{In Archive {In Archive In Archive} Fw:RNRC-McElmo Creek Unit McElmo Creek Unit McElmo Creek Unit :PSD Permit Application PSD Permit Application

Shirley Rivera Shirley Rivera to: Andrew Chew 06/02/2009 10:56 AM

History: This message has been forwarded.

Archive: This message is being viewed in an archive .

here is the electronic version of the application revision - S.

-------------------------------------------

Shirley F. Rivera 

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San Francisco, CA 94105

----- Forwarded by Shirley Rivera/R9/USEPA/US on 06/02/2009 10:56 AM -----

From: "Patrick Flynn" <pflynn@rnrc.net>

To: Shirley Rivera/R9/USEPA/US@EPA

Date: 05/05/2008 02:17 PM

Subject: RE: RNRC - McElmo Creek Unit: PSD Permit Application

Shirley,

Please see the attached information provided as a result of the higher flare gas Btu previously discussed. 

A hard copy with a cover letter signed by our responsible official will follow via mail.

Thanks - Pat

From: Rivera.Shirley@epamail.epa.gov [mailto:Rivera.Shirley@epamail.epa.gov] 

Sent: Monday, April 21, 2008 3:39 PM

To: Patrick Flynn

Subject: RE: RNRC - McElmo Creek Unit: PSD Permit Application

Pat - Confirming receipt of your telecon. Thanks. I will look for the additional information later this week or 

early next week.

Have a good week! 

- Shirl

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San Francisco, CA 94105

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

"Patrick Flynn "Patrick Flynn Patrick Flynn "<pflynn@rnrc.net> 

03/25/2008 08:13 AM

ToShirley Rivera/R9/USEPA/US@EPA

cc

SubjectRE: RNRC - McElmo Creek Unit: PSD Permit Application
 

I traded emails with MMA yesterday and they're wrapping it up. I'll get it to you ASAP.

Pat

Sent by GoodLink (www.good.com)

-----Original Message-----

From: Rivera.Shirley@epamail.epa.gov [mailto:Rivera.Shirley@epamail.epa.gov]

Sent: Tuesday, March 25, 2008 08:32 AM Mountain Standard Time

To: Patrick Flynn

Subject: RE: RNRC - McElmo Creek Unit: PSD Permit Application

Patrick,

Just checking-in. It's been approx. a month. Let us know when you all

send over the revised info. As a side note, Scott (our modeler) is out

this week (and may also be so next week). Meanwhile, I am continuing to

draft up documents. I'll check-in again at end of week if I do not hear

from you all.

- Shirl

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San

Francisco, CA 94105

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

 

 Shirley 

 Rivera/R9/USEPA/ 

 US To

 "Patrick Flynn" <pflynn@rnrc.net>

 02/26/2008 02:44 cc

 PM Shirley Rivera, Scott 

 Bohning/R9/USEPA/US@EPA 

 Subject

 RE: RNRC - McElmo Creek Unit: PSD

 Permit Application(Document link:

 Shirley Rivera) 

 

 

 

 
 

 

[Scott - FYI; McElmo Creek revision (updated heat values for flare gas)

to modeling in progress. - S.]

==========

Patrick,

Thanks for the update. Please let us know what the estimated submittal

time frame is. Also, if there is a potential that you all (and/or

McVehil-Monnet) want to pow-wow with Scott Bohning (copied on this note;

our modeler) or me, let us know, as well.

Best regards,

- Shirl

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San

Francisco, CA 94105

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

 

 "Patrick Flynn" 

 <pflynn@rnrc.net 

 > To

 Shirley Rivera/R9/USEPA/US@EPA 

 02/26/2008 01:05 cc

 PM 

 Subject

 RE: RNRC - McElmo Creek Unit: PSD

 Permit Application 

 

 

 

 

 

 

We made contact with McVehil-Monnett Associates. They're working on

updating the model and submission.

Thanks - Pat

-----Original Message-----
From: Rivera.Shirley@epamail.epa.gov

[mailto:Rivera.Shirley@epamail.epa.gov]

Sent: Thursday, February 21, 2008 1:22 PM

To: Patrick Flynn

Subject: RE: RNRC - McElmo Creek Unit: PSD Permit Application

Pat,

Thanks much for the update. We'll touch base again next week or so.

Best regards,

- Shirley

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San

Francisco, CA 94105

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

 "Patrick Flynn"

 <pflynn@rnrc.net

 > To

 Shirley Rivera/R9/USEPA/US@EPA

 02/21/2008 09:54 cc

 AM

 Subject

 RE: RNRC - McElmo Creek Unit: PSD

 Permit Application

Shirley,

I wanted to provide you with a quick update on our status responding to

this information request. I'm compiling the information I have ready

access to and putting it into a formal letter to EPA. In the meantime, I

have placed several calls to the consultant used by ExxonMobil to

perform the air quality modeling in the hopes they could update the

model with the new Btu value. This seems the most efficient means of

amending the model. Unfortunately, I have not been able to make contact

with them yet. If I do not hear back from them by early next week, we'll

contact another modeling consultant and go from there.
Thanks - Pat

-----Original Message-----

From: Rivera.Shirley@epamail.epa.gov

[mailto:Rivera.Shirley@epamail.epa.gov]

Sent: Friday, February 15, 2008 9:17 AM

To: Patrick Flynn; Dwight Mallory

Cc: Bohning.Scott@epamail.epa.gov

Subject: RE: RNRC - McElmo Creek Unit: PSD Permit Application

[Scott - FYI, providing McElmo folks (Resolute Natural Resources) your

contact information, as we had discussed. - s.]

========

Pat,

Thanks for the reminder. In short, yes, given the description of the

upcoming revision to the PSD permit application information, please, at

a minimum, provide revised air quality modeling. Meanwhile, a few thing

and thoughts:

Our modeler's contact information

 Scott Bohning [Bohning.Scott@epa.gov ((415) 947-4127)] and I have

 briefly discussed the updated heat value information you provided. He

 noted that it appears the revision would pretty straightforward given

 the SCREEN3 effort that was originally conducted. If you all have any

 questions regarding modeling, Scott is available to discuss.

Application info update - MARCH 22, 2007 submittal

 Emissions information - The ExxonMobil information application update

 information has tables with Pre-Project and Post-Project Actual

 emissions, e.g., calculation methodologies, summary tables. You will

 need to update information from that submittal because of the

 assumptions that need to be revised.

 Appendix B includes the calculation methodology which presents the

 gross heating value (GHV) of gas flared as a variable for the

 emission estimates. There is a table that presents the "Input Factor

 Values" where the GHV (Btu/scf) is noted.

 Tables for Capital Cost Analysis (BACT) - If there are revisions to

 be made to the cost analysis and other information provided, please

 do so.

Application dated August 2006 (submitted in September 2006)

 Section 7, Air Quality Impacts, presents the assumptions of the

 modeled air quality impacts. On page 7-1, assumptions are listed.

 Item 1 speaks to the gas heat value and relationship to the plume or

 release height of the emissions.

 Modeling related runs and values are presented in Appendices C and E.

 Appendix C presents the input/output of the SCREEN3 runs for NO2, CO

 and SO2. Note that runs were presented for heat content of either 300

 or 443 Btu/scf. Discussions in Section 7 are included for NAAQS and

 PSD increments. You can see in Appendix C where there are input
 values. You will want to ensure values are updated as needed. For

 instance, at this point, we understand the Btu/scf will be updated.

 Presumably, gas flow (scf/hr) should remain the same, unless you all

 have additional information otherwise. Appendix E presents Class I

 impacts.

 Appendix D presents the Class I and Endangered Species e-mail

 exchanges that ExxonMobil provided for the PSD application. In review

 of the contents of this appendix, reference is made to the TPY total

 emissions, as well as other operating related information. Please

 note that if Resolute believes this information may need to be

 updated with the agencies, it will be necessary to contact them,

 accordingly.

Thanks for your patience in receipt of this information. As mentioned, I

am continuing to work on the support information, as well as pulling

information together for our docket. We are on holiday Monday, however,

I expect to be in all next week.

==================

- Shirl

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San

Francisco, CA 94105

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

 "Patrick Flynn"

 <pflynn@rnrc.net

 > To

 Shirley Rivera/R9/USEPA/US@EPA,

 02/14/2008 11:31 "Dwight Mallory"

 AM <dmallory@rnrc.net>

 cc

 Subject

 RE: RNRC - McElmo Creek Unit: PSD

 Permit Application

Shirley,
Please confirm whether or not EPA is directing Resolute to perform a

revised air quality model based on the higher Btu value for the gas

being combusted by the flare. I understood you were planning to talk

with your modeling folks to get their input on whether increasing the

Btu necessitates remodeling.

Patrick E. Flynn

Environmental Health & Safety Manager

Resolute Natural Resources Company

1675 Broadway, Suite 1950

Denver, Colorado 80202

Phone: 303.534.4600 X1145

Fax: 303.623.3628

Cell: 303.941.0389

From: Rivera.Shirley@epamail.epa.gov

[mailto:Rivera.Shirley@epamail.epa.gov]

Sent: Wed 2/13/2008 7:04 PM

To: Patrick Flynn; Dwight Mallory

Cc: Rios.Gerardo@epamail.epa.gov; Rios.Gerardo@epamail.epa.gov

Subject: RNRC - McElmo Creek Unit: PSD Permit Application

Patrick,

This is a follow-up note regarding the next steps resulting from our

conference call last week. Below is an e-mail thread, which includes:

 - RNRC recent information

 - Agenda for our meeting last week.

As a result of our meeting, for the purposes of your current PSD permit

application, please do submit formally the following to EPA Region 9,

for the purposes of the PSD permit application - a letter from Resolute

that provides:

a) Contact person(s) - State the contact persons and information for

our PSD records. Essentially, we'll have

b) Proposed PSD application revisions - Provide specific description of

the proposed revision to the permit application. As we discussed, we

understand Resolute has a record of the ExxonMobil filings associated

with the permit application - from original submittal to revised/updated

information as a result for ExxonMobil's responses to EPA's data

requests for completeness. Proposed revisions should include a

description of the following, including but not limited to -

 - Updates of assumptions associated with emissions,

 - Updates in any operating parameters or assumptions,

 - Updates to air quality modeling, if applicable, and

 - Updates to any other application element, e.g., BACT, additional

impacts analyses, etc.

Thank you for your patience in receipt of this information. Feel free to

call me or e/m me if you have additional questions or clarification.

Meanwhile, we will continue to prepare the portions of the PSD permit
and air quality impact report/technical support document while awaiting

your updated information. I'll check-in w/you later next week if I do

not hear from you all.

- Shirl

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3) | 75 Hawthorne St., San

Francisco, CA 94105

T: (415) 972-3966 | F: (415) 947-3579 | Rivera.Shirley@epa.gov

 Shirley

 Rivera/R9/USEPA/

 US To

 "Patrick Flynn"

 02/05/2008 10:08 <pflynn@rnrc.net>, "Dwight

 AM Mallory" <dmallory@rnrc.net>

 cc

 Shaheerah Kelly/R9/USEPA/US@EPA,

 Gerardo Rios/R9/USEPA/US@EPA

 Subject

 RNRC: 02/07 (Thurs) Telecon @

 9:00010:00 (PACIFIC)(Document

 link: Shirley Rivera)

Pat and All,

Let's go with Thursday, February 7, at 9:00-10:00 (PACIFIC) and below is

a slightly revised agenda (which can be updated, accordingly, as we

begin the telecon) ...

PROPOSED/DRAFT AGENDA FOR CALL:

For this Thursday's, here is strawman agenda - and please do

incorporate items you would like to discuss.

OBJECTIVE: To discuss "scope/activities" for moving forward with PSD

permit issuance.

1. Introductions (ALL)

 - RNRC (Roles and Responsibilities)

 - EPA (Roles and Responsibilities)

 - Others?
2. Status of EPA draft PSD permit

 - Content

 - Potential clarifications

3. Site visit findings of RNRC's site visit

 - Equipment status, e.g., operational, shutdown in place, removed

from site, etc.

 - Additional info that may be relevant for PSD permit

 - Additional info that may be relevant for Title V/Part 71 permit

4. Recent and Potential Revisions

 - Updates/Corrections to ExxonMobil information (Heat Value)

 - Status of future project

 - Other?

5. Next Steps and Milestones

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3)

T: (415) 972-3966 | F: (415) 947-3579

 75 Hawthorne St., San Francisco, CA 94105

 Rivera.Shirley@epa.gov

 "Patrick Flynn"

 <pflynn@rnrc.net

 > To

 Shirley Rivera/R9/USEPA/US@EPA

 02/04/2008 05:16 cc

 PM "Dwight Mallory"

 <dmallory@rnrc.net>, Shaheerah

 Kelly/R9/USEPA/US@EPA

 Subject

 RE: MCU PSD and Title V Permits

Thursday works for us. Let me know when you confirm.

Sent by GoodLink (www.good.com)

-----Original Message-----
From: Rivera.Shirley@epamail.epa.gov [

mailto:Rivera.Shirley@epamail.epa.gov]

Sent: Monday, February 04, 2008 05:03 PM Mountain Standard Time

To: Patrick Flynn

Cc: Dwight Mallory; Kelly.Shaheerah@epamail.epa.gov

Subject: RE: MCU PSD and Title V Permits

Pat - Let's shoot for Thursday morning, Feb 7th ... I still need to firm

up on my end and will let you know tomorrow morning ... so I am thinking

-

 9 AM (pacific)

 and I will see about keeping my morning for RNRC (just in case)

In case Thursday falls through - I will come in on Friday - and in that

case,

 8 AM (pacific)

 and, likewise, will keep my morning for RNRC (just in case)

- S.

 "Patrick Flynn"

 <pflynn@rnrc.net

 > To

 Shirley Rivera/R9/USEPA/US@EPA

 02/04/2008 11:50 cc

 AM "Dwight Mallory"

 <dmallory@rnrc.net>, Shaheerah

 Kelly/R9/USEPA/US@EPA

 Subject

 RE: MCU PSD and Title V Permits

I'm available for a call:

a. Tomorrow morning 10-11AM or afternoon 2-3PM Mountain Time.

b. Wednesday anytime after 10AM Mountain.

c. Thursday anytime after 9AM Mountain.

d. Friday anytime after 9AM Mountain.

-----Original Message-----

From: Rivera.Shirley@epamail.epa.gov

[mailto:Rivera.Shirley@epamail.epa.gov]
Sent: Monday, February 04, 2008 9:39 AM

To: Patrick Flynn

Cc: Dwight Mallory; Patrick Flynn; Kelly.Shaheerah@epamail.epa.gov

Subject: Re: MCU PSD and Title V Permits

Pat,

Wanted to just send you a note confirming receipt. Thanks for outlining

specifics. This is very helpful. The information you provided, needless

to say, will need to be taken into consideration across the board for

our efforts.

Please note that I'll be checking in with Tom Mintz, our Regional

Counsel who has been involved with the Consent Decree, and to Gerardo

Rios, the Chief of our Permits Office.

Also, will forward you, once again, availability for telecon regarding,

at least, the PSD permit. Let me digest what you all provided so I can

understand our next steps and get the telecon rescheduled.

Thanks much,

- Shirl

-------------------------------------------

Shirley F. Rivera

U.S. EPA, Region 9, Air Permits Office (AIR-3)

T: (415) 972-3966 | F: (415) 947-3579

 75 Hawthorne St., San Francisco, CA 94105

 Rivera.Shirley@epa.gov

 "Patrick Flynn"

 <pflynn@rnrc.net

 > To

 Shirley Rivera/R9/USEPA/US@EPA,

 02/01/2008 02:58 Shaheerah Kelly/R9/USEPA/US@EPA

 PM cc

 "Dwight Mallory"

 <dmallory@rnrc.net>, "Patrick

 Flynn" <pflynn@rnrc.net>

 Subject

 MCU PSD and Title V Permits
Shirley and Shaheerah,

Since we have been unable to connect on the phone over the past few

weeks, and in anticipation of our eventual teleconference, I'd like to

point out a few things regarding the PSD application prepared by

ExxonMobil in August-September 2006 for the MCU facility. Many of these

comments apply to the yet to be issued Title V permit as well.

 1. The PSD permit application still lists ExxonMobil and ExxonMobil

 contacts as the owner/operator. This should be changed throughout

 to Resolute Natural Resources Company.

 2. Resolute added a fifth electric-powered compressor to the MCU

 facility in 2007, at a cost of $9.5M. We did this in order to

 improve compressor reliability and try to minimize flaring. We're

 still in the start-up phase but are optimistic this should help

 reduce flare emissions.

 3. ExxonMobil used an unrealistically low Btu value for the flare gas

 for all of its Main Flare emission calculations and modeling. They

 used a range of 300 to 433 Btu. During 2007, we collected monthly

 flare gas samples that showed Btu ranging from 550 to 664. As a

 result, even through the volume of gas being flared has decreased,

 the resulting NOx and CO emissions have increased. The NOx and CO

 levels contained in the Consent Decree, the PSD application, and

 presumably the Title V application are too low and need to be

 revisited. We are currently running at about 98 percent of the NOx

 and CO limits. We need higher emission limits in both permits.

 4. ExxonMobil's use of incorrect Btu values has some impact on the

 air quality modeling.

 5. As I mentioned several months ago to Shaheerah, our mid-term plan

 is to add a gas refrigeration skid to the facility. Although

 actual emissions associated with the proposed skid will be low

 (primarily fugitives and a few low-Btu heaters) and constriction

 wouldn't start until the end of 2008 or beginning 2009, I wanted

 to give you both a heads-up.

Thanks - Pat

Patrick E. Flynn

Environmental Health & Safety Manager

Resolute Natural Resources Company

1675 Broadway, Suite 1950

Denver, CO 80202

Phone: 303.534.4600 X1145

Fax: 303.623.3628

Cell: 303.941.0389

THIS COMMUNICATION AND ANY ATTACHMENTS ARE CONFIDENTIAL AND PROPRIETARY

INFORMATION INTENDED FOR THE ADDRESSED PARTY ONLY, AND MAY BE

PRIVILEGED UNDER LAW. IF YOU ARE NOT THE INTENDED RECIPIENT YOU ARE

HEREBY NOTIFIED THAT ANY FURTHER REVIEW OR DISSEMINATION OF THIS MESSAGE

AND ANY ATTACHMENTS IS PROHIBITED BY LAW . IN SUCH EVENT YOU SHOULD

DELETE THIS COMMUNICATION AND ALL ATTACHMENTS AND DESTROY ANY PRINTED

COPIES. PLEASE NOTIFY THE SENDER OF ANY ERRONEOUS TRANSMISSION OF THIS

EMAIL. THANK YOU.

 RESOLUTE NATURAL RESOURCES

 for Resolute Natural Resources Company 

 1675 Broadway, Suite 1950 

 Denver, CO 80202

McElmo Creek Unit Oil Production Facility - 

Main Flare, Gas Compression Facility 

PSD Permit Application and Support Document 

Resolute Natural Resources Company 

Revised April 2008 

MMA Project Number 2220-08 

 

by McVehil-Monnett Associates, Inc. 

 44 Inverness Drive East, Building C 

 Englewood, CO 80112 
i 

TABLE OF CONTENTS

Page No. 

in Section

1.0 INTRODUCTION............................................................................................... 1 

1.1 GENERAL INFORMATION ...................................................... .................1 

 1.2 PERMIT APPLICATION ..............................................................2 

2.0 PROJECT DESCRIPTION............................................................1 

2.1 FACILITY AIR QUALITY PERMIT HISTORY........................................... 1 

2.2 EXISTING FACILITY OPERATIONS ........................................................... 2 

2.3 MODIFICATION................................................................................................ 3 

2.4 MAIN FLARE REGULATORY REQUIREMENTS...................................... 3 

2.4.1 New Source Review............................................................................................... 3 

2.4.2 Consent Decree Requirements............................................................................. 4 

2.4.3 New Source Performance Standards (NSPS) and National Emission 

Standards for Hazardous Air Pollutants (NESHAP)....................................... 4 

2.4.4 Other Air Quality Requirements......................................................................... 5 

2.4.5 Title V Requirements............................................................................................ 5 

3.0 MAIN FLARE EMISSIONS .............................................................................. 1 

3.1 CRITERIA POLLUTANTS............................................................................... 2 

4.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS ................... 1 

4.1 ALTERNATIVE CONTROLS ON FLARES .................................................. 2 

 4.1.1 Volatile Organic Compounds (VOC)..................................................2

 4.1.2 Carbon Monoxide (CO)...................................................................................... 5 

 4.1.3 Nitrogen Oxides (NOx)........................................................................................ 6 

 4.1.4 Sulfur Dioxide (SO2)............................................................................................ 8 

 4.2 COMPRESSOR ENGINE MODIFICATIONS......................................9 

 4.2.1 Past Flaring Due to Compressor Downtime..........................................9 

 4.2.2 Options to Improve Reliability of HOS-6 Compressor Engine Operations..10 

 4.2.3 Other Compressor Changes...........................................................11 

 4.3 FLARE GAS RECOVERY SYSTEMS..............................................12 

 4.4 OPERATION & MAINTENANCE (O&M) PLAN.............................. 14 

5.0 EXISTING ENVIRONMENT............................................................................ 1 

5.1 TOPOGRAPHY .................................................................................................. 1 

5.2 AIR QUALITY.................................................................................................... 1 

5.3 AREA CLIMATE AND METEOROLOGY .................................................... 2 

5.4 SOILS AND VEGETATION ............................................................................. 4 

6.0 IMPACT ASSESSMENT APPROACH............................................................ 1 

6.1 AIR QUALITY MODEL DESCRIPTION ....................................................... 2 

6.2 MODEL INPUT .................................................................................................. 3 

6.3 METEOROLOGICAL DATA........................................................................... 3 

6.4 SOURCE CHARACTERISTICS AND EMISSION RATES ......................... 4 

6.4.1 Fuel Rate and Heat Release ................................................................................. 4 
ii 

6.4.2 Flare Height........................................................................................................... 5 

6.4.3 Modeled Emission Rates ...................................................................................... 5 

6.5 RECEPTOR SELECTION ................................................................................ 6 

 6.6 CLASS I AREA IMPACTS.............................................................6 

 6.7 ADDITIONAL IMPACTS ..............................................................7

 6.8 ENDANGERED SPECIES..............................................................8 

7.0 AIR QUALITY IMPACTS................................................................................. 1 

7.1 NITROGEN DIOXIDE (NO2)............................................................................ 2 

7.1.1 Increment Consumption....................................................................................... 2 

7.1.2 National Ambient Air Quality Standards (NAAQS)......................................... 3 

7.2 SULFUR DIOXIDE (SO2).................................................................................. 3 

7.2.1 Increment Consumption....................................................................................... 4 

7.2.2 National Ambient Air Quality Standards (NAAQS)......................................... 4 

7.3 CARBON MONOXIDE (CO)............................................................................ 6 

7.3.1 National Ambient Air Quality Standards (NAAQS)......................................... 6 

 7.4 CLASS I AREA IMPACTS..............................................................7 

 7.4.1 Class I Increments.........................................................................7 

 7.4.2 Visibility......................................................................................8 

 7.4.3 Deposition....................................................................................8 

 8.0 REFERENCES ......................................................................................1 

LIST OF TABLES

TABLE 3-1 PRE-PROJECT & POST-PROJECT ACTUAL & PTE EMISSIONS 

TABLE 3-2 MAIN FLARE CRITERIA POLLUTANT EMISSION LIMITS 

TABLE 4-1 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY -VOC 

TABLE 4-2 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY -CO 

TABLE 4-3 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY -NOx 

TABLE 4-4 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY – SO2

TABLE 4-5a McELMO GAS COMPRESSION FACILITY – CHANGE HOS-6 

COMPRESSOR PROCESS CAPITAL COST SUMMARY 

TABLE 4-5b McELMO GAS COMPRESSION FACILITY – CHANGE HOS-6 

COMPRESSOR PROCESS OPERATING COST SUMMARY 

TABLE 4-6a McELMO GAS COMPRESSION FACILITY – REPLACE HOS-6 

COMPRESSOR CAPITAL COST SUMMARY 

TABLE 4-6b McELMO GAS COMPRESSION FACILITY – REPLACE HOS-6 

COMPRESSOR OPERATING COST SUMMARY 

TABLE 4-7a McELMO GAS COMPRESSION FACILITY – FLARE GAS 

RECOVERY SYSTEM CAPITAL COST SUMMARY 

TABLE 4-7b McELMO GAS COMPRESSION FACILITY – FLARE GAS 

RECOVERY SYSTEM OPERATING COST SUMMARY 

TABLE 5-1 AIR QUALITY IN THE MCELMO CREEK AREA 
iii 

TABLE 5-2 JOINT FREQUENCY DISTRIBUTION OF BLANDING, UTAH 

TABLE 5-3 ANNUAL STABILITY CLASS DISTRIBUTION AT BLANDING,UT 

TABLE 5-4 MONTHLY AVERAGE TEMPERATURE & TOTAL PRECIPITATION 

TABLE 6-1 SUMMARY OF NATIONAL AMBIENT AIR QUALITY STANDARDS 

 & PSD INCREMENTS 

TABLE 6-2 SCREEN3 MODELED STACK PARAMETERS & EMISSIONS FOR 

THE MAIN FLARE 

TABLE 7-1 COMPARISON OF MODELED MAIN FLARE NO2 IMPACTS TO THE 

 PSD INCREMENTS 

TABLE 7-2 COMPARISON OF MODELED CUMULATIVE NO2 IMPACTS TO 

THE NAAQS 

TABLE 7-3 COMPARISON OF MODELED MAIN FLARE SO2 IMPACTS TO THE 

 PSD INCREMENTS 

TABLE 7-4 COMPARISON OF MODELED CUMULATIVE SO2 IMPACTS TO 

THE NAAQS 

TABLE 7-5 COMPARISON OF MODELED CUMULATIVE CO IMPACTS TO 

THE NAAQS 

TABLE 7-6 CLASS I AREA AMBIENT AIR IMPACTS 

TABLE 7-7 CLASS I AREA DEPOSITION IMPACTS 

LIST OF FIGURES

FIGURE 2-1 LOCATION MAP OF McELMO CREEK OIL PRODUCTION FACILITY 

FIGURE 2-2 FLOW DIAGRAM OF EXISTING GATHERING SYSTEM OPERATIONS 

FIGURE 2-3 BLOCK FLOW DIAGRAM OF GAS COMPRESSION PLANT 

FIGURE 5-1 WIND ROSE OF 2004 BLANDING, UTAH METEOROLOGICAL DATA 

LIST OF APPENDICES

APPENDIX A EXXONMOBIL MCELMO CREEK OIL PRODUCTION UNIT 

CONSENT DECREE 

APPENDIX B DERIVATION OF ESTIMATED PRE-PROJECT AND POST-PROJECT 

ACTUAL AND POTENTIAL TO EMIT EMISSIONS 

APPENDIX C SCREEN3 MODELING INPUT AND OUTPUT RESULTS 

APPENDIX D E-MAILS FROM MR. JOHN NOTAR of the NATIONAL PARK 

SERVICE and MR. HENRY MADDUX, UTAH ENDANGERED 

SPECIES SUPERVISOR 

APPENDIX E SCREEN3 AND VISCREEN PRINT-OUTS FOR CLASS I AREA 

IMPACTS 
1-1 

1.0 INTRODUCTION 

1.1 GENERAL INFORMATION

Resolute Natural Resources Company (Resolute) is submitting this revised Prevention of 

Significant Deterioration (PSD) permit application for its Main Flare at the McElmo Creek Oil 

Production Facility, located on the Navajo Nation near Aneth, Utah. This revised PSD permit 

application is submitted to meet the terms of a Consent Decree (DOJ Case No. 90-5-2-1-2237, 

filed June 8, 2005) issued to the previous owner/operator of the facility, ExxonMobil 

Corporation (ExxonMobil). No modification is proposed with this permit application. 

