1 

### Kelly, Shaheerah

From: Kelly, Shaheerah Sent: Wednesday, October 15, 2014 10:16 PM To: thormel@mcvehil-monnett.com; tbbegay@na vajo-nsn.gov; rbisht@navajo-nsn.gov Cc: Kelly, Shaheerah Subject: Proposed Clean Air Act Prevention of Sign ificant Deterioration Permit for McElmo Creek Unit Oil Production Facility (NU 05-01) Attachments: EPA Transmittal Letter for MCU Proposed PS D Permit Amendment.PDF; Proposed MCU PSD Permit Amendment.pdf; Proposed MC U PSD Amendment Permit Appendix A - OM Plan.pdf; Proposed MCU PSD Permit Amendment Appendix B - RCFA.pdf; Proposed MCU PSD Permit Amendment Append ix 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. These documents have also been transmitted by e

‐ mail to Resolute Natural Resources Company. Feel free to contact me for questions.

Regards,

************************************ Shaheerah Kelly U.S. Environmental Protec tion Agency, Region 9 Permits Office, Air Division San Francisco, CA 94105 Phone: 415-947-4156 Fax: 415-947-3579 Email: kelly.shaheerah@epa.govUNITED 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 SIGNIF ICANT DETERIORATION PERMIT ISSUED PURSUANT TO THE

REQUIREMENTS AT 40 CFR § 52.21

U.S. ENVIRONMENTAL PROTEC TION 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 Ac t (CAA), Subchapter I, Part C (42 U.S.C. § 7470, et. seq. ), and the Code of Federal Regulations (C FR) 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 Producti on Facility as described herein, in accordance with the permit application (and plans submitted w ith the permit application), federal regulations governing the Prevention of Signi ficant Deterioration of air qu ality (40 CFR § 52.21), and other terms and conditions set forth in this amended PSD Permit.

Failure to comply with any condition or term se t forth in this amended PSD Permit is subject to enforcement action pursuant to Section 113 of th e Clean Air Act. This permit does not relieve Resolute from the responsibility to comply w ith 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 beco mes 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 DateMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 2 ABBREVIATIONS & ACRONYMS

Act Clean Air Act [42 U.S.C. § 7401 et seq.] Applicant Resolute Natural Resources Company BACT Best Availabl e 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 CO 2 

### Carbon Dioxide DSCFM Dry standard cubic feet per minute EPA United States Environmental Protection Agency H 2 

### S 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 Standard s for Hazardous Air Pollutants NNEPA Navajo Nation Environmental Protection Agency NO x 

### Oxides of nitrogen O 2 

### Oxygen Permittee / Owner or Operator Resolute Natural Resources Compan y, 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 SO 2 

### Sulfur Dioxide SO x 

### 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 

### 3 

## MCELMO CREEK UNIT OIL PRODUCTION FACILITY PREVENTION OF SIGNIFICAN T DETERIORATION PERMIT

PERMIT CONDITIONS

PROJECT DESCRIPTION

The McElmo Creek Unit Oil Production Facility (MCU Facility or Fa cility) is an existing oil and gas production operation located within the F our Corners Area on the Navajo Nation Indian Reservation near the city of Aneth, San Juan County, Utah. Th e Facility is owned, in partnership with the Navajo Nation Oil and Gas Company, a nd 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 f unction as testing facilitie s 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 pl ant receives produced gas through a gathering system, pressures the gas up to a suitable working pressure, and re-i njects the gas to maintain reservoir pressure in the oilfield. The natural gas is injected with pr oduced water in a dual in jection 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 lo cated 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 fo r emissions of sulfur dioxide (SO 2 

### ), nitrogen oxides (NO x 

### ), carbon monoxide (CO), and volatile organic compounds (VOC). Air pollution emissions associated with this permit amendment will not ca use or contribute to violations of any National Ambient Air Quality Standards (NAAQS) or any a pplicable 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 

### 4 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 ga s to provide heat to the Glycol Heater Glycol Heater One (1) Glycol Heater (TEG re generator), 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 Perm it shall become invalid if construction:

A. is not commenced (as defined in 40 CF R § 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, postmarke d within 30 days of such date;

B. actual date of initial startup, as defi ned 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 te st protocol; and

D. date upon which initial performance eval uation of the continuous emissionsMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 5 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 star tup, shutdown, shakedown, and malfunction, the Permittee shall, to the extent practicable, maintain and operate the Facility, including associated air po llution control equipment, in a manner consistent with good air pollution control pr actice for minimizing emissi ons. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to EPA, wh ich may include, but is not limited to, monitoring results, opacity observations, review of operating maintenance procedures, and inspecti on 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 pro cess 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 sh all 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 de scription 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 notific ation 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, cons ultants, and agents shall have authority to enter theMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 6 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 otherw ise affects any righ t 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 ow nership of the Facility, this PSD Permit shall be binding on all subsequent ow ners or operators. Within 14 days of any such change in control or ownership, the Permittee shall no tify the succeeding owner or operator of the existence of this PSD Permit and its conditions by letter. The Pe rmittee 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 severa ble, and, if any provision of the PSD Permit is held invalid, the remainder of th is 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 appli cable federal, state, and local air quality regulations. This PSD Permit does not rel ease 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 

### 7 IX. SPECIAL CONDITIONS FOR THE MAIN FLARE

A. Definitions

1. “CO 2 

### 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 su ch 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 Satu rday, Sunday, or federal holiday.

3. “Facility” shall mean the Permittee’ s McElmo Creek Unit Oil Production Facility and associated oil fields, lo cated near Aneth, Utah, on the Navajo Nation Indian Reservation.

4. “Field Flares” shall mean the followi ng 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 conti nuous or intermittent flaring at the Main Flare that results in the emissions of SO 2 

### equal to, or greater than, five-hundred (500) pounds in any twen ty-four (24) hour period; provided, however, that if five-hundred (500) pounds or more of SO 2 

### have been emitted in a twenty-four (24) hour pe riod and the flaring continues into subsequent, contiguous, non-overlapping tw enty-four (24) ho ur period(s), each period of which results in emissi ons equal to, or greater than, five hundred (500) pounds of SO 2 

### , then only one Flaring Incident shall have occurred. Subsequent, contiguous, n on-overlapping periods are measured from the initial commencement of flaring within the Flaring Incident.

6. “Main Flare” shall mean the flare instal led 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 ofMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 8 fuel gas in the Main Flare’s pilot, (2 ) the closed drain and filter backwash operations, (3) CO 2 

### 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. CO 2 

### Breakthroughs and Scheduled Maintenance of the Facility’s compressors are not Malfunctions.

9. “Root Cause” shall mean the primar y cause of a Flaring Incident as determined through a process of investig ation; provided, however, that if a Flaring Incident encompasse s multiple releases of SO 2 

### , 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 pl anned and arranged on a set frequency, usually based on periods of time (e.g., da ily, weekly or monthly) or on the operating hours of the equipment. Scheduled Maintenance shall not include work necessitated by the fail ure of a part of a compressor.

B. Air Pollution Control Equipment

1. The Main Flare shall be an auto matic 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 cau se 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.

SO 2 

### NO x 

### 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 SO 2 

### , NO x 

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

3. The Permittee shall not use the Field Flares to circumvent the emissionMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 9 limitations in Condition IX.C.1.

4. All emissions during all modes of op eration (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, pur suant 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 a ssist dilution parameter (NHV dil 

### ) shall be greater than or equal to 24.4 BTU/ft 2 

### , calculated as follows:



## ܨܦ ൌ ܳ ௩௚ 

## ൈ ܦ݅ܽ݉ ܳ ௩௚ 

## ൅ ܳ ௦ 

## ൅ ܳ ௣௥௘௠௜௫ ௔௜௥ 

## ൅ ܳ ௣௘௥௜௠௘௧௘௥	௔௜௥ 

### (Eqn 1)



## ܰܪܸ ௗ௜௟ 

## ൌ ܰܪܸ ௩௚ 

## ൈ ܨܦ ) Eqn 2)

where:

DF = Dilution factor, feet (ft). Q vg 

### = Volumetric flow rate of the flare vent gas, scfm. Q s 

### = Cumulative volumetric flow of total steam, scfm.McElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 10 Q premix air 

### = Cumulative volumetric flow of premix assist air, scfm Q perimeter air 

### = Cumulative volumetric flow of perimeter assist air, scfm. Diam = Diameter of the flar e vent gas release stack, ft. NHV vg 

### = Net heating value of flare vent gas, BTU/scf. NHV dil 

### = Net heating value air a ssist 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 Em issions Calculations

1. The Permittee shall use the following requirements to determine compliance with the emission limitati ons in Condition IX .C.1 for the Main Flare.

(a) The Permittee shall measure and record the H 2 

### S concentration in the field gas at the Facility in each ca lendar month at the inlet to the Facility’s former gas processing plan t where the Main Flare is located.

(b) The Permittee shall continuously meas ure and record the volume of gas combusted in the Main Flare.

(c) The Permittee shall install, ope rate and maintain continuous monitoring systems on the Main Flar e for the usage of pilot gas and purge gas (other than nitrogen or othe r inert gas) by the Main Flare, in standard cubic feet per minute (SCF M). 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 H 2 

### S concentration in the fiel d gas at the Facility and that day’s recorded volume of gas combusted in the Main Flare.

(e) Each and every calendar day, the Pe rmittee shall calculate the 365-day rolling total of emissions of SO 2 

### , NO x 

### , CO, and VOC for the Main Flare. Each 365-day rolling total sha ll be calculated using data from the previous 365 days. The Permitt ee shall maintain all records of actual operating data an d calculations.

(f) If the Permittee is unable to measure the volume of gas combusted inMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 11 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 previ ous 12 months’ emissions data. However, the use of this daily av erage 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 calcul ate and record the net heating value air assist dilution parameter of the fi eld 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/temperatu re monitoring system(s) and appropriate engineering calculations may be used in lieu of a continuous volumetric flow m onitoring 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 ai r assist dilution parameter of the field gas being combusted in the Ma in Flare in sixty-minute averages, rolled every five minutes.

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

### ) using 40 CFR 60.18(f)(3).McElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 12 3. The Permittee shall continuously monito r the Main Flare for the presence of a flare pilot flame using a thermoc ouple or any other eq uivalent device to detect the presence of a flame, which monitoring shall be conducted in accordance with 40 CFR 60.18(f)(2). Th e 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 sha ll 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 co mpliance of flares with the visible emission provisions. The observation pe riod is 2 hours and shall be used according to Method 22. The Permittee shall perform monthly visible emissions tests during a flar ing 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, CO 2 

### Breakthrough, Scheduled Maintenance, or unschedul ed maintenance of the Facility’s compressors, operate and maintain th e compressor station equipment and Main Flare in a manner consistent w ith 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 proc edures 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 sh all maintain inspection logs at the Facility documenting that these insp ections have been conducted.

