

Define sequence of events

- Identify missing or needed

information

- Investigate further to find missing

information

Define causal factors

Root Cause Analysis

Analyze each Causal Factor’s Root

Causes

- Analyze one Causal Factor at a

time

- begin at the top of the Tree and work

through the questions to determine

what Basic Cause Categories apply

- Examine all of the Basic Cause

Categories that apply to determine

what root causes apply

Use the TapRoor® Root Cause Tree®

Dictionary for definitions to all of the

questions and root causes on the Root

Cause Tree®

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OCopynght 2000 by System Improvements Inc., Knoxville, TN. All Rights Reserved Worldwide. Duplication Prohibited.
U.S. ENVIRONMENTAL PROTECTION AGENCY

REGION IX

AMBIENT AIR QUALITY IMPACT REPORT

& FACT SHEET

For a Clean Air Act 

Prevention of Significant Deterioration Permit Amendment

Resolute Natural Resources Company

McElmo Creek Unit Oil Production Facility

PSD Permit No. NU 05-01

October 2014
This page left intentionally blank
i

PROPOSED CLEAN AIR ACT 

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT AMENDMENT

RESOLUTE NATURAL RESOURCES COMPANY

MCELMO CREEK UNIT OIL PRODUCTION FACILITY

PSD Permit NU 05-01

Ambient Air Quality Impact Report & Fact Sheet

Table of Contents

ACRONYMSACRONYMS & ABBREVIATIONS.................................................................................IV

EXECUTIVE SUMMARY................................................................................................................... 1

1. PURPOSE OF THIS DOCUMENT ................................................................................................. 2

2. APPLICANT ............................................................................................................................... 2

3. FACILITY LOCATION................................................................................................................ 2

4. PROJECT DESCRIPTION............................................................................................................ 3

4.1 Facility History ............................................................................................................. 3

4.2 Facility Operations........................................................................................................ 4

4.2.1 Field Operations......................................................................................... 4

4.2.2 Gas Compression Plant .............................................................................. 4

4.3 PSD Permit History....................................................................................................... 6

4.4 PSD Permit Changes..................................................................................................... 7

5. PROJECT EMISSIONS .............................................................................................................. 10

6. APPLICABILITY OF THE PREVENTION OF SIGNIFICANT DETERIORATION REGULATIONS... 11

7. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS ........................................................ 12

7.1 BACT for Sulfur Dioxides.......................................................................................... 13

7.1.1 Step 1 - Identify All Control Technologies for SO2................................... 13

7.1.2 Step 2 - Eliminate Technically Infeasible Options for SO2....................... 14

7.1.3 Step 3 - Rank Control Technologies ......................................................... 15

7.1.4 Step 4 – Economic, Energy and Environmental Impacts for SO2............. 16

7.1.5 Step 5 – Select BACT for SO2 ................................................................... 16

7.2 BACT for Carbon Monoxide...................................................................................... 18

7.2.1 Step 1 - Identify All Control Technologies for CO ................................... 18

7.2.2 Step 2 - Eliminate Technically Infeasible Options for CO ....................... 18

7.2.3 Step 3 - Rank Control Technologies for CO............................................. 18
ii

7.2.4 Step 4 – Economic, Energy and Environmental Impacts for CO ............. 20

7.2.5 Step 5 – Select BACT for CO.................................................................... 20

7.3 BACT for Nitrogen Oxides......................................................................................... 21

7.3.1 Step 1 - Identify All Control Technologies for NOX.................................. 21

7.3.2 Step 2 - Eliminate Technically Infeasible Options for NOX...................... 22

7.3.3 Step 3 - Rank Control Technologies for NOX ........................................... 23

7.3.4 Step 4 – Economic, Energy and Environmental Impacts for NOX............ 25

7.3.5 Step 5 – Select BACT for NOX .................................................................. 25

7.4 BACT for Volatile Organic Compounds.................................................................... 26

7.4.1 Step 1 - Identify All Control Technologies for VOC................................. 26

7.4.2 Step 2 - Eliminate Technically Infeasible Options for VOC..................... 26

7.4.3 Step 3 - Rank Control Technologies ......................................................... 29

7.4.4 Step 4 –Economic, Energy and Environmental Impacts for VOC............ 32

7.4.5 Step 5 – Select BACT for VOC.................................................................. 33

8. AIR QUALITY IMPACTS ANALYSIS......................................................................................... 34

8.1 Introduction................................................................................................................. 34

8.1.1 Overview of PSD Air Impact Requirements.............................................. 34

8.1.2 Identification of MCU Facility Main Flare Modeling Documentation .... 35

8.2 Background Ambient Air Quality............................................................................... 35

8.3 Modeling Methodology for Class II areas.................................................................. 36

8.3.1 Model selection ......................................................................................... 36

8.3.2 Meteorology model inputs......................................................................... 37

8.3.3 Land characteristics model inputs............................................................ 37

8.3.4 Model receptors........................................................................................ 38

8.3.5 Stack parameter model inputs................................................................... 38

8.3.6 Good Engineering Practice (GEP) Analysis ............................................ 39

8.4 National Ambient Air Quality Standards (NAAQS) and PSD Class II Increment 

Consumption Analysis................................................................................................ 40

8.4.1 Pollutants with Significant Emissions....................................................... 40

8.4.2 Preliminary Analysis: Project-Only Impacts............................................ 40

8.4.3 Cumulative Impact Analysis ..................................................................... 41

8.5 Class I Area Analysis.................................................................................................. 43

8.5.1 Air Quality Related Values ....................................................................... 43

8.5.2 Class I Increment Consumption Analysis................................................. 44

9. ADDITIONAL IMPACT ANALYSIS ............................................................................................ 45

9.1 Soils and Vegetation ................................................................................................... 45

9.2 Visibility Impairment.................................................................................................. 47

9.3 Growth ........................................................................................................................ 48

10. ENDANGERED SPECIES ACT................................................................................................... 49

11. NATIONAL HISTORIC PRESERVATION ACT........................................................................... 49
iii

12. MAGNUSON-STEVENS FISHERY CONSERVATION AND MANAGEMENT ACT.......................... 50

13. COASTAL ZONE MANAGEMENT ACT ..................................................................................... 50

14. ENVIRONMENTAL JUSTICE ANALYSIS ................................................................................... 50

15. CLEAN AIR ACT TITLE V OPERATING PERMIT .................................................................... 51

16. PUBLIC PARTICIPATION ......................................................................................................... 51

16.1 Public Comments........................................................................................................ 51

16.2 Public Information Meeting & Public Hearing........................................................... 51

16.3 Availability of Permit Documents.............................................................................. 52

16.4 Final Permit Decision ................................................................................................. 53

16.5 Contact Information.................................................................................................... 54

17. CONCLUSION AND PROPOSED ACTION .................................................................................. 54
iv

ACRONYMS & ABBREVIATIONS 

AAQIR Ambient Air Quality Impact Report and Fact Sheet

Act Clean Air Act [42 U.S.C. Section 7401 et seq.]

Applicant Resolute Natural Resources Company

bext Light extinction coefficient

BA Biological Assessment

BACT Best Available Control Technology

BTU British thermal units

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.]

CMS Continuous Monitoring System

CFR Code of Federal Regulations

CO Carbon Monoxide

CO2 Carbon Dioxide

Consent Decree United States v. Mobil Exploration and Producing U.S. Inc., Case No. 2:05–

CV–319, filed June 8, 2005

CZMA Coastal Zone Management Act

DSCFM Dry standard cubic feet per minute

e-mail Electronic mail

g grams

gr grains

gr/scf Grains per Standard Cubic Feet

EAB Environmental Appeals Board

EPA United States Environmental Protection Agency

ESA Endangered Species Act

ESP Electrostatic Precipitator

Facility McElmo Creek Unit Oil Production Facility

Fact Sheet Ambient Air Quality Impact Report and Fact Sheet

FLM Federal Land Manager

FWS United States Fish and Wildlife Service

GHG Greenhouse Gases

HP Horsepower

HHV higher heating value

hr hour

ISO International Organization for Standards

lb, lbs pound, pounds

km kilometers

kW kilowatts of electrical power

lb, lbs pound, pounds

m meters

m/s meters per second

MCU Facility McElmo Creek Unit Oil Production Facility

min minute

μg/m3 microgram per cubic meter

MMBTU million British thermal units
v

MSFCMA Magnuson-Stevens Fishery Conservation and Management Act

MW Megawatts of electrical power

NAAQS National Ambient Air Quality Standards

NESHAP National Emission Standards for Hazardous Air Pollutants

NHPA National Historic Preservation Act

NMFS National Marine Fisheries Service

NNEPA Navajo Nation Environmental Protection Agency

NO Nitrogen Oxide or Nitric Oxide

NO2 Nitrogen Dioxide

NOx Nitrogen Oxides or Oxides of Nitrogen (NO + NO2)

NP National Park

NPS National Park Service

NSPS New Source Performance Standards, 40 CFR Part 60

NSR New Source Review

O2 Oxygen

Permittee Resolute Natural Resources Company; or the owner and/or operator of the 

McElmo Creek Unit Oil Production Facility

PM Total Particulate Matter

PM2.5 Particulate Matter less than 2.5 micrometers (μm) in diameter

PM10 Particulate Matter less than 10 micrometers (μm) in diameter

ppm parts per million

PSD Prevention of Significant Deterioration

PTE Potential to Emit

PUC Public Utilities Commission

RATA Relative Accuracy Test Audit

RBLC U.S. EPA RACT/BACT/LAER Clearinghouse

scf standard cubic foot

SIL Significant Impact Level

SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide

SOx Sulfur Oxides

tpy tons per year

USFS United States Forest Service

VOC Volatile Organic Compounds

WA Wilderness Area
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Proposed Prevention of Significant Deterioration Permit Amendment

Ambient Air Quality Impact Report and Fact Sheet

RESOLUTE NATURAL RESOURCES COMPANY

MCELMO CREEK OIL UNIT PRODUCTION FACILITY

EXECUTIVE SUMMARY

The United States Environmental Protection Agency (EPA) is amending the Clean Air Act 

(CAA) Prevention of Significant Deterioration (PSD) permit for the McElmo Creek Unit Oil 

Production Facility (MCU Facility or Facility) to incorporate pollution limits, terms, and 

conditions of a federal Consent Decree that applies to the Main Flare at the Facility. The MCU 

Facility is an existing oil and gas production operation located within the Four Corners Area on 

the Navajo Nation Indian Reservation near the city of Aneth, San Juan County, Utah. The 

Facility is on the McElmo Creek Unit oilfield, which includes field operations and a gas 

compression plant. It is owned and operated by the Resolute Natural Resources Company

(Resolute). 

EPA is issuing a proposed amended PSD permit to Resolute for the MCU Facility, which is 

consistent with the requirements of the PSD program for the following reasons: 

• The proposed amended PSD permit requires the Best Available Control Technology (BACT) 

to limit emissions of volatile organic compounds (VOC), nitrogen oxides (NOx), sulfur 

dioxide (SO2), and carbon monoxide (CO). 

• The proposed emission limits will protect the National Ambient Air Quality Standards 

(NAAQS) for ozone, nitrogen dioxide (NO2), SO2, and CO. Since VOC is a precursor in the 

formation of ground level ozone, there is a NAAQS for ozone, but no NAAQS specifically 

for VOC. 

• The proposed emission limits will not cause or contribute to violations of any applicable PSD 

increments for the pollutants regulated under the PSD permit;

• The Facility will not adversely impact soils and vegetation, or air quality, visibility, and 

deposition in Class I areas, which are parks or wilderness areas given special protection 

under the Clean Air Act; 
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1. PURPOSE OF THIS DOCUMENT

This document serves as the Ambient Air Quality Impact Report and Fact Sheet for the proposed 

amended PSD permit for the MCU Facility. This document describes the legal and factual basis 

for the proposed amended PSD permit, including requirements under the CAA, Subchapter I, 

Part C (42 U.S.C. Section 7470, et. seq.) and the PSD regulations at Title 40 of the Code of 

Federal Regulations (CFR) § 52.21. This document also serves as a Fact Sheet for the proposed 

amended PSD permit per 40 CFR § 124.8.

2. APPLICANT

Resolute Natural Resources Company

1675 Broadway, Suite 1950

Denver, Colorado 80202

3. FACILITY LOCATION

The MCU Facility is located in Section 31, Township 40 South, Range 25 East within the Four 

Corners Interstate Air Quality Control Region on the Navajo Nation Indian Reservation near the 

city of Aneth, San Juan County, Utah. The map in Figure 3-1 shows the location of the Facility. 

Figure 3-1: Location of McElmo Creek Unit Oil Production Facility
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The Four Corners Interstate Air Quality Control Region is currently designated as attainment or 

unclassifiable for all criteria pollutants: nitrogen dioxide (NO2), sulfur dioxide (SO2), carbon 

monoxide (CO), particulate matter less than 10 microns in aerodynamic diameter (PM10), fine 

particulate matter less than 2.5 microns (PM2.5), lead, and ozone (regulated as volatile organic 

compounds (VOC) and oxides of nitrogen (NOx), which are precursors to ozone formation). The 

U.S. Environmental Protection Agency (EPA) is the PSD permitting authority for stationary 

source located on the Navajo Nation Indian Reservation because Navajo Nation Environmental 

Protection Agency (NNEPA) currently does not have a delegated or federally-approved PSD 

permitting program.

4. PROJECT DESCRIPTION

4.1 FACILITY HISTORY

The MCU Facility began operation in the 1950s. At that time, it was owned and operated by 

Superior Oil. Mobil purchased the Facility from Superior Oil in 1984.1 

In 1986, Mobil constructed a natural gas processing plant at the Facility, which included

dehydrator, amine treater, refrigeration separation unit, a natural gas liquids recovery unit and 

compressors to transport the produced liquid natural gas. Mobil installed an upright flare (Main 

Flare) as part of the emergency relief system for the gas processing plant, and has used it as a 

control device to combust process upset gas. At that time, Mobil did not obtain a permit for the 

Main Flare. Petroleum liquid storage tanks and heater treaters were also installed in the early 

1990s. Mobil stopped operating the equipment at the gas processing plant to separate out the 

natural gas liquids in 1996, but continued to operate the Main Flare at the gas processing plant.

In 1997, following a fire, most all processing equipment was removed. The Main Flare was kept 

for emergency flaring, flaring closed drain system fumes, and control of dehydrator emissions. 

The former gas processing plant is now referred to as the gas compression plant. The 

compressors were later converted to run on electricity.

In 1997 and 1999, EPA issued Notice of Violations for, among other things, permitting violations 

relating to the Main Flare. The Facility is currently subject to a federal Consent Decree for the 

Main Flare.2

 The Consent Decree imposes interim emission limitations, monitoring, operation 

and maintenance, and reporting requirements that apply to the Main Flare until these 

requirements are incorporated into the PSD permit.

In April 2006, Resolute, in partnership with Navajo Nation Oil and Gas Company, acquired 

ownership of the MCU Facility, and assumed operation of the Facility on June 1, 2006.

 1 Mobil includes Mobil Exploration & Producing U.S., Inc. and ExxonMobil Production Company. The 

ExxonMobil Production Corporation was formed in 1999 by the merger of Exxon and Mobil, and ExxonMobil 

became the owner and operator of the MCU facility that year. 

2 United States v. Mobil Exploration and Producing U.S. Inc., filed June 8, 2005.
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4.2 FACILITY OPERATIONS

The MCU Facility is on McElmo Creek Unit oilfield, which is primarily involved in crude 

petroleum oil production. The McElmo Creek Unit oilfield operation includes field operations 

and a gas compression plant.

4.2.1 Field Operations

The field operations located on the McElmo Creek Unit oilfield consist of approximately 90 

producing wells where petroleum crude oil is recovered from producing strata, brought to the 

surface to be stored at either a satellite or a tank battery. There are eleven satellites that function 

as testing facilities for producing wells and four tank batteries. 

Crude oil is recovered using water alternating gas (WAG) injection, which is a tertiary recovery 

method. WAG injection is where water is injected into the producing strata, followed by carbon 

dioxide (CO2) gas, and again by water to enhance crude oil recovery to the surface. CO2 is 

delivered to the MCU Facility via pipeline from the KinderMorgan gas plant at the Shell Dome, 

which is approximately 25 miles north of the Facility. 

Natural gas, water, and solids that are extracted from the producing strata with the crude oil are 

separated before the oil is stored. Separated water is re-injected back into the producing strata 

via the water injection station. Separated gas is sent to the gas compression plant at the MCU 

Facility and processed as described in Section 4.2.2 below. Crude oil is sold at the lease 

automatic custody transfer (LACT) unit at each central tank battery and transported to Western 

Refining’s Ciniza Refinery in Gallup, New Mexico, via the Running Horse Pipeline, which is 

owned and operated by the Navajo Nation Oil and Gas Company.

Gases sent to the gas compression plant are compressed, dried through a glycol dehydrator, 

blended with carbon dioxide (CO2), and re-injected into the field. Liquids are further separated at 

the central tank batteries, with oil being sold and transported through a pipeline system. Water 

from the central tank batteries is pumped to the water flood injection plant.

