i 

Oil and Natural Gas Sector: Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission, and 

Distribution. 

Background Supplemental Technical Support Document for the 

Final New Source Performance Standards 
ii 

April 2012 

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

Production, Transmission, and Distribution. 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

With technical support provided by: 

EC/R, Incorporated 

501 Eastowne Dr, Suite 250 

Chapel Hill, North Carolina 27514 

ICF International 

9300 Lee Hwy 

Fairfax, VA 22031 

RTI International 

3040 East Cornwallis Road 

Post Office Box 12194 

Research Triangle Park, NC 27709-2194 
iii 

DISCLAIMER 

This report has been reviewed by EPA’s Office of Air Quality Planning and Standards and has been 

approved for publication. Mention of trade names or commercial products is not intended to 

constitute endorsement or recommendation for use. 
iv 

Contents 

SUPPLEMENTAL TECHNICAL SUPPORT DOCUMENT SUMMARY ................................. vi

1.0 EVALUTION OF THE EMISSION FACTOR FOR HYDRAULICALY FRACTURED 

GAS WELL COMPLETIONS AND RECOMPLETIONS .............................................. 1-1

1.1 Emission Factor Development .............................................................................. 1-1

1.2 Data Submitted Through NSPS Comments .......................................................... 1-6

1.3 Evaluation of Alternative Emission Factor Calculations ...................................... 1-8

1.4 Final Emission Factor .......................................................................................... 1-13

1.5 Summary of Evaluation ....................................................................................... 1-14

1.6 Statistical Analysis: Development of a Bayesian Posterior Interval for the 

Emission Factor for Hydraulically Fractured Well Completions ........................ 1-15

2.0 NSPS LOW PRESSURE COMPLETION THRESHOLD ............................................... 2-1

2.1 Overview ............................................................................................................... 2-1

2.2 Development of the Pressure Equation ................................................................. 2-2

2.3 Estimated National Impacts of Implementing the Pressure Equation ................. 2-16

2.4 Conclusions ......................................................................................................... 2-21

3.0 GAS WELL RE-FRACTURE FREQUENCY .................................................................. 3-1

3.1 Revised Gas Well Re-Fracture Frequency Methodology ...................................... 3-1

4.0 NATIONAL IMPACT OF NSPS OOOO REQUIREMENTS ON GAS WELL 

COMPLETIONS ............................................................................................................... 4-1

4.1 Summary of National Impacts Methodology ........................................................ 4-1

4.2 Descriptions of Data Used in the Impacts Analysis .............................................. 4-3

4.3 Final Impacts Results ............................................................................................ 4-5

5.0 VOLUNTARY REDUCTIONS FROM GAS WELL COMPLETIONS WITH 

HYDRAULIC FRACTURING ......................................................................................... 5-1

5.1 Number of Voluntary RECs .................................................................................. 5-1

5.2 Number of Completions Events Eligible for RECs.................................... 5-3 

5.3 Fraction of Eligible Completions with Voluntary RECs ....................................... 5-6

5.4 New Source Completions and Recompletions with Voluntary Action ................. 5-7

6.0 CENTRIFUGAL COMPRESSOR IMPACTS ................................................................. 6-1

6.1 Projected Number of Affected Units ..................................................................... 6-1

6.2 Capital Costs .......................................................................................................... 6-1

6.3 Without Revenues from Additional Product Recovery ......................................... 6-2

6.4 With Revenues from Additional Product Recovery .............................................. 6-2
v 

6.5 Baseline Emissions from Wet Seal Centrifugal Compressors in the Processing 

Sector ..................................................................................................................... 6-2

6.6 Emission Reduction for Wet Seal Centrifugal Compressors in the Processing 

Sector ..................................................................................................................... 6-2

7.0 UPDATE TO TECHNICAL SUPPORT DOCUMENT FOR PROPOSED STANDARDS 

OF PERFORMANCE FOR CRUDE OIL AND NATURAL GAS PRODUCTION, 

TRANSMISSION, AND DISTRIBUTION – STORAGE VESSELS ............................. 7-1

7.1 INTRODUCTION ................................................................................................. 7-1

7.2 BASELINE EMISSIONS ...................................................................................... 7-1

7.3 COST OF CONTROL TECHNIQUES ................................................................. 7-1

7.4 REGULATORY OPTIONS AND NATIONWIDE IMPACTS OF 

REGULATORY OPTIONS .................................................................................. 7-4

8.0 UPDATE TO TECHNICAL SUPPORT DOCUMENT FOR PROPOSED STANDARDS 

OF PERFORMANCE FOR CRUDE OIL AND NATURAL GAS PRODUCTION, 

TRANSMISSION, AND DISTRIBUTION – EQUIPMENT LEAKS ............................. 8-1

8.1 INTRODUCTION ................................................................................................. 8-1

8.2 BACKGROUND ................................................................................................... 8-1

8.3 UNIFORM STANDARDS DATA AND METHODOLOGY .............................. 8-2

8.3 RESULTS ................................................................................................................. 5

APPENDIX A: SUPPLEMENTARY DATA FOR THE EVALUTION OF THE EMISSION 

FACTOR FOR HYDRAULICALLY FRACTURED GAS WELL COMPLETIONS AND 

RECOMPLETIONS ......................................................................................................... A-1

APPENDIX B: SUPPLEMENTARY ANALYSES FOR LOW PRESSURE COMPLETION 

THRESHOLD .................................................................................................................. B-1

B.1 Derivation of Density from the Ideal Gas Law .................................................... B-1

B.2 Water Film Impact on Inner Tubing Diameter ..................................................... B-3

B.3 Determination of Turbulent Flow ......................................................................... B-5

B.4 Alternative Method for Calculating the Compressibility Factor for Natural Gas B-7

APPENDIX C: COST AND EMISSION SPREADSHEETS OF THE LDAR ANALYSES.... C-1
vi 

SUPPLEMENTAL TECHNICAL SUPPORT DOCUMENT SUMMARY 

This Supplemental Technical Support Document (TSD) provides background and technical 

analyses to support the final New Source Performance Standards (NSPS) for limiting volatile 

organic compound (VOC) and sulfur dioxide (SO2) emissions from the Oil and Natural Gas 

Sector. The standards were developed according to section 111(b)(1)(B) under the Clean Air 

Act, which requires EPA to review and revise, if appropriate, NSPS standards. The final 

standards were developed following consideration of public comments received on the standards 

proposed on August 23, 2011 (76 FR 52738). Section 1.0 presents the development of the 

emission factor for hydraulically fractured gas well completions and recompletions used in the 

NSPS regulatory impacts analysis, including a discussion of the methodology and the data 

sources. This section also provides an analysis of relevant data submitted with the public 

comments. Section 2.0 presents the derivation of an equation to determine the pressure threshold 

for a “low pressure” well. In Section 3.0, changes to the gas well refracture frequency estimates 

from the proposed NSPS to the final standards are summarized. Section 4.0 presents the impacts 

of regulating VOC emissions from new gas well completions following hydraulic fracturing 

where reduced emissions completions (RECs) are required. Section 5.0 details the analysis used 

to estimate the number of gas well completions with hydraulic fracturing voluntarily performed 

with capture and combustion equipment in the year 2015. Section 6.0 presents an estimate of the 

impacts related to the regulation of centrifugal compressors and the data used in those estimates. 

Section 7.0 presents an analysis of impacts associated with regulatory options for storage vessels. 

Finally, Section 8.0 provides the results of the equipment leak cost analysis for the NSPS using 

emission factors and cost data from the Uniform Standards for Equipment Leaks rule (40 CFR 

part 65, subpart J) that EPA proposed on February 24, 2012. Appendices contained at the end of 

this TSD provide supplemental information to the main chapters described above. 

The following table presents a crosswalk between the sections of the proposal TSD and the 

sections of this document that update the proposal TSD sections. 

Proposal TSD Updated by Section in 

Section Number Section Title this Document 

1.0 New Source Performance Background N/A 

2.0 Sector Description N/A 

3.0 New Source Performance Review Process N/A 

4.0 Well Completions and Recompletions 1.0, 2.0, 3.0, 4.0, 5.0 

5.0 Pneumatic Controllers N/A 

6.0 Compressors 6.0 

7.0 Storage Vessels 7.0 

8.0 Equipment Leaks 8.0 
1-1 

1.0 EVALUTION OF THE EMISSION FACTOR FOR HYDRAULICALY 

FRACTURED GAS WELL COMPLETIONS AND RECOMPLETIONS 

This section details the development of the emission factor used in the NSPS regulation impacts 

analysis, including a discussion of the methodology and the data sources, and then provides 

detail on the analysis of data presented to EPA through the public comment period of the NSPS. 

1.1 Emission Factor Development 

1.1.1 Previous Estimates of Methane from Natural Gas Production

EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks1 methane emissions estimates for 

natural gas systems depend heavily on emissions factors from a 1996 EPA/GRI study.2 

Hydraulically fractured gas well completions and workovers are a significant proportion of 

completions and workovers today, but were not as common during the development of the 1996 

EPA/GRI study. The study calculated an emission factor for gas well completions by making 

several key assumptions. These assumptions were based on the data and knowledge of industry 

practices available at the time but which are not appropriate for hydraulically fractured wells. 

These assumptions included: 

• Emissions that occur during the well completion are equal to one day of the average gas 

production rate per gas well in 1992 based on the American Gas Association’s Gas Facts. 

• All completion emissions are flared (reducing the methane emissions from each 

completion by approximately 98 percent). 

Since the publication of the 1996 EPA/GRI study, the number of hydraulically fractured gas well 

completions has increased significantly to 9,000 hydraulically fractured wells completed 

annually according to the National Energy Modeling System’s (NEMS) models. Through 

extensive interactions with oil and gas companies and industry experts and through a review of 

best available data, EPA became aware that the assumptions made in the 1996 EPA/GRI study 

did not accurately characterize methane emissions from hydraulically fractured gas wells. In 

particular: 

• The 16.97 million cubic feet per year average gas production rate in 1992, which GRI 

used as a surrogate for the average completion flow rate, includes a large number of 

marginal wells. Marginal low pressure wells have significantly less gas production than 

newly completed hydraulically fractured wells. 

• Significant quantities of gas are produced during the completion process for a 

hydraulically fractured gas well, in particular during the flowback period. In 2004, 

companies began sharing information with EPA on voluntary activities to reduce 

emissions from hydraulically fractured gas well completions, referred to as Reduced 

Emission Completions. Companies reported that the extended flowback time (as 

compared to conventional completions) and increased volume of natural gas during the 

 

1

 http://epa.gov/climatechange/emissions/usinventoryreport.html 

2

 EPA/GRI. Methane Emissions from the Natural Gas Industry. June 1996. Available at 

http://www.epa.gov/gasstar/tools/related.html 
1-2 

flowback period, made it cost-effective to bring portable equipment on-site to capture the 

increased natural gas for market. EPA currently assumes an average flowback period of 3 

to 10 days for hydraulically fractured wells. 

• Finally, through interactions with companies at EPA and industry events as well as public 

data and experiences shared by the industry, EPA is aware that not all companies are 

flaring the flowback gas, contrary to the assumption in the 1996 EPA/GRI study. In fact, 

many companies are either capturing through reduced emissions completions (RECs) or 

venting the gas that occurs during the completion of hydraulically fractured gas wells. 

Based on this information, and review of available data on emissions per completions from 

hydraulic fracturing, EPA has concluded that the emission factor for gas well completions from 

the 1996 EPA/GRI study no longer represents the diversity of gas well completion practices in 

use today, and the emission rates associated with these practices. On the basis of the available 

data reported by companies carrying out hydraulic fracturing and RECs, EPA developed an 

emission factor specifically for gas well completions with hydraulic fracturing, as described in 

the section below. 

1.1.2 Emission factor for completions with hydraulic fracturing

In 2010, on the basis of information reported by companies carrying out hydraulic fracturing and 

RECs, EPA developed an emission factor specifically for hydraulically fractured gas well 

completions. This factor was first used in the Technical Support Document for Subpart W of 

Part 98, GHG reporting rule, and also in the 1990-2009 Inventory (published in April 2011). 

The emission factor for gas well completions with hydraulic fracturing was developed using four 

data sources, together representing data from over 1,000 well completions with hydraulic 

fracturing. These data were provided to EPA or its technical contractors by industry for 

presentation at Natural Gas STAR technology transfer workshops from 2004-2007. For each 

data source, EPA calculated the average gas release per gas well completion. The data from these 

wells collectively indicate that the true average gas release rate for a hydraulically fractured well 

completion is substantially higher (greater than two orders of magnitude) than the 1996 

GRI/EPA emission factor that is applicable to conventional well completions. These data also 

indicate that there is a high degree of variability in gas release rates across hydraulically 

fractured well completions due to geology, technology and operating conditions. The four 

calculated averages were each then rounded to the nearest single significant digit to reflect the 

precision of these averages. The resulting emission factors from each of the four data sources 

were arithmetically averaged to determine the final emission factor for gas well completions with 

hydraulic fracturing. 

As the variability was already reflected through the rounding of the rate developed from each 

data set, EPA elected not to round the final average calculated from the four rates. Had EPA 

rounded the final number, it would be 9,000 Mcf per completion or 2% lower. If EPA had not 

rounded the results of the initial studies, the final average well emission factor would be 11,057 

Mcf per completion, or 21% higher. 
1-3 

A detailed breakdown of each source and the calculation method to determine the emission 

factor is shown in Table 1-1. The calculation is as follows: 

completion

completion Mcf

Mcf

completion

Mcf

completion

Mcf

completion

Mcf

9,175

4

6,000 10,000 700 20,000

=

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

Table 1-1: Summary of Data Sources Used for the Original EF (9,175 Mcf per completion)

Data Source Year(s) # of Wells 

Total Gas 

Emissions 

(Mcf) 

Average Gas 

Emissions Per 

Completion 

(Mcf) 

Formation 

Type 

Industry Data 

Set #1 - 106 616,887 5,820 Tight Sands

Williams 2002 to 2006 1,064 26,014,00

0 24,449 Tight Sands

Devon 2004 30 357,000 11,900 Shale 

Weatherford 2004 3 2,000 667 CBM 

1.1.2.1 Industry Data Set #1 

In 2004, an EPA technical contractor received a data set from a natural gas production company. 

The data set included information on volumes of gas sold and flared from 106 completions at 

wells with hydraulic fracturing (see Appendix A). On the basis of this information, the 

contractor calculated a national-level estimate of recoverable gas from completions3

. In the 

original work to develop the factor, EPA used the national estimate of recoverable gas from 

completions and information on national well counts to calculate average potential emissions per 

well.4

 The calculated results of average value of potential emissions per well, 5,815 Mcf per 

completion, was rounded to the nearest 1,000 Mcf per completion (one significant figure), 

equaling 6,000 Mcf per completion. 

The gas producer has since provided EPA with the detailed data set, after removing identifying 

information such as the geographic area and company name. EPA used this data set on number 

of completions, gas flared, and sold for each completion to calculate average potential emissions 

 

3

 Green Completions. Natural Gas STAR Producer’s Technology Transfer Workshop. September 21, 2004. 

<http://epa.gov/gasstar/workshops/techtransfer/2004/houston-02.html> Slide 4. 

4

 Appendix B of the Background Technical Support Document for Subpart W of the Greenhouse Gas Reporting 

Rule, available at http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_TSD.pdf
1-4 

(5,820 Mcf per completion, which also rounds to 6,000 Mcf per completion). The detailed data 

set is shown in Appendix A. 

1.1.2.2 Williams Data 

Williams Inc. reported generating 26,014 MMcf of natural gas from 1,064 completions5. 

Therefore, 

[26,014 MMcf]*[1000 Mcf/MMcf] / [1064 completions] = 24,449 Mcf per completion 

The 24,449 Mcf per completion was rounded to the nearest 10,000 Mcf per completion, equaling 

20,000 Mcf per completion. 

1.1.2.3 Devon Data 

Devon Energy provided EPA6 with data from 30 wells with an average rate of 11,900 Mcf 

natural gas recovered and sold rather than vented. To calculate a potential emissions rate from 

this data, EPA assumed that 90% of the natural gas vented was recovered. Therefore, 

[11,900 Mcf/completion] / [90%] = 13,222 Mcf per completion 

The 13,222 Mcf per completion was rounded to the nearest 10,000 Mcf per completion, equaling 

10,000 Mcf per completion. 

1.1.2.4 Weatherford Data 

Weatherford provided data from 3 well completions7. Those completions together captured 2 

MMcf of gas. Again to calculate a potential emissions factor, EPA assumed that 90% of the 

natural gas released was recovered. Therefore, 

[2 MMcf/completion]*[1000 Mcf/MMcf] / ([90%]*[3 completions]) = 740 Mcf per completion 

The 740 Mcf per completion was rounded to the nearest 100 Mcf per completion, equaling 700 

Mcf per completion. 

 

5

 EPA. Reducing Methane Emissions During Completion Operations. Natural Gas STAR Producer’s Technology 

Transfer Workshop. September 11, 2007. <http://www.epa.gov/gasstar/documents/workshops/glenwood2007/04_recs.pdf> Slide 14. 

6

 Green Completions. Natural Gas STAR Producer’s Technology Transfer Workshop. September 21, 2004. 

<http://epa.gov/gasstar/workshops/techtransfer/2004/houston-02.html> Slide 13. 

7

 Green Completions. Natural Gas STAR Producer’s Technology Transfer Workshop. September 21, 2004. 

<http://epa.gov/gasstar/workshops/techtransfer/2004/houston-02.html> Slide 14. 
1-5 

1.1.3 Estimating Emissions from Completions with Hydraulic Fracturing

The 9,175 Mcf per completion emission factor represents natural gas released from the 

completion of a hydraulically fractured natural gas well (i.e., potential gas emissions from the 

completion process in the absence of controls to capture or flare the released gas). It is very 

important to note that in calculating total national emissions from completions with hydraulic 

fracturing for the Inventory of U.S. Greenhouse Gas Emissions and Sinks, the EPA adjusts 

calculated methane release for methane that is actually not emitted (i.e., that is instead flared or 

controlled with certain technologies and practices) due to both voluntary action and State 

regulations. EPA uses this approach across the national inventory for many source categories, 

and it is consistent with internationally agreed guidance from the IPCC.8 Specifically, the 

development of the national emissions estimates for unconventional natural gas wells requiring 

hydraulic fracture involves the following key steps: 

• Start with the unmitigated national emission factor (9,175 Mcf of gas per completion). 

• Adjust this factor by the average methane content of gas (on a regional basis). 

• Multiply by the number of well completions and recompletions that involve hydraulic 

fracturing in each region, and then sum the regional totals to calculate total unmitigated 

methane emissions from the completions and workovers with hydraulic fracturing in the 

U.S. 

• Calculate the amount of the methane that is not emitted, using data on voluntary action 

and State regulations in order to develop a more accurate picture of actual emissions from 

this source category and sector. 

• Deduct the calculated amount of methane that is not emitted from the calculated total 

unmitigated methane emissions value to develop the net emissions estimate that is 

included in national emissions totals. The EPA notes that there has been a great deal of 

confusion about the Inventory methods for calculating net emissions. In the 1990-2010 

Inventory of U.S. Greenhouse Gas Emissions and Sinks (public review draft), EPA has 

provided improved information on this methodology. 

The NSPS analysis takes a similar approach in the development of its baseline emissions 

estimates, taking into account reductions from voluntary action and state regulations. Please see 

the RIA for more information on baseline emissions estimates. 

 

8 IPCC 2006, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Prepared by the National 

Greenhouse Gas Inventories Programme, Eggleston H.S., Buendia L., Miwa K., Ngara T. and Tanabe K. (eds). 

Published: IGES, Japan. 
1-6 

1.2 Data Submitted Through NSPS Comments 

This section describes well completions emissions information received through the NSPS public 

comments. Table 1-2 summarizes this information. 

Table 1-2: Summary of Data Presented to EPA through NSPS Comment Period 

Data Source Year(s) # of Wells 

Total Gas 

Emissions 

(Mcf) 

Average Gas 

Emissions Per 

Completion 

(Mcf) 

Formation 

Type 

Noble Energy Unknown 5 16,800 3,360 Tight Sands 

ConocoPhillips 2010 101 1,276,290 12,637 Tight Sands, 

Shale, CBM 

URS Data 2011 98 71,948 734 Tight Sands, 

Shale 

BP 1 2007 50 30,000 600 CBM 

BP 2 2007 18 16,938 941 CBM 

La Plata CEAP Unknown Unknown Unknown 1,875 CBM 

Southern Ute 

Tribe Unknown Unknown Unknown 5,000 CBM 

1.2.1 Noble Energy Data

In a comment submitted by Noble Energy for the NSPS9

, Noble provided average emissions per 

completion for 2 vertical and 3 horizontal wells. These wells were hydraulically fractured and 

produced from tight formations. The average from all 5 wells was 3,360 Mcf per completion. 