ExxonMobil installed an automatic air-assisted system on the Main Flare on May 8 – 12, 2006, 

pursuant to the provisions of 40 CFR § 60.18 (c)(5) and (f)(6), as required in Paragraph 11.b of 

its Consent Decree. 

This PSD permit application document presents a facility process description for existing 

operations, criteria pollutant permit emission limits for the Main Flare, a Best Available Control 

Technology (BACT) analysis for the Main Flare, air modeling methodology, and air modeling 

results. Impacts are evaluated in both Class I and II areas. 

This permit application contains information submitted on March 22, 2007 with revisions 

intended to respond to recent EPA Region IX comments concerning increased emissions due to 

processing flare gas with a higher BTU content than previously cited. Specific 

additions/revisions to the application document submitted on March 22, 2007 in response to EPA 

Region IX comments include: 

1. Emissions Data: Post-project potential to emit (PTE) emissions have been reestimated per EPA’s request to estimate the maximum post-project PTE for all criteria 

pollutants, using the higher BTU content values tested during 2005-08 operations. 

Section 3.0 presents a summary of previously estimated pre- and post-project actual 

emissions and pre-project PTE and revised post-project PTE. Appendix B contains 

detailed emission calculations and fuel gas composition used to provide these estimates. 

These calculations include the basis for the revised post-project PTE estimates. 
1-2 

2. BACT Analysis: The Top-Down BACT analysis presented in Section 4 has been 

revised to consider the re-estimated post-project PTE for all criteria pollutants and to 

address the potential range of control efficiencies provided by compressor improvements. 

The cost effectiveness analyses presented in Tables 4-5 through 4-7 were revised to 

consider the higher estimates of post-project PTE for each criteria pollutant and the 

maximum control efficiency estimated for compressor improvements. 

Description of BACT, Class I area, additional impacts and endangered species analyses 

presented in the March 22, 2007 submittal have been retained to provide for an all-inclusive 

support document of PSD review and analyses performed for this permit application. 

1.2 PERMIT APPLICATION FORM

A completed permit application form providing information on the existing facility, including the 

Main Flare, is attached at the end of this section. Flare specification sheets are attached after the 

permit application form to provide information on flare manufacturer and model. 
PSD Permit Application Form Page 1 of 4 

General Information 

Company Name and Address: 

Resolute Natural Resources Company 

1675 Broadway, Suite 1950 

Denver, CO 80202 

Phone No.: 303-534-4600 

Fax No.: 303-623-3628

Company Contact for Environmental Matters: 

Patrick E. Flynn 

Environmental Health & Safety Manager 

1675 Broadway, Suite 1950 

Denver, CO 80202 

Phone No.: 303-534-4600

Fax No.: 303-623-3628

Facility Name and Address: 

McElmo Creek Unit Oil Production Facility 

P.O. Box 100130 

Aneth, UT 84510 

Phone No.: 303-534-4600

Fax No.: 303-623-3628

Owners Name and Address: 

Resolute Natural Resources Company 

1675 Broadway, Suite 1950 

Denver, CO 80202 

Phone No.: 303-534-4600

Fax No.: 303-623-3628

County where facility is located: 

San Juan 

Latitude and Longitude or UTM coordinates: 

37o

 15' 37.58" N 

109o

 12' 12.07" W 

Directions to facility (street address and/or directions to site): 

From Cortez Airport, take Hwy 160 South for 30 miles. Turn right (heading Northwest) on CO 41 to Utah. CO 41 turns 

into UT 262 at the state line. Continue on UT 262 for 14 miles, through the town of Aneth. Turn Right at the Resolute 

sign and follow the road 3.1 miles to the office. The office is on the left and the gas compression plant is on the right. 

List current air quality permits for facility: 

U.S. EPA Region VIII PSD Permit 8AT-AP (last amended April 18, 1991) 

If request for a modification, identify permit # to be modified: 

Permit No.: 8AT-AP

Dated: April 18, 1991

Type of business at this facility:

Oil & Gas Production 

Are the total number of company employees greater 

than 100? Yes 

Standard Industrial Code Classification: 1311 

Application for: 

 ___ New construction X Modification 

 X Existing equipment operating without permit ___ Permanent site for portable equipment 

 ___ Change of permit condition ___ Change of location 

For new construction or modification, enter estimated start date: Flare Upgrade will begin in March 2006 

 estimated completion date: Must be completed by June 8, 2006 

For change of permittee, location, or condition, enter 

date of occurrence: N/A

For existing equipment in operation without prior 

permit, enter initial operation date: 1991 
PSD Permit Application Form Page 2 of 4 

Process Information 

Name of process: Oil & Gas Production; Gas 

Dehydration and Compression; CO2 and Water Injection 

End product of this process: Oil 

Primary process equipment: Separators, Heaters, Tank Batteries, Dehydration System, Compressors, and Flare

 

Operating Data 

Maximum Operating Schedule: 

 24 hours/day

 7 days/week

 52 weeks/year

Percent annual production by quarter: 

 Winter 25% Spring 25%

 Summer 25% Fall 25%

Daily production rates: 

Average: 3,700 bopd 

Maximum: 5,000 bopd

Maximum annual production: 

1,825,000 bbls of oil 

Projected percent annual increase in production: N/A

Type of operation: X Continuous

 __Batch

 __Intermittent

If batch, indicate minutes per cycle: N/A

Minutes between cycles: N/A

Materials used in process: (1) raw material, (2) principal use, and (3) amounts: 

3,700 bbls of oil produced (bop) and sold each day on average from the tank batteries 

26,000 bbls of water produced (bwp) and injected each day on average 

10-18 million cubic feet of gas produced each day on average 

6-14 million cubic feet of CO2 is purchased each day to supplement injection to 24 million total cubic feet per day 
PSD Permit Application Form Page 3 of 4 

Flare System Information 

Manufacturer: Zeeco, Inc. will perform upgrade in March 2006; Originally by American Steel and Iron Works

Model No: N/A

Fuel Minimum Expected Flowrate Design Max Temp oF Pressure (psig) 

Waste gas stream: Dehydrated Produced Gas (approx. 70% CO2 and 0.05% H2S) - Up to 14 million cubic feet per day

Fuel added to gas stream: N/A

Heat Content of flared gas 500-682.4 BTU/scf 

Number of pilots: Currently 1 Pilot fuel type: Natural Gas 

Pilot fuel flow rate, per pilot (scfm 70oF & 14.7 psia): 1.0

Flare height: Currently 195 feet Flare tip inside diameter: 24 inches

Steam Injection NA

 Steam pressure (psig): NA

 Minimum expected: NA

 Design maximum: NA

 Total steam flowrate (lb/hr): NA

 Temperature (oF): NA

 Velocity (ft/sec): NA

 Number of jet streams: NA

 Diameter of jet streams (in.): NA

Water Injection: 

 Water pressure (psig): NA

 Minimum expected: NA

 Design maximum: NA

 Total water flowrate (gpm): NA

 Minimum expected: NA

 Design maximum: NA

 Number of water jets: NA

 Diameter of water jets (in.): NA

 

Air Assist: 

 Air pressure (psig): 

 Minimum expected: 

 Design maximum: 

 Total air flowrate: Currently in Design

 Velocity (ft/sec): 

 Number of air jets: 

 Diameter of air jets (in.): 

 
PSD Permit Application Form Page 4 of 4 

Certification Statement 

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

submitted in this document and all attachments and that this document and its 

attachments were prepared either by me personally or under my direction or supervision 

in a manner designed to ensure that qualified and knowledgeable personnel properly 

gathered and presented the information contained therein. I further certify, based on my 

personal knowledge or on my inquiry of those individuals immediately responsible for 

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

aware that there are significant penalties for submitting false information, including the 

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

false statement. 

Signature:_____________________________________ Date:___________ 

Name (type): Dale E. Cantwell_____________________ 

Title: Vice President, Operations

Phone:_303-534-4600_______________________________________ 


2-1 

2.0 PROJECT DESCRIPTION 

This section presents an overview of the McElmo Creek Oil Production Facility, including a 

summary of the facility’s air permit history, overview of operations including the gas 

compression plant and the Main Flare, and a review of applicable air quality requirements. 

2.1 FACILITY AIR QUALITY PERMIT HISTORY 

The McElmo Creek Oil Production Facility is located in San Juan County, Utah near Aneth, 

Utah in Section 23 of T40S, R24E on Navajo Nation land. A location map of the facility is 

presented in Figure 2-1. 

The original oil well production facility, owned by Superior Oil, started operations in the 1950s. 

Mobil Exploration and Producing U.S., Inc. (Mobil) purchased the facility from Superior Oil in 

1984. In 1986, Mobil constructed a gas processing plant at the facility, including an upright 

flare, dehydrator, amine treater, refrigeration separation unit, a natural gas liquids recovery unit 

and compressors to transport the produced liquid natural gas. In 1991, the equipment was 

switched out with an emergency flare added as a control device for the dehydrators. Petroleum 

liquid storage tanks and heater treaters were also installed in the early 1990s. At that time, the 

emergency flare was not permitted because it was viewed as an emergency control device. The 

permit and facility operations have been overseen by EPA Region IX. EPA has delegated 

oversight authority of this facility since it is on tribal land and is assisting the tribe in 

administering its recently approved regulatory program. 

In 1997, following a fire, all processing equipment except for one dehydrator was removed, the 

compressors were converted to run on electricity, and the flare was kept for emergency flaring, 

flaring closed drain system fumes, and control of dehydrator emissions. The former gas 

processing plant is now referred to as the gas compression plant. 

In 1997 and 1999, EPA issued NOVs (Notice of Violations), asserting the flare should have been 

permitted. The NOVs also cited the lack of fugitive VOC (volatile organic compounds) 

monitoring per the New Source Performance Standards (NSPS) of 40 CFR 60, Subpart KKK. 
2-2 

The following is a summary of the PSD permit history associated with the McElmo facility: 

• March 14, 1985 - U.S. EPA Region VIII determined Stage I of McElmo Creek Unit does 

not require a PSD permit; 

• May 8, 1986 - Mobil Exploration and Producing North America submitted PSD Permit 

Application for CO2 Project Stage 2; 

• February 2, 1987 - U.S. EPA Region VIII issued PSD permit to Mobil; 

• September 1, 1987 - Mobil submitted letter requesting to replace three reciprocating 

internal combustion engines with two natural gas fueled turbines; 

• October 27, 1987 - U.S. EPA Region VIII issued amended PSD permit for the change; 

• February 21, 1991 - Mobil requested amendment of PSD permit to allow construction of 

waste heat recovery unit turbine, replacing two existing pieces of fuel-burning 

equipment; 

• February 22, 1991 - Mobil requested EPA approval for temporary replacement of turbine 

with an identical unit, during turbine overhauls; 

• April 18, 1991 - U.S. EPA Region VIII issues amended PSD permit for requested 

changes and also, rescinded approval of the second turbine since Mobil had no plans to 

install it. 

Resolute acquired ExxonMobil’s ownership interest in the McElmo facility in April 2006 and 

assumed operation effective June 1, 2006 

2.2 EXISTING FACILITY OPERATIONS 

 

Currently, produced fluids at the oil production facility are processed, sold, and re-injected 

through a series of satellite facilities, main tank batteries, and injection plants. Produced fluids 

are gathered and separated at one of eleven satellite facilities located throughout the field. Gases 

from the satellite facilities are directed to the gas compression plant, and liquids are pumped to 

one of four central tank batteries. Gases sent to the gas compression plant are compressed, dried 

through a glycol dehydrator, blended with carbon dioxide (CO2), and re-injected into the field. 

Liquids are further separated at the central tank batteries, with oil being sold and transported 

through a pipeline system. Water from the central tank batteries is pumped to the water flood 

injection plant. 
2-3 

The Main Flare at the gas compression plant combusts gases that have been bypassed around the 

plant’s electric-driven compressors or that come through various emergency relief valves in the 

compression plant. Additionally, the vent stream from the plant’s glycol dehydrator is directed 

to the Main Flare. 

A flow diagram of the facility’s gathering system operations is presented in Figure 2-2, 

illustrating the flow through the satellite facilities, central tank batteries, water flood injection 

plant, and gas compression plant. Figure 2-3 presents a simple block flow diagram for the gas 

compression plant, including the streams directed to the Main Flare. 

2.3 MODIFICATION

As noted in Section 1, no modification of existing operations is proposed with this PSD permit 

application. This application is submitted in order to meet the requirements of a Consent Decree 

(DOJ Case No. 90-5-2-1-2237, filed June 8, 2005) issued to the former owner, ExxonMobil. 

Paragraph 14.a requires ExxonMobil to submit an application for a PSD permit for the Main 

Flare, including “(i) an analysis of the best available control technology for the Main Flare for 

[sulfur dioxide] SO2, [carbon monoxide] CO, [nitrogen oxides] NOx, and [volatile organic 

compounds] VOC; and (ii) an air quality analysis” within 180 days of the Consent Decree’s 

effective date of June 8, 2005. 

2.4 MAIN FLARE REGULATORY REQUIREMENTS

2.4.1 New Source Review 

No modifications are being proposed to necessitate a PSD permit application. However, the 

Consent Decree requires a PSD permit application submittal for the Main Flare, including a 

BACT analysis for SO2, CO, NOx, and VOC, and an air quality analysis to assess the impacts of 

the Main Flare’s criteria emissions to ambient air quality standards. Based on EPA Region IX’s 

comments in their May 22, 2006 letter, assessment of the Main Flare’s emissions consider BACT 

criteria and impacts on Class II areas are modeled. Class I area impacts, additional impacts and 

effects on endangered species are not formally assessed per telephone and e-mail correspondence 
2-4 

with Mr. Notar of the National Park Service and Mr. Henry Maddux, Utah Endangered Species 

Field Supervisor. 

Consent Decree Requirements 

The Consent Decree further requires in Paragraph 14.a that the PSD application include “among 

other things, terms and conditions that are at least as stringent as the terms and conditions 

included in Paragraphs 9.a, 10, 11, and 25(i)-(ix) of this Consent Decree, with the exception that 

the quarterly report required by Paragraph 25 may be changed, at the discretion of the permitting 

authority, to a semiannual report.” Paragraph 9.a of the Consent Decree refers to the rolling 365-

day cumulative emission limits for SO2, CO, NOx, and VOC, which will be discussed in Section 

3 of this application document. Paragraph 10 of the Consent Decree addressing monitoring 

requirements for the Main Flare, and Paragraph 11 presents operation and maintenance 

requirements for the Main Flare and compressors at the gas compression plant. Paragraph 25 of 

the Consent Decree details a quarterly reporting system, the frequency of which may be changed 

by the permitting authority, as noted earlier. A copy of the Consent Decree has been attached as 

an appendix to this application. The air permit for the Main Flare will contain the terms and 

conditions found in Paragraphs 9.a, 10, 11, and 25(i)-(ix) of the Consent Decree either by 

reference or by direct inclusion in the permit. 

2.4.2 New Source Performance Standards (NSPS) and National Emission Standards for 

Hazardous Air Pollutants (NESHAP) 

The Consent Decree specifies recordkeeping, maintenance, and operational procedures to 

demonstrate a 98 percent destruction efficiency on VOCs consistent with 40 CFR § 60.18 

(NSPS) and 40 CFR § 63.11 (NESHAP). These procedures and limitations are applicable to a 

flare used as a control device for affected facilities subject to individual NSPS and/or NESHAP 

subparts. Such is not the case here. Rather, the Main Flare at the McElmo Creek Gas Plant has 

been typically used as an emergency flare to control process gas and waste gas release emissions 

when the injection system (the primary control “device”) is malfunctioning and/or undergoing 

maintenance. As such, it is the Consent Decree alone that compels the flare destruction 

efficiency requirement. 

 
2-5 

2.4.4 Other Air Quality Requirements 

Since the facility is located on the Navajo Nation, it is the Navajo Nation, and not the state of 

Utah that has the authority (aside from EPA) to implement air quality programs relevant to the 

facility. Although the Navajo Nation has been granted delegated authority as of October 15, 

2004, EPA is acting as an oversight reviewing agency assisting the Navajo Nation in 

administering their approved program. 

2.4.5 Title V Requirements 

A Title V operating permit application must be submitted, as required by Paragraph 14.b of the 

Consent Decree, no later than 180 days after the Consent Decree’s effective date of June 8, 2005. 

Similar to the requirements for the PSD permit application, the Title V operating permit 

application must include terms and conditions at least as stringent as those in Paragraphs 9.a, 10, 

11, and 25(i)-(ix) of the Consent Decree, with the exception that the quarterly report described at 

Paragraph 25 may become a semiannual report. 

Fig

Block Flow Di

Gathering Sy

McElmo Creek O
3-1 

3.0 MAIN FLARE EMISSIONS 

As requested in the EPA Region IX comment letter of May 22, 2006, this section presents preand post-project actual emissions, as well as pre-project estimates of the potential to emit (PTE) 

for all criteria pollutants, including particulate matter (PM10 and PM2.5) and lead. Pre- and postproject gas flow rates to the flare are also included. Per EPA’s comment letter, pre-project is 

defined as prior to the gas compression facility being dismantled in 1997, and post-project is 

defined as subsequent to the gas plant being dismantled. Thus, pre-project emission estimates 

provided in Table 3-1 are based on 1996 gas flare rates and a conservative gas analysis from that 

year and post-project emission estimates are based on the 2005 emission inventory, updated by 

gas analysis data from 2005-08. The post-project emissions presented in Table 3-1 reflect the 

updated estimates from 2005-08 gas analyses data. 

As clarified in the EPA Region IX comment letter of November 8, 2006, post-project PTE is for 

the period following the dismantling of the gas plant, but prior to the imposition of the Consent 

Decree limits. Therefore, the post-project PTE emissions provided are based on 2003 flare 

emissions data multiplied by a PTE factor of 1.2 since the annual flare rate in 2003 was the 

highest of the five year period 2001-2005. Updated post-project PTE emissions based on more 

recent gas analyses from late 2005 through 2008 and the natural gas flow rate from 2003 

multiplied by 1.2 are also provided. These post-project PTE determinations were made in 

accordance with the methodology outlined in 40 CFR §63.760(a)(1)(i)(B) (E&P MACT) and 

past Texas Commission on Environmental Quality (TCEQ) guidance on PTE calculations for oil 

& gas operations. Applicable calculation methodology with input data used to estimate 

emissions are presented in Appendix B. 

The gas flow rates to the flare used for the emission estimates are 1,145.96 MMscf in 1996 (for 

both actual and PTE emissions), 727.704 in 2005 (rounded off to 730.0 MMSCF) for postproject actual emissions, and 1,070.366 MMscf for post-project PTE emissions. Because the 

flare is only used for emergency relief and to control dehydrator still vent emissions, the daily 

rates vary. 
3-2 

Table 3-1 

Pre-Project and Post-Project Actual and PTE Emissions

Criteria 

Pollutant

Pre-Project 

Actual Emissions 

(tpy) 

Pre-Project 

PTE1

(tpy) 

Post-Project 

Actual Emissions 

(tpy) 

Post-Project 

PTE2

(tpy) 

CO 159.2 159.2 82.5 135.1 

NOx 29.3 29.3 15.2 24.8 

VOC 183.6 183.6 91.7 151.8 

SO2 138.1 138.1 30.1 44.2 

Lead 0.00021 0.00021 0.000109 0.000179 

PM10 3.2 3.2 1.7 2.7 

PM2.5 3.2 3.2 1.7 2.7 

1

 Pre-project PTE is equivalent to 1996 actual emission estimates. 

2

 Post-project PTE is estimated by identifying the maximum annual gas flow rate from the most recent five-year 

period with available data (i.e., 2001 – 2005) and multiplying by a contingency factor of 1.2 to provide a worstcase post-project PTE estimate. The maximum gas flow year of 2003 was selected as the basis for this estimate. 

The maximum BTU content from 2005-08 gas analyses data (682.4 BTU/SCF) was assumed for emission 

estimates.

3.1 CRITERIA POLLUTANTS

Table 3-2 presents a summary of criteria pollutant emission limits for the Main Flare as listed in 

Paragraph 9.a of Exxon Mobil’s Consent Decree. Due to the higher BTU content occurring 

since issuance of the Consent Order, Resolute is requesting revised emission limits 

corresponding to the last column of Table 3-1. 

Table 3-2 

Main Flare Criteria Pollutant Emission Limits1

Pollutant tons/year2

SO2 60 

CO 73 

NOx 13.4 

VOC 95.4 

1. As listed in Paragraph 9.a of Consent Decree (DOJ Case No. 90-5-

2-1-2237) 

2. Cumulative 365-day rolling average. 
4-1 

4.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS 

The 1977 Clean Air Act Amendments established revised conditions for the approval of 

preconstruction permit applications under the PSD Program. One of these requirements is that 

Best Available Control Technology (BACT) be installed for all pollutants regulated under the 

Act emitted in significant amounts from new major sources or modifications. BACT is defined 

as an emission limitation based on the maximum degree of pollutant reduction determined on a 

case-by-case basis considering technical, economic, energy, and environmental factors. 

Additionally, a BACT limitation cannot be less stringent than emissions limits established by an 

applicable New Source Performance Standard (NSPS). For this specific case, a BACT analysis 

will be performed for VOC, CO, NOx, and SO2 from the Main Flare as required by 

ExxonMobil’s Consent Decree (DOJ Case No. 90-5-2-1-2237). Current and future operation of 

the Main Flare will not otherwise trigger PSD review. The Main Flare is used to incinerate the 

residual hydrocarbons and sulfur in the injection gas stream during times when injection is not 

possible, thus, controlling VOC and H2S emissions. 

EPA has specified use of a “top-down” approach to BACT determinations, in order to bring 

consistency to the BACT process. The steps of a Top-Down BACT determination are: 

1. Identify all available control options; 

2. Evaluate and eliminate those options that are technically infeasible; 

3. Rank remaining control alternatives by control effectiveness; 

4. Evaluate feasibility of each control option and combinations of control options on the 

basis of energy, environmental and economic factors; 

5. The most stringent control option or combination of options found to be feasible on the 

basis of technical, energy, environmental and economic factors is selected as BACT. 

The first step, to determine all control options for the pollutant in question and emission unit(s) 

under review, requires research to determine what available control options exist. The EPA 

maintains a “RACT/BACT/LAER” clearinghouse of historical BACT determinations, known as 

the “RBLC” database, which can be very useful in gathering an initial list of control options. 

Other resources may be used as available to complete the list. Following a technical feasibility 

assessment for all options, those found to be technically feasible are evaluated and ranked on the 
4-2 

basis of control effectiveness (encompassing percent removal, amount of emission reduction, 

energy impacts, environmental impacts, and economic factors). When investigating each control 

option in order of effectiveness, it is important to identify individual controls that can be 

combined on the basis of technical feasibility. These combinations may result in control 

alternatives that are more effective than the separate individual control options. As the final step, 

the most effective control option or combination of options that has not been eliminated is 

selected as BACT. 

EPA Region IX has also requested the Top-Down BACT analysis to consider operating options 

that would reduce the need to flare. Specific options to be analyzed include improving the 

efficiency, reliability and/or capacity of the gas compressors and measures designed to reduce 

flaring frequency and the quantity of gas flared. Thus, the options evaluated in this Top-Down 

analysis are: 

1. Increasing the reliability and efficiency of the existing Dresser HOS-6 compressor 

2. Installation of a flare gas recovery unit (FGRU) that would capture most of the gas 

potentially flared for further processing 

The Top-Down BACT analysis presented below considers control alternatives for the flare itself 

and alternative operating options designed to minimize the need for flaring consisting of 

modifications to the HOS-6 compressor or installation of a FGRU. 

4.1 ALTERNATIVE CONTROLS FOR FLARE

4.1.1 Volatile Organic Compounds (VOCs)

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 VOCs, since combustion through a flaring system prevents the release of 

hydrocarbons to the atmosphere. When combustion is not complete, flares will emit VOCs in 

the form of unburned hydrocarbons. The EPA addressed this issue through regulations in the 

New Source Performance Standard’s (NSPS) General Control Device Requirements at 40 CFR § 

60.18 and in the Control Device Requirements for the National Emission Standards for 
4-3 

Hazardous Air Pollutants (NESHAP) regulations at 40 CFR § 63.11. These requirements 

establish specifications on visible emissions, continuous presence of a flame, exit velocities, fuel 

heating value, and monitoring for flare systems applicable to any NSPS, 40 CFR Part 61 

NESHAP, or 40 CFR Part 63 NESHAP, with the intent to ensure 98 percent control 

(hydrocarbon destruction) efficiency for applicable flares. This objective was based on tests 

confirming 98 percent control efficiencies for flares combusting organic emissions. 

Additionally, flare manufacturers such as the John Zink Company LLC established that a 

“properly designed and operated” flare burner will have a combustion efficiency of more than 98 

percent. Flares not subject to an NSPS or NESHAPs are not required to meet these 

specifications. 

In order to achieve the visible emission requirements of 40 CFR § 60.18 and 40 CFR § 63.11, 

“smokeless” flare systems are designed with some type of external momentum force, such as 

steam, air, water spray, natural gas, or a specialized high velocity vortex design. An external 

momentum force provides for more complete combustion by improving the fuel flow 

momentum, which allows a sufficient amount of combustion air to be educted into the 

combustion zone just outside the flare burner. High-pressure flares (5 to 10 psig or more) might 

not require a supplemental external momentum design in order to achieve smokeless 

combustion. However, many flare systems require some type of supplemental assist in order to 

achieve smokeless operation and 98 percent control efficiency. Steam injection is common, as it 

can add sufficient momentum and aid the chemistry of the combustion process. Low-pressure 

air can be used as an assist medium in locations where steam, water, or gas is not readily 

available or where cold temperatures present freezing issues. In this case, a blower is utilized to 

inject approximately 15 to 50 percent of the stoichiometric air requirement into the flame, 

providing adequate momentum to achieve smokeless and complete combustion. Air-assist 

design is often used in remote locations. Gas-assist with natural gas can provide an additional 

benefit by increasing the heating value to the fuel stream, in situations where the waste gas to be 

combusted does not have a sufficient heating value for safe combustion. Available literature 

suggests that each technology option for supplemental external momentum provides similar 

additional control to VOC emissions from flare systems. 