4.2.2 Gas Compression Plant

The gas compression plant is used to support tertiary recovery of crude oil in the McElmo Creek 

Unit oilfield. The goal of the plant is to receive produced gas through a gathering system, 

pressure the gas up to a suitable working pressure, and then re-inject the gas into the producing 

strata to maintain reservoir pressure. The natural gas is injected with produced water into the 

producing strata using a dual injection system. Due to varying water injection demands in the 

field, and to the number of wells being serviced at any time, the gas volume entering the plant 

can vary between 10 and 18 million standard cubic feet per day (MSCFD). 
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The gas is processed in three main steps: inlet separation, compression and re-injection. The 

inlet separation consists of an inlet slug receiver which collects free liquids. The gas then passes 

through filter vessels which collect any incoming solids. During the compression stage, 4 highspeed electrically-driven reciprocating compressors, which utilize 6300 brake horsepower 

(BHP), are used to compress the gas. Each compressor consists of four stages which raise the 

pressure of the incoming gas from 40 psig to 2900 psig. Each stage has a dedicated aerial cooler 

and liquid scrubber vessel. On the largest compressor, inter stage dehydration takes place to 

remove water for corrosion mitigation. During re-injection, the gases from the four compressors 

discharge into a single header, where purchased CO2 is co-mingled to achieve a daily injection 

goal of 24 MSCFD. The gas is then distributed to the field. During plant upsets, additional CO2

is purchased to meet the daily injection goal.

The Main Flare at the gas compression plant combusts gases that have been bypassed around the 

facility’s electric-driven compressors or that come through various emergency relief valves in the 

compression plant. Additionally, the vent stream from the plant’s glycol dehydrator is directed 

to the Main Flare.

A flow diagram of the Facility’s gathering system operations is presented in Figure 4-1, 

illustrating the flow through the satellite facilities, central tank batteries, water flood injection 

plant, and gas compression plant. Figure 4-1 presents a simple block flow diagram for the gas 

compression plant, including the streams directed to the Main Flare.
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Figure 4-1: McElmo Creek Unit Oil Production Facility Operations

Source: April 2008 PSD Application, Figure 2-2

4.3 PSD PERMIT HISTORY

The PSD permit history associated with the MCU Facility is as follows.

3

February 2, 1987 – EPA issued the initial PSD permit to Mobil for the modification of the MCU 

Facility for the MCU Stage 2 CO2 Project. The permit authorized the construction and operation 

of three 1730 horsepower (HP) reciprocating internal combustion engines.

October 27, 1987 – EPA amended the PSD permit to replace the three reciprocating internal 

combustion engines with two 3216 HP natural gas-fired turbines. 

 3 The previous PSD permits for the MCU facility were issued by the United States Environmental Protection 

Agency, Region 8 Office (EPA Region 8). EPA Region 8 was the PSD permitting authority for the portion of the 

Navajo Nation Indian Reservation in southeastern Utah, until October 9, 1991. According to a Memorandum of 

Agreement dated October 9, 1991 between EPA Regions 6, 8, 9 and the Navajo Nation Indian Reservation regarding 

the implementation of EPA-related activities on the reservation, this authority was transferred to EPA Region 9. 

The Navajo Nation Indian Reservation covers portions of northeastern Arizona, southeastern Utah, and northwestern 

New Mexico. 
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March 21, 1989 – EPA issued a letter to Mobil amending stack heights in the PSD permit. 

EPA’s letter was in response to a January 25, 1989 letter from the Mobil to EPA stating that the 

height of the MCU Facility stacks had been increased from the height in the amended PSD 

permit issued on October 27, 1987. Mobil’s January 25, 1989 letter stated that the height of the 

stacks were approximately 40 feet instead of 20 feet.

April 19, 1991 – EPA amended the PSD permit to (1) replace existing heating equipment at the 

Facility with a waste heat recovery unit; (2) temporarily replace the existing gas turbine with an 

identical unit during maintenance overhaul of the turbine, (3) change the rating of the existing 

gas turbine one gas turbine which was installed from 3216 HP to 4390 HP and add requirements 

for the New Source Performance Standard for Gas Turbines (40 CFR Part 60, Subpart GG); and 

(4) remove the second gas turbine from the permit since it was never installed. 

Several pieces of equipment have been removed from MCU Facility.4

 During the mid-1990s, 

the natural gas liquids facility was shut down. With the shutdown of the natural gas liquids 

facility, all gas-driven compressors and turbines at the gas compression plant were converted to 

electric units and sulfur recovery was ceased. The natural gas liquids and sulfur recovery 

processes were discontinued and dismantled in June 1998. Also, the only remaining gas turbine 

was removed in June 1998. During that same time period, gas dehydration was reduced. The 

plant currently operates one TEG dehydration unit. The CO2 line heater, which was used during 

severe cold weather, was removed from the MCU Facility in March 2004.

4.4 PSD PERMIT CHANGES

This permit action consists of incorporating pollution limits, terms, and conditions for the 

already existing Main Flare into the PSD Permit for the MCU Facility pursuant to a federal 

Consent Decree, which was filed and became effective on June 8, 2005. Paragraph 14.a of the 

Consent Decree requires the owner and operator of the MCU Facility to submit, to EPA, a PSD 

permit application in accordance with the CAA and the PSD regulations at 40 CFR § 52.21 for 

the MCU Facility’s Main Flare not later than the 180 days after the effective date of the Consent 

Decree. The Consent Decree requires that the PSD application include, among other things, 

BACT and air quality analyses for SO2, CO, NOx, and VOC for the Main Flare. It also requires 

that the PSD application include terms and conditions that are at least as stringent as the 

following Consent Decree requirements.

5

• Paragraph 9.a (Emission Limits)

• Paragraph 10 (Monitoring)

• Paragraph 11 (Operation and Maintenance of Main Flare and Compressors)

• Paragraph 25(i)-(ix) (Reporting and Recordkeeping Requirements)

 4

 See letter from ExxonMobil Production Company (Neil J. Ryan) to EPA Region 9 (Gerardo C. Rios), dated 

May 27, 2004. 5

 See Paragraph 4.o of the Consent Decree.
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Mobil submitted a PSD application dated December 5, 2005 for the Main Flare, and also 

provided supplemental information in 2006 and 2007. Resolute, which acquired ownership of 

the MCU Facility in 2006, submitted a revised PSD application dated April 2008 for the Main 

Flare, as well as various supplemental information thereafter. 

This permit action also consists of updating the equipment covered in the PSD Permit, which 

includes removing emission units that have been shut down and removed from the MCU Facility 

site and the associated requirements that apply to these units. Table 4-1 shows the equipment 

and activities listed in Tables 1 and 2 of the PSD Permit, and Table 4-2 shows other operations at 

the Facility that are not explicitly listed in the permit. Both tables also show the current status of 

these equipment and operations.

Table 4-1: Equipment in Tables 1 & 2 of the MCU Facility’s 1991 PSD Permit6

Operation Status

T4500 Gas Turbine (4390 HP) Shutdown 1997

Waste Heat Recovery Unit (11 MMBtu/hr) Shutdown 1997

Ingersoll Rand IC Engine (491 HP) Shutdown 1993

Fairbanks Morse IC Engine (1712 HP) Shutdown 1997

Fairbanks Morse IC Engine (1712 HP) Shutdown 1997

Fairbanks Morse IC Engine (1848 HP) Shutdown 1997

Fairbanks Morse IC Engine (1848 HP) Shutdown 1997

DPC-540 IC Engine (470 HP) Shutdown 1998

HC Liquid Reboiler (1 MMBtu/hr) Shutdown 1993

Heat Medium Heater (4 MMBtu/hr) Shutdown 1993

Heat Medium Heater (12.2 MMBtu/hr) Shutdown 1991

TEG Reboiler (0.33 MMBtu/hr) Shutdown 1991

TEG Reboiler (0.33 MMBtu/hr) Shutdown 1991

TEG Reboiler (0.33 MMBtu/hr) Shutdown 1991

TEG Reboiler (0.1 MMBtu/hr) Shutdown 1991

Sources: Letter from ExxonMobil Production Company (Neil J. Ryan) to EPA Region 9 (Gerardo C. Rios), dated May 27, 2004; 

Email from Resolute to EPA Region 9 regarding additional information, dated December 4, 2012

 6 The MCU Facility’s most recent PSD permit was issued by EPA on April 19, 1991.
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Table 4-2: Other Equipment and Operations at the MCU Facility7

Operation Status

Natural Gas Liquids Processing Shutdown 1998

Natural Gas Processing Facility Shutdown 1998

Main Flare (618,104 scf/hr) Operational

TEG Reboiler (0.75 MMBtu/hr) Operational

Gasoline Storage Tank Shutdown 1993

Gasoline Storage Tank Shutdown 1993

Gasoline Storage Tank (10,000 gallon nominal capacity) Operational

Diesel Storage Tank Shutdown 1993

CO2 line heater Shutdown 2004

Glycol Heater for TEG regenerator (12 MMcfd) Operational

Sources: Letter from ExxonMobil Production Company (Neil J. Ryan) to EPA Region 9 (Gerardo C. Rios), dated May 27, 2004; 

Email from Resolute to EPA Region 9 regarding additional information, dated December 4, 2012

The Facility currently operates the following air emission units remaining at the site: Main Flare, 

gasoline tank, triethylene glycol (TEG) dehydration unit reboiler, and glycol heater. Other than 

the replacement of a fixed speed fan with a variable speed fan to provide better pollution control 

at the Main Flare, this permit action does not authorize any new construction or modification of 

existing equipment at the MCU Facility.

 7

 The listed equipment and operations were located at the MCU site, but were not included in Tables 1 and 2 of the 

MCU Facility’s 1991 PSD Permit. 
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5. PROJECT EMISSIONS 

This section describes the emission levels of SO2, CO, NOx, and VOC from the Main Flare, and 

the emission requirements in the Consent Decree. 

Table 5-1 shows the actual emissions for the Facility, and Table 5-2 shows the greenhouse gas 

emission estimates. 

Table 5-1: Actual Emissions (2011) for MCU Facility

Operation Size / 

Throughput

SO2

(tpy)

NOx

(tpy)

CO

(tpy)

VOC

(tpy)

PM

(tpy)

Main Flare 618,104 scf/hr 26.7 8.4 45.4 54.9 0.9

Glycol Heater 12 MMscf/day 0.0 0.1 0.5 2.7 0.0

TEG Reboiler 0.75 MMBtu/hr 0.0 0.3 0.3 0.0 0.0

Gasoline Storage Tank 10,000 Gallons 0.0 0.0 0.0 2.0 0.0

Total 26.7 8.8 46.2 59.6 0.9

Source: Email from Resolute to EPA Region 9 regarding additional information, dated December 4, 2012

Table 5-2: CO2e Emission Estimates for MCU Facility

Operation Emissions (Metric Tons CO2e)

Main Flare 26,122

Glycol Dehydrator 1,092

Compressor Rod Packing Venting 242

Equipment Leaks 51

Total Facility GHG Emissions 27,507

Source: Email from Resolute to EPA Region 9 regarding additional information, dated April 18, 2012

Paragraphs 14.a and 9.a of the Consent Decree requires that BACT for the Main Flare be at least 

as stringent as the limits, based on rolling 365-day cumulative amounts (to be calculated each 

day), in Table 5-3. Paragraph 9.a of the Consent Decree also requires that the field flares shall 

not be used to circumvent these emission limits.

Table 5-3: Minimum Consent Decree BACT Requirements

SO2 NOx CO VOC

60 tpy 13.4 tpy 73 tpy 95.4 tpy

Source: Consent Decree, Paragraph 9.a
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6. APPLICABILITY OF THE PREVENTION OF SIGNIFICANT 

DETERIORATION REGULATIONS

The PSD program of the Clean Air Act is a preconstruction permitting program and is intended 

to protect air quality in “attainment/unclassified areas”, which are areas that meet the National 

Ambient Air Quality Standards (NAAQS) or where the attainment status is uncertain. As shown 

in Table 6-1, the Navajo Nation Indian Reservation is in attainment or unclassifiable for all 

NAAQS pollutants. EPA is currently the PSD permitting authority for stationary sources located 

on the Navajo Nation Indian Reservation. 

Table 6-1: NAAQS Attainment Status for Navajo Nation

Pollutant Attainment Status

SO2 Attainment or Unclassifiable

CO Attainment or Unclassifiable

Nitrogen Dioxide (NO2) Attainment or Unclassifiable

Ozone8 Attainment or Unclassifiable

Particulate Matter (PM2.5)9 Attainment or Unclassifiable

Particulate Matter (PM10)10 Attainment or Unclassifiable

Lead Attainment or Unclassifiable

Pursuant to the federal Consent Decree, Resolute is required to submit a PSD application to EPA 

for the Main Flare in accordance with the PSD regulations at 40 CFR § 52.21 for the following 

pollutants: SO2, CO, NOx, and VOC. EPA issued a PSD permit to the MCU Facility on 

February 2, 1987, and the permit was last amended on April 19, 1991. EPA received a PSD 

application for the Main Flare in 2005 from Mobil, and has received revised applications in 2007 

and 2008 and other supplemental information for the PSD application from Mobil and Resolute. 

 8 Troposheric, or ground level ozone, is not emitted directly into the air, but is created by chemical reactions 

between NOx and VOC. Thus, both NOx and VOC precursors in the formation of ozone and are regulated under the 

CAA. 

9 Fine particulate matter, or PM2.5, is particulate matter with diameters that are 2.5 micrometers and smaller. Some 

PM2.5 is emitted directly from a stationary source, such as construction sites, unpaved roads, fields, or smokestacks. 

SO2 and NOx are precursors in the formation of PM2.5 since these pollutants form in complicated reactions in the 

atmosphere after being emitted from smokestacks.

10 Coarse particulate matter, or PM10, includes “inhalable coarse particles,” with diameters larger than 2.5 

micrometers and smaller than 10 micrometers.
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7. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS

This section describes EPA’s BACT analysis for the control of SO2, CO, NOx and VOC

emissions at the MCU Facility’s Main Flare. Section 169(3) of the CAA defines BACT as 

follows:

“The term ‘best available control technology’ means an emission limitation based on the 

maximum degree of reduction of each pollutant subject to regulation under the Clean Air Act 

emitted from or which results from any major emitting facility, which the permitting authority, 

on a case-by-case basis, taking into account energy, environmental, and economic impacts and 

other costs, determines is achievable through application of production processes and available 

methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of each such pollutant. In no event shall application of ‘best 

available control technology’ result in emissions of any pollutants which will exceed the 

emissions allowed by any applicable standard established pursuant to section 111 [New Source 

Performance Standards or NSPS] or 112 [or NESHAPS] of the Clean Air Act.”

See also 40 CFR § 52.21(b)(12). In accordance with 40 CFR § 52.21(j), a new major stationary 

source is required to apply BACT for each regulated NSR pollutant that it would have the 

potential to emit (PTE) in significant amounts. 

EPA outlines the process it generally uses to do this case-by-case analysis (referred to as a “topdown” BACT analysis) in a June 13, 1989 memorandum. The top-down BACT analysis is a 

well-established procedure that EPA’s Environmental Appeals Board (EAB) has consistently 

followed in adjudicating PSD permit appeals. See, e.g., In re Knauf, 8 E.A.D. 121, 129-31 (EAB 

1999); In re Maui Electric, 8 E.A.D. 1, 5-6 (EAB 1998). 

In brief, under the top-down process, all available control technologies are ranked in descending 

order of control effectiveness. The PSD applicant first examines the most stringent technology. 

That technology is established as BACT unless it is demonstrated that technical considerations, 

or energy, environmental, or economic impacts justify a conclusion that the most stringent 

technology is not achievable for the case at hand. If the most stringent technology is eliminated, 

then the next most stringent option is evaluated until BACT is determined. The top-down BACT 

analysis is a case-by-case exercise for the particular source under evaluation. In summary, the 

five steps involved in a top-down BACT evaluation are:

1. Identify all available control options with practical potential for application to the 

specific emission unit for the regulated pollutant under evaluation;

2. Eliminate technically infeasible technology options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate the most effective control alternative and document results, considering 

energy, environmental, and economic impacts as appropriate; if top option is not 
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selected as BACT, evaluate next most effective control option; and

5. Select BACT, which will be the most stringent technology not rejected based on 

technical, energy, environmental, and economic considerations. 

A BACT analysis was conducted for the Main Flare. Table 7-1 provides a summary of the 

BACT determinations for SO2, CO, NOx, and VOC emissions. EPA evaluated the information 

that Resolute and Mobil submitted. The analyses and our evaluation for each pollutant are 

presented below.

Table 7-1: Summary of BACT Limits and Requirements for the Main Flare11

SO2 CO NOx VOC

• 60.0 tpy, based on a 

cumulative 365-day 

rolling total

• Monitor sulfur content 

(in terms of H2S) of the 

gas stream to the flare for 

calculating SO2

emissions.

• Follow manufacturer’s 

specifications for Main 

Flare 

• Operate and maintain in 

accordance with the flare 

requirements in 40 CFR 

§ 60.18 

• Follow the operations 

and maintenance, root 

cause, and corrective 

action requirements of 

the Consent Decree

• 73.0 tpy, based on a 

cumulative 365-day 

rolling total

• Follow manufacturer’s 

specifications for Main 

Flare 

• Operate and maintain in 

accordance with the flare 

requirements in 40 CFR § 

60.18 

• Follow the operations and 

maintenance, root cause, 

and corrective action 

requirements of the 

Consent Decree

• 13.4 tpy, based on a 

cumulative 365-day rolling 

total

• Follow manufacturer’s 

specifications for Main Flare 

• Operate and maintain in 

accordance with the flare 

requirements in 40 CFR § 

60.18 

• Follow the operations and 

maintenance, root cause, and 

corrective action 

requirements of the Consent 

Decree

• 95.4 tpy, based on a 

cumulative 365-day rolling 

total

• Operating the Main Flare 

using air-assist technology.