4. The Permittee shall maintain daily r ecords 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 theMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 13 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 Pa rts List, the Permittee shall replace such equipment as expeditiously as possible. The Permittee shall place a purchase order for such equipment with in 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 establishe d 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, En forcement Division of EPA Region IX, of such Flaring Incident. Tele phone 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 CO 2 

### Breakthrough, the Permittee shall submit a report to EPA, at the address in Condition X.C of this PSD Permit, no la ter than sixty (60) days following the end of such a Flaring Incident that sets forth the following information listed below. Except for those Flar ing Incidents caused by Scheduled Maintenance or a CO 2 

### 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 inMcElmo Creek Unit Oil Production Facility Proposed Amended PSD Permit No. NU 05-01 October 2014 

### 14 Condition X.C of this PSD Permit, no la ter 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 In cident started and ended. To the extent that the Flaring Incident invo lved multiple releases either within a twenty-four (24) hour period or within subsequent, contiguous, nonoverlapping twenty-four (24) hour pe riods, the Permittee shall set forth the starting and ending dates and times of each release;

(b) An estimate of the quantity of SO 2 

### that was emitted and the calculations that were used to determine that quantity;

(c) The steps, if any, that the Permitt ee took to limit the duration and/or quantity of SO 2 

### emissions associated with the Flaring Incident;

(d) Except for those Flaring Incidents caused by Scheduled Maintenance or a CO 2 

### Breakthrough, a detailed analysis that sets forth the Root Cause and all contributing causes of th at Flaring Incident, to the extent determinable; however, if a Flaring Incident is caused by Scheduled Maintenance or CO 2 

### Breakthrough, then the Permittee need only identify the Root Cause as Scheduled Maintenance or CO 2 

### Breakthrough (whichever is applicab le), and either (i) describe the nature of the work done for Scheduled Maintenance or (ii) identify the specific wells that most likely experienced the CO 2 

### Breakthrough;

(e) An analysis of the measures, in cluding possible design, operational, and maintenance changes, that are available to reduc e 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) requi red under Section IX .H (Corrective Action) of this PSD Permit, the report shall include a description of the action(s) and, if not already comp leted, a schedule for its (their) implementation, including proposed commencement and completion dates. If the Permittee concludes th at corrective action is not required under Section IX.H (Corr ective Action) of this PSD Permit, the report shall explain the basis for that conclusion;

(f) To the extent that investigati ons 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 PermitMcElmo 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, notificatio n, reporting, and correc tive 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 recurr ence of the Root Cause and all contributing causes of th at 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 si gned and affirmed by a responsible official, and bearing the certi fication 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 ga thered 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 th e information is true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possib ility 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 incl ude the following information:

(a) A list of the rolling 365-day cumulativ e Main Flare emissions for each day in that semiannual period;

(b) A list of each day in the semiannua l 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 CO 2 

### 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 associ ated 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 H 2 

### S 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 perf ormed all of the obligations (including, but not limited to, in spection 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 correctiveMcElmo 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 opera tion 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 appli cable records shall be maintained at the nearest manned facility and shall be readily accessible.

(a) Each 365-day rolling total for SO 2 

### , NO x 

### , CO, and VOC emissions;

(b) Emissions calculations of SO 2 

### , NO x 

### , CO, and VOC for the Main Flare, which shall include the emission f actors, operating data and other supporting documentation that th e Permittee used to calculate emissions of each pollutant;

(c) Monthly H 2 

### S 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 anal yses 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 Se ction 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 in spection: (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 co ntent determinations, flowrateMcElmo 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) f unctioned properly, i.e., a flame was present and any visible emi ssions 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 ta ken 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 perm it 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 Divi sion (Attn: AIR-3) U. S. Environmental Protection Agency Region 9 75 Hawthorne Street San Francisco, CA 94105McElmo 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 corresponden ce required by this PSD Permit to:

Navajo Nation Environmental Protection Agency Air Quality Control Program a nd Operating Permits Program P.O. Box 529 Fort Defiance, AZ 86504

C. Compliance Reporting.

Unless otherwise directed by the EPA or th is PSD Permit, the owner or operator shall submit a copy of all test plans, repor ts, certifications, not ifications, and other information pertaining to compliance w ith this PSD Permit to the following address. All notices and submissions sha ll be sent by certified mail, express mail, or similar overnight mail delivery with re turn receipt requested and addressed to:

Director, Enforcement Di vision (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 certi fication 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 prepar ed either by me personally or under my direction or supervision in a manner de signed to ensure that qualified and knowledgeable personnel properly gather ed and presented the information contained therein. I furt her certify, based on my pe rsonal knowledge or on my inquiry of those individuals immedi ately responsible for obtaining the information, that the information is true, accurate, and complete. I am aware that there are significant penalties for su bmitting false information, including the possibility of fines and imprisonment for knowing and willful submission of a materially false statement.”

# A PPENDIX A



# MCELMO CREEK UNIT OPERATIONS & MAINTENANCE PLAN

McElmo Creek Unit Oil Production Facility PSD Permit Number: N U 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 of the 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 if this 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 of the 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 1 OPERATIONS 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) VIBRATIONL1-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 LEVELMAINTENANCE 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 VIBRATIONL1-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 LEVELU)zU)20HUIa0U)20HLUci0U)20H4UIa0U)20HUIa0 t0U)20Hwa0U)20HUIa0U)20HUIa0UiILU) z0HUIa0U)z0H4Liia0U)D0I@4r(I)20H4wa0U)D03D(NU)20HUIa0Cl)z0HUIa0Cd)D03:@4U) zU)2U)D03:@4U)2U)D03:(NU)2C’)D0I@4pU)ctD0r@4U)D03:@4UIDU)U)UIftCaOHU)D0:3:eqwDC,,U)UIaU)D0IeqoaUI1wOHU)0I@4On1wOHUIDU)C’)UIaU)D0I@4OnUJ1wOHU)D0I@4wOaU)wwrwrOHaU)D0I@4UIsco8oaU)UIUIIUIOHaU)D0I(‘4UIDCd)U)UIccaU)D0I(NoaUJ1wOHUIItst:QooacnW2WIwItOHaU)ItD0IeqUIDCDU)U)UIIta0UII0aUIUIUiItItXLiiDDDrU)U)JU)S11UIOCOOUIOCOOWOCOOOwow>www>www>UIwwUI>W>wIItIwIItIwIItIIwIwoaooaoion-oO..JO.Jz0 IUiC-)-J-IUi0 a I0Co20C-)z0F0DU)HU)UI(9It4IC—)U)HU)CzUIIIIt02-JLii>UI-JItUI>2HUI40-,U)20H0DU)C2(NU)4(9C04C244U)4(9C04UI(9It4I0U)CC2@4-J0ccH20C-)LiU0UIa::0U)U)wIta-J0a0020H00(-I)CItC,,UI(9It4I0U)CCccC,,2aUI024zUII24UIcc0U)U)UIItaItUIH4Hw0420HC)0U)3DHIt0LIUIIt0U)U)wIta-J0UI—-JUI(9It4I0U)CIH2-JUi-J0-J3:2024UItUI-J00C-)ccUIHLL42000-JUI>UI-J-J0UIm0-J:4.U)ItUI0It0U)UI(34HU)C2(NHU)-JUI>UI-J-J0UIU)ccUI0It0U)UI(34HU)IHCItC,, F;-JeqC,,F-JUI24aF-JtoI-:-JCi,F-jF—F-J

F;-JC) F;-J0F-J

F;-J(N F;-JC,,F;-JU, F;-JCD F;-JF—F;-J

### NOTE LEVELS 2 THROUGH 6 ARE THE SAME FORALL COMPRESSORS

LEVEL 2tIrsaVicIMEBASED TESTING (**R- 

## 1n TASK $TASKDESCRIPTION .ACTIVITY 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 INSPECTIONLEVEL 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 SERVICELEVEL 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,

YES TERDA I’S TODAY’S TOTAL RUNTJME RUNTIME P-9201 RUN TIME P-9201 P-9201

YESTERDAY’S TODAY’S TOTAL RUN TIME 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&BExxonMobil Production Isolation Procedure

- File Name I-IOS6ISO Aneth Operations HOS$ COMPRESSOR Authorized McElmo Creek Unit ISOLATION PROCEDURE Page 1 of 4 Gas Reinjecuon Facility 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. Isolation Procedure ExxonMobii Production

I File Name HDS6ISO Aneth Operations HOS-6 COMPRESSOR Authorized MeElmo Creek Umt ISOLATION PROCEDURE Pane 2 of 4 Gas Reinjecuon Facilit 3

’ 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 Isolation Procedure ExxonMobil Production 

## 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 HOS-6 COMPRESSOR Authorized McElmo 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 serviceExxomMobi( Production 

## [ Operating Procedure File Name HOSCCOMP 

### i Aneth Operations HOS-6 COMPRESSOR Authorized

-

McEImo 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 okayEnsure 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 9 on 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 File Name HOS6cO 1
McEhno Creek Umt 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

2.2ExxonMobil Production Operatmg Proceduie File Name HOS6COMP Aneth Operations HOS-6 COMPRESSOR Authorized McElmo Creek Umt OPERATING PROCEDURE Page 4 of 10 Gas Reinjection 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 temperaturesExxonMobil Production Operating Procedure File Name FIOS6CDMP Aneth Operanons l-Ios-6 COMPRESSOR Authorized McElmo Creek Umt OPERATING PROCEDURE Page 5 of 10 Gas Renijection 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 dutiesExxonMobil 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. 

# IExxonMobil 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 BOS-6 COMPRESSOR Authorized McElmo 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 1 st 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 3 rd 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

2 0d Stage Discharge Pressure 370 to 380 psig

3(0 Stage Suction Pressure 350 to 380 psig

3 1d Stage Discharge Pressure 1000 to 1050 psig

4fl Stage Suction Pressure 1000 to 1040 psig

4 tfl 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/sExxonMobif 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 M mode, 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

Gas Reinjection Facility ________________________________________________

Page 2 of 3

I Equipment. 4 CM-3400ExxonMobil 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 serviceExxonMobil 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 annunciator2.2 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 

# I

Gas Reinjecrion Facility _____________________________________________

Page 4 of 11 I Equipment. 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 

# 1

Aneth Operations File Name HOS4COMP

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 operationExxomMobil 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 alarmExxonMobil Production Operating Procedure

- 

# I

File ?same HOS4COMP t Aneth Operanons 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 lubricatorAneth 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 psigExxomMobil Production Aneth Operations McElmo Creek Unit Gas Reinjecrion Facility Operatin2 Procedure

HOS-4 COMPRESSOR

Equipment. m CM-3400 Aui Page 11 of 11ExxonMobil 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 File Name AGISO Aneth Operations McElmo Creek Unit ACID GAS COMPRESSOR ISOLATION Authonzed Page 2 of 3 Gas Remjeccion facility 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 1 s for 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 File Name AGCOMP Aneth Oceranons McElmo Creek Unit ACID GAS COMPRESSORS “A” and ,,‘, Authonzed Page 1 of9 Gas Remjecnon 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 onExxonMobil 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 operationExxonMobil 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 atExxonMobil 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 psigExxonMobjl 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.



### If high manifold temperature continues 

### and you have taken all corrective steps, call 

### Mechanic.

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 2 5 Z 

### 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 

# El Low Coolant Level 1. Check coolant level. 

### 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 if they are Malfunction loose or damaged. Caution: To prevent injury, use lock-out/tag-out procedure 

### if you 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 A NALYSIS 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 McE l mo 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 CO 2 breakthrough

.
Step 2

– P lan 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 que stions 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

– Collec t 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 inci dent 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 i s 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 fact s 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 fa cilitate 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 aski ng, "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 t he 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 ide ntified, 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 c orrective 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 re liability 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 i s, 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 rea ch 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 cor rective 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 CompletionMcElmo 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 m ake 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 indefini tely.