The emissions estimates were determined using a calibrated roots meter. 

1.2.2 ConocoPhillips Data

In a comment submitted by Earthworks10, Earthworks provided a reference to a presentation 

given by ConocoPhillips for a Natural Gas STAR Workshop in 2009. The presentation includes 

101 wells in three different formation types. The average from all wells is 12,637 Mcf per 

completion. 

 

9 http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0505-4228 10 http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0505-4275
1-7 

1.2.3 URS Data

A comment submitted by Devon Energy11 contains a study conducted by URS for ANGA. In the 

study, 7 companies submitted information relating to hydraulically fractured well completions at 

nearly 1200 wells. Of the 7 companies, 4 submitted emissions estimates for 98 well non-green 

completions (i.e., completions without RECs). Emissions estimates were not included for wells 

with RECs, which comprised 92% of the URS data set. For each of the 98 wells without REC 

completions, URS provided information on pressure, flowback duration, and choke size and used 

Equation W-11B from Subpart W of EPA’s Greenhouse Gas Reporting Rule to calculate the 

emissions from completions. Using this equation, and a number of simplifying assumptions, 

URS calculated an average emissions rate of 765 Mcf per completion. 

The 765 Mcf per completion is an emissions average per completion for wells in each of 5 

basins. The 765 Mcf per completion factor represents the simple average of the average 

emissions calculated from the 5 basins. For the calculations shown below, we have recalculated 

the rate per completion so that it is not weighted by basin, as the other data sets evaluated do not 

allow for separate estimates by basin. Instead, using the data from the 98 wells with emissions 

estimates, EPA calculated the average emissions rate of the data set to be 734 Mcf per 

completion. 

In reviewing the data and URS’ use of the Subpart W equation, it became apparent that the 

resulting flowrate from Equation W-11B was misinterpreted to result in a flow rate at standard 

conditions when it was in fact a flowrate at actual conditions. Converting from actual volume 

(actual conditions) to standard volume (standard conditions), which is the input intended to 

estimate emissions from gas well venting during completions and workovers following hydraulic 

fracturing in Equation W-10A, EPA re-calculated an average value greater than 50,000 Mcf per 

completion. This value is far higher than the value presented by URS (765 Mcf per completion) 

and values given in other data sets. EPA’s evaluation shows that the URS study is significantly 

underestimating emissions by using the equation at actual conditions, however, due to highly 

conservative assumptions made by URS (e.g., 100% gas in flowback instead of a mixture of gas 

and fluids, and maximum choke size and casing pressure), the recalculated emissions average of 

over 50,000 Mcf per completion may also be an inaccurate depiction of emissions. Given this 

uncertainty, EPA performed the analyses presented below both with (using the URS-calculated 

values per completion, averaged to 734 Mcf as noted above) and without the URS emissions 

estimates, for completeness and transparency. 

1.2.4 BP

In a comment submitted by Earthworks9, the commenter referenced two BP presentations. The 

two data sets corresponded to well completions carried out in CBM formations. The first BP data 

set contained 50 well completions and had average emissions of 600 Mcf per completion. The 

second BP data set contained 18 well completions and had average emissions of 941 Mcf per 

completion. 

 

11 http://www.epa.gov/quality/informationguidelines/documents/12003-attB.pdf
1-8 

1.2.5 La Plata CEAP

In a comment submitted by Earthworks9, the commenter referenced a La Plata Climate and 

Energy Action Plan process in which two companies (BP and Red Cedar, the Southern Ute 

Indian Tribe’s gas company) estimated that green completions could recover 1,875 Mcf per 

completion in the San Juan Basin based on industry completion data. 

1.2.6 Southern Ute Tribe

In a comment submitted by Earthworks9, the commenter referenced a figure from a 

Programmatic Environmental Assessment (PEA) for 80‐acre Infill Oil & Gas Development on 

the Southern Ute Indian Reservation developed by Environ. The emissions estimate was 5,000 

Mcf per completion.

1.3 Evaluation of Alternative Emission Factor Calculations 

In this section, EPA presents an analysis to determine whether or not the new information 

submitted through NSPS comments indicates a need to revise the emission factor used in the 

proposal, and to present and evaluate alternative emission factors. 

To determine how the factor might change by including data received through the public 

comment period, EPA used the data submitted through NSPS comments (Table 1-2 above) in 

combination with the data used for the original emission factor calculation (Table 1-1 above) to 

calculate a number of alternative emission factors for consideration. 

First, EPA developed two simple averages of the data: alternative factor 1, which is an average 

by well completion, and alternative factor 2, which is an average by data source. 

The data used to calculate alternative factors 1, and 2, which includes the data used in the 

original emission factor and the data submitted through NSPS comments is presented in Table 

1-3. 

Table 1-3: Data Used for Alternative Factors 1 and 2 

Data Source Year(s) # of Wells 

Total Gas 

Emissions 

(Mcf) 

Average Gas 

Emissions Per 

Completion 

(Mcf) 

Formation 

Type 

Industry Data 

Set #1* Unknown 106 616,887 5,820 Tight Sands 

Williams* 2002 to 

2006 1,064 26,014,000 24,449 Tight Sands 

Noble Energy Unknown 5 16,800 3,360 Tight Sands 
1-9 

ConocoPhillips 2010 101 1,276,290 12,637 Tight Sands, 

Shale, CBM 

URS Data 2011 98 71,948 734 Tight Sands, 

Shale 

Devon* 2004 30 357,000 11,900 Shale 

Weatherford* 2004 3 2,000 667 CBM 

BP 1 2007 50 30,000 600 CBM 

BP 2 2007 18 16,938 941 CBM 

La Plata CEAP Unknown Unknown Unknown 1,875 CBM 

Southern Ute 

Tribe Unknown Unknown Unknown 5,000 CBM 

* Denotes sources used for the original emission factor calculation. 

1.3.1 Alternative Factor 1: Average by Well Completion

The first alternative emission factor assessed was calculated by summing the total emissions 

from all data sets and dividing by the total number of completions. The La Plata CEAP and 

Southern Ute Tribe data points cannot be included when calculating emission factors using this 

method because these sources did not provide total emissions and total number of well 

completions. The resulting emission factor was about 20,574 Mcf per completion. Including 

the URS data, the calculated value is 19,256 Mcf per completion. 

This method results in an emission factor heavily affected by the number of well completions 

included in a given data set resulting in bias for one formation type. Tight sands are over 

represented, as 86% of the well completions in the data set were in tight sands, while nationally 

26.5 percent of annual completions are tight sands (NEMS 2010). Further, one data source 

(Williams) accounts for 1,064 of the 1,377 well completions, which may bias the result towards 

the Williams data, which has an average emissions rate of 24,449 Mcf per completion. 

1.3.2 Alternative Factor 2: Average by Data Source

The second alternative emission factor for assessment was estimated by performing a simple 

unweighted average of the average emissions per completion reported for each data source. This 

method calculated an average emission factor for each data source individually and then 

calculated a simple average of the 10 resulting emission factors. The average emission factors 

ranged from 600 Mcf per completion to 24,449 Mcf per completion. Of the 10 data sources, 3 

corresponded to tight sands, 1 to shale, 5 to CBM, and 1 was a mix of all three formations. The 
1-10 

resulting emission factor was about 6,725 Mcf per completion. Including the URS data, the 

calculated factor is 6,180 Mcf per completion. 

 

This method has the advantage of having no over-representation due to number of well 

completions included in a given data set resulting in bias for one formation type. However, it 

does result in over-representation of CBM completions due to the number of data sets including 

those types of completions (6 out of 10 data sources). In the U.S., 26.9 percent of annual 

completions are CBM (NEMS 2010). It also results in underrepresentation of shale completions, 

as only 2 of the data sources included shale completions. In the U.S. 46.5% of annual well 

completions are in shale (NEMS 2010). 

1.3.3 Alternative Factors 3 through 5

Next, a number of alternatives that weigh the factor by formation type were developed. Based 

on the data EPA has evaluated, formation type can greatly influence the volume of gas released 

per completion. Based on observations of the available data from the U.S. oil and natural gas 

industry, of the three formation types included here, coal bed methane typically has the lowest 

volume of gas released per completion, and shale typically has the highest. As the national 

average gas release per completion will therefore be influenced by the mix of completions 

nationally, here we examine factors that take this mix into account. To develop these weighted 

factors, we disaggregated data sets that included more than one formation type. The Conoco 

Phillips data set included three formation types, and was split into three data sets, and the URS 

data included two formation types and was likewise split into two data sets. Table 1-5 presents 

this disaggregation. 

Table 1-5: Data Used for Alternative Factors 3, 4, and 5 

Data Source Year(s) # of Wells

Total Gas 

Emissions 

(Mcf) 

Average Gas 

Emissions Per 

Completion 

(Mcf) 

Formation 

Type 

Industry Data Set 

#1* Unknown 106 616,887 5,820 Tight Sands 

Williams* 2002 to 

2006 1,064 26,014,000 24,449 Tight Sands 

Noble Energy Unknown 5 16,800 3,360 Tight Sands 

ConocoPhillips 2010 10 60,222 6,022 Tight Sands 

URS Data 2011 41 16282 397 Tight Sands 

ConocoPhillips 2010 83 1,200,000 14,458 Shale 
1-11 

Devon* 2004 30 357,000 11,900 Shale 

URS Data 2011 57 55,666 977 Shale 

Weatherford* 2004 3 2,000 667 CBM 

BP 1 2007 50 30,000 600 CBM 

BP 2 2007 18 16,938 941 CBM 

La Plata CEAP Unknown Unknown Unknown 1,875 CBM 

Southern Ute 

Tribe Unknown Unknown Unknown 5,000 CBM 

ConocoPhillips 2010 8 16,068 2,009 CBM 

* Denotes sources used for the original emission factor calculation. 

1.3.3.1 Alternative Factor 3: Weighting by 3 Formation Types Based on Production 

Using all of the data for which we had information on formation type, an emission factor for 

tight sands (9,913 Mcf per completion), an emission factor for shale (13,179 Mcf per 

completion), and an emission factor for CBM (1,849 Mcf per completion) were generated.12 A 

final emission factor was then determined using a weighted average based on ratios of 

production from each formation to the total production from CBM, shale, and tight sands (see 

Table 1-6). The resulting emission factor was about 9,984 Mcf per completion. Including the 

URS data, the calculated factor is 7,554 Mcf per completion. 

 

This alternative factor has the advantage of having no over-representation of a given formation 

type due to greater number of data sets or wells. This method recognizes within the calculation 

methodology that formation can be a significant variable affecting the total emissions per 

completion. However, a ratio of gas production may not be a good surrogate for a ratio of 

completion flowback volumes. In addition, a ratio of gas production might not be representative 

of the current completions being carried out in each formation. 

 

12 Including the URS, the calculated emissions rate for tight sands is 8,010 Mcf/completion and for shale is 9,111 

Mcf/completion. The URS data set did not include data on CBM, so that rate is unaffected. 
1-12 

Table 1-6: Summary of Data Used for Weighting of Alternative Factor 3

Formation Type 

U.S. Gas 

Production 

(Mcf/year) 

Fraction of Average 

Production Flow Rate 

Tight Sands 6,287,544,084 0.49 

Shale 4,656,526,998 0.37 

CBM 1,773,088,295 0.14 

U.S. Total Gas 

Production 12,717,159,377 1.0 

1.3.3.2 Alternative Factor 4: Weighting by 3 formation types, based on the number of 

completions for each formation type 

The same calculated emissions rates for each of the three formation types used to calculate 

Alternative Factor 3 were used to calculate Alternative Factor 4. A final emission factor was 

then determined using a weighted average based on the number of well completions carried out 

in each formation according to the NEMS models (see Table 1-7). The resulting emission factor 

was about 9,263 Mcf per completion. Including the URS data, the value is 6,864 Mcf per 

completion. 

Table 1-7: Summary of Data Used for Weighting of Alternative Factors 4 and 5

Formation Type U.S. Gas Completion 

Counts % of Total 

Tight Sands 2,393 26.5% 

Shale 4,196 46.5% 

CBM 2,426 26.9% 

U.S. Total Gas Completions 9,015 100% 

This alternative factor has the advantages of having no over-representation of a given formation 

type due to greater number of data sets, and that it represents current trends in the natural gas 

industry based on the formations being developed. This method recognizes within the calculation 

methodology that formation can be a significant variable affecting the total emissions per 

completion. This method also weighs by the number of completions by formation type, which is 

more closely corresponds to total completion emissions per formation, than production by 

formation. 
1-13 

1.3.3.3 Alternative Factor 5: Weighing by 2 formation categories (CBM and tight sands/shale), 

based on number of completions in formation categories 

As data for tight sands and shale showed similar levels of emissions, EPA evaluated an option 

that treated the two formation types as one. To develop the fifth alternative emission factor for 

analysis, the data was first separated into one of two groups according to formation: tight/shale 

and CBM. An emission factor for tight sands/shale (11,025 Mcf per completion)13 and an 

emission factor for CBM (1,849 Mcf per completion) were generated. 

A final emission factor was then determined using a weighted average based on the number of 

well completions carried out in each formation according to the National Energy Modeling 

System (NEMS) models. The resulting emission factor was about 8,538 Mcf per completion. 

Including the URS data, the factor is 7,466 Mcf per completion. 

This alternative factor has the advantages of having no over-representation of a given formation 

type due to greater number of data sets, and that it represents current trends in the natural gas 

industry based on the formations being developed. This method recognizes within the calculation 

methodology that formation can be a significant variable affecting the total emissions per 

completion, but that emissions from tight sands and shale formations may not be significantly 

different. This method also weighs by the number of completions by formation type, which is 

more closely corresponds to total completion emissions per formation, than production by 

formation. 

1.4 Final Emission Factor 

The EPA evaluated all of the data (both data used to develop the original factor and data from the 

commenters) in several ways to determine whether an improved emission factor could be 

developed. Every calculation methodology considered had positive and negative aspects with 

respect to arriving at a single average emissions factor to represent U.S. flowback emissions 

following hydraulic fracture of a gas well. Excluding the URS data, 3 of the 5 analyses produced 

factors higher than the 9,175 factor, and 2 produced lower results. Including the URS data, 1 of 

the analyses produced a factor higher than 9,175, and 4 analyses produced factors lower than 

9,175. 

 

13 Including the URS data, this value is 9,969 Mcf/completion. 
1-14 

1.5 Summary of Evaluation 

Table 1-11: Summary of Results 

Alternative 

Factor 

Number 

Description Factor Value 

(Mcf/completion) 

1 Average by Well Completion 20,574 

2 Average by Data Source 6,725 

3 Weighting by 3 formation types based on production per 

formation type 

9,984 

4 Weighting by 3 formation types, based on the number of 

completions for each formation type 

9,263 

5 

Weighing by 2 formation categories (CBM and tight 

sands/shale), based on number of completions in formation 

categories 

8,538 

The alternative factors weighted by formation type have the advantage of having no overrepresentation of a given formation type due to greater number of data sets or wells. These 

methods recognize within the calculation methodology that formation can be a significant 

variable affecting the total emissions per completion. The factors weighted by formation type 

were very similar to EPA’s emission factor of 9,175. 

The five different calculation methodologies incorporating new data submitted through NSPS 

comments result in emission factors that fall within the expected interval estimate calculated for 

EPA’s original factor in section 1.6 below. Additionally, EPA’s original factor is closest to the 

results produced when formation type is taken into account, which is a key factor in influencing 

the emission rate. As a result of this analysis EPA concludes that, although it does have 

uncertainty, the original EPA emission factor provides a valid central estimate of emissions from 

this source in the U.S. Therefore, EPA has decided to retain the data set and the methodology 

used to develop the original emission factor of 9,175 thousand cubic feet (Mcf) per completion. 

EPA acknowledges that it did not apply a consistent approach to rounding of significant figures 

in each individual steps of the original calculation. To address this inconsistency, EPA is 

making a minor revision by rounding the end result to 1 significant figure. The final emission 

factor is 9,000 Mcf per completion.

 
1-15 

1.6 Statistical Analysis: Development of a Bayesian Posterior Interval for the Emission 

Factor for Hydraulically Fractured Well Completions 

Overview

EPA conducted a statistical analysis of the data and developed a Bayesian posterior interval to 

assess the validity of the emission factor for hydraulically fractured completions. This section 

describes that analysis. 

Data Set for Analysis 

As described above, the development of the emission factor of 9,175 Mcf per completion used 

data from four data sets, together representing data from over 1,000 well completions with 

hydraulic fracturing. To calculate a robust interval estimate for the emission factor EPA used 

data on emissions reductions reported by industry to EPA’s Natural Gas STAR program. The 

data set includes several years of data, and contains 56 data entries on reductions from over 

9,000 completions at wells with hydraulic fracturing. This larger data set was able to provide a 

robust interval estimate for the emission factor. 

As will be shown in this section, the distributional characteristic of the Gas STAR data appeared 

to be similar in nature to the data used to calculate the emission factor. Based on these statistical 

similarities it is justifiable to use the Gas STAR data to construct prior distributions for purposes 

of improving the estimate of variance and interval estimates centered on the emission factor. 

Specifically, the Gas STAR data is used to estimate the variance of the emission factor. 

Gas Content 

The emission factor of 9,175 Mcf per completion represents total potential gas emissions. The 

Gas STAR data represents potential methane emissions (i.e., a subset of the total potential gas 

emissions). To develop a meaningful comparison for the purposes of this analysis, we’ve 

converted the 9,175 Mcf whole gas emission factor to a methane emission factor of 8,900 Mcf 

CH4 per completion, using a methane content value of 83.24% (ECR 2011) and the same 

averaging and rounding methodologies that were used in the calculation of the 9,175 factor. 

More detail is presented below. 

Within Data Set Variation 

Due to the nature of the data—data entries in Gas STAR are aggregate, not at the well-level--a 

within data set estimate of variance was unobtainable. All estimates of variance explored here 

are due to between data set variability. For this reason, it is possible that the overall variance 

presented in this section is an underestimate of the true amount of variability. However, if the 

between source variability is significantly greater than the within source variability then the bias 

in the variance is likely to be small. 

Bayesian Model 
1-16 

A relatively simple model was chosen for purposes of analysis14. The four observations of the 

emission factors data are assumed to be normally distributed with a mean of ߤ and a known 

variance of ߪଶ set equal to the sample variance. From prior knowledge, it is reasonable to 

assume that the mean ߤ is normally distributed with known mean ߤ ଴and variance ߬ଶ. The mean 

of the prior distribution will be set to the mean of the sample, which is the current emission 

factor, converted to Mcf CH4 per completion, of 8,900. As a result, the posterior distribution will 

be normal with a mean equal to the emission factor (8,900) and variance that is a sum of inverse 

of the prior variance, ߬ଶ, and the inverse of the sample variance, ߪଶ⁄݊ . The sample size for the 

emission factor data set is 4. Therefore the posterior variance of the emission factor is: 

 

ாிߪ

ଶ ൌ 1

ቀ 1

߬ଶ ൅ 4

ଶቁߪ

Note that the sample size is 4. The interval estimate will be based on the posterior distribution of 

the mean. 

Datasets

Emission Factor Data 

Information from the 4 data sets used to calculate the emission factor is shown in Table 1-8 

below. The data sets together represent emissions calculated for over 1,000 well completions; 

however, not all of the data sets presented well-level information. As such, we were unable to 

analyze the within data set variance. The values presented below are the average emissions for 

each data set. The column labeled ‘Whole Gas’ shows the value used to develop the Mcf gas per 

completion value of 9,175. The column labeled ‘Modified’ is the Whole Gas column multiplied 

by the methane content correction factor of 0.8324. The final column labeled ‘Rounded’ is the 

values that are used to calculate the emission factor. 

Table 1-8. Data Used to Calculate the Emission Factor 

Data Source Whole Gas Modified Rounded 

Weatherford 667 555 600 

Industry Data Set #1 5,820 4,844 5,000 

Devon 11,900 9,905 10,000 

William 24,449 20,351 20,000 

The average of the four rounded values is 8900 and the standard error is 4,168. Due to the small 

number of data sets (4) the confidence interval around the emission factor that is very wide. 