• Ensure that the net heating 

value for dilution is greater 

than or equal to 24.4

BTU/scf2

• Follow manufacturer’s

specifications for Main 

Flare 

• Operate and maintain Main 

Flare in accordance with 

the flare requirements in 40 

CFR § 60.18 

• Follow the operations and 

maintenance, root cause, 

and corrective action 

requirements of the 

Consent Decree

7.1 BACT FOR SULFUR DIOXIDES

SO2 emissions are formed as a result of the combustion of gasses containing reduced sulfur 

compounds. Typically, sulfur dioxide from combustion processes can be controlled by limiting 

the sulfur content in the fuel or by end-of-pipe control technology. 

7.1.1 Step 1 - Identify All Control Technologies for SO2

The available add-on control technologies for reducing SO2 emissions are as follows.

• Absorption (e.g., absorbers or scrubbers for acid gases)

• Dry injection (e.g., hydrated lime or sodium bicarbonate for acid gases)

 11 The owner and operator of the MCU facility must keep all records of all testing, fuel use, and fuel testing 

requirements for a period of five (5) years and must report excess emissions to EPA semi-annually, except when: 

more frequent reporting is specifically required by an applicable subpart; or the Administrator, on a case-by-case 

basis, determines that more frequent reporting is necessary to accurately assess the compliance status of the source. 
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• Spray dryer (e.g., slurry for acid gases)

• Soda ash tower (for acid gases)

• Flue gas desulfurization (e.g., wet scrubbing, spray-dry scrubbing, sulfur recovery, dry 

sorbent injection systems)

The following pre-treatment control options for reducing SO2 emissions are as follows.

• Limiting the fuel type

• Limiting the sulfur content

Other control options for reducing SO2 emissions are as follows.

• Natural gas combustion in flare

• Proper operation and maintenance

7.1.2 Step 2 - Eliminate Technically Infeasible Options for SO2

Add-On Control Technologies 

The add-on control technology options are not technically feasible for flare systems, due to the 

inherent design of flaring and the fact that literally, no end-of-pipe exists after the combustion 

zone. Additionally, we found no known demonstrations of add-on control options such as 

absorbers or other scrubbing techniques for open, elevated flares. Because these controls are 

neither available in the marketplace for flares nor applicable to them, all of the add-on control 

technology options listed above are eliminated as technically infeasible for the Main Flare.

Pre-Treatment Control Options 

Limiting the fuel type is not technically feasible because the gasses cannot be switched with 

other process or vent streams without changing the inherent purpose and design of the 

compressor plant. Likewise, limiting the sulfur content or flue gas desulfurization is not 

technically feasible because they would inherently change the plant’s purpose and design. 

During normal operation, the process and vent gas streams are re-injected into the oilfield 

without any sweetening process. Therefore, the options of limiting the fuel type and sulfur 

content of the gas before it is flared are not technically feasible for the Main Flare.

Other Control Options

EPA’s New Source Performance Standards (NSPS) regulations at 40 CFR part 60 define natural 

gas as the following: “a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, 

or propane) produced in geological formations beneath the Earth’s surface that maintains a 

gaseous state at standard atmospheric temperature and pressure under ordinary conditions. 

Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Equivalents 

of this in other units are as follows: 0.068 weight percent total sulfur, 680 parts per million by 

weight (ppmw) total sulfur, and 338 parts per million by volume (ppmv) at 20 degrees Celsius 

total sulfur. Additionally, natural gas must either be composed of at least 70 percent methane by 

volume or have a gross calorific value between 950 and 1100 British thermal units per standard 

cubic foot (BTU/scf). Natural gas does not include the following gaseous fuels: landfill gas, 

digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a process which might result in highly variable sulfur 
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content or heating value.”

The MCU Facility’s Main Flare is used to burn dehydrated produced gas from the MCU oilfield. 

According to Resolute’s PSD Application, this dehydrated produced gas is approximately 70

percent CO2 and 0.05 percent H2S, and does not include natural gas as defined above. Thus, 

requiring combustion of natural gas in the Main Flare to control SO2 emissions is not technically 

feasible.

Proper operation and maintenance is typically specific to a facility and could entail work 

practices to ensure that the flare is being maintained and operated properly. For the Main Flare, 

proper operation and maintenance include (1) following the manufacturer’s specifications for the 

flare, (2) operating and maintaining the flare in accordance with the flare requirements in 40 

CFR § 60.18, and (3) following the operations and maintenance, root cause, and corrective action 

requirements of the Consent Decree. Proper operation and maintenance is technically feasible 

for the Main Flare.

7.1.3 Step 3 - Rank Control Technologies

Proper operation and maintenance is the remaining technically feasible control option. Table 7-1 

shows a summary of recent SO2 BACT determinations for flares at other facilities. These control 

determinations include combustion of natural gas or refinery gas in the flare, limiting the sulfur 

content in the feedstock, and proper operation and maintenance. As described in Step 2, natural 

and refinery gases are part of the dehydrated produced gas stream that is vented to the flare for 

combustion, and are not technically feasible control options. In addition, as described in Step 2, 

limiting the sulfur content in the feedstock is not technically feasible for the Main Flare.

Sulfur compounds contained in a flare gas stream are converted to SO2 when burned. The 

amount of SO2 emitted depends directly on the quantity of sulfur in the flared gases. The SO2

BACT emission levels in Table 7-1 vary for each facility listed. This indicates that the sulfur 

content also varies for each of these facilities and that the SO2 BACT emission levels are facilityspecific. Thus, the SO2 BACT emission level for the MCU Facility’s Main Flare will be based 

on the expected sulfur content in it flare gas stream.

The SO2 emission rate specified in the Consent Decree is 60 tpy based on a cumulative 365-day 

rolling total. The sulfur content of the dehydrated produced gas that is burned in the MCU’s 

Main Flare is approximately 0.05 percent H2S, but may also result in highly variable sulfur 

content or heating value. 
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Table 7-1: SO2 BACT Determinations for Flares

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Oil and Gas 

Production Facility UT Proposed Main Flare Proper operation and maintenance

60 tpy, 365-day rolling 

total N/A

Valero TX 8/19/2010 Flare None listed 1.38 lb/hr TX-0574

St. Charles Refinery LA 11/17/2009 Flares (2)

Natural gas or 

refinery fuel gas 

combustion in flare

None listed LA-0213

Lake Charles 

Gasification Facility LA 6/22/2009 Flares (2) No additional control 0.01 lb/hr; 1303.99 lb/hr LA-0231

Sun Company, Inc., 

Toledo Refinery OH 2/23/2009 Flare None listed 4.2 lb/hr, 18. 4 tpy OH-0308

Rumpke Sanitary 

Landfill OH 12/23/2008

Candlestick 

flares (5), open 

flare (1)

None listed 0.47 lb/hr, 2.05 tpy; 0.47 

lb/hr, 2.05 tpy OH-0330

Homeland Energy 

Solutions, LLC IA 8/8/2007 Biomethanator flare None listed 0.0007 lb/MMBtu IA-0089

Garyville Refinery LA 12/27/2006 Flare None listed 0.01 lb/hr LA-0211

Air Products 

Hydrogen, Steam, 

and Electricity 

Production

TX 8/18/2006 Flares (2) None listed 1.38 lb/hr, 0.01 tpy; 1.38 

lb/hr, 0.1 tpy TX-0526

BASF TX 2/3/2006 Flare None listed 1.38 lb/hr, 7 tpy TX-0511

Enterprise Mont 

Belvieu Complex TX 1/24/2006 Flare None listed 1.38 lb/hr, 0.6 tpy TX-0514

Formosa Point 

Comfort Plant TX 5/9/2005 Flares (3) None listed

1.38 lb/hr, 0.05 tpy; 1.38 

lb/hr, 0.02 tpy; 1.38 lb/hr, 

0.08 tpy

TX-0475

Virtex Petroleum 

Company Doering 

Ranch Gas Plant

TX 5/5/2005 Flare None listed 1.38 lb/hr, 615.39 tpy TX-0492

Citgo Corpus Christi 

Refinery TX 4/20/2005 Flares (3) None listed

1.38 lb/hr, 0.9 tpy; 1.38 

lb/hr, 0.8 tpy; 1.38 lb/hr, 

116 tpy

TX-0478

Rohm and Haas TX 3/24/2005 Flares (2) None listed 1.38 lb/hr, 0.03 tpy; 1.38 

lb/hr, 0.01 tpy TX-0487

Continental Carbon 

Sunray Plant TX 3/18/2005 Flare None listed 1.38 lb/hr, 1487.05 tpy TX-0464

Flint Hills Resources TX 1/24/2005 Flares (2) None listed 1.38 lb/hr, 965.79 tpy TX-0494

Source: RACT/BACT/LAER Clearinghouse (RBLC)

7.1.4 Step 4 – Economic, Energy and Environmental Impacts for SO2

No significant economic, energy, or environmental impacts are expected from proper operation 

and maintenance of the Main Flare.

7.1.5 Step 5 – Select BACT for SO2

Based on the above analysis, BACT for SO2 emissions from the Main Flare are the following 

requirements.

• SO2 emissions not to exceed an emission limit of 60 tpy based on a cumulative 365-day 

rolling total.

• Proper operation and maintenance which include:

(1) following the manufacturer’s specifications for the flare;
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(2) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18;

(3) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit); and 

(4) monitoring of the sulfur content (in terms of H2S) of the gas stream to the flare for 

calculating SO2 emissions.
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7.2 BACT FOR CARBON MONOXIDE

Flaring is a high-temperature oxidation process used to burn combustible components, mostly 

hydrocarbons (i.e., VOC), of waste gases from industrial operations. In some waste gas streams 

sent to a flare, CO is the major combustible component. However, for the MCU Facility, is not 

part of the gas stream sent to the Main Flare and is formed from by incomplete combustion of the 

dehydrated produced gas from the MCU oilfield in the Main Flare. 

7.2.1 Step 1 - Identify All Control Technologies for CO

The CO control options for the Main Flare are listed as follows.

• Proper operation and maintenance

7.2.2 Step 2 - Eliminate Technically Infeasible Options for CO

Proper operation and maintenance, the only control option for the Main Flare, is technically 

feasible. Proper operation and maintenance include (1) following the manufacturer’s 

specifications for the flare, (2) operating and maintaining the flare in accordance with the flare 

requirements in 40 CFR § 60.18, and (3) following the operations and maintenance, root cause, 

and corrective action requirements of the Consent Decree. 

7.2.3 Step 3 - Rank Control Technologies for CO

Proper operation and maintenance is the only control option for the Main Flare. Table 7-2 shows 

a summary of recent CO BACT determinations for flares at other facilities. 

These control determinations include proper operation and maintenance, comply with the flare 

requirements in 40 CFR §§ 60.18 and 63.11, and good combustion practices. Proper operation 

and maintenance for the Main Flare include maintaining and operating the flare in accordance 

with the flare requirements in 40 CFR § 60.18. The flare requirements of 40 CFR § 60.18 are 

substantively the same as those in 40 CFR § 63.11. Proper operation and maintenance for the 

Main Flare also include good combustion practices which require Resolute to operate the flare in 

accordance with the manufacturer’s specifications for the flare to ensure complete combustion. 

The CO emission rate specified in the Consent Decree is 73 tpy based on a cumulative 365-day 

rolling total. This is based on an emission factor of 0.37 lb/MMBtu. This level is within the 

range of BACT determinations listed in Table 7-2.
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Table 7-2: CO BACT Determinations for Flares

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Oil and Gas 

Production Facility UT Proposed Main Flare Proper operation and maintenance

73 tpy, 365-day 

rolling total N/A

Sabine Pass LNG 

Terminal LA 12/6/2011

Marine Flare 

(1) and 

Wet/Dry Gas 

Flares (4)

Proper operation and 

maintenance None listed LA-0257

Direct Reduction Iron 

Plant LA 1/27/2011 Flares (2) Proper operation and maintenance None listed LA-0248

Valero Three Rivers 

Refinery TX 8/19/2010 Flare Proper operation and maintenance None listed TX-0574

Breitburn Energy –

Newlove Lease CA 7/17/2009

Horizontal 

Enclosed 

Flare (forced 

draft)

None listed

0.0371 lb/MMBtu, 

40 min avg CA-1171

Lake Charles Gasification 

Facility LA 6/22/2009 Flares (2) Proper operation and maintenance None listed LA-0231

Rhode Island Central 

Genco LLC RI 5/12/2009 ULE flare, enclosed flare None listed

0.06 lb/MMBtu, 

1.25 lb/hr; 

0.2 lb/MMBtu, 

19.8 lb/hr

RI-0023

St. Charles Refinery LA 11/17/2009 Flares Comply with 40 CFR 

60.18/63.11 None listed LA-0213

Sun Company, Inc., 

Toledo Refinery OH 2/23/2009 Flare (steam assisted)

Comply with 40 CFR 

60.18/63.11 

0.082 lb/MMBtu OH-0308

Power County Advanced 

Energy Center ID 2/10/2009 Flares (3)

Good combustion 

practices; comply with 40 

CFR 60.18

None listed ID-0017

Rumpke Sanitary Landfill OH 12/23/2008

Candlestick 

flare (5), open 

flare

None listed

0.37 lb/MMBtu

OH-0330

Homeland Energy

Solutions, LLC PN 06-

672

IA 8/8/2007 Biomethanator 

Flare None listed

0.37 lb/MMBtu

IA-0089

University of New 

Hampshire NH 7/25/2007 Utility Flare Good combustion practices 0.37 lb/MMBtu, 3-hr avg NH-0014

Garyville Refinery LA 12/27/2006 Flare Comply with 40 CFR 

60.18/63.11 None listed LA-0211

Air Products Hydrogen, 

Steam, and Electricity 

Production

TX 8/18/2006 Flares (2) Proper operation and 

maintenance None listed TX-0526

Bethel Landfill VA 7/25/2006 Flares Proper operation and 

maintenance None listed VA-0301

Fountain Avenue Landfill NY 6/29/2006 Flare Good combustion practices None listed NY-0096

BASF 

Ethylene/Propylene 

Cracker

TX 2/3/2006

Ground flare 

(high 

pressure)

None listed None listed TX-0511

Enterprise Mont Belvieu 

Complex TX 1/24/2006 Flares (2) None listed None listed TX-0514

Formosa Point Comfort 

Plant TX 5/9/2005 Flares (3) None listed None listed TX-0475

Citgo Corpus Christi 

Refinery – West Plant TX 4/20/2005 Flares (3) Proper operation and maintenance None listed TX-0478

Rohm and Haas 

Chemicals LLC Lone Star 

Plant

TX 3/24/2005 Flares (2) Flare used to control CO 

emissions None listed TX-0487

Continental Carbon 

Sunray Plant TX 3/18/2005 Flare Proper operation and maintenance None listed TX-0464

Flint Hills Resources 

Installation of Boilers TX 1/24/2005 Flares (2) None listed None listed TX-0494

Source: RBLC
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7.2.4 Step 4 – Economic, Energy and Environmental Impacts for CO

No significant economic, energy, or environmental impacts are expected from proper operation 

and maintenance of the Main Flare.

7.2.5 Step 5 – Select BACT for CO

Based on the above analysis, BACT for CO emissions from the Main Flare are the following 

requirements.

• CO emissions not to exceed an emission limit of 73 tpy based on a cumulative 365-day 

rolling total.

• Proper operation and maintenance which include: 

(1) following the manufacturer’s specifications for the flare to ensure complete 

combustion in the flare;

(2) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; and

(3) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit). 
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7.3 BACT FOR NITROGEN OXIDES

NOx is formed as a result of the combustion of hydrocarbons (which are entrained in the vent gas 

streams) at the flare (through ignition with natural gas at the flare pilot) in the presence of 

ambient air. There are three principal forms of NOx, designated as “thermal” NOx, “prompt 

NOx,” and “fuel” NOx. Thermal NOx formation is the result of oxidation of atmospheric 

nitrogen contained in the inlet gas in the high-temperature, post-flame region of the combustion 

zone. The major factors influencing thermal NOx formation are temperature, concentrations of 

nitrogen and oxygen in the inlet air, and residence time within the combustion zone. Prompt 

NOx is formed through relatively fast reaction between nitrogen, oxygen, and hydrocarbon 

radicals and is an important mechanism in lower temperature combustion processes. Fuel NOx is 

formed by the oxidation of fuel-bound nitrogen. It is not a concern for high-quality gaseous 

fuels such as natural gas or propane, because these fuels normally have no organically-bound 

nitrogen. Fuel NOx is a concern when burning oil, coal, or waste fuels. NOx emissions from the 

flare can be best reduced by minimizing the frequency and amount of vent gases flared and by 

promoting optimal conditions upon combustion. 

7.3.1 Step 1 - Identify All Control Technologies for NOX

Generally, several options exist to reduce NOx emissions from combustion processes, such as

pre-treating the fuel or switching fuels and/or oxidizers to prevent NOx formation, modifying the 

combustion process or equipment to lower NOx formation, and add-on control technologies to 

remove NOx. These options are listed below.

The available add-on control technologies are listed as follows.

• Selective Catalytic Reduction (SCR)

• Selective Non-Catalytic Reduction (SNCR)

The following inherently lower-emitting control options are listed as follows.

• Air Preheat Reduction

• Burners Out of Service

• Low NOx burners (LNB)

The following pre-treatment control options for NOx emissions are listed as follows.