An important part of incident reporting communication is the Snap Chart. A Snap Chart can be particularly helpful in providing an o rganized 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 t he 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® 

# r: 1 ___



# ceO _



### •IIII



# EziL:• 

# t’ I



# E 

# JJczI

E E C r.

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 CLEA N AIR ACT PREVENTION OF SIGN IFICANT DETERIORATIO N PERMIT AMENDMENT

RESOLUTE NATURAL RE SOURCES COMPANY MCELMO CREEK UNIT OIL PRODUCTION FACILITY PSD Permit NU 05-01

Ambient Air Quality Impact Report & Fact Sheet

Table of Contents

A CRONYMS 

### A CRONYMS 

### & A BBREVIATIONS


### ................................................................................. IV



### E XECUTIVE 

### S UMMARY 

### ................................................................................................................... 1

1. P URPOSE OF THIS 

### D OCUMENT 

### ................................................................................................. 2

2. A PPLICANT


### .............................................................................................................................. . 2

3. F ACILITY 

### L OCATION 

### ................................................................................................................ 2

4. P ROJECT 

### D ESCRIPTION 

### ............................................................................................................ 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. P ROJECT 

### E MISSIONS 

### .............................................................................................................. 10

6. A PPLICABILITY OF THE 

### P REVENTION OF 

### S IGNIFICANT 

### D ETERIORATION 

### R EGULATIONS 

### 1111

7. B EST 

### A VAILABLE 

### C ONTROL 

### T ECHNOLOGY 

### A NALYSIS


### .................................................... 1212 7.1 BACT for Sulfur Dioxides ...................................................................................... 1313 7.1.1 Step 1 - Identify All C ontrol Technologies for SO 2



### ............................... 1313 7.1.2 Step 2 - Eliminate Technicall y Infeasible Options for SO 2



### ................... 1414 7.1.3 Step 3 - Rank Control Technologies ..................................................... 1515 7.1.4 Step 4 – Economic, Energy and Environmental Impacts for SO 2



### ......... 1616 7.1.5 Step 5 – Select BACT for SO 2



### ............................................................... 1616 7.2 BACT for Carbon Monoxide .................................................................................. 1818 7.2.1 Step 1 - Identify All Cont rol Technologies for CO ............................... 1818 7.2.2 Step 2 - Eliminate Technically Infeasible Options for CO ................... 1818 7.2.3 Step 3 - Rank Control Technologies for CO ......................................... 1818

### ii 7.2.4 Step 4 – Economic, Energy and Environmental Impacts for CO ......... 2020 7.2.5 Step 5 – Select BACT for CO ................................................................ 2020 7.3 BACT for Nitrogen Oxides ..................................................................................... 2121 7.3.1 Step 1 - Identify All C ontrol Technologies for NO X



### .............................. 2121 7.3.2 Step 2 - Eliminate Technically Infeasible Options for NO X



### .................. 2222 7.3.3 Step 3 - Rank Control Technologies for NO X



### ....................................... 2323 7.3.4 Step 4 – Economic, Energy and Environmental Impacts for NO X



### ........ 2525 7.3.5 Step 5 – Select BACT for NO X



### .............................................................. 2525 7.4 BACT for Volatile Organic Compounds ................................................................ 2626 7.4.1 Step 1 - Identify All Cont rol Technologies for VOC ............................. 2626 7.4.2 Step 2 - Eliminate Technically Infeasible Options for VOC ................. 2626 7.4.3 Step 3 - Rank Control Technologies ..................................................... 2929 7.4.4 Step 4 –Economic, Energy and Environmental Impacts for VOC ........ 3232 7.4.5 Step 5 – Select BACT for VOC .............................................................. 3333

8. A IR 

### Q UALITY 

### I MPACTS 

### A NALYSIS


### ..................................................................................... 3434 8.1 Introduction ............................................................................................................. 3434 8.1.1 Overview of PSD Air Impact Requirements .......................................... 3434 8.1.2 Identification of MCU Facility Ma in Flare Modeling Documentation 3535 8.2 Background Ambient Air Quality ........................................................................... 3535 8.3 Modeling Methodology for Class II areas .............................................................. 3636 8.3.1 Model selection ..................................................................................... 3636 8.3.2 Meteorology model inputs..................................................................... 3737 8.3.3 Land characteristics model inputs ........................................................ 3737 8.3.4 Model receptors .................................................................................... 3838 8.3.5 Stack parameter model inputs ............................................................... 3838 8.3.6 Good Engineering Practice (GEP) Analysis ........................................ 3939 8.4 National Ambient Air Quality Standard s (NAAQS) and PSD Class II Increment Consumption Analysis ............................................................................................ 4040 8.4.1 Pollutants with Significant Emissions ................................................... 4040 8.4.2 Preliminary Analysis: Project-Only Impacts ........................................ 4040 8.4.3 Cumulative Impact Analysis ................................................................. 4141 8.5 Class I Area Analysis .............................................................................................. 4343 8.5.1 Air Quality Related Values ................................................................... 4343 8.5.2 Class I Increment Consumption Analysis ............................................. 4444

9. A DDITIONAL 

### I MPACT 

### A NALYSIS


### ........................................................................................ 4545 9.1 Soils and Vegetation ............................................................................................... 4545 9.2 Visibility Impairment .............................................................................................. 4747 9.3 Growth .................................................................................................................... 4848

10. E NDANGERED 

### S PECIES 

### A CT


### ............................................................................................... 4949

11. N ATIONAL 

### H ISTORIC 

### P RESERVATION 

### A CT


### ....................................................................... 4949

### iii 12. M AGNUSON



### - STEVENS 

### F ISHERY 

### C ONSERVATION AND 

### M ANAGEMENT ACT


### ...................... 5050

13. C OASTAL 

### Z ONE 

### M ANAGEMENT ACT


### ................................................................................. 5050

14. E NVIRONMENTAL 

### J USTICE 

### A NALYSIS


### ............................................................................... 5050

15. C LEAN 

### A IR 

### A CT 

### T ITLE 

### V O PERATING 

### P ERMIT


### ................................................................ 5151

16. P UBLIC 

### P ARTICIPATION


### ..................................................................................................... 5151 16.1 Public Comments .................................................................................................... 5151 16.2 Public Information Meeting & Public Hearing ....................................................... 5151 16.3 Availability of Permit Documents .......................................................................... 5252 16.4 Final Permit Decision ............................................................................................. 5353 16.5 Contact Information ................................................................................................ 5454

17. C ONCLUSION AND 

### P ROPOSED 

### A CTION


### .............................................................................. 5454

### iv 

### ACRONYMS & AB BREVIATIONS

AAQIR Ambient Air Quality Imp act Report and Fact Sheet Act Clean Air Act [42 U.S.C. Section 7401 et seq.] Applicant Resolute Natural Resources Company b ext 

### Light extinction coefficient BA Biological Assessment BACT Best Availabl e 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 CO 2 

### Carbon Dioxide Consent Decree United States v. Mobil Explor ation 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 Un it 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/m 3 

### microgram per cubic meter MMBTU million British thermal units

### v MSFCMA Magnuson-Stevens Fishery C onservation and Management Act MW Megawatts of electrical power NAAQS National Ambient Air Quality Standards NESHAP National Emission Standard s 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 NO 2 

### Nitrogen Dioxide NO x 

### Nitrogen Oxides or Oxid es of Nitrogen (NO + NO 2 

### ) NP National Park NPS National Park Service NSPS New Source Performance Standards, 40 CFR Part 60 NSR New Source Review O 2 

### Oxygen Permittee Resolute Natural Resources Compan y; or the owner and/or operator of the McElmo Creek Unit Oil Production Facility PM Total Particulate Matter PM 2.5 

### Particulate Matter less than 2.5 micrometers ( μ m) in diameter PM 10 

### Particulate Matter less than 10 micrometers ( μ m) 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 SO 2 

### Sulfur Dioxide SO x 

### Sulfur Oxides tpy tons per year USFS United States Forest Service VOC Volatile Organic Compounds WA Wilderness AreaMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 1 

## Proposed Prevention of Significa nt 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 Ag ency (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 incorporat e pollution limits, terms, and conditions of a federal Consent Decree that applie s to the Main Flare at the Facility. The MCU Facility is an existing oil and gas production op eration located within the Four Corners Area on the Navajo Nation Indian Reservation near th e city of Aneth, San Juan County, Utah. The Facility is on the McElmo Creek Unit oilfie ld, which includes fiel d operations and a gas compression plant. It is owned and operate d 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 th e PSD program for the following reasons:

 The proposed amended PSD permit requires the Best Available Cont rol Technology (BACT) to limit emissions of volatile organi c compounds (VOC), nitrogen oxides (NO x 

### ), sulfur dioxide (SO 2 

### ), and carbon monoxide (CO).

 The proposed emission limits will protect th e National Ambient Air Quality Standards (NAAQS) for ozone, nitrogen dioxide (NO 2 

### ), SO 2 

### , 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 cont ribute to violations of any applicable PSD increments for the pollutants regulated under th e 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;McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 2 

### 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 le gal 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 al so 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, Town ship 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 locat ion of the Facility.

Figure 3-1: Location of McElmo Creek Unit Oil Production FacilityMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 3 

### The Four Corners Interstate Air Quality Control Re gion is currently designated as attainment or unclassifiable for all criteria po llutants: nitrogen dioxide (NO 2 

### ), sulfur dioxide (SO 2 

### ), carbon monoxide (CO), particulate matter less than 10 microns in aerodynamic diameter (PM 10 

### ), fine particulate matter less than 2.5 microns (PM 2.5 

### ), lead, and ozone (regula ted as volatile organic compounds (VOC) and oxides of nitrogen (NO x 

### ), 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 Rese rvation because Navajo Nation Environmental Protection Agency (NNEPA) currently does not have a delegated or federally-approved PSD permitting program.



### 4. PROJECT DESCRIPTION

4.1 F ACILITY 

### H ISTORY


### 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 natu ral gas processing plant at th e Facility, which included dehydrator, amine treater, refriger ation separation unit, a natural gas liquids recovery unit and compressors to transport the produced liquid natura l gas. Mobil installed an upright flare (Main Flare) as part of the emergenc y relief system for the gas proce ssing 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 st orage tanks and heater treaters we re 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 c ontinued to operate the Main Flar e at the gas processing plant.

In 

### 1997, following a fire, most all processing equipm ent was removed. The Main Flare was kept for emergency flaring, flaring clos ed drain system fumes, and c ontrol of dehydrator emissions. The former gas processing plant is now refe rred to as the gas compression plant. The compressors were later convert ed to run on electricity.

In 

### 1997 and 1999, EPA issued Notice of Violations fo r, among other things, permitting violations relating to the Main Flare. The Facility is curr ently 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 Faci lity 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 4 

### 4.2 F ACILITY 

### O PERATIONS



### The MCU Facility 

### is on McElmo Creek Unit oilfield, wh ich 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 r ecovered from producing strata, brought to the surface to be stored at either a satellite or a ta nk battery. There are eleven satellites that function as testing facilities for producing wells and four tank batteries.