 

14Gelman, Andrew; Carlin, John B.; Stern, Hal S.; Rubin, Donald B. (2003). Bayesian Data Analysis, Second Edition.

Boca Raton, FL: Chapman and Hall/CRC. ISBN 1‐58488‐388‐X.
1-17 

Using the standard distributional assumptions, the 95% confidence interval based on the 4 data 

sets is: 

ݔ ഥ േ ݐଷ,.଴ଶହܵܧሺݔ ഥ ሻ

where ݐଷ,.଴ଶହ is a value from the T-distribution with 3 degrees of freedom. The values for ݔ ഥ and 

ܵܧሺݔ ഥሻ are given in Table 1-9. Using these values the 95% CI for the current emission factor is (-

8,510, 26,100). In the sections below the goal will be to obtain a more useful interval estimate 

for the emission factor. 

Table 1-9. Descriptive Statistics for Emission Factor Data 

Observations 4

Minimum 555

Maximum 20,351

Mean 8,900

Variance 6.95+07

Standard Error 4168.5

Gas STAR Data 

A key assumption for employing Bayesian analysis in this situation is that the data used to 

calculate the emission factor should have a similar distribution to the Gas STAR data. If this 

assumption appears to be reasonable then the Gas STAR data can be used to create a prior 

distribution for the emission factor. In order to provide justification for this assumption the 

means, variances and ranges of the Gas STAR data are compared to the emission factor data. 

The Gas STAR data set reviewed contained 55 data entries with information on completion type. 

The Williams observation, which was included in both the emission factor and in the Gas STAR 

data set, was removed from the Gas STAR data for purposes of calculating theses statistics 

which are shown in Table 1-10. Inclusion of this observation would imply that the statistics 

calculated using the Gas STAR data are correlated with statistics from the emission factor data. 

This type of correlation would make the analysis needlessly complicated. 

Table 1-10. Descriptive Statistics for all Gas STAR Data 

Observations 55

Minimum 76

Maximum 65,322

Mean 9,174

Variance 1.25E+08

Mean 

The mean of the Gas STAR data is 9,174 Mcf CH4 per completion, which compares favorably to 

the converted methane emission factor of 8,900. Given the amount of variability in the data, 

these values are statistically equivalent. 

Range 

The range of observations for the emission factor data are (555, 20,351) and for Gas STAR the 

range is (76, 65,322). It should be noted that the second largest value in the Gas STAR data is 
1-18 

27,305. While the range of the Gas STAR data appears to be greater than the emission factor 

data, it appears to be a function of one large observation. If that observation is removed then the 

ranges of the two datasets are nearly identical. The minimum for the emission factor data is 555. 

Of the 55 Gas STAR observations only 6 have a value less than 555. This implies that the value 

of 555 is not an expected minimum when only four observations are in the sample. 

Variance of the Mean 

Assuming that the observations in the Gas STAR dataset are independent and identically 

distributed, the variance of the mean is calculated by dividing the variance shown above by the 

sample size. Thus: 

߬̂

ଶ ൌ 124733847

55 ൌ 2,267,888

The standard error of the mean is the square root of this value which is 1,506. 

Corrected Standard Error for the Emission Factor 

The estimate of the standard error for the emission factor ߪොாி can now be determined using the 

Gas STAR information and the emission factor data. This will be done by using Bayesian 

analysis. The Gas STAR data will be used to create a normal prior distribution for the mean 

emission factor value. This prior will has a mean of 8900 and variance ߬ଶ as defined above. The 

new variance of emission factor the will be determined using the following formula: 

 

ොாிߪ

ଶ ൌ 1

ቀ 1

߬̂

ଶ ൅ 4ଶቁߪ

where ݏଶ is the variance of four emission factor observations (6.95E7). This gives: 

ොாிߪ

ଶ ൌ 2,006,067

And 

ߪොாி ൌ 1416.3

The posterior distribution for the emission factor is then N(8,900, 2,006,067). The 95% 

prediction interval is 

1416.5 כ 1.96 േ 8900

This gives bounds of (6,123, 11,676). 

Summary of Results

The 95% posterior interval for the converted methane emission factor of 8,900 Mcf methane per 

completion was determined to be (6,123, 11,676). As this is a Bayesian interval estimate the 

interpretation is there is a probability of 0.95 that the true emission factor is between 6,123 and 
1-19 

11,676 given that the posterior distribution for the emission factor is N(8,900, 2,006,067). 

The posterior interval shown above is calculated for the methane emission factor of 8,900. It is 

likely that the emission factor of 9,175 Mcf whole gas per completion, and the rounded factor of 

9,000 Mcf whole gas per completion, would have a similar interval estimate as that of the 

methane emission factor. The center of the two interval estimates would clearly be similar (8,900 

versus 9,000 or 9,175). However, it is likely that the whole gas interval would be wider as the 

variance would likely be larger. As a result, it is reasonable to assume that probability that the 

true emission factor for whole gas being contained in the interval 6,123 and 11,676 is similar to 

0.95. 
2-1 

2.0 NSPS LOW PRESSURE COMPLETION THRESHOLD 

2.1 Overview 

Many commenters stated that not all gas wells have the necessary reservoir pressure to flow at 

rates appropriate for transporting solids and liquid from a hydraulic fractured gas well 

completion into an imposed back-pressure. One commenter provided an analysis recommending 

an applicability cut-off to exclude wells that do not have sufficient reservoir pressure to flow into 

a gathering line. In light of these comments this analysis evaluates the minimum flowback 

pressure determination to provide facilities subject to the well completion NSPS rule a means to 

determine when flowback gas at a facility has sufficient pressure to flow into a flow line, and 

when a facility does not have sufficient pressure, in which case the flowback gas must be 

diverted to a combustion device. This section describes the flowback condition being 

investigated by detailing the three flow regimes encountered during the flowback event within 

the horizontal and/or vertical span of a well’s tubing: 

2.2.1 Fracture Fluid Flow 

After hydraulic fracture (frack) of a new or existing well, the well tubing is filled with frack 

fluid which consists of thousands of barrels of injected liquid, i.e. water (plus additives) and 

proppant, i.e. typically sand. This material must be evacuated to prepare the well for 

production. When the flowback is initiated, the vertical column of frack fluid in the tubing is 

being acted upon by the forces of: 

• the weight of the frack fluid column in the well tubing, 

• friction from the tubing walls opposing the flow to the surface, 

• the pressure of the gas in the formation, 

• the pressure that the formation rock exerts on the frack fluid within the fracture zone(s), 

• for energized fracks, the pressure exerted by the inert gas introduced into the reservoir 

ahead of or with the frack water 

• the pressure drop through surface equipment connected to the well which may include 

separators and temporary flow lines, and 

• the backpressure of the gas gathering destination of the flowback gas 

During the initial flowback, virtually all of the flow output from the well consists of the frack 

material itself, rather than hydrocarbons from the formation, given that the well tubing is filled 

with the frack fluid. During this initial flow of only frack fluid, the pressure opposing the 

direction of the flowback is highest given that the vertical distance of the tubing completely 

filled with frack fluid. For this analysis the density is assumed to be that of the water/sand that is 

present rather than with any vapor which has a lower density. As the frack fluid reaches the 

surface, it is typically directed to atmospheric pressure storage, typically in a tank. 

2.2.2 Slug Flow 
2-2 

As the column of frack fluid flows to the surface, it is replaced with gas (hydrocarbon from the 

formation and/or inert gas introduced during the frack) that enters the well tubing and flows 

upward towards the wellhead. The presence of the gas in the tubing, where gas has replaced 

liquids, decreases the weight of the material in the vertical column. As the slug flow reaches the 

surface, it is directed to temporary storage where the liquids portion of the slug flow is 

contained while the gas portion of the slug flow typically vents the atmosphere or a combustion 

device. Because the low density and viscosity of the flowback gas relative to the frack fluid 

(water) there is substantial bypassing of gas and liquid such that the flowing fluid is multiphase slugs of gas and liquid.

2.2.3 Steady Flow of Vapor

As the frack fluid in the tubing is pushed out and replaced with vapor and frack fluid from the 

fracture zone in the reservoir formation, the initial steady flow of liquid transitions to slug flow 

of frack fluid and vapor. Over time (on the order of hours to days), the slug flow transitions to a 

steady flow condition where the frack fluid slugs in the tubing have been largely evacuated and 

there is a reasonably steady flow of a continuous vapor phase entraining droplets of water 

and/or condensate. For energized fracks, this steady flow of vapor may, for a time, contain a 

significant percentage of the inert gas introduced into the formation during the frack, and over 

time, (on the order of hours) the steady flow of vapor transitions to primarily hydrocarbons 

from the formation. Depending upon the pressure of the gas after it flows to the wellhead and 

through any potential REC equipment, the steady flow of gas can be directed to surface 

equipment and then to a combustion device or to the flow line. 

The minimum pressure equation developed in the next section applies to the steady flow of vapor 

condition encountered during the flowback since this is the flow that may be capable of being 

routed to the flow line (although an REC may be physically capable of diverting some gas from 

the slug flow condition into sales). 

2.2 Development of the Pressure Equation 

To determine whether the flowback gas at a facility has sufficient pressure to flow into a flow 

line, a model was developed to calculate the pressure for flowback gas exiting a well in steady 

flow, given its reservoir pressure and depth. The model requires inputs for the reservoir pressure 

and for the well vertical depth, which are expected to be known before the flowback occurs. The 

model uses an established quantitative relationship for fluid flow during well cleanups to 

determine the gas velocity of a well during the steady flow condition of the flowback. The model 

then uses an energy balance to determine the pressure drop based on the calculated velocity, and 

then the model accounts for pressure losses of surface equipment. The result of the model is a 

prediction of the pressure of the flowback gas immediately before it enters the flow line. The 

result can be compared to the actual flow line pressure available to the well. For wells with 

insufficient predicted pressure to produce into the flow line, combustion can be specified as the 

control standard. For wells with sufficient pressure to produce into the flow line, gas capture in 

combination with combustion can be specified as the control standard. 

This section describes the steps taken to develop such a model in the following sections: 
2-3 

2.2.1 Pressure Drop Theory introduces the engineering principles for the model and the model’s 

structure.

2.2.2 Model Parameter Definitions and Assumptions defines all the parameters in the model and 

the associated assumptions. 

2.2.3 Final Numerical Model combines the theoretical basis and the parameter definitions to 

create the complete model. 

2.2.4 Linear Regression of Numerical Model Results develops a practical equation that can be 

used in the rule based on outputs of the pressure drop model. 

2.2.5 Incorporation of Pressure Threshold Equation into the Rule describes how the linear 

equation is used in the rule.

2.2.1 Pressure Drop Theory

The pressure of the flowback gas at the flow line during the steady flow condition is determined 

primarily by the reservoir pressure and the depth of the well. Starting at the reservoir pressure, 

the pressure of the flowback gas decreases due to energy losses as it travels through the reservoir 

and into the tubing (including any horizontal segment), up the tubing, and through the surface 

equipment. This section describes the fundamental structure of the model, which is based on the 

pressure decrease as the gas travels through the reservoir, the tubing, and the REC equipment. 

2.2.1.1 Pressure Decrease in Reservoir 

The change in pressure as the gas travels through the reservoir is difficult to determine 

analytically because it varies from reservoir to reservoir and is dependent on the porosity and 

transport efficiency within the reservoir and near the wellbore. In addition, there is little public 

data available to determine the change in pressure from the reservoir to the bottom of the well at 

a national level. This analysis accepts the assumption for the pressure change from the reservoir 

to the wellbore provided by the American Petroleum Institute (API) in its comments on the 

proposed NSPS OOOO ruling15. API stated that, “...it is not unusual for the required reservoir 

pressure to be more than twice the bottom hole pressure...” Considering the API comment, this 

analysis conservatively assumed the reservoir pressure to be twice the bottom hole pressure. 

Accordingly, Equation 2-2 determines the bottom hole pressure (pressure of the gas at the 

bottom of the tubing at the perforations) given the reservoir pressure by dividing the reservoir 

pressure by two. 

ܲ஻ு ൌ ܲோ

2

ൗ (Eq. 2-2)

2.2.1.2 Pressure Decrease along Well Tubing 

 

15 Comment submitted by Howard J. Feldman, Director, Regulatory and Scientific Affairs, American Petroleum 

Institute (API) www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0505-4266 
2-4 

As the flowback fluid travels from the bottom of the tubing, through the tubing, and to the 

wellhead, the gas experiences further pressure losses. This pressure decrease can be modeled 

using an energy balance. Since energy must be conserved along the tubing (i.e. the energy into 

the system is equal to the energy out of the system), an energy balance can be constructed to 

characterize the energy acting on the fluid and the energy leaving the fluid moving within the 

tubing. This fundamental energy balance is shown in Equation 2-3. The integration sign in 

Equation 2 indicates that the kinetic energy, potential energy, work, and friction losses are 

analyzed as they change from point 1, the bottom of the tubing, to point 2, the surface. The 

kinetic energy, potential energy, work, and friction losses are then determined for each segment 

and summed over the entire tubing length. Figure 2-1, shows a visual depiction of the energy 

balance in Equation 2. 

( ) 0

2

1

+ + + = ∫ KE PE W F dz (Eq. 2-3)

where, 

KE = specific kinetic energy of the fluid, ft/s2

PE = specific potential energy of the fluid, ft/s2

F = energy lost from the fluid due to friction, ft/s2

W = specific work performed by the fluid, ft/s2

dz = height of an infinitesimal section of the tubing, ft 

The kinetic energy (KE) of the fluid is defined as ݑ

ௗ௨

ௗ௭, where u is the velocity of the fluid, in feet 

per second (ft/s), and du is the change in velocity of the fluid, in ft/s. The specific potential 

energy (PE) of the fluid is defined as – g cos ߠ, where θ is the angle of the tubing with respect to 

the vertical (for a vertical tubing as assumed here θ = 0), in radians and g is gravitational 

acceleration, in ft/s2

. Specific work (W) is defined as െ ଵ

ఘ

ௗ௉

ௗ௭

 where dP is the change is pressure, 

in absolute pounds per square inch (psia), and ρ is the density of the fluid, in cubic feet per pound 

mass (ft3

/lbm). Specific friction loss (F) is defined as ି௙௨మ

ଶ஽

 where f is the Moody friction factor, u

is the velocity of the fluid, in ft/s, and D is the diameter of the tubing, in feet. Plugging these 

definitions for KE, PE, W, and F into Equation 2 yields Equation 2-4. 

0

2

cos

2

1

2

= ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ − + − − ∫ dz

D

fu gdP udu θ

ρ

(Eq. 2-4) 

Since this analysis is determining the pressure of the gas at the flow line, the dP term is of most 

interest. Also, du is assumed to be negligible since the tubing has a constant cross sectional area 

Figure 2-1. Visual Representation of an Energy Balance 

Across a Vertical Tubing 

1

2

 KE

 F 

 dz

W PE 
2-5 

and since dz is taken to be a small interval. This assumption is corroborated by the Natural Gas 

Engineering Handbook16and Perry’s Chemical Engineering Handbook17. Finally, the tubing is 

assumed to completely vertical, which means θ is equal to zero. Therefore, Equation 3 is solved 

for dP with ݑ݀ݑ and θ set equal to zero, yielding Equation 2-5. Equation 2-5 is the basis for the 

calculation to determine the change in pressure from bottom-hole to the wellhead. Equation 4 

can be found in the Natural Gas Engineering Handbook and Perry’s Chemical Engineering 

Handbook. 

∫ ∫ ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = − +

2

1

2

1

2

2

dz

D

fu dP g ρ ρ (Eq. 2-5) 

Equation 4 is a differential equation governing the pressure change of a fluid over a length of 

vertical well tubing. As shown in Appendix B.1, the density of the fluid, a mixture of natural gas, 

water, and sand, is a function of the temperature and pressure of the fluid, which change as the 

fluid moves up the tubing. In addition, the velocity is a function of the density. Based on these 

factors, an analytical solution of Equation 2-5 is not possible. Instead the equation is solved 

numerically with the known values of the parameters in a preceding fluid segment used to 

calculate the values in the next segment. This numerical integration process yields the pressure 

drop across the tubing. 

Numerical integration is an approximation method which involves dividing a tubing of a given 

length into a finite number of segments, applying Equation 2-5 to each segment, and solving for 

the pressure exiting each segment in sequence beginning from the bottom. This is shown in 

Equation 2-6 and Figure 2-2. The pressure exiting a segment is assumed to be the pressure 

entering the following segment. The pressure exiting a segment is also used to determine the 

density and velocity of the natural gas in the following segment. The pressure change from the 

first segment at the bottom of the well to the last segment as the surface is equal to the pressure 

drop over the entire tubing length, as shown in Equation 2-7. Numerical integration is an 

approximation method used to solve complex integrals, which approaches the true integral 

solution as the height of each segment (zi+1 – zi) or dz approaches zero. 

 

16 Guo, B. Ghalambor, A. (2005) Natural Gas Engineering Handbook. Gulf Publishing Company. pg. 52. 17 Perry, R.H. (1963). Perry's Chemical Engineers' Handbook (4th Edition). McGraw-Hill. Equation 5-58. pg. 5-23, 

Covert Fanning f to Moody f. 
2-6 

( ) i i

MPi i

i i MPi z z

D

fu P P g − ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

+ = − + +1

2

1 2

ρ ρ (Eq. 2-6) 

∑ ( ) =

+ − ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = − +

n

i

i i

MPi i

WH BH MPi z z

D

fu P P g

0

1

2

2

ρ ρ

 

(Eq. 2-7)

where, 

Pi+1 = Pressure fluid exiting segment i, in psia 

Pi = Pressure of fluid entering segment i, in psia 

n = number of segments 

(zi+1 - zi) = height of segment i or length of tubing divided by n, in feet 

ρMPi = density of the multiphase fluid, in pounds per cubic feet 

PWH = pressure of fluid at the wellhead 

PR = bottom hole pressure, pressure of the fluid at the perforations 

Equation 2-6 is solved n times (i.e., for each segment) to determine the pressure drop across a 

tubing with a given length and bottom hole pressure as shown by the summation term in 

Equation 2-7. Section 2.2 defines each parameter in Equation 2-6 and Equation 2-7 in order to 

solve for Pi+1 and subsequently PWH. 

2.2.1.3 Pressure Decrease along REC Equipment 

The pressure of the flowback gas decreases further as it passes through the reduced emission 

completion recovery equipment and/or other surface equipment after exiting the wellhead but 

before entering the flow line that leads to sales and/or the gas gathering system. This decrease in 

pressure from surface equipment is small compared to the decrease occurring as the gas flows 

from the reservoir to the wellhead. This analysis assumes that the ratio of the pressure before the 

REC equipment (the wellhead pressure) and the pressure after the REC equipment (the flow line 

pressure) is constant at 1.01. Therefore, given the wellhead pressure, the pressure immediately 

before the flow line can be determined using the Equation 2-8. 

ܲ௅ ൌ ܲௐு

1.01 ൗ (Eq. 2-8)

... ... 

1

2

(zi+1 – zi) 

i = n 

i = 1 

i = 2 

i = 3 

Pi 

Pi+1

Figure 2-2. Visual Representation of the 

Numerical Integration of a Vertical Tubing 
2-7 

where, 

PL = the pressure of the fluid immediately before the flow line 

PWH = pressure of fluid at the wellhead 

2.2.2 Parameter Definitions and Assumptions

This section defines the parameters in Equations 2-6 and 2-7 to solve the pressure drop across 

each segment in the numerical integration described previously. The key parameters in Equations 

2-6 and 2-7 are the density of the moving fluid ρ, the velocity of the fluid u, the Moody friction 

factor f, and the inner tubing diameter D. The methodology to determine a value for each of these 

parameter is discussed in the sections below. The nomenclature for all the variables discussed is 

at the end of each section. 

2.2.2.1 Defining Fluid Density 

The fluid inside the well tubing during the steady flow regime is a mixture of natural gas, water, 

and sand. This analysis assumes that the multiphase fluid acts like a single phase fluid within 

each segment (zi+1 – zi) and has a density equivalent to the weighted average of the densities for 

each of the components. This assumption allows for the use of the Tuner Equation, explained in 

section 2.2.2 for determining the velocity of the fluid travel up the well bore. Equation 2-9 

shows how the density of the mixture is calculated based on the densities of the natural gas, 

water, and sand weighted by their volume percent. 