• Fuel Switching

• Fuel Additives

• Oxidizer Switching

Other control options for NOx emissions are listed as follows. 

• Proper operation and maintenance
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7.3.2 Step 2 - Eliminate Technically Infeasible Options for NOX

Add-On Control Technologies

The add-on control technology options are not technically feasible for flare systems, due to the 

inherent design of flaring and the fact that literally, no end-of-pipe exists after the combustion 

zone. Additionally, we found no known demonstrations of add-on control options such as 

absorbers or other scrubbing techniques for open, elevated flares. Because these controls are 

neither available in the marketplace for flares nor applicable to them, all of the add-on control 

technology options listed above are eliminated as technically infeasible for the Main Flare.

Inherently Lower-Emitting Control Options

Reducing the amount of air preheat and taking burners out of service are options intended for 

process heaters and boilers, where the combustion air is heated for more efficiency and where 

multiple burners exist. LNB incorporate concepts such as lowering excess air, fuel staging, and 

gas recirculation, which can be successfully implemented with process heaters and boilers. 

However, flare burner design differs substantially from process heater and boiler burner design, 

because the primary objective of flare burner design is to achieve safe and complete combustion 

of unwanted hydrocarbons during unpredictable circumstances such as upsets, malfunctions, and 

emergencies. Therefore, air preheat reduction, taking burners out of service, and LNB are not 

technically feasible for the Main Flare.

Pre-Treatment Control Options

Fuel additives, which are intended to change the chemistry of the combustion process, operate 

under specific temperature conditions and stable operations, neither of which is possible with 

flare systems. Oxidizer switching, where pure oxygen is used for combustion rather than air, is 

not widely used in the hydrocarbon, petrochemical, and power generation industries due to the 

cost and energy requirements of producing pure oxygen. Fuel switching from fuels with higher 

fuel-bound nitrogen contents to those with lower fuel-bound nitrogen contents is a possible 

option for reducing NOx from flare systems, but only in specific cases where the fuel to the flare 

can be controlled and predicted.

Fuel switching, fuel additives, and oxidizer switching are not technically infeasible for the Main 

Flare as the fuel stream to the flare cannot be switched without inherently changing the 

compressor plant’s purpose and design. Primarily, fuel is sent to the Main Flare through various 

pressure-relief piping or compressor bypass piping, as a result of emergency or maintenance 

situations, and also continuously from the dehydration reboiler. Secondly, the fuel to the Main 

Flare consists of light hydrocarbons (methane, ethane, propane) and carbon dioxide, with very 

little (fuel-bound) nitrogen content. Therefore, these NOx control options are eliminated for 

technical infeasibility. 
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Other NOx Control Options 

Proper operation and maintenance is typically specific to a facility and could entail work 

practices to ensure that the flare is being maintained and operated properly. For the Main Flare, 

proper operation and maintenance include (1) following the manufacturer’s specifications for the 

flare, (2) operating and maintaining the flare in accordance with the flare requirements in 40 

CFR § 60.18, and (3) following the operations and maintenance, root cause, and corrective action 

requirements of the Consent Decree. Proper operation and maintenance is technically feasible 

for the Main Flare.

7.3.3 Step 3 - Rank Control Technologies for NOX

Proper operation and maintenance is the only control option for the Main Flare. Table 7-3 shows 

a summary of recent NOx BACT determinations for flares at other facilities. 

These control determinations include proper operation and maintenance, comply with the flare 

requirements in 40 CFR § 60.18, and good combustion practices. Proper operation and 

maintenance for the Main Flare include operating and maintaining the flare in accordance with 

the flare requirements in 40 CFR § 60.18. Proper operation and maintenance for the Main Flare 

include good combustion practices. 

The NOx emission rate specified in the Consent Decree is 13.4 tpy based on a cumulative 365-

day rolling total. This is based on an emission factor of 0.068 lb/MMBtu. This level is within 

the range of BACT determinations listed in Table 7-3.
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Table 7-3: NOx BACT Determinations for Flares

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Facility UT Proposed Main Flare Proper operation and 

maintenance

13.4 tpy, 365-day rolling 

total N/A

Petrorock - Tunnell 

Lease CA 1/24/2012 Enclosed Ground Flare

Good combustion 

practices

15 ppmvd@ 3% O2, 40 

min avg CA-1187

Sabine Pass LNG 

Terminal LA 12/6/2011

Marine Flare, 

Wet/Dry Gas 

Flares (4)

Proper operation and 

maintenance

185.1 lb/hr, 2.13 tpy; 

0.03 lb/hr, 0.11 tpy LA-0257

Direct Reduction Iron 

Plant LA 1/27/2011 Flare Proper operation and maintenance

1.27 lb/hr, 2.58 tpy 

(each) LA-0248

Sabina Petrochemicals 

LLC TX 8/20/2010 Flares (2, HP and LP)

Proper operation and 

maintenance 9.07 tpy TX-0575

Evonik Degussa 

Corporation AL 1/7/2010 Flares (4) Good combustion practices

14.29 lb/hr; 14.29 lb/hr; 

1.79 lb/hr; 20.01 lb/hr AL-0249

St. Charles Refinery LA 11/17/2009 Flares (2) None listed None provided LA-0213

Breitburn Energy –

Newlove Lease CA 7/17/2009

Horizontal 

Enclosed Flare 

(forced draft)

None listed 0.0146 lb/MMBtu, 40 min 

avg

CA-1171

Lake Charles Gasification 

Facility LA 6/22/2009 Flare None listed 0.05 lb/hr; 48.81 lb/hr LA-0231

Rhode Island Central 

Genco LLC RI 5/12/2009 ULE flare, enclosed flares None listed

0.025 lb/MMBtu, 0.52 

lb/hr; 0.06 lb/MMBtu, 

5.94 lb/hr

RI-0023

Sun Company, Inc., 

Toledo Refinery OH 2/23/2009 Flare None listed

15.23 lb/hr, 66.71 tpy 

based on 365-day sum 

of daily emissions

OH-0308

Power County Advanced 

Energy Center ID 2/10/2009 Flares (3) Good combustion practices None listed ID-0017

Rumpke Sanitary Landfill OH 12/23/2008

Candlestick 

flares (5), Open 

LFG flare

None listed 1.2 lb/hr, 5.26 tpy (each) OH-0330

Homeland Energy 

Solutions, LLC IA 8/8/2007 Biomethanator flare None listed 0.07 lb/MMBtu IA-0089

University of New 

Hampshire NH 7/25/2007 Utility flare Good combustion practices

0.068 lb/MMBtu, 3-hour 

avg

NH-0014

Garyville Refinery LA 12/27/2006 Flare None listed 1.8 lb/hr LA-0211

Air Products Hydrogen, 

Steam, and Electricity 

Production

TX 8/18/2006 Flares (2) Proper operation and 

maintenance

0.022 lb/hr, 0.1 tpy; 160 

lb/hr, 2.9 tpy TX-0526

Bethel Landfill VA 7/25/2006 Flares Proper operation and 

maintenance 13.4 lb/hr, 58.6 tpy VA-0301

Fountain Avenue Landfill NY 6/29/2006 LFG flare None listed 39 tpy NY-0096

BASF 

Ethylene/Propylene 

Cracker

TX 2/3/2006 Ground flare None listed 2219.7 lb/hr, 452.7 tpy TX-0511

Enterprise Mont Belvieu 

Complex TX 1/24/2006 Flares (2) None listed 376.6 lb/hr, 153 tpy; 154.1 lb/hr, 1.1 tpy TX-0514

Formosa Point Comfort 

Plant TX 5/9/2005 Flares (3) None listed

1.14 lb/hr, 2.38 tpy; 1.92 

lb/hr, 8.39 tpy; 1.45 lb/hr, 

6.34 tpy

TX-0475

Virtex Petroleum 

Company Doering Ranch 

Gas Plant

TX 5/5/2005 Flare None listed 0.19 lb/hr, 0.85 tpy TX-0492

Citgo Corpus Christi 

Refinery – West Plant TX 4/20/2005 Flares (2) None listed 0.6 lb/hr, 2.6 tpy; 0.36 lb/hr, 1.6 tpy TX-0478

Rohm and Haas 

Chemicals LLC Lone Star 

Plant

TX 3/24/2005 Flares (2) None listed 152.13 lb/hr, 48.41 tpy; 

130.65 lb/hr, 7.78 tpy TX-0487

Continental Carbon 

Sunray Plant TX 3/18/2005 Flare None listed 25.96 lb/hr, 113.72 tpy TX-0464

Flint Hills Resources TX 1/24/2005 Flares (2) None listed 1150.9 lb/hr, 3123.7 tpy 

(each) TX-0494

Source: RBLC
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7.3.4 Step 4 – Economic, Energy and Environmental Impacts for NOX

No significant economic, energy, or environmental impacts are expected from proper operation 

and maintenance of the Main Flare.

7.3.5 Step 5 – Select BACT for NOX

Based on the above analysis, BACT for NOx emissions from the Main Flare are the following 

requirements.

• NOx emissions not to exceed an emission limit of 13.4 tpy based on a cumulative 365-day 

rolling total.

• Proper operation and maintenance which include: 

(1) following the manufacturer’s specifications for the flare;

(2) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; and

(3) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit). 
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7.4 BACT FOR VOLATILE ORGANIC COMPOUNDS 

The purpose of a flare system is to control process equipment operation through the safe and 

effective disposal of gases and liquids. Flare systems are considered as an emission control 

device for VOC, since combustion through a flaring system prevents the release of hydrocarbons 

to the atmosphere. When combustion is incomplete, flares will emit VOC in the form of 

unburned hydrocarbons. 

7.4.1 Step 1 - Identify All Control Technologies for VOC

The VOC control options for the Main Flare are listed as follows.

• Compressor engine modifications

• Flare Gas Recovery System

• Proper operation and maintenance which include supplemental external momentum 

design (i.e., steam, air, or gas-assist technology)

7.4.2 Step 2 - Eliminate Technically Infeasible Options for VOC

Compressor engine modifications

The Applicant evaluated minimizing flaring events due to compressor downtime, and considered 

various options to improve the reliability of the HOS-6 compression engine operations, and 

considered other compressor changes. 

Flaring Due to Compressor Downtime: The majority of the flaring at the MCU Facility is a 

result of downtime associated with the HOS-6 compressor. This unit is a 4-stage, 6-cylinder 

Dresser HOS model compressor, which is driven by an electric motor. HOS-6 compressor 

reliability is influenced by the interaction of the gas composition and process requirements at 

MCU. The gas is primarily composed of carbon dioxide and has a tendency to liquefy at relative 

low temperatures. The gas pressure between the 3rd and 4th stages of compression is 

approximately 1000 psi. The gas at this pressure liquefies at approximately 85°F. Additionally, 

the discharge pressure is above the critical pressure of the gas. Therefore, the process stream 

actually leaves the compressor and can simultaneously have the properties of a liquid and a gas. 

It is when the gas behaves as a liquid that compressor damage can occur. This mixed gas stream 

allows for the potential of liquid drop-out throughout the compression process.

In an effort to reduce the potential for damage on the 4th stage of the compressor, the field 

operations group attempts to maintain the suction temperature of the 4th stage near 100° F. 

However, the large temperature swings that can occur in the MCU Gas Compression Plant area, 

especially in the winter months, make this difficult. Some of the issues are:

• No automatic controls on the coolers

• Gas separation between stages located remotely from the compressor

• Piping between the separation equipment and the compressor having multiple elevation 

changes, which increase the potential for liquid accumulation in the lines.
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The compressor has had downtime associated with 2nd stage failures due to liquids entering the 

cylinder. The implemented solution was to remove the liquid traps between the separation and 

compression equipment. This eliminated liquid collection and slugging, thereby reducing 

downtime events significantly.

Reliability of HOS-6 Compressor Engine Operations: The Applicant evaluated two options to 

increase reliability of compressor engine operation: (1) changing the compressor process and (2) 

replacing the HOS-6 compressor. The option to change the compressor process would consist of 

reducing the discharge pressure of the reciprocating compression, cooling the gas stream to 

liquefy it, and utilizing pumps to reach the required pipeline pressure. This could provide 

increased reliability and minimize potential compression failures at the MCU Gas Compression 

Plant. This option would require new refrigeration equipment, new pumps, and, at a minimum, 

restaging of the existing compression. Further corrective actions would also be necessary, as 

described below, if the existing HOS-6 compressor was used.

The option to replacing the HOS-6 compressor would entail replacing the HOS-6 unit with one 

or more reciprocating compressors. The basic process would not change. Replacing the existing 

compressor may reduce the potential for liquid retention by utilizing different piping 

configurations. However, problems inherent with the process would still remain.

Other Compression Changes: The Applicant considered three options for potential changes to 

compression operations. These options are (1) relocating the HOS-6 separation equipment, (2) 

reconfiguring piping, and (3) insulate and heat trace the piping. The option to relocate the HOS6 equipment would consist of moving the HOS-6 separation equipment closer to the compression 

equipment. By doing this, the potential for liquid forming in the intermediate piping and 

entering the compressor would be reduced. However, the potential for liquid entering the 

compressor equipment would still remain because of the size of the separation equipment 

required on the HOS-6 compressor. Additionally, relocation of the separation equipment would 

not remove the inherent process issues and there would be no assurance of flaring frequency and 

duration reductions.

Reconfiguring the piping between the separation and compression equipment, similar to 

replacing the compressor or relocating the separation equipment, would reduce the potential for 

liquids to enter the compression equipment by removing liquid traps. The potential for 

downtime occurrences would still remain, however, and there would be no assurance of flaring 

frequency and duration reductions.

By insulating and heat-tracing the piping between the separation and compression equipment, the 

probability of the gas cooling and liquids forming would be reduced. The potential for liquids

entering the compression equipment would still remain and there would be no assurance of 

flaring frequency and duration reductions.
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Flare Gas Recovery System

Another method of reducing flaring emissions is to recover gas that would otherwise be flared 

and redirect for further processing in the existing gas compression facility. Flare gas recovery 

systems recover fuel gas from the flare gas header prior to the flare’s liquid seal. A flare gas 

recovery system consists of a compressor, separator, and process controls (to maintain slight 

positive pressure on the flare header). Flare gas recovery systems are typically designed to 

recover fuel gas from miscellaneous processes that might regularly be relieved to the flare header 

system and can effectively recover 100 percent of these fuel gases. However, flare gas recovery 

systems cannot recover large quantities of fuel gas that might be suddenly released to the flare 

header system as a result of a process upset or malfunction.12 These gases would still be flared 

as necessary to maintain the integrity of the process units and the safety of the plant personnel. 

Flare gas recovery systems have been used at refineries and has been required in EPA’s final 

standards for petroleum refineries.13 These systems have been considered at facilities, such as 

petroleum refineries, that have flares receiving high gas flows. 

Proper Operation and Maintenance (Use of Steam, Air, or Gas-Assist Technology)

The flare requirements in 40 CFR § 60.18 establish specifications on visible emissions, 

continuous presence of a flame, exit velocities, fuel heating value, and monitoring for flare 

systems with the intent to ensure 98 percent control (hydrocarbon destruction) efficiency for 

applicable flares. In order to achieve the visible emission requirements of 40 CFR § 60.18, 

smokeless flare systems are designed with some type of external momentum force, such as 

steam, air, water spray, natural gas, or a specialized high velocity vortex design. An external 

momentum force provides for more complete combustion by improving the fuel flow 

momentum, which allows a sufficient amount of combustion air to be educted into the 

combustion zone just outside the flare burner. 

Steam, air, or gas-assist technology allows flare systems to achieve smokeless operation and 98 

percent control efficiency. Steam injection is common, as it can add sufficient momentum and 

aid the chemistry of the combustion process. Low-pressure air can be used as an assist medium 

in locations where steam, water, or gas is not readily available or where cold temperatures 

present freezing issues. In this case, a blower is utilized to inject approximately 15 to 50 percent 

of the stoichiometric air requirement into the flame, providing adequate momentum to achieve 

smokeless and complete combustion. Air-assist design is often used in remote locations. Gasassist with natural gas can provide an additional benefit by increasing the heating value to the 

fuel stream, in situations where the waste gas to be combusted does not have a sufficient heating 

value for safe combustion. 

Of the steam, air, and gas-assist technology options, steam-assisted technology is immediately 

determined to be infeasible. The MCU Facility is located in a remote area, where steam is not 

readily available. Therefore, the only feasible supplemental external momentum designs are air 

and gas-assist technologies. The MCU’s Main Flare employs air-assist technology.

 12 See 72 Federal Register 27187, Standards of Performance for Petroleum Refineries. 13 See 73 FR 35837 (June 24, 2008) and 77 FR 56422 (September 12, 2012).
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Proper operation and maintenance is typically specific to a facility and could entail work 

practices to ensure that the flare is being maintained and operated properly. For the Main Flare, 

proper operation and maintenance include (1) the use of using air-assist technology, (2) 

following the manufacturer’s specifications for the flare and taking other measures to ensure 

complete combustion and proper flare performance, (3) maintaining and operating the flare in 

accordance with the flare requirements in 40 CFR § 60.18, and (4) following the operations and 

maintenance, root cause, and corrective action requirements of the Consent Decree. Proper 

operation and maintenance is technically feasible for the Main Flare.

7.4.3 Step 3 - Rank Control Technologies

The technically feasible control options are listed in order of control effectiveness for VOC (with 

the most effective alternative at the top) as follows in Table 7-4.