Crude oil is recovered using wate r alternating gas (WAG) injection, which is a tertiary recovery method. WAG injection is where water is inje cted into the producing strata, followed by carbon dioxide (CO 2 

### ) gas, and again by water to enhance cr ude oil recovery to the surface. CO 2 

### 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 wa ter is re-injected back into the produc ing strata via the water injection station. Separated gas is sent to the gas compression plant at the MCU Facility and processed as descri bed in Section 4.2.2 below. Cr ude oil is sold at the lease automatic custody transfer (LACT) unit at each cen tral tank battery and transported to Western Refining’s Ciniza Refinery in Gallup, New Mexico, via the R unning 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 (CO 2 

### ), 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 pumpe d 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 natura l gas is injected with produced water into the producing strata using a dual inj ection system. Due to varying water injection demands in the field, and to the number of wells being serviced at any time, the gas vo lume entering the plant can vary between 10 and 18 million standard cubic feet per day (MSCFD).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 5 

### The gas is processed in three main steps: in let 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 incomi ng solids. During the compression stage, 4 highspeed electrically-driven reci procating compressors, which utilize 6300 brake horsepower (BHP), are used to compress the gas. Each comp ressor 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 comp ressor, inter stage dehydration takes place to remove water for corrosion mitigation. During re-i njection, the gases from the four compressors discharge into a single header, where purchased CO 2 

### is co-mingled to achieve a daily injection goal of 24 MSCFD. The gas is then distributed to the field. During plant upsets, additional CO 2 

### is purchased to meet the daily injection goal.

The Main Flare at the gas compression plant co mbusts gases that have been bypassed around the facility’s electric-driven compre ssors or that come through various emergency relief valves in the compression plant. Additionally, th e vent stream from the plant’s glycol dehydrator is directed to the Main Flare.

A flow diagram of the Facility’s gathering sy stem operations is presented in Figure 4-1, illustrating the flow through the sa tellite facilities, central tank batteries, water flood injection plant, and gas compression plant. Figure 4-1 pres ents a simple block flow diagram for the gas compression plant, including the stre ams directed to the Main Flare.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 6 

### Figure 4-1: McElmo Creek Unit Oil Production Facility Operations

Source: April 2008 PSD Application, Figure 2-2



### 4.3 PSD P ERMIT 

### H ISTORY


### The PSD permit history associated with the MCU Facility is as follows. 3



### February 2, 1987 – EPA issued the initial PSD pe rmit to Mobil for the modification of the MCU Facility for the MCU Stage 2 CO 2 

### Project. The permit authorized the construction and operation of three 1730 horsepower (HP) recipro cating 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 is sued 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 reservati on, this authority was transferred to EPA Region 9. The Navajo Nation Indian Reservation covers portions of northeastern Arizona, southeastern Utah, and northwestern New Mexico.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 7 

### 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 hei ght 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 hea ting equipment at the Facility with a waste heat reco very unit; (2) temporarily replace the existing gas turbine with an identical unit during maintenance overhaul of th e turbine, (3) change th e rating of the existing gas turbine one gas turbine wh ich was installed from 3216 HP to 4390 HP and add requirements for the New Source Performance Standard for Ga s 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 tu rbines at the gas compression plan t 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 CO 2 

### line heater, which was used during severe cold weather, was removed from th e MCU Facility in March 2004.

4.4 PSD P ERMIT 

### C HANGES


### 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 eff ective on June 8, 2005. Paragraph 14.a of the Consent Decree requires th e owner and operator of the MCU Faci lity to submit, to EPA, a PSD permit application in accordance with the C AA and the PSD regulations at 40 CFR § 52.21 for the MCU Facility’s Main Flare no t later than the 180 days after th e effective date of the Consent Decree. The Consent Decree re quires that the PSD application include, among other things, BACT and air quality analyses for SO 2 

### , CO, NO x 

### , and VOC for the Main Flare. It also requires that the PSD application include terms and condi tions that are at leas t as stringent as the following Consent Decree requirements. 5



###  Paragraph 9.a (Emission Limits)

 Paragraph 10 (Monitoring)

 Paragraph 11 (Operation and Maintena nce 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 8 

### Mobil submitted a PSD application dated Dece mber 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 supplem ental information thereafter.

This permit action also consists of updating the equipment cove red 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 Tabl e 4-2 shows other operations at the Facility that are not explicitly listed in the perm it. 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 Permit 6 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 9 Table 4-2: Other Equipment and Operations at the MCU Facility 7 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 CO 2 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 em ission units remaining at the site: Main Flare, gasoline tank, triethylene glycol (TEG) dehydration unit reboiler, a nd 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 au thorize any new construc tion 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 10 

### 5. PROJECT EMISSIONS

This section describes the emission levels of SO 2 

### , CO, NO x 

### , and VOC from the Main Flare, and the emission requirements in the Consent Decree.

Table 5-1 shows the actual emissions for the F acility, and Table 5-2 shows the greenhouse gas emission estimates. Table 5-1: Actual Emissions (2011) for MCU Facility Operation Size / Throughput SO 2 (tpy) NO x (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 regardi ng additional information, dated December 4, 2012

Table 5-2: CO 2 e Emission Estimates for MCU Facility Operation Emissions (Metric Tons CO 2 e) 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 regard ing additional information, dated April 18, 2012


### Paragraphs 14.a and 9.a of the C onsent Decree requires that BACT fo r 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 SO 2 NO x CO VOC 60 tpy 13.4 tpy 73 tpy 95.4 tpy Source: Consent Decree, Paragraph 9.aMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 11 

### 6. APPLICABILITY OF THE PREV ENTION 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/unclassifie d areas”, which are areas that meet the National Ambient Air Quality Standards (NAAQS) or where th e 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

SO 2 Attainment or Unclassifiable
CO Attainment or Unclassifiable Nitrogen Dioxide (NO 2 ) Attainment or Unclassifiable
Ozone 8 Attainment or Unclassifiable Particulate Matter (PM 2.5 ) 9 Attainment or Unclassifiable Particulate Matter (PM 10 ) 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: SO 2 

### , CO, NO x 

### , and VOC. EPA issued a PSD permit to the MCU Facility on February 2, 1987, and the permit was last am ended on April 19, 1991. EPA received a PSD application for the Main Flare in 2005 from Mobil, and has recei ved revised applications in 2007 and 2008 and other supplemental information for th e PSD application from Mobil and Resolute.

8 Troposheric, or ground level ozone, is no t emitted directly into the air, but is created by chemical reactions between NOx and VOC. Thus, both NO x and VOC precursors in the formation of ozone and are regulated under the CAA.
9 Fine particulate matter, or PM 2.5 , is particulate matter with diameters that are 2.5 mi crometers and smaller. Some PM 2.5 is emitted directly from a stationary source, such as construction sites, unpaved roads, fields, or smokestacks. SO 2 and NO x are precursors in the formation of PM 2.5 since these pollutants form in complicated reactions in the atmosphere after being emitted from smokestacks.
10 Coarse particulate matter, or PM 10 , includes “inhalable coarse particles, ” with diameters larger than 2.5 micrometers and smaller than 10 micrometers.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 12 

### 7. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS

This section describes EPA’s BACT analysis for the control of SO 2 

### , CO, NO x 

### 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 und er 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 en ergy, environmental, and economic impacts and other costs, determines is achievable through ap plication of production pr ocesses and available methods, systems, and technique s, including fuel cleaning or treatment or innovative fuel combustion techniques for control of each such po llutant. In no event sha ll application of ‘best available control technology’ result in emissi ons of any pollutants which will exceed the emissions allowed by any applicable standard es tablished 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 re gulated 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 Environm ental Appeals Board (EAB) has consistently followed in adjudicating PSD permit appeals. Se e, 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 pr ocess, all available control tech nologies 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 te chnical 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 st ringent 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 exerci se for the particular source under evaluation. In summary, the five steps involved in a t op-down BACT evaluation are:

1. Identify all available control options with practical potential for application to the specific emission unit for the regul ated pollutant under evaluation;

2. Eliminate technically inf easible technol ogy options;

3. Rank remaining control technologie s by control effectiveness;

4. Evaluate the most effective control alte rnative and document re sults, considering energy, environmental, and economic impact s as appropriate; if top option is notMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 13 

### 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 SO 2 

### , CO, NO x 

### , and VOC emissions. EPA evaluated the information that Resolute and Mobil submitted. The analys es and our evaluation for each pollutant are presented below.

Table 7-1: Summary of BACT Limits and Requirements for the Main Flare 11 SO 2 CO NO x VOC

 60.0 tpy, based on a

cumulative 365-day rolling total

 Monitor sulfur content

(in terms of H 2 S) of the gas stream to the flare for calculating SO 2 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/scf 2

 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 

### S ULFUR 

### D IOXIDES



### SO 2 

### emissions are formed as a result of the co mbustion of gasses containing reduced sulfur compounds. Typically, sulfur dioxide from comb ustion processes can be controlled by limiting the sulfur content in the fuel or by end-of-pipe cont rol technology.

7.1.1 Step 1 - Identify All Control Technologies for SO 2



### The available add-on control technologies for reducing SO 2 

### 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 re port excess emissions to EPA semi-annually, except when: more frequent reporting is specifically required by an app licable subpart; or the Admini strator, on a case-by-case basis, determines that more frequent reporting is necessary to accurately assess the complian ce status of the source.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 14 

###  Spray dryer (e.g., slu rry 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 c ontrol options for reducing SO 2 

### emissions are as follows.

 Limiting the fuel type

 Limiting the sulfur content

Other control options for reducing SO 2 

### emissions are as follows.

 Natural gas combustion in flare

 Proper operation and maintenance

7.1.2 Step 2 - Eliminate Technically Infeasible Options for SO 2


### Add-On Control Technologies The add-on control technol ogy options are not techni cally feasible for flare systems, due to the inherent design of flaring and the fact that l iterally, no end-of-pipe exis ts after the combustion zone. Additionally, we found no known demonstrat ions 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 no r applicable to them, all of the add-on control technology options listed above ar e eliminated as technically in feasible for the Main Flare.

Pre-Treatment Control Options Limiting the fuel type is not technically feasib le because the gasses can not be switched with other process or vent streams without cha nging the inherent purpos e and design of the compressor plant. Likewise, limiting the sulfur content or flue gas desulfurization is not technically feasible because th ey 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) re gulations at 40 CFR part 60 define natural gas as the following: “a naturally oc curring 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 temperat ure 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 we ight 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 l east 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 furn ace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might resu lt in highly variable sulfurMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 15 

### 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 CO 2 

### and 0.05 percent H 2 

### S, and does not include natural gas as defined above. Thus, requiring combustion of natural gas in the Main Flare to control SO 2 

### emissions is not technically feasible.

Proper operation and maintenance is typically sp ecific to a facility and could entail work practices to ensure that the flare is being main tained and operated properly. For the Main Flare, proper operation and maintenance include (1) follo wing 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 ma intenance, root cause, and corrective action requirements of the Consent Decr ee. 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 c ontrol option. Table 7-1 shows a summary of recent SO 2 

### 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 prope r operation and maintenance. As described in Step 2, natural and refinery gases are part of th e 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 flar e gas stream are converted to SO 2 

### when burned. The amount of SO 2 

### emitted depends directly on the quantity of sulfur in the flared gases. The SO 2 

### BACT emission levels in Table 7-1 vary for each f acility listed. This indicates that the sulfur content also varies for each of these facilities and that the SO 2 

### BACT emission levels are facilityspecific. Thus, the SO 2 

### BACT emission level for the MCU Faci lity’s Main Flare will be based on the expected sulfur cont ent in it flare gas stream.