( ) ( ) MPi gi liquid water water sand sand liquid ρ = ρ 1− f + ρ f + ρ f f (Eq. 2-9) 

The density of the fracture sand, ρsand, is assumed to be that of silica (i.e. SiO2), the primary 

constituent of sand typically used to fracture gas wells. As Industrial Minerals states “Frac sand 

must be >99% quartz or silica [SiO2].”18 The fraction of sand in the water sand mixture (fsand) 

was assumed to be five percent by volume based on expert judgment. The fraction of water and 

sand in the flowback fluid (fliquid) was assumed to be 5 percent by volume. 

Equation 2-10, the derivation of which is shown in Appendix B.1, shows that the density of the 

natural gas in the gas-water-sand mixture is determined using the pressure at segment i, the 

molecular weight of natural gas (MW), the compressibility factor (Zi), the gas constant (R), and 

average fluid temperature (T). 

( )

Z RT

P MW

i

i ρgi = (Eq. 2-10) 

The molecular weight (MW) of the natural gas was assumed to be 16 pounds per pound-mole 

(lb/lb-mol) representing the molecular weight of methane, the primary constituent of natural gas. 

 

18 Zdunczyk, M. (2007) “The Facts of Frac” Industrial Minerals. Jan. 2007 

<www.indmin.com/Article/1913170/The-facts-of-frac.html> 
2-8 

The natural gas compressibility factor for a given well segment i (Zi) determined in this analysis 

using the Brill and Beggs correlation19. A second correlation, the Pitzer correlation20, was also 

performed to calculate a compressibility factor for each well segment for validation purposes, 

and the two correlations were found to agree within 10 percent for pressures 3000 psi or less. A 

more detailed investigation of alternative methods for calculating the compressibility factor can 

be found in Appendix B.4. The compressibility factor accounts for the deviation of a gas from 

the characteristics of an ideal gas. The compressibility factor is a function of the pressure of the 

gas, temperature of the gas, and the composition of the gas. In this analysis, the compressibility 

factor was determined for each segment using the pressure at each segment, the average 

temperature of the fluid, and the average CO2, H2S, and N2 composition of the gas. The CO2, 

H2S, and N2 composition in the gas was determined using a technical memo published in the 

NSPS OOOO rule making docket titled “Composition of Natural Gas for Use in the Oil and 

Natural Gas Sector Rulemaking.” 

The average temperature (T) of the fluid was assumed to be 200 °F based on expert judgment. 

This was held constant over the entire numerical integration. The gas constant (R) is universal 

and is equal to approximately 10.73 ft3 psia °R−1 lb-mol−1

. 

Table 2-1 summarizes the values selected to determine the density of the flowback fluid for each 

segment.

Table 2-1. Summary of Parameters to determine Flowback Fluid Density 

Parameter Description Method Value 

Pi pressure of gas Calculated by 

Equation 5 Varies for each segment 

MW molecular weight of the gas Assumption 16 lb/lb-mol 

T temperature of the gas Assumption 200 °F 

Zi 

compressibility factor of the 

gas at Pi and T

Brill and Beggs 

Correlation 

Varies for each segment 

with pressure (Pi) 

R universal gas constant Universal constant 10.73 ft3 psia °R−1 lb-mol−1

ρMPi

density of the flowback fluid, 

pounds per cubic feet 

Calculated by 

Equation 8 

Varies for each segment 

with pressure (Pi) 

ρsand 

density of proppant, pounds 

per cubic feet 

Assumed to be 

same as pure silica 

(SO2) 

165 lbm/ft3

ρwater

density of water, pounds per 

cubic feet 

Standard density 

of H2O at STP 62 lbm/ft3

ρgi

density of gas at Pi and T, 

pounds per cubic feet 

Calculated by 

Equation 9 

Varies for each segment 

with pressure (Pi) 

fwater 

fraction of water, by volume, 

in water-sand mixture Assumption 95% 

 

19 Brill, J. P., and H. D. Beggs. "Two-Phase Flow in Pipes." INTERCOMP Course, The Hague, 

1974. 

20 J.M. Smith, H.C. Van Ness, M.M. Abbott. (2005). Introduction to Chemical Engineering Thermodynamics. 

McGraw-Hill. 
2-9 

fsand

fraction of sand, by volume, 

in water-sand mixture Assumption 5% 

fliquid 

fraction of water-sand 

mixture in fluid, by volume, 

in flowback fluid 

Assumption 5% 

2.2.2.2 Defining Fluid Velocity 

The velocity of the fluid in each segment of the tubing is determined assuming the operator 

needs to maintain sufficient flow to clean up the well of the water and proppant mixture. This is 

determined using the entrained drop model developed by R.G. Turner21 specifically with well 

cleanup in mind. This model, henceforth referred to as the Turner velocity model, determines 

the minimum gas velocity needed to lift fluid of a known density from inside a well bore. The 

Turner velocity model was adapted in this analysis to determine the minimum velocity needed to 

lift flowback material out of the well, where all of that flowback material was conservatively 

assumed to have the density of the most dense component, which in this case is the sand. This 

adapted Turner velocity model is shown in Equation 2-11. 

( )

2

1 4

1

4

1 4

1

1.3

d gi

sand gi

i

C

u

ρ

σ ρ − ρ = (Eq. 2-11) 

Equation 2-11 determines the minimum velocity to lift a droplet of the flowback material 

assuming the density of the droplet is equivalent to that of sand. The surface tension coefficient 

(σ) and drag coefficient (Cd) in Equation 2-11 are assumed to be the same assumed by R.G. 

Turner for water since we expect flowback water to collect around the sand particles during the 

cleanup. R.G. Turner also adjusts the velocity calculated by the equation upward by 20% to 

match field data; this analysis accepts this adjustment which is already incorporated into 

Equation 2-11. 

Since the density of the gas (ρgi) changes for each tubing segment in the numerical integration, 

the minimum gas velocity also changes for each step in the numerical integration. The surface 

tension coefficient (σ) and drag coefficient (Cd) remain constant. 

Table 2-2. Summary of Parameters to determine Flowback Fluid Velocity 

Parameter Description Method Value 

ui

Turner velocity, minimum 

gas velocity needed to lift a 

droplet

Calculated by 

Equation 10 

Varies for each segment 

with density (ρgi) and 

pressure (Pi) 

σ surface tension of water, 

dynes per centimeter 

Accepted value 

from R.G. Turner 60 dynes/cm 

 

21 Turner, R. G. et. al. Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from 

Gas Wells. Journal of Petroleum Technology. Nov. 1969. Equation 4, pg. 1476 
2-10 

Cd drag coefficient of water Accepted value 

from R.G. Turner 0.44 

ρsand 

density of proppant, pounds 

per cubic feet 

Assumed to be 

same as pure silica 

(SO2) 

165 lbm/ft3

ρgi

density of gas at Pi and T, 

pounds per cubic feet 

Calculated by 

Equation 9 

Varies for each segment 

with pressure (Pi) 

2.2.2.3 Inner Tubing Diameter 

The inner diameter of the tubing was taken to be 2 and 7/8th inches which is a common value for 

gas wells. The inner tubing diameter remains constant over the entire numerical integration. 

An additional investigation was conducted to determine if the functional diameter, through 

which the completion fluid would flow, is smaller than the inner tubing diameter due to 

significant water plating on the walls of the tubing. It was determined that with a 5 percent 

fraction of liquid in the flowback fluid, the thickness of the film of water plating the inner tubing 

wall is at the most 0.035 inches (which is multiplied by two to account for both endpoints of a 

line passing through the center of the tubing cross section). Since the film of water plating the 

inner tubing wall is at the most only 2.5% of the tubing diameter it was concluded that the 

effective tubing diameter was the same as the inner diameter of the tubing. This calculation is 

shown in Appendix B.2. 

Table 2-3. Summary of Parameters to determine the Tubing Diameter 

Parameter Description Method Value 

D Inner tubing diameter, inches Assumption 2.875 inches 

2.2.2.4 Defining Friction Factor 

The Moody friction factor is a unitless constant that accounts for the friction experienced by the 

moving fluid in the tubing. The Moody friction factor was determined assuming turbulent flow, 

which is the case for gas wells, and a correlation equation in the Natural Gas Engineering 

Handbook. Appendix B.3 discusses further how the turbulent flow assumption is valid for gas 

wells. The Nikuradse22 friction factor correlation used in this analysis for turbulent flow in rough 

pipes, shown in Equation 2-12, requires the roughness factor and the tubing diameter to 

determine the Moody friction factor. This analysis assumes 0.0001 inches for the average 

roughness. The Natural Gas Engineering recommends using a value of 0.006 inches for the 

roughness of tubing pipes if no information is available23. However, since the inner tubing wall 

will likely be plated with water, the roughness experienced by the gas/water interface is much 

less than the roughness of the inner tubing wall. Since this analysis also estimates a constant 

tubing diameter, discussed further below, the friction factor remains constant over the entire 

numerical integration, the value of which is shown in Equation 2-12. 

 

22Guo, B. Ghalambor, A. (2005) Natural Gas Engineering Handbook.Gulf Publishing Company. pg. 54, Equation 

4.10. 

23 Guo, B. Ghalambor, A. (2005) Natural Gas Engineering Handbook.Gulf Publishing Company. pg. 204 
2-11 

( ) 0.00989

2.875

2 0.0001 1.74 2log

1

2 1.74 2log

1

2 2

=

⎥

⎥

⎥

⎥

⎦

⎤

⎢

⎢

⎢

⎢

⎣

⎡

⎟

⎠

⎞ ⎜

⎝

⎛ −

=

⎥

⎥

⎥

⎥

⎦

⎤

⎢

⎢

⎢

⎢

⎣

⎡

⎟

⎠

⎞ ⎜

⎝

⎛ −

=

D

f

ε

(Eq. 2-12) 

Table 2-4. Summary of Parameters to determine the Moody Friction Factor 

Parameter Description Method Value 

f

Moody friction factor, 

unitless

Calculated by 

Equation 11 0.00989 

ε

roughness of inner tubing 

wall, inches Assumption 0.0001 inches 

D

Inner tubing diameter, 

inches Assumption 2.875 inches 

2.2.3 Final Numerical Model

The complete model to determine the pressure immediately ahead of the flow line (PL) of a gas 

well during its steady flow phase of a cleanup after a hydraulic fracture, given its reservoir 

pressure (PR) and well depth (L) is depicted in the block flow diagram in Figure 2-3. First, the 

reservoir pressure and well depth are inputted. Next, the bottom-hole pressure (PBH) is 

determined from the reservoir pressure using Equation 2-7, and the well depth is divided into 

segments for the numerical integration. The number of segments (n) equals the number of steps 

taken in the numerical integration; this analysis uses n=2,000 steps. The bottom-hole pressure is 

used to determine the compressibility factor of the natural gas for the first step in the numerical 

integration (Zi). Next, the density of the natural gas (ρgi) is determined for the first step in the 

numerical integration using the bottom-hole pressure and the compressibility factor, using 

Equation 2-10. The density of the natural gas is used to determine the velocity of the gas (ui) 

using the Turner velocity model in Equation 2-11 and the density of the flow back fluid (ρMPi) 

accounting for water and sand using Equation 2-9. Finally, the velocity of the gas and density of 

the flow back fluid are used to determine the pressure of the gas exiting the first segment (Pi+1) 

using Equation 2-6. The pressure of the gas exiting the first segment is then set equal to the 

pressure of the gas entering the next segment and the process above is repeated until the sum of 

the each segment’s height is equal to the well depth. The pressure of the gas exiting the last 

segment is equal to the wellhead pressure (PWH). Finally, the wellhead pressure is used to 

determine the pressure immediately before the flow line using Equation 2-8. 
2-12 

Input Reservoir Pressure (PR) and 

Well Depth (L)

Calculate the Compressibility 

Factor Zi = f(Pi)

Calculate the Natural Gas Density (ρgi = 

f(Pi, Zi)) 

(E i 9)

Calculate the Multiphase Density (ρMPi =

f(ρgi))

Calculate the Turner Velocity (ui = 

f(ρgi))

Calculate new Pressure (Pi+1) 

from zi to zi+1 and set as Pi 

 (Equation 5) 

Set initial pressure 

ܲ஻ு ൌ ܲோ

2

ൗ ൌ ܲ௜

Does ݅ ൌ 2000? No 

i = i Yes 

Output Wellhead 

Pressure (Pi = PWH)

Calculate the pressure 

immediately before flow 

line (PL) (Equation 7) 

Declare well tubing segments (n) of 

equal length and begin at the 

bottom-most segment 

Figure 2-3. Block Flow Diagram of the Model used to Determine the Pressure Immediately

Ahead of the Flow Line, for a Hydraulically Fractured Gas Well Completion Flowback in 

the Steady Flow Condition 
2-13 

2.2.4 Linear Regression of Numerical Model Results

A linear regression was used to develop a simplified linear equation that yields similar line 

pressures outputs as the model described above for a given well depth and reservoir pressure. 

Two steps were taken to arrive at the linear pressure threshold equation in the NSPS OOOO 

ruling using the results of the numerical model described above. 

2.2.4.1 Generate Line Pressures using Numerical Model 

First, the numerical model was run for various plausible combinations of well depths and 

reservoir pressures. Well depths ranging from 500 feet to 20,100 feet in increments of 400 feet 

and reservoir pressures ranging from 100 pounds per square inch absolute (psia) to 9,850 psia in 

increments of 250 psia were inputted into the numerical model to determine a line pressure for 

each combination of well depth and reservoir pressure. The depth and pressure increments used 

to generate the matrix of test cases are different than the numerical integration increments 

discussed in section 2.3.3. The matrix of test cases yielded about 2,000 numerical model runs 

with calculated flowback gas pressures after exiting surface equipment varying from 3 psia to 

4,827 psia. 

2.2.4.2 Regress the Line Pressure Outputs from the Numerical Model 

Second, a regression was developed based on these 2,000 numerical model runs. Some model 

run flowback gas pressure outputs were low, and some were high, as described in the previous 

section. Two options were evaluated on how to conduct the regression. One option was to 

develop a regression over the entire range of model runs so that the standard error would be 

minimized equally across the range. The second option was to select a subset of the range in 

which to regress, so that the standard error is minimized in that region of interest. The region of 

interest in this analysis was the line pressures outputted by the numerical model less than 1,000 

psia. The regression was performed on line pressures less than 1,000 psia because most flow 

lines that will receive flowback back are at less than 1,000 psia. Subsequently, the standard error 

of the correlation was minimized for line pressures less than 1000 pisa. There were 418 model 

runs with line pressures less than 1,000 psia. These model runs were regressed against the 

reservoir pressure and well depth to generate a simple linear equation that estimates the line 

pressure of a well given its reservoir pressure and well depth. The resulting regression equation 

is shown in Equation 12. 

ܲ௅ ൌ 0.445 ൈ ܲோ െ 0.038 ൈ ܮ ൅ 67.578) Eq. 2-13) 

This regression is an approximation of the numerical model results for line pressures less than 

1,000 psia and therefore has an associated error when estimating line pressures. The regression 

analysis yielded a standard error of 24.3 psia for line pressures less than 1,000 psia, which 

means the average deviation between the line pressure determined by Equation 12 and the line 

pressure determined by the numerical model is 24.3 psia for line pressures less than 1,000 psia. 

Since the regression was performed for line pressures less than 1,000 psia, the standard error 

increases as the resulting line pressures increase above 1,000 psia. 
2-14 

The coefficient of determination (R2

) is a parameter that quantifies the fit of the regression. The 

coefficient of determination indicates how well the linear regression equation approximates the 

model runs regressed. A coefficient of determination equal to one indicates that the line perfectly 

fits the regressed data, whereas coefficient of determination values less than one indicate a less 

than perfect fit. The regression performed in this analysis has an R2

 value of 0.992 for flow line 

pressures less than 1000 psia. 

Figure 2-4 compares the line pressures as determined by the numerical model and the linear 

regression equation. On the x-axis of 

Figure 2-4 is a selection of the 2,000 model runs in the region of interest, each assigned a 

number, representing a combination reservoir pressure and well depth that was inputted into the 

numerical model and the linear regression equation. For each combination of reservoir pressure 

and well depth, the numerical model and linear regression equation outputted a flow line 

pressure, which is plotted on the y-axis in 

Figure 2-4. The blue diamonds represent the numerical model line pressures and the red squares 

represent the linear regression line pressures. Where the red squares and blue dots seem to 

overlap indicates the numerical model and the linear regression equation outputted similar flow 

line pressures for the same reservoir pressure and well depth inputs. Conversely, where the red 

squares and blue dots deviate significantly indicates the numerical model and the linear 

regression equation outputted different flow line pressures for the same reservoir pressure and 

well depth inputs. 
2-15 

Figure 2-4. Comparison between Line Pressures from the Linear Regression and Numerical Model

Figure 2-4 shows how for the same reservoir pressure and well depth, Equation 2-8 correlates 

well with the numerical model for line pressures less than 1,000 psia but has some deviation 

from the numerical model at line pressures greater than 1,000 psia. This analysis accepts the 

decrease in accuracy for line pressures above 1,000 psia because actual flow line pressures above 

1,000 psia are uncommon, so that at pressures of this magnitude it is expected that flowback gas 

can enter most flow line systems. 

Equation 2-13 indicates that when the reservoir pressure is zero and the well depth is zero the 

line pressure is 67.5784, which is not intended to have a physical meaning given this is a 

correlation rather than the model itself. A linear regression is an approximation that has inherent 

uncertainty in modeling the line pressure at a given depth and reservoir pressure. Therefore, 

since the regression is already an approximation, this analysis does not use a zero-intercept at the 

cost of not fitting the numerical model results the best. 

2.2.5 Incorporation of Pressure Threshold Equation into the Rule

‐

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1 101 201 301 401 501 601 701 801

Line Pressure (pisa)

Model Run f (Reservoir Pressure, Well Depth)

Numerical Model Linear Regression
2-16 

The Final NSPS OOOO Rule includes Equation 2-13 for operators to determine if they are 

required to combust flowback gas or perform gas capture plus combustion. Operators will input 

the reservoir pressure and vertical well depth for their new source gas well with hydraulic 

fracturing into Equation 2-13 and determine a calculated pressure of the gas immediately before 

it would be routed to the flow line. If the calculated line pressure is greater than the actual line 

pressure to be used by the operator, then the rule requires natural gas from the completion 

flowback to be captured in combination with combustion. If the calculated line pressure is less 

than or equal to the actual line pressure to be used by the operator, then the rule requires the 

natural gas from the completion flowback to be sent to a combustion device. The rule instructs 

operators to round the result of the linear equation to the nearest 10 psi to reflect the appropriate 

precision of the equation given how pressure settings vary within a gathering line. Rounding to 

the nearest 100 psia would be too coarse since gathering line pressures are typically on the order 

of hundreds of psia, and rounding to the nearest one psia is too precise given the sensitivity of 

the model. 

2.3 Estimated National Impacts of Implementing the Pressure Equation 

As part of the NSPS proposal rulemaking process, the EPA assessed the regulatory impacts of 

the proposed NSPS OOOO. This section describes the potential effect of implementing the 

pressure determination equation shown in Equation 2-13 to the national impacts. 

To determine the impacts of implementing a pressure equation, three different investigations 

were carried out. The investigations differed in the methodology and data used. All 

investigations employed Equation 2-13 to calculate the pressure of the flowback gas as it exits 

the well. 

 

For these analyses, a line pressure of 500 psia was assumed. If the calculated pressure of the well 

exceeded 500 psi, then the well was considered to be captured by the regulation. This assumption 

was used due to the lack of available gathering line pressures by producing areas in the U.S. and 

the understanding that such pressures typically range from 80 to 500 psia based on expert 

judgment. Depending on the producing area gathering line pressures will differ. The line 

pressure of 500 psia is therefore a conservatively high value of pressure in any field. 

The three different investigations and the final conclusions drawn from the impacts estimates are 

listed below and discussed in the rest of this section: 

2.3.1 Impacts Based on 2008 Well Completions uses characteristics of well completions from 

2008 in all formations.

2.3.2 Impacts Based on All Completions from 2000 – 2010 uses characteristics of well 

completions from 2000 to 2010 in all formations.

2.3.3 Impacts Based on Individual Basins or Formations uses characteristics of well completions 

carried out in specific basins or formations.

2.3.1 Impacts Based on 2008 Well Completions

The data used for this first investigation is an output from an HPDI database query (HPDI is a 

data service company supplying products that aggregate U.S. production data). The query 
2-17 

provided the total depth and the formation type (tight gas, shale, and coal bed methane) of all 

new gas wells in 2008 (where formation type was determined based on an assessment of each 

well’s location and other characteristics). Using the total depth and an expert assumption of the 

pressure gradient per unit of distance for each formation type, the bottom-hole pressure could be 

estimated. Table 2-5 summarizes the pressure gradients used. 