Table 7-4: Control Effectiveness for VOC Control Options

Control Option Control Effectiveness

• Compressor engine modifications • 75-95% VOC control at facility

• 98% VOC control by Main Flare

• Flare gas recovery system • 75% VOC control at facility

• 98% VOC control by Main Flare

• Proper operation and maintenance with 

air-assist technology • 98% VOC control by Main Flare

Table 7.5 shows a summary of recent VOC BACT determinations for flares at other facilities. 

These control determinations include proper operation and maintenance, comply with the flare 

requirements in 40 CFR §§ 60.18 and 63.11, good combustion practices, and 98% VOC control. 

The VOC emission rate specified in the Consent Decree is 95.4 tpy based on a cumulative 365-

day rolling total. 

Proper operation and maintenance for the Main Flare include operating and maintaining the flare 

in accordance with the flare requirements in 40 CFR § 60.18, which are substantively the same 

as the flare requirements in 40 CFR § 63.11. These federal requirements for flares include the 

following minimum requirements:

• Designed and operated with no visible emissions using EPA Method 22 (except for 

periods not to exceed 5 minutes in 2 hours);

• Operated with a flame present at all times, confirmed by the use of a thermocouple or 

equivalent device;

• Used only when the net heating value of the gas to be combusted is 300 BTU per 

standard cubic foot (BTU/scf) or greater (if the flare is steam- or air-assisted), or 200 

BTU/scf or greater (if the flare is nonassisted); and

• Designed for and operated with an exit velocity less than 60 feet per second (ft/sec). An

exit velocity of greater than 60 ft/sec but less than 400 ft/sec may be used if the net 

heating value of the gas being combusted is sufficiently high.
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Proper operation and maintenance include other measures that ensure complete combustion and 

proper flare performance. EPA supported a study to better understand flare performance and to 

identify key operating/monitoring parameters that would ensure adequate performance of flares 

at all times. Based on this study EPA established that, while there are many parameters that 

affect combustion efficiency of a flare, proper mixing at the flare tip and the heating value of 

vent gas to be combusted are two important factors for achieving high combustion efficiency. 14 

Proper mixing at the flare tip, which is where combustion occurs, is needed to prevent 

overaeration in air-assisted flares. EPA has found that facilities can use either or both of the 

following techniques to ensure proper mixing for air-assisted flares:

15

• Continuously measure the flow rate of the waste gas and continuously measure, and 

then control, the air being added as assist gas. Follow the manufacturer’s 

recommendations and publicly available documents in setting proper assist gas rates.

• Utilize automatic damper actuators or variable frequency drives on the air supply 

system.

Ensuring that the heating value, often measured in BTU/scf, of the vent gas is sufficient is 

important in maintaining flame stability and achieving high combustion efficiency. The heating 

value is a measure of the combustibility of the gas. The flare requirements in 40 CFR part 60 

and 40 CFR part 63 regulate the net heating value and require gases contain at least 300 BTU/scf 

if they are being combusted in an air or steam assisted flare. If this heating value minimum 

cannot be met by the vent gases alone, then supplemental gas, such as natural gas, must be 

added. EPA has found that facilities can use one or a combination of the following techniques to 

ensure high combustion efficiency and prevent low heat value in the vent gas stream:

16

• Ensure that the flare waste gas meets the current regulatory heating value limits of 300 

BTU/scf for assisted flares, and 200 BTU/scf for unassisted flares, at all times. This 

will require evaluating the heating value of vent gas over the full range of operating 

scenarios.

• Determine the heating value of the flare vent gas as a whole, not only the hydrocarbons 

in the vent gas, just before it leaves the flare tip (flare vent gas to includes all flare 

waste gas, sweep gas, purge gas and supplemental gas, but not include pilot gas or 

assist media). The heating value evaluation includes nitrogen and any other 

compounds that make up the gas mixture that is present just inside the flare tip. 

• Monitor the vent gas flow and automatically supply supplemental fuel if the vent gas

does not have sufficient heating value.

• Evaluate other control options and limit flare use to true emergency situations.

EPA has incorporated requirements for ensuring proper mixing at the flare tip and sufficient 

heating value of the vent gas to be combusted in the flares in recent consent decrees for refinery 

 14 See Enforcement Alert: EPA Enforcement Targets Flaring Efficiency Violations, EPA 325-F-012-002, August 

2012

15 Ibid. 16 Ibid.
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flares.

17 EPA has also included such requirements for flares in the proposed revisions to the 

federal air quality refinery standards.18 EPA’s studies that provide the basis for the flare 

requirements in these proposed revisions estimate that the vent gas in an air-assisted flare should 

have a combustion zone heating value that is greater than or equal to 270 BTU/scf and a net 

heating value air assist dilution parameter that is greater than or equal to 22 BTU/ft2.

19 Since the 

Main Flare does not employ premix air or steam, the combustion zone heating value would equal 

the heating value of the vent gas. The Main Flare must comply with the heating value of the vent 

gas of 300 BTU/scf required by 40 CFR§ 60.18(c)(3)(ii). Thus, for this unit, the net heating 

value air assist dilution parameter would need to be greater than or equal to 24.4 BTU/ft2 (i.e., 22 

BTU/ ft2 x [(300 BTU/scf)/(270 BTU/scf)]).

A properly operated flare can achieve a destruction efficiency of 98% or greater when 

controlling emission streams with heat contents greater than 300 BTU/scf.20 Resolute’s Main 

Flare will achieve this 98% destruction efficiency through compliance with the heat content 

requirements of 40 CFR § 60.18 and the combustion efficiency provisions discussed above. 

 17 See Consent Decrees for Marathon Petroleum Company, LP and Catlettsburg Refining, LLC Settlement dated 

April 5, 2012; and Consent Decree for BP Products North America, Inc., case 2:12-cv-00207, filed 09/18/12 18 See Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards at 79 

Federal Register 36880.

19 Memorandum regarding Petroleum Refinery Sector Rule: Operating Limits for Flares, Jeff Coburn, RTI 

International to Andrew Bouchard and Brenda Shine, EPA/OAQPS, December 12, 2013 

20 EPA Air Pollution Control Fact Sheet for Industrial Flares (EPA 452/F-03-019)
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Table 7-5: VOC BACT Determinations for Flares

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Facility UT Proposed Main Flare Proper operation and 

maintenance

95.4 tpy, 365-day 

rolling total N/A

Petrorock - Tunnell Lease CA 1/24/2012 Enclosed Ground 

Flare Good combustion practices None listed *CA-1187

Sabine Pass LNG Terminal LA 12/6/2011

Marine Flare, 

Wet/Dry Gas 

Flares (4)

Proper maintenance and 

operation None listed LA-0257

Sabina Petrochemicals LLC TX 8/20/2010 Flare 98% VOC control with flare 98% control TX-0575

Highlands Ethanol Facility FL 12/10/2009 Flares (2) Proper maintenance and 

operation None listed FL-0318

St. Charles Refinery LA 11/17/2009 Flares (2) Comply with 40 CFR 60.18 

and 63.11 None listed LA-0213

Breitburn Energy – Newlove 

Lease CA 7/17/2009 Horizontal enclosed flare Forced draft enclosed flare 10 ppmvd @3% O2, 40 min avg CA-1171

Rhode Island Central Genco, 

LLC RI 5/12/2009 ULE flare, enclosed flares None listed None listed RI-0023

Sun Company, Inc., Toledo 

Refinery OH 2/23/2009 Flare (steamassisted)

Comply with 40 CFR 60.18 

and 63.11 5 lb/MMscf OH-0308

Rumpke Sanitary Landfill OH 12/23/2008 Candlestick flares 

(5), open flare None listed None listed OH-0330

Homeland Energy Solutions, 

LLC IA 8/8/2007 Biomethanator flare 98% VOC control with flare 0.052 lb/MMBtu, 98% control IA-0089

Garyville Refinery LA 12/27/2006 Flare Comply with 40 CFR 60.18 None listed LA-0211

Valero Three Rivers Refinery TX 8/19/2006 Flares (HP and LP) Proper maintenance and 

operation None listed TX-0574

Air Products Hydrogen, 

Steam, and Electricity 

Production

TX 8/18/2006 Flares (2)

98% VOC control with flare; 

proper maintenance and 

operation

98% control TX-0526

Fountain Avenue Landfill NY 6/29/2006 LFG flare 98% VOC control 98% control NY-0096

BASF Ethylene/Propylene 

Cracker TX 2/3/2006 Ground flare Flare used to control VOC None listed TX-0511

Enterprise Mont Belvieu 

Complex TX 1/24/2006 Flares (2) None listed None listed TX-0514

Formosa Point Comfort Plant TX 5/9/2005 Flares (5) None listed None listed TX-0475

Citgo Corpus Christi Refinery 

– West Plant TX 4/20/2005 Flares (3)

98% VOC control with flare; 

proper maintenance and 

operation

98% control TX-0478

Rohm and Haas Chemicals 

LLC Lone Star Plant TX 3/24/2005 Flares (6) 98% VOC control with flare 98% control TX-0487

Continental Carbon Sunray 

Plant TX 3/18/2005 Flares (3) 98% VOC control with flare 98% control TX-0464

Source: RBLC

7.4.4 Step 4 –Economic, Energy and Environmental Impacts for VOC

Resolute provided a cost analysis for the top two VOC control options, compressor engine 

modifications and flare gas recovery systems. The third control option (i.e., Proper operation 

and maintenance with steam, air, or gas-assist technology) does not additional controls beyond 

the Main Flare and an economic analysis is not needed since this is the baseline case. A 

summary of the cost analysis is provided in Table 7-6. This analysis is based on the EPA 

Control Cost Manual and the VOC requirements of the Consent Decree. With cost effectiveness 

values ranging between $58,395 and $69,646 per ton VOC removed, the top control options are 

considered cost-prohibitive for the Main Flare. Therefore, we are eliminating compressor 

modifications and flare recovery systems.

No significant energy or environmental impacts are expected from proper operation and 

maintenance of the Main Flare.
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Table 7-6: VOC Economic Analysis 

Cost Parameters

Compressor 

Modifications -

Change HOS-6 

Compressor Process

Compressor 

Modifications -

Replace HOS-6 

Compressor

Flare Recovery 

Systems

Cost Recovery Factor 0.1061 0.1061 0.1061

Total Capital Costs $29,253,312 $24,377,760 $27,546,869

Total Annualized Costs $5,290,607/year $4,422,271/year $4,986,689

Control Range 75%-95% 75%-95% 75%

Control Level Used in 

Cost Analysis 95% 95% 75%

Tons of VOC Removed 90.6 tpy

(0.95 x 95.4 tpy)

90.6 tpy

(0.95 x 95.4 tpy)

71.6 tpy

(0.75 x 95.4 tpy)

Cost Effectiveness $58,395/ton VOC 

removed

$48,811/ton VOC 

removed

69,646/ton VOC 

removed

7.4.5 Step 5 – Select BACT for VOC

Based on the above analysis, BACT for VOC emissions from the Main Flare are the following 

requirements.

• VOC emissions not to exceed an emission limit of 95.4 tpy based on a cumulative 365-

day rolling total. 

• Proper operation and maintenance which include: 

(1) operating the Main Flare using air-assist technology;

(2) complying with a net heating value air assist dilution parameter of greater than or 

equal to 24.4 BTU/ft2 to ensure complete combustion in the flare; 

(3) following the manufacturer’s specifications for the flare to ensure complete 

combustion in the flare;

(4) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; and

(5) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit). 
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8. AIR QUALITY IMPACTS ANALYSIS

The Consent Decree requires the owner or operator of the MCU Facility, Resolute, to submit a 

PSD application that includes an air quality analysis for SO2, CO, NOx, and VOC in accordance 

with 40 CFR § 52.21. Under Clean Air Act section 165 and EPA’s PSD regulations at 40 CFR §

52.21, Resolute must demonstrate, using air quality models, that the Facility’s emissions of SO2, 

CO, NOx, and VOC will not cause or contribute to a violation of (1) the applicable NAAQS, or 

(2) the applicable PSD increments (explained below in Sections 8.4 and 8.5 of this document). 

The following sections provide a discussion of the relevant background data and air quality 

modeling, and EPA’s conclusion that the Facility’s emission increases will not cause or 

contribute to an exceedance of the applicable NAAQS or applicable PSD increments, and is 

otherwise consistent with PSD requirements governing air quality.

8.1 INTRODUCTION

8.1.1 Overview of PSD Air Impact Requirements

Under the PSD regulations, permit applications for sources subject to review under the PSD 

regulations at 40 CFR § 52.21 must include an air quality analysis demonstrating that the 

facility’s emissions of the PSD-regulated air pollutants will not cause or contribute to a violation 

of the applicable NAAQS or applicable PSD increments. (A PSD increment for a pollutant 

applies only to areas that that are in attainment with the corresponding NAAQS for that 

pollutant.) The Applicant provides separate modeling analyses for each criteria pollutant emitted 

above the applicable significant emission rate. If a preliminary analysis shows that the ambient 

concentration impact of the Main Flare by itself is greater than the Significant Impact Level 

(SIL), then a full or cumulative impact analysis is required for that pollutant. The cumulative 

impact analysis includes nearby pollution sources in the modeling, and adds a monitored 

background concentration to account for sources not explicitly included in the model. The

cumulative impact analysis must demonstrate that the Main Flare will not cause or contribute to 

a NAAQS or increment violation. If a preliminary analysis shows that the ambient concentration 

impact of the Main Flare by itself is less than the Significant Impact Level (SIL), then further 

analysis is generally not required. Required model inputs characterize the various emitting units, 

meteorology, and the land surface, and define a set of receptors (i.e., spatial locations at which to 

estimate concentrations, typically out to 50 km from the facility). Modeling should be performed 

in accordance with EPA’s Guideline on Air Quality Modeling, in Appendix W to 40 CFR Part 

51 (GAQM or Appendix W). AERMOD with its default settings is the standard model choice, 

with CALPUFF available for complex wind situations. 

A PSD permit application typically includes a Good Engineering Practice (GEP) stack height 

analysis, to ensure that (1) downwash is properly considered in the modeling, and (2) stack 

heights used as inputs to the modeling are no greater than GEP height, so as to disallow artificial 

dispersion from the use of overly tall stacks. The application may also include initial “load 

screening,” in which a variety of source operating loads and ambient temperatures are modeled, 

to determine the worst-case scenario for use in the rest of the modeling.
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The PSD regulations also require an analysis of the impact on nearby Class I areas, generally 

those within 100 km, though the relevant Federal Land Manager (FLM) may specify additional 

or fewer areas. This analysis includes the NAAQS, PSD increments, and Air Quality Related 

Values (AQRVs). AQRVs are defined by the FLM, and typically limit visibility degradation and 

the deposition of sulfur and nitrogen. Generally, CALPUFF is the standard model choice for 

Class I analyses, since it can handle visibility chemistry as well as the typically large distances 

(over 50 km) to Class I areas.

Finally, the PSD regulations require an additional impact analysis, showing the Main Flare’s

effect on visibility, soils, vegetation, and growth. This visibility analysis is independent of the 

Class I visibility AQRV analysis. The additional impact analysis for the Main Flare at the MCU 

Facility is discussed in Section 9 below.

8.1.2 Identification of MCU Facility Main Flare Modeling Documentation

The modeling analysis for the MCU Facility comprises the documents listed in Table 8-1 below. 

The original PSD Permit application dated March 22, 2007 contained the results of the original 

modeling. The revised PSD Application addresses higher BTU content and increased emissions 

and was submitted in April 2008. Resolute submitted a revised 1-hour SO2 Modeling analysis 

with AERMOD and accompanying DVD in April 2011.

Table 8-1: Modeling Documentation for MCU Facility Main Flare PSD Application

Short name Citation

December 2005 PSD 

Application for Main Flare 

PSD Permit Application for Main Flare submitted by ExxonMobil, 

dated December 5, 2005

March 2007 PSD 

Application for Main Flare

Revised PSD Permit Application for Main Flare submitted by 

ExxonMobil, dated March 22, 2007

(received by EPA on March 29, 2007)

April 2008 Revised PSD 

Application

Revised PSD Permit Application submitted by Resolute to address 

higher BTU content and increased emissions, dated April 2008

(received by EPA on June 2, 2008)

April 2011 MCU 1-Hour 

SO2 Modeling

McElmo Creek Unit Oil Production Facility-Main Flare, Gas 

Compression Facility 1-Hour SO2 Modeling with AERMOD and 

accompanying DVD, dated April 2011

(received by EPA on June 3, 2011)

8.2 BACKGROUND AMBIENT AIR QUALITY

The PSD regulations require the air quality analysis to contain air quality monitoring data as 

needed to assess ambient air quality in the area for the PSD-regulated pollutants for which there 

are NAAQS that may be affected by the source. In addition, for demonstrating compliance with 

the NAAQS, a background concentration is added to represent those sources not explicitly 

included in the modeling, so that the total accounts for all contributions to current air quality.
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No site or area-specific data was available for southeastern Utah for NO2, CO, SO2 and ozone21; 

therefore, air quality data gathered from monitoring stations located in north central Utah,

primarily within the Salt Lake City metropolitan area, are used as conservative indicators of air

quality for this rural area of Utah. Background PM10 concentrations are not addressed since 

PM10 emissions are insignificant from a flare, and the Consent Decree does not cite emission 

limits for PM10.

Table 8-2 below describes the maximum background concentrations of the PSD-regulated 

pollutants for which there are NAAQS that may be affected by the Facility’s emissions, and the 

corresponding NAAQS.