Table 4-1 presents a summary of recent BACT determinations from the EPA’s RBLC database 

for flare VOC emissions. The table shows that seven of the twelve RBLC determinations did not 
4-4 

list any control technology for VOCs, although four of those seven determinations noted flares as 

the control device for VOC emissions. Three of the entries which noted flares as a VOC control 

device went on to state the flare would have 98% control efficiency, and one entry also stated the 

flare would be designed and operated to meet 40 CFR § 60.18 specifications. Four of the twelve 

entries noted the use of “gas-assisted” smokeless flare systems as the VOC control technology. 

(Note that it is not clear in the RBLC if “gas-assisted” refers to the use of air or natural gas as the 

source of external momentum.) One of the twelve determinations noted “good combustion 

practices” as the control technology. For those seven determinations where no control 

technology was specified, including those noting the flare system as the control device for 

VOCs, it cannot be determined if those flare systems are designed and operated with any type of 

supplemental external momentum technology such as steam, air, or gas-assist. It is logical to 

conclude that some of these systems might have an “assisted” design, particularly in the case of 

the refinery flares, if the compliance with the provisions of 40 CFR § 60.18 or 40 CFR § 63.11 is 

required. 

Based on review of Table 4-1 and knowledge of controls used to reduce VOC emissions from 

flare systems, the possible VOC control options for the Main Flare are: 

• No control/good combustion practices; 

• Meet requirements of 40 CFR § 60.18 and/or 40 CFR § 63.11 for flare systems; and 

• Supplemental external momentum design - steam, air, or gas-assist technology. 

Some overlap exists between the second and third options, because as explained previously, the 

visible emission requirements of 40 CFR § 60.18 and 40 CFR § 63.11 are frequently met by the 

use of a supplemental external momentum design, such as steam, air, or gas technology. 

Therefore, in some cases, compliance with the requirements of the NSPS or NESHAP control 

device regulations can only occur by utilizing a supplemental external momentum design such as 

steam, air, or gas-assist technology. 

Of the options listed above, steam-assisted technology is immediately determined to be 

infeasible. The McElmo Creek Gas Compression 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. 
4-5 

The McElmo Creek Gas Compression Facility’s Main Flare has not been previously viewed as 

subject to the requirements at 40 CFR § 60.18 or 40 CFR § 63.11, because its use was not 

specifically for compliance with a provision of a NSPS or NESHAP. However, Paragraph 11(b) 

of the Consent Decree with the EPA (DOJ Case No. 90-5-2-1-2237) states that “...[t]hereafter, 

Mobil shall operate and maintain the Main Flare in compliance with 40 CFR § 60.18(c)(1), 

(c)(2), (c)(3)(ii), (c)(5), (d), (e), (f)(1) through (f)(4), and (f)(6). Additionally, Paragraph 11(b) of 

the Consent Decree states that “Within three hundred sixty-five (365) days from the Effective 

Date, Mobil shall install an automatic air-assisted flare system on the Main Flare, pursuant to the 

provisions of 40 CFR §60.18(c)(5) and (f)(6). Therefore, Consent Decree conditions requiring 

compliance with NSPS requirements (typical starting point for BACT), supplemented by one of 

the three supplemental external momentum technologies, represents the most stringent BACT 

currently implemented. On this basis, further analysis of employing a gas-assist technology 

rather than air-assist is unnecessary, since there would be no additional environmental benefit 

from using gas-assist. VOC BACT is proposed to be the combination of air-assist technology 

and complying with the flare specifications of the General Control Device Requirements at 40 

CFR § 60.18 as specified in the Consent Decree. 

4.1.2 Carbon Monoxide (CO) 

Carbon monoxide (CO) from flare systems is formed in the same manner as any combustion 

process – through incomplete combustion. VOC emissions from flare systems also originate 

from incomplete combustion. Therefore, control options to address CO emissions from flares 

will be the same as those for VOC emissions. 

Table 4-2 presents a summary of recent BACT determinations from the EPA’s RBLC database 

for flare CO emissions. Nine of the sixteen determinations do not cite a specific CO control 

technology. It is uncertain how many of the flares represented by these determinations are 

designed and operated with any type of supplemental external momentum technology such as 

steam, air, or gas-assist technology; however, it is reasonable to conclude that some of the listed 

flares, particularly those located at petroleum refineries, utilize an assist technology in order to 

meet NSPS and NESHAP requirements. Four of the sixteen determinations note the use of “gasassist” smokeless technology (note that it is not clear in the RBLC if “gas-assisted” refers to the 

use of air or natural gas as the source of external momentum). Two entries cite “proper 
4-6 

operation and maintenance,” and one entry cites “good combustion practices” as the CO control 

technology, with no further detail provided. 

Based on review of Table 4-2, and typical flare system operations, BACT options for CO are 

considered to be identical as those for VOC. Therefore, CO BACT is proposed to be the 

combination of air-assist technology and the requirement to meet the flare specifications under 

the General Control Device Requirements at 40 CFR § 60.18. 

4.1.3 Nitrogen Oxides (NOx)

There are three principal forms of NOx, designated as “thermal” NOx, “prompt NOx,” and “fuel” 

NOx. Thermal NOx formation is the result of oxidation of atmospheric nitrogen contained in the 

inlet gas in the high-temperature, post-flame region of the combustion zone. The major factors 

influencing thermal NOx formation are temperature, concentrations of nitrogen and oxygen in the 

inlet air, and residence time within the combustion zone. Prompt NOx is formed through 

relatively fast reaction between nitrogen, oxygen, and hydrocarbon radicals and is an important 

mechanism in lower temperature combustion processes. Fuel NOX is formed by the oxidation of 

fuel-bound nitrogen. It is not a concern for high-quality gaseous fuels such as natural gas or 

propane, because these fuels normally have no organically-bound nitrogen. Fuel NOx is a 

concern when burning oil, coal, or waste fuels. 

Generally, several options exist to reduce NOx emissions from combustion processes, such as 

pre-treating the fuel or switching fuels and/or oxidizers to prevent NOx formation, modifying the 

combustion process or equipment to lower NOx formation, and post-treatment end-of-pipe 

technologies to remove NOx. These options are listed below: 

Pre-Treatment Combustion Modification Post-Treatment

• Fuel switching • Air Preheat Reduction • SCR 

• Fuel additives • Burners Out-of-Service • SNCR 

• Oxidizer switching • Low NOx burner 

Post-treatment, end-of-pipe options are not technically feasible for flare systems, due to the 

inherent design of flaring and the fact that literally, no end-of-pipe exists after the combustion 
4-7 

zone. Combustion modification options have limited technical feasibility for flare systems, as 

well. Reducing the amount of air preheat and taking burners out of service are options intended 

for process heaters and boilers, where the combustion air is heated for more efficiency and where 

multiple burners exist. Low NOx burners incorporate concepts such as lowering excess air, fuel 

staging, and gas recirculation, which can be successfully implemented with process heaters and 

boilers. However, flare burner design differs substantially from process heater and boiler burner 

design, because the primary objective of flare burner design is to achieve safe and complete 

combustion of unwanted hydrocarbons, sometimes in emergency situations, and often in 

unpredictable volumes, flowrates, and temperatures. Essentially, the best low-NOx burner for a 

flare is a well-designed one, properly sized and constructed for a specific flare’s conditions. 

Thus, the only technically feasible options for NOx control from the Main Flare fall within the 

pre-treatment category; however, few options in this category are technically feasible. 

Fuel additives, intended to change the chemistry of the combustion process, operate under 

specific temperature conditions and stable operations, neither of which are possible with flare 

systems. Oxidizer switching, where pure oxygen is used for combustion rather than air, is not 

widely used in the hydrocarbon, petrochemical, and power generation industries due to the cost 

and energy requirements of producing pure oxygen. Fuel switching from fuels with higher 

fuel-bound nitrogen contents to those with lower fuel-bound nitrogen contents is a possible 

option for reducing NOx from flare systems, but only in specific cases where the fuel to the flare 

can be controlled and predicted. 

Table 4-3 presents a summary of recent BACT determinations from the EPA’s RBLC database 

for flare NOx emissions. Eight of the twelve determinations do not cite a specific NOx control 

technology. Two of the twelve determinations note “proper operation and maintenance” as the 

control technology, one notes a limitation on fuel type (use of natural gas only) and one notes the 

flare will be operated in accordance with 40 CFR § 60.18 General Control Device requirements. 

Based on review of Table 4-3, and the previous discussion of possible NOx control technologies 

for combustion processes, the list of possible NOx control options for the Main Flare are: 

• No control/good combustion practices; 

• Meet requirements of 40 CFR § 60.18 and/or 40 CFR § 63.11 for flare systems; and 

• Fuel switching. 
4-8 

Of these options, fuel switching has been determined to be technically infeasible for the Main 

Flare. Fuel is sent to the Main Flare through various pressure-relief piping or compressor bypass 

piping, as a result of emergency or maintenance situations, and also continuously from the 

dehydration reboiler. This fuel stream to the Main Flare cannot be switched without inherently 

changing the compressor plant’s purpose and design. Furthermore, the fuel to the Main Flare 

consists of light hydrocarbons (methane, ethane, propane) and carbon dioxide, with very little 

fuel-bound nitrogen content. 

Since the Consent Decree requires the site operator to “operate and maintain the Main Flare in 

compliance with 40 CFR § 60.18(c)(1), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (f)(1) through (f)(4), and 

(f)(6)” following installation of an air-assist technology, BACT for NOx is proposed as meeting 

the General Control Device requirements of 40 CFR § 60.18 for flare systems. Compliance with 

these requirements also guarantees that good combustion practices are being followed. 

4.1.4 Sulfur Dioxide (SO2) 

Sulfur dioxide emissions from flare systems depend on the amount of sulfur in the fuel stream. 

Typically, sulfur dioxide from combustion processes can be controlled through limiting the fuel 

type or sulfur content, or through end-of-pipe control technology. As discussed in section 4.3, 

end-of-pipe control technologies are not feasible for flare systems. Therefore, the primary means 

of controlling SO2 emissions from flare systems is to limit the fuel type or sulfur content, where 

possible. 

Table 4-4 presents a summary of recent BACT determinations from the EPA’s RBLC database 

for flare SO2 emissions. Ten of the sixteen determinations note some type of fuel sulfur 

limitation as the control technology. Five entries do not list any type of SO2 control technology, 

and one entry contains a reference to continuous pilot ignition, flame monitors, and other 

specifications that can be found in the 40 CFR § 60.18 flare requirements. Following this 

review, the SO2 control options for the Main Flare are determined to be: 

• No control/good combustion practices; 

• Limit fuel type; and 

• Limit sulfur content. 
4-9 

Limiting the fuel type has been determined to be a technically infeasible option for the Main 

Flare. As discussed in Section 4.3 for NOx, the fuel sent to the Main Flare is a combination of 

the process gas which is compressed for re-injection and the vent stream from the dehydration 

reboiler. This fuel stream cannot be switched to a different type without inherently changing the 

compressor plant’s purpose and design. 

Additionally, limiting the fuel’s sulfur content has been determined to be technically infeasible. 

The compressor plant is designed and operated to compress gas and re-inject it into the field. 

The gas directed to the compressor plant is not processed for sale or sold to outside customers. 

Its average hydrogen sulfide (H2S) content is 400-500 ppm, with the maximum H2S content 

potentially higher, depending on the quality of product from the field. Limiting the sulfur or 

hydrogen sulfide content in the gas directed to the Main Flare could result in an inherent change 

to the compressor plant’s purpose and design, because the gas to the Main Flare is a combination 

of process gas and dehydrator vent gas, and because the plant’s design does not call for any 

sweetening process due to the fact that it is re-injected, and not sold. 

The only remaining technically feasible option is no control/good combustion practices. 

Therefore, BACT for SO2 is proposed as good combustion practices, which will be achieved 

through compliance with 40 CFR § 60.18 flare operational requirements. 

4.2 COMPRESSOR ENGINE MODIFICATIONS

4.2.1 Past Flaring Due to Compressor Downtime 

The majority of the flaring at McElmo Creek Gas Compression Facility is a result of downtime 

associated with the HOS-6 compressor. This unit is a 4-stage, 6-cylinder Dresser HOS model 

compressor, which is driven by an electric motor. 

HOS-6 compressor reliability is influenced by the interaction of the gas composition and process 

requirements at McElmo Creek. The gas is primarily composed of carbon dioxide and has a 

tendency to liquefy at relative low temperatures. The gas pressure between the 3rd and 4th 

stages of compression is approximately 1000 psi. The gas at this pressure liquefies at 

approximately 85 °F. Additionally, the discharge pressure is above the critical pressure of the 
4-10 

gas. Therefore, the process stream actually leaves the compressor and can simultaneously have 

the properties of a liquid and a gas. It is when the gas behaves as a liquid that compressor 

damage can occur. This mixed gas stream allows for the potential of liquid drop-out throughout 

the compression process. 

In an effort to reduce the potential for damage on the 4th stage of the compressor, the field 

operations group attempts to maintain the suction temperature of the 4th stage near 100° F. 

However, the large temperature swings that can occur in the McElmo Gas Compression Facility 

area, especially in the winter months, make this difficult. Some of the issues are: 

• No automatic controls on the coolers 

• Gas separation between stages located remotely from the compressor 

• Piping between the separation equipment and the compressor having multiple 

elevation changes, which increase the potential for liquid accumulation in the lines. 

The compressor has had downtime associated with 2nd stage failures due to liquids entering the 

cylinder. The implemented solution was to remove the liquid traps between the separation and 

compression equipment. This eliminated liquid collection and slugging, thereby reducing 

downtime events significantly. 

4.2.2 Options to Improve Reliability of HOS-6 Compressor Engine Operations 

A Top-Down analysis of options to increase reliability of compressor engine operation is 

presented below. Cost effectiveness based on annual emissions reduction of each pollutant is 

estimated for each option to evaluate economic feasibility. Cost estimation methodology is 

based on the EPA Cost Control Manual. ExxonMobil experience with capital costs and 

maintenance labor is cited, but actual cost effectiveness estimates are based on the EPA costing 

factors. Implementing these options is assumed to achieve a minimum decrease of 75% and up 

to a maximum of 95% of base emissions for each pollutant. The maximum of 95% is based 

upon industry experience in which compressor downtime of 5% annually is considered 

acceptable. As discussed below, options for increasing the reliability of compressor engine 

operation are changing the compression process and replacing the compressor engines. 
4-11 

Change Compression Process 

Reducing the discharge pressure of the reciprocating compression, cooling the gas stream to 

liquefy it, and utilizing pumps to reach the required pipeline pressure could provide increased 

reliability and minimize potential compression failures at the McElmo Gas Compression Facility. 

However, this would require new refrigeration equipment, new pumps, and, at a minimum, 

restaging of the existing compression. Further corrective actions would also be necessary, as 

described below, if the existing HOS-6 compressor was used. 

The estimated equipment cost for this corrective action would be $12,000,000, at a minimum, if 

the HOS-6 compressor was reconfigured for this process. Based on the cost-effectiveness 

analyses in Tables 4-5a and b, this method is considered economically infeasible. To achieve a 

95% reduction in annual emissions of each pollutant, the cost effectiveness is a minimum of 

$36,687 per ton of VOC removal. 

Replace the HOS-6 Compressor 

This option would replace the HOS-6 unit with one or more reciprocating compressors. The 

basic process would not change. Replacing the existing compressor may reduce the potential for 

liquid retention by utilizing different piping configurations. However, problems inherent with 

the process would still remain. 

The equipment cost for this corrective action would be approximately $10,000,000, at a 

minimum. Based on the cost-effectiveness analyses in Tables 4-6a and b, this method is 

considered economically infeasible. To achieve the maximum of 95% reduction in annual 

emissions of each pollutant, the cost effectiveness is a minimum of $30,665 per ton of VOC 

removal. In addition, compression process issues contributing to potential flaring would remain. 

4.2.3 Other Compression Changes 

The following potential changes to compression operations were also considered, but their effect 

on reducing the frequency or duration of flaring is uncertain and may be minimal since 

documented studies of the results from implementing these changes are not available. 
4-12 

Relocate the HOS-6 separation equipment 

By moving the HOS-6 separation equipment closer to the compression equipment, the potential 

for liquid forming in the intermediate piping and entering the compressor would be reduced. A 

potential for liquid entering the compressor equipment would still remain because of the size of 

the separation equipment required on the HOS-6 compressor. Additionally, relocation of the 

separation equipment would not remove the inherent process issues and there would be no 

assurance of flaring frequency and duration reductions. 

Reconfigure piping 

Reconfiguring the piping between the separation and compression equipment, similar to 

replacing the compressor or relocating the separation equipment, would reduce the potential for 

liquids to enter the compression equipment by removing liquid traps. The potential for 

downtime occurrences would still remain, however, and there would be no assurance of flaring 

frequency and duration reductions. 

Insulate and heat-trace the piping 

By insulating and heat-tracing the piping between the separation and compression equipment, the 

probability of the gas cooling and liquids forming would be reduced. The potential for liquids 

entering the compression equipment would still remain and there would be no assurance of 

flaring frequency and duration reductions. 

4.3 FLARE GAS RECOVERY SYSTEMS 

Another method of reducing flaring emissions is to recover gas that would otherwise be flared 

and redirect for further processing in the existing gas compression facility. Description of a 

commercially available flare gas recovery unit (FGRU) is provided below to illustrate its 

operation. 

• The Flare Gas Recovery Unit (FGRU) initially withdraws gas from the flare header 

upstream of the liquid seal drum and recovers gas normally combusted by the flare; 
4-13 

• To prevent ambient air from being drawn into the flare system or FGRU, the FGRU 

operates with a slight positive pressure upstream of the liquid seal drum; 

• As the volume of gas increases within the FGRU, the pressure exerted in the flare header 

will increase until equaling the back-pressure created by the liquid seal drum. Any gas in 

excess of the back-pressure will be flared; 

• As long as the pressure of the collected gas remains below the liquid seal drum backpressure, gas is diverted back to the suction header by staging compressors; 

• The staging compressors typically use liquid ring compressor technology; rotary screw, 

reciprocating sliding vane or rotary-lobed compressors can also be used; 

• The recovered gases and some of the sealing liquid combine inside the compressor and 

flow into a separator vessel to separate liquids and gases; 

• The compressor sealing liquid from the separator goes through a heat exchanger and 

returns to the compressor; 

• Compressed gas from the separator is then sent by pipeline to its sales destination. 

Various vendors of FGRUs use different methods for achieving the sealed system necessary to 

prevent recovered gas from simply flowing past the flare header and being flared into the 

atmosphere. However, the degree of difficulty in installing and operating the variety of available 

FGRU systems is similar both in terms of costs and technical considerations. 

Cost effective use of FGRUs are typically achieved by large oil and gas production facilities 

where the volume of recovered gas becomes additional sales gas and its revenue from this can 

largely offset initial FGRU costs and future operating costs within a few years. Thus, facilities 

that have successfully used FGRUs and have found them to be both technically and financially 

feasible are large production facilities. The amount of recovered flared gas at these facilities 

represents a significant revenue stream. The Main Flare at the McElmo Gas Compression 

Facility is used intermittently and the additional volume of gas that would be recovered as sales 

gas would minimally offset the substantial economic costs associated with installing and 

operating the FGRU system. 

The equipment cost associated with a typical FGRU is approximately $1,300,000. Since 

additional compressors are required and the cost associated with their installation are similar to 
4-14 

those cited for the replacement of existing compressors in Section 4.2.2 (i.e., $10,000,000), the 

total equipment cost is estimated as $11,300,000. Based on the cost-effectiveness analyses in 

Tables 4-7a and b, this method is considered economically infeasible. To achieve the 75% 

reduction in annual emissions of each pollutant, the cost effectiveness is a minimum of $43,801 

per ton of VOC removal. In addition, efficient use of a FGRU for an application of this small 

size is uncertain. This uncertainty in demonstrated efficiency does not support the use of a 

control efficiency higher than 75%. 

4.4 OPERATION & MAINTENANCE (O&M) PLAN 

Since the above options are considered impractical because of cost-ineffectiveness or 

uncertainty, the existing facility and equipment must be operated and maintained in such a 

manner to reduce compressor downtime and thereby, keep flaring to a minimum. This prudent 

operation and maintenance is conducted in accordance with Paragraphs 9.a, 10, and 11 and in 

accordance with Appendix B (the "O&M Plan") of the Consent Decree. This includes constant 

monitoring, inspecting and performing maintenance on the compressors and associated 

equipment in accordance with the Life Cycle Maintenance Plan in Appendix B of the Consent 

Decree, maintaining a supply of designated spare parts for the compressors and associated 

equipment, and training all operators on the Decree requirements and the "O&M Plan." This 

practice, therefore, constitutes BACT for reducing the occurrence of flaring at the Facility. 

Resolute has already taken measures to further reduce compressor downtime, thereby 

minimizing flaring, by installing a fifth electric-powered compressor/engine at the McElmo 

facility in 2007. This compressor is a 2,500 horsepower, four-stage, five cylinder unit 

(designated as C5) with total installed costs of $5,459,950. This significant expenditure to 

further increase compressor reliability is indicative of Resolute’s intent to minimize flaring. 
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Table 4-1. BACT Determinations for Flare VOC Emissions 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Othe

Exxon Mobil Salt Creek Gas Plant 

Kent County, TX 

2 Flares Not provided VOC 42.82 lb/hr, each 

156.31 tpy, combined 

None listed – Notes flare as VOC control device,with 98% efficiency 

BAC

Conoco, Inc. Ponca City Refinery 

Kay County, OK 

1 Flare 0.20 lb/MMbtu – 

no further detail provided 

VOC 0.14 lb/MMbtu Good combustion practice BAC

Valero Refining Co. Corpus Christi Refinery 

Nueces County, TX 

Main Flare – 2 groups of equipment vents to flare 

Not provided VOC 226 lb/hr 

39.6 tpy, and 4,013 lb/hr 1,544 tpy (2 sets of limits) 

None listed. Notes flare as VOC control device, with 98% efficiency. Process notes indicate flare will be designed & operated per 40 CFR § 60.18. 

BAC

Duke Energy Field Services - Minden 

Webster Parish, LA 

1 Flare Not provided VOC 2.82 lb/hr 

8.73 tpy 

None listed “oth

– thiminoonly 

Orion Refining Co. St. Charles 

Parish, LA 

2 Flares 60,700,000 Btu/hr, 

each 

VOC 25.4 lb/hr, each 

16.7 tpy, each 

None listed. Notes flare as VOC control device, with 98% control efficiency. 

BAC

Flint Hills Resources LP West Refinery 

Nueces, TX Flares Not provided VOC 4,036.26 lb/hr 

2,982.09 tpy, Both “initial” caps 

None listed. “oth

Trifinery Petroleum Service Trigeant Corpus Christi 

Nueces, TX 1 Flare Not provided VOC 12.74 lb/hr 

55.79 tpy 

None listed. Notes flare as VOC control device. 