Table 2-5. Pressure Gradients for each Formation Type

Formation Type 

Pressure Gradient 

(psi per vertical foot) 

Gas Shale 0.7 

Tight Gas 0.7 

CBM 0.465 

The bottom-hole pressure—calculated using the pressure gradients listed above—and the total 

depth for each new gas well in 2008 was entered into Equation 12. The resulting pressure was 

compared to an assumed flow line pressure of 500 psia. If the calculated pressure was greater 

than 500 psia, the well was considered to be capable of complying with the REC requirements of 

the rule. 

This investigation led to the conclusion that approximately 90% of well completions would be 

able to overcome a flow line pressure of 500 psia. The remaining 10% had an estimated pressure 

below 500 psia, according to the equation and parameters used. Figure 2-5 illustrates this 

distribution. 

Figure 2-5. Distribution of 2008 Gas Wells Above and 

Below the 500 psi Flow Line Pressure 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Number of Gas Wells in 2008

Above Pressure of 500 psi

Below Pressure of 500 psi
2-18 

This investigation did not make any distinctions for exploratory and delineation wells. It includes 

all new gas wells in tight, shale, and CBM formations in 2008. 

2.3.2 Impacts Based on All Completions from 2000 – 2010

The data used for this second investigation also originated from an HPDI query. The query 

provided the total depth and the formation type (tight gas or shale) of all gas wells that began 

producing from 2000 to 2010. Using the total depth and an assumption of the pressure gradient 

per unit of distance for each formation type as shown above in Table 2-5, the bottom-hole 

pressure could be estimated. 

The bottom-hole pressure—calculated using the pressure gradients listed above—and the total 

depth for each gas well that began producing from 2000 to 2010 were entered into Equation 2-

13. The resulting pressure was compared to an assumed flow line pressure of 500 psi. If the 

calculated pressure was greater than 500 psia, the well was considered to be capable of 

complying with the REC requirements of the rule. 

This investigation led to the conclusion that approximately 98% of well completions would be 

able to overcome a flow line pressure of 500 psi. The remaining 2% had an estimated pressure 

below 500 psi, according to the equation and parameters used. Figure 2-6 illustrates this 

distribution. 

Figure 2-6. Distribution of 2000 to 2010 Gas Wells Above and Below the 500 psi Flow Line Pressure 

This investigation did not make any distinctions for exploratory and delineation wells. It includes 

all gas wells in tight and shale formations that began producing sometime between 2000 and 

2010. 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

Number of Gas Wells from 2000 to 2010

Above Pressure of 500 psi

Below Pressure of 500 psi
2-19 

2.3.3 Impacts Based on Individual Basins or Formations

The data used for the third investigation originated from a variety of references including the 

Pennsylvania Department of Environmental Quality, the Wyoming Department of 

Environmental Quality, oil and gas service providers, and the Department of Energy24. The data 

collected from these references were reservoir pressures and well depths that were then inputted 

directly into Equation 2-13. 

 

Several references provided a multitude of values for reservoir pressure and/or well depth. 

Therefore, within a given formation, this investigation paired the lower reservoir pressures with 

the lower depths, the average reservoir pressures with the average depths, and the higher 

reservoir pressures with the deeper depths to assess the impacts. 

For this investigation, the selection of production areas represented by the researched data 

included: 

• Marcellus shale 

• Barnett shale 

• Eagle Ford shale 

• Haynesville shale 

• Powder River Basin 

The summary of the findings from this investigation are summarized in Table 2-6. N/A indicates 

that the researched data did not provide multiple values for reservoir pressure and depth. 

Table 2-6. Summary of Calculated Flow Line Pressures from Individual Basins

Region 

Formation 

Type 

Bottom-Hole 

Pressure (psia) 

Total Depth 

(ft) 

Eq. 12 Calculated Flow 

Line Pressure (psia) 

Marcellus 

(Lower Bound) 

Gas Shale 1,700 3,000 710 

Marcellus 

(Average) 

Gas Shale 4,000 7,000 1,582 

Marcellus 

(Upper Bound) 

Gas Shale 5,760 12,000 2,175 

Barnett 

(Lower Bound) 

Gas Shale 2,750 5,000 1,101 

 

24 Table 3.4 of http://treichlerlawoffice.com/radiation/HillNY.pdf, Table 2 of 

http://www.sooga.org/studies/Marcellus%20Shale%20Decline%20Analysis%20-%202010%20-

%20Brandon%20Baylor.pdf, http://www.transformsw.com/papers-and-presentations/studies.html#Barnett, Table A6 (pg 212) Reservoir Pressure Profile on pg 50 (Fig 2-12) of 

http://www.fe.doe.gov/programs/oilgas/publications/coalbed_methane/PowderRiverBasin2.pdf, Tables 2-4 and 3-13 

(Additional depths in Tables 3-3 to 3-11) of 

http://www.fe.doe.gov/programs/oilgas/publications/coalbed_methane/PowderRiverBasin2.pdf, page 6 of 

http://www.halliburton.com/public/solutions/contents/Shale/related_docs/H063771.pdf, 

http://www.transformsw.com/papers-and-presentations/studies.html#Eagle Ford 
2-20 

Barnett 

(Average) 

Gas Shale 4,000 7,500 1,563 

Barnett 

(Upper Bound) 

Gas Shale N/A N/A N/A 

Eagle Ford 

(Lower Bound) 

Gas Shale N/A N/A N/A 

Eagle Ford 

(Average) 

Gas Shale 5,200 11,500 1,945 

Eagle Ford 

(Upper Bound) 

Gas Shale N/A N/A N/A 

Haynesville 

(Lower Bound) 

Gas Shale 5,690 16,600 1,969 

Haynesville 

(Average) 

Gas Shale 8,500 12,000 3,394 

Haynesville 

(Upper Bound) 

Gas Shale N/A N/A N/A 

Powder River 

Basin 

(Lower Bound) 

CBM 165 500 122 

Powder River 

Basin 

(Average) 

CBM 490 1,250 238 

Powder River 

Basin 

(Upper Bound) 

CBM 2,161 5,270 829 

Based on the results summarized above, it is possible to draw the following conclusions: 

• Most of the wells in Marcellus, Barnett, and Haynesville would be capable of 

overcoming a flow line pressure of 500 psia based on the pressure model developed in 

this section. 

• The average gas wells in Eagle Ford would be capable of overcoming a flow line 

pressure of 500 psia based on the pressure model developed in this section. 

• The average gas wells in the Powder River Basin would not be able to overcome a 

flow line pressure of 500 psia based on the pressure model developed in this section. 

Some wells in these basins would be capable of overcoming such a pressure as 

evidenced by the upper bound for the Powder River Basin. 
2-21 

2.4 Conclusions 

This analysis examined the pressure drop situation for the steady flow condition of a flowback 

after a hydraulic fracture, for a variety of well reservoir pressures and depths. A mathematical 

model describing well cleanup is appropriate to describe the diversity of conditions in 

hydraulically fractured gas wells. This model approach accounts for the range of conditions 

including well depth and reservoir pressure to more accurately depict the flowback pressure 

immediately before the flow line. The model acknowledges that a number of factors influence 

the pressure of the flowback gas and represents the effects of those factors using fluid flow 

equations paired with the best available parameters or assumptions based on expert judgment. 

Other factors that may determine when to vent, combust, and/or capture are 

gas combustibility, fire hazards, and other field parameters, however, these were not 

incorporated into this model. 

 

Given the very limited data on actual flow line pressures, the national impacts were determined 

based on a characteristic 500 psia flow line pressure which is expected to be a maximum value 

for most situations. When using available actual field data with Equation 2-13, the result was 

determined to be reasonable. Based on the limited research into flow line pressures, this analysis 

expects from a national impacts perspective that about 90 percent of annual affected facilities 

will be required to do gas capture in combination with combustion with provisions for venting. 
3-1 

3.0 GAS WELL RE-FRACTURE FREQUENCY 

This section summarizes changes to the gas well refracture frequency estimates from the 

proposed NSPS rule to the final rule. The NSPS proposed rule estimated the number of existing 

natural gas wells that are fractured each year (i.e., refractured or recompleted) using an 

assumption from a publically available study25 that estimated wells were refractured on average 

every 10 years (i.e., 10% of the total fractured gas well count is the number of gas well 

recompletions with hydraulic fracture in a given year). In response to comments, the EPA has 

reevaluated this assumption. This review included an evaluation of all comments received and 

other information available to EPA through the development process for the annual estimates in 

the Inventory of U.S. Greenhouse Emissions and Sinks. 

3.1 Revised Gas Well Re-Fracture Frequency Methodology 

Comments received on the proposed rule suggested that the number of wells refractured each 

year is less than EPA’s estimates. Comments stated that the number of hydraulically fractured 

gas wells recompleted per year is less than EPA’s estimate, ranging from 1 percent to 5 percent. 

No new data was provided specific to hydraulically fractured wells. One commenter cited a 1996 

Gas Research Institute study26, which the commenter stated shows a refracture rate of 2 to 3 

percent. Another commenter provided records for 2008, 2009, and 2010 showing the number of 

producing gas wells, the number of gas well completions, and the number of gas well 

recompletions. In both of these cases, the data set includes both wells that were and were not 

hydraulically fractured, and did not distinguish between the two; therefore, it is not possible to 

break out the specific number of wells that were refractured. 

In the evaluation of comments received, EPA consulted other data available to the Agency. This 

data included two sets of data provided by two separate industry representatives through the 

development process for annual estimates in the Inventory of U.S. Greenhouse Emissions and 

Sinks, and are shown below. A petroleum and natural gas industry entity (Entity X) provided the 

data shown in Table 3-1. Entity X provided the number of operating gas wells in all states 

associated with this entity except those in Alaska and Hawaii, the total number of fractured 

stimulation jobs per year, the number of initial stimulations completed per year, and the number 

of fractured stimulation jobs conducted each year on previously fractured stimulated wells 

(referred to in Table 3-1 as the number of workovers per year). The term fractured stimulated 

workovers was defined by Entity X as existing fractured gas wells re-stimulated with fracturing 

after 30 or more days of the initial fracture stimulation. Entity X averaged the number of 

operating gas wells and number of workovers per years from 2004 to 2010 then divided the 

averages to yield the re-fractured frequency per year as a percentage of the number of operating 

gas wells, which was 0.27%. Therefore, the average re-fracture frequency for Entity X is 0.27% 

ranging from 0.50% in 2006 to 0.11% in 2010. 

 

25 ARI/ICF (2008) Greenhouse Gas Life-Cycle Emissions Study: Fuel Life-Cycle of U.S. Natural Gas Supplies and International 

LNG. Prepared for Sempra LNG. <http://www.adv-res.com/pdf/ARI_LCA_NOV_10_08.pdf> 26Assessment of Technology Barriers and Potential Benefits of Restimulation R&D for Natural 

Gas Wells”, Final Report, GRI- 96/0267, July, 1996. 
3-2 

Another petroleum and natural gas entity (Entity Y) submitted the data shown in Table 3-2. 

Entity Y provided its number of produced gas wells that have been completed with hydraulic 

fracturing, the number of gas wells that were re-completed using hydraulic fracturing, and the 

percent of unconventional gas wells recompleted with hydraulic fracturing for 2008, 2009, and 

2010. The percent of unconventional gas well recompleted with hydraulic fracturing is 

equivalent to the percentage of gas wells that are re-fractured annually. The average re-fracture 

frequency for Entity Y from 2008 to 2010 is 0.61% and ranges from 0.8% in 2008 to 0.4% in 

2010. 

These two new data sources (submitted by Entity X and Y) and comments received on the 

proposed rule show a refracture frequency rate well below the 10% rate EPA used in the 

proposal. Based on analysis of this data and comments received, the estimate used in the final 

rule impacts analysis is 1%. 
3-3 

Table 3-1. Workover Frequency for Each Year from 2004 to 2010 from Entity X 
3-4 

Table 3-2. Workover frequency for each year from 2008 to 2010 from Entity Y 
4-1 

4.0 NATIONAL IMPACT OF NSPS OOOO REQUIREMENTS ON GAS WELL 

COMPLETIONS 

4.1 Summary of National Impacts Methodology 

This section summarizes the approach for estimating the impacts of regulating volatile organic 

compound (VOC) emissions from new gas well completions following hydraulic fracturing 

where reduced emissions completions (REC) are required. A description of the data and how it 

was used is provided. A similar procedure as the one shown here was used to estimate the 

impacts from recompletions following hydraulic fracturing and for the portion of affected 

facilities where combustion is used for VOC control instead of the combination of combustion 

and gas capture. Below is the list of steps taken to estimate each aspect of the impacts. 

Estimate Emissions from Representative Individual Source 

1. Develop a methane emission factor for hydraulically fractured well completions (see 

section 1.0 of this TSD) 

2. Develop a conversion of mass of methane to mass of VOC (see separate docket memo: 

Composition of Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking) 

Estimate Reductions from Representative Individual Source 

1. Determine the control efficiency of implementing a REC (see separate docket memo: 

Percent of Emissions Recovered by Reduced Emission Completions, May 19, 2011) 

2. Multiply the control efficiency by the VOC emissions from a representative source 

Estimate the Cost of Compliance for Representative Individual Source 

1. Determine average cost per day of a REC (see Section 4.4.2.3 of Proposal Technical 

Support Document) 

2. Determine average duration of REC in days (see Section 4.4.2.3 of Proposal Technical 

Support Document) 

Estimate the Cost-Effectiveness of VOC Control 

1. Divide the reductions from a representative source by the cost for a representative source 

Estimate Total Emissions from All Hydraulically Fractured Gas Well Completions 

1. Estimate the number of gas well completions in a representative year 

2. Multiply the number of gas well completions by the representative emissions from an 

individual source 

Estimate Total Reductions from All Hydraulically Fractured Gas Well Completions 

1. Estimate the number of gas well completions in a representative year 

2. Multiply the number of gas well completions by the representative emissions reductions 

from an individual source 
4-2 

Estimate Total Cost of Compliance for All Hydraulically Fractured Gas Well Completions 

1. Estimate the number of gas well completions in a representative year 

2. Multiply the number of gas well completions by the cost of compliance for a 

representative individual source 

Figure 4-1 illustrates the general process by which each aspect of the impacts was determined. 

Methane Emission 

Factor

Conversion of 

Methane to VOC

VOC Emissions per 

Gas Well Completion 

REC Control 

Efficiency 

VOC Reductions per 

Gas Well Completion 

Average Cost of 

REC per Day 

Average Duration 

of RECs 

Cost of REC per 

Well Completion 

Cost-Effectiveness of 

VOC Control 

Total VOC 

Reductions 

Total Cost of 

Compliance 

Total VOC 

Emissions 

Number of Hydraulically 

Fractured Gas Well 

Completions per year 

Figure 4-1: Flow Diagram of Impacts Estimations 
4-3 

4.2 Descriptions of Data Used in the Impacts Analysis 

This section describes the data used for the impacts calculations. The data is also discussed in 

related docket memos and in the proposed TSD. The list of the data is: 

• Methane emission factor for hydraulically fractured gas well completions 

• Conversion of mass of methane to mass of VOC 

• REC control efficiency 

• Average cost of REC per day 

• Revenues from natural gas product recovery 

• Average duration of RECs 

• Number of hydraulically fractured gas well completions per year 

4.2.1 Methane Emission Factor

The emission factor for gas well completions with hydraulic fracturing was developed using four 

data sources, together representing data from over 1,000 well completions with hydraulic 

fracturing. The data included tight sands formations, shale formations, and coal bed methane 

(CBM) formations. 

EPA evaluated both data used to develop the original factor and data received through comments 

in several ways to determine whether an improved emission factor could be developed. As a 

result of this assessment, the EPA concludes that, although it does have uncertainty, the original 

EPA emission factor provides a valid central estimate of emissions from this source in the U.S. 

Therefore, the EPA has decided to retain the data set and the methodology used to develop the 

original emission factor for well completions 

For more information on the development of the original emission factor and the evaluation of 

data submitted through NSPS comments, please see the section 1 of this Background 

Supplemental Technical Support Document titled “Evaluation of the Emission Factor for 

Hydraulically Fractured Gas Well Completions and Recompletions.” 

4.2.2 Conversion of Mass of Methane to Mass of VOC

A conversion of mass of methane to mass of VOC was determined using composition data from 

9 different references. Based on this data, it was possible to generate an average composition 

profile for produced gas, and subsequently, a ratio of mass of methane to mass of VOC. 

For more information regarding the development of this ratio as well as the raw data on which it 

is based, please see the memo from EC/R to Bruce Moore titled “Composition of Natural Gas for 

use in the Oil and Natural Gas Sector Rulemaking”. 

4.2.3 REC Control Efficiency
4-4 

Based on the results reported by 4 different Natural Gas STAR Partners who performed RECs, it 

was possible to estimate a representative control efficiency of using RECs. The companies 

provided both recovered and total produced gas, allowing for the calculation of the percentage of 

the total gas which was recovered. This estimate was based on data for more than 12,000 well 

completions. 

4.2.4 Average Cost and Duration of RECs

The average cost and duration of RECs was obtained from data also shown in the Natural Gas 

STAR Lessons Learned document titled “Reduced Emissions Completions for Hydraulically 

Fractured Natural Gas Wells” and is available at: 

http://epa.gov/gasstar/documents/reduced_emissions_completions.pdf. The impacts calculations 

use the cost per day for gas capture and the duration of gas capture along with a 

setup/takedown/transport cost and a flare cost to represent the total cost. The cost is then 

annualized across the time horizon under study. The average cost and duration information is 

also covered in the TSD. 

4.2.5 Revenue from Recovered Products

The costs were depicted in two different ways: without accounting for the value of the product 

recovered as a result of controlling VOC, and with the revenue from recovered products. To 

estimate the revenue from recovered products, the estimated value of the recovered gas was 

added to the estimated value of the recovered condensate. 90% of the gas emitted (ie 90% of the 

emission factor per completion event) was depicted as being captured and sold (see separate 

docket memo: Percent of Emissions Recovered by Reduced Emission Completions, May 19, 

2011). This saved gas was multiplied by a characteristic gas price of $4 per Mcf gas. A 

characteristic amount of gas condensate was determined to be 34 barrels per completion, and this 

number of barrels was multiplied by its characteristic market value of $70 per barrel. 

4.2.6 Number of Hydraulically Fractured Gas Well Completions per Year

The number of hydraulically fractured gas well completions was estimated using the National 

Energy Modeling System analysis consistent with the Annual Energy Outlook 2011 Reference 

Case. It is estimated that there would be 11,403 gas well completions in tight, shale, and CBM 

formations. From this total, three deductions were made: 

1. The first deduction was for wildcat and delineation wells 

a. 446 well completions 

b. According to Annual Energy Outlook 2011 Reference Case 

2. The second deduction was for RECs already required by state regulations 

a. 1,644 well completions 

b. 15 percent of gas well completions (after subtracting wildcat and delineation 

wells) 

c. Explained in Section 4.3.3 of Proposal Technical Support Document 

3. The third deduction was for low pressure wells 
4-5 

a. 931 well completions 

b. 10 percent of gas well completions (after subtracting wildcat and delineation gas 

wells and the gas well completions already controlled by state regulations) 

c. Based on the analysis conducted in Section 2.0 of this TSD 

4. The fourth deduction was for completions performed with voluntary RECs 

a. 4,275 well completions 

b. 51 percent of gas well completions (after subtracting wildcat and delineation gas 

wells, the gas well completions already controlled by state regulations, and low 

pressure completions) 

c. Based on the analysis conducted in Section 5.0 of this TSD 

Table 4-1 summarizes the breakdown of the estimated number of gas well completions. 

Table 4-1: Number of Hydraulically Fractured Gas Well Completions 

Source 

Required to 

perform RECs 

not already 

performed 

voluntarily 

Estimated to be 

performed with 

voluntary 

RECs 

Required to 

Combust 

Completion 

Emissions*

Completions 

Already 

Regulated 

by States 

Total 

Hydraulically 

Fractured 

Gas Well 

Completions 

Hydraulical

ly Fractured 

Gas Well 

Completion 

4,107 4,275 1,377 1,644 11,403 

* Note that the gas well completions required to combust the completion emissions are not prohibited from performing RECs. 

However, for the impacts assessment, these well completions are assumed to control emissions through a combustion device 

only. 