The SO 2 

### emission rate specified in the Consent D ecree is 60 tpy based on a cumulative 365-day rolling total. The sulfur cont ent of the dehydrated produced gas that is burned in the MCU’s Main Flare is approximately 0.05 percent H 2 

### S, but may also result in highly variable sulfur content or heating value.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 16 Table 7-1: SO 2 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 c ontrol 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 SO 2


### 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 SO 2


### Based on the above analysis, BACT for SO 2 

### emissions from the Main Flare are the following requirements.

 SO 2 

### emissions not to exceed an emission lim it of 60 tpy based on a cumulative 365-day rolling total.

 Proper operation and maintenance which include: (1) following the manufacturer’s spec ifications for the flare;McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 17 

### (2) operating and maintaining the flare in acco rdance with the flare requirements in 40 CFR § 60.18; (3) following the operations and maintenance, root cause, and corrective action requirements (incorporated from the Cons ent Decree into the PSD permit); and (4) monitoring of the sulfur content (in terms of H 2 

### S) of the gas stream to the flare for calculating SO 2 

### emissions.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 18 

### 7.2 BACT FOR 

### C ARBON 

### M ONOXIDE


### Flaring is a high-temperature ox idation process used to burn combustible components, mostly hydrocarbons (i.e., VOC), of waste gases from indus trial operations. In so me waste gas streams sent to a flare, CO is the major combustible co mponent. 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 contro l option for the Main Fl are, is technically feasible. Proper operation and maintenan ce include (1) followi ng the manufacturer’s specifications for the flare, (2) operating and main taining the flare in accordance with the flare requirements in 40 CFR § 60.18, and (3) following th e operations and maintenance, root cause, and corrective action requirement s of the Consent Decree.

7.2.3 Step 3 - Rank Control Technologies for CO

Proper operation and maintenance is the only contro l option for the Main Fl are. Table 7-2 shows a summary of recent CO BACT determinati ons for flares at ot her facilities.

These control determinations in clude proper operation and mainte nance, 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 main taining 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 sp ecifications 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 fact or of 0.37 lb/MMBtu. This level is within the range of BACT determinati ons listed in Table 7-2.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 19 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: RBLCMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 20 

### 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 emis sions 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 specificatio ns for the flare to ensure complete combustion in the flare; (2) operating and maintaining the flare in acco rdance 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 C onsent Decree into the PSD permit).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 21 

### 7.3 BACT FOR 

### N ITROGEN 

### O XIDES



### NO x 

### is formed as a result of the combustion of hydrocarbons (which are entr ained in the vent gas streams) at the flare (through igni tion with natural gas at the fl are pilot) in the presence of ambient air. There are three principal forms of NO x 

### , designated as “thermal” NO x 

### , “prompt NO x 

### ,” and “fuel” NO x 

### . Thermal NO x 

### 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 NO x 

### formation are temperatur e, concentrations of nitrogen and oxygen in the inlet air, and reside nce time within the combustion zone. Prompt NO x 

### is formed through relatively fast re action between nitrogen, oxygen, and hydrocarbon radicals and is an important mechanism in lo wer temperature combustion processes. Fuel NO x 

### 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 NO x 

### is a concern when burning oil, coal, or waste fuels. NO x 

### emissions from the flare can be best reduced by minimizing the freq uency and amount of vent gases flared and by promoting optimal conditions upon combustion.

7.3.1 Step 1 - Identify All Control Technologies for NO X


### Generally, several options exist to reduce NO x 

### emissions from combustion processes, such as pre-treating the fuel or switching fu els and/or oxidizers to prevent NO x 

### formation, modifying the combustion process or equipment to lower NO x 

### formation, and add-on control technologies to remove NO x 

### . 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 NO x 

### burners (LNB)

The following pre-treatment control options for NO x 

### emissions are listed as follows.

 Fuel Switching

 Fuel Additives

 Oxidizer Switching

Other control options for NO x 

### emissions are listed as follows.

 Proper operation and maintenanceMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 22 

### 7.3.2 Step 2 - Eliminate Technically Infeasible Options for NO X


### Add-On Control Technologies The add-on control technol ogy options are not techni cally feasible for flare systems, due to the inherent design of flaring and the fact that l iterally, no end-of-pipe exis ts after the combustion zone. Additionally, we found no known demonstrat ions 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 no r applicable to them, all of the add-on control technology options listed above ar e eliminated as technically in feasible for the Main Flare.

Inherently Lower-Emitting Control Options Reducing the amount of air prehea t and taking burners out of serv ice are options intended for process heaters and boilers, wher e 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 im plemented with process heaters and boilers. However, flare burner design differs substantiall y from process heater and boiler burner design, because the primary objective of flare burner desi gn is to achieve safe and complete combustion of unwanted hydrocarbons during un predictable 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 th e chemistry of the combustion process, operate under specific temperature conditions and stable operations, neither of which is possible with flare systems. Oxidizer switchi ng, where pure oxygen is used for co mbustion rather than air, is not widely used in the hydrocarbon, petrochemi cal, and power generation industries due to the cost and energy requirements of producing pure oxygen. Fuel switch ing from fuels with higher fuel-bound nitrogen contents to those with lo wer fuel-bound nitrogen contents is a possible option for reducing NO x 

### 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 techni cally infeasible for the Main Flare as the fuel stream to the flare cannot be switched w ithout inherently changing the compressor plant’s purpose and design. Primarily, fu el is sent to the Main Flare through various pressure-relief piping or compre ssor bypass piping, as a result of emergency or maintenance situations, and also continuously from the dehydrat ion reboiler. Secondly, the fuel to the Main Flare consists of light hydro carbons (methane, ethane, propane) and carbon dioxide, with very little (fuel-bound) nitrogen c ontent. Therefore, these NO x 

### control options are eliminated for technical infeasibility.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 23 

### Other NO x 

### Control Options Proper operation and maintenance is typically sp ecific to a facility and could entail work practices to ensure that the flare is being main tained and operated properly. For the Main Flare, proper operation and maintenance include (1) follo wing 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 ma intenance, root cause, and corrective action requirements of the Consent Decr ee. Proper operation and maintena nce is technically feasible for the Main Flare.

7.3.3 Step 3 - Rank Control Technologies for NO X


### Proper operation and maintenance is the only contro l option for the Main Fl are. Table 7-3 shows a summary of recent NO x 

### BACT determinations for flares at other facilities.

These control determinations in clude proper operation and mainte nance, comply with the flare requirements in 40 CFR § 60.18, and good comb ustion 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. Prope r operation and maintenan ce for the Main Flare include good combustion practices.

The NO x 

### 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 determina tions listed in Table 7-3.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 24 Table 7-3: NO x 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% O 2 , 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: RBLCMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 25 

### 7.3.4 Step 4 – Economic, Energy an d Environmental Impacts for NO X


### 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 NO X


### Based on the above analysis, BACT for NO x 

### emissions from the Main Flare are the following requirements.

 NO x 

### 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 spec ifications for the flare; (2) operating and maintaining the flare in acco rdance 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 C onsent Decree into the PSD permit).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 26 

### 7.4 BACT FOR 

### V OLATILE 

### O RGANIC 

### C OMPOUNDS


### 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 flari ng 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 Cont rol 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 in clude supplemental ex ternal 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 th e reliability of the HOS-6 co mpression engine operations, and considered other compressor changes.

Flaring Due to Compressor Downtime : The majority of the flari ng at the MCU Facility is a result of downtime associated with the HOS-6 co mpressor. 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 di oxide and has a tendency to liquefy at relative low temperatures. The gas pressure between the 3 rd 

### and 4 th 

### stages of compression is approximately 1000 psi. The gas at this pressure liquefies at approximate ly 85°F. Additionally, the discharge pressure is above the critical pressu re 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 comp ressor 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 4 th 

### stage of the compressor, the field operations group attempts to maintain the suction temperature of the 4 th 

### 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 th is 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 27 

### The compressor has had downtime associated with 2 nd 

### stage failures due to liquids entering the cylinder. The implemented solution was to rem ove the liquid traps between the separation and compression equipment. This eliminated liquid collection and sl ugging, thereby reducing downtime events significantly.

Reliability of HOS-6 Compressor Engine Operations: The Applicant evaluated two options to increase reliability of compressor engine opera tion: (1) changing the co mpressor process and (2) replacing the HOS-6 compressor. The option to change the compressor process would consist of reducing the discharge pressure of the recipr ocating compression, cooling the gas stream to liquefy it, and utilizing pumps to reach the requ ired pipeline pressure. This could provide increased reliability and minimize potential co mpression failures at the MCU Gas Compression Plant. This option would require new refriger ation equipment, new pumps, and, at a minimum, restaging of the existing compression. Further co rrective actions would also be necessary, as described below, if the existing HOS-6 compressor was used.

The option to replacing the HOS-6 compressor w ould entail replacing the HOS-6 unit with one or more reciprocating compressors. The basic pr ocess would not change. Replacing the existing compressor may reduce the potential for liqui d retention by utilizi ng different piping configurations. However, problems inhere nt with the process would still remain.

Other Compression Changes: The Applicant considered three options for potential changes to compression operations. These options are (1) re locating 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. Ho wever, 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 assu rance of flaring frequency and duration reductions.

Reconfiguring the piping between the separa tion and compression equipment, similar to replacing the compressor or relo cating the separation equipment, would reduce the potential for liquids to enter the compressi on 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 betwee n the separation and compression equipment, the probability of the gas cooling and liquids formin g would be reduced. The potential for liquids entering the compression equipment would still remain and there would be no assurance of flaring frequency a nd duration reductions.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 28 

### Flare Gas Recovery System Another method of reducing flaring emissions is to recover gas th at would otherwise be flared and redirect for further processing in the existi ng 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, separa tor, 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 recove r 100 percent of these fuel gases. However, flare gas recovery systems cannot recover large quantities of fuel ga s 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 inte grity of the process un its and the safety of the plant personnel.

Flare gas recovery systems have been used at re fineries and has been re quired in EPA’s final standards for petroleum refineries. 13 

### These systems have been considered at facilities, such as petroleum refineries, that have fl ares receiving high gas flows.

Proper Operation and Maintenance (Use of Steam, Air, or Gas-Assist Technology) The flare requirements in 40 CFR § 60.18 esta blish specifications on visible emissions, continuous presence of a flame, exit velocities, fuel heating value, and monitoring for flare systems with the intent to ensu re 98 percent control (hydrocarbon destruction) efficiency for applicable flares. In order to achieve th e visible emission require ments of 40 CFR § 60.18, smokeless flare systems are designed with some t ype of external momentum force, such as steam, air, water spray, natural gas, or a specia lized 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 flar e 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 appr oximately 15 to 50 percent of the stoichiometric air requirement into the flame, providing adequate momentum to achieve smokeless and complete combustion. Air-assist desi gn is often used in remote locations. Gasassist with natural gas can provide an additiona l benefit by increasing the heating value to the fuel stream, in situations wher e 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 ai r-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).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 29 

### Proper operation and maintenance is typically sp ecific to a facility and could entail work practices to ensure that the flare is being main tained 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 CF R § 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 opt ions 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 Effectiven ess 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 dete rminations for flares at other facilities. These control determinations in clude proper operation and mainte nance, comply with the flare requirements in 40 CFR §§ 60.18 and 63.11, good combus tion practices, and 98% VOC control. The VOC emission rate specified in the Consen t Decree is 95.4 tpy ba sed on a cumulative 365- day rolling total.