“oth

Citgo Refining & Chemicals Co LP Corpus Christi Refinery – West Plant 

Nueces, TX 1 Flare (HP) 80,000 scf/day VOC None listed “Gas- Assist” smokeless 

technology 

“oth
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Othe

Citgo Refining & Chemicals Co LP Corpus Christi Refinery – West Plant 

Nueces, TX 1 Flare (LP) 20,000 scf/day NG 

430,000 scf/day produced gas 

VOC None listed “Gas- Assist” smokeless 

technology 

“oth

BP Exploration Inc. Northstar Development Facility 

AK 1 Flare (HP) 660,000,000 scfd VOC None Gas-assist smokeless flare 

technology 

“oth

BP Exploration Inc. Northstar Development Facility 

AK 1 Flare (LP) 

Natural and Produced Gas 

18,022,000 scfd VOC None Gas-assist smokeless flare 

technology 

“oth

Mobil Exploration & Producing US, Inc. Salt Creek Gas Plant 

Kent County, TX 

Process Emergency Flare 

Not provided VOC 0.01 lb/hr 

0.01 tpy 

None listed “oth
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Table 4-2. BACT Determinations for Flare CO Emissions 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Exxon Mobil Salt Creek Gas Plant 

Kent County, TX 

2 Flares Not provided CO 37.2 lb/hr, each 

135.8 tpy, combined 

None listed BAC

Conoco, Inc. Ponca City Refinery 

Kay County, OK 

1 Flare 0.20 lb/MMbtu – 

no further detail provided 

CO 0.37 lb/MMbtu Good combustion practice BAC

Valero Refining Co. Corpus Christi Refinery 

Nueces County, TX 

Main Flare Not provided CO 472 lb/hr 

90.5 tpy 

None listed. BAC

Duke Energy Field Services - Minden 

Webster Parish, LA 

1 Flare Not provided CO 0.26 lb/hr 

1.14 tpy 

None listed “oth

– thiminoonly 

Orion Refining Co. St. Charles 

Parish, LA 

2 Flares 60,700,000 Btu/hr, 

each 

CO 149 lb/hr, each 

98.3 tpy, each 

None listed. BAC

Flint Hills Resources LP West Refinery 

Nueces, TX Flares Not provided CO 901.5 lb/hr 

2,657.98 tpy, Both “initial” caps 

None listed. “oth

Trifinery Petroleum Service Trigeant Corpus Christi 

Nueces, TX 1 Flare Not provided CO 16.3 lb/hr 

71.36 tpy 

None listed. “oth

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare 1,000,000 Btu/hr CO 0.04 lb/MMBtu None listed. “oth

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare (HP) 261,000,000 scfd CO 0.37 lb/MMBtu Proper Operation & Maintenance “oth

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare (LP) 212,000,000 scfd CO 0.37 lb/MMBtu Proper Operation & Maintenance “oth

Citgo Refining & Chemicals Co LP Corpus Christi 

Nueces, TX 1 Flare (HP) 80,000 scf/day CO None listed “Gas- Assist” smokeless 

technology 

“oth
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Refinery – West Plant Citgo Refining & Chemicals Co LP Corpus Christi Refinery – West Plant 

Nueces, TX 1 Flare (LP) 20,000 scf/day NG 

430,000 scf/day produced gas 

CO None listed “Gas- Assist” smokeless 

technology 

“oth

BP Exploration Inc. Northstar Development Facility 

AK 1 Flare (HP) 660,000,000 scfd CO None Gas-assist smokeless flare 

technology 

“oth

BP Exploration Inc. Northstar Development Facility 

AK 1 Flare (LP) 18,022,000 scfd CO None Gas-assist smokeless flare 

technology 

“oth

Mobil Exploration & Producing US, Inc. Salt Creek Gas Plant 

Kent County, TX 

1 Flare Not provided CO 1.1 lb/hr 

4.8 tpy 

None listed “oth

Equistar Chemicals, LP 

Nueces, TX 2 Flares Not provided CO 0.05 lb/hr, each 

0.23 tpy, each 

None listed. BAC
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Table 4-3. BACT Determinations for Flare NOx Emissions 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Exxon Mobil Salt Creek Gas Plant 

Kent County, TX 

2 Flares Not provided NOx 4.37 lb/hr, each 

15.85 tpy, combined 

None listed BAC

Conoco, Inc. Ponca City Refinery 

Kay County, OK 

1 Flare 0.20 lb/MMbtu – 

no further detail provided 

NOx 0.068 lb/MMbtu Limit fuel to pipeline-grade natural 

gas 

BAC

Valero Refining Co. Corpus Christi Refinery 

Nueces County, TX 

Main Flare Not provided NOx 75.8 lb/hr 

18.8 tpy 

None listed. BAC

Orion Refining Co. St. Charles 

Parish, LA 

2 Flares 60,700,000 Btu/hr, 

each 

NOx 33.6 lb/hr, each 

45.3 tpy, each 

None listed. BAC

Flint Hills Resources LP West Refinery 

Nueces, TX Flares Not provided NOx 1,409.8 lb/hr 

5,266.82 tpy, Both “initial” caps 

None listed. “oth

Trifinery Petroleum Service Trigeant Corpus Christi 

Nueces, TX 1 Flare Not provided NOx 3.2 lb/hr 

14.01 tpy 

None listed. “oth

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare 1,000,000 Btu/hr NOx 0.14 lb/MMBtu None listed. N/A 

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare (HP) 261,000,000 scfd NOx 0.068 lb/MMBtu Proper Operation & Maintenance “oth

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare (LP) 212,000,000 scfd NOx 0.068 lb/MMBtu Proper Operation & Maintenance “oth

Conoco, Inc. Lake Charles Refinery 

Calcasieu Parish, LA 

1 Flare Not provided NOx 1.2 lb/hr 

5.0 tpy 

Operate in accordance with 40 CFR § 60.18 General Control Device Requirements 

BAC

Mobil Exploration & Producing US, Inc. Salt Creek Gas Plant 

Kent County, TX 

1 Flare Not provided NOx 0.08 lb/hr 

0.4 tpy 

None listed “oth
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Equistar Chemicals, LP 

Nueces, TX 2 Flares Not provided NOx 0.01 lb/hr 

0.04 tpy 

None listed. “oth
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Table 4-4. BACT Determinations for Flare SO2 Emissions 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Exxon Mobil Salt Creek Gas Plant 

Kent County, TX 

2 Flares Not provided SO2 50.48 lb/hr, each 

184.24 tpy, combined 

None listed “oth

Conoco, Inc. Ponca City Refinery 

Kay County, OK 

1 Flare 0.20 lb/MMbtu – 

no further detail provided 

SO2 0.0006 lb/MMbtu Limit fuel to pipeline-grade natural 

gas 

BAC

Valero Refining Co. Corpus Christi Refinery 

Nueces County, TX 

Main Flare Not provided SO2 51.1 lb/hr 

12 tpy 

None listed. BAC

Orion Refining Co. St. Charles 

Parish, LA 

2 Flares 60,700,000 Btu/hr, 

each 

SO2 133 lb/hr, each 

87.6 tpy, each 

None listed. BAC

BP Exploration (Alaska) Inc. Milne Point Production Facility 

AK 1 Flare Max rate 

83,000,000 scfd Nominal rate 340,000 scfd 

SO2 500 ppm, 3-hr 

average 

Burn fuel oil with no greater than 0.3 wt% sulfur, and Burn natural gas with no greater than 100 ppmvd H2S 

SIP 

Flint Hills Resources LP West Refinery 

Nueces, TX Flares Not provided SO2 962.12 lb/hr 

118.76 tpy, Both “initial” caps 

None listed. BAC

Trifinery Petroleum Service Trigeant Corpus Christi 

Nueces, TX 1 Flare Not provided SO2 71.48 lb/hr 

263.31 tpy 

Continuous ignition with two pilots, UV fire-eye flame monitor, KO pot & seal druml; 98% control efficiency 

BAC

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare 1,000,000 Btu/hr SO2 500 ppm, 3-hr 

average 

Fuel sulfur content limits: 0.35% sulfur in diesel, 0.01% sulfur in natural gas, 0.01% sulfur in LPG, and 168 ppmv H2S in refinery gas 

BAC
BACT/LAER Clearinghouse Database Summary 

Determinations 1995 – 2005 

Industrial Flares (RBLC Report 8/4/05) 

Company Location Emission 

Source 

Throughput (Size) 

Pollutant Emission Limit Control Technology BAC

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare (HP) 261,000,000 scfd SO2 None listed Fuel sulfur content limits: 

0.15% sulfur in distillate, and 200 ppm H2S in fuel gas 

BAC

Tesoro Alaska Co Kenai Refinery 

AK 1 Flare (LP) 212,000,000 scfd SO2 None listed Fuel sulfur content limits: 

0.15% sulfur in distillate, and 200 ppm H2S in fuel gas 

“oth

Citgo Refining & Chemicals Co LP Corpus Christi Refinery – West Plant 

Nueces, TX 1 Flare (HP) 80,000 scf/day SO2 500 ppm, 3-hr 

average 

H2S content limited to 50 ppmv “oth

Citgo Refining & Chemicals Co LP Corpus Christi Refinery – West Plant 

Nueces, TX 1 Flare (LP) 20,000 scf/day NG 

430,000 scf/day produced gas 

SO2 500 ppm, 3-hr 

average 

Fuel sulfur content limits: 0.15% sulfur in fuel oil, and 50 ppmv H2S in fuel gas 

“oth

BP Exploration Inc. Northstar Development Facility 

AK 1 Flare (HP) 660,000,000 scfd SO2 500 ppm, 3-hr 

average 

H2S content of the fuel shall not 

exceed 50 ppmv 

“oth

BP Exploration Inc. Northstar Development Facility 

AK 1 Flare (LP) 18,022,000 scfd SO2 500 ppm, 3-hr 

average 

H2S content of the fuel shall not 

exceed 50 ppmvm, and Sulfur content of fuel oil shall not exceed 0.15 wt% 

“oth

Conoco, Inc. Lake Charles Refinery 

Calcasieu Parish, LA 

1 Flare Not provided SO2 0.3 lb/hr 

1.1 tpy 

None listed “oth

Mobil Exploration & Producing US, Inc. Salt Creek Gas Plant 

Kent County, TX 

1 Flare Not provided SO2 39.74 lb/hr 

174.1 tpy 

None listed Fuel limited to pipeline quality sweet natural gas with no more than 5 grains sulfur/dscf 

“oth
Item ExxonMobil Assumptions ExxonMob

DIRECT CAPITAL COSTS

1. Purchased Equipment: A) Process Changes Base Cost $12,000,000 $12,000,000 B) Instrumentation & Controls 10% of Base Cost $1,200,000 $1,800,000

In the EM estimate, 15% is the based on ExxonMobil experienbasis. The EPA cost cost conrange from 5% to 30%.

 C) Freight & Taxes 4% Taxes; 4% Freight on 1A & 1B $1,056,000 $1,104,000Total Purchased Equipment Costs (TEC): Sum of 1A, 1B and 1C $14,256,000 $14,904,0002. Installation Costs: A) Foundation & Supports 8% of TEC $1,140,480 $1,192,320 B) Erection and Handling 14% of TEC $1,995,840 $2,086,560 C) Electrical 4% of TEC $570,240 $596,160 D) Piping 5% of TEC $712,800 $745,200 E) Insulation 2% of TEC $285,120 $298,080 F) Painting 1% of TEC $142,560 $149,040 G) Site Preparation 3% of TEC $427,680 $447,120Total Installation Costs (TINC): $5,274,720 $5,514,480Total Direct Capital Costs (TDCC): Sum of TEC and TINC $19,530,720 $20,418,480

INDIRECT CAPITAL COSTS

1. Engineering & Supervision 15% of TEC $2,138,400 $2,235,6002. Construction and Field Expenses 5% of TEC $712,800 $745,2003. Contractor Fees 10% of TEC $1,425,600 $1,490,4004. Start-up 2% of TEC $285,120 $447,120 In the EM estimate, 3% is the f

on ExxonMobil experience ins

5. Performance Testing 2% of TEC $285,120 $447,120 In the EM estimate, 3% is the f

based on ExxonMobil experien

6. Government Permitting & Fees 1% of TEC $149,040 In the EM estimate, 1% is adde

and Fees based on ExxonMob

EPA Cost Control Manual

TABLE 4-5a

McElmo Gas Compression Facility

Change HOS-6 Compressor Process

Capital Cost Analysis
Item EPA Cost Control Manual ExxonMobil Assumptions ExxonMob

TABLE 4-5a

McElmo Gas Compression Facility

Change HOS-6 Compressor Process

Capital Cost Analysis

Total Indirect Capital Costs (TICC): Sum of 1, 2, 3, 4 and 5 $4,847,040 $5,514,480Total Direct & Indirect Capital Costs (TDICC): Sum of TDCC and TICC $24,377,760 $25,932,960Owners Cost $3,111,955

In the EM estimate, 12% is addExxonMobil experience to covrequired to oversee the designcommissioning contractors.

Contingency 20% of TDICC $4,875,552 $7,779,888

In the EM estimate, 30% is the based on ExxonMobil experienbasis. The EPA cost control mcost estimate (a "study estima

TOTAL CAPITAL COSTS (TCC): Sum of TDICC and Contingency $29,253,312 $36,824,803
Item ExxonMobil Assumptions Exxon

DIRECT OPERATING COSTS

1. Operating Labor 2 hr/shift @ $20/hr, 3 shifts/day, 365 days/yr $43,800 $43,8002. Supervisory Labor 15% of Operating Labor $6,570 $6,5703. Maintenance Labor & Materials 2% of TCC $585,066 $1,104,744

In the EM estimate, 3% Maintenance Labor & experience instead of 

Total Direct Operating Costs (TDOC): Sum of 1 - 9 $635,436 $1,155,114

INDIRECT OPERATING COSTS

1. Overhead 60% of Total Labor + Maintenance $381,262 $693,068Total Indirect Operating Costs (TIOC): $381,262 $693,068

CAPITAL CHARGES COSTS

1. Property Tax 1% of TCC $292,533 $368,2482. Insurance 1% of TCC $292,533 $368,2483. General Administrative 2% of TCC $585,066 $736,4964. Capital Recovery Factor CRF = 0.1061 [10% @ 30 yr.] $3,103,776 $3,907,112Total Capital Charges Costs (TCCC): Sum of 1, 2, 3 and 4 $4,273,909 $5,380,104

TOTAL ANNUALIZED OPERATING COSTS: Sum of TDOC, TIOC and TCCC $5,290,607 $7,228,286

75% control of annual SO2 emissions (.95 x 44.2 tpy) = 42.0 $125,997 per ton of SO2 removal75% control of annual CO emissions (.95 x 135.1 tpy) = 128.3 $41,222 per ton of CO removal75% control of annual NOx emissions (.95 x 24.8 tpy) = 23.6 $224,559 per ton of NOx removal75% control of annual VOC emissions (.95 x 151.8 tpy) = 144.2 $36,687 per ton of VOC removal

EPA Cost Control Manual

TABLE 4-5b

McElmo Gas Compression Facility

Change HOS-6 Compressor Process

Operating Cost Analysis
Item ExxonMobil Assumptions ExxonMob

DIRECT CAPITAL COSTS

1. Purchased Equipment: A) Process Changes Base Cost $10,000,000 $10,000,000 B) Instrumentation & Controls 10% of Base Cost $1,000,000 $1,500,000

In the EM estimate, 15% is the based on ExxonMobil experienbasis. The EPA cost cost conrange from 5% to 30%.

 C) Freight & Taxes 4% Taxes; 4% Freight on 1A & 1B $880,000 $920,000Total Purchased Equipment Costs (TEC): Sum of 1A, 1B and 1C $11,880,000 $12,420,0002. Installation Costs: A) Foundation & Supports 8% of TEC $950,400 $993,600 B) Erection and Handling 14% of TEC $1,663,200 $1,738,800 C) Electrical 4% of TEC $475,200 $496,800 D) Piping 5% of TEC $594,000 $621,000 E) Insulation 2% of TEC $237,600 $248,400 F) Painting 1% of TEC $118,800 $124,200 G) Site Preparation 3% of TEC $356,400 $372,600Total Installation Costs (TINC): $4,395,600 $4,595,400Total Direct Capital Costs (TDCC): Sum of TEC and TINC $16,275,600 $17,015,400

INDIRECT CAPITAL COSTS

1. Engineering & Supervision 15% of TEC $1,782,000 $1,863,0002. Construction and Field Expenses 5% of TEC $594,000 $621,0003. Contractor Fees 10% of TEC $1,188,000 $1,242,0004. Start-up 2% of TEC $237,600 $372,600 In the EM estimate, 3% is the f

on ExxonMobil experience ins

5. Performance Testing 2% of TEC $237,600 $372,600 In the EM estimate, 3% is the f

based on ExxonMobil experien

6. Government Permitting & Fees 1% of TEC $124,200 In the EM estimate, 1% is adde

and Fees based on ExxonMob

EPA Cost Control Manual

TABLE 4-6a

McElmo Gas Compression Facility

Replace HOS-6 Compressor

Capital Cost Analysis
Item EPA Cost Control Manual ExxonMobil Assumptions ExxonMob

TABLE 4-6a

McElmo Gas Compression Facility

Replace HOS-6 Compressor

Capital Cost Analysis

Total Indirect Capital Costs (TICC): Sum of 1, 2, 3, 4 and 5 $4,039,200 $4,595,400Total Direct & Indirect Capital Costs (TDICC): Sum of TDCC and TICC $20,314,800 $21,610,800Owners Cost $2,593,296

In the EM estimate, 12% is addExxonMobil experience to covrequired to oversee the designcommissioning contractors.

Contingency 20% of TDICC $4,062,960 $6,483,240

In the EM estimate, 30% is the based on ExxonMobil experienbasis. The EPA cost control mcost estimate (a "study estima

TOTAL CAPITAL COSTS (TCC): Sum of TDICC and Contingency $24,377,760 $30,687,336
Item ExxonMobil Assumptions Exxon

DIRECT OPERATING COSTS

1. Operating Labor 2 hr/shift @ $20/hr, 3 shifts/day, 365 days/yr $43,800 $43,8002. Supervisory Labor 15% of Operating Labor $6,570 $6,5703. Maintenance Labor & Materials 2% of TCC $487,555 $920,620

In the EM estimate, 3% Maintenance Labor & experience instead of 

Total Direct Operating Costs (TDOC): Sum of 1 - 9 $537,925 $970,990

INDIRECT OPERATING COSTS

1. Overhead 60% of Total Labor + Maintenance $322,755 $582,594Total Indirect Operating Costs (TIOC): $322,755 $582,594

CAPITAL CHARGES COSTS

1. Property Tax 1% of TCC $243,778 $306,8732. Insurance 1% of TCC $243,778 $306,8733. General Administrative 2% of TCC $487,555 $613,7474. Capital Recovery Factor CRF = 0.1061 [10% @ 30 yr.] $2,586,480 $3,255,926Total Capital Charges Costs (TCCC): Sum of 1, 2, 3 and 4 $3,561,591 $4,483,420

TOTAL ANNUALIZED OPERATING COSTS: Sum of TDOC, TIOC and TCCC $4,422,271 $6,037,004

75% control of annual SO2 emissions (.95 x 44.2 tpy) = 42.0 $105,317 per ton of SO2 removal75% control of annual CO emissions (.95 x 135.1 tpy) = 128.3 $34,456 per ton of CO removal75% control of annual NOx emissions (.95 x 24.8 tpy) = 23.6 $187,703 per ton of NOx removal75% control of annual VOC emissions (.95 x 151.8 tpy) = 144.2 $30,665 per ton of VOC removal

EPA Cost Control Manual

TABLE 4-6b

McElmo Gas Compression Facility

Replace HOS-6 Compressor

Operating Cost Analysis
Item ExxonMobil Assumptions ExxonMob

DIRECT CAPITAL COSTS

1. Purchased Equipment: A) Equipment Base Cost $11,300,000 $11,300,000 B) Instrumentation & Controls 10% of Base Cost $1,130,000 $1,695,000

In the EM estimate, 15% is the based on ExxonMobil experienbasis. The EPA cost cost conrange from 5% to 30%.

 C) Freight & Taxes 4% Taxes; 4% Freight on 1A & 1B $994,400 $1,039,600Total Purchased Equipment Costs (TEC): Sum of 1A, 1B and 1C $13,424,400 $14,034,6002. Installation Costs: A) Foundation & Supports 8% of TEC $1,073,952 $1,122,768 B) Erection and Handling 14% of TEC $1,879,416 $1,964,844 C) Electrical 4% of TEC $536,976 $561,384 D) Piping 5% of TEC $671,220 $701,730 E) Insulation 2% of TEC $268,488 $280,692 F) Painting 1% of TEC $134,244 $140,346 G) Site Preparation 3% of TEC $402,732 $421,038Total Installation Costs (TINC): $4,967,028 $5,192,802Total Direct Capital Costs (TDCC): Sum of TEC and TINC $18,391,428 $19,227,402

INDIRECT CAPITAL COSTS

1. Engineering & Supervision 15% of TEC $2,013,660 $2,105,1902. Construction and Field Expenses 5% of TEC $671,220 $701,7303. Contractor Fees 10% of TEC $1,342,440 $1,403,4604. Start-up 2% of TEC $268,488 $421,038 In the EM estimate, 3% is the f

on ExxonMobil experience ins

5. Performance Testing 2% of TEC $268,488 $421,038 In the EM estimate, 3% is the f

based on ExxonMobil experien

6. Government Permitting & Fees 1% of TEC $140,346 In the EM estimate, 1% is adde

and Fees based on ExxonMob

EPA Cost Control Manual

TABLE 4-7a

McElmo Gas Compression Facility

Flare Gas Recovery System

Capital Cost Analysis
Item EPA Cost Control Manual ExxonMobil Assumptions ExxonMob

TABLE 4-7a

McElmo Gas Compression Facility

Flare Gas Recovery System

Capital Cost Analysis

Total Indirect Capital Costs (TICC): Sum of 1, 2, 3, 4 and 5 $4,564,296 $5,192,802Total Direct & Indirect Capital Costs (TDICC): Sum of TDCC and TICC $22,955,724 $24,420,204Owners Cost $2,930,424

In the EM estimate, 12% is addExxonMobil experience to covrequired to oversee the designcommissioning contractors.

Contingency 20% of TDICC $4,591,145 $7,326,061

In the EM estimate, 30% is the based on ExxonMobil experienbasis. The EPA cost control mcost estimate (a "study estima

TOTAL CAPITAL COSTS (TCC): Sum of TDICC and Contingency $27,546,869 $34,676,690
Item ExxonMobil Assumptions Exxon

DIRECT OPERATING COSTS

1. Operating Labor 2 hr/shift @ $20/hr, 3 shifts/day, 365 days/yr $43,800 $43,8002. Supervisory Labor 15% of Operating Labor $6,570 $6,5703. Maintenance Labor & Materials 2% of TCC $550,937 $1,040,301

In the EM estimate, 3% Maintenance Labor & experience instead of 

Total Direct Operating Costs (TDOC): Sum of 1 - 9 $601,307 $1,090,671

INDIRECT OPERATING COSTS

1. Overhead 60% of Total Labor + Maintenance $360,784 $654,402Total Indirect Operating Costs (TIOC): $360,784 $654,402

CAPITAL CHARGES COSTS

1. Property Tax 1% of TCC $275,469 $346,7672. Insurance 1% of TCC $275,469 $346,7673. General Administrative 2% of TCC $550,937 $693,5344. Capital Recovery Factor CRF = 0.1061 [10% @ 30 yr.] $2,922,723 $3,679,197Total Capital Charges Costs (TCCC): Sum of 1, 2, 3 and 4 $4,024,598 $5,066,264

TOTAL ANNUALIZED OPERATING COSTS: Sum of TDOC, TIOC and TCCC $4,986,689 $6,811,337

75% control of annual SO2 emissions (.75 x 44.2 tpy) = 33.2 $150,428 per ton of SO2 removal75% control of annual CO emissions (.75 x 135.1 tpy) = 101.3 $49,215 per ton of CO removal75% control of annual NOx emissions (.75 x 24.8 tpy) = 18.6 $268,102 per ton of NOx removal75% control of annual VOC emissions (.75 x 151.8 tpy) = 113.9 $43,801 per ton of VOC removal

EPA Cost Control Manual

TABLE 4-7b

McElmo Gas Compression Facility

Flare Gas Recovery System

Operating Cost Analysis
5-1 

5.0 EXISTING ENVIRONMENT 

5.1 TOPOGRAPHY

The McElmo Creek Oil Production Facility is located on Navajo Nation land in southeastern 

Utah, in San Juan County, near the town of Aneth. The gas compression facility is located 

approximately 23 km (14 miles) northwest of the Utah / Colorado border and 4.8 km (3 miles) 

north of State Highway 262. Arches National Park and Canyonlands National Park are located 

to the northwest, approximately 160 km (100 miles) and 96 km (60 miles), respectively. Mesa 

Verde National Park is located approximately 60 km (38 miles) east of the gas compression 

facility site. The western boundary of the Canyon of the Ancients National Monument is 

approximately 16 km (10 miles) northwest of the plant site. 

Elevations around the gas compression plant range from 5,500 feet to 5,900 feet. Terrain 

generally increases in both the north and south directions from the east-west valley formed by 

the San Juan River. Ground cover is relatively sparse because of the semiarid climatic 

conditions surrounding the gas compression facility site. 

5.2 AIR QUALITY

Background air quality monitoring data for 1999-2003 are presented in Table 5-1 for ozone (O3), 

nitrogen dioxide (NO2), carbon monoxide (CO), and sulfur dioxide (SO2). Ozone concentrations 

are cited as surrogate for VOC impacts because VOCs do not have an ambient air quality 

standard; rather, VOC is considered a contributor to the formation of O3. 

No site or area-specific data was available for southeastern Utah for NO2, CO, SO2 and O3; 

therefore, air quality data gathered from monitoring stations located in north central Utah, 

primarily within the Salt Lake City metropolitan area, are used as conservative indicators of air 

quality for this rural area of Utah. Background PM10 concentrations are not addressed since 

PM10 emissions are insignificant from a flare, and the Consent Decree does not cite emission 

limits for PM10. 
5-2 

Table 5-1. 

Air Quality in the McElmo Creek Area.

Pollutant Monitor 

Location/County1 Year Averaging Period Maximum 

ppm/μg/m3

Annual Mean 

ppm / μg/m3

NAAQS

ppm 

μg/m3

Ozone (O3) 

Spanish Fork/Utah 

Spanish Fork/Utah 

Spanish Fork/Utah 

Spanish Fork/Utah 

Spanish Fork/Utah 

1999 

2000 

2001 

2002 

2003 

8 hour 

8 hour 

8 hour 

8 hour 

8 hour 

0.102 / 200

0.100 / 196 

0.081 / 159

0.081 / 159 

0.080 / 157

0.08 2

157 

Nitrogen Dioxide 

(NO2) 

North Provo/Utah 

North Provo/Utah 

North Provo/Utah 

North Provo/Utah 

North Provo/Utah 

1999 

2000 

2001 

2002 

2003 

Annual 

Annual 

Annual 

Annual 

Annual 

0.024 / 45

0.024 / 45 

0.024 / 45 

0.025 / 47

0.022 / 41

0.053 

100 

Carbon Monoxide 

(CO) 

North Provo/Utah 

North Provo/Utah 

North Provo/Utah 

North Provo/Utah 

North Provo/Utah 

1999 

2000 

2001 

2002 

2003 

8 hours 

8 hours 

8 hours 

8 hours 

8 hours 

5 / 5,726

4 / 4,581

4 / 4,581

4 / 4,581

3 / 3,436

35 

40,000 

Sulfur Dioxide 

(SO2) 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

1999 

2000 

2001 

2002 

2003 

3 hours 

3 hours 

3 hours 

3 hours 

3 hours 

0.033 / 86

0.042 / 110

0.041 / 107

0.052 / 136

0.036 / 94

No data 

No data 

No data 

No data 

No data 

0.50 

1,300 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

North Salt Lake/Salt Lake 

1999 

2000 

2001 

2002 

2003 

24 hours 

24 hours 

24 hours 

24 hours 

24 hours 

0.012 / 31

0.014 / 37

0.013 / 34

0.010 / 26

0.015 / 39

No data 

No data 

No data 

No data 

No data 

0.14 

365 

1. No site-specific data is available. These monitoring locations provide the closest available data. 

2. To attain this standard, the 3-year average of the fourth-highest daily maximum 8-hour average ozone concentrations 

measured at each monitor within an area over each year must not exceed 0.08 ppm. 

This table shows that with the exception of ozone, all pollutants are well below the National 

Ambient Air Quality Standards (NAAQS). Note that compliance with the 8-hour ozone NAAQS 

is based on the 3-year average of the 4th highest daily maximum value; Table 5-1 presents only 

the 1st highest ozone value for each year and cannot directly be compared to the 8-hour ozone 

standard. However, these concentrations represent maximum worst-case background conditions 

as an indicator of potential compliance with the ozone NAAQS. 

5.3 AREA CLIMATE AND METEOROLOGY

The southeastern area of the state, where the McElmo Creek facility is located, can be 

characterized as an area of low precipitation, high summer temperatures, and moderate winter 

temperatures. Meteorological monitoring has not been conducted onsite at the McElmo Creek 

facility. The nearest meteorological monitoring station with available data is located by 
5-3 

International Uranium Corporation’s White Mesa Mill near Blanding, Utah. This data can be 

considered as representative of the southeastern Utah area. The annual 2004 wind frequency 

distribution is presented in Table 5-2, and graphically as a wind rose in Figure 5-1. The average 

wind speed for 2004 was 3.4 meters/second (m/s), or 7.6 miles per hour (mph). The predominant 

wind directions were from the north-northeast (15.5%), from the north (11%), and from the 

south-southwest (10.8%). Annual atmospheric stability distribution for 2004 is in Table 5-3. 

Table 5-3. Annual Stability Class Distribution at Blanding, Utah. 

Stability Class Percent of Occurrence (%) 

A 15.2 

B 10.1 

C 12.2 

D 36.0 

E 13.2 

F 13.3 

Temperature and precipitation conditions in vicinity of the McElmo Gas Compression Facility 

are depicted by a long-term climatic monthly summary (12/8/1904 – 3/31/2005) of data from 

Blanding, Utah in Table 5-4. 

Table 5-4. Monthly Average Temperature and Total Precipitation at Blanding, Utah.

Month Avg. Temp. 

Max. (o

F) 

Avg. Temp. 

Min. (oF) 

Avg. Temp. 