Background air quality monitoring data shown in the table are from 2009-2011 for NO2, CO, and 

ozone. No site or area-specific data was available for southeastern Utah for NO2, CO and ozone; 

therefore, except for SO2, air quality data gathered from monitoring stations located in north 

central Utah, primarily within the Salt Lake City metropolitan area, are used as conservative 

indicators of air quality for this rural area of Utah. Available SO2 data from Shiprock 

(Farmington, New Mexico) are more representative of rural areas around the MCU Facility. 

Ozone concentrations are cited as surrogate for VOC impacts because VOCs do not have an 

ambient air quality standard; rather, VOC is considered a contributor to the formation of ozone. 

Table 8-2: Maximum Background Concentrations and NAAQS

NAAQS pollutant 

& averaging time

Background 

Concentration, μg/m3 NAAQS, μg/m3

NO2, 1-hour 103.4 (55 ppb) 188 (100 ppb)

NO2, annual 34 (18 ppb) 100 (53 ppb)

SO2, 1-hour 79 (30 ppb) 196 (75 ppb)

CO, 1-hour 5,726 (5 ppm) 40,000 (35 ppm)

Ozone, 8-hour 0.065 (ppm) 0.07 (ppm)

Note: The NO2 1-hr value is 98th percentile averaged over three years rather than maximum;

The SO2 1-hr value is 99th percentile averaged over three years rather than maximum

8.3 MODELING METHODOLOGY FOR CLASS II AREAS

The Applicant modeled the impact of the Main Flare on the NAAQS and PSD Class II 

increments using AERMOD and SCREEN in accordance with EPA’s GAQM (Appendix W of 

40 CFR Part 51). The modeling analyses included the maximum air quality impacts from a 

variety of conditions to determine worst-case short-term air impacts.

8.3.1 Model selection

As discussed in the latest PSD Application (April 2011 MCU 1-Hour SO2 Modeling, p.5-2), the

model that Resolute selected for analyzing air quality impacts in Class II areas is AERMOD, 

along with AERMAP for terrain processing and AERMET for meteorological data processing. 

This is in accordance with the default recommendations in EPA’s GAQM, Section 4.2.2 on 

 21 NOx and VOC are precursors to ozone formation.
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Refined Analytical Techniques. SCREEN was also used in earlier the earlier modeling 

submittals.

8.3.2 Meteorology model inputs

AERMOD requires representative meteorological data in order to accurately simulate air quality 

impacts. Resolute used surface meteorological data collected for a five consecutive-year period 

(2005-2009) at the Canyonlands Airport meteorological station near Moab, Utah, northwest of 

the Main Flare site. This station is located approximately 105 miles (170 km) from the t site. 

Utah processed the data using EPA’s AERMET data processor, and provided the data to the 

Applicant. EPA concurs that the chosen Canyonlands Airport data is the most representative for 

the Main Flare analysis.

For upper air data, the Applicant obtained concurrent data from the Grand Junction, Colorado 

upper air site located approximately 134 miles (215 km) north of the Main Flare site as being the 

most representative site available that had data complete enough to use. No other upper air 

meteorological monitoring stations are located closer to the Main Flare site. (MCU 1-hour SO2

Modeling, April 2011, p.5-3pdf17). EPA agrees that it is appropriate to use Grand Junction, 

Colorado upper air data for the Main Flare analysis.

For screening model application, the full array of 44 discrete meteorological conditions

internally generated by SCREEN3 was used to estimate potential worst-case short-term (i.e.,

one-hour averaged) impacts for each modeled pollutant. The maximum impact cited by

SCREEN3 from a specific discrete meteorological condition (wind speed, stability class and

mixing height combination) and receptor distance was used as the basis for estimating maximum

pollutant impacts. The maximum one-hour impact for each pollutant was extrapolated to values

for each averaging period for which a pollutant has an applicable NAAQS and PSD increment,

using the adjustment factors referenced below: 

Averaging Time Multiplying Factor

3 hours 0.9

8 hours 0.7

24 hours 0.4

Annual 0.08

8.3.3 Land characteristics model inputs

Land characteristics are used in the AERMOD modeling system in three ways: 1) via elevation 

within AERMOD to assess plume interaction with the ground; 2) via a choice of rural versus 

urban algorithm within AERMOD; and 3) via specific values of AERMET parameters that affect 

turbulence and dispersion, namely surface roughness length, Bowen ratio, and albedo. The 

surface roughness length is related to the height of obstacles to the wind flow and is an important 

factor in determining the magnitude of mechanical turbulence. The Bowen ratio is an indicator 

of surface moisture. The albedo is the fraction of total incident solar radiation reflected by the 

surface back to space without absorption. 
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AERMAP is a terrain preprocessor that uses Digital Elevation Model (DEM) or National 

Elevation Dataset (NED) electronic files, which are readily available online, for use with usergenerated receptor grids. The output file consists of the x, y locations of each receptor, mean sea 

level (MSL) elevation and hill profile parameter. The hill profile parameter is used in 

determining plume flow around elevated terrain. Source elevation and receptor elevations and 

hill heights were determined through AERMAP using NED files.

Reolute determined surface parameters including the surface roughness length, albedo, and 

Bowen ratio for the area surrounding the Canyonlands Airport meteorological tower using the 

AERMET preprocessor, AERSURFACE (Version 08009), and the USGS 1992 National Land 

Cover (NLCD92) land-use data set. The NLCD92 data set used in the analysis has 30 m data 

point spacing and 21 land-use categories. Seasonal surface parameters were determined using 

AERSURFACE according to EPA’s guidance.

8.3.4 Model receptors

Receptors in the model are geographic locations at which the model estimates concentrations. 

The Applicant places the receptors such that they have good area coverage and are closely 

spaced enough so that the maximum model concentrations can be found. At larger distances, 

spacing between receptors may be greater than it is close to the source, since concentrations vary 

less with increasing distance. The spatial extent of the receptors is limited by the applicable 

range of the model (roughly 50 km for AERMOD), and possibly by knowledge of the distance at 

which impacts fall to negligible levels. Receptors need be placed only in ambient air, that is, 

locations to which the public has access, and that are not inside the project fence line. 

Discrete receptors in UTM Zone 12 NAD83 coordinates were processed by AERMAP using 10-

meter NED data with the following grid resolutions:

• A single ring of receptors 200 meters from the center point of the flare

• 100 meter spaced grid out to 2,200 meters from the flare

• 250 meter spaced grid from 2.2 to 10 kilometers from the flare

• 500 meter spaced grid from 10 to 20 kilometers from the flare

Additional blocks of 100-meter spaced grids were also used to determine maximum 

concentrations within the coarse grids. 

AERMOD was run in both the FLAT and ELEV modes to assess the effects of terrain on 

modeled impacts.

8.3.5 Stack parameter model inputs

Short-term pollutant emission rates were estimated by assuming that the maximum volume of 

process gas that could be generated from the well field would be sent to the flare at four different 

heat content values (in BTU/scf). These four heat content values represent a range of estimates 
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including the lowest allowable LHV, the lowest LHV from 2004 gas analyses, the lowest LHV 

from 2005-2008 gas analyses and the highest LHV from 2005-2008 gas analyses data. The 

lowest value input was 300 BTU/scf, which is the lowest allowable LHV as stated in 

40 CFR § 60.18(c)(3)(ii). The next lowest value utilized was 443 BTU/scf, which is the lowest 

of four 2004 actual plant gas samples from the MCU Facility. The LHV of 443 BTU/scf was 

utilized due to the assumption that it would provide the least amount of heat rise, thus producing 

the lowest effective release height. The lowest and highest LHVs from 2005-2008 gas analyses 

data of 538.8 and 682.4 BTU/scf, respectively, were also used for emission estimation. The 

resultant range of BTU contents and effective release heights were modeled to evaluate the 

sensitivity of impacts to each emission rate/effective release height and diameter combination. 

The modeling done by the Applicant used the corresponding stack parameters in Table 8-3 

below.

Table 8-3: Stack Parameters for Main Flare

Operating Mode Stack Height

(m)

Stack Diameter

(m)

Stack Velocity

(m/s)

Stack Temp

(Degrees K)

300 BTU/scf 59.45 3.56 20.0 1273

443 BTU/scf 59.45 4.33 20.0 1273

538.8 BTU/scf 59.45 4.77 20.0 1273

682.4 BTU/scf 59.45 5.37 20.0 1273

Source: April 2011 MCU 1-hour SO2 modeling, Table 5-3

Table 8-4: Load Screening for Main Flare

Operating Mode NOx

(g/s)

SO2

(g/s)

CO

(g/s)

300 BTU/scf 1.50 9.18 12.84

443 BTU/scf 2.21 9.18 18.96

538.8 BTU/scf 2.21 9.18 23.06

682.4 BTU/scf 2.21 9.18 29.21

Source: April 2011 MCU 1-hour SO2 modeling, Table 5-3

8.3.6 Good Engineering Practice (GEP) Analysis

For modeling purposes, particularly for comparison to short-term standards and PSD increments, 

the worst-case impacts from the Main Flare would be during an upset episode when all process 

gas is sent to the flare, rather than re-injected into the ground. Thus, modeled flare stack 

parameters were adjusted to reflect the instantaneous nature of heat release characteristics of a 

flare when combusting all process gas rather than re-injecting for input to AERMOD. The 

algorithm for this characterization is based on the Texas Commission on Environmental 

Quality’s “Technical Basis for Flare Parameters” (September 10, 2004). An effective stack 

diameter at an assumed stack velocity of 20 m/s at the estimated heat release (in calories per 

second) of the flare is estimated. An effective stack height is estimated based on heat release and 

the physical stack height of the flare. The actual flare stack height of 195 feet was field verified 

to ensure proper stack height.
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8.4 NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS) AND PSD CLASS II

INCREMENT CONSUMPTION ANALYSIS

8.4.1 Pollutants with Significant Emissions

The PSD regulations require an air quality impact analysis for each PSD-regulated pollutant (for 

which there is a NAAQS) that a major source has the potential to emit in a significant amount, 

i.e., an amount greater than the Significant Emission Rate for the pollutant. Applicable MCU 

Facility emissions and the Significant Emission Rates are shown in Table 8-4. As shown in 

Table 8-4, EPA does not expect the MCU Facility to emit CO and NOx in significant amounts. 

However, based on the estimates submitted by the applicant, EPA expects the MCU Facility to 

emit SO2 and VOC in significant amounts. Therefore, this permit action triggers air impact 

analyses for CO, NO2 and SO2.

Table 8-5: PSD Applicability to the MCU Facility

Criteria 

Pollutant

McElmo Creek Emissions

(tpy)

Significant Emission Rate

(tpy) PSD applicable?

CO 73 100 No

NOx 13.4 40 No

SO2 60 40 Yes

VOC 95.4 40 Yes

Source: April 2008 Revised PSD Application, Table 3-2

However, the worst-case conditions based on the modeled maximum flare rate of 14.83 MCFD 

and LHV of 682.4 BTU/scf result in emissions of 319.1 tpy of SO2, 1,015.4 tpy of CO, and 118.5 

tpy of NOx. These very conservative worst-case conditions result in emission rates in the 

analysis that are at least five times greater than current air permit limits. Even with these worstcase emission estimates that far exceed the current air permit limits and actual flow rate 

conditions, the modeling results show no exceedances of the NAAQS or the PSD Class II 

Increments.

8.4.2 Preliminary Analysis: Project-Only Impacts

EPA has established Significant Impact Levels (SILs) to characterize air quality impacts. A SIL 

is the ambient concentration resulting from the Facility’s emissions, for a given pollutant and 

averaging period, below which the source is considered to have an insignificant impact. For 

maximum modeled concentrations below the SIL, further air quality analysis for the pollutant 

may not be necessary. For maximum concentrations that exceed the SIL, EPA requires a 

cumulative modeling analysis, which incorporates the combined impact of nearby sources of air 

pollution to determine compliance with the NAAQS and PSD increments.

Table 8-5 shows the results of the preliminary or project-only analysis based on maximum 

operations for the Main Flare. The worst case short-term impacts from the flare would be during 

an upset episode when all process gas is sent to the flare, rather than injected in the ground. The 

updated modeling includes the worst-case impacts from four flare gas heat content scenarios 

defined in a revise permit application submitted in April 2008. Resolute used SCREEN results 
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to predict annual, 24-hour and 3-hour SO2 impacts. Resolute performed 1-hour SO2 modeling 

with AERMOD. EPA determined 1-hour NO2 and 1-hour and 8-hour CO impacts from the SO2

AERMOD results by taking the ratio of the NO2 and SO2 emissions for various cases, including 

the worst case. EPA compared the ratio with the predicted SO2 cumulative impacts from Tables 

6-1 and 6-2 provided in Resolute’s April 2008 PSD application submittal for 1-hour SO2

Modeling. The only significant impacts predicted by the modeling results was for 1-hour SO2.

Table 8-6: Main Flare Significant Impacts

NAAQS Pollutant & 

Averaging Time

Project-Only Modeled 

Impact, μg/m3

Significant Impact 

Level (SIL), μg/m3

Project impact 

significant?

NO2, 1-hour 5.0 7.5 (4 ppb) No

NO2, Annual 0.15 1 No

SO2, 1-hour 11.6 7.9 (3 ppb) Yes

SO2, 3-hour 11.6 25 No

SO2, 24-hour 4.65 5 No

SO2, Annual 0.93 1 No

CO, 1-hour 30 2000 No

CO, 8-hour 30 500 No

Sources: April 2008 Revised PSD Application, Sections 6 and 7; April 2011 MCU 1-Hour SO2 Modeling, Sections 5 and 6

8.4.3 Cumulative Impact Analysis

A cumulative NAAQS or PSD increment impact analysis considers impacts from nearby sources 

in addition to impacts from the project itself. In addition, for demonstrating compliance with the 

NAAQS, the applicant adds a background concentration to represent those sources not explicitly 

included in the modeling, so that the total accounts for all contributions to current air quality. In 

this case, Resolute submitted cumulative impact analyses demonstrating compliance with the 

1-hour SO2 NAAQS.

PSD increments are limits on cumulative air quality degradation. They are set to prevent air with 

pollutant concentrations lower than the NAAQS from being degraded to the level of the 

NAAQS. PSD increments apply in addition to the NAAQS. Increments have been established 

for NO2 and SO2. However, there have been no increments established for 1-hour NO2 and SO2. 

For demonstrating compliance with the PSD increment, only increment-consuming sources need 

to be included, because the increment concerns only changes occurring since the applicable 

baseline date. For this analysis, no pollutants with Class II increments were predicted to have 

impacts above the SIL.

8.4.3.1 Nearby Source Emission Inventory

For both the PSD increment and NAAQS analyses, there may be a large number of sources that 

could potentially be included, so judgment must be applied to exclude small and/or distant 

sources that have only a negligible contribution to total concentrations. Only sources with a 

significant concentration gradient in the vicinity of the source need be included; the number of 

such sources is expected to be small except in unusual situations. (GAQM, Section 8.2.3)
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The Utah Department of Air Quality (UDAQ) and the Colorado Air Pollution Control Division 

(CAPCD) provided a list of all stationary sources within 50 km of the MCU Facility’s Main 

Flare (approximate distance to the farthest significant impact plus 50 km) for SO2. A 

comprehensive procedure was used to determine which sources were included in the emissions 

inventory. 

It should be noted that short-term maximum emission rates rather than annual emission rates 

determine the distance over which a facility might have a significant impact for short-term 

standards (e.g., hourly NO2). Peak rates that occur with flare heat content of 300 BTU/scf

determine the MCU Facility’s Main Flare significant impact area for hourly SO2. The applicant 

identified eight facilities nearby for inclusion in the emission inventory for the 1-hour SO2

cumulative analysis, based on data from Utah and Colorado. 

Current EPA SO2 guidance suggests that emphasis on determining which nearby sources to 

include in the nearby source inventory should focus on the area within about 10 km of the MCU 

Facility’s Main Flare location in most cases, which indicates that the MCU Facility inventory is 

adequate for performing these cumulative analyses.22 

Therefore, taking into consideration the current EPA guidance suggesting a focus on sources 

within 10 km, EPA concludes that the combination of a representative background monitored 

concentration, and the additional consideration of sources out to 50 km provide sufficient 

justifications for the inventories used in the cumulative analysis.

8.4.3.2 NO2-Specific Considerations

While the new 1-hour NO2 NAAQS is defined relative to ambient concentrations of NO2, the 

majority of NOx emissions from stationary sources are in the form of nitric oxide (NO) rather 

than NO2. Appendix W notes that the impact of an individual source on ambient NO2 depends in 

part “on the chemical environment into which the source’s plume is to be emitted” (see Section 

5.1.j). Because of the role NOx chemistry plays in determining ambient impact levels of NO2 

based on modeled NOx emissions, Section 5.2.4 of Appendix W recommends a three-tiered 

screening approach for NO2 modeling. Later guidance documents issued by EPA expand on this 

approach. Tier 1 assumes full conversion of NO to NO2. Tiers 2 and 3 are refinements of the 

amount of conversion of NO to NO2. The applicant and EPA used the Tier 1 approach, in which 

the 1-hour NO2 and annual impacts are based on the assumption that all of the NO is converted 

to NO2. 

