RE: McElmo Main Flare: Pat's 12/06/10 letter

Dwight Mallory to: Andrew Chew 04/18/2012 03:22 PM

Cc: Shaheerah Kelly, Cleveland Holladay, Tom Mintz, "Patrick Flynn", 

"John Jacus", Randy.Dann

Andrew,

Thanks for the follow up email and phone call. As we discussed during

the call this morning, GHG emissions for the MCU CO2 recycle facility

are attached.

I look forward to your comments on the modeling discussion. In the

meantime, I will follow up on the Class I area impacts and ESA issues

with Mr. Notar and Mr. Maddux respectively and will forward copies of

any correspondence with them to you as soon as possible.

Please call or email if you need anything else.

Dwight E. Mallory

Environmental, Health & Safety Coordinator

Resolute Energy Corporation

1675 Broadway, Suite 1950

Denver, CO 80202

Direct: 303-573-4886 X 1165

Cell: 970-302-8620

Email: dmallory@ResoluteEnergy.com

From: Andrew Chew [mailto:Chew.Andrew@epamail.epa.gov] 

Sent: Wednesday, April 18, 2012 11:56 AM

To: Dwight Mallory

Cc: Shaheerah Kelly; Cleveland Holladay; Tom Mintz

Subject: McElmo Main Flare: Pat's 12/06/10 letter

Hi Dwight,

To be frank and honest, we wish we can narrow down the list further 

than what was bulleted in Pat's letter, but we're still a little ways away. 

For the Class I area impacts and ESA issues, please get separate 

confirmations from the federal land manger and Fish and Wildlife 

Service that their 2006 assessment statements apply to this day if the 

PSD Main Flare permit were to be issued in a few months. 

Also, we're reviewing McVehil Monnet's 6/1/11 report on 1-hr SO2 

modelling and plan to let you know our findings next week. While Scott 

believed that the 1-hr NO2 modelling work was sufficient, he asked that 

1-hr SO2 modelling work to be more specific. However, since Scott is 

no longer on this project, Cleve Holladay of our agency will be helping 

me with reviewing the modelling work.

Finally, we would need GHG CO2e emissions quantification so that the 

record reflects what's found. Shaheerah Kelly, my peer in our Air 
Permits office, will be partnering with me to help move the permit

process along. She's very knowledgeable and has been with the 

agency for more than 7 years. I plan to include her in future 

correspondence and meetings. Thanks again.

- Andrew 

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

Andrew Chew, P.E. 

T: (415) 947-4197 | F: (415) 947-3579 | chew.andrew@epa.gov

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

Francisco, CA 94105

From: "Dwight Mallory" <dmallory@ResoluteEnergy.com>

To: Andrew Chew/R9/USEPA/US@EPA

Date: 04/17/2012 11:28 AM

Subject: RE: Pat's 12/06/10 letter

Andrew,

Thanks for sending the letter. Based on our conversation in reference to the

bullet list of requested information on page 2, it is my understanding that you

are requesting information to address the review of the Class I area impacts

and Endangered Species sections of the PSD application.  

We have reviewed the Class I area impacts and Endangered Species sections of

the PSD application. Because the previous Class I area and Endangered Species

assessments and findings were based on the maximum facility emissions

allowable under the Consent Decree emission limits and the annual averaged

emissions from the SCREEN 3 modeling scenario, and inasmuch as neither the

Consent Decree emission limits nor the modeling inputs have been modified;

we believe that the Class I area impacts and Endangered Species impacts

analyses provided in the PSD application are still valid and no update is

needed.  

It is also my understanding that McVehil Monnet discussed the potential need

for additional air quality modeling to address the 1 hour NAAQS standard for

SO2 with Scott Bohning at EPA and that they were in agreement that

additional modeling, and thus additional assessment of impacts to Class I areas

and Endangered Species, were unnecessary.

Please contact me if you require additional information.
Dwight E. Mallory

Environmental, Health & Safety Coordinator

Resolute Energy Corporation

1675 Broadway, Suite 1950

Denver, CO 80202

Direct: 303-573-4886 X 1165

Cell: 970-302-8620

Email: dmallory@ResoluteEnergy.com

From: Andrew Chew [mailto:Chew.Andrew@epamail.epa.gov] 

Sent: Monday, April 16, 2012 4:52 PM

To: Dwight Mallory

Subject: Pat's 12/06/10 letter

 

- Andrew 

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

Andrew Chew, P.E. 