Proper operation and maintenance for the Main Fl are 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. Thes e federal requirements for flares include the following minimum requirements:

 Designed and operated with no visible em issions 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 st eam- 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 pe r second (ft/sec). An exit velocity of greater than 60 ft/sec but less than 400 f t/sec may be used if the net heating value of the gas being combusted is sufficiently high.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 30 

### Proper operation and maintenance include other m easures that ensure complete combustion and proper flare performance. EPA supported a study to better unde rstand flare performance and to identify key operating/monitoring parameters that would ensure adequate performance of flares at all times. Based on this study EPA establis hed 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 wher e 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 th e waste gas and continuously measure, and then control, the air being added as assist gas. Follow the manufacturer’s recommendations and publicly available docum ents in setting proper assist gas rates.

 Utilize automatic damper actuators or vari able 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 contai n 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 supp lemental 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 preven t low heat value in the vent gas stream: 16



###  Ensure that the flare waste gas meets the cu rrent regulatory heating value limits of 300 BTU/scf for assisted flares, and 200 BTU/scf for unassisted fl ares, 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 ve nt gas as a whole, not only the hydrocarbons in the vent gas, just before it leaves the flare tip (flare vent ga s to includes all flare waste gas, sweep gas, purge gas and supplemental gas, but not include pilot gas or assist media). The heating value eval uation includes nitrogen and any other compounds that make up the gas mixture that is present just insi de 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 Flar ing Efficiency Violations , EPA 325-F-012-002, August 2012
15 Ibid.
16 Ibid.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 31 

### flares. 17 

### EPA has also included such requirements fo r flares in the propos ed 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 ai r-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 th at is greater than or equal to 22 BTU/ft 2



### . 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 Flar e must comply with the h eating 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/ft 2 

### (i.e., 22 BTU/ ft 2 

### x [(300 BTU/scf)/(270 BTU/scf)]).

A properly operated flare can achieve a destru ction efficiency of 98% or greater when controlling emission streams with heat contents gr eater than 300 BTU/scf. 20 

### Resolute’s Main Flare will achieve this 98% dest ruction efficiency through comp liance with the heat content requirements of 40 CFR § 60.18 and the combusti on efficiency provision s discussed above.

17 See Consent Decrees for Marathon Petroleum Compan y, LP and Catlettsburg Refining, LLC Settlement dated April 5, 2012; and Consent Decree for BP Products Nort h America, Inc., case 2:12-c v-00207, filed 09/18/12
18 See Petroleum Refinery Sector Risk and Technology Review and New Source Perf ormance 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)McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 32 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% O 2 , 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 (steam assisted) 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 opti ons, compressor engine modifications and flare gas recovery systems. The third control opti on (i.e., Proper operation and maintenance with steam, air, or gas-assist technology) does not ad ditional controls beyond the Main Flare and an economic analysis is no t 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 Flar e. Therefore, we are eliminating compressor modifications and flare recovery systems.

No significant energy or environmental imp acts are expected from proper operation and maintenance of the Main Flare.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 33 

### Table 7-6: VOC Ec onomic 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 emi ssions 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 us ing air-assist technology; (2) complying with a net heating value air assi st dilution parameter of greater than or equal to 24.4 BTU/ft 2 

### to ensure complete combustion in the flare; (3) following the manufacturer’s specificatio ns for the flare to ensure complete combustion in the flare; (4) operating and maintaining the flare in acco rdance 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 C onsent Decree into the PSD permit).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 34 

### 8. AIR QUALITY IMPACTS ANALYSIS

The Consent Decree requires the owner or operator of the MCU F acility, Resolute, to submit a PSD application that includes an air quality analysis for SO 2 

### , CO, NO x 

### , and VOC in accordance with 40 CFR § 52.21. Under Clean Air Act secti on 165 and EPA’s PSD regul ations at 40 CFR § 52.21, Resolute must demonstrate, using air quality models, that the Facility’s emissions of SO 2 

### , CO, NO x 

### , and VOC will not cause or c ontribute to a violation of (1) the applicable NAAQS, or (2) the applicable PSD increments (explained be low 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 Facil ity’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 I NTRODUCTION



### 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 anal ysis demonstrating that the facility’s emissions of the PSD-re gulated air pollutants will not cause or contribute to a violation of the applicable NAAQS or applicable PSD in crements. (A PSD incr ement for a pollutant applies only to areas that that are in at tainment with the corresponding NAAQS for that pollutant.) The Applicant provides separate modeling analyses for each criteria pollutant emitted above the applicable sign ificant emission rate. If a prelimin ary 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 po llutant. The cumulative impact analysis includes nearby pollution sour ces 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 th e 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 Qual ity 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 typica lly 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 mode ling are no greater than GEP height , so as to disallow artificial dispersion from the use of overly tall stacks. Th e application may also include initial “load screening,” in which a variety of source operatin g loads and ambient temperatures are modeled, to determine the worst-case scenario for use in the rest of the modeling.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 35 

### The PSD regulations also require an analysis of the impact on nearby Class I areas, generally those within 100 km, though the re levant Federal Land Manager (FLM) may specify additional or fewer areas. This analysis includes th e 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. Generall y, CALPUFF is the standard model choice for Class I analyses, since it can handle visibility ch emistry as well as the typically large distances (over 50 km) to Class I areas.

Finally, the PSD regulations requ ire an additional impact analys is, showing the Main Flare’s effect on visibility, soils, vegeta tion, 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 compri ses the documents listed in Table 8-1 below. The original PSD Permit applica tion dated March 22, 2007 contained the results of the original modeling. The revised PSD App lication addresses higher BTU c ontent and increased emissions and was submitted in April 2008. Resolute submitted a revised 1-hour SO 2 

### 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 s ubmitted 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 SO 2 Modeling McElmo Creek Unit Oil Production Facility-Main Flare, Gas Compression Facility 1-Hour SO 2 Modeling with AERMOD and accompanying DVD, dated April 2011 (received by EPA on June 3, 2011)



### 8.2 B ACKGROUND 

### A MBIENT 

### A IR 

### Q UALITY


### The PSD regulations require the ai r 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 36 

### No site or area-specific data was available for southeastern Utah for NO 2 

### , CO, SO 2 

### and ozone 21 

### ; therefore, air quality data gathered from mon itoring stations located in north central Utah, primarily within the Salt Lake City metropolitan ar ea, are used as conservative indicators of air quality for this rural area of Utah. Background PM 10 

### concentrations are not addressed since PM 10 

### emissions are insignificant from a flare, and the Consent Decree does not cite emission limits for PM 10



### .
Table 8-2 below describes the maximum bac kground 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 show n in the table are from 2009-2011 for NO 2 

### , CO, and ozone. No site or area-specific data wa s available for southeastern Utah for NO 2 

### , CO and ozone; therefore, except for SO 2 

### , air quality data gathered from m onitoring stations located in north central Utah, primarily within the Salt Lake City metropolitan ar ea, are used as conservative indicators of air quality for this rural area of Ut ah. Available SO 2 

### data from Shiprock (Farmington, New Mexico) are more representati ve 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 consid ered a contributor to th e formation of ozone.

Table 8-2: Maximum Background Concentrations and NAAQS NAAQS pollutant & averaging time Background Concentration, μg/m 3 NAAQS, μg/m 3

NO 2 , 1-hour 103.4 (55 ppb) 188 (100 ppb) NO 2 , annual 34 (18 ppb) 100 (53 ppb) SO 2 , 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 NO 2 1-hr value is 98 th percentile averaged over three years rather than maximum; The SO 2 1-hr value is 99 th percentile averaged over three years rather than maximum



### 8.3 M ODELING 

### M ETHODOLOGY FOR 

### C LASS 

### II AREAS


### The Applicant modeled the impact of th e 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 incl uded 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 A pplication (April 2011 MCU 1-Hour SO 2 

### 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 meteorologica l data processing. This is in accordance with the default r ecommendations in EPA’ s GAQM, Section 4.2.2 on

21 NO x and VOC are precursors to ozone formation.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 37 

### Refined Analytical Techniques. SCREEN was also used in earlier the earlier modeling submittals.

8.3.2 Meteorology model inputs

AERMOD requires representative mete orological data in order to a ccurately simulate air quality impacts. Resolute used surface meteorological data collected for a five consecutive-year period (2005-2009) at the Canyonlands Airport meteorologi cal station near Moab, Utah, northwest of the Main Flare site. This stat ion is located approximately 105 m iles (170 km) from the t site. Utah processed the data using EPA’s AERMET da ta processor, and provi ded the data to the Applicant. EPA concurs that the chosen Canyonla nds Airport data is the most representative for the Main Flare analysis.

For upper air data, the Applicant obtained conc urrent 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 da ta complete enough to use. No other upper air meteorological monitoring stations are located cl oser to the Main Flar e site. (MCU 1-hour SO 2 

### 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 arra y of 44 discrete meteorological conditions internally generated by SCREEN3 was used to estimate potential worst-ca se short-term (i.e., one-hour averaged) impacts fo r 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 fact ors 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 ch oice of rural versus urban algorithm within AERMOD; and 3) via speci fic values of AERMET parameters that affect turbulence and dispersion, namely surface roughn ess 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 magnit ude of mechanical turbulence. The Bowen ratio is an indicator of surface moisture. The albedo is the fraction of total incident solar ra diation reflected by the surface back to space without absorption.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 38 

### AERMAP is a terrain preprocessor that uses Digital Elevation Mode l (DEM) or National Elevation Dataset (NED) electronic files, which are readily available onlin e, 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 paramete r. The hill profile parameter is used in determining plume flow around elev ated terrain. Source elevati on and receptor elevations and hill heights were determined th rough AERMAP using NED files.

Reolute determined surface parameters in cluding the surface roughness length, albedo, and Bowen ratio for the area surrounding the Canyonla nds Airport meteorolog ical tower using the AERMET preprocessor, AERSURFACE (Ver sion 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 geogr aphic locations at which the m odel estimates concentrations. The Applicant places the receptors such that they have good area cove rage and are closely spaced enough so that the maximum model concentr ations 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 ha s access, and that are not insi de the project fence line.

