1 

MEMORANDUM

DATE: August 15, 2015 

SUBJECT: Summary of Estimated Methane Emissions, Reductions and Cost 40 CFR 60 

Subpart OOOO 

FROM: Veronica Hanzel, EC/R Incorporated 

TO: Charlene Spells, EPA/OAQPS/SPPD 

The 40 CFR part 60, subpart OOOO new source performance standards (NSPS) for the 

oil and natural gas sector were promulgated in 2012 to reduce volatile organic compound (VOC) 

emissions from gas well completions, equipment leaks, compressors and pneumatic controllers at 

natural gas processing plants, compressors at gathering and boosting stations and storage vessels. 

We anticipate reductions in methane and hazardous air pollutants (HAP) emissions as well as 

natural gas savings as a co-benefit of the 2012 NSPS standards. During the development of the 

proposed (in 2011) and final standards (in 2012) and the reconsideration of storage vessel 

provisions in 2013, these estimated emissions reductions and natural gas savings were previously 

provided in various support documents. For ease of review, this memorandum briefly 

summarizes control technology discussion and the estimated reductions of methane and HAP 

emissions and the natural gas savings anticipated from implementation of the 2012 NSPS for 

these affected facilities. In addition, we present the corresponding reduction in carbon dioxide 

equivalents (CO2e) based on estimated methane reductions. 

The supporting documents from which we have compiled emissions information for these 

affected facilities are as follows: 

 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission and Distribution. Background Technical Support Document for 

the Final New Source performance Standards, dated July 2011.1

 This document will be 

referred to here as the 2011 TSD. 

 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission and Distribution. Background Supplemental Technical Support 

                                                            

1

 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution. Background Technical Support Document for Proposed 

Standards. July 2011. EPA-453/R-11002. 
2 

Document for the Final New Source performance Standards, dated April 2012.2 This 

document will be referred to here as the 2012 TSD. 

 Memorandum, Heather Brown, EC/R titled "Composition of Natural Gas for use in the 

Oil and Natural Gas Sector Rulemaking", dated July 28, 2011. This document will be 

referred here as the 2011 Natural Gas Composition Analysis.3

Estimation of Methane and HAP Emissions 

A potential benefit of VOC emissions reductions for the affected facilities under the 

NSPS is the reduction of methane and HAP as a result of reduction of the emission of natural gas 

that contains methane and HAP. As such, when conducting the analysis for VOC emissions 

reductions for the development of the 2012 NSPS, we also calculated methane and HAP 

emissions reductions. The general method for estimating VOC emissions for the NSPS analysis 

was to estimate methane emissions by applying a ratio of methane in natural gas (segment 

specific) emitted by a source, and convert that to VOC or HAP based on weight percent ratios 

that were determined in the 2011 Natural Gas Composition Analysis for the oil and natural gas 

sector. Our natural gas composition analysis determined a weight percent of methane in natural 

gas to be 65.7 percent for the production segment and 86.2 percent in the transmission and 

storage segment. Natural gas composition was determined to be different for gas well 

completions compared to other aspects of production. We determined, for well completions, the 

average natural gas composition (volume percent) of methane in natural gas to be 83.081 percent 

for gas wells and 46.73 percent for oil wells. Because natural gas composition was determined to 

vary among industry segments and among the various affected facilities, different ratios were 

used accordingly. Table 1 summarizes the weight percent ratios used for the various affected 

facilities in the various segments. 

 

                                                            

2

 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution. Background Supplemental Technical Support Document 

for Proposed Standards. April 2012. Docket ID EPA-HQ-OAR-2010-0505-4550. 3

 Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. "Composition of Natural Gas for use in the 

Oil and Natural gas Sector Rulemaking". July 2011. Docket ID EPA-HQ-OAR-2010-0505-0084. 
3 

Table 1. Ratios Used in Estimating Emissions for the Oil and Natural Gas Sector 

Segment Affected Facility Ratio 

VOC/Methane HAP/Methane 

Production HF Gas Well Completionsa 0.146 0.0106 

Production Equipment Leaks - Processingb 0.278 0.0105 

Transmissionb

Equipment Leaks 

Pneumatic Pumps 

Pneumatic Controllers 

Reciprocating Compressors 

0.0277 0.000822 

Storageb

Equipment Leaks 

Pneumatic Pumps 

Pneumatic Controllers 

Reciprocating Compressors 

Centrifugal Compressor 

0.0277 0.000822 

a. From Table 9 of the 2011 Natural Gas Composition Analysis. 

b. From Table 6 of the 2011 Natural Gas Composition Analysis. 