T: (415) 947-4197 | F: (415) 947-3579 | chew.andrew@epa.gov

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

Francisco, CA 94105 MCU GHG Estimate.xlsx
MCELMO CREEK UNIT REINJECTION FACILITY

GHG Emissions Estimate

FLARE STACK 26,122 Metric Tons CO2e

GYYCOL DEHYDRATOR 1,092 Metric Tons CO2e

COMPRESSOR ROD PACKING VENTING 242.1 Metric Tons CO2e

EQUIPMENTS LEAKS 51 Metric Tons CO2e

Total Facility GHG Emissions 27,507 Metric Tons CO2e
MCELMO CREEK UNIT REINJECTION FACILITY

GHG Emissions from Flare Stack

Ref 98.232 (C)(9)

MCU Main Flare ( based on 2011 Flare Volume)

Enter Flare Volume 423,359 mcf

Flare Gas HHV 0.000324597 mmbtu/scf

Gas Content CO2 59.819 Mole %

Gas Methane Content CH4 17.63 Mole %

Gas Ethane Content C2H6 5.897 Mole %

Gas Propane Content C3H8 4.039 Mole %

Gas Butane Content C4H10 1.974 Mole %

Gas Pentane + Content C5H12+ 1.109 Mole %

Total CO2 25,512 Metric Tons

Total CH4 605 Metric Tons Co2e

Total N2O 4 Metric Tons Co2e

Total GHG Emissions 26,122 Metric Tons Co2e

Total GHG Emissions 28,794 Short Tons

Total CO2 481,365,282 scf

Total CH4 1,492,765 scf

Uncombusted CH4 Ea CH4 (uncombusted) Va ƞ 

Ea CH4 (uncombusted) = Va*(1‐ƞ)*XCH4 1,492,765 scf 423359300 

Uncombusted CO2 Ea CO2 (uncombusted) Va XCO2

Ea CO2 (uncombusted) = Va*XCO2 253,249,300 scf 423359300 0.59

Total CO2 from HydrocarbonCombustion

Ea CO2 (combusted) = ∑j ƞ* Va* Yj * Rj Ea CO2 (combusted)

228,115,982 scf

Individual Hydrocarbons CO2 from Combustion

Ea CO2 (combusted) = ƞ* Va* Yj * Rj Ea CO2 (combusted) ƞ Va Methane 73,145,480 0.98 42335Ethane 48,932,376 0.98 42335Propane 50,272,477 0.98 42335Butane 32,759,881 0.98 42335Pentane Plus 23,005,768 0.98 42335
Where

Ea CH4 (uncombusted) = uncombusted CH4 in cubic feet

Ea CO2 (uncombusted) = uncombusted CO2 in cubic feet

Ea CO2 (combusted) = CO2 from combustion in cubic feet

Va = Annual Flare Volume in scf

ƞ = Fraction of gas combusted by flare (.98)

XCH4 = Mole fraction of CH4 in gas

XCO2 =Mole fraction of CO2 in gas stream

Yj = Mole fraction of hydrocarbon in gas (methane +)

Rj = Number of carbon atoms in the gas hydrocarbon constituent (1 for

methane, 2 for ethane, 3 for propane, 4 for butane and 5 for pentanes

plus)

N2O from Combustion 0.01 Mt

N2O = (1 * 10^3) * Fuel * HHV * EF

Where

N2O = Annual N2O emissions from combustion in metric tons

1 * 10^‐3 = Conversion from kg to metric Tons

Fuel = Mass or volume of fuel combusted per year (Va)

HHV = High heat value of fuel from paragraphs (z)(8)(i) or (z)(8)(iii)

EF = 1.0 * 10^‐4 kg N2O/mmbtu

Mass Conversion and Global Warming Potential

Masssj = Esj * ρi * GWP * 10^‐3

Where

Masssj = Mass GHG Emissions in Metric Tons CO2e

Esj =GHG volumtric emissions in scf

ρi = Density of GHG of interest: 0.0530 kg/ft3 for CO2 and N2O, 0.0193 kg/ft3

for CH4GWP = Global Warming Potential: 1 for CO2, 21 for CH4, 310 for N2O
MCU Plant Dehydration Unit GHG Emission Calculations

Ref 98.232 (C)(14)