Mean (oF) 

Precipitation Total 

(inches) 

January 39.1 17.1 28.1 1.39 

February 44.8 22.3 33.6 1.23 

March 52.7 27.8 40.3 1.04 

April 62.2 34.3 49.3 0.87 

May 72.2 42.0 57.1 0.71 

June 83.3 50.7 67.0 0.45 

July 88.6 57.8 72.2 1.15 

August 86.2 56.1 71.1 1.39 

September 78.2 48.3 63.3 1.28 

October 66.0 37.9 51.9 1.45 

November 51.4 26.6 41.0 1.06 

December 41.1 19.1 30.1 1.35 

Annual Avg. Temp./Annual Total Precip. 63.8 36.7 50.3 13.35 
5-4 

5.4 SOILS AND VEGETATION

Soils within this area of Utah have textural, depth, and drainage characteristics that limit the 

amount of water the soils can hold and make available for plant growth. Vegetation in the 

vicinity of the project area is sparse, predominantly sagebrush with scattered grasses and forbs. 

No listed threatened or endangered plant species are known to occur within the project area. 
Table 5-2 

 10 METER WIND DATA ANALYSIS 

 FROM 1/ 1/2004 THROUGH 12/31/2004 

 INTERNATIONAL URANIUM METEOROLOGICAL STATION 

 FREQUENCY OF OCCURRENCE OF WIND SPEED BY DIRECTION 

 +----------WIND SPEED CLASSES (M/S)----------+ 

 AVERAGE 

 0.0- 1.8- 3.3- 5.4 8.4 > WIND 

 DIR 1.8 3.3 5.4 8.4 11.0 11.0 TOTAL SPEED 

------------------------------------------------------------------------- 

 N .0141 .0514 .0388 .0052 .0004 .0000 0.110 3.2 

 NNE .0216 .0895 .0360 .0028 .0012 .0001 0.151 2.9 

 NE .0231 .0370 .0098 .0018 .0005 .0000 0.072 2.5 

 ENE .0124 .0121 .0043 .0013 .0000 .0000 0.030 2.4 

 E .0082 .0072 .0031 .0008 .0000 .0000 0.019 2.5 

 ESE .0085 .0091 .0024 .0012 .0000 .0000 0.021 2.4 

 SE .0097 .0186 .0095 .0028 .0002 .0000 0.041 3.4 

 SSE .0108 .0242 .0112 .0018 .0006 .0000 0.049 2.9 

 S .0100 .0375 .0254 .0079 .0014 .0000 0.082 3.5 

 SSW .0073 .0352 .0376 .0199 .0057 .0020 0.108 4.4 

 SW .0073 .0227 .0197 .0170 .0026 .0011 0.070 4.3 

 WSW .0054 .0134 .0109 .0105 .0020 .0001 0.042 4.3 

 W .0064 .0109 .0098 .0082 .0004 .0004 0.036 3.9 

 WNW .0071 .0117 .0078 .0033 .0000 .0000 0.030 3.2 

 NW .0087 .0179 .0162 .0095 .0017 .0000 0.054 3.9 

 NNW .0110 .0218 .0322 .0164 .0026 .0002 0.084 4.1 

------------------------------------------------------------------------- 

 TOT: 0.172 0.420 0.275 0.110 0.019 0.004 1.000 

 AVG: 1.4 2.6 4.2 6.7 9.4 12.0 3.4 

 TOTAL NUMBER OF VALID READINGS FOR THIS TABLE => 8456 

 OUT OF 8456 TOTAL VALID HOURS 

 TOTAL NUMBER OF MISSING HOURS => 328 

 TOTAL NUMBER OF CALM HOURS => 41 
WRPLOT View - Lakes Environmental Software

White Mesa Mill - Blanding, Utah

DATE:

1/19/2005

PROJECT NO.:

1721-03

COMMENTS:

PREPARED BY:

McVehil-Monnett 

Associates

COMPANY:

International Uranium Corporation

NORTH

SOUTH

WEST EAST

4%

8%

12%

16%

20%

WIND SPEED

(m/s)

>= 11.1

8.8 - 11.1

5.7 - 8.8

3.6 - 5.7

2.1 - 3.6

0.5 - 2.1

Calms: 0.15%

TOTAL COUNT:

8456 hrs.

CALM WINDS:

0.15%

DATA PERIOD:

2004 

Jan 1 - Dec 31

00:00 - 23:00

AVG. WIND SPEED:

3.43 m/s

 Wind Speed

Direction (blowing from)
6-1 

6.0 IMPACT ASSESSMENT APPROACH

This section presents the methodology used to evaluate the potential ambient air quality impacts 

resulting from the operation of the Main Flare. These analyses are compared against the 

National Ambient Air Quality Standards (NAAQS) and PSD increments presented in Table 6-1. 

TABLE 6-1 

SUMMARY OF NATIONAL AMBIENT AIR QUALITY 

STANDARDS AND PSD INCREMENTS 

 

 NAAQS Class II PSD 

 Averaging Primary Increment 

Pollutant Time μg/m3

 (ppm) μg/m3 (ppm)

1-houra Carbon Monoxide 40,000 (35) -- 

8-houra

 10,000 (9) -- 

Nitrogen Dioxide Annual (arith. mean) 100 (0.05) 25 (0.013) 

Ozone 8-Hourb (0.08) -- 

24-houra Particulates (PM10) 150 (--) 30 (--) 

Annual (arith. mean) 50 (--) 17 (--) 

3-houra 1,300 (0.50) 512 (0.20) 

24-houra 365 (0.14) 91 (0.035) 

Sulfur Dioxide 

Annual (arith. mean) 80 (0.03) 20 (0.008) 

Lead Calendar Quarter (arith. mean) 1.5 (--) -- 

a. Not to be exceeded more than once per year. 

b. The 3-year average of the 4th highest daily maximum concentrations must not exceed this standard. 
6-2 

6.1 AIR QUALITY MODEL DESCRIPTION

SCREEN3 is an EPA-approved screening model for estimating near-field impacts from a single 

emission source or group of emission sources that can be characterized from one location. 

SCREEN3 utilizes Gaussian dispersion to estimate concentrations within a plume, with 

maximum impacts estimated at the plume centerline. Version 96043 of SCREEN3 was used for 

this application. 

SCREEN3 transport is assumed to instantaneously occur at specified receptor distances from the 

source with specific dispersion dependent upon the atmospheric stability class, using Pasquill 

stability categories and wind speed. The intended use of SCREEN3 is for short-term averaging 

periods on the order of one hour or less. However, estimated maximum short-term impacts can 

be extrapolated to longer averaging periods by adjustment factors referenced from the 

“Screening Procedures for Estimating the Air Quality Impact of Stationary Sources” (EPA, 

1992). These factors are intended to account for long-term wind direction meander as 

summarized below: 

Averaging Time Multiplying Factor

 3 hours 0.9 

 8 hours 0.7 

 24 hours 0.4 

 Annual 0.08 

The SCREEN3 model is most suitable for estimating concentrations for distances greater than 

100 meters from the source and for source plume heights less than 300 meters. In addition, 

SCREEN3 internally examines a full range of meteorological conditions, representative of 

possibly occurring stability class and wind speed combinations to find maximum impacts. 

The SCREEN3 model also simulates the effects of buoyancy-induced dispersion (BID). The 

inclusion of BID in SCREEN3 can affect estimated concentrations, depending on the source and 

distance. For sources with plume heights below 300 meters, the effect of BID on estimated 

maximum concentrations will usually be less than about ± 10 percent. For elevated sources with 

relatively large buoyancy, the inclusion of BID may be expected to decrease the estimated 

maximum concentration by as much as 25 percent. 
6-3 

6.2 MODEL INPUT 

The Main Flare is a point (stack) source that routinely operates in the stand-by mode as reflected 

in the annual emissions presented as limits in Section 3. For modeling purposes, particularly for 

comparison to short-term standards and PSD increments, the worst-case impacts from the Main 

Flare would be during an upset episode when all process gas is sent to the flare, rather than reinjected into the ground. Thus, modeled flare stack parameters were based on using the 

buoyancy flux algorithm in SCREEN3. This algorithm estimates an effective stack diameter at 

an assumed stack velocity of 20 m/s at the estimated heat release (in calories per second) of the 

flare when combusting all process gas that would otherwise be re-injected. 

Modeling was performed to estimate impacts of NO2, CO and SO2 only, since PM10 emissions 

are insignificant and VOCs are not modeled directly except as a precursor to ozone. The annual 

emission limit for VOCs (95.4 tons per year) is below the 100 ton per year criterion typically 

cited as that level requiring ozone modeling. 

Refer to Section 6.4 for additional information about source characteristics and emission rates 

used in the model input. 

6.3 METEOROLOGICAL DATA

The selection of an appropriate meteorological data set for air quality modeling is based on 

proximity to the project site, similarity of topography and conformity of the data collection and 

reporting procedures to PSD monitoring requirements. Another consideration is that the 

meteorological data can be readily processed into a format compatible for use in air dispersion 

modeling. 

For this screening model application, the full array of 44 discrete meteorological conditions 

internally generated by SCREEN3 was used to estimate potential worst-case short-term (i.e., 

one-hour averaged) impacts for each modeled pollutant. The maximum impact cited by 

SCREEN3 from a specific discrete meteorological condition (wind speed, stability class and 

mixing height combination) and receptor distance was used as the basis for estimating maximum 

pollutant impacts. The maximum one-hour impact for each pollutant was extrapolated to values 
6-4 

for each averaging period for which a pollutant has an applicable NAAQS and PSD increment, 

using the adjustment factors referenced in Section 6.1. 

6.4 SOURCE CHARACTERISTICS AND EMISSION RATES

6.4.1 Flare Rate and Heat Release 

Short-term pollutant emission rates were estimated by assuming that the maximum volume of 

process gas that could be generated from the well field would be sent to the flare at four different 

heat content values (in BTU/SCF). These four heat content values represent a range of estimates 

including the lowest allowable LHV, the lowest LHV from 2004 gas analyses, the lowest LHV 

from 2005-08 gas analyses and the highest LHV from 2005-08 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 McElmo. (The four analyses are dated 4/28/04, 5/27/04, 

8/29/04, and 9/29/04; and their LHV values were 443, 505, 512, and 453 BTU/scf, respectively.) 

The LHV of 443 BTU/scf was utilized due to the assumption that it would provide the least 

amount of heat rise, thus producing the lowest effective release height. The lowest and highest 

LHVs from 2005-08 gas analyses data of 538.8 and 682.4 BTU/scf, respectively, were also used 

for emission estimation. The resultant range of BTU contents and effective release heights were 

modeled to evaluate the sensitivity of impacts to each emission rate/effective release height 

combination. 

The maximum flare rate utilized was 689,423 acf/hr (618,104 scf/hr), which assumes that the 

flare is operating at 14.83 MCFD for the entire year. The flare rate value of 618,104 scf/hr was 

based on the assumption that the new flare tip will be 24 inches in diameter and will have a flare 

tip exit velocity of 64.74 ft/s. This exit velocity is below the maximum exit velocity as specified 

by 40 CFR 60.18, which is 66.98 ft/s. 

The heat released from the flare tip was then calculated and converted to a rate of calories per 

second based on the conversion of 1 BTU = 252.1644 calories. The equation used for this 

calculation is as follows: 
6-5 

s

LHV V cal heat cal s

3600

( )( )(252.1644 ) ( / ) =

 Where: 

 LHV = lower heating value of gas burned (BTU/scf) 

 V = 618,104 scf/hr. 

6.4.2 Flare Height 

The actual flare stack height of 195 feet was taken from drawing D-SA-107 as provided by 

Zeeco, Inc. from 1991. This measurement was field verified to ensure proper stack height. 

6.4.3 Modeled Emission Rates 

The emission factors for NOx and CO were derived by the Chemical Section of the Texas 

Commission on Environmental Quality NSR Division based on data published in the 1983 

Chemical Manufacturer's Association document entitled "A Report On A Flare Efficiency 

Study." The factors used were as follows: 

 NOx = 0.0641 lb/MMBTU 

 CO = 0.5496 lb/MMBTU. 

Therefore, the equation used to calculate the emission rate for NOx and CO contaminants at the 

specified LHV is as follows: 

s

hr

lb

g

MMBTU

lb EF

BTU

MMBTU

scf

BTU LHV

hr

scf rate g s V

3600

* 453.59 * *

10 ( / ) * *

6 =

 Where: 

 V = 618,104 scf/hr 

 LHV = lower heating value of gas burned (BTU/scf) 

 EF = emission factor (lb/MMBTU). 
6-6 

Regarding the SO2 emission calculation, recent tests at the McElmo site indicate the plant inlet 

gas contains approximately 500 ppm H2S. However, it was assumed that the flared gas contains 

700 ppm H2S on the SCREEN3 SO2 dispersion model. This H2S value was used in order to 

provide a conservative estimate of SO2 emissions from the flare. The emission rate was 

calculated as follows: 

rate (g/s) = (618,104 scf/hr * 700 ppm * 64 lb/lb-mole SO2)/(380 scf/lb-mole * 1,000,000 ppm)= 72.87 lbSO2/hr 

In summary, the stack parameters and estimated emission rates for the Main Flare at the four 

representative heat content values during upset conditions are summarized below in Table 6-2. 

Table 6-2 

SCREEN3 Modeled Stack Parameters and Emissions for the Main Flare 

(Maximum Volumetric Process Gas Flow of 618,104 SCF/hr) 

Heat 

Content 

(BTU/SCF) 

Total Heat 

Release 

(cal/sec) 

Stack 

Height 

(m.) 

Effective 

Release 

Height (m.) 

Stack 

Velocity 

(m/s) 

Short-Term 

NOx Emission 

Rate (gm/sec) 

Short-Term 

SO2 Emission 

Rate (gm/sec) 

Short-Term 

CO Emission 

Rate (gm/sec) 

300 12,988,700 59.45 70.9117 20.0 1.50 9.18 12.84 

443 19,179,900 59.45 73.2591 20.0 2.21 9.18 18.96 

538.8 23,327,600 59.45 74.6137 20.0 2.69 9.18 23.06 

682.4 29,544,900 59.45 76.4268 20.0 3.41 9.18 29.21 

6.5 RECEPTOR SELECTION

Receptor points were generated using the automated grid option of SCREEN3, starting at 200 

meter from the Main Flare and extending out to 4,000 meters. Since the flare is a highly buoyant 

source with a stack height of nearly 60 meters, in-close impacts would be minimal and maximum 

ground-level impacts would likely be located at least one or more kilometers away from the 

stack. Receptors were placed at 100 meter intervals from 200 to 5,000 meters. 

Since terrain within 5 kilometers of the Main Flare is relatively flat, SCREEN3 was run in the 

simple terrain mode and all receptor elevations were assumed to be at the elevation of the Main 

Flare stack base. 
6-7 

6.6 CLASS I AREA IMPACTS

A telephone conversation with Mr. John Notar of the National Park Service on June 15, 2006, 

followed up by an e-mail message from Mr. Notar dated June 21, 2006, provided guidance on 

the level of detail required for the Class I area impact analysis. Mr. Notar indicated in his 

6/21/06 e-mail that estimated emissions from the flare are sufficiently small to not require a 

detailed quantitative analysis of ambient air quality and air quality related value impacts on 

nearby Class I and sensitive Class II areas. Appendix D contains documentation of Mr. Notar’s 

guidance in his 6/21/06 e-mail. 

A general discussion of ambient air quality impacts is presented based on the SCREEN3 

modeling results at a receptor distance of 50 km. away from the modeled flare emissions. The 

selection of a receptor distance of 50 km. is based on regulatory guidance stating that 50 km. is 

the furthest distance at which application of a near-field model is deemed appropriate. 

VISCREEN was used to estimate visibility impacts at the nearest Class I area, Mesa Verde 

National Park (approximately 60 km. from the McElmo Gas Compression Facility). Annual 

averaged ambient air quality impacts of NOx and SO2 based on SCREEN3 modeling were used 

to estimate deposition impacts. 

6.7 ADDITIONAL IMPACTS ANALYSIS 

EPA Region IX’s comment letter of May 22, 2006 stated that additional impacts from secondary 

growth, soils and vegetation and visibility impairment must be performed even for a source with 

small emissions. These additional impacts are addressed by: 

1. No secondary growth is associated with Main Flare operations as existing manpower 

used for operation of the McElmo Gas Compression Facility is sufficient. 

2. Soils and vegetation impacts are addressed by deposition considerations presented in 

Section 7.4.3. 

3. Visibility impairment is addressed in Section 7.4.2 and VISCREEN has been used to 

estimate visibility impacts. 
6-8 

6.8 ENDANGERED SPECIES 

The effect on threatened and endangered species and critical habitat within the region 

surrounding Aneth, Utah would be assessed if discernible effects are deemed to potentially 

occur. Mr. Henry Maddux, Utah Endangered Species Field Supervisor, was contacted to 

determine if such an effects analysis is necessary. Mr. Maddux responded via an e-mail dated 

June 29, 2006 that the Main Flare emissions addressed in the Consent Decree have no effect on 

listed species and their critical habitat in the region surrounding Aneth, Utah. Therefore, no 

further analyses of effects on endangered species and critical habitat were performed. 

Appendix D contains documentation of Mr. Maddux’s guidance in his 6/29/06 e-mail. 
7-1 

7.0 AIR QUALITY IMPACTS

This section presents modeled air quality impacts of the Main Flare facility to demonstrate 

compliance with the National Ambient Air Quality Standards (NAAQS) and Prevention of 

Significant Deterioration Increments for Class II Areas. Air quality impacts are presented from 

the Main Flare alone and combined with representative ambient air background concentrations 

for an assessment of cumulative impacts. 

As discussed in the previous section, in order to conservatively calculate emission rates from the 

Main Flare for use in this modeling analysis, several assumptions were made. Many of these 

assumptions were made with the intent of providing conservative estimates including: 

1. Consideration of a range of heat value ratings and corresponding effective release heights 

for the gas at McElmo to evaluate and identify maximum impacts produced by the 

McElmo Main Flare; 

2. The maximum design flare rate of 14.83 MCFD; and 

3. The H2S concentration of 700 ppm instead of the actual measured value of approximately 

450 ppm. 

Emission limitations established by the Consent Decree for the Main Flare are 60 tons per year 

of SO2, 73 tons per year of CO, 13.4 tons per year of NOx, and 94.5 tons per year of VOC. 

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 319.12 tons per year of SO2, 1,015.41 tons per 

year of CO, and 118.54 tons per year of NOx. These very conservative worst-case conditions 

result in emission rates in the analysis that are at least five times greater than current air permit 

limits. In addition, the actual field conditions are not capable of sustaining a flow rate of 14.83 

MCFD. The remainder of this section will show that even with these worst-case emission 

estimates that far exceed the current air permit limits and actual flow rate conditions, the 

modeling results show no exceedances of the NAAQS or the PSD Class II Increments. 

Hard copies of the SCREEN3 model run input and output are contained in Appendix B. Model 

runs for estimated NO2, CO and SO2 impacts for process gas with a heat content of 300, 443, 

538.8 and 682.4 BTU/SCF were generated. 
7-2 

7.1 NITROGEN DIOXIDE (NO2)

The Main Flare was modeled at the heat content scenarios of 300, 443, 538.8 and 682.4 

BTU/SCF. The modeled impact concentrations from SCREEN3 were multiplied by a factor 

0.75, the default ozone limiting factor, and the annual averaging period adjustment factor of 

0.08. The ozone limiting factor takes into account the conversion of NO (the majority of a NOX

release) to NO2 by reacting with ozone, assuming that approximately 75% is converted as a longterm average. A maximum background annual averaged NO2 concentration from Table 5-1 of 

47 μg/m3

 is cited as the value to add to the maximum modeled annual NO2 impact to obtain an 

estimate of cumulative impacts for comparison to the NO2 NAAQS. 

7.1.1 Increment Consumption 

Table 7-1 summarizes estimation of the maximum annual averaged NO2 impact from the Main 

Flare, with a heat content of 300, 443, 538.8 and 682.4 BTU/SCF. The resultant values from the 

Main Flare are compared to the annual NO2 PSD Class II Increment. 

Table 7-1 

Comparison of Modeled Main Flare NO2 Impacts to the PSD Increment 

 Max. Modeled Max. Adjusted 

Heat One-Hour Modeled PSD Class II Percent of 

Content Concentration Averaging Adjustment Concentration Increment Increment 

(BTU/SCF) (ug/m3) Period Factora (ug/m3) (ug/m3) (%) 

 

300 1.893 Annual 0.06 0.11 25 0.44% 

443 2.148 Annual 0.06 0.13 25 0.52% 

538.8 2.376 Annual 0.06 0.14 25 0.56% 

682.4 2.456 Annual 0.06 0.15 25 0.59% 

a. Combination of ozone limiting adjustment factor of 0.75 and the annual averaging period adjustment factor of 0.08. 

(0.75 x 0.08 = 0.06) 

The predicted maximum annual averaged concentration from the Main Flare is 0.15 μg/m3

located 1,174 meters from the flare stack. This maximum concentration is approximately only 

0.59% of the PSD Class II increment of 25 μg/m3

. In addition, the maximum annual 

concentration is only 15% of the Class II significant impact level (SIL) of 1 μg/m3

. 
7-3 

7.1.2 National Ambient Air Quality Standards (NAAQS)

Table 7-2 provides a comparison of the estimated cumulative maximum annual averaged NO2

impact from the Main Flare, with a heat content of 300, 443, 538.8 and 682.4 BTU/SCF, to the 

annual NO2 NAAQS. The modeled results are added to the cited background concentration to 

arrive at the estimated cumulative concentration, and the total value is compared to the annual 

NO2 NAAQS. 

Table 7-2. 

Comparison of Modeled Cumulative NO2 Impacts to the NAAQS 

 Max. Modeled Max. Adjusted Monitored Maximum National 

Heat One-Hour Modeled Background Cumulative Ambient Air Percent of 

Content Concentration Averaging Adjustment Concentration Concentration Concentration Quality Std. NAAQS 

(BTU/SCF) (ug/m3) Period Factor (ug/m3) (ug/m3) (ug/m3) (ug/m3) (%) 

 

300 1.893 Annual 0.06 0.11 47.00 47.11 100 47.11% 

443 2.148 Annual 0.06 0.13 47.00 47.13 100 47.13% 

538.8 2.376 Annual 0.06 0.14 47.00 47.14 100 47.14% 

682.4 2.456 Annual 0.06 0.15 47.00 47.15 100 47.15% 

The predicted maximum annual averaged concentration from the Main Flare is 0.15 μg/m3

located 1,174 meters from the flare stack. This maximum concentration, added to the 

background concentration of 47 μg/m3

, results in a cumulative concentration which is 

approximately 47.15% of the NAAQS.

7.2 SULFUR DIOXIDE (SO2)

The Main Flare was modeled at the heat content scenarios of 300, 443, 538.8 and 682.4 

BTU/SCF. The modeled impact concentrations from SCREEN3 were multiplied by the 3-hour, 

24-hour and annual averaging period adjustment factors of 0.90, 0.40 and 0.08, respectively. 

Maximum background 3-hour, 24-hour and annual averaged SO2 concentration from Table 5-1 

of 136, 39 and 39 μg/m3

 are cited as the values to add to the maximum modeled SO2 impacts 

from the Main Flare to obtain an estimate of cumulative impacts for comparison to the SO2

NAAQS. Note that the cited 24-hour background concentration has been assumed to also 
7-4 

represent the annual background concentration since no specific annual averaged monitoring 

data were available. 

7.2.1 Increment Consumption 

Table 7-3 summarizes estimation of the maximum 3-hour, 24-hour and annual averaged SO2

impacts from the Main Flare, with a heat content of 300, 443, 538.8 and 682.4 BTU/SCF. The 

resultant maximum values from the Main Flare are compared to the SO2 PSD Class II 

Increments. 

Table 7-3 

Comparison of Modeled Main Flare SO2 Impacts to the PSD Increment 

 Max. Modeled Max. Adjusted 

Heat One-Hour Modeled PSD Class II Percent of 

Content Concentration Averaging Adjustment Concentration Increment Increment 

(BTU/SCF) (ug/m3) Period Factor (ug/m3) (ug/m3) (%) 

 

300 11.63 3-hour 0.90 10.47 512 2.04% 

443 8.951 3-hour 0.90 8.06 512 1.57% 

538.8 8.108 3-hour 0.90 7.30 512 1.43% 

682.4 6.612 3-hour 0.90 5.95 512 1.16% 

300 24-hour 0.40 4.65 91 5.11% 

443 24-hour 0.40 3.58 91 3.93% 

538.8 24-hour 0.40 3.24 91 3.56% 

682.4 24-hour 0.40 2.64 91 2.90% 

300 Annual 0.08 0.93 20 4.65% 

443 Annual 0.08 0.72 20 3.60% 

538.8 Annual 0.08 0.65 20 3.25% 

682.4 Annual 0.08 0.53 20 2.65% 

The predicted maximum 3-hour, 24-hour and annual averaged concentrations from the Main 

Flare are 10.47, 4.65 and 0.93 μg/m3

, respectively, located 1,097 meters from the flare stack. 

These maximum concentrations are approximately only 2.04%, 5.11% and 4.65% of the PSD 

Class II increments of 512, 91 and 20 μg/m3

.for the 3-hour, 24-hour and annual averaging 

periods, respectively. In addition, the maximum 3-hour, 24-hour and annual concentrations are 

less than the Class II SILs of 25, 5 and 1 μg/m3

, respectively. 
7-5 

7.2.2 National Ambient Air Quality Standards (NAAQS)

Table 7-4 provides a comparison of the estimated cumulative maximum 3-hour, 24-hour and 

annual averaged SO2 impacts from the Main Flare, with a heat content of 300, 443, 538.8 and 

682.4 BTU/SCF, to the corresponding SO2 NAAQS. The modeled results are added to the cited 

background concentrations to arrive at the estimated cumulative concentration for each 

averaging time, and the total value is compared to the 3-hour, 24-hour and annual SO2 NAAQS. 

Table 7-4. 

Comparison of Modeled Cumulative SO2 Impacts to the NAAQS 

 Max. Modeled Max. Adjusted Monitored Maximum National 

Heat One-Hour Modeled Background Cumulative Ambient Air Percent of 

Content Concentration Averaging Adjustment Concentration Concentration Concentration Quality Std. NAAQS 

(BTU/SCF) (ug/m3) Period Factor (ug/m3) (ug/m3) (ug/m3) (ug/m3) (%) 

 

300 11.63 3-hour 0.90 10.47 136 146.47 1300 11.27% 

443 8.951 3-hour 0.90 8.06 136 144.06 1300 11.08% 

538.8 8.108 3-hour 0.90 7.30 136 143.30 1300 11.02% 

682.4 6.612 3-hour 0.90 5.95 136 141.95 1300 10.92% 

300 24-hour 0.40 4.65 39 43.65 365 11.96% 

443 24-hour 0.40 3.58 39 42.58 365 11.67% 

538.8 24-hour 0.40 3.24 39 42.24 365 11.57% 

682.4 24-hour 0.40 2.64 39 41.64 365 11.41% 

300 Annual 0.08 0.93 39 39.93 80 49.91% 

443 Annual 0.08 0.72 39 39.72 80 49.65% 

538.8 Annual 0.08 0.65 39 39.65 80 49.56% 

682.4 Annual 0.08 0.53 39 39.53 80 49.41% 

The predicted maximum 3-hour, 24-hour and annual averaged concentrations from the Main 

Flare are 10.47, 4.65 and 0.93 μg/m3

, respectively, located 1,097 meters from the flare stack. 