4.3 Final Impacts Results 

The Tables 4-2 through 4-4 provide the final rule impacts for well completions when REC are 

performed estimated using the methodologies, data, and parameters described in this section, in 

the docket memos, and in the TSD. 

Table 4-2: Estimated Impacts per Individual Hydraulically Fractured Gas Well 

Completion When REC is Performed 

Source 

Uncontrolled 

VOC 

Emissions 

(tons) 

VOC 

Emissions 

Reductions 

(tons) 

Cost of 

Compliance 

(without 

savings) 

Cost of 

Compliance 

(with 

savings) 

Individual 

Hydraulically 

Fractured Gas 

Well Completion 

22.691 21.500 $33,237 -$1,543 

 
4-6 

Table 4-3: Estimated Impacts for All Hydraulically Fractured Gas Well Completion 

When REC is Required 

Source 

Uncontrolled 

VOC 

Emissions 

(tons) 

VOC 

Emissions 

Reductions 

(tons) 

Cost of 

Compliance 

(without 

savings) 

Cost of 

Compliance 

(with 

savings) 

All Hydraulically 

Fractured Gas 

Well Completions 

93,198 88,305 $136,511,391 -$6,336,330 

Note: An additional 29,608 tons of 31,246 tons of VOC emissions are estimated to be reduced via completion combustion for 

hydraulically fractured gas well completions that are not required to implement a REC but are required to combust emissions. 

Table 4-4: VOC Control Cost Effectiveness when a REC is Performed 

Source 

VOC Control Cost 

Effectiveness ($/ton)—

without savings 

VOC Control Cost 

Effectiveness ($/ton)—

with savings 

All Hydraulically Fractured Gas 

Well Completion $1,546 per ton VOC -$72 per ton VOC 
5-1 

5.0 VOLUNTARY REDUCTIONS FROM GAS WELL COMPLETIONS WITH 

HYDRAULIC FRACTURING 

This section discusses an analysis which estimates the number of hydraulically fractured gas well 

completions performed with voluntary use of capture and combustion equipment. The analysis 

uses data from 2008 through 2010 and then projects that data to a 2015 basis to be consistent 

with the Regulatory Impacts Analysis. The analysis concludes that 51% of hydraulically 

fractured gas well completions and recompletions not already under state regulation and with 

sufficient pressure to perform a REC will implement RECs voluntarily in 2015. 

The baseline emissions estimates in the proposed Regulatory Impacts Analysis for natural gas 

well completions and other emissions sources take into account emissions reductions conducted 

pursuant to state regulations covering these operations. Based on public comments and reports to 

the EPA's Natural Gas STAR Program, the EPA acknowledges that some producers conduct well 

completions using reduced emission completion (REC) techniques voluntarily. This analysis 

acknowledges this voluntary activity by estimating the number of hydraulically fractured gas 

well completions performed with voluntary use of capture and combustion equipment in 2015. 

The number of hydraulically fractured gas well completions performed with voluntary use of 

capture and combustion equipment in 2015 is determined in the three following steps: 

5.1 Number of Voluntary RECs calculates the number of gas well completions with hydraulic 

fracturing performed with voluntary reduction emission completion techniques in 2008, 2009, 

and 2010. 

5.2 - Number of Completions Events Eligible for RECs calculates the number of gas well 

completions with hydraulic fracturing not under state regulation and with sufficient pressure to 

perform an REC. 

5.3 - Fraction of Eligible Completions with Voluntary RECs assumes that the average 

fraction of gas well completions with hydraulic fracturing performed with voluntary reduction 

emission completion techniques in 2008, 2009, and 2010 as the fraction of gas well completions 

with hydraulic fracturing performed with voluntary reduction emission completion techniques in 

2015. 

5.1 Number of Voluntary RECs 

Voluntary methane reductions from capturing and combusting methane when performing a 

reduced emission completion are reported by Partners and published annually in aggregate by the 

Natural Gas STAR Program. This analysis uses this data to estimate the number of gas well 

completions with hydraulic fracturing conducted using REC techniques voluntarily. 

Table 5-1 shows the total methane reductions reported to the Natural Gas STAR Program from 

Partners performing RECs from 2008 to 2010. These figures are published annually on the 
5-2 

Natural Gas STAR website under the Accomplishments webpage.27 The figures published on the 

Natural Gas STAR website, however, are not updated for reports received from Partners after the 

reported year (e.g. 2010 REC reductions reported in 2011). Table 5-1shows the most up-to-date 

total emission reductions reported from Natural Gas STAR Partner performing RECs including 

2010 REC reductions reported in 2011. 

Table 5-1. Number of Voluntary Reduced Emission Completions Performed 

Year 

REC iSTAR Methane 

Reductions (short tons/year) 

Estimated Number of 

Voluntary RECs 

Performed 

2008 975,905 6,600 

2009 504,480 3,412 

2010 590,724 3,995 

The annual REC reductions shown in Table 5-1 were divided by the average methane reductions 

per completion, shown in Equation 5-1 to determine the number of completions with voluntary 

RECs, also shown in Table 5-1. 

The average methane reductions per completion was determined using the emission factor for 

gas well completions with hydraulic fracturing, the average methane content for gas well 

completions, and the average reduction effectiveness for RECs. The emission factor for gas well 

completions with hydraulic fracturing is 9,000 Mcf. This is discussed in section 1.1.2 of this 

document. A memo titled Composition of Natural Gas for use in the Oil and Natural Gas Sector 

Rulemaking, which can be found in the rule making docket, indicates, in Table 8, that the average 

composition of methane in gas well completions is 83.081%. In addition, this analysis assumes that 

an REC reduces methane emissions from gas well completions by 95 percent. Based on an 83.081 

percent methane composition, a reduction effectiveness of 95 percent, and the conversion of 48.04 

thousand cubic feet per short ton, the average methane reductions per completion and 

recompletions is 147.86 thousand cubic feet. The calculation to determine the average methane 

reductions per completion is shown in Equation 5-1. 

ܴ ൌ

ܥ ൈ ܯ ൈ ܨܧ

48.04 ൌ 147.86

ݏ݊݋ݐ ݐݎ݋݄ݏ

 5-1 .Eq ݊݋݅ݐ݈݁݌݉݋ܿ

where, 

R = average methane reductions per completion 

EF = average natural gas emissions per completion (9,000 Mcf/completion) 

M = average methane composition for gas well completions (83.081%) 

 

27 EPA. (2012) Accomplishments. <www.epa.gov/gasstar/accomplishments/index.html> 
5-3 

C = reduction effectiveness (95%) 

48.04 = conversion factor 48.04 thousand cubic feet equals 1 short ton 

5.2 Number of Completions Events Eligible for RECs 

The historical number of gas well completions with hydraulic fracturing not required by state 

regulation and with sufficient pressure to perform an REC is determined using the total 

successful developmental and exploratory gas completions with hydraulic fracturing in 2008, 

2009 and 2010, the fraction of gas well completions with hydraulic fracturing impacted by state 

regulation, and the fraction of low pressure completions. 

5.2.1 Historical Gas Well Completions with Hydraulic Fracturing from the EIA NEMS Model

The total gas completions with hydraulic fracturing in 2008, 2009 and 2010 are determined by 

the National Energy Modeling System (NEMS). NEMS is a model of U.S. energy economy 

developed and maintained by the Energy Information Administration (EIA)28. NEMS is used to 

produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the 

energy economy from the current year to 2035. The NEMS database defines unconventional 

reservoirs as those in shale, tight sand, and coalbed methane formations and distinguishes those from 

wells drilled in conventional reservoirs. This analysis assumes new successful natural gas wells in 

shale, tight sand, and coalbed methane formations are completed with hydraulic fracturing. Table 5-2 

shows the total successful developmental and exploratory gas well completions with hydraulic 

fracturing for 2008, 2009, and 2010. Equation 5-2 shows the number of developmental completions 

is the total completions less the exploratory completions. 

 5-2 .Eq ܥܧ െ ܥܶ ൌ ܥܦ

where, 

DC = total developmental gas well completions with hydraulic fracturing 

TC = total gas well completions with hydraulic fracturing 

EC = total exploratory gas well completions with hydraulic fracturing 

 

28 U.S. Energy Information Administration. Annual Energy Outlook 2011. Energy Information Administration. 
5-4 

Table 5-7. Total Successful Developmental and Exploratory Gas Well Completions with 

Hydraulic Fracturing 

Year 

Total Gas 

Completions with 

Hydraulic Fracturing 

Exploratory Gas 

Completions with 

Hydraulic Fracturing 

Developmental Gas 

Completions with 

Hydraulic Fracturing 

2008 16,862 0 16,862 

2009 10,275 0 10,275 

2010 9,015 312 8,703 

5.2.2 Completions with Hydraulic Fracturing under State Regulation

The fraction of gas well completions and recompletions with hydraulic fracturing impacted by 

state regulation is determined using the analysis from the Technical Support Document (TSD) 

for the proposed NSPS OOOO rule.29 The TSD determines fraction of gas well completions and 

recompletions with hydraulic fracturing impacted by state regulation accounting for regulations 

in Wyoming and Colorado. Since this analysis is considering historical data, when the respective 

Wyoming and Colorado regulations were implemented was considered. The Wyoming 

regulation was in place in 200830 and the Colorado regulation was implemented in 200931. 

Therefore, the TSD analysis was revisited to determine the fraction of gas well completions and 

recompletions with hydraulic fracturing impacted by only the Wyoming regulation, for the 2008 

estimate. The result was approximately 9.6 percent. This is shown in Equation 5-3, while 

Equation 5-4 shows that the number of developmental gas completions without hydraulic 

fracturing with RECs due to state regulations is determined using the 15 percent for both the WY 

and CO regulations, used in the 2009 and 2010 estimates. 

ܥܦ௢௡ௌ௧௔௧௘ ൌ ܥܦ ൈ ሺ1 െ 9.6%ሻ Eq. 5-3 

ܥܦ௢௡ௌ௧௔௧௘ ൌ ܥܦ ൈ ሺ1 െ 15%ሻ Eq. 5-4 

where, 

DCNoState = total developmental gas well completions with hydraulic 

 

29 EPA. (2011) 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. EPA-453/R-11-

002. pg. 4-12 

30 State of Wyoming Department of Environmental Quality, Air Quality Division. Well Completions/Recompletions Permit Application. Page 2. August 2010. http://deq.state.wy.us/aqd/Oil%20and%20Gas/AQDOG11_Green%20Completion%20Application.pdf 

31 Colorado Oil and Gas Conservation Commission. 2 CCR-404-1. http://oilgas.state.co.us/RuleMaking/FinalDraftRules/COGCCFinalDraftRules_110708.pdf 
5-5 

fracturing not under state regulation 

15% = fraction of gas well completions and recompletions with hydraulic 

fracturing impacted by both WY and CO state regulations 

9.5% = fraction of gas well completions and recompletions with hydraulic 

fracturing impacted by both WY state regulations 

DC = total developmental gas well completions with hydraulic 

fracturing 

Table 5-8. Total Successful Developmental Gas Well Completions with Hydraulic 

Fracturing Not Under State Regulation 

Year 

Developmental Gas 

Completions with 

Hydraulic Fracturing 

Developmental Gas 

Completions with 

Hydraulic Fracturing with 

RECs due to State 

Regulations 

Developmental Gas 

Completions with 

Hydraulic Fracturing 

not under State 

Regulation 

2008 16,862 1,616a 15,246 

2009 10,275 1,554b 8,722 

2010 8,703 1,316b 7,387 

a. Only the Wyoming regulation is in place (9.5% of completions) 

b. Both the Colorado and Wyoming regulations are in place (15% of completions) 

5.2.3 Completions with Hydraulic Fracturing with Low Pressure

The fraction of gas well completions with low pressure (i.e. insufficient to capture and direct 

flowback gas from the well to a flow line) is 10 percent as determined in section 2.0 of this 

document. Table 5-4 shows how the total developmental gas well completions with hydraulic 

fracturing for 2008, 2009, and 2010 not under state regulation is used to determine the gas 

completions with hydraulic fracturing with sufficient pressure to perform a REC and not under 

state regulation in 2008, 2009, and 2010. Equation 5-5 shows how this calculation is performed. 

DCNSNLP ൌ DCN୭S୲ୟ୲ୣ ൈ ሺ1 െ 10%ሻ

Eq. 5-5 

where, 

DCNSNLP = historical gas completions with hydraulic fracturing with sufficient pressure 

perform a REC and not under state regulation 

10% = fraction of gas well completions and recompletions with hydraulic fracturing 
5-6 

impacted by state regulation 

DCNoState = total developmental gas well completions with hydraulic fracturing not under 

state regulation 

Table 5-9. Total Developmental Gas Well Completions with Hydraulic Fracturing with 

Sufficient Pressure to Perform a REC and Not Under State Regulation 

Year 

Developmental Gas 

Completions with 

Hydraulic Fracturing 

not under State 

Regulation 

Low Pressure Gas 

Completions with 

Hydraulic Fracturing 

incapable of performing 

RECs 

Total Developmental Gas Well 

Completions with Hydraulic 

Fracturing with Sufficient 

Pressure to Perform a REC and 

Not Under State Regulation 

2008 15,246 1,525 13,722 

2009 8,722 872 7,850 

2010 7,387 739 6,648 

5.2.4 Historical Completions with Hydraulic Fracturing with Sufficient Pressure to Perform a 

REC and not under State Regulation

Table 5-4 shows the total gas well completions with hydraulic fracturing from the EIA NEMS 

model is finally reduced to the gas well completions with hydraulic fracturing not under state 

regulation and with sufficient pressure to perform and REC in 2008, 2009, and 2010. 

5.3 Fraction of Eligible Completions with Voluntary RECs 

The final step in this analysis determines the percent of completions not under state regulation 

and with sufficient pressure to perform an REC that were conducted with voluntary REC 

techniques in 2015. This is done by first dividing the number of completions with voluntary 

RECs (from Table 5-1) by the number of historical gas completions with hydraulic fracturing 

with sufficient pressure to perform a REC and not under state regulation (from Table 5-4) for 

each year 2008, 2009, and 2010. The results of this calculation for 2008, 2009, and 2010 are 

shown in Table 5-5. 

Table 5-5. Percent of Completionsthat were Conducted with Voluntary RECs 

Year 

Estimated Number of 

Voluntary RECs 

Performed 

Total Developmental 

Gas Well Completions 

with Hydraulic 

Fracturing with 

Sufficient Pressure to 

Perform a REC and 

Not Under State 

Regulation 

Percent of Completions not 

under State Regulations, with 

Sufficient Pressure that were 

Conducted with Voluntary 

RECs 
5-7 

2008 6,600 13,722 48% 

2009 3,412 7,850 43% 

2010 3,995 6,648 60% 

Secondly, a three-year average from 2008 to 2010 was taken of the historical percentages shown 

in Table 5-5 to represent the variability in the implementation of voluntary RECs. The result of 

averaging 48%, 43%, and 60% is about 51%. The analysis and other NSPS OOOO regulation 

impacts analyses will assume that this 51% will be the fraction of hydraulically fractured gas 

well completions not already under state regulation and with sufficient pressure to perform a 

REC that will implement RECs voluntarily in 2015. 

5.4 New Source Completions and Recompletions with Voluntary Action 

The EPA estimates the number of gas completions with hydraulic fracturing with sufficient 

pressure to perform a REC and not under state regulation in 2015 is 8,382. Therefore, assuming 

51% of these completions will perform a REC, the remaining 4,107 will constitute the 

completions impacted by this NSPS OOOO rule. 

In addition, final TSD indicates that the number of gas recompletions with hydraulic fracturing 

with sufficient pressure to perform a REC and not under state regulation in 2015 is 1,085. 

Therefore, assuming 51% of these recompletions will perform a REC, the remaining 532 will 

constitute the recompletions impacted by this NSPS OOOO rule. 
6-1 

6.0 CENTRIFUGAL COMPRESSOR IMPACTS 

This section provides additional information on parameters used in the centrifugal compressor 

regulatory impact analysis. This section also provides the affected facility emissions reduction 

estimates and cost estimates, as they have been updated in the final rule as compared to the 

proposed rule. Below are the parameters with significant updates along with text descriptions of 

those changes. 

6.1 Projected Number of Affected Units 

The final rule projects the number of affected units to be 13 wet seal centrifugal compressors 

annually. This is based on 16 new centrifugal compressor units expressed in the TSD32 with a 

ratio applied to represent just wet seal units. The Inventory of Greenhouse Gas Emissions and 

Sinks 1990 to 2009 includes an improvement that distinguishes between wet seal vs dry seal 

units33. This data was used to create a ratio of new wet seal units versus new dry seal units. 

From table A-121 of the inventory annex, there were 646 wet seal compressors and 140 dry seal 

compressors in processing. It was decided to use this inventory ratio in lieu of the general 

understanding that 90% of new centrifugal compressors are dry seal34 so that the worst-case 

impacts can be represented. 

6.2 Capital Costs 

Based on comment s received, it is evident that vapor captured from centrifugal compressor seal 

oil degassing is not always routed to a flare but in many cases routed back to the compressor 

suction or fuel system. The cost of a system of this type in which the seal oil degassing vents are 

routed to fuel gas, compressor suction, or an existing flare is estimated to be $22,00035. The 

estimated cost includes an intermediate pressure degassing drum, new piping, gas demister/filter, 

and a pressure regulator for the fuel line. Since a new flare or other combustion source is 

expected to be available in gas processing facilities, it was not included in the capital cost for this 

control option, whereas the proposed rule did include the cost of a flare. For other facilities 

types, the EPA estimate is that zero new affected facilities will come into existence each year36. 

Therefore the capital costs (before applying the capital recovery factor) for an affected facility in 

the final rule is $22,000 for seal oil degassing capture as compared to $67,918 in the proposed 

rule’s TSD for the gas capture system and flare37, and as compared to the proposal costs of 

$75,000 for use of dry seals used in the TSD38. 

 

32 Table 6-14 page 6-30 of the TSD at www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0505-0045 33 Page A-153 of epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-Annex-3.pdf Table A121

34 Page 6-27 of the TSD 

35 www.epa.gov/gasstar/documents/ngspartnerup_spring09.pdf 36 Table 6-14 on page 6-30 of the TSD depicts the number of new sources per year for production and gathering & 

boosting to be zero each. Additionally, page 6-19 of the TSD states that new sources will be located in only the 

processing and transmission segments. 

37 Table 6-12 on page 6-26 of the TSD 

38 Table 6-12 on page 6-22 of the TSD 
6-2 

6.3 Without Revenues from Additional Product Recovery 

The per unit annual cost is calculated by taking the cost of $22,000 multiplied by an annualized 

capital recovery factor (explained further in the TSD) of 0.1424.The total annual cost for wet 

seal centrifugal compressors without revenue from additional product recovery is estimated to be 

$40,720. This is based on a total annual cost per unit of $3,132 multiplied by 13 new units per 

year. 

6.4 With Revenues from Additional Product Recovery 

The per unit annual cost savings is calculated by taking the value of the gas that is not emitted 

and routed to a useful purpose as a result of the VOC control, assuming that all gas that is not 

emitted is being routed to a useful purpose which is reasonable given the available information 

on the destination of recovered seal oil degassing streams. The value of the gas is estimated as 

95%39 of the 13,186 Mcf/yr40 of natural gas emitted per unit. The total annual cost for wet seal 

centrifugal compressors with revenue from additional product recovery is estimated to be -

$610,657. This is based on a total annual cost per unit of -$46,974 multiplied by the 13 new units 

per year. 

6.5 Baseline Emissions from Wet Seal Centrifugal Compressors in the Processing Sector 

The baseline emissions from a representative new source are summarized in Table 6-1 based on 

the emissions factors and gas composition profiles in the TSD. The VOC and HAP emissions are 

estimated using a conversion from mass of methane to mass of VOC or HAP and a weighted 

average based on the assumption that 75% of centrifugal compressors in the processing segment 

will compress transmission quality gas. 

Table 6-1. Wet Seal Centrifugal Compressor Baseline Emissions

Source 

VOC 

(tpy)

Methane 

(tpy)

HAP 

(tpy)

Emissions per New Wet Seal Centrifugal Compressor 20.534 227.529 0.736 

Total Emissions from ALL New Wet Seal Centrifugal 

Compressors 267 2,958 10 

6.6 Emission Reduction for Wet Seal Centrifugal Compressors in the Processing Sector 

The emissions reductions for wet seal centrifugal compressors in the processing sector are 

summarized in Table 6-2 using a 95% control efficiency. 