Flash Gas Parameters

Flash Gas scf/yr: 5,439,960 Condenser Vent scf/yr: 14,366,400

Destruction Eff: 95% Destruction Eff: 95%

CO2 Mole Fraction: 0.83 CO2 Mole Fraction: 0.46

CH4 (C1) Mole Fraction: 0.03 CH4 (C1) Mole Fraction: 0.12

C2 Mole Fraction: 0.03 C2 Mole Fraction: 0.04

C3 Mole Fraction: 0.04 C3 Mole Fraction: 0.03

C4 Mole Fraction: 0.03 C4 Mole Fraction: 0.02

C5+ Mole Fraction: 0.02 C5+ Mole Fraction: 0.08

Actual Temperature 65 °F Standard Temperature 60 °F

Actual Pressure 12.2 psia Standard Pressure 14.696 ps

Un‐Combusted CH4 96,012.58 ft3 Un]Combusted CH4 78,946.02 ft

Un‐Combusted CO2 11,096,931.48 ft3 Un]Combusted CO2 9,124,414.49 ft

Combusted C1 (as CO2) 1,824,238.99 ft3 Combusted C1 (as CO2) 1,499,974.36 ft

Combusted C2 (as CO2) 1,533,345.14 ft3 Combusted C2 (as CO2) 1,260,787.87 ft

Combusted C3 (as CO2) 2,035,198.36 ft3 Combusted C3 (as CO2) 1,673,434.99 ft

Combusted C4 (as CO2) 1,822,980.37 ft3 Combusted C4 (as CO2) 1,498,939.46 ft

Combusted C5+ (as CO2) 6,004,572.34 ft3 Combusted C5+ (as CO2) 4,937,239.36 ft

Un‐Combusted CH4 32 metric tons

Un‐Combusted CO2 483.59 metric tons

Combusted C1 79.5 metric tons

Combusted C2 66.82 metric tons

Combusted C3 88.69 metric tons

Combusted C4 79.44 metric tons

Combusted C5+ 261.67 metric tons

N2O 0.76 metric tons

Total: 1,092.48 metric tons of CO2e

Values from GRI GlyCalc run by Lesair Environmental 3/16/2011

Flash Gas and Condenser Vent Emissions at Actual Conditions Flash Gas and Condenser Vent Emissions at Standard 

GHG Emissions at Standard Conditions

Condenser Vent Parameters
GHG Emissions from Reciprocal Compressor Packing

Ref 98.232 (C)(11)

Equation W‐29 from 40 CFR 98.233

ECH4 28,440 scf

EC02 1,581 scf

Compressor Count 3

EF CH4 9,480

EF CO2 527

Total CH4 12 Metric Tons

Total CO2 0 Metric Tons

Total CO2e 242 Metric Tons CO2e
GHG Emissions from Equipment Leaks

Ref 98.232 (C)(21)

(refer to equation W‐31, Subpart W to Part 98)

Valves Connectors Open Ended Lines Other

Wellhead 11 36 1 0

Separator 34 106 6 2

Meters/Piping 14 51 1 1

Compressors 73 179 3 4

In‐Line Heaters 14 65 2 1

Dehydrators 24 90 2 2

Total Whole Gas Emissions 493,013 scf

ECO2 294,915 scf

ECH4 86,943 scf

ECO2 16 Metric Tons CO2e

ECH4 35 Metric Tons CO2e

Total GHG Emissions 51 Metric Tons CO2e

Avg Default Values from Table W‐1B to Subpart W of Part 98
Valves Connectors Open Ended Lines

Wellhead 0 0 0 0

Separator 2 68 212 12

Meters/Piping 4 56 204 4

Compressors 3 219 537 9

In‐Line Heaters 0 0 0 0

Dehydrators 1 24 90 2

Totals 367 1,043 27

EF (from Table W‐1A)* 0.123 0.005 0.032

Whole Gas Emissions (scf/hr) 45.141 5.215 0.864

Facility Equipment Count

Facility Total Components
Other

0

4

4

12

0

2

22

0.23 * Western US factors for gas service were used

5.06
1 All of the MCU CO2 recycle facility pneumatic equipment operates 

23 All of the MCU CO2 recycle facility pneumatic equipment operates 

4 Not applicable to the MCU CO2 recycle facility

5 Not applicable to the MCU CO2 recycle facility

6 Not applicable to the MCU CO2 recycle facility

7 Not applicable to the MCU CO2 recycle facility

8 Not applicable to the MCU CO2 recycle facility

9 Calculations included

10 There are no hydrocarbon storage tanks at the MCU gas recycle fa

11 Calculations included

12 Not applicable to the MCU CO2 recycle facility

13 Not applicable to the MCU CO2 recycle facility

14 Calculations included

1516 There have been no reported EOR injection pump blow downs at t

17 Not applicable to the MCU CO2 recycle facility

18 Not applicable to the MCU CO2 recycle facility

19 Not applicable to the MCU CO2 recycle facility

2021 Calculations included

22 Not applicable to the MCU CO2 recycle facility

Storage tanks vented emissions from produced hydrocarbons

40 CFR 98.232 (c) For an onshore petroleum and natural CO2 production facility, report CO2, CH4, and N2O emissions from only the following source types on a well pad or associated w

Natural gas pneumatic device venting

[Reserved]Natural gas driven pneumatic pump venting

Well venting for liquids unloading

Gas well venting during well completions without hydraulic fracturing

Gas well venting during well completions with hydraulic fracturing

Gas well venting during well workovers without hydraulic fracturing

Gas well venting during well workovers with hydraulic fracturing

Flare stack emissions

You must use the methods in § 98233z and report under this subpart the emissions of CO2, CH4, and N2O

from stationary or portable fuel combustion equipment that cannot move on roadways under its own power

and drive train, and that are located at an onshore production well padStationary or portable equipment are

the following equipment which are integral to the extraction, processing or movement of oil or natural gas:

Well drilling and completion equipment, workover equipment, natural gas dehydrators, natural gas

compressors, electrical generators, steam boilers, and process heaters

Reciprocating compressor rod packing venting

Well testing venting and flaring

Associated gas venting and flaring from produced hydrocarbons

Dehydrator vents

[Reserved]EOR injection pump blow down

Acid gas removal vents

EOR hydrocarbon liquids dissolved CO2

Centrifugal compressor venting

[Reserved]Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other

equipment leak sources such as instruments, loading arms, stuffing boxes, compressor seals, dump lever

arms, and breather caps.