These maximum concentrations added to the background concentrations of 136, 39 and 39 μg/m3

result in cumulative concentrations of 11% to 12% of the 3-hour and 24-hour averaged NAAQS 

of 1300 and 365 μg/m3

, respectively, and approximately 50% of the annual averaged NAAQS of 

80 μg/m3

.
7-6 

7.3 CARBON MONOXIDE (CO)

The Main Flare was modeled at the heat content scenarios of 300, 443, 538.8 and 682.4 

BTU/SCF. The modeled impact concentrations from SCREEN3 were multiplied by the 1-hour 

and 8-hour averaging period adjustment factors of 1.00 and 0.70, respectively. The maximum 

background 1-hour and 8-hour averaged CO concentration from Table 5-1 of 5,726 μg/m3

 is 

cited as the value to add to the maximum modeled CO impacts from the Main Flare to obtain an 

estimate of cumulative impacts for comparison to the CO NAAQS. Note that the cited 8-hour 

background concentration has been assumed to also represent the 1-hour background 

concentration since no specific 1-hour averaged monitoring data was available. 

7.3.1 National Ambient Air Quality Standards (NAAQS)

Table 7-5 provides a comparison of the estimated cumulative maximum 1-hour and 8-hour 

averaged CO impacts from the Main Flare, with a heat content of 300, 443, 538.8 and 682.4 

BTU/SCF, to the corresponding CO NAAQS. The modeled results are added to the cited 

background concentrations to arrive at the estimated cumulative concentration for each 

averaging time, and the total value is compared to the 1-hour and 8-hour CO NAAQS. 

Table 7-5. 

Comparison of Modeled Cumulative CO Impacts to the NAAQS 

 Max. Modeled Max. Adjusted Monitored Maximum National 

Heat One-Hour Modeled Background Cumulative Ambient Air Percent of 

Content Concentration Averaging Adjustment Concentration Concentration Concentration Quality Std. NAAQS 

(BTU/SCF) (ug/m3) Period Factor (ug/m3) (ug/m3) (ug/m3) (ug/m3) (%) 

 

300 16.21 1-hour 1.00 16.21 5,726 5742.21 40,000 14.36% 

443 18.43 1-hour 1.00 18.43 5,726 5744.43 40,000 14.36% 

538.8 20.37 1-hour 1.00 20.37 5,726 5746.37 40,000 14.37% 

682.4 21.04 1-hour 1.00 21.04 5,726 5747.04 40,000 14.37% 

300 8-hour 0.70 11.35 5,726 5737.35 10,000 57.37% 

443 8-hour 0.70 12.90 5,726 5738.90 10,000 57.39% 

538.8 8-hour 0.70 14.26 5,726 5740.26 10,000 57.40% 

682.4 8-hour 0.70 14.73 5,726 5740.73 10,000 57.41% 
7-7 

The predicted maximum 1-hour and 8-hour averaged concentrations from the Main Flare are 

21.04 and 14.73 μg/m3

, respectively, located 1,174 meters from the flare stack. These maximum 

concentrations added to the background concentrations of 5,726 μg/m3

 results in cumulative 

concentrations of 14.37% of the 1-hour and 57.41% of the 8-hour averaged NAAQS of 40,000 

and 10,000 μg/m3

, respectively. 

In addition, the maximum 1-hour and 8-hour averaged concentrations of 21.04 and 14.73 μg/m3

are less than the Class II SILs of 2,000 and 500 μg/m3

, respectively. 

7.4 CLASS I AREA IMPACTS 

Modeled SCREEN3 impacts at receptors located 50 km. from the flare are used to provide the 

qualitative discussion of impacts on ambient air quality and air quality related values presented 

below. The selection of a receptor distance of 50 km. is based on regulatory guidance stating 

that 50 km. is the furthest distance at which application of a near-field model is deemed 

appropriate. 

SCREEN3 was used to estimate impacts at 50 km. from the flare with a unit emission rate of 1.0 

gm/sec at each of the four effective release heights associated with the range of modeled flare 

gas BTU contents. Since the resultant impact is for a short-term averaging period of one hour or 

less, averaging period adjustment factors described for Class II area impacts are applied to 

qualitatively estimate impacts at Class I and sensitive Class II areas located 50 km. or more from 

the McElmo Gas Compression Facility. The estimated maximum impact at 50 km. from the 

flare for a one-hour averaging period with a unit emission rate is 0.243 μg/m3

. The nearest 

Class I areas are Mesa Verde National Park, Canyonlands National Park and Arches National 

Park. The distances to these three Class I areas from the main flare are 60, 96 and 160 km., 

respectively. 

7.4.1 Class I Increments 

The maximum modeled one-hour impact at 50 km. from the flare with a unit emission rate, 

adjusted for averaging period and using pollutant-specific short-term and annualized emission 

rates, provides conservative estimates of Class I and sensitive Class II area impacts. Table 7-6 
7-8 

shows that maximum NO2 and SO2 impacts are well below applicable PSD Class I area 

increments even with assuming flare upset emissions and assessing impacts at 50 km. away. A 

print-out of the SCREEN3 model run is included in Appendix E. 

TABLE 7-6. CLASS I AREA AMBIENT AIR IMPACTS 

 

 Max. 1-hr. 3-Hour 24-Hour Annual 

 Chi/Q Class I Class I Class I 

 Impact 3-Hour Increment 24-Hour Increment Annual Increment 

Pollutant (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) 

NO2 0.243 -- -- -- -- 0.0102 2.5 

SO2 0.243 2.0142 25.0 0.8952 5.0 0.0336 2.0 

7.4.2 Visibility 

Since Mesa Verde National Park is the closest Class I area to the McElmo Gas Compression 

Facility, VISCREEN was used to estimate visibility impacts from the Main Flare. Since the 

nearest distance of Mesa Verde to the Main Flare is approximately 60 km., use of VISCREEN is 

appropriate given the closeness of this distance to the 50 km. range cited for near-field models. 

A print-out of the VISCREEN run is presented in Appendix E. 

Based on the results of the VISCREEN run, visibility impacts at Mesa Verde National Park from 

the Main Flare are less than the Level I screening thresholds. These thresholds state that plumes 

resulting from the proposed action will not cause an hourly change in extinction (∆E) greater 

than or equal to 2.0, or cause an absolute plume contrast (Cp) greater than or equal to 0.05. 

Impacts at the more distant Class I areas would even be lower. 

7.4.3 Deposition 

Sulfur (S) and nitrogen (N) deposition were conservatively assessed by using the Level I 

screening methodology presented in the IWAQM Phase 1 document, which assumes that 

concentrations of NO2 and SO2 are deposited as HNO3 and SO2. This methodology assumes that 

all NOx is converted to HNO3. Maximum annual impacts of NOX and SO2 were predicted by 

SCREEN3 at 50 km. from the Main Flare by using the SCREEN3 model results, and the 

resulting NOx impacts were then converted to HNO3. This approach provides a conservative 
7-9 

estimate of deposition, as SCREEN3 does not account for any removal of mass from the plume 

(i.e., depositional settling) during transport to the Class I areas. 

Resulting HNO3 and SO2 impacts were then multiplied by conservative depositional velocity 

rates for each pollutant to assess nitrate and sulfate deposition in Class I areas at least 50 km. 

away. Assumed depositional velocity rates are 0.05 m/s and 0.005 m/s for nitrogen and sulfur 

deposition, respectively. Initial estimates were then multiplied by two to account for both wet 

and dry deposition. Estimated nitrate and sulfate deposition are presented in Table 7-7. 

TABLE 7-7. CLASS I AREA DEPOSITION IMPACTS 

 

NO2 Conc. Nitrate Deposition SO2 Conc. Sulfate Deposition 

Class I Area (μg/m3

) (kg/ha-yr) (μg/m3) (kg/ha-yr) 

 

Any Class I Area > 50 km. away 0.01364 0.58900 0.03355 0.10581 

These conservative estimates of deposition impacts are well below any threshold effects levels 

for soils and vegetation which typically start at approximately 3.0 - 5.0 kg/ha-yr. 
8-1 

 8.0 REFERENCES

Baukal, Jr., C. (Ed.). (2001). The John Zink Combustion Handbook. CRC Press: New York. 

Consent Decree, United States of America v. Mobil Exploration & Producing, U.S., Inc., DOJ 

Case No. 90-5-2-1-2237, filed June 8, 2005 in United States District Court, District of 

Utah. 

U.S. Environmental Protection Agency, 2000. Compilation of Air Pollution Emissions Factors, 

5th Edition, AP 42, Office of Air and Radiation, Office of Air Quality Planning and 

Standards, Research Triangle Park, North Carolina. 

U.S. Environmental Protection Agency (EPA) Electronic Bulletin Board, RACT/BACT/LAER 

Clearinghouse. 
APPENDIX A 

EXXONMOBIL MCELMO CREEK OIL PRODUCTION UNIT 

CONSENT DECREE 
Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 1 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 2 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 3 of 35

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Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 7 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 8 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 9 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 10 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 11 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 12 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 13 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 14 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 15 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 16 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 17 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 18 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 19 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 20 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 21 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 22 of 35

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Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 28 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 29 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 30 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 31 of 35

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Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 33 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 34 of 35

Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 35 of 35

APPENDIX B 

DERIVATION OF ESTIMATED PRE-PROJECT AND POST-PROJECT 

ACTUAL AND POTENTIAL TO EMIT EMISSIONS
B-1 

Appendix B 

Flare Emission Calculation Methodology - McElmo Gas Compression Facility

Applicable Emission Factor Equations: 

 

Nitrogen oxides (NOx), Carbon Monoxide (CO), Particulate Matter (PM) and Lead (Pb) 

ER = V * GHV * (1000 SCF/kscf) * (MMBtu/106

 Btu) * EF * (1 ton/2000 lb) 

 ER = Pollutant Emissions, tons per year (tpy) 

 V = Volume of Gas Flared, 103

 scf per year (kscf/yr) 

 GHV = Gross Heating Value of Gas Flared, Btu/SCF 

 EF = Pollutant emission factor, lb/MMBTU 

 Table 13.5-1 (NOx and CO) and Table 1.4-2 (PM and Pb) of AP-42 

 

Volatile Organic Compounds 

(VOC) 

ER = V * (1000 SCF/kscf) * (lb-mole/ 380 SCF) * MW * WFVOC * (1 - (DEFF/100)) * (1 ton/2000 lb) 

 ER = Pollutant Emissions, tons per year (tpy) 

 V = Volume of Gas Flared, 103

 scf per year (kscf/yr) 

 MW = Molecular Weight of VOCs in Flared Gas, lb/lb-mole 

 WFVOC = Weight Fraction of VOCs in Flared Gas 

 DEFF = Percent Destruction Efficiency of Flare ==> 98.0 percent 

 

Sulfur Dioxide 

(SO2) 

ER = V * (1000 SCF/kscf) * (lb-mole/ 380 SCF) * MFH2S * MWSO2 * (DEFF/100) * (1 ton/2000 lb) 

 ER = Pollutant Emissions, tons per year (tpy) 

 V = Volume of Gas Flared, 103

 scf per year (kscf/yr) 

 MFH2S = Molar Fraction of H2S in Flared Gas 

 MWSO2 = Molecular Weight of SO2, 64 lb/lb-mole 

 DEFF = Percent Destruction Efficiency of Flare ==> 98.0 percent 

 

 Equation Inputs for Actual Emissions 

 Parameter Pre-Project Post-Project 

Name Units (1996) (2005) (Updated 2008) 

V kscf/yr 1,145,960 727,704 730,000 

GHV Btu/SCF 751.1 490.0 610.6 

MWSO2 lb/lb-mole 64.0 64.0 64.0 

MWVOC lb/lb-mole 36.9 39.1 37.9 

MFH2S unitless 0.00146 0.00049 0.0005 

WFVOC unitless 0.165 0.116 0.126 

Notes: Updated 2008 GHV based on average of 538.8 and 682.4 Btu/SCF, range of values from 2005 - 08 data; 

 Updated 2008 WFVOC based on average of .1072 and .1446, range of values from 2005-08 data 

 Updated 2008 MWVOC based on average of 37.264 and 38.535, range of values from 2005-08 data 
B-2 

 Actual Emission Estimates 

Pollutant Pre-Project Post-Project 

Name Units EF (lb/MMBtu) (1996) (2005) (Updated 2008) 

NOX tpy 0.068 29.3 12.1 15.2 

CO tpy 0.37 159.2 66.0 82.5 

PM10 tpy 0.00745 3.2 1.3 1.7 

PM2.5 tpy 0.00745 3.2 1.3 1.7 

Pb tpy 4.90E-07 0.00021 0.000087 0.000109 

VOC tpy -- 183.6 86.9 91.7 

SO2 tpy -- 138.1 29.4 30.1 

McElmo Flare Actual Emissions 

2001 – 2005 

Year Volume 

(kscf/yr) 

NOx 

(tpy) 

VOC 

(tpy) 

SO2 

(tpy) 

CO 

(tpy) 

 2001 500,591 7.47 41.97 24.03 33.27 

 2002 863,834 13.46 98.93 36.17 73.48 

 2003 891,972 13.97 108.66 46.38 71.24 

 2004 580,005 9.89 76.46 26.88 53.52 

 2005 727,703 12.10 90.60 29.20 66.00 

891,972 (maximum) x 1.2 (PTE factor) = 1,070,366 PTE Volume 

 

Equation Inputs for PTE Emissions 

 Parameter Pre-Project Post-Project 

 Name Units (1996) (2005) 

(Updated 

2008) 

 V kscf/yr 1,145,960 1,070,366 1,070,366 

 GHV Btu/SCF 751.1 445.0 682.4 

 MWSO2 lb/lb-mole 64.0 64.0 64.0 

 MWVOC lb/lb-mole 36.9 38.5 37.3 

 MFH2S unitless 0.00146 0.00063 0.0005 

 WFVOC unitless 0.165 0.120 0.145 

Notes: Updated 2008 GHV based on maximum value of 682.4 Btu/SCF from 2005 - 08 data; 

 Updated 2008 WFVOC based on maximum value of .1446 from 2005-08 data 

 Updated 2008 MWVOC based on 37.264 estimate with maximum Btu/SCF gas from 2005-08 data 

 

PTE Emission Estimates 

 Pollutant Pre-Project Post-Project 

 Name Units EF (lb/MMBtu) (1996) (2005) (Updated 2008) 

 NOX tpy 0.068 29.3 16.2 24.8 

 CO tpy 0.37 159.2 88.1 135.1 

 PM10 tpy 0.00745 3.2 1.8 2.7 

 PM2.5 tpy 0.00745 3.2 1.8 2.7 

 Pb tpy 4.90E-07 0.00021 0.00012 0.000179 

 VOC tpy -- 183.6 130.1 151.8 

 SO2 tpy -- 138.1 55.7 44.2 
APPENDIX C 

SCREEN3 MODELING INPUT AND OUTPUT RESULTS 
 10/07/05 

 19:01:54 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 NOX - McELMO CREEK MAIN FLARE - 618.104 SCF/HR; 300 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 1.50000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .129887E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 70.9117 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 215.357 M**4/S**3; MOM. FLUX = 131.320 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .1976E-03 5 1.0 2.0 10000.0 212.67 42.14 40.98 NO 

 300. .2504E-03 5 1.0 2.0 10000.0 212.67 43.89 41.43 NO 

 400. .1994E-02 1 3.0 3.4 960.0 353.43 102.30 83.27 NO 

 500. .9364E-01 1 3.0 3.4 960.0 353.43 123.67 116.05 NO 

 600. .5748 1 3.0 3.4 960.0 353.43 144.45 164.03 NO 

 700. 1.071 1 3.0 3.4 960.0 353.43 164.74 222.37 NO 

 800. 1.236 1 3.0 3.4 960.0 353.43 184.62 291.21 NO 

 900. 1.570 1 1.5 1.7 636.9 635.95 241.27 392.31 NO 

 1000. 1.831 1 1.5 1.7 636.9 635.95 262.53 480.98 NO 

 1100. 1.893 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 

 1200. 1.849 1 1.5 1.7 636.9 635.95 293.46 686.83 NO 

 1300. 1.769 1 1.5 1.7 636.9 635.95 308.54 807.14 NO 

 1400. 1.687 1 1.5 1.7 636.9 635.95 323.75 939.12 NO 

 1500. 1.611 1 1.5 1.7 636.9 635.95 339.05 1082.70 NO 

 1600. 1.541 1 1.5 1.7 636.9 635.95 354.42 1237.88 NO 

 1700. 1.477 1 1.5 1.7 636.9 635.95 369.84 1404.65 NO 

 1800. 1.417 1 1.5 1.7 636.9 635.95 385.28 1583.04 NO 

 1900. 1.363 1 1.5 1.7 636.9 635.95 400.74 1773.09 NO 

 2000. 1.312 1 1.5 1.7 636.9 635.95 416.20 1974.82 NO 

 2100. 1.265 1 1.5 1.7 636.9 635.95 431.66 2188.30 NO 

 2200. 1.221 1 1.5 1.7 636.9 635.95 447.11 2413.56 NO 
 2300. 1.181 1 1.5 1.7 636.9 635.95 462.53 2650.65 NO 

 2400. 1.143 1 1.5 1.7 636.9 635.95 477.94 2899.62 NO 

 2500. 1.107 1 1.5 1.7 636.9 635.95 493.32 3160.53 NO 

 2600. 1.074 1 1.5 1.7 636.9 635.95 508.66 3433.41 NO 

 2700. 1.042 1 1.5 1.7 636.9 635.95 523.98 3718.32 NO 

 2800. 1.013 1 1.5 1.7 636.9 635.95 539.26 4015.30 NO 

 2900. .9848 1 1.5 1.7 636.9 635.95 554.51 4324.41 NO 

 3000. .9585 1 1.5 1.7 636.9 635.95 569.72 4645.68 NO 

 3500. .9357 2 1.5 1.7 636.9 635.95 495.84 461.21 NO 

 4000. .9215 2 1.5 1.7 636.9 635.95 551.47 525.60 NO 

 4500. .8746 2 1.5 1.7 636.9 635.95 606.70 591.64 NO 

 5000. .8172 2 1.5 1.7 636.9 635.95 661.47 659.02 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1097. 1.893 1 1.5 1.7 636.9 635.95 277.95 574.19 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 5000. 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 1.893 1097. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 10/07/05 

 18:59:19 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 NOx - McELMO CREEK MAIN FLARE - 618.104 SCF/HR; 443 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 2.21000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .191799E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 73.2591 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .4666E-03 5 1.0 2.0 10000.0 234.08 47.40 46.37 NO 

 300. .5548E-03 5 1.0 2.0 10000.0 234.08 48.96 46.76 NO 

 400. .6661E-03 5 1.0 2.0 10000.0 234.08 50.95 47.20 NO 

 500. .2049E-01 1 3.0 3.4 960.0 429.40 126.59 119.17 NO 

 600. .3019 1 3.0 3.4 960.0 429.40 147.64 166.85 NO 

 700. .8718 1 3.0 3.4 960.0 429.40 168.18 224.94 NO 

 800. 1.266 1 3.0 3.4 960.0 429.40 188.30 293.55 NO 

 900. 1.755 1 2.0 2.3 640.0 607.47 228.42 384.54 NO 

 1000. 2.089 1 2.0 2.3 640.0 607.47 248.95 473.71 NO 

 1100. 2.143 1 2.0 2.3 640.0 607.47 269.15 573.82 NO 

 1200. 2.061 1 2.0 2.3 640.0 607.47 288.71 684.81 NO 

 1300. 1.969 1 2.0 2.3 640.0 607.47 304.03 805.43 NO 

 1400. 1.876 1 2.0 2.3 640.0 607.47 319.45 937.65 NO 

 1500. 1.800 1 1.5 1.7 786.5 785.55 360.99 1089.77 NO 

 1600. 1.731 1 1.5 1.7 786.5 785.55 375.46 1244.06 NO 

 1700. 1.667 1 1.5 1.7 786.5 785.55 390.04 1410.10 NO 

 1800. 1.606 1 1.5 1.7 786.5 785.55 404.72 1587.88 NO 

 1900. 1.550 1 1.5 1.7 786.5 785.55 419.46 1777.41 NO 

 2000. 1.497 1 1.5 1.7 786.5 785.55 434.26 1978.71 NO 

 2100. 1.447 1 1.5 1.7 786.5 785.55 449.09 2191.81 NO 

 2200. 1.401 1 1.5 1.7 786.5 785.55 463.96 2416.74 NO 
 2300. 1.358 1 1.5 1.7 786.5 785.55 478.84 2653.55 NO 

 2400. 1.317 1 1.5 1.7 786.5 785.55 493.74 2902.27 NO 

 2500. 1.278 1 1.5 1.7 786.5 785.55 508.64 3162.96 NO 

 2600. 1.242 1 1.5 1.7 786.5 785.55 523.54 3435.64 NO 

 2700. 1.207 1 1.5 1.7 786.5 785.55 538.43 3720.38 NO 

 2800. 1.175 1 1.5 1.7 786.5 785.55 553.32 4017.22 NO 

 2900. 1.144 1 1.5 1.7 786.5 785.55 568.18 4326.19 NO 

 3000. 1.115 1 1.5 1.7 786.5 785.55 583.04 4647.34 NO 

 3500. 1.024 2 2.0 2.3 640.0 607.47 493.05 458.20 NO 

 4000. 1.012 2 2.0 2.3 640.0 607.47 548.96 522.97 NO 

 4500. .9615 2 2.0 2.3 640.0 607.47 604.41 589.30 NO 

 5000. .9124 2 1.5 1.7 786.5 785.55 672.98 670.57 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1075. 2.148 1 2.0 2.3 640.0 607.47 263.93 546.73 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 5000. 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 2.148 1075. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
1 

 03/10/08 

 12:23:31 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 NOx McELMO CREEK MAIN FLARE - 618104 SCF/HR; 538.8 BTU 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 2.69000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .233276E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 74.6137 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 386.779 M**4/S**3; MOM. FLUX = 235.850 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .6884E-03 5 1.0 2.0 10000.0 245.91 50.30 49.34 NO 

 300. .7985E-03 5 1.0 2.0 10000.0 245.91 51.78 49.71 NO 

 400. .9341E-03 5 1.0 2.0 10000.0 245.91 53.66 50.12 NO 

 500. .7289E-02 1 3.0 3.5 960.0 474.63 128.33 121.01 NO 

 600. .1865 1 3.0 3.5 960.0 474.63 149.55 168.54 NO 

 700. .7154 1 3.0 3.5 960.0 474.63 170.23 226.48 NO 

 800. 1.209 1 3.0 3.5 960.0 474.63 190.49 294.96 NO 

 900. 1.799 1 2.0 2.3 675.6 674.64 233.15 387.37 NO 

 1000. 2.250 1 2.0 2.3 675.6 674.64 253.95 476.35 NO 

 1100. 2.376 1 2.0 2.3 675.6 674.64 274.40 576.30 NO 

 1200. 2.314 1 2.0 2.3 675.6 674.64 294.53 687.29 NO 

 1300. 2.194 1 2.0 2.3 675.6 674.64 313.89 809.20 NO 

 1400. 2.098 1 2.0 2.3 675.6 674.64 328.85 940.89 NO 

 1500. 2.006 1 2.0 2.3 675.6 674.64 343.93 1084.24 NO 

 1600. 1.921 1 2.0 2.3 675.6 674.64 359.09 1239.22 NO 

 1700. 1.843 1 2.0 2.3 675.6 674.64 374.31 1405.83 NO 

 1800. 1.771 1 2.0 2.3 675.6 674.64 389.58 1584.09 NO 

 1900. 1.704 1 2.0 2.3 675.6 674.64 404.87 1774.02 NO 

 2000. 1.642 1 2.0 2.3 675.6 674.64 420.18 1975.67 NO 

 2100. 1.584 1 2.0 2.3 675.6 674.64 435.50 2189.06 NO 

 2200. 1.530 1 2.0 2.3 675.6 674.64 450.81 2414.25 NO 

 2300. 1.480 1 2.0 2.3 675.6 674.64 466.12 2651.28 NO 

 2400. 1.433 1 2.0 2.3 675.6 674.64 481.41 2900.20 NO 

 2500. 1.389 1 2.0 2.3 675.6 674.64 496.68 3161.05 NO 

 2600. 1.348 1 2.0 2.3 675.6 674.64 511.92 3433.89 NO 

 2700. 1.309 1 2.0 2.3 675.6 674.64 527.15 3718.77 NO 

 2800. 1.272 1 2.0 2.3 675.6 674.64 542.34 4015.72 NO 

 2900. 1.238 1 2.0 2.3 675.6 674.64 557.50 4324.79 NO 

 3000. 1.205 1 2.0 2.3 675.6 674.64 572.63 4646.04 NO 
2 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1104. 2.376 1 2.0 2.3 675.6 674.64 275.01 579.47 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 3100. 1.174 1 2.0 2.3 675.6 674.64 587.73 4979.50 NO 

 3200. 1.145 1 2.0 2.3 675.6 674.64 602.79 5000.00 NO 

 3300. 1.117 1 2.0 2.3 675.6 674.64 617.82 5000.00 NO 

 3400. 1.104 2 2.0 2.3 675.6 674.64 488.10 452.26 NO 

 3500. 1.115 2 2.0 2.3 675.6 674.64 499.19 464.80 NO 

 3600. 1.122 2 2.0 2.3 675.6 674.64 510.27 477.44 NO 

 3700. 1.126 2 2.0 2.3 675.6 674.64 521.34 490.15 NO 

 3800. 1.128 2 2.0 2.3 675.6 674.64 532.40 502.95 NO 

 3900. 1.127 2 2.0 2.3 675.6 674.64 543.45 515.82 NO 

 4000. 1.123 2 2.0 2.3 675.6 674.64 554.48 528.76 NO 

 4100. 1.118 2 2.0 2.3 675.6 674.64 565.50 541.77 NO 

 4200. 1.111 2 2.0 2.3 675.6 674.64 576.51 554.85 NO 

 4300. 1.103 2 2.0 2.3 675.6 674.64 587.50 567.99 NO 

 4400. 1.093 2 2.0 2.3 675.6 674.64 598.47 581.19 NO 

 4500. 1.082 2 2.0 2.3 675.6 674.64 609.43 594.45 NO 

 4600. 1.071 2 2.0 2.3 675.6 674.64 620.38 607.77 NO 

 4700. 1.059 2 2.0 2.3 675.6 674.64 631.30 621.13 NO 

 4800. 1.047 2 2.0 2.3 675.6 674.64 642.21 634.55 NO 

 4900. 1.034 2 2.0 2.3 675.6 674.64 653.11 648.02 NO 

 5000. 1.021 2 2.0 2.3 675.6 674.64 663.98 661.54 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 3000. 