Discrete receptors in UTM Zone 12 NAD83 coor dinates 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 esti mated by assuming that the maximum volume of process gas that could be generate d from the well field woul d be sent to the flar e at four different heat content values (in BTU/scf). These four h eat content values represent a range of estimatesMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 39 

### including the lowest allowable LHV, the lowest LHV from 2004 gas analyses, the lowest LHV from 2005-2008 gas analyses and the highest LH V 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 th at it would provide the least am ount of heat rise, thus producing the lowest effective release height. The lowe st 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 em ission rate/effective release hei ght 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 SO 2 modeling, Table 5-3

Table 8-4: Load Screening for Main Flare Operating Mode NO x (g/s) SO 2 (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 SO 2 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 woul d be during an upset episode when all process gas is sent to the flare, rath er than re-injected into the gr ound. Thus, modeled flare stack parameters were adjusted to reflect the instanta neous nature of heat release characteristics of a flare when combusting all process gas rather than re-injecting for i nput to AERMOD. The algorithm for this characterization is base d on the Texas Commission on Environmental Quality’s “Technical Basis for Flare Parameters” (September 10, 2004). An effective stack diameter at an assumed stack ve locity of 20 m/s at the estimate d heat release (in calories per second) of the flare is estimated. An effective st ack height is estimated based on heat release and the physical stack height of the fl are. The actual flare stack height of 195 feet was field verified to ensure proper stack height.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 40 

### 8.4 N ATIONAL 

### A MBIENT 

### A IR 

### Q UALITY 

### S TANDARDS 

### (NAAQS) AND 

### PSD C LASS 

### II I NCREMENT 

### C ONSUMPTION 

### A NALYSIS



### 8.4.1 Pollutants with Significant Emissions

The PSD regulations require an ai r quality impact analysis for each PSD-regulated pollutant (for which there is a NAAQS) that a major source ha s the potential to emit in a significant amount, i.e. , an amount greater than the Si gnificant Emission Rate for th e pollutant. Applicable MCU Facility emissions and the Signi ficant 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 NO x 

### in significant amounts. However, based on the estimates submitted by the applicant, EPA expects the MCU Facility to emit SO 2 

### and VOC in significant amounts. Therefor e, this permit action triggers air impact analyses for CO, NO 2 

### and SO 2



### .

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 NO x 13.4 40 No SO 2 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 SO 2 

### , 1,015.4 tpy of CO, and 118.5 tpy of NO x 

### . These very conservative worst-case c onditions result in emission rates in theanalysis that are at least five times greater than current air permit limits. Even with these worstcase emission estimates that far exceed the cu rrent air permit limits and actual flow rate conditions, the modeling results show no exceed ances of the NAAQS or the PSD Class II Increments.

8.4.2 Preliminary Analysis: Project-Only Impacts

EPA has established Significant Impact Levels (SIL s) 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 consid ered 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-on ly analysis based on maximum operations for the Main Flare. The worst case s hort-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 resultsMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 41 

### to predict annual, 24-hour and 3-hour SO 2 

### impacts. Resolute performed 1-hour SO 2 

### modeling with AERMOD. EPA determined 1-hour NO 2 

### and 1-hour and 8-hour CO impacts from the SO 2 

### AERMOD results by taking the ratio of the NO 2 

### and SO 2 

### emissions for various cases, including the worst case. EPA compared the ratio with the predicted SO 2 

### cumulative impacts from Tables 6-1 and 6-2 provided in Resolute’s April 2008 PSD application submittal for 1-hour SO 2 

### Modeling. The only significant impacts predic ted by the modeling results was for 1-hour SO 2



### .

Table 8-6: 

### Main Flare Significant Impacts NAAQS Pollutant & Averaging Time Project-Only Modeled Impact, μ g/m 3 Significant Impact Level (SIL), μ g/m 3 Project impact significant? NO 2 , 1-hour 5.0 7.5 (4 ppb) No NO 2 , Annual 0.15 1 No SO 2 , 1-hour 11.6 7.9 (3 ppb) Yes SO 2 , 3-hour 11.6 25 No SO 2 , 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 SO 2 Modeling, Sections 5 and 6



### 8.4.3 Cumulative Impact Analysis

A cumulative NAAQS or PSD increment impact anal ysis 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 bac kground concentration to represent those sour ces 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 SO 2 

### NAAQS.

PSD increments are limits on cumulative air quality degradation. They are se t 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 NO 2 

### and SO 2 

### . However, there have been no increments established for 1-hour NO 2 

### and SO 2



### . For demonstrating compliance with the PSD incr ement, 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 w ith 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, th ere may be a large numb er of sources that could potentially be included, so judgment must be applied to exclude small and/or distant sources that have only a negligib le contribution to total concentr ations. 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)McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 42 

### The Utah Department of Air Quality (UDAQ) and the Colorado Air Pollution Control Division (CAPCD) provided a list of all stationary sour ces within 50 km of the MCU Facility’s Main Flare (approximate distance to the farthest significant impact plus 50 km) for SO 2 

### . A comprehensive procedure was used to determine which sources were included in the emissions inventory.

It should be noted that short-term maximum emi ssion rates rather than annual emission rates determine the distance over which a facility mi ght have a significant impact for short-term standards ( e.g. , hourly NO 2 

### ). Peak rates that occur with flare heat content of 300 BTU/scf determine the MCU Facility’s Main Flare significant impact area for hourly SO 2 

### . The applicant identified eight facilities nearby for inclus ion in the emission inve ntory for the 1-hour SO 2 

### cumulative analysis, based on data from Utah and Colorado.

Current EPA SO 2 

### guidance suggests that emphasis on de termining which nearby sources to include in the nearby source inventory should focu s on the area within about 10 km of the MCU Facility’s Main Flare location in most cases, whic h 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 NO 2 

### -Specific Considerations

While the new 1-hour NO 2 

### NAAQS is defined relative to ambient concentrations of NO 2 

### , the majority of NO x 

### emissions from stationary sources are in the form of nitric oxide (NO) rather than NO 2 

### . Appendix W notes that the impact of an individual source on ambient NO 2 

### 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 NO x 

### chemistry plays in determining ambient impact levels of NO 2 

### based on modeled NO x 

### emissions, Section 5.2.4 of Appendix W recommends a three-tiered screening approach for NO 2 

### modeling. Later guidance documents issued by EPA expand on this approach. Tier 1 assumes full conversion of NO to NO 2 

### . Tiers 2 and 3 are refinements of the amount of conversion of NO to NO 2 

### . The applicant and EPA used the Tier 1 approach, in which the 1-hour NO 2 

### and annual impacts are based on the assumption that all of the NO is converted to NO 2



### .

8.4.3.3 Results of the Cumulative Impacts Analysis

The results of the PSD cumulative impacts analys is for the MCU Facility’s worst case operations for SO 2 

### emissions are shown in Table 8-6. The anal ysis demonstrates that emissions from the MCU Facility’s Main Flare will not cause or co ntribute to exceedances of the NAAQS or for any

22 See “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO 2 National Ambient Air Quality Standard”, Memorandum fro m Tyler Fox, EPA Air Quality Modeling Group to EPA Regional Air Division Directors, March 1, 2011, page 16McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 43 

### applicable PSD increments. The background concen trations 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 NO 2 

### , and for annual, 24-hour and 3-hour SO 2 

### ; therefore, a cumulative impacts analysis was not required to demonstrate compliance for these pollutants and averaging times.

EPA also considered additional information to en sure 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 in clusion/exclusion, in the cumulative impacts modeling above. EPA concluded that these s ources 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 Complian ce with Class II PSD Increments and NAAQS NAAQS pollutant &

averaging time All Sources Modeled Impact (ug/m 3 ) PSD Increment Consumption (ug/m 3 ) Background Concentration (ug/m 3 ) Cumulative impact w/ background (ug/m 3 ) NAAQS (ug/m 3 ) PSD Increment

(ug/m 3 )

SO 2 , 1-hour 26.76 N/A 79 105.76 196 None Source: April 2011 MCU 1-Hour SO 2 Modeling, Tables 6-1 and 6-2 Note: There are currently no PSD increments defined for 1-hour SO 2



### 8.5 C LASS 

### I A REA 

### A NALYSIS



### 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 Wa rner 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 Anal ysis is required. This approach, which only applies to projects located more than 50 km from a Class I ar ea, requires adding all of the visibility-related emissions (SO 2 

### , NOx, PM 10 

### and sulfuric acid mist) from a project (based on 24- hour maximum allowable emissions expressed in un its of tons per year) and dividing the sum by the distance between the project and the nearest Cl ass I area, which is Mesa Verde 60 km away. The values input into the table ar e the maximum. If th e result is less than 10, the project is presumed to have negligible impacts to Cla ss I AQRVs. The table below shows that theMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 44 

### project’s emissions are well belo w the FLAG screening cr iteria. Therefore, no further Class I AQRV analysis is required.

Table 8-8 : Summary of Q/D Analysis Parameter Value NO x Emission Increase 13.4 tpy SO 2 Emission Increase 60 tpy PM 10 Emission Increase -- H 2 SO 4 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 NO 2 

### and annual, 24-hour and 3-hour SO 2 

### was included in the original ap plication submitted in 2008. Based on the results, EPA did not require updated modeli ng to be submitted with the 2011 PSD application because of the very low predicted impacts by S CREEN. The results are presented in Table 8-9 below.

NO 2 

### and SO 2 

### 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 PM 10 

### or NO 2



### . Table 8-9: MCU Facility Main Flare Cla ss 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 NO 2 Annual 0.0102 2.5

SO 2 Annual 0.03 2 24-hour 0.90 5 3-hour 2.01 25 Source: April 2008 Revised PSD Application, Table 7-6McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 45 

### 9. ADDITIONAL IMPACT ANALYSIS

In addition to assessing the ambient air quality impacts expected from a source subject to PSD review, the PSD regulations requ ire that EPA evaluate other pot ential impacts on 1) soils and vegetation; 2) growth; and 3) visibility impairment. 40 CF R § 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 visibi lity in the source's impact area.

9.1 S OILS AND 

### V EGETATION


### The additional impact analysis includes consideration of potentia l impacts to soils and vegetation associated with the MCU’s emissions. This component generally includes:

 A screening analysis to determine if maxi mum modeled ground-leve l concentrations of pollutants from the Main Flare coul d have an impact on plants; and

 A discussion of soils and vegetation that ma y be affected by proposed emissions from the Main Flare and the potential impacts on such soils and vegetation a ssociated 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. Th e MCU Facility is an oilfield operation, which is primarily involved in crude pe troleum and natural gas extracti on. The Applicant presented its discussion of the potential impacts on soils a nd vegetation in its supplemental PSD permit application submitted to EPA Region 9 in Fe bruary 2013. Ground cover is relatively sparse because of the semiarid climatic conditions su rrounding the site. Vegetation in San Juan County includes woodlands, dominated by Pinyon Pine and Ut ah 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 informa tion is provided in Table 9-1.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 46 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 slick r ock, hi g her elevations in Aba j o 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 mi xed 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 Cutle r Formation, warm/sal t deser t shrub: 4,000 - 4,600 ft. elev. Source: Table 7-8 of the supplemental PSD permit app lication submitted to EPA Region 9 on February 20, 2013



### The values in Table 9-2 below a nd Table 8-5 of this document provide the concentration impacts used below in EPA’s “Screening Procedure for th e Impacts of Air Pollution Sources on Plants, Soils and Animals” (1980) 23 

### to determine if maximum modele d ground-level concentrations of SO 2 

### , NO 2 

### and CO from the main flare could have an impact on plants, soils, and animals.

23 “ Screening Procedure for the Impacts of Air Pollution Sour ces on Plants, Soils, and An imals,” EPA 450/2-81-078, December 1980.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 47 Table 9-2: Screening Ambient Air Concentrat ions for Sensitive Vegetation Exposure

Pollutant 1-hour (μg/m 3 ) 3-hour (μg/m 3 ) 4-hour (μg/m 3 ) 8-hour (μg/m 3 ) 1-week (μg/m 3 ) 1-month (μg/m 3 ) Annual (μg/m 3 )

SO 2 9 7

-- -- -- -- 18 NO 2

-- -- 3760 3760

-- 564 94 CO

-- -- -- -- 1,800,000

-- -- Source: Table 7-9 of the supplemental PSD permit app lication submitted to EPA Region 9 on February 20, 2013


### The modeled impacts of SO 2 

### , NO 2 

### , and CO emissions from the Main Flare range from below one percent to five percent of the minimum impact le vels/screening concentrations identified in this Screening Procedure.