8.4.3.3 Results of the Cumulative Impacts Analysis

The results of the PSD cumulative impacts analysis for the MCU Facility’s worst case operations 

for SO2 emissions are shown in Table 8-6. The analysis demonstrates that emissions from the 

MCU Facility’s Main Flare will not cause or contribute to exceedances of the NAAQS or for any 

 22 See “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2

National Ambient Air Quality Standard”, Memorandum from Tyler Fox, EPA Air Quality Modeling Group to EPA 

Regional Air Division Directors, March 1, 2011, page 16 
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applicable PSD increments. The background concentrations were taken from Table 8-2 above. 

As discussed above, the MCU Facility’s Main Flare maximum modeled concentrations are 

below the SILs for annual and 1-hour NO2, and for annual, 24-hour and 3-hour SO2; therefore, a 

cumulative impacts analysis was not required to demonstrate compliance for these pollutants and 

averaging times. 

EPA also considered additional information to ensure that the project would not be responsible 

for causing a new NAAQS exceedance outside this modeling area. EPA considered sources in 

Utah and Colorado (no sources of interest were located outside of these states) that were not 

included, but which had been evaluated for inclusion/exclusion, in the cumulative impacts 

modeling above. EPA concluded that these sources are either small enough or distant enough 

that the Main Flare’s expected emissions along with emissions from these sources would not 

create any new NAAQS exceedance in the modeling area outside of the significant impact area.

Table 8-7: MCU Facility Main Flare Compliance with Class II PSD Increments and NAAQS

NAAQS 

pollutant & 

averaging 

time

All Sources 

Modeled 

Impact 

(ug/m3)

PSD 

Increment 

Consumption

(ug/m3)

Background 

Concentration 

(ug/m3)

Cumulative 

impact w/ 

background

(ug/m3)

NAAQS 

(ug/m3)

PSD 

Increment 

(ug/m3)

SO2, 1-hour 26.76 N/A 79 105.76 196 None

Source: April 2011 MCU 1-Hour SO2 Modeling, Tables 6-1 and 6-2

Note: There are currently no PSD increments defined for 1-hour SO2

8.5 CLASS I AREA ANALYSIS

8.5.1 Air Quality Related Values

The two nearest Class I areas are within 100 km of the MCU Facility site and are listed below:

• Mesa Verde National Park 60 km (38 miles) 

• Canyonlands National Park 96 km (60 miles) 

There are an additional six areas within 200 km: Marble Mountain Wilderness Area (116 km), 

Redwood National Park (147 km), Lava Beds National Monument (148 km) Arches National 

Park is located 160 km and South Warner Wilderness Area (192 km). 

Based on the most recent Federal Land Managers’ Air Quality Related Values (AQRV) Work 

Group (FLAG) (2010) published guidance the following screening approach is used to determine 

whether a more refined Class I Air Quality Analysis is required. This approach, which only 

applies to projects located more than 50 km from a Class I area, requires adding all of the 

visibility-related emissions (SO2, NOx, PM10 and sulfuric acid mist) from a project (based on 24-

hour maximum allowable emissions expressed in units of tons per year) and dividing the sum by 

the distance between the project and the nearest Class I area, which is Mesa Verde 60 km away. 

The values input into the table are the maximum. If the result is less than 10, the project is 

presumed to have negligible impacts to Class I AQRVs. The table below shows that the 
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project’s emissions are well below the FLAG screening criteria. Therefore, no further Class I 

AQRV analysis is required.

Table 8-8: Summary of Q/D Analysis

Parameter Value

NOx Emission Increase 13.4 tpy

SO2 Emission Increase 60 tpy

PM10 Emission Increase --

H2SO4 Emission Increase --

Distance to Closest Class I Area 73.4 km

Q/D 1.22 tpy/km

Q/D Threshold of Concern 10 tpy/km

8.5.2 Class I Increment Consumption Analysis

EPA requires an analysis addressing Class I increment impacts for the applicable pollutants 

regardless of the results of the Class I AQRV analysis. The analysis for annual NO2 and annual, 

24-hour and 3-hour SO2 was included in the original application submitted in 2008. Based on 

the results, EPA did not require updated modeling to be submitted with the 2011 PSD application 

because of the very low predicted impacts by SCREEN. The results are presented in Table 8-9

below.

NO2 and SO2 impacts are well below their respective significant impact levels; therefore, the 

Applicant has demonstrated the emission levels for the Main Flare will not cause or contribute to 

any Class I violation for PM10 or NO2.

Table 8-9: MCU Facility Main Flare Class I Increment Impacts at Class I Area

Class I Area Pollutant Averaging Time Main Flare

Impact, μg/m3

Class I PSD 

Increment, μg/m3

Mesa Verde

NO2 Annual 0.0102 2.5

SO2

Annual 0.03 2

24-hour 0.90 5

3-hour 2.01 25

Source: April 2008 Revised PSD Application, Table 7-6
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9. ADDITIONAL IMPACT ANALYSIS

In addition to assessing the ambient air quality impacts expected from a source subject to PSD 

review, the PSD regulations require that EPA evaluate other potential impacts on 1) soils and 

vegetation; 2) growth; and 3) visibility impairment. 40 CFR § 52.21(o). The depth of the 

analysis generally depends on existing air quality, the quantity of emissions, and the sensitivity 

of local soils, vegetation, and visibility in the source's impact area. 

9.1 SOILS AND VEGETATION 

The additional impact analysis includes consideration of potential impacts to soils and vegetation 

associated with the MCU’s emissions. This component generally includes: 

• A screening analysis to determine if maximum modeled ground-level concentrations of 

pollutants from the Main Flare could have an impact on plants; and

• A discussion of soils and vegetation that may be affected by proposed emissions from the 

Main Flare and the potential impacts on such soils and vegetation associated with such 

emissions.

The Main Flare at the MCU Facility is located on Navajo Nation land in southeastern Utah near 

the town of Aneth in San Juan County, Utah. The MCU Facility is an oilfield operation, which 

is primarily involved in crude petroleum and natural gas extraction. The Applicant presented its 

discussion of the potential impacts on soils and vegetation in its supplemental PSD permit 

application submitted to EPA Region 9 in February 2013. Ground cover is relatively sparse 

because of the semiarid climatic conditions surrounding the site. Vegetation in San Juan County 

includes woodlands, dominated by Pinyon Pine and Utah Juniper, desert and semi-desert shrubs 

classified as saltbush because of the because of the prevailing saline soils, sagebrush, blackbush 

and scattered grassland areas. Resolute provided specific vegetation designated as sensitive for 

San Juan County. This information is provided in Table 9-1.
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Table 9-1: Sensitive Plant Species Potentially Occurring in San Juan County, Utah

Common Name Habitat

Navajo Sedge Seasonally wet, seeps, springs, hanging gardens in Navajo sandstone:

3,770 -5,908 ft. elevation

Chatterly's Onion Moist pinyon-juniper and sagebrush sites

Culter Milkwood Sand dunes

Cronquist Milkvetch Cutler formation (Comb Wash), Morrison formation (Aneth)

Copper Canyon Milkvetch Warm desert shrub, 3,085 ft. elevation, Copper Canyon

Skull Valley Spring Parsley Deposits of wind-blown sand

Beck's Spring Parsley Sandy soil of Navajo sandstone origin, crevices and ledges of 

slickrock, higher elevations in Abajo Mountains

Hole-in-the Rock Prairie 

Clover

Sandstone bedrock and sand in blackbrush and mixed desert shrub:

4,690 -5,000 ft. elevation

Spineless Hedgehog Cactus Blackbrush, ephedra, sagebrush, pinyon-juniper mountain brush,

aspen communities: 3,200 - 8,400 ft. elevation

Nevada Willowherb Talus slopes, crevices

Kachina Daisy Seasonally wet seeps, hanging gardens on sandstone outcrops

Redroot Buckwheat Sagebrush and pinyon-juniper: 5,000 ft. elevation

Cataract Canyon Gilia Mixed warm and cool desert shrub communities: 3,280 - 5,215 ft. 

elevation

Alcove Bog Orchid Moist streambanks, seeps, hanging gardens in mixed desert shrub,

pinyon-juniper and oakbrush: 4,360 - 8,690 ft. elevation

Canyonlands Lomatium Slot canyons between Entrada sandstone, sandy soil or crevices in 

sandstone, sheltered cool areas of slopes

Western Hophornbeam Small tree at bases of monoliths, hanging gardens of sandstone:

4,000 - 5,600 ft. elevation

Paradox Breadroot Pinyon-juniper and mixed desert shrub: 5,020 ft. elevation

Alcove Rock Daisy Drier crevices in seasonally wet hanging gardens, alcoves at

4,000 ft. elevation, Navajo & Windgate sandstone, Rico

Formation

Howell Scorpionweed Salt and warm desert shrub, pinyon-juniper: 3,690 - 5,000 ft. elevation

Bluff Phacelia Salt desert shrub: 4,500 ft. elevation

Mancos Shadscale Salt desert shrub in Morrison Formation

Jane's Globemallow Sandy soils of weathered white rim and Organ Rock areas of

Cutler Formation, warm/salt desert shrub: 4,000 - 4,600 ft. elev.

Source: Table 7-8 of the supplemental PSD permit application submitted to EPA Region 9 on February 20, 2013

The values in Table 9-2 below and Table 8-5 of this document provide the concentration impacts 

used below in EPA’s “Screening Procedure for the Impacts of Air Pollution Sources on Plants, 

Soils and Animals” (1980)23 to determine if maximum modeled ground-level concentrations of 

SO2, NO2 and CO from the main flare could have an impact on plants, soils, and animals. 

 23 “

Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals,” EPA 450/2-81-078, 

December 1980.
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Table 9-2: Screening Ambient Air Concentrations for Sensitive Vegetation Exposure

Pollutant 1-hour

(μg/m3)

3-hour

(μg/m3)

4-hour

(μg/m3)

8-hour

(μg/m3)

1-week

(μg/m3)

1-month

(μg/m3)

Annual

(μg/m3)

SO2 9 7 -- -- -- -- 18

NO2 -- -- 3760 3760 -- 564 94

CO -- -- -- -- 1,800,000 -- --

Source: Table 7-9 of the supplemental PSD permit application submitted to EPA Region 9 on February 20, 2013

The modeled impacts of SO2, NO2, and CO emissions from the Main Flare range from below one 

percent to five percent of the minimum impact levels/screening concentrations identified in this

Screening Procedure.

Table 9-3: Maximum Concentrations & Screening Concentrations for Ambient Exposures

Criteria Pollutant and Guidance 

Averaging Time

EPA Screening 

Concentration 

(μg/m3)

Modeled Maximum 

Concentrations

(μg/m3)

Modeling 

Averaging time

SO2 1-Hour 917 11.6 1 hour

SO2 3-Hours 786 (0.30 ppm) 11.6 (0.0045 ppm) 3 hour

SO2 Annual 18 0.93 Annual

NO2 4-Hours 3,760 5.0 1 hour

NO2 8-Hours 3,760 5.0 1 hour

NO2 1-Month 564 5.0 1 hour

NO2 Annual 94 (0.05 ppm) 0.15 (0.00008 ppm) Annual

CO Weekly 1,800,000 30 8 hour

In summary, based on our consideration of the information and analysis provided by the 

Applicant, and other relevant information, we do not believe that emissions associated with the 

MCU Facility will generally result in adverse impacts to soils or vegetation. 

9.2 VISIBILITY IMPAIRMENT

The additional impact analysis also evaluates the potential for visibility impairment (e.g., plume 

blight) associated with the Main Flare. Using procedures from EPA’s Workbook for Plume 

Visual Impact Screening and Analysis,

24 the potential for visibility impairment is characterized 

for:

• Class I areas located within 50 km of the proposed MCU; and 

• Class II areas identified as potentially sensitive state or federal parks, forests, 

monuments, or recreation areas. 

 24 “Workbook for Plume Visual Impact Screening and Analysis (Revised)”, EPA, EPA–454/R–92–023, 1992.
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There are no Federal Class I areas located within 50 km of the MCU Facility’s Main Flare site;

the nearest Class I area is Mesa Verde National Park 61 km (38 miles), as presented in Section 

8.5.1. For Class II areas, the Applicant evaluated both Level I and Level II VISCREEN 

screening analyses for visibility impairment for five different Hovenweep units in the 

Hovenweep federal Class II areas within 50 km of the site:

• Cajon Unit (4.8 km away) 

• Square Tower (18 km away) 

• Holly (21 km away)

• Horseshoe and Hackberry (22 km away)

• Cuthroat Castle (28 km away)

Even though, the closest three units had predicted values over the quantitative visibility 

impairment threshold for Class I areas, EPA has not yet established a similar quantitative 

visibility impairment threshold for Class II areas. For the MCU Facility’s Main Flare, these 

predicted values are used for informational purposes only. There is a Level 3 analysis using the 

model PLUVUE that can be requested, but has been limited to being requested only for projects 

which have predicted impacts over the Class I threshold levels in a Class I area. A Level-3 

analysis is no longer considered a screening analysis because it a comprehensive analysis of the 

magnitude and frequency of occurrence of plume visual impacts as observed at a sensitive Class 

I area vista. Even if a PLUVUE analysis were done and the predicted impacts were greater than 

the Level 3 threshold, this would not likely result in a change in the emission rates for the flare. 

9.3 GROWTH

The growth component of the additional impact analysis involves a discussion of general 

commercial, residential, industrial, and other growth associated with the MCU Facility. This 

analysis considers emissions generated by growth that will occur in the area due to the source. 

In conducting this review, we focus on residential, commercial and industrial growth that is 

likely to occur to support the source under review including, for example, employment expected 

during construction and operations and potential growth impacts associated with such 

employment, such as impacts to local population and housing needs.

No additional temporary employees have been used. Although there has been an increase in the 

number of full-time employees, no significant growth is expected for this Facility.
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10. ENDANGERED SPECIES ACT

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. 1536, and its 

implementing regulations at 50 CFR Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued existence of 

any endangered or threatened species or result in the destruction or adverse modification of such 

species’ designated critical habitat. EPA has determined that this PSD permitting action is 

subject to ESA Section 7 requirements. However, the MCU Facility is an existing operation, 

other than the replacement of a fixed speed fan with a variable speed fan to provide better 

pollution control at the Main Flare, EPA Region 9’s action does not authorize any new 

construction or modification of existing equipment at the MCU Facility. Therefore, EPA has 

determined that this permit action will have no effect on any endangered or threatened species or 

any designated critical habitat in the area. The United States Fish and Wildlife Service (FWS) in 

a January 25, 2013 e-mail to EPA Region 9.

11. NATIONAL HISTORIC PRESERVATION ACT

Pursuant to Section 106 of the National Historic Preservation Act (NHPA), 6 U.S.C. § 470f, and 

its implementing regulations at 36 CFR Part 800, prior to the approval of the expenditure of any 

funds on or prior to the issuance of any license for an undertaking, EPA is required to take into 

account the effects of its undertakings on historic properties and afford the Advisory Council on 

Historic Preservation (Council) a reasonable opportunity to comment with regard to such 

undertakings. Consultation is required for all undertakings that have the potential to affect 

historic properties. Section 106 consultations assess whether historic properties exist within an 

undertaking’s area of potential effect and, if so, whether the undertaking will adversely affect 

such properties. The term “historic properties” means prehistoric or historic districts, sites, 

buildings, structures, or objects included in, or eligible for inclusion in, the National Register of 

Historic Places maintained by the Department of the Interior. Historic properties include 

properties of traditional religious and cultural importance to an Indian Tribe or Native Hawaiian 

organization. Consultation is generally with relevant state and tribal historic preservation 

authorities in the first instance, with opportunities for direct Council involvement in certain 

circumstances. 

EPA’s action, which is for the issuance of a federal PSD permit, is an undertaking as defined in 

36 CFR 800.16(y). The MCU Facility has been in operation since the 1950s. This permit action 

is for the Main Flare which has been in operation since the 1990s. The EPA’s permit action is to 

incorporate the federal Consent Decree requirements for the Main Flare into the PSD permit. 

Other than the replacement of a fixed speed fan with a variable speed fan to provide better 

pollution control at the Main Flare, this permit action does not authorize any new construction or 

modification of existing equipment at the MCU Facility. EPA is currently consulting with the 

Tribal Historic Preservation Officers for the Navajo Nation and Ute Mountain Indian tribes. 
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12. MAGNUSON-STEVENS FISHERY CONSERVATION AND 

MANAGEMENT ACT

The Magnuson-Stevens Fishery Conservation and Management Act (MSFCMA) was enacted to 

promote the U.S. fishing industry’s optimal exploitation of coastal fisheries by consolidating control 

over territorial waters to manage fish stocks. Implementation of the MSFCMA is by the U.S. 

Department of Commerce, National Marine Fisheries Service (NMFS), and its appointed regional 

fishery management councils. Because the MCU Facility is located on the Navajo Nation Indian 

Reservation in Utah, which is not located near any coastal or territorial waters and will not 

directly affect any fisheries or fishery resources. Therefore, this PSD permit action will not 

affect marine fisheries management. 

13. COASTAL ZONE MANAGEMENT ACT

The Coastal Zone Management Act (CZMA) of 1972 provides for management of the nation’s 

coastal resources, including the Great Lakes. It encourages states to preserve, protect, develop, 

and where possible, restore or enhance valuable natural coastal resources such as wetlands, 

floodplains, estuaries, beaches, dunes, barrier islands, and coral reefs, as well as the fish and 

wildlife using those habitats. The CZMA is administered by the National Oceanic and 

Atmospheric Administration’s Office of Ocean and Coastal Resource Management. Under this 

act, two national programs were created, the National Coastal Zone Management Program 

(CZMP) and the National Estuarine Research Reserve System, covering areas bordering the 

Atlantic, Pacific, and Arctic Oceans, the Gulf of Mexico, Long Island Sound, and the Great 

Lakes. Because the MCU Facility is located in on the Navajo Nation Indian Reservation in Utah, 

which is not a coastal State, this PSD permit action will not affect any coastal resources.