 0. 3100. -- 

 0. 3200. -- 

 0. 3300. -- 

 0. 3400. -- 

 0. 3500. -- 

 0. 3600. -- 

 0. 3700. -- 

 0. 3800. -- 

 0. 3900. -- 

 0. 4000. -- 

 0. 4100. -- 

 0. 4200. -- 
3 

 0. 4300. -- 

 0. 4400. -- 

 0. 4500. -- 

 0. 4600. -- 

 0. 4700. -- 

 0. 4800. -- 

 0. 4900. -- 

 0. 5000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 2.376 1104. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 ***************************************************
1 

 03/10/08 

 12:34:04 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 NOx - McELMO CREEK MAIN FLARE - 618104 SCF/HR; 682.4 BTU 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 3.41000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .295449E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 76.4268 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 489.864 M**4/S**3; MOM. FLUX = 298.709 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .1062E-02 5 1.0 2.0 10000.0 261.24 54.07 53.17 NO 

 300. .1201E-02 5 1.0 2.0 10000.0 261.24 55.44 53.52 NO 

 400. .1369E-02 5 1.0 2.0 10000.0 261.24 57.21 53.90 NO 

 500. .1579E-02 5 1.0 2.0 10000.0 261.24 59.31 54.33 NO 

 600. .8705E-01 1 3.0 3.5 960.0 536.60 152.15 170.85 NO 

 700. .5045 1 3.0 3.5 960.0 536.60 173.04 228.59 NO 

 800. 1.067 1 3.0 3.5 960.0 536.60 193.49 296.90 NO 

 900. 1.465 1 2.0 2.3 767.7 766.68 239.56 391.26 NO 

 1000. 2.094 1 2.0 2.3 767.7 766.68 260.73 480.00 NO 

 1100. 2.402 1 2.0 2.3 767.7 766.68 281.52 579.73 NO 

 1200. 2.451 1 2.0 2.3 767.7 766.68 301.99 690.52 NO 

 1300. 2.366 1 2.0 2.3 767.7 766.68 322.16 812.44 NO 

 1400. 2.244 1 2.0 2.3 767.7 766.68 342.05 945.58 NO 

 1500. 2.149 1 2.0 2.3 767.7 766.68 357.48 1088.61 NO 

 1600. 2.065 1 2.0 2.3 767.7 766.68 372.09 1243.05 NO 

 1700. 1.987 1 2.0 2.3 767.7 766.68 386.80 1409.21 NO 

 1800. 1.914 1 2.0 2.3 767.7 766.68 401.59 1587.09 NO 

 1900. 1.845 1 2.0 2.3 767.7 766.68 416.44 1776.70 NO 

 2000. 1.782 1 2.0 2.3 767.7 766.68 431.34 1978.07 NO 

 2100. 1.722 1 2.0 2.3 767.7 766.68 446.28 2191.23 NO 

 2200. 1.666 1 2.0 2.3 767.7 766.68 461.23 2416.22 NO 

 2300. 1.614 1 2.0 2.3 767.7 766.68 476.20 2653.07 NO 

 2400. 1.565 1 2.0 2.3 767.7 766.68 491.18 2901.84 NO 

 2500. 1.518 1 2.0 2.3 767.7 766.68 506.15 3162.56 NO 

 2600. 1.475 1 2.0 2.3 767.7 766.68 521.12 3435.28 NO 

 2700. 1.433 1 2.0 2.3 767.7 766.68 536.08 3720.04 NO 
2 

 2800. 1.395 1 2.0 2.3 767.7 766.68 551.03 4016.90 NO 

 2900. 1.358 1 2.0 2.3 767.7 766.68 565.96 4325.89 NO 

 3000. 1.323 1 2.0 2.3 767.7 766.68 580.87 4647.06 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1174. 2.456 1 2.0 2.3 767.7 766.68 296.49 659.51 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 3100. 1.290 1 2.0 2.3 767.7 766.68 595.76 4980.46 NO 

 3200. 1.258 1 2.0 2.3 767.7 766.68 610.62 5000.00 NO 

 3300. 1.229 1 2.0 2.3 767.7 766.68 625.46 5000.00 NO 

 3400. 1.200 1 2.0 2.3 767.7 766.68 640.27 5000.00 NO 

 3500. 1.173 1 2.0 2.3 767.7 766.68 655.06 5000.00 NO 

 3600. 1.147 1 2.0 2.3 767.7 766.68 669.81 5000.00 NO 

 3700. 1.123 1 2.0 2.3 767.7 766.68 684.54 5000.00 NO 

 3800. 1.105 2 2.0 2.3 767.7 766.68 541.25 512.31 NO 

 3900. 1.115 2 2.0 2.3 767.7 766.68 552.12 524.95 NO 

 4000. 1.123 2 2.0 2.3 767.7 766.68 562.99 537.67 NO 

 4100. 1.127 2 2.0 2.3 767.7 766.68 573.84 550.47 NO 

 4200. 1.130 2 2.0 2.3 767.7 766.68 584.69 563.35 NO 

 4300. 1.130 2 2.0 2.3 767.7 766.68 595.53 576.30 NO 

 4400. 1.129 2 2.0 2.3 767.7 766.68 606.36 589.31 NO 

 4500. 1.126 2 2.0 2.3 767.7 766.68 617.18 602.39 NO 

 4600. 1.121 2 2.0 2.3 767.7 766.68 627.99 615.53 NO 

 4700. 1.115 2 2.0 2.3 767.7 766.68 638.79 628.74 NO 

 4800. 1.108 2 2.0 2.3 767.7 766.68 649.57 642.00 NO 

 4900. 1.100 2 2.0 2.3 767.7 766.68 660.34 655.31 NO 

 5000. 1.091 2 2.0 2.3 767.7 766.68 671.10 668.68 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 3000. 

 0. 3100. -- 

 0. 3200. -- 

 0. 3300. -- 

 0. 3400. -- 

 0. 3500. -- 
3 

 0. 3600. -- 

 0. 3700. -- 

 0. 3800. -- 

 0. 3900. -- 

 0. 4000. -- 

 0. 4100. -- 

 0. 4200. -- 

 0. 4300. -- 

 0. 4400. -- 

 0. 4500. -- 

 0. 4600. -- 

 0. 4700. -- 

 0. 4800. -- 

 0. 4900. -- 

 0. 5000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 2.456 1174. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 10/07/05 

 18:48:51 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 CO - McELMO CREEK MAIN FLARE - 618.104 SCF/HR; 300 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 12.8400 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .129887E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 70.9117 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 215.357 M**4/S**3; MOM. FLUX = 131.320 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .1691E-02 5 1.0 2.0 10000.0 212.67 42.14 40.98 NO 

 300. .2143E-02 5 1.0 2.0 10000.0 212.67 43.89 41.43 NO 

 400. .1707E-01 1 3.0 3.4 960.0 353.43 102.30 83.27 NO 

 500. .8015 1 3.0 3.4 960.0 353.43 123.67 116.05 NO 

 600. 4.920 1 3.0 3.4 960.0 353.43 144.45 164.03 NO 

 700. 9.169 1 3.0 3.4 960.0 353.43 164.74 222.37 NO 

 800. 10.58 1 3.0 3.4 960.0 353.43 184.62 291.21 NO 

 900. 13.44 1 1.5 1.7 636.9 635.95 241.27 392.31 NO 

 1000. 15.67 1 1.5 1.7 636.9 635.95 262.53 480.98 NO 

 1100. 16.21 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 

 1200. 15.83 1 1.5 1.7 636.9 635.95 293.46 686.83 NO 

 1300. 15.14 1 1.5 1.7 636.9 635.95 308.54 807.14 NO 

 1400. 14.44 1 1.5 1.7 636.9 635.95 323.75 939.12 NO 

 1500. 13.79 1 1.5 1.7 636.9 635.95 339.05 1082.70 NO 

 1600. 13.19 1 1.5 1.7 636.9 635.95 354.42 1237.88 NO 

 1700. 12.64 1 1.5 1.7 636.9 635.95 369.84 1404.65 NO 

 1800. 12.13 1 1.5 1.7 636.9 635.95 385.28 1583.04 NO 

 1900. 11.66 1 1.5 1.7 636.9 635.95 400.74 1773.09 NO 

 2000. 11.23 1 1.5 1.7 636.9 635.95 416.20 1974.82 NO 

 2100. 10.83 1 1.5 1.7 636.9 635.95 431.66 2188.30 NO 

 2200. 10.45 1 1.5 1.7 636.9 635.95 447.11 2413.56 NO 
 2300. 10.11 1 1.5 1.7 636.9 635.95 462.53 2650.65 NO 

 2400. 9.780 1 1.5 1.7 636.9 635.95 477.94 2899.62 NO 

 2500. 9.476 1 1.5 1.7 636.9 635.95 493.32 3160.53 NO 

 2600. 9.190 1 1.5 1.7 636.9 635.95 508.66 3433.41 NO 

 2700. 8.921 1 1.5 1.7 636.9 635.95 523.98 3718.32 NO 

 2800. 8.668 1 1.5 1.7 636.9 635.95 539.26 4015.30 NO 

 2900. 8.430 1 1.5 1.7 636.9 635.95 554.51 4324.41 NO 

 3000. 8.205 1 1.5 1.7 636.9 635.95 569.72 4645.68 NO 

 3500. 8.010 2 1.5 1.7 636.9 635.95 495.84 461.21 NO 

 4000. 7.888 2 1.5 1.7 636.9 635.95 551.47 525.60 NO 

 4500. 7.487 2 1.5 1.7 636.9 635.95 606.70 591.64 NO 

 5000. 6.995 2 1.5 1.7 636.9 635.95 661.47 659.02 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1097. 16.21 1 1.5 1.7 636.9 635.95 277.95 574.19 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 5000. 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 16.21 1097. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 11/07/05 

 16:19:36 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 CO - McELMO CREEK MAIN FLARE - 618.104 SCF/HR; 443 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 18.9600 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .191799E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 73.2591 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .4003E-02 5 1.0 2.0 10000.0 234.08 47.40 46.37 NO 

 300. .4760E-02 5 1.0 2.0 10000.0 234.08 48.96 46.76 NO 

 400. .5715E-02 5 1.0 2.0 10000.0 234.08 50.95 47.20 NO 

 500. .1758 1 3.0 3.4 960.0 429.40 126.59 119.17 NO 

 600. 2.590 1 3.0 3.4 960.0 429.40 147.64 166.85 NO 

 700. 7.479 1 3.0 3.4 960.0 429.40 168.18 224.94 NO 

 800. 10.86 1 3.0 3.4 960.0 429.40 188.30 293.55 NO 

 900. 15.06 1 2.0 2.3 640.0 607.47 228.42 384.54 NO 

 1000. 17.92 1 2.0 2.3 640.0 607.47 248.95 473.71 NO 

 1100. 18.39 1 2.0 2.3 640.0 607.47 269.15 573.82 NO 

 1200. 17.68 1 2.0 2.3 640.0 607.47 288.71 684.81 NO 

 1300. 16.89 1 2.0 2.3 640.0 607.47 304.03 805.43 NO 

 1400. 16.09 1 2.0 2.3 640.0 607.47 319.45 937.65 NO 

 1500. 15.45 1 1.5 1.7 786.5 785.55 360.99 1089.77 NO 

 1600. 14.85 1 1.5 1.7 786.5 785.55 375.46 1244.06 NO 

 1700. 14.30 1 1.5 1.7 786.5 785.55 390.04 1410.10 NO 

 1800. 13.78 1 1.5 1.7 786.5 785.55 404.72 1587.88 NO 

 1900. 13.30 1 1.5 1.7 786.5 785.55 419.46 1777.41 NO 

 2000. 12.84 1 1.5 1.7 786.5 785.55 434.26 1978.71 NO 

 2100. 12.42 1 1.5 1.7 786.5 785.55 449.09 2191.81 NO 

 2200. 12.02 1 1.5 1.7 786.5 785.55 463.96 2416.74 NO 
 2300. 11.65 1 1.5 1.7 786.5 785.55 478.84 2653.55 NO 

 2400. 11.30 1 1.5 1.7 786.5 785.55 493.74 2902.27 NO 

 2500. 10.96 1 1.5 1.7 786.5 785.55 508.64 3162.96 NO 

 2600. 10.65 1 1.5 1.7 786.5 785.55 523.54 3435.64 NO 

 2700. 10.36 1 1.5 1.7 786.5 785.55 538.43 3720.38 NO 

 2800. 10.08 1 1.5 1.7 786.5 785.55 553.32 4017.22 NO 

 2900. 9.815 1 1.5 1.7 786.5 785.55 568.18 4326.19 NO 

 3000. 9.565 1 1.5 1.7 786.5 785.55 583.04 4647.34 NO 

 3500. 8.786 2 2.0 2.3 640.0 607.47 493.05 458.20 NO 

 4000. 8.679 2 2.0 2.3 640.0 607.47 548.96 522.97 NO 

 4500. 8.249 2 2.0 2.3 640.0 607.47 604.41 589.30 NO 

 5000. 7.828 2 1.5 1.7 786.5 785.55 672.98 670.57 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1075. 18.43 1 2.0 2.3 640.0 607.47 263.93 546.73 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 5000. 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 18.43 1075. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
1 

 03/10/08 

 12:28:12 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 CO - McELMO CREEK MAIN FLARE - 618104 SCF/HR; 538.8 BTU 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 23.0600 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .233276E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 74.6137 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 386.779 M**4/S**3; MOM. FLUX = 235.850 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .5902E-02 5 1.0 2.0 10000.0 245.91 50.30 49.34 NO 

 300. .6845E-02 5 1.0 2.0 10000.0 245.91 51.78 49.71 NO 

 400. .8008E-02 5 1.0 2.0 10000.0 245.91 53.66 50.12 NO 

 500. .6249E-01 1 3.0 3.5 960.0 474.63 128.33 121.01 NO 

 600. 1.599 1 3.0 3.5 960.0 474.63 149.55 168.54 NO 

 700. 6.133 1 3.0 3.5 960.0 474.63 170.23 226.48 NO 

 800. 10.37 1 3.0 3.5 960.0 474.63 190.49 294.96 NO 

 900. 15.43 1 2.0 2.3 675.6 674.64 233.15 387.37 NO 

 1000. 19.29 1 2.0 2.3 675.6 674.64 253.95 476.35 NO 

 1100. 20.37 1 2.0 2.3 675.6 674.64 274.40 576.30 NO 

 1200. 19.84 1 2.0 2.3 675.6 674.64 294.53 687.29 NO 

 1300. 18.81 1 2.0 2.3 675.6 674.64 313.89 809.20 NO 

 1400. 17.98 1 2.0 2.3 675.6 674.64 328.85 940.89 NO 

 1500. 17.20 1 2.0 2.3 675.6 674.64 343.93 1084.24 NO 

 1600. 16.47 1 2.0 2.3 675.6 674.64 359.09 1239.22 NO 

 1700. 15.80 1 2.0 2.3 675.6 674.64 374.31 1405.83 NO 

 1800. 15.18 1 2.0 2.3 675.6 674.64 389.58 1584.09 NO 

 1900. 14.61 1 2.0 2.3 675.6 674.64 404.87 1774.02 NO 

 2000. 14.08 1 2.0 2.3 675.6 674.64 420.18 1975.67 NO 

 2100. 13.58 1 2.0 2.3 675.6 674.64 435.50 2189.06 NO 

 2200. 13.12 1 2.0 2.3 675.6 674.64 450.81 2414.25 NO 

 2300. 12.69 1 2.0 2.3 675.6 674.64 466.12 2651.28 NO 

 2400. 12.29 1 2.0 2.3 675.6 674.64 481.41 2900.20 NO 

 2500. 11.91 1 2.0 2.3 675.6 674.64 496.68 3161.05 NO 

 2600. 11.55 1 2.0 2.3 675.6 674.64 511.92 3433.89 NO 

 2700. 11.22 1 2.0 2.3 675.6 674.64 527.15 3718.77 NO 

 2800. 10.91 1 2.0 2.3 675.6 674.64 542.34 4015.72 NO 

 2900. 10.61 1 2.0 2.3 675.6 674.64 557.50 4324.79 NO 

 3000. 10.33 1 2.0 2.3 675.6 674.64 572.63 4646.04 NO 
2 

 

MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1104. 20.37 1 2.0 2.3 675.6 674.64 275.01 579.47 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 3100. 10.06 1 2.0 2.3 675.6 674.64 587.73 4979.50 NO 

 3200. 9.812 1 2.0 2.3 675.6 674.64 602.79 5000.00 NO 

 3300. 9.573 1 2.0 2.3 675.6 674.64 617.82 5000.00 NO 

 3400. 9.466 2 2.0 2.3 675.6 674.64 488.10 452.26 NO 

 3500. 9.557 2 2.0 2.3 675.6 674.64 499.19 464.80 NO 

 3600. 9.620 2 2.0 2.3 675.6 674.64 510.27 477.44 NO 

 3700. 9.656 2 2.0 2.3 675.6 674.64 521.34 490.15 NO 

 3800. 9.667 2 2.0 2.3 675.6 674.64 532.40 502.95 NO 

 3900. 9.657 2 2.0 2.3 675.6 674.64 543.45 515.82 NO 

 4000. 9.628 2 2.0 2.3 675.6 674.64 554.48 528.76 NO 

 4100. 9.583 2 2.0 2.3 675.6 674.64 565.50 541.77 NO 

 4200. 9.523 2 2.0 2.3 675.6 674.64 576.51 554.85 NO 

 4300. 9.452 2 2.0 2.3 675.6 674.64 587.50 567.99 NO 

 4400. 9.370 2 2.0 2.3 675.6 674.64 598.47 581.19 NO 

 4500. 9.279 2 2.0 2.3 675.6 674.64 609.43 594.45 NO 

 4600. 9.182 2 2.0 2.3 675.6 674.64 620.38 607.77 NO 

 4700. 9.079 2 2.0 2.3 675.6 674.64 631.30 621.13 NO 

 4800. 8.973 2 2.0 2.3 675.6 674.64 642.21 634.55 NO 

 4900. 8.863 2 2.0 2.3 675.6 674.64 653.11 648.02 NO 

 5000. 8.751 2 2.0 2.3 675.6 674.64 663.98 661.54 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 3000. 

 0. 3100. -- 

 0. 3200. -- 

 0. 3300. -- 

 0. 3400. -- 

 0. 3500. -- 

 0. 3600. -- 

 0. 3700. -- 

 0. 3800. -- 

 0. 3900. -- 

 0. 4000. -- 

 0. 4100. -- 

 0. 4200. -- 
3 

 0. 4300. -- 

 0. 4400. -- 

 0. 4500. -- 

 0. 4600. -- 

 0. 4700. -- 

 0. 4800. -- 

 0. 4900. -- 

 0. 5000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 20.37 1104. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 03/13/08 

 10:58:20 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 CO - McELMO CREEK MAIN FLARE - 618,104 SCF/HR; 682.4 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 29.2100 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .295449E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 76.4268 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 489.864 M**4/S**3; MOM. FLUX = 298.709 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .9095E-02 5 1.0 2.0 10000.0 261.24 54.07 53.17 NO 

 300. .1029E-01 5 1.0 2.0 10000.0 261.24 55.44 53.52 NO 

 400. .1172E-01 5 1.0 2.0 10000.0 261.24 57.21 53.90 NO 

 500. .1352E-01 5 1.0 2.0 10000.0 261.24 59.31 54.33 NO 

 600. .7457 1 3.0 3.5 960.0 536.60 152.15 170.85 NO 

 700. 4.322 1 3.0 3.5 960.0 536.60 173.04 228.59 NO 

 800. 9.140 1 3.0 3.5 960.0 536.60 193.49 296.90 NO 

 900. 12.55 1 2.0 2.3 767.7 766.68 239.56 391.26 NO 

 1000. 17.94 1 2.0 2.3 767.7 766.68 260.73 480.00 NO 

 1100. 20.58 1 2.0 2.3 767.7 766.68 281.52 579.73 NO 

 1200. 20.99 1 2.0 2.3 767.7 766.68 301.99 690.52 NO 

 1300. 20.27 1 2.0 2.3 767.7 766.68 322.16 812.44 NO 

 1400. 19.22 1 2.0 2.3 767.7 766.68 342.05 945.58 NO 

 1500. 18.41 1 2.0 2.3 767.7 766.68 357.48 1088.61 NO 

 1600. 17.69 1 2.0 2.3 767.7 766.68 372.09 1243.05 NO 

 1700. 17.02 1 2.0 2.3 767.7 766.68 386.80 1409.21 NO 

 1800. 16.39 1 2.0 2.3 767.7 766.68 401.59 1587.09 NO 

 1900. 15.81 1 2.0 2.3 767.7 766.68 416.44 1776.70 NO 

 2000. 15.26 1 2.0 2.3 767.7 766.68 431.34 1978.07 NO 

 2100. 14.75 1 2.0 2.3 767.7 766.68 446.28 2191.23 NO 
 2200. 14.27 1 2.0 2.3 767.7 766.68 461.23 2416.22 NO 

 2300. 13.82 1 2.0 2.3 767.7 766.68 476.20 2653.07 NO 

 2400. 13.40 1 2.0 2.3 767.7 766.68 491.18 2901.84 NO 

 2500. 13.01 1 2.0 2.3 767.7 766.68 506.15 3162.56 NO 

 2600. 12.63 1 2.0 2.3 767.7 766.68 521.12 3435.28 NO 

 2700. 12.28 1 2.0 2.3 767.7 766.68 536.08 3720.04 NO 

 2800. 11.95 1 2.0 2.3 767.7 766.68 551.03 4016.90 NO 

 2900. 11.63 1 2.0 2.3 767.7 766.68 565.96 4325.89 NO 

 3000. 11.33 1 2.0 2.3 767.7 766.68 580.87 4647.06 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1174. 21.04 1 2.0 2.3 767.7 766.68 296.49 659.51 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 3100. 11.05 1 2.0 2.3 767.7 766.68 595.76 4980.46 NO 

 3200. 10.78 1 2.0 2.3 767.7 766.68 610.62 5000.00 NO 

 3300. 10.52 1 2.0 2.3 767.7 766.68 625.46 5000.00 NO 

 3400. 10.28 1 2.0 2.3 767.7 766.68 640.27 5000.00 NO 

 3500. 10.05 1 2.0 2.3 767.7 766.68 655.06 5000.00 NO 

 3600. 9.828 1 2.0 2.3 767.7 766.68 669.81 5000.00 NO 

 3700. 9.616 1 2.0 2.3 767.7 766.68 684.54 5000.00 NO 

 3800. 9.464 2 2.0 2.3 767.7 766.68 541.25 512.31 NO 

 3900. 9.552 2 2.0 2.3 767.7 766.68 552.12 524.95 NO 

 4000. 9.616 2 2.0 2.3 767.7 766.68 562.99 537.67 NO 

 4100. 9.658 2 2.0 2.3 767.7 766.68 573.84 550.47 NO 

 4200. 9.680 2 2.0 2.3 767.7 766.68 584.69 563.35 NO 

 4300. 9.684 2 2.0 2.3 767.7 766.68 595.53 576.30 NO 

 4400. 9.671 2 2.0 2.3 767.7 766.68 606.36 589.31 NO 

 4500. 9.644 2 2.0 2.3 767.7 766.68 617.18 602.39 NO 

 4600. 9.604 2 2.0 2.3 767.7 766.68 627.99 615.53 NO 

 4700. 9.552 2 2.0 2.3 767.7 766.68 638.79 628.74 NO 

 4800. 9.491 2 2.0 2.3 767.7 766.68 649.57 642.00 NO 

 4900. 9.422 2 2.0 2.3 767.7 766.68 660.34 655.31 NO 

 5000. 9.345 2 2.0 2.3 767.7 766.68 671.10 668.68 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 
 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 3000. 