 

39 Page 6-23 of the TSD 

40 47.7 scf methane / minute in Table 6-2 of the TSD * 43.6% annual operating factor on page 6-19 of the TSD, 

converted to Mcf/year and using a conversion factor of methane to natural gas of 82.9 volume percent found in the 

gas composition memo dated July 28, 2011. 
6-3 

Table 6-2. Wet Seal Centrifugal Compressor Emission Reductions – 95 Percent Control 

Source 

VOC 

(tpy)

Methane 

(tpy)

HAP 

(tpy)

Emissions Reductions Per New Wet Seal Centrifugal 

Compressor 19.508 216.152 0.699 

Total Emissions Reductions from ALL New Wet Seal 

Centrifugal Compressors 253.60 2,810 9.09 
7-1 

7.0 UPDATE TO TECHNICAL SUPPORT DOCUMENT FOR PROPOSED 

STANDARDS OF PERFORMANCE FOR CRUDE OIL AND NATURAL GAS 

PRODUCTION, TRANSMISSION, AND DISTRIBUTION – STORAGE VESSELS 

7.1 INTRODUCTION 

On August 23, 2011, the U.S. Environmental Protection Agency (EPA) proposed new source 

performance standards (NSPS) for new sources in the crude oil and natural gas production, 

transmission, and distribution source category. The NSPS includes standards for storage vessels 

with throughput greater than 1 barrel of condensate per day (bpd) and crude oil storage vessels 

with throughput greater than 20 bpd of crude oil under the authority of section 111 of the Clean 

Air Act (CAA). The public comment period closed on November 30, 2011, and EPA received 

comments regarding the throughput thresholds and cost impacts of the proposed amendments to 

the storage vessel standards. 

In response to these comments, we evaluated changes to the storage vessels new source 

standards. The purpose of this section is to present this analysis. 

7.2 BASELINE EMISSIONS 

In the technical support document (TSD) for the proposed standards,41 we developed model tank 

batteries to represent the predominant population of tanks (e.g., condensate and crude oil tanks). 

These model tank batteries are presented in Tables 7-1 and 7-2. Using these model tanks, we 

developed nationwide baseline emissions (i.e., nationwide emissions in the absence of a federal 

rulemaking). The nationwide baseline emissions are presented in Table 7-3. 

7.3 COST OF CONTROL TECHNIQUES 

We evaluated two control techniques, a vapor recovery unit (VRU) and a combustor; both of 

which can reduce VOC emissions by 95 percent. A detailed discussion on the development of the 

costs associated with a VRU and a combustor is presented in the TSD. 

 

41 EC/R Incorporated. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

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

Proposed Standards. Prepared for U.S. Environmental Protection Agency. Research Triangle 

Park, NC. Publication No. EPA-453/R-11-0012. July 2011. Docket No. EPA-HQ-OAR-2010-

0505-0045. 
7-2 

Table 7-1. Model Condensate Tank Batteries 

 Model Condensate Tank Battery 

Parameter E F G H 

Condensate throughput (bbl/day) 15 100 1,000 5,000 

Condensate throughput (bbl/yr) 5,475 36,500 365,000 1,825,000 

Number of fixed-roof product storage vessels 

 210 barrel capacity 4 2 

 500 barrel capacity 2 2 

 1,000 barrel capacity 2 4 

Estimated tank battery population (1992) 12,000 500 100 70 

Estimated tank battery population (2008) 14,038 585 117 82 

Total number of storage vessels (2008) 56,151 2,340 468 328 

Percent of number of storage vessels in model 

condensate tank battery 94.7% 3.95% 0.789% 0.552% 

Percent of throughput per model condensate tank 

battery 26% 7% 15% 51% 

Total tank battery condensate throughput 

(MMbbl/yr) 32.8 9.11 18.2 63.8 

Condensate throughput per model condensate 

battery (bbl/day) 6.41 42.7 427 2,135 

Condensate throughput per storage vessel 

(bbl/day) 1.60 10.7 106.8 534 

Minor discrepancies may be due to rounding. 

a

Model condensate tank battery development presented in the TSD for the proposed rule. (Reference 41).

Table 7-2. Model Crude Oil Tank Batteriesa

Parameter 

Model Crude Oil Tank Battery 

E F G H 

Percent of number of condensate storage vessels in 

model size range 94.7% 3.95% 0.789% 0.552% 

Number of storage vessels 491,707 20,488 4,098 2,868 

Percent of throughput across condensate tank 

batteries 26% 7% 15% 51% 

Crude oil throughput per model plant category 

(MMbbl/yr) 351 97.5 195 683 

Crude oil throughput per storage vessel (bbl/day) 1.96 13.0 130 652 

Minor discrepancies may be due to rounding. 

a Model crude oil tank battery development presented in the TSD for the proposed rule. (Reference 41).

 
7-3 

Table 7-3. Nationwide Baseline Emissions for Storage Vesselsa

 Model Tank Battery 

E F G H Total 

Model Condensate Tank Batteries 

Total number of storage vessels (2008) 56,151 2,340 468 328 59,286 

Total projected number of new or modified 

storage vessels (2015) b 4,630 193 39 27 4,889 

Number of uncontrolled storage vessels in 

absence of federal regulationc

 1,688 70 14 10 1,782 

Uncontrolled VOC Emissions from storage vessel 

at model tank batteryd

 3.35 22.3 223 1,117 1,366 

Total Nationwide Uncontrolled VOC Emissions 5,657 1,572 3,143 11,001 21,373 

Model Crude Oil Tank Batteries 

Total number of storage vessels (2008) 491,707 20,488 4,098 2,868 519,161

Total projected number of new or modified 

storage vessels (2015) b 40,548 1,689 338 237 42,812 

Number of uncontrolled storage vessels in 

absence of federal regulationc

 14,782 616 123 86 15,607 

Uncontrolled VOC Emissions from storage vessel 

at model tank batteryd

 0.4 2.80 28 140 171 

Total Nationwide Uncontrolled VOC Emissions 6,200 1,722 3,444 12,055 23,421 

Minor discrepancies may be due to rounding 

a

 Nationwide baseline emissions were presented in the Technical Support Document for Proposed 

Standards (Reference 41) 

b

Calculated by applying the expected 8.25 percent industry growth to the number of storage vessels in 

2008. 

c

Calculated by applying the estimated 36 percent of storage vessels that are uncontrolled in the absence of 

a Federal Regulation to the total projected number of new or modified storage vessels in 2015. 

d

 VOC Emissions from individual storage vessel at model tank battery.

 
7-4 

Cost data for a VRU was obtained from an Initial Economic Impact Analysis (EIA) prepared for 

the proposed State-only revisions to a Colorado regulation. 42 We assumed that the cost data in 

the EIA were presented in 2007 dollars. For this analysis, we escalated the costs to 2008 dollars 

using the Chemical Engineering (CE) Indices for 2007 (525.4) and 2008 (575.4).43 Total capital 

investment was estimated to be $98,186 and is presented in Table 7-4. We estimated total annual 

costs to be $18,983 per year. 

For combustors, we also obtained the cost data from the initial EIA prepared for State-only 

revisions to the Colorado regulation.42 In addition to these cost data, we added a line-item for 

operating labor. This is consistent with the guidelines outlined in EPA’s OAQPS Control Cost 

Manual (OCCM) for combustion devices.44 However, the OCCM recommends that combustion 

devices would require 630 hours per year of operating labor. Since we believe that most of these 

sites will be unmanned and would most likely be operated remotely, an estimate of 2 hours per 

day seems unreasonable. Therefore, we assumed that the operating labor would be more similar 

to that estimated for a condenser in the OCCM, 130 hours per year. We estimated a total capital 

investment of $32,301and a total annual cost of $19,580/yr. The costs for a combustor are 

presented in Table 5. 

7.4 REGULATORY OPTIONS AND NATIONWIDE IMPACTS OF REGULATORY 

OPTIONS 

7.4.1 Consideration of Regulatory Options for Condensate and Crude Oil Storage Vessels

The VOC emissions from storage vessels vary significantly, depending on the rate of liquid 

entering and passing through the vessel (i.e., its throughput), the pressure of the liquid as it enters 

the atmospheric pressure storage vessel, the liquid’s volatility and temperature of the liquid. 

Some storage vessels have negligible emissions, such as those with very little throughput and/or 

handling heavy liquids entering at atmospheric pressure. Therefore, in order to determine the 

most cost effective means of controlling the storage vessels, a threshold was evaluated to limit 

the applicability of the standards to these storage vessels. We originally proposed the 

applicability threshold for storage vessel control requirements in terms of throughput because we 

believed that this would simplify applicability determinations for sources, particularly small 

sources. However, because emission factors vary widely, we now recognize that it is 

inappropriate to develop liquid throughput thresholds based on average emission factors. 

 

42 Initial Economic Impact Analysis for Proposed State-Only Revisions to the Air Quality 

Control Commission’s Regulation Number 7, “Emissions of Volatile Organic Compounds.” 

September 18, 2008. 

43 Economic Indicators: Chemical Engineering Plant Cost Index. Chemical Engineering 

Magazine. 

44 OAQPS Control Cost Manual: Fourth Edition (EPA 450/3-90-006, January 1990). U.S. 

Environmental Protection Agency. Research Triangle Park, NC. 
7-5 

As a result, we evaluated a threshold based on VOC emissions instead of liquid throughput. We 

believe that the use of a VOC emissions threshold is a more flexible approach, ensuring that 

controls will be required only on those storage vessels where they can be applied costeffectively. Therefore, we evaluated the costs of controlling storage vessels with varying 

emissions to determine which level of emissions would provide the most cost effective control 

option. 

We evaluated an emission reduction of 95 percent, which, as discussed above, could be achieved 

with a VRU or a combustor. A combustor is an option for tank batteries because of the 

operational issues associated with a VRU. While the use of a VRU is preferable to a combustor 

because a combustor destroys, rather than recycles, valuable resources and there are secondary 

impacts associated with the use of a combustor, the cost impacts associated a combustor installed 

for the control of storage vessels were evaluated. This is a conservative approach, because the 

cost of a combustor is (slightly) higher than that of a VRU. 

Table 7-4. Total Capital Investment and Total Annual Cost of a Vapor Recovery Unit 

Cost Itema

Capital 

Costs

($)

NonRecurring, 

One-time 

Costs ($)

Total 

Capital 

Investment 

($)b

O&M 

Costs ($)

Savings due 

to Fuel 

Sales ($/yr)

Annualized 

Total Cost 

($/yr) c

VRU $78,000

Freight and Design $1,500

VRU Installation $10,154

Maintenance $8,553

Recovered natural 

gas ($1,063)

Subtotal Costs (2007) $78,000 $11,654 $8,553 ($1,063)

Subtotal Costs 

(2008)d $85,423 $12,763 $98,186 $9,367 ($1,164)

Annualized costs 

(using 7% interest, 15 

year equipment life) $9,379 $1,401 n/a n/a $18,983

Minor discrepancies may be due to rounding 

a

 Assume cost data provided is for the year 2007. Reference 42. b

 Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one-time 

costs. 

c

 Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and savings 

due to fuel sales. 

d

 Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4). 

Reference 43. 
7-6 

Table 7-5. Total Capital Investment and Total Annual Cost of a Combustor

Cost Itema

Capital 

Costs 

($) 

NonRecurring, 

One-time 

Costs ($) 

Total 

Capital 

Investment 

($)b

O&M 

Costs ($) 

Annualized 

Total Cost 

($/yr) c

Combustor $16,540 

Freight and Design $1,500 

Combustor Installation $6,354 

Auto Igniter $1,500 

Surveillance Systemd $3,600 

Pilot Fuel $1,897 

Operating Labore $9,743 

Maintenance $2,000 

Data Management $1,000 

Subtotal Costs (2007) $21,640 $7,854 $14,640 

Subtotal Costs (2008)f $23,699 $8,601 $32,301 $16,033 

Annualized costs (using 7% 

interest, 15 year equipment 

life) $2,602 $944 n/a $19,580 

Minor discrepancies may be due to rounding 

a

 Assume cost data provided is for the year 2007 (Reference 42).

b

 Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one-time 

costs. 

c

 Total Annual Costs is the sum of the annualized capital and non-recurring costs, O&M costs. 

d

 Surveillance system identifies when pilot is not lit and attempt to relight it, documents the duration of 

time when the pilot is not lit, and notifies and operator that repairs are necessary. e

 Operating labor consists of labor resources for technical operation of device (130 hr/yr), supervisory 

labor (15 percent of technical labor hours), and maintenance labor hours (130 hr/yr). Labor rates are 

$33.51/hr (for technical and maintenance labor) and $52.85 (supervisory labor) (Reference 45). 

f Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4) 

(Reference 43).

 

 

45 Employer Costs for Employee Compensation Historical Listing March 2004 – December 2010

ftp://ftp.bls.gov/pub/special.requests/ocwc/ect/ececqrtn.pdf. 
7-7 

To conduct this evaluation, we considered the following four regulatory options, which are 

presented in Table 7-6: 

• Regulatory Option 1: Control condensate storage vessels with VOC emissions greater 

than 3 tpy; 

• Regulatory Option 2: Control condensate storage vessels with VOC emissions greater 

than 6 tpy; 

• Regulatory Option 3: Control condensate storage vessels with VOC emissions greater 

than 12 tpy; and 

• Regulatory Option 4: Control condensate storage vessels with VOC emissions greater 

than 30 tpy. 

As shown in Table 7-6, Regulatory Option 1 is not cost effective for condensate storage vessels 

with emissions greater than 3 tpy. Therefore Regulatory Option 1 is rejected. Since the cost 

effectiveness associated with Regulatory Option 2 is acceptable ($3,435/ton), this option was 

selected. As shown in Table 7-3, Model Condensate Storage Vessel Categories F, G, and H have 

emissions greater than 6 tpy. Therefore, for the purposes of determining impacts, the populations 

of new and modified condensate storage vessels associated with categories F, G, and H are 

assumed to be required to reduce their emissions by 95 percent, a total of 94 new or modified 

condensate storage vessels by 2015. 

A similar evaluation was performed for crude oil vessels and is also presented in Table 6 for the 

following regulatory options: 

• Regulatory Option 1: Control crude oil storage vessels with emissions greater than 

0.3 tpy; 

• Regulatory Option 2: Control crude oil storage vessels with emissions greater than 

1.5 tpy; 

• Regulatory Option 3: Control crude oil storage vessels with emissions greater than 6 tpy; 

and 

• Regulatory Option 4: Control crude oil storage vessels with emissions greater than 

15 tpy. 

As shown in Table 7-6, Regulatory Options 1 and 2 are not cost effective crude oil storage 

vessels with a emissions of 0.3 and 1.5 tpy, respectively. Therefore Regulatory Options 1 and 2 

are rejected. Since the cost effectiveness associated with Regulatory Option 3 is acceptable 

($3,435/ton), this option was selected. As shown in Table 3, Model Crude Oil Storage Vessel 

Categories G and H have emissions greater than 6 tpy. Therefore, for the purposes of 

determining impacts, the populations of new and modified crude oil storage vessels associated 

with categories G and H are assumed to be required to reduce their emissions by 95 percent, a 

total of 209 new or modified condensate storage vessels by 2015. 

 
7-8 

Table 7-6. Options for VOC Emissions Thresholds for Storage Vessels 

Regulatory 

Option 

VOC 

Emissions 

Threshold 

(tpy) 

VOC 

Emission 

Reduction 

(tpy) a

Annual 

Costs for 

Combustor 

($/yr) b

Cost 

Effectiveness 

($/ton VOC) 

Number 

of 

impacted 

unitsc

Condensate Storage Vessels 

1 3 2.85 $19,580 $6,870 1782 

2 6 5.70 $19,580 $3,435 94 

3 12 11.40 $19,580 $1,718 94 

4 30 28.50 $19,580 $687 24 

Crude Oil Storage Vessels 

1 0.3 0.28 $19,580 $70,584 15607 

2 1.5 1.39 $19,580 $14,117 825 

3 6 5.70 $19,580 $3,435 209 

4 15 14.25 $19,580 $1,374 209 

Minor discrepancies may be due to rounding 

a

 Calculated using 95 percent reduction 

b

 Refer to Table 5 for Combustor Annual Costs. 

c

 Number of impacted units determined by evaluating which of the model tank batteries and storage 

vessel populations associated with each model tank battery (refer to Table 7-3) would be subject to each 

regulatory option. A storage vessel at a model tank battery was considered to be impacted by the 

regulatory option if its emissions were greater than the thresholds for the option.

 
7-9 

7.4.2 Nationwide Impacts of Regulatory Options

This section provides an analysis of the primary environmental impacts (i.e., emission 

reductions), cost impacts and secondary environmental impacts related to Regulatory Option 2 

for condensate storage vessels and Regulatory Option 3 for crude oil storage vessels which were 

selected as viable options for setting standards for storage vessels. In addition, combined impacts 

for a typical storage vessel are presented. 

Primary Environmental Impacts of Regulatory Options 

Regulatory Option 2 (condensate storage vessels) and 3 (crude oil storage vessels) were selected 

as options for setting standards for storage vessels as follows: 

• Regulatory Option 2 (Condensate Storage Vessels): Reduce emissions from condensate 

storage vessels with average emissions greater than 6 tpy. 

• Regulatory Option 3 (Crude Oil Storage Vessels): Reduce emissions from crude oil 

storage vessels with average emissions greater than 6 tpy. 

Because the emissions threshold does not depend upon the type of liquid being stored in the 

storage vessel, the regulations will apply to all storage vessels, regardless of contents. However, 

for the purposes of estimating impacts, we only included populations for condensate and crude 

oil storage vessels. The number of storage vessels that would be subject to the regulatory options 

listed above are presented in Table 7-6. It was estimated that, by 2015, there would be 94 new or 

modified condensate storage vessels not otherwise subject to State regulations and impacted by 

Regulatory Option 2 (condensate storage vessels). As shown in Table 7-6, in 2015, 209 new or 

modified crude oil storage vessels not otherwise subject to State regulations would be impacted 

by Regulatory Option 3 (crude oil storage tanks). 

 

Table 7-7 presents the nationwide emission reduction estimates for each regulatory option. 

Emissions reductions were estimated by applying a 95 percent control efficiency to the VOC 

emissions presented in Table 7-3 for each storage vessel in the model condensate and crude oil 

tank batteries and multiplying by the number of impacted storage vessels. For Regulatory Option 

2 (condensate storage vessels), the total nationwide VOC emission reduction was estimated to be 

15,061 tpy and 14,710 tpy for Regulatory Option 3 (crude oil storage vessels). 

7.4.3 Nationwide Cost Impacts

Cost impacts of the individual control techniques (VRU and combustors) were presented in 

Tables 7-4 and 7-5. For both regulatory options, it was assumed that 50 percent of facilities 

would install a combustor and 50 percent a VRU. This accounts for the operational difficulties of 

using a VRU. Therefore, the average capital cost of control for each storage vessel was estimated 

to be $65,243 (the average of the total capital investment for a VRU of $98,186 and $32,301 for 
7-10 

Table 7-7. Nationwide Impacts of Regulatory Options 

Model 

Tank 

Battery 

Number 

of New 

Sources 

subject to 

Regulator

y Option 

by 2015a

VOC 

Emissions 

for a 

Typical 

Storage 

Vessel 

(tpy) 

Capital 

Cost 

for 

Typical 

Storage 

Vesselb

($) 

Annual Cost for a 

Typical Storage 

Vesselb

($/yr) 

Nationwide 

Emission 

Reductions (tpy)c

VOC Cost 

Effectiveness 

($/ton) 

Methane Cost 

Effectiveness 

($/ton) 

Without 

Savings 

With 

Savings VOC Methaned

Without 

Savings 

With 

Savings 

Without 

Savings 

With 

Savings 

C

Regulatory Option 2: Condensate Storage Vessels 

F 70 22.3 65,243 19,864 19,281 1,483 325 938 910 4284 4158 

G 14 223 65,243 19,864 19,281 2,966 649 94 91 428 416 H 10 1117 65,243 19,864 19,281 10,612 2323 19 18 86 83 

Total for Regulatory Option 2 15,061 3,296 

Regulatory Option 3: Crude Oil Storage Vessels

G 123 28 65,243 19,864 19,281 3,272 716 747 725 3412 3312 H 86 140 65,243 19,864 19,281 11,438 2503 149 145 682 662 

Total for Regulatory Option 3 14,710 3,220 

Combined Impactse

Typical Storage 

Vessel 304 103 65,243 19,864 19,281 29,746 6,511 203 197 927 900 

Minor discrepancies may be due to rounding a Number of storage vessels in each model tank battery (refer to Table 7-3) determined to be subject to the regulatory option as outlined bIt was assumed for the purposes of estimating nationwide impacts that 50 percent of facilities would install a combustor and 50 percen

for the operational difficulties of using a VRU. Capital and Annual Costs determined using the average of costs presented in Tables 7-4 

c Nationwide emission reductions calculated by applying a 95 percent emissions reduction to the VOC emissions for a typical storage v

number of sources subject to the regulatory option. 

d Methane Reductions calculated by applying the average Methane to VOC factor from the E&P Tanks Study (see Appendix A). Methae For purposes of evaluating NSPS impact, impacts were determined for an average storage vessel by calculating total VOC emissions f

and dividing by the total number of impacted storage vessels to obtain an average VOC emissions per storage vessel.
7-11 

a combustor from Tables 7-4 and 5, respectively). Similarly, the average annual cost for a typical 

storage vessel was estimated to be $19,864/yr (average of the total annual cost for a VRU of 

$20,147/yr and $19,580/yr for a combustor from Tables 7-4 and 7-5, respectively) without 

including any cost savings due to fuel sales and $19,281/yr (average of the total annual cost for a 

VRU of $18,983/yr and $19,580/yr for a combustor from Tables 7-4 and 7-5, respectively) 

including cost savings. 