14. ENVIRONMENTAL JUSTICE ANALYSIS

Executive Order 12898, entitled “Federal Actions To Address Environmental Justice in Minority 

Populations and Low-Income Populations,” states in relevant part that “each Federal agency 

shall make achieving environmental justice part of its mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or environmental effects of its 

programs, policies, and activities on minority populations and low-income populations.” Section 

1-101 of Exec. Order 12898, 59 Fed. Reg. 7629 (Feb. 16, 1994). 

EPA determined that there may be minority or low-income populations potentially affected by its 

proposed action on the MCU Facility PSD permit application, and determined that it would be 

appropriate to prepare an Environmental Justice Analysis for this action. EPA prepared an 

Environmental Justice Analysis, which is included in the administrative record for EPA’s 

proposed PSD permit for the MCU Facility. EPA’s analysis concludes that the MCU Facility’s 

Main Flare will not cause or contribute to air quality levels in excess of health standards for the 

pollutants regulated under the proposed PSD permit amendment; therefore, the Main Flare will 

not result in disproportionately high and adverse human health or environmental effects with 

respect to these air pollutants on minority or low-income populations residing near the MCU 

Facility site, or on the community as a whole.
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15. CLEAN AIR ACT TITLE V OPERATING PERMIT

The Applicant must apply for and obtain a Title V operating permit from the Navajo Nation 

Environmental Protection Agency (NNEPA). The NNEPA has been delegated authority to 

administer the federal Title V operating program by EPA for stationary sources on the Navajo 

Nation Indian Reservation, and has jurisdiction to issue the Title V Operating Permit for the 

MCU Facility. 

16. PUBLIC PARTICIPATION

16.1 PUBLIC COMMENTS

The comment period for EPA’s proposed PSD permit amendment for the MCU Facility begins 

on November 15, 2014. Any interested person may submit written comments. All written 

comments on EPA’s proposed action must be received by EPA via email or postmarked by

November 20, 2014. An extension of the comment period may be granted if the written request 

for an extension adequately explains why more time is required to prepare comments. 

Comments must be sent or delivered in writing to one of the following addresses:

E-mail: R9airpermits@epa.gov

U.S. Mail: Shaheerah Kelly (AIR-3)

U.S. EPA Region 9

75 Hawthorne Street

San Francisco, CA 94105-3901

Alternatively, written comments may be submitted at the Public Hearing for this matter that

will be held on November 20, 2014 as described below. Comments should address the PSD 

permit action and Facility, including such matters as:

• BACT determinations for the Main Flare;

• The effects, if any, on Class I areas;

• The effect of the proposed facility on ambient air quality; and

• The attainment and maintenance of the NAAQS.

16.2 PUBLIC INFORMATION MEETING & PUBLIC HEARING

EPA will hold a Public Information Meeting for the purpose of providing interested parties with 

additional information and an opportunity for informal discussion of the proposed PSD permit. 

Immediately following the Public Information Meeting, EPA will hold a Public Hearing, 

pursuant to 40 CFR 124.12, to provide the public with further opportunity to comment on the 

proposed PSD permit. At the Public Hearing, any interested person may provide written 
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comments or oral comments, in English or Diné, and relevant data pertaining to the proposed 

permit amendment. The date, time, and location of the Public Hearings are as follows:

Date: November 20, 2014

Time: 5:00 PM – 6:00 PM (PUBLIC INFORMATION MEETING)

6:00 PM – 8:00 PM (PUBLIC HEARING)

Location: Aneth Chapter House 

East Highway 162, Mile Post 30

Aneth, Utah 84510

(435) 651-3525

English-Diné translation services will be provided at each Public Information Meeting and 

Public Hearing. If you require a reasonable accommodation, please contact Philip Kum, EPA 

Region 9 Reasonable Accommodations Coordinator, by October 31, 2014 at (415) 947-3566, or 

kum.philip@epa.gov.

16.3 AVAILABILITY OF PERMIT DOCUMENTS

All information submitted by the Applicant is available as part of the administrative record. The 

proposed air permit, Ambient Air Quality Impact Report/Fact Sheet (AAQIR/Fact Sheet), permit 

application and other supporting information are available on the EPA Region 9 website at 

http://www.epa.gov/region09/air/permit/r9-permits-issued.html#pubcomment. The 

administrative record may also be viewed in person, Monday through Friday (excluding federal 

holidays) from 9:00 AM to 4:00 PM, at the EPA Region 9 address above. Due to building 

security procedures, please contact Shaheerah Kelly at (415) 947-4156 at least 72 hours in 

advance to arrange a visit. Hard copies of the administrative record can be mailed to individuals 

upon request in accordance with Freedom of Information Act requirements as described on the 

EPA Region 9 website at http://www.epa.gov/region9/foia/.

The proposed PSD permit and the accompanying AAQIR/Fact Sheet are available for review and 

inspection at the Navajo Nation Environmental Protection Agency, Fort Defiance, AZ, 

(928) 871-7692 and the following Navajo Nation chapter house locations:

• Aneth Chapter House, Aneth, UT, (435) 651-3525

• Red Mesa Chapter House near Montezuma Creek, UT, (928) 656-3679

• Teec Nos Pos Chapter House, Teec Nos Pos, AZ, (928) 656-3662

• Mexican Water Chapter House, Bluff, AZ, (928) 429-0986

• Sweetwater Chapter House, Sweetwater, AZ, (928) 429-0977

• Dennehotso Chapter, Dennehotso, AZ, (928) 658-3300
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The proposed PSD permit amendment and AAQIR/Fact Sheet are also available for review and 

inspection at Receptionist Desk of the following libraries: 

• Monticello Library, Monticello, UT, (435) 587-2281

• Blanding Library, Blanding, UT, (435) 678-2335

• Montezuma Creek Library, Montezuma Creek, UT, (435) 651-3309

• Bluff Library, Bluff, UT, (435) 672-9996

• La Sal Library, La Sal, UT, (435) 686-9936

All comments that are received will be included in the public docket without change and will be 

available to the public, including any personal information provided, unless the comment 

includes Confidential Business Information (CBI) or other information whose disclosure is 

restricted by statute. Information that you consider CBI or otherwise protected should be clearly 

identified as such and should not be submitted through e-mail. If you send e-mail directly to the 

EPA, your e-mail address will be automatically captured and included as part of the public 

comment. Please note that an e-mail or postal address must be provided with your comments if 

you wish to receive direct notification of EPA’s final decision regarding the permit.

EPA will consider all written comments submitted during the public comment period before 

taking final action on the PSD permit amendment and will send notice of the final decision to 

each person who submitted comments and contact information during the public comment period 

or requested notice of the final permit decision. EPA will respond to all substantive comments in 

a document accompanying EPA’s final permit decision.

16.4 FINAL PERMIT DECISION

Before taking final action, EPA Region 9 will consider all written and oral comments submitted 

during the public comment period, including those provided at the public hearing, before taking 

final action on the PSD permit amendment. 

EPA will send notice of the final decision to each person who provides contact information and 

who: (i) submits comments during the public comment period, including oral comments 

provided at the public hearing; or (ii) requests notice of the final permit decision. EPA will 

summarize the contents of all substantive comments and provide written responses in a 

document accompanying EPA’s final permit decision. EPA will also make a transcript of the 

Public Hearing proceedings available to the public.

EPA’s final permit decision will become effective 30 days after the service of notice of the 

decision unless:

1. A later effective date is specified in the decision; or

2. The decision is appealed to EPA’s Environmental Appeals Board pursuant to 40 CFR 

124.19; or 

3. There are no comments requesting a change to the proposed permit decision, in which case 

the final decision shall become effective immediately upon issuance.
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16.5 CONTACT INFORMATION

If you have questions, would like to be added to our mailing list to receive future information 

about this proposed permit decision, or other PSD permit decisions issued by EPA Region 9,

please contact Shaheerah Kelly at (415) 947-4156 or e-mail at R9airpermits@epa.gov, or visit 

EPA Region 9’s website at http://www.epa.gov/region09/air/permit/psd-public-guidelines.html.

Shaheerah Kelly can also be reached through EPA Region 9’s toll-free general information line 

at (866) 372-9378.

17. CONCLUSION AND PROPOSED ACTION

EPA is proposing to amend the PSD permit for the MCU Facility owned and operated by 

Resolute. We believe that the proposed PSD permit amendment complies with PSD 

requirements, including the installation and operation of BACT and protection of the any 

NAAQS and PSD increment. We have made this determination based on the information 

supplied by the Applicant and our review of the analyses contained in the permit application. 

EPA will provide the proposed PSD permit amendment and this AAQIR/Fact Sheet to the public 

for review, and make a final decision after considering any public comments on our proposal.
Page 1 of 4 

* * * PUBLIC NOTICE * * * 

MCELMO CREEK UNIT OIL PRODUCTION FACILITY 

ANNOUNCEMENT OF PROPOSED PERMIT AMENDMENT, PUBLIC HEARING, AND 

REQUEST FOR PUBLIC COMMENT ON PROPOSED CLEAN AIR ACT PREVENTION 

OF SIGNIFICANT DETERIORATION PERMIT 

PERMIT APPLICATION NO. NU 05-01 

Proposed Action: The United States Environmental Protection Agency (EPA) Region 9 

provides notice of, and requests public comment on, EPA’s proposed action relating to 

amendments to the Prevention of Significant Deterioration (PSD) permit for the McElmo Creek 

Unit Oil Production Facility (MCU Facility), an existing oil and gas production operation. The 

MCU Facility is owned and operated by the Resolute Natural Resources Company. The mailing 

address for the facility is P.O. Box 100130, Aneth, UT 84510. The facility is located in Section 

31, Township 40 South, Range 25 East within the Four Corners Area on the Navajo Nation 

Indian Reservation near the town of Aneth, San Juan County, Utah. 

EPA is amending the PSD permit, in accordance with PSD regulations (40 CFR 52.21), to 

incorporate pollution limits, terms, and conditions for the already existing Main Flare at the 

MCU Facility pursuant to a federal Consent Decree (United States v. Mobil Exploration and 

Producing U.S. Inc., Case No. 2:05–CV–319, filed June 8, 2005). These pollution limits, terms, 

and conditions include Best Available Control Technology (BACT) emission limitations for 

nitrogen oxides, carbon monoxide, sulfur dioxide, and volatile organic compounds. 

Additionally, EPA is amending the PSD permit to remove and update other applicable 

requirements in the MCU Facility’s PSD permit due to equipment that has been shut down and 

removed from the site. Air pollution emissions as a result of this permit action would not cause 

or contribute to violations of any National Ambient Air Quality Standards (NAAQS) or any 

applicable PSD increments. Other than the replacement of a fixed speed fan with a variable 

speed fan to provide better pollution control at the Main Flare, this permit action does not 

authorize any new construction or modification of existing equipment at the MCU Facility. 

Request for Public Comment: Any interested person may submit written comments regarding 

today’s proposed PSD permit amendment. All written comments must be received or 

postmarked by November 20, 2014. Comments must be sent or delivered in writing to 

Shaheerah Kelly at one of the following addresses: 

E-mail: R9airpermits@epa.gov 

U.S. Mail: Shaheerah Kelly 

 U.S. EPA Region 9 (AIR-3) 

 75 Hawthorne Street 

 San Francisco, CA 94105-3901 
Page 2 of 4 

Alternatively, written comments may be submitted at the Public Hearing for this matter that 

will be held on November 20, 2014 as described below. 

Comments should address the proposed PSD permit amendment including, but not limited to, 

such matters as: 

1. BACT determinations for the Main Flare; 

2. The effects, if any, on Class I areas; 

3. The effect of the proposed PSD permit amendment on ambient air quality; and 

4. The attainment and maintenance of the NAAQS. 

Public Information Meeting & Public Hearing: EPA will hold a Public Information Meeting 

for the purpose of providing interested parties with additional information and an opportunity for 

informal discussion of the proposed PSD permit amendment. 

Immediately following the Public Information Meeting, EPA will hold a Public Hearing, 

pursuant to 40 CFR 124.12, to provide the public with further opportunity to comment on the 

proposed PSD permit amendment. At the Public Hearing, any interested person may provide 

written comments or oral comments, in English or Diné, and relevant data pertaining to the 

proposed PSD permit amendment. The date, time, and location of the Public Information 

Meeting and Public Hearing are as follows: 

Date: November 20, 2014 

Time: 5:00 PM – 6:00 PM (PUBLIC INFORMATION MEETING)

6:00 PM – 8:00 PM (PUBLIC HEARING)

Location: Aneth Chapter House 

East Highway 162, Mile Post 30 

Aneth, Utah 84510 

(435) 651-3525 

English-Diné translation services will be provided at each Public Information Meeting and 

Public Hearing. If you require a reasonable accommodation, please contact Philip Kum, EPA 

Region 9 Reasonable Accommodations Coordinator, by October 31, 2014 at (415) 947-3566, or 

kum.philip@epa.gov. 

Additional Information: All information submitted by the applicant is available as part of the 

administrative record. The proposed amended PSD permit, Ambient Air Quality Impact 

Report/Fact Sheet (AAQIR/Fact Sheet), PSD application, and other supporting information are 

available through the EPA Region 9 website at http://www.epa.gov/region09/air/permit/r9-

permits-issued.html#pubcomment. The administrative record may also be viewed in person, 

Monday through Friday (excluding federal holidays) from 9:00 AM to 4:00 PM, at the EPA 

Region 9 address above. Due to building security procedures, please call Shaheerah Kelly at 

(415) 947-4156, or through EPA Region 9’s toll-free general information line at (866) 372-9378, 
Page 3 of 4 

at least 72 hours in advance to arrange a visit. Hard copies of the administrative record can be 

mailed to individuals upon request in accordance with Freedom of Information Act requirements 

as described on the EPA Region 9 website at http://www.epa.gov/region9/foia/. 

The proposed PSD permit amendment and the accompanying AAQIR/Fact Sheet are available 

for review and inspection at the Navajo Nation Environmental Protection Agency, Fort Defiance, 

AZ, (928) 871-7692 and the following Navajo Nation chapter house locations: 

 Aneth Chapter House, Aneth, UT, (435) 651-3525 

 Red Mesa Chapter House near Montezuma Creek, UT, (928) 656-3679 

 Teec Nos Pos Chapter House, Teec Nos Pos, AZ, (928) 656-3662 

 Mexican Water Chapter House, Bluff, AZ, (928) 429-0986 

 Sweetwater Chapter House, Sweetwater, AZ, (928) 429-0977 

 Dennehotso Chapter, Dennehotso, AZ, (928) 658-3300 

The proposed PSD permit amendment and AAQIR/Fact Sheet are also available for review and 

inspection at Receptionist Desk of the following libraries: 

 Monticello Library, Monticello, UT, (435) 587-2281 

 Blanding Library, Blanding, UT, (435) 678-2335 

 Montezuma Creek Library, Montezuma Creek, UT, (435) 651-3309 

 Bluff Library, Bluff, UT, (435) 672-9996 

 La Sal Library, La Sal, UT, (435) 686-9936 

All comments that are received will be included in the public docket without change and will be 

available to the public, including any personal information provided, unless the comment 

includes Confidential Business Information (CBI) or other information whose disclosure is 

restricted by statute. Information that is considered to be CBI or otherwise protected should be 

clearly identified as such and should not be submitted through e-mail. If a commenter sends email directly to the EPA, the e-mail address will be automatically captured and included as part 

of the public comment. Please note that an e-mail or postal address must be provided with 

comments if the commenter wishes to receive direct notification of EPA’s final decision 

regarding the PSD application and proposed PSD permit amendment. 

EPA’s Final Permit Decision: Before taking final action, EPA Region 9 will consider all 

written and oral comments submitted during the public comment period, including those 

provided at the public hearing, before taking final action on the PSD permit amendment. 

EPA will send notice of the final decision to each person who provides contact information and 

who: (i) submits comments during the public comment period, including oral comments 

provided at the public hearing; or (ii) requests notice of the final permit decision. EPA will 

summarize the contents of all substantive comments and provide written responses in a 

document accompanying EPA’s final permit decision. EPA will also make a transcript of the 

Public Hearing proceedings available to the public. 
Page 4 of 4 

EPA’s final permit decision will become effective 30 days after the service of notice of the 

decision unless: 

1. A later effective date is specified in the decision; or 

2. The decision is appealed to EPA’s Environmental Appeals Board pursuant to 40 CFR 

124.19; or 

3. There are no comments requesting a change to the proposed permit decision, in which case 

the final decision shall become effective immediately upon issuance. 

For More Information: If you have questions, please contact Shaheerah Kelly at 

(415) 947-4156 or e-mail at R9airpermits@epa.gov. If you would like to be added to our 

mailing list to receive future information about this proposed permit decision or other PSD 

permit decisions issued by EPA Region 9, please Shaheerah Kelly at (415) 947-4156 or send an 

e-mail at R9airpermits@epa.gov, or visit EPA Region 9’s website at 

http://www.epa.gov/region09/air/permit/psd-public-guidelines.html. Shaheerah Kelly can also 

be reached through EPA Region 9’s toll-free general information line at (866) 372-9378. 

Please bring the foregoing notice to the attention of all persons who would be interested in this 

matter.