Table 9-3: Maximum Concentrations & Scr eening Concentrations for Ambient Exposures

Criteria Pollutant and Guidance Averaging Time EPA Screening Concentration (μg/m 3 ) Modeled Maximum Concentrations (μg/m 3 ) Modeling Averaging time

SO 2 1-Hour 917 11.6 1 hour
SO 2 3-Hours 786 (0.30 ppm) 11.6 (0.0045 ppm) 3 hour
SO 2 Annual 18 0.93 Annual
NO 2 4-Hours 3,760 5.0 1 hour
NO 2 8-Hours 3,760 5.0 1 hour
NO 2 1-Month 564 5.0 1 hour
NO 2 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 in formation, we do not believe that emissions associated with the MCU Facility will generally result in adve rse impacts to soils or vegetation.

9.2 V ISIBILITY 

### I MPAIRMENT


### The additional impact analysis also evaluate s 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 sens itive 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 48 

### 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 m iles), as presented in Section 8.5.1. For Class II areas, the Applicant eval uated both Level I and Level II VISCREEN screening analyses for visibil ity impairment for five diffe rent 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 pred icted 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 purpo ses 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 ove r the Class I threshold levels in a Class I area. A Level-3 analysis is no longer considered a screening anal ysis 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 im pacts were greater than the Level 3 threshold, this would not likely result in a change in th e emission rates for the flare.

9.3 G ROWTH


### The growth component of the additional impact analysis involves a discussion of general commercial, residential, industrial, and other gr owth associated with the MCU Facility. This analysis considers emissions generated by growth th at will occur in the area due to the source. In conducting this review, we fo cus 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 use d. Although there has been an increase in the number of full-time employees, no significant growth is expected for this Facility.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 49 

### 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, EP A is required to ensure that any action authorized, funded, or carried out by EPA is not likely to jeopardi ze the continued existence of any endangered or threatened spec ies 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. Howeve r, 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 Re gion 9’s action does not authorize any new construction or modification of existing equipmen t 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 Fi sh 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, pr ior 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 undertak ings on historic properties and afford the Advisory Council on Historic Preservation (Council) a reasonable opportunity to co mment with regard to such undertakings. Consultation is required for all unde rtakings that have th e potential to affect historic properties. Section 106 consultations assess whether histor ic properties exist within an undertaking’s area of potential eff ect and, if so, whether the unde rtaking will adversely affect such properties. The term “historic properties” means prehistoric or historic districts, sites, buildings, structures, or objects incl uded in, or eligible for inclus ion in, the National Register of Historic Places maintained by the Department of the Interior. Histor ic properties include properties of traditional religious and cultural importance to an Indian Tribe or Native Hawaiian organization. Consultation is generally with re levant state and tribal historic preservation authorities in the first instan ce, with opportunities for direct Council involvement in certain circumstances.

EPA’s action, which is for the issu ance 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 operatio n since the 1990s. The EPA’s permit action is to incorporate the federal Consent Decree requiremen ts 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 Faci lity. EPA is currently consulting with the TPHOs for the Navajo Nation and Ute Mountain Indian tribes.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 50 

### 12. MAGNUSON-STEVENS FISH ERY CONSERVATION AND MANAGEMENT ACT

The 

### Magnuson-Stevens Fishery Conservati on 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 Fisher ies Service (NMFS), and its appointed regional fishery management councils. 

### Because the MCU Facility is locat ed on the Navajo Nation Indian Reservation in Utah, which is not located near any coastal or te rritorial 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 MA NAGEMENT ACT

The Coastal Zone Management Act (CZMA) of 1972 provides for management of the nation’s coastal resources, incl uding the Great Lakes. It encourages states to preserve , protect, develop, and where possible, restore or enhance valuable natural coastal resour ces such as wetlands, floodplains, estuaries, beaches, dunes, barrier isla nds, 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 a nd 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, coveri ng areas bordering the Atlantic, Pacific, and Arctic Oceans, the Gu lf of Mexico, Long Is land 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 JUST ICE 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 environmenta l justice part of its mission by identifying and addressing, as appropriate, disproportionately hi gh and adverse human health or environmental effects of its programs, policies, and activitie s 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 lo w-income populations pote ntially affected by its proposed action on the MCU Facility PSD permit app lication, and determined that it would be appropriate to prepare an Envi ronmental Justice Analysis for this action. EPA prepared an Environmental Justice Analysis, which is incl uded in the administra tive 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 qual ity levels in excess of health standards for the pollutants regulated under the proposed PSD permit amendment; th erefore, 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 51 

### 15. CLEAN AIR ACT TITLE V OPERATING PERMIT

The Applicant must apply for and obtain a T itle 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 P UBLIC 

### C OMMENTS


### The comment period for EPA’s proposed PSD permit amendment for the MCU Facility begins on November 15, 2014. Any interested person ma y submit written comments. All written comments on EPA’s proposed action must be re ceived by EPA via email or postmarked by November 20, 2014. An extension of the comment period ma y 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, in cluding such matters as:

 BACT determinations for the Main Flare;

 The effects, if any, on Class I areas;

 The effect of the proposed facili ty on ambient air quality; and

 The attainment and maintenance of the NAAQS.

16.2 P UBLIC 

### I NFORMATION 

### M EETING 

### & P UBLIC 

### H EARING


### EPA will hold a Public Information Meeting for th e purpose of providing interested parties with additional information and an opportunity for info rmal discussion of the proposed PSD permit.

Immediately following the Public Informati on 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 Heari ng, any interested person may provide writtenMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 52 

### comments or oral comments, in English or Diné, and relevant data pertaining to the proposed permit amendment. The date, time, and locati on 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 pr ovided at each Public Information Meeting and Public Hearing. If you require a reasonable accommodation, pleas e contact Philip Kum, EPA Region 9 Reasonable Accommodations Coordinato r, by October 31, 2014 at (415) 947-3566, or kum.philip@epa.gov

.

16.3 A VAILABILITY OF 

### P ERMIT 

### D OCUMENTS


### All information submitted by the Applicant is availa ble 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 ar e available on the EPA Region 9 website at http://www.epa.gov/region09/air/perm it/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 reco rd 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 AAQI R/Fact Sheet are available for review and inspection at the Navajo Nation Environmen tal 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, Sw eetwater, AZ, (928) 429-0977

 Dennehotso Chapter, Dennehotso, AZ, (928) 658-3300McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 53 

### 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, Montic ello, UT, (435) 587-2281

 Blanding Library, Blanding, UT, (435) 678-2335

 Montezuma Creek Library, Mont ezuma 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 persona l information provided, unless the comment includes Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Information that you consid er CBI or otherwise prot ected should be clearly identified as such and should not be submitted th rough e-mail. If you send e-mail directly to the EPA, your e-mail address will be automatically ca ptured and included as part of the public comment. Please note that an e-mail or postal address must be provide d with your comments if you wish to receive direct not ification of EPA’s final deci sion regarding the permit.

EPA will consider all written comments subm itted during the public comment period before taking final action on the PSD pe rmit 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 F INAL 

### P ERMIT 

### D ECISION


### Before taking final action, EPA Region 9 will cons ider all written and oral comments submitted during the public comment peri od, including those provided at th e 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) request s notice of the final permit decision. EPA will summarize the contents of all substantive co mments 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 sp ecified in the decision; or 2. The decision is appealed to EPA’s Envi ronmental 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 ef fective immediat ely upon issuance.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet October 2014 Page 54 

### 16.5 C ONTACT 

### I NFORMATION


### If you have questions, would like to be added to our mailing list to receive future information about this proposed permit decision, or othe r 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/pe rmit/psd-public-guidelines.html

. Shaheerah Kelly can also be reached through EP A 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 th is 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 amendm ent and this AAQIR/Fact Sheet to the public for review, and make a final decision after c onsidering 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 PROP OSED 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 comm ent on, EPA’s proposed action relating to amendments to the Prevention of Significant De terioration (PSD) permit for the McElmo Creek Unit Oil Production Facility (MCU Facility), an existing oil a nd gas production operation. The MCU Facility is owned and operated by the Reso lute Natural Resources Company. The mailing address for the facility is P.O. Box 100130, Anet h, 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 condition s for the already existin g Main Flare at the MCU Facility pursuant to a federal Consent D ecree (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 Cont rol 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 re placement of a fixed speed fan with a variable speed fan to provide better pol lution control at the Main Flar e, 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 subm it written comments regarding today’s proposed PSD permit amendment. A ll 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 94105-3901Page 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 pe rmit 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 perm it 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 wi th additional information and an opportunity for informal discussion of the propos ed PSD permit amendment.

Immediately following the Public Informati on 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 interest ed person may provide written comments or oral comments, in English or Diné, and relevant data pertaining to the proposed PSD permit amendment. The date, tim e, 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 pr ovided at each Public Information Meeting and Public Hearing. If you require a reasonable accommodation, pleas e contact Philip Kum, EPA Region 9 Reasonable Accommodations Coordinato r, by October 31, 2014 at (415) 947-3566, or kum.philip@epa.gov

.
Additional Information: All information submitted by the appli cant is available as part of the administrative record. The proposed amende d PSD permit, Ambient Air Quality Impact Report/Fact Sheet (AAQIR/Fact Sh eet), PSD application, and othe r 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 ma y also be viewed in person, Monday through Friday (excluding federal holiday s) from 9:00 AM to 4:00 PM, at the EPA Region 9 address above. Due to building securi ty procedures, please call Shaheerah Kelly at (415) 947-4156, or through EPA Region 9’s toll-f ree general information line at (866) 372-9378,Page 3 of 4 

### at least 72 hours in advance to a rrange 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 ac companying AAQIR/Fact Sheet are available for review and inspection at th e Navajo Nation Environmental Pr otection Agency, Fort Defiance, AZ, (928) 871-7692 and the following Nava jo 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, Sw eetwater, 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, Montic ello, UT, (435) 587-2281

 Blanding Library, Blanding, UT, (435) 678-2335

 Montezuma Creek Library, Mont ezuma 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 persona l information provided, unless the comment includes Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Information that is consid ered to be CBI or othe rwise protected should be clearly identified as such and should not be s ubmitted 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 a nd 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 taki ng 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) request s notice of the final permit decision. EPA will summarize the contents of all substantive co mments and provide written responses in a document accompanying EPA’s final permit decisi on. 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 sp ecified in the decision; or

2. The decision is appealed to EPA’s Envi ronmental 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 ef fective immediat ely 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 Regi on 9’s website at http://www.epa.gov/region09/air/pe rmit/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.