 0. 3100. -- 

 0. 3200. -- 

 0. 3300. -- 

 0. 3400. -- 

 0. 3500. -- 

 0. 3600. -- 

 0. 3700. -- 

 0. 3800. -- 

 0. 3900. -- 

 0. 4000. -- 

 0. 4100. -- 

 0. 4200. -- 

 0. 4300. -- 

 0. 4400. -- 

 0. 4500. -- 

 0. 4600. -- 

 0. 4700. -- 

 0. 4800. -- 

 0. 4900. -- 

 0. 5000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 21.04 1174. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 10/07/05 

 18:43:30 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 SO2 - McELMO CREEK MAIN FLARE - 618.104 SCF/HR; 300 BTU/SCF; 700 PPM H2S 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 9.21000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .129887E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 70.9117 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 215.357 M**4/S**3; MOM. FLUX = 131.320 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .1213E-02 5 1.0 2.0 10000.0 212.67 42.14 40.98 NO 

 300. .1537E-02 5 1.0 2.0 10000.0 212.67 43.89 41.43 NO 

 400. .1224E-01 1 3.0 3.4 960.0 353.43 102.30 83.27 NO 

 500. .5749 1 3.0 3.4 960.0 353.43 123.67 116.05 NO 

 600. 3.529 1 3.0 3.4 960.0 353.43 144.45 164.03 NO 

 700. 6.577 1 3.0 3.4 960.0 353.43 164.74 222.37 NO 

 800. 7.587 1 3.0 3.4 960.0 353.43 184.62 291.21 NO 

 900. 9.638 1 1.5 1.7 636.9 635.95 241.27 392.31 NO 

 1000. 11.24 1 1.5 1.7 636.9 635.95 262.53 480.98 NO 

 1100. 11.63 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 

 1200. 11.35 1 1.5 1.7 636.9 635.95 293.46 686.83 NO 

 1300. 10.86 1 1.5 1.7 636.9 635.95 308.54 807.14 NO 

 1400. 10.36 1 1.5 1.7 636.9 635.95 323.75 939.12 NO 

 1500. 9.889 1 1.5 1.7 636.9 635.95 339.05 1082.70 NO 

 1600. 9.460 1 1.5 1.7 636.9 635.95 354.42 1237.88 NO 

 1700. 9.066 1 1.5 1.7 636.9 635.95 369.84 1404.65 NO 

 1800. 8.703 1 1.5 1.7 636.9 635.95 385.28 1583.04 NO 

 1900. 8.367 1 1.5 1.7 636.9 635.95 400.74 1773.09 NO 

 2000. 8.056 1 1.5 1.7 636.9 635.95 416.20 1974.82 NO 

 2100. 7.768 1 1.5 1.7 636.9 635.95 431.66 2188.30 NO 

 2200. 7.499 1 1.5 1.7 636.9 635.95 447.11 2413.56 NO 
 2300. 7.249 1 1.5 1.7 636.9 635.95 462.53 2650.65 NO 

 2400. 7.015 1 1.5 1.7 636.9 635.95 477.94 2899.62 NO 

 2500. 6.797 1 1.5 1.7 636.9 635.95 493.32 3160.53 NO 

 2600. 6.592 1 1.5 1.7 636.9 635.95 508.66 3433.41 NO 

 2700. 6.399 1 1.5 1.7 636.9 635.95 523.98 3718.32 NO 

 2800. 6.218 1 1.5 1.7 636.9 635.95 539.26 4015.30 NO 

 2900. 6.047 1 1.5 1.7 636.9 635.95 554.51 4324.41 NO 

 3000. 5.885 1 1.5 1.7 636.9 635.95 569.72 4645.68 NO 

 3500. 5.745 2 1.5 1.7 636.9 635.95 495.84 461.21 NO 

 4000. 5.658 2 1.5 1.7 636.9 635.95 551.47 525.60 NO 

 4500. 5.370 2 1.5 1.7 636.9 635.95 606.70 591.64 NO 

 5000. 5.017 2 1.5 1.7 636.9 635.95 661.47 659.02 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1097. 11.63 1 1.5 1.7 636.9 635.95 277.95 574.19 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 5000. 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 11.63 1097. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 10/07/05 

 18:34:49 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 SO2 - McELMO CREEK MAIN FLARE - 618.104 SCF/HR; 443 BTU/SCF; 700 PPM H2S 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 9.21000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .191799E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 73.2591 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .1945E-02 5 1.0 2.0 10000.0 234.08 47.40 46.37 NO 

 300. .2312E-02 5 1.0 2.0 10000.0 234.08 48.96 46.76 NO 

 400. .2776E-02 5 1.0 2.0 10000.0 234.08 50.95 47.20 NO 

 500. .8538E-01 1 3.0 3.4 960.0 429.40 126.59 119.17 NO 

 600. 1.258 1 3.0 3.4 960.0 429.40 147.64 166.85 NO 

 700. 3.633 1 3.0 3.4 960.0 429.40 168.18 224.94 NO 

 800. 5.276 1 3.0 3.4 960.0 429.40 188.30 293.55 NO 

 900. 7.314 1 2.0 2.3 640.0 607.47 228.42 384.54 NO 

 1000. 8.704 1 2.0 2.3 640.0 607.47 248.95 473.71 NO 

 1100. 8.931 1 2.0 2.3 640.0 607.47 269.15 573.82 NO 

 1200. 8.589 1 2.0 2.3 640.0 607.47 288.71 684.81 NO 

 1300. 8.207 1 2.0 2.3 640.0 607.47 304.03 805.43 NO 

 1400. 7.816 1 2.0 2.3 640.0 607.47 319.45 937.65 NO 

 1500. 7.503 1 1.5 1.7 786.5 785.55 360.99 1089.77 NO 

 1600. 7.215 1 1.5 1.7 786.5 785.55 375.46 1244.06 NO 

 1700. 6.945 1 1.5 1.7 786.5 785.55 390.04 1410.10 NO 

 1800. 6.694 1 1.5 1.7 786.5 785.55 404.72 1587.88 NO 

 1900. 6.458 1 1.5 1.7 786.5 785.55 419.46 1777.41 NO 

 2000. 6.238 1 1.5 1.7 786.5 785.55 434.26 1978.71 NO 

 2100. 6.032 1 1.5 1.7 786.5 785.55 449.09 2191.81 NO 

 2200. 5.839 1 1.5 1.7 786.5 785.55 463.96 2416.74 NO 
 2300. 5.657 1 1.5 1.7 786.5 785.55 478.84 2653.55 NO 

 2400. 5.487 1 1.5 1.7 786.5 785.55 493.74 2902.27 NO 

 2500. 5.326 1 1.5 1.7 786.5 785.55 508.64 3162.96 NO 

 2600. 5.174 1 1.5 1.7 786.5 785.55 523.54 3435.64 NO 

 2700. 5.031 1 1.5 1.7 786.5 785.55 538.43 3720.38 NO 

 2800. 4.896 1 1.5 1.7 786.5 785.55 553.32 4017.22 NO 

 2900. 4.768 1 1.5 1.7 786.5 785.55 568.18 4326.19 NO 

 3000. 4.646 1 1.5 1.7 786.5 785.55 583.04 4647.34 NO 

 3500. 4.268 2 2.0 2.3 640.0 607.47 493.05 458.20 NO 

 4000. 4.216 2 2.0 2.3 640.0 607.47 548.96 522.97 NO 

 4500. 4.007 2 2.0 2.3 640.0 607.47 604.41 589.30 NO 

 5000. 3.803 2 1.5 1.7 786.5 785.55 672.98 670.57 NO 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1075. 8.951 1 2.0 2.3 640.0 607.47 263.93 546.73 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 5000. 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 8.951 1075. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
1 

 03/10/08 

 12:31:24 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 SO2 - McELMO CREEK MAIN FLARE - 618104 SCF/HR; 538 BTU 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 9.18000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .233276E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 74.6137 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 386.779 M**4/S**3; MOM. FLUX = 235.850 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .2349E-02 5 1.0 2.0 10000.0 245.91 50.30 49.34 NO 

 300. .2725E-02 5 1.0 2.0 10000.0 245.91 51.78 49.71 NO 

 400. .3188E-02 5 1.0 2.0 10000.0 245.91 53.66 50.12 NO 

 500. .2488E-01 1 3.0 3.5 960.0 474.63 128.33 121.01 NO 

 600. .6365 1 3.0 3.5 960.0 474.63 149.55 168.54 NO 

 700. 2.442 1 3.0 3.5 960.0 474.63 170.23 226.48 NO 

 800. 4.126 1 3.0 3.5 960.0 474.63 190.49 294.96 NO 

 900. 6.141 1 2.0 2.3 675.6 674.64 233.15 387.37 NO 

 1000. 7.677 1 2.0 2.3 675.6 674.64 253.95 476.35 NO 

 1100. 8.107 1 2.0 2.3 675.6 674.64 274.40 576.30 NO 

 1200. 7.897 1 2.0 2.3 675.6 674.64 294.53 687.29 NO 

 1300. 7.489 1 2.0 2.3 675.6 674.64 313.89 809.20 NO 

 1400. 7.159 1 2.0 2.3 675.6 674.64 328.85 940.89 NO 

 1500. 6.846 1 2.0 2.3 675.6 674.64 343.93 1084.24 NO 

 1600. 6.557 1 2.0 2.3 675.6 674.64 359.09 1239.22 NO 

 1700. 6.290 1 2.0 2.3 675.6 674.64 374.31 1405.83 NO 

 1800. 6.044 1 2.0 2.3 675.6 674.64 389.58 1584.09 NO 

 1900. 5.816 1 2.0 2.3 675.6 674.64 404.87 1774.02 NO 

 2000. 5.604 1 2.0 2.3 675.6 674.64 420.18 1975.67 NO 

 2100. 5.407 1 2.0 2.3 675.6 674.64 435.50 2189.06 NO 

 2200. 5.223 1 2.0 2.3 675.6 674.64 450.81 2414.25 NO 

 2300. 5.051 1 2.0 2.3 675.6 674.64 466.12 2651.28 NO 

 2400. 4.891 1 2.0 2.3 675.6 674.64 481.41 2900.20 NO 

 2500. 4.741 1 2.0 2.3 675.6 674.64 496.68 3161.05 NO 

 2600. 4.599 1 2.0 2.3 675.6 674.64 511.92 3433.89 NO 

 2700. 4.467 1 2.0 2.3 675.6 674.64 527.15 3718.77 NO 

 2800. 4.341 1 2.0 2.3 675.6 674.64 542.34 4015.72 NO 

 2900. 4.223 1 2.0 2.3 675.6 674.64 557.50 4324.79 NO 

 3000. 4.112 1 2.0 2.3 675.6 674.64 572.63 4646.04 NO 
2 

 MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1104. 8.108 1 2.0 2.3 675.6 674.64 275.01 579.47 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 3100. 4.006 1 2.0 2.3 675.6 674.64 587.73 4979.50 NO 

 3200. 3.906 1 2.0 2.3 675.6 674.64 602.79 5000.00 NO 

 3300. 3.811 1 2.0 2.3 675.6 674.64 617.82 5000.00 NO 

 3400. 3.768 2 2.0 2.3 675.6 674.64 488.10 452.26 NO 

 3500. 3.805 2 2.0 2.3 675.6 674.64 499.19 464.80 NO 

 3600. 3.830 2 2.0 2.3 675.6 674.64 510.27 477.44 NO 

 3700. 3.844 2 2.0 2.3 675.6 674.64 521.34 490.15 NO 

 3800. 3.848 2 2.0 2.3 675.6 674.64 532.40 502.95 NO 

 3900. 3.844 2 2.0 2.3 675.6 674.64 543.45 515.82 NO 

 4000. 3.833 2 2.0 2.3 675.6 674.64 554.48 528.76 NO 

 4100. 3.815 2 2.0 2.3 675.6 674.64 565.50 541.77 NO 

 4200. 3.791 2 2.0 2.3 675.6 674.64 576.51 554.85 NO 

 4300. 3.763 2 2.0 2.3 675.6 674.64 587.50 567.99 NO 

 4400. 3.730 2 2.0 2.3 675.6 674.64 598.47 581.19 NO 

 4500. 3.694 2 2.0 2.3 675.6 674.64 609.43 594.45 NO 

 4600. 3.655 2 2.0 2.3 675.6 674.64 620.38 607.77 NO 

 4700. 3.614 2 2.0 2.3 675.6 674.64 631.30 621.13 NO 

 4800. 3.572 2 2.0 2.3 675.6 674.64 642.21 634.55 NO 

 4900. 3.528 2 2.0 2.3 675.6 674.64 653.11 648.02 NO 

 5000. 3.484 2 2.0 2.3 675.6 674.64 663.98 661.54 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 3000. 

 0. 3100. -- 

 0. 3200. -- 

 0. 3300. -- 

 0. 3400. -- 

 0. 3500. -- 

 0. 3600. -- 

 0. 3700. -- 

 0. 3800. -- 

 0. 3900. -- 

 0. 4000. -- 

 0. 4100. -- 

 0. 4200. -- 
3 

 0. 4300. -- 

 0. 4400. -- 

 0. 4500. -- 

 0. 4600. -- 

 0. 4700. -- 

 0. 4800. -- 

 0. 4900. -- 

 0. 5000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 8.108 1104. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
1 

 03/10/08 

 12:41:18 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 SO2 - McELMO CREEK MAIN FLARE - 618104 SCF/HR; 682.4 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 9.18000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .295449E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 76.4268 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 489.864 M**4/S**3; MOM. FLUX = 298.709 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN AUTOMATED DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 200. .2858E-02 5 1.0 2.0 10000.0 261.24 54.07 53.17 NO 

 300. .3233E-02 5 1.0 2.0 10000.0 261.24 55.44 53.52 NO 

 400. .3685E-02 5 1.0 2.0 10000.0 261.24 57.21 53.90 NO 

 500. .4250E-02 5 1.0 2.0 10000.0 261.24 59.31 54.33 NO 

 600. .2343 1 3.0 3.5 960.0 536.60 152.15 170.85 NO 

 700. 1.358 1 3.0 3.5 960.0 536.60 173.04 228.59 NO 

 800. 2.872 1 3.0 3.5 960.0 536.60 193.49 296.90 NO 

 900. 3.945 1 2.0 2.3 767.7 766.68 239.56 391.26 NO 

 1000. 5.637 1 2.0 2.3 767.7 766.68 260.73 480.00 NO 

 1100. 6.468 1 2.0 2.3 767.7 766.68 281.52 579.73 NO 

 1200. 6.598 1 2.0 2.3 767.7 766.68 301.99 690.52 NO 

 1300. 6.371 1 2.0 2.3 767.7 766.68 322.16 812.44 NO 

 1400. 6.041 1 2.0 2.3 767.7 766.68 342.05 945.58 NO 

 1500. 5.787 1 2.0 2.3 767.7 766.68 357.48 1088.61 NO 

 1600. 5.560 1 2.0 2.3 767.7 766.68 372.09 1243.05 NO 

 1700. 5.348 1 2.0 2.3 767.7 766.68 386.80 1409.21 NO 

 1800. 5.151 1 2.0 2.3 767.7 766.68 401.59 1587.09 NO 

 1900. 4.968 1 2.0 2.3 767.7 766.68 416.44 1776.70 NO 

 2000. 4.796 1 2.0 2.3 767.7 766.68 431.34 1978.07 NO 

 2100. 4.636 1 2.0 2.3 767.7 766.68 446.28 2191.23 NO 

 2200. 4.485 1 2.0 2.3 767.7 766.68 461.23 2416.22 NO 

 2300. 4.344 1 2.0 2.3 767.7 766.68 476.20 2653.07 NO 

 2400. 4.212 1 2.0 2.3 767.7 766.68 491.18 2901.84 NO 

 2500. 4.087 1 2.0 2.3 767.7 766.68 506.15 3162.56 NO 

 2600. 3.970 1 2.0 2.3 767.7 766.68 521.12 3435.28 NO 

 2700. 3.859 1 2.0 2.3 767.7 766.68 536.08 3720.04 NO 

 2800. 3.754 1 2.0 2.3 767.7 766.68 551.03 4016.90 NO 

 2900. 3.655 1 2.0 2.3 767.7 766.68 565.96 4325.89 NO 

 3000. 3.561 1 2.0 2.3 767.7 766.68 580.87 4647.06 NO 
2 

 

MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 

 1174. 6.612 1 2.0 2.3 767.7 766.68 296.49 659.51 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 3100. 3.472 1 2.0 2.3 767.7 766.68 595.76 4980.46 NO 

 3200. 3.388 1 2.0 2.3 767.7 766.68 610.62 5000.00 NO 

 3300. 3.308 1 2.0 2.3 767.7 766.68 625.46 5000.00 NO 

 3400. 3.231 1 2.0 2.3 767.7 766.68 640.27 5000.00 NO 

 3500. 3.158 1 2.0 2.3 767.7 766.68 655.06 5000.00 NO 

 3600. 3.089 1 2.0 2.3 767.7 766.68 669.81 5000.00 NO 

 3700. 3.022 1 2.0 2.3 767.7 766.68 684.54 5000.00 NO 

 3800. 2.974 2 2.0 2.3 767.7 766.68 541.25 512.31 NO 

 3900. 3.002 2 2.0 2.3 767.7 766.68 552.12 524.95 NO 

 4000. 3.022 2 2.0 2.3 767.7 766.68 562.99 537.67 NO 

 4100. 3.035 2 2.0 2.3 767.7 766.68 573.84 550.47 NO 

 4200. 3.042 2 2.0 2.3 767.7 766.68 584.69 563.35 NO 

 4300. 3.043 2 2.0 2.3 767.7 766.68 595.53 576.30 NO 

 4400. 3.039 2 2.0 2.3 767.7 766.68 606.36 589.31 NO 

 4500. 3.031 2 2.0 2.3 767.7 766.68 617.18 602.39 NO 

 4600. 3.018 2 2.0 2.3 767.7 766.68 627.99 615.53 NO 

 4700. 3.002 2 2.0 2.3 767.7 766.68 638.79 628.74 NO 

 4800. 2.983 2 2.0 2.3 767.7 766.68 649.57 642.00 NO 

 4900. 2.961 2 2.0 2.3 767.7 766.68 660.34 655.31 NO 

 5000. 2.937 2 2.0 2.3 767.7 766.68 671.10 668.68 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 200. 3000. 

 0. 3100. -- 

 0. 3200. -- 

 0. 3300. -- 

 0. 3400. -- 

 0. 3500. -- 

 0. 3600. -- 

 0. 3700. -- 

 0. 3800. -- 

 0. 3900. -- 

 0. 4000. -- 

 0. 4100. -- 

 0. 4200. -- 
3 

 0. 4300. -- 

 0. 4400. -- 

 0. 4500. -- 

 0. 4600. -- 

 0. 4700. -- 

 0. 4800. -- 

 0. 4900. -- 

 0. 5000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 6.612 1174. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
APPENDIX D 

E-MAILS FROM MR. JOHN NOTAR of the NATIONAL PARK SERVICE and 

MR. HENRY MADDUX, UTAH ENDANGERED SPECIES SUPERVISOR 
E-MAIL FROM MR. JOHN NOTAR CONCERNING CLASS I AREA IMPACTS 

----- Forwarded by Justin J Harrison/U-Houston/ExxonMobil on 06/22/06 10:24 

AM ----- 

 

 John_Notar@nps 

 .gov 

 To 

 justin.j.harrison@exxonmobil.com 

 06/21/06 04:59 cc 

 PM Liana_Reilly@nps.gov, 

 John_Bunyak@nps.gov, 

 John_Vimont@nps.gov 

 Subject 

 Re: Class I Analysis for McElmo 

 Creek PSD Permit Application 

 

Justin: Thank you for the information on the McElmo Creek upset flare 

project at the Mc Elmo Creek compressor station. Based on the information 

provided below and on the call; given the distance to the nearest National 

Park Service Class I area of 61 kilometers to Mesa Verde National Park, and 

the total emissions of 60 TPY of SO2, 13 TPY of NOx from the project, the 

National Park Service does not request that a Class I air quality analysis 

be performed due to the small amount of emissions and the distance to the 

nearest NPS Class I area. Please share this information with EPA Region 9, 

the permitting authority for this project in Utah. If you have further 

questions on this issue please contact Liana Reilly of the NPS Air 

Resources Division at (303)-987-6895. 

thanks you 

John Notar 

John Notar 

National Park Service 

Air Resources Division 

12795 W. Alameda Pkwy. 

Lakewood, CO 80228 

Phone: 303-969-2079 

Fax: 303-969-2822 

E-Mail: john_notar@nps.gov 

 justin.j.harrison@exx 

 onmobil.com To: 

John_Notar@nps.gov 

 cc: 

 06/15/2006 04:55 PM Subject: Class I 

Analysis for McElmo Creek PSD Permit Application 

 EST 

John, 

As we discussed today, ExxonMobil submitted a PSD permit application to EPA 

Region IX on December 5, 2005 for the Emergency Flare located at McElmo 

Creek Gas Compression Facility. In their response letter dated May 22, 

2006, EPA asked us to contact you to determine if additional Class I 

screening is necessary. 

The facility is located on the Navajo Nation approximately 4-5 miles 

northwest of Aneth, Utah, 3 miles from Utah State Road 262. It is 

comprised of four compressors, a dehydration unit, and an emergency flare, 

which is used during compressor downtime and to control dehydration still 

vent emissions. The current emission limits for the flare are as follows: 

60 TPY SO2, 73 TPY CO, 13.4 TPY NOx, and 95.4 TPY VOCs. We do not 
anticipate any changes to these limits. 

Total emissions for 2005 were: 29.2 tons SO2, 66 tons CO, 12.1 tons NOx, 

and 90.6 tons VOCs. During normal operations when all compressors are 

running, daily flare volumes are typically less than 500 kcf. Average 

daily flare volumes for 2005 were 2 MMCF. 

Arches National Park and Canyonlands National Park are located to the 

northwest, approximately 160 km (100 miles) and 96 km (60 miles), 

respectively. Mesa Verde National Park is located approximately 60 km (38 

miles) east of the gas plant site. The western boundary of the Canyon of 

the Ancients National Monument is approximately 16 km (10 miles) northwest 

of the plant site. 

A conservative SCREEN 3 model was submitted in the PSD application to 

estimate near-field impacts from the flare operating at 14.83 MMCFD for the 

entire year, which is 7 times greater than the average emissions in 2005. 

With respect to NOx and SO2, this model estimated the following 

concentrations: 

 The predicted maximum annual averaged NO2 concentration from the flare 

 is 0.13 micrograms/cubic meter located 1,075 meters from the stack. 

 The predicted maximum 3-hour, 24-hour, and annual averaged SO2 

 concentrations from the flare are 10.47, 4.65, and 0.93 micrograms/cubic 

 meter, respectively, located 1,097 meters from the stack. 

As you indicated today, you did not feel that any additional Class I 

screening would be necessary based on this information. We appreciate you 

confirming this via e-mail as we discussed. If you need any additional 

information, please let me know. 

Thanks. 

Justin J. Harrison 

ExxonMobil U.S. Production 

Safety & Air Compliance 

CORP-MI-3038 

P.O. Box 4697 

Houston, TX 77210-4697 

Office: 281-654-1127 

Fax: 281-654-1147
E-MAIL FROM Mr. HENRY MADDUX CONCERNING ENDANGERED SPECIES 

----- Forwarded by Justin J Harrison/U-Houston/ExxonMobil on 06/29/06 08:48 

AM ----- 

 

 Henry_Maddux@f 

 ws.gov 

 To 

 <justin.j.harrison@exxonmobil.com> 

 06/29/06 08:39 cc 

 AM 

 Subject 

 Flare-up Near Aneth 

 

 

 

 

 

 

Dear Mr. Harrison, 

I have reviewed our list of Threatened and Endangered species and critical 

habitat within your project area near Aneth, Utah. I have determined that 

the reported flare-up has no effect on listed species and their critical 

habitat. If you have any questions or if additional environmental impacts 

occur beyond those we have discussed, please contact me at (801)975-3330 

x124. 

Henry R. Maddux 

Utah ES Field Supervisor 

West Valley City, UT 
APPENDIX E 

SCREEN3 AND VISCREEN PRINT-OUTS FOR CLASS I AREA IMPACTS 
 08/03/06 

 08:51:00 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 McELMO MAIN FLARE - CHI/Q DISPERSION AT 50 KM., 618.104 SCF/HR, 300 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 1.00000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .129887E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 70.9117 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 215.357 M**4/S**3; MOM. FLUX = 131.320 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 1100. 1.262 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 

 50000. .2430 5 1.0 2.0 10000.0 212.67 1678.21 156.86 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 1100. -- 

 0. 50000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN 1.262 1100. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 03/13/08 

 14:51:31 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 MCELMO MAIN FLARE - CHI/Q Dispersion at 50 km, 618,104 scf/hr, 443 btu/scf 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 1.00000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .191799E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 73.2591 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 50000. .2001 5 1.0 2.0 10000.0 234.08 1678.35 158.35 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

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

 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN .2001 50000. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 03/11/08 

 15:15:15 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 McELMO MAIN FLARE - CHI/Q DISPERSION AT 50KM, 618,104 SCF/HR, 538.8 BTU/SCF 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 1.00000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .233276E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 74.6137 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 386.779 M**4/S**3; MOM. FLUX = 235.850 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 50000. .1789 5 1.0 2.0 10000.0 245.91 1678.43 159.25 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 50000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

 *************************************** 
 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN .1789 50000. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 03/11/08 

 15:08:21 

 *** SCREEN3 MODEL RUN *** 

 *** VERSION DATED 96043 *** 

 McELMO MAIN FLARE - CHI/Q Dispersion at 50km, 618,104 scf/hr, 682.4 btu/scf 

 SIMPLE TERRAIN INPUTS: 

 SOURCE TYPE = FLARE 

 EMISSION RATE (G/S) = 1.00000 

 FLARE STACK HEIGHT (M) = 59.4500 

 TOT HEAT RLS (CAL/S) = .295449E+08 

 RECEPTOR HEIGHT (M) = .0000 

 URBAN/RURAL OPTION = RURAL 

 EFF RELEASE HEIGHT (M) = 76.4268 

 BUILDING HEIGHT (M) = .0000 

 MIN HORIZ BLDG DIM (M) = .0000 

 MAX HORIZ BLDG DIM (M) = .0000 

 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. 

 THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED. 

 BUOY. FLUX = 489.864 M**4/S**3; MOM. FLUX = 298.709 M**4/S**2. 

 *** FULL METEOROLOGY *** 

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

 *** SCREEN DISCRETE DISTANCES *** 

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

 *** TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** 

 DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA 

 (M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH 

 ------- ---------- ---- ----- ----- ------ ------ ------ ------ ----- 

 50000. .1541 5 1.0 2.0 10000.0 261.24 1678.55 160.48 NO 

 DWASH= MEANS NO CALC MADE (CONC = 0.0) 

 DWASH=NO MEANS NO BUILDING DOWNWASH USED 

 DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED 

 DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED 

 DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB 

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

 * SUMMARY OF TERRAIN HEIGHTS ENTERED FOR * 

 * SIMPLE ELEVATED TERRAIN PROCEDURE * 

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

 TERRAIN DISTANCE RANGE (M) 

 HT (M) MINIMUM MAXIMUM 

 ------- -------- -------- 

 0. 50000. -- 

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

 *** SUMMARY OF SCREEN MODEL RESULTS *** 

 *************************************** 
 CALCULATION MAX CONC DIST TO TERRAIN 

 PROCEDURE (UG/M**3) MAX (M) HT (M) 

 -------------- ----------- ------- ------- 

 SIMPLE TERRAIN .1541 50000. 0. 

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

 ** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS ** 

 *************************************************** 
 Visual Effects Screening Analysis for 

 Source: McElmo Main Flare 

 Class I Area: Mesa Verde National Park 

 *** User-selected Screening Scenario Results *** 

 Input Emissions for 

 Particulates .05 G /S 

 NOx (as NO2) 1.50 G /S 

 Primary NO2 .00 G /S 

 Soot .00 G /S 

 Primary SO4 .00 G /S 

 

 PARTICLE CHARACTERISTICS 

 Density Diameter 

 ======= ======== 

 Primary Part. 2.5 6 

 Soot 2.0 1 

 Sulfate 1.5 4 

 Transport Scenario Specifications: 

 Background Ozone: .04 ppm 

 Background Visual Range: 250.00 km 

 Source-Observer Distance: 60.00 km 

 Min. Source-Class I Distance: 60.00 km 

 Max. Source-Class I Distance: 80.00 km 

 Plume-Source-Observer Angle: 11.25 degrees 

 Stability: 5 

 Wind Speed: 1.00 m/s 

 R E S U L T S 

 Asterisks (*) indicate plume impacts that exceed screening criteria 

 Maximum Visual Impacts INSIDE Class I Area 

 Screening Criteria ARE NOT Exceeded 

 Delta E Contrast 

 =========== ============ 

 Backgrnd Theta Azi Distance Alpha Crit Plume Crit Plume 

 ======== ===== === ======== ===== ==== ===== ==== ===== 

 SKY 10. 84. 60.0 84. 2.00 .063 .05 .000 

 SKY 140. 84. 60.0 84. 2.00 .048 .05 -.000 

 TERRAIN 10. 84. 60.0 84. 2.00 .029 .05 .000 

 TERRAIN 140. 84. 60.0 84. 2.00 .015 .05 .000 

 

 Maximum Visual Impacts OUTSIDE Class I Area 

 Screening Criteria ARE NOT Exceeded 

 Delta E Contrast 

 =========== ============ 

 Backgrnd Theta Azi Distance Alpha Crit Plume Crit Plume 

 ======== ===== === ======== ===== ==== ===== ==== ===== 

 SKY 10. 0. 1.0 169. 2.00 .692 .05 -.002 

 SKY 140. 0. 1.0 169. 2.00 .419 .05 -.009 

 TERRAIN 10. 0. 1.0 169. 2.00 .597 .05 .009 

 TERRAIN 140. 0. 1.0 169. 2.00 .396 .05 .006