We determined the natural gas emissions from the various types of sources evaluated for 

the NSPS based on different studies and data available at the time of the development of the 

NSPS. Our estimation of methane, VOC and HAP emissions for each of the affected facility 

types under the 2012 NSPS were conducted as described below. 

Hydraulically Fractured Natural Gas Well Completions 

The basic approach for estimation of emissions from hydraulically fractured natural gas 

well completions was to approximate natural gas emissions from representative gas well 

completions and then estimate methane, VOC and HAP using a representative gas composition 

ratios as described in the 2011 Natural Gas Composition Analysis. We determined for the final 

rule, as described in the 2012 TSD, that the emission factor for a gas well completion was 9,000 

Mcf of natural gas per completion and that natural gas is 83.081 percent methane by volume. 

Based on the volume percent of methane to natural gas from the 2011 Natural Gas 

Composition Analysis and the conversion from volume methane to weight methane of 0.0208 

tons of methane per Mcf of methane, we estimated the methane emissions for hydraulically 

fractured gas wells in the 2012 NSPS final rule. We then used the gas composition ratios 

described in Table 1 above to calculate the VOC and HAP emissions. Table 2 summarizes the 

emissions, emission reductions, gas savings, capital cost (in 2008 dollars), and methane cost of 

control for natural gas well completions as calculated for the 2012 NSPS and based on a 7-day 

completion event. 
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Equipment Leaks from Natural Gas Processing Plants 

For equipment leaks from natural gas processing plants, the baseline emissions used for 

the analysis were the NSPS standards under 40 CFR Part 60, subpart KKK. Based on a model 

plant analysis, as described in Table 8-6 of the 2011 TSD, we determined baseline emissions of 

methane to be 51.4 tons per year (tpy) per plant and the HAP emissions to be 0.539 tpy per plant. 

Based on our 2011 NSPS analysis of level of control achieved by LDAR programs, the 

incremental additional emissions reductions above the subpart KKK (subpart VV level of 

control) afforded by a subpart VVa program or an LDAR program based on the monthly 

monitoring of components using optical gas imaging (OGI) combined annual Method 21 were 

calculated. The reductions were estimated to be the same for both of these control options which 

were 48.5 tons per year of methane and 0.508 tons per year of HAP per plant. 

Table 3 summarizes the results of the cost analysis with respect to these control options. 

Compressors in the Production and Processing Segments 

The 2012 NSPS included emission standards for compressors at natural gas processing 

plants and in the production segment between the well head and natural gas processing plants 

(not including compressors located at the wellhead). The baseline emissions for the NSPS were 

calculated based on methane emission factors from "Methane Emissions from the Natural Gas 

Industry: Volume 8 - Equipment Leaks" Table 4-8. The emission factors used are summarized in 

Table 6-2 of the 2011 TSD. 

Using an average number of cylinders per compressor and a percent pressurized factor, 

we determined the baseline emissions from reciprocating compressors in the production segment 

(i.e., gathering and boosting stations) to be 12.3 tpy of methane and 0.129 tpy of HAP, and 23.3 

tpy of methane and 0.244 tpy of HAP at natural gas processing plants. 

The emission factors used for centrifugal compressors were for wet seal and dry seal 

compressors. The estimated emissions from wet seal centrifugal compressors in the processing 

segment were determined to be 228 tpy of methane and 0.736 tpy of HAP. The estimated 

emissions from dry seal centrifugal compressors in the processing segment were determined to 

be 28.6 tpy of methane and 0.0926 tpy of HAP. These emission rates are summarized in table 6-3 

of the 2011 TSD. 

For reciprocating compressors, only one control method was evaluated; replacement of 

rod packing. The estimated emission reduction from replacing rod packing were 6.84 tpy of 
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methane and 0.0717 tpy of HAP. This was based on a formula that considered the gas 

composition of the segments, the current emission factors for reciprocating compressors as stated 

above and an assumed 11.5 cubic feet per hour per cylinder emission rate for a compressor with 

newly installed rod packing. 

For centrifugal compressors at natural gas processing plants we estimated potential 

reductions for 95 percent control using a capture system combined with either a combustion 

device or rerouting of captured gas in a process. This resulted in emission reductions of 216 tpy 

of methane and 0.699 tpy of HAP per unit. Table 4 below summarizes the cost analysis of the 

control options for methane as was conducted for the NSPS. 

Pneumatic Controllers in Production and Processing Segments 

For pneumatic controllers in production and at natural gas processing plants, we 

calculated the estimated methane and HAP emissions based on the emission rates for high-bleed 

and low bleed controllers. The controller is considered to be high-bleed when the emission are in 

excess of 6 standard cubic feet per hour (scfh), while low bleed devices bleed at a rate less than 

or equal to 6 scfh. For the 2012 NSPS, for the production segment, we used the best available 

emissions estimates from pneumatic devices that are presented in Table W-1A and W-1B of the 

Greenhouse Gas Mandatory Reporting Rule for Petroleum and Natural Gas Systems (Subpart 

W). For the processing segment we used the representative emissions from a bleed-device from 

Volume 12 of the EPA/GRI report. We used the methane emission rates from these sources and 

then applied the natural gas composition ratios to estimate HAP emissions. For natural gas and 

oil production the emission rates were estimated to be 6.91 tpy methane and 0.073 tpy HAP for a 

high bleed controller and 0.26 tpy methane and 0.003 tpy of HAP for a low-bleed controller. For 

the natural gas processing segment, the emissions were estimated to be 1 tpy of methane and 

0.01 tpy of HAP for both a high bleed device and a low-bleed device. 

The control technology options evaluated for pneumatic controllers in the production 

segment was replacement of high-bleed controllers with low-bleed controllers. For natural gas 

processing, we assumed that all high-bleed controllers had already been replaced by non-gas 

driven controllers. We estimated that the emission reduction from replacing a high-bleed 

pneumatic controller with a low-bleed controller to be 6.65 tpy of methane and 0.07 tpy of HAP 

in the production segment. We used the incremental cost of a high-bleed device over a low-bleed 

device of $165 to estimate cost of control for the production segment. 
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Because we estimated that the high-bleed devices were already replaced with instrument 

air systems (non-gas driven) the rule required zero emissions from these sources. We estimated 

the cost of several size instrument air systems to evaluate cost of control for these sources at 

natural gas processing plants. The cost evaluation of these systems is discussed in detail in 

section 5.4.2.3 of the 2011 TSD. Table 5 below summarizes the results of the cost of control 

analysis for pneumatic controllers for the 2012 NSPS. 
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Table 2. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Hydraulically FracNatural Gas Well Completions 

Emissions Per Unit 

(tons/completion 

event)a Control Method 

Natural Gas 

Savedb 

(Mcf/ 

completion 

event) 

Emission Reductions 

(tons/completion 

event)c

Capital 

Costd

($2008) 

Total Cost 

 ($/completion 

event)d

Methane HAP Methane HAP without savings with gas savingse 

155.53 1.649 REC 8,100 139.97 1.48 29,713 $29,713 net savings 155.53 1.649 Combustion NA 147.75 1.57 3,523 $3,523 NA 155.53 1.649 REC with Combustion 8,100 147.75 1.57 $33,237 $33,237 $837 

a. Based on 9,000 Mcf natural gas emissions per 7-day completion event (from the final 2012 TSD Section 1.5) and 83.081 percent mfrom gas wells, and 0.0208 tons of methane per Mcf, and 0.0106 HAP to methane ratio for gas wells. b. Based on gas savings of ninety percent for a REC. Calculated from savings per unit based on $4 per Mcf of natural gas. Gas saved fcompressors only applies to control routing to a process. c. Based on 90 percent control for REC and 95 percent control for combustion and REC combined with combustion. d. From tables 4-5, 4-6 and 4-8 of the 2011 TSD. e. Savings based on natural gas saved for a REC at $4 per Mcf. No savings is attributed to combustion. 
8 

Table 3. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Equipment LProcessing Plants

Emissions Per Unit 

(tpy)a Control Method 

Natural 

Gas 

Savedb 

(Mcf/yr) 

Emission 

Reductions 

(tpy)c

Capital 

Costd

($2008) 

Annual Cost 

($2008)d

Methane HAP Methane HAP without savings with gas savingse 

51.4 0.539 Subpart VVa LDAR 2,819 48.5 0.508 7,522 $45,160 $33,915 51.4 0.539 OGI/Method 21 Monitoring 2819 48.5 0.508 92,522 $87,059 $75,813 

a. Based on model plant described in Table 8-6 of the 2011 TSD. b. Estimated gas savings for model plant described in Table 8-6 of the 2011 TSD. c. Based on a control effectiveness of 93.6% for valves, 95.9% for connectors, 100% for open-ended lines and 100% for pressure relied. From tables 8-13 and 8-18 of the 2011 TSD. e. Savings based on $4 per Mcf of natural gas saved. 
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Table 4. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Compressors 

Compressor 

Type/ 

Oil and Gas 

Segment 

Emissions Per 

Unit 

(tons/year)a Control 

Method 

Natural 

Gas 

Savedb

per unit 

(Mcf/yr) 

Emission 

Reductions 

(tons/compressoryear)c Capital Costd

($2008)c

Annual Cost per 

Compressor 

($/compressoryear)d

Methane HAP Methane HAP without savings with ga

savings

Reciprocating 

Gathering & 

Boosting 12.3 0.129 Replace Rod Packing 397 6.84 0.072 $5,346 $1,669 $83 

Processing 23.3 0.244 Replace Rod Packing 1079 18.6 0.195 $4,050 $1,413 Net Saving

Centrifugal (wet seal) 

Processing 228 0.736 

Route to 

Combustion 

device or 

process 

12,527 216 0.699 $67,918 $103,371 $53,26

a. From Table 6-3 of the 2011 TSD. b. Calculated from savings per unit based on $4 per Mcf of natural gas. Gas saved for centrifugal compressors only applies to control roc. From Table 6-6 of the 2011 TSD for reciprocating compressors and Table 6-10 of the 2011 TSD for centrifugal compressors d From table 6-7 of the 2011 TSD for reciprocating compressors and Table 6-12 of the 2011 TSD for centrifugal compressors. e. Savings for centrifugal compressors only applies when routing emissions to a process. There is no savings for routing to a combustio
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Table 5. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Pneumatic Control

Compressor 

Type/ 

Oil and Gas 

Segment 

Emissions Per 

Unit 

(tons/year)a Control 

Method 

Natural 

Gas 

Savedb

per unit 

(Mcf/yr) 

Emission 

Reductions 

(tons/compressoryear)c Capital Costd

($2008)c

Annual Cost per 

Compressor 

($/compressoryear)d

Methane HAP Methane HAP without savings with ga

saving

Natural Gas 

Processing 1 0.01 

Instrument Air- Zero Emission Rate 

871 225 2 16,972 11,090 7,606 

Oil and 

Natural Gas 

Production 

6.91 0.073 

Emission threshold -  6 scfh) 

386 6.65 0.07 165 23 -1,519 

a. From table 5-2 of the 2011 TSD . b. Value of recovered product assumes natural gas processing is 82.8 percent methane by volume. A natural gas price of $4 per Mcf wa

c. From Table 5-6 of the 2011 TSD for production segment. For the natural gas processing segment, the reductions are based on a smalreduction per loop and 15 control loops (See table 5-11 of the 2011 TSD). d. From Tables 5-10 and 5-11 of the 2011 TSD.