Nationwide capital and annual costs were calculated by applying the number of storage vessels 

subject to the regulatory option. As shown in Table 7-7, the nationwide capital cost of 

Regulatory Option 2 (condensate storage vessels) was estimated to be $6.13 million and for 

Regulatory Option 3 (crude oil storage vessels) nationwide capital cost was estimated to be $13.6 

million. Total annual costs without fuel savings were estimated to be $1.87 million/yr for 

Regulatory Option 2 (condensate storage vessels) and $4.15 million/yr for Regulatory Option 3 

(crude oil storage vessels). Total annual costs with fuel savings were estimated to be $1.81 

million/yr for Regulatory Option 2 (condensate storage vessels) and $4.03 million/yr for 

Regulatory Option 3 (crude oil storage vessels). 

For purposes of evaluating the impact of a federal standard, impacts were determined for an 

average storage vessel by calculating the total VOC emissions from all storage vessels and 

dividing by the total number of impacted storage vessels (304) to obtain the average VOC 

emissions per storage vessel (103 tpy). Therefore, the nationwide annual costs were estimated to 

be $6.041 million/yr. A total nationwide VOC emission reduction of 29,746 tpy results in a cost 

effectiveness of $203/ton. 
8-1 

8.0 UPDATE TO TECHNICAL SUPPORT DOCUMENT FOR PROPOSED 

STANDARDS OF PERFORMANCE FOR CRUDE OIL AND NATURAL GAS 

PRODUCTION, TRANSMISSION, AND DISTRIBUTION – EQUIPMENT 

LEAKS 

8.1 INTRODUCTION 

On August 23, 2011, the U.S. Environment Protection Agency (EPA) proposed new source 

performance standards (NSPS) for new sources in the crude oil and natural gas production, 

processing, transmission, and distribution source category (40 CFR part 60, subpart OOOO). The 

NSPS includes standards for equipment leaks at natural gas processing plants under the authority 

of section 111 of the Clean Air Act (CAA). The public comment period closed on November 30, 

2011, and EPA received comments on the emission reductions and cost impacts associated with 

equipment leaks at natural gas processing plants. 

In response to these comments, we evaluated revisions to the equipment leak requirements in the 

proposed standards. The purpose of this memorandum is to present the results of the equipment 

leak cost analysis for the NSPS using emission factors and cost data from the Uniform Standards 

for Equipment Leaks rule (40 CFR part 65, subpart J) that EPA proposed on February 24, 2012. 

In addition to the emission factors and cost data, the methodology outlined in the supporting 

documentation for the Uniform Standards for Equipment Leaks46 was used to estimate emission 

reductions for this revised analysis. 

8.2 BACKGROUND 

Nationwide emissions for the proposed rule were calculated using the model plant approach for 

estimating emissions. Baseline model plant emissions for the gas production, processing, and 

transmission segments were calculated using average component counts47 for each of these 

segments. The emissions and emission reductions were calculated using emission factors and the 

control effectiveness methodology provided in the EPA equipment leak protocol48. Annual 

emissions were calculated assuming 8,760 hours of operation each year. The emissions factors 

were provided for total organic compounds (TOC) and included non-VOCs such as methane and 

ethane. The emission factors for the production and processing segments and the transmission 

segments that were used to estimate the new source emissions are available in Chapter 8 of the 

Technical Support Document49 (TSD) for the proposed rule. Emissions for VOC, hazardous air 

pollutants (HAP), and methane were calculated using TOC weight fractions also available in the 

TSD. 

 

46 Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, Analysis of Emission 

Reduction Techniques for Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180 47 GRI/EPA Research and Development, Methane Emissions From The Natural Gas Industry Volume 8: Equipment 

Leaks, June 1996. EPA-600/R-96-080h 

48 EPA, Protocol for Equipment Leak Emission Estimates, November 1995. EPA-453/R-95-017 

49 EPA, 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-HQ-OAR-2010-0505-0045 
8-2 

The current NSPS regulation (40 CFR part 60, subpart KKK) requires new and reconstructed 

natural gas processing facilities to comply with 40 CFR part 60 subpart VV standards to control 

emissions from equipment leaks. Equipment leaks are fugitive emissions emanating from 

valves, pump seals, flanges, compressor seals, pressure relief valves, open-ended lines, and other 

process and operation components. The standards require that the facility establish a leak 

detection and repair (LDAR) program to limit VOC emissions from pumps in light liquid 

service, compressors, pressure relief valves in gas/vapor service, sampling connection systems, 

valves in gas/vapor and light liquid service, pumps and valves in heavy liquid service, and 

pressure relief devices in light liquid or heavy liquid service and connectors. These equipment 

leaks are detected using a detection instrument which reads the airborne concentration of volatile 

organic carbons at a potential leak point on a parts per million (ppm) basis. If the leak exceeds 

the threshold definition of the applicable regulation, repair of the leaking equipment is required. 

Equipment leaks also may be defined on the basis of visual observation of certain types of 

equipment. For most components, subpart VV defines an equipment leak as a measured 

instrument reading of 10,000 ppm or greater. 

For the proposed subpart OOOO rule, the following regulatory options were considered for 

reducing equipment leaks from natural gas processing facilities: 

• Regulatory Option 1: Require the implementation of a subpart VVa LDAR program; 

• Regulatory Option 2: Require the implementation of a component subpart VVa LDAR 

program; 

• Regulatory Option 3: Require the implementation of the alternative work practice in 

§60.18 of 40 CFR Part 60; 

• Regulatory Option 4: Require the implementation of a modified alternative work practice 

in §60.18 of 40 CFR Part 60 that removes the requirement for annual monitoring using a 

Method 21 device. 

Based on a review of these options in the TSD, the implementation of a subpart VVa LDAR 

program was determined to be the best system of emission reduction (BSER) for equipment 

leaks at natural gas processing plants. The cost effectiveness of this regulatory option was 

calculated to be $3,352 per ton of volatile organic compounds (VOC). 

8.3 UNIFORM STANDARDS DATA AND METHODOLOGY 

Since proposal, EPA has gathered equipment leaks data and cost information for the 

development of the Uniform Standards for Equipment Leaks. We believe this data represents the 

most up-to-date information that is available for equipment leaks from the oil and gas sector. The 

Uniform Standards for Equipment Leaks memorandum identifies the baseline control option as a 

combination of LDAR program elements, equipment design standards, and performance 

standards. The baseline control option is equivalent to the subpart VV LDAR program and 

represents the same set of requirements that apply to natural gas processing plants under 40 CFR 

part 60, subpart KKK. 

The memorandum also provides emission factors and equipment leak frequency data for valve 

and connector control options. The leak frequency refers to the estimated percentage of 
8-3 

equipment that will be found leaking at a given leak definition. The leak frequencies were used 

to calculate both cost and emission estimates and were estimated using several sources including 

the Protocol for Equipment Leak Emissions Estimates and industry data. Emission factors are 

the estimated leak rates of an equipment type at a given leak definition and are normally given in 

kg/hr/piece of equipment. Two control options from the Uniform Standards memorandum were 

used to evaluate the proposed subpart OOOO LDAR program. The Valve 1 Option lowers the 

leak definition of Valves Gas/Light Liquid to 500 ppm, and the Connectors Option 1 adds 

instrument monitoring for Connectors Gas/Light Liquid at 500 ppm. These valve and connector 

options are equivalent to a subpart VVa LDAR program and the data from these options were 

used to evaluate this control option. The Uniform Standards memorandum assumes that the 

annual monitoring would not provide any additional emissions reductions from pressure relief 

devices or open-ended lines. 

Emission reductions were calculated from the baseline requirements. For this analysis, the leak 

frequency and emission factors from the Uniform Standards memorandum were used to calculate 

the emission reductions and costs. The Baseline data from these tables were used to calculate the 

subpart VV LDAR emissions and costs. The Valves Option 1 and Connectors Option 1 data 

were used to calculate the emissions and costs for the subpart VVa LDAR program. The initial 

and annual monitoring fees for each of the components were obtained from the Uniform 

Standards memorandum. The natural gas processing plant component counts were obtained 

from the GRI/EPA document50. A summary of the equipment leak frequencies used for this 

analysis are presented in Table 8-1. Tables 8-2 and 8-3 present the emission factors used for the 

LDAR analysis for each of the sectors. The Uniform Standards memorandum did not present an 

emission factor for pressure relief valves at the baseline level of control. Therefore, the pressure 

relief valve emission factors for subpart VV and VVa were assumed to be leaking at the rate of 

emissions below a 500 ppm leak definition using EPA leak rate curves.51 

Table 8-1. Summary of Equipment Leak Frequency Percent for Model Plants 

LDAR Programa Valves Connectors 

Baseline 1.18/1.18 NA 

Valves Option 1 5.95/1.91 NA 

Connectors Option 1 NA 1.70/0.81 

Data Source: Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, 

Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011, Table 5. 

a

 The leak frequencies provided in the tables are presented as initial leak frequency/subsequent leak 

frequency.

 

 

50 GRI/EPA Research and Development, Methane Emissions From The Natural Gas Industry Volume 8: Equipment 

Leaks, June 1996. EPA-600/R-96-080h 

51 EPA, Protocol for Equipment Leak Emission Estimates, November 1995. EPA-453/R-95-017 
8-4 

Table 8-2. Summary of VOC Equipment Leak Emission Factors for Production, 

Gathering & Boosting and Processing Model Plants 

Component 

Uncontrolled 

(kg/comp-hr) 

Baselinea 

(kg/comp-hr) 

Valve 

Option 1b 

(kg/comp-hr) 

Connector 

Option 1b 

(kg/comp-hr) 

Valves 3.71E-04 2.24E-04 8.85E-05 NA 

Connectors 1.04E-04 1.04E-04 NA 3.95E-05 

Open-Ended Lines 2.30E-03 7.34E-05 NA NA 

Pressure Relief Valves 1.60E-01 9.8E-02 NA NA 

Data Source: Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, 

Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011, Table 7. 

a

 The baseline option is assumed to be equivalent to a subpart V/VV LDAR program. 

b

 The valve and connector option 1 were assumed to be equivalent to a subpart VVa LDAR program.

Table 8-3. Summary of Methane Equipment Leak Emission Factors for 

Transmission and Storage Model Plants 

Component 

Uncontrolleda

(Ton/comp-yr) 

V/VVb

(Ton/comp-yr) 

VVab

(Ton/comp-yr) 

Valves 0.0496 0.0300 0.0118 

Connectors 0.0084 0.0084 0.0032 

Open-Ended Lines 0.6408 0.0205 0.0205 

Pressure Relief Valves 0.3547 0.2171 0.2171 

Data Source: GRI/EPA Research and Development, Methane Emissions From The Natural Gas Industry 

Volume 8: Equipment Leaks, June 1996, Tables 4-17 (Transmission) and 4-24 (Storage). a

 The uncontrolled volumetric methane emission factors were converted to a mass based emission factors 

assuming that methane is an ideal gas. 

b

 The emission factors for the V/VV and VVa LDAR options were calculated assuming the same 

emission reductions in Table 2 for each of the LDAR options.

The monitoring costs for LDAR programs were based on the following assumptions: 

• Initial monitoring and setup costs are $23.80 for valves, $1.10 per connector, $122 for 

pressure relief valve disks, $6,374 for pressure relief valve disk holder and valves, and 

$141 for open-ended lines. 

• Subsequent monitoring costs are $1.50 for valves, $2.50 for connectors, $2.00 for 

pressure relief valve disks, and $5.00 for pressure relief valve devices and open-ended 

lines. 

• A wage rate of $66.24 per hour was used to determine labor costs for repair. 
8-5 

• Administrative costs and initial planning and training costs are based on 320 hours for 

planning and training and 250 hours per year for reporting and administrative tasks at 

$92.72 per hour. 

• The capital cost for purchasing a TVA or OVA monitoring system was estimated to be 

$10,800 and $14,500 for a data collection system. 

8.3 RESULTS 

In the proposed rule, it was determined that only processing plants were cost effective to control 

emissions of VOC. However, since a new methodology was being used to calculate emission 

reductions from processing plants, we decided to re-evaluate the LDAR options for each of the 

oil and natural gas segments. The production, gathering and boosting, transmission and storage 

segments were evaluated for the subpart VV and subpart VVa options from their current 

uncontrolled baseline. 

Table 8-4 provides a summary of the VOC cost effectiveness of going from uncontrolled 

emission level to a subpart VV or subpart VVa LDAR program for the production, gathering and 

boosting, transmission, and storage segments. For processing plants the table provides the 

incremental cost effectiveness of going from a subpart VV to a subpart VVa LDAR program. 

The average VOC cost effectiveness of the production pads were calculated to be $7,964 per ton 

of VOC reduced for the subpart VV LDAR option and $7,379 per ton of VOC reduced for the 

subpart VVa LDAR option. For gathering and boosting stations, the average VOC cost 

effectiveness were calculated to be $4,265 per ton of VOC reduced for the subpart VV LDAR 

option and $4,131 per ton of VOC reduced for the subpart VVa LDAR option. The average 

VOC cost effectiveness of the transmission and storage segments were calculated to be $112,127 

and $27,201 per ton of VOC reduced, respectively, for the subpart VV LDAR option and 

$57,144 and 23,819 per ton of VOC reduced, respectively, for the subpart VVa LDAR option. 

The incremental VOC cost effectiveness for processing plants was calculated to be $2,691 per 

ton of VOC reduced. The incremental emission reductions from going from a subpart VV to a 

subpart VVa LDAR program is estimated to be 4.56 tons per year of VOC. In addition, 0.172 

tons per year of HAP, and 16.4 tons per year of methane will also be removed. Appendix C 

provides a summary of the emissions calculations using the subpart VV and VVa emission 

factors from the Uniform Standards document, and a summary of the capital and annual costs of 

implementing the subpart VV and subpart VVa LDAR programs using cost data from the 

Uniform Standards memorandum. These results will be used to calculate the regulatory impacts 

of requiring a subpart VVa LDAR program in the final subpart OOOO rule. 

 
8-6 

Table 8-4. Summary of VOC Cost Effectiveness of the LDAR 

Options for each of the Oil and Natural Gas Segments 

LDAR Option 

Total Capital 

Investment 

Annual LDAR 

Cost ($/yr) 

VOC Emission 

Reduction 

(Ton/yr) 

VOC Cost 

Effectiveness 

($/Ton of VOC) 

Well Pads 

V/VV $101,100 $55,365 6.95 $7,964 

VVa $102,543 $57,534 7.80 $7,379 

Gathering & Boosting 

V/VV $374,334 $135,821 31.8 $4,265 

VVa $379,571 $143,807 34.8 $4,131 

Processinga

VVa $8,041 $12,261 4.56 $2,691 

Transmission 

V/VV $151,669 $78,728 0.702 $112,127 

VVa $156,332 $85,601 1.50 $57,144 

Storage 

V/VV $571,841 $206,513 7.59 $27,201 

VVa $582,574 $222,970 9.36 $23,819 

a

 Processing plants are already required to do a subpart VV LDAR program under subpart KKK. The 

costs and emissions from this sector are the incremental costs from going from a subpart VV to a subpart 

VVa LDAR program. 
Oil and Natural Gas Sector: Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission, and 

Distribution. 

Background Supplemental Technical Support Document for the 

Final New Source Performance Standards 

Appendices 
A-1 

APPENDIX A: SUPPLEMENTARY DATA FOR THE EVALUTION OF THE 

EMISSION FACTOR FOR HYDRAULICALLY FRACTURED GAS WELL 

COMPLETIONS AND RECOMPLETIONS 

A.1 Industry Data Set #1

This section contains Industry Data Set #1. This data set includes vertical gas wells drilled 

before 2004, that were in tight sand and hydraulically fractured and were used to assist in 

development of the Reduced Emissions Completions Lessons Learned study. This data set was 

used in developing the first depiction of national methane emissions potential from hydraulic 

fracturing completion, presented in a Gas STAR workshop September 21, 2004. 

The data set is provided in the below table. Each row contains one well completion at a well 

with hydraulic fracture. The columns report the total gas flared during the completion event, the 

total gas sold (recovered by reduced emissions completion methods into the flow line), and the 

sum of the flared and sold volumes which represents the total gas produced by the well during 

the completion event. 

At the bottom of the table are the sums for the total completions, total gas flared, total gas sold, 

and total gas produced. The sums are then used to calculate an average emissions factor. 

Well Completion 

Number 

Flared Gas 

(Mcf) Gas Sold (Mcf) 

TOTAL Mcf 

PRODUCED 

PER 

COMPLETION 

1 878 6,919 7,797 

2 3,293 8,638 11,931 

3 3,348 2,386 5,734 

4 1,670 2,339 4,009 

5 7,095 800 7,895 

6 2,884 11,549 14,433 

7 1,553 4,503 6,056 

8 4,005 169 4,174 

9 6,614 363 6,977 

10 2,536 3,377 5,913 

11 2,043 5,203 7,246 

12 1,010 3,792 4,802 

13 3,586 149 3,735 

14 12,659 4,692 17,351 

15 4,307 970 5,277 

16 4,053 1,105 5,158 

17 3,987 12,058 16,045 

18 1,320 964 2,284 

19 1,576 2,133 3,709 

20 2,752 3,903 6,655 

21 4,063 2,629 6,692 

22 5,591 12,652 18,243 
A-2 

23 2,550 3,696 6,246 

24 1,057 7,429 8,486 

25 2,206 9,085 11,291 

26 1,274 6,832 8,106 

27 4,333 6,558 10,891 

28 4,626 941 5,567 

29 1,091 23 1,114 

30 861 278 1,139 

31 324 7 331 

32 774 1,197 1,971 

33 1,503 4,489 5,992 

34 6,525 7,398 13,923 

35 1,125 2,027 3,152 

36 1,894 1,723 3,617 

37 1,398 4,876 6,274 

38 2,104 11,331 13,435 

39 1,149 3,641 4,790 

40 803 420 1,223 

41 2,619 445 3,064 

42 889 2,532 3,421 

43 153 0 153 

44 1,749 3,986 5,735 

45 1,450 1,248 2,698 

46 807 277 1,084 

47 1,833 0 1,833 

48 1,577 3,508 5,085 

49 1,219 1,552 2,771 

50 1,557 4,444 6,001 

51 1,880 5,795 7,675 

52 2,501 4,096 6,597 

53 5,698 211 5,909 

54 2,355 1,922 4,277 

55 971 2,034 3,005 

56 6,213 159 6,372 

57 2,599 2,592 5,191 

58 1,502 8,212 9,714 

59 2,219 931 3,150 

60 6,114 1,925 8,039 

61 1,020 740 1,760 

62 594 2,727 3,321 

63 2,189 5,840 8,029 

64 1,350 1,528 2,878 

65 0 0 0 

66 2,674 3,872 6,546 

67 2,424 3,352 5,776 

68 941 3,639 4,580 
A-3 

69 1,126 4,683 5,809 

70 1,264 2,117 3,381 

71 1,833 1,953 3,786 

72 1,513 4,940 6,453 

73 9,157 9,568 18,725 

74 3,026 7,770 10,796 

75 3,026 501 3,527 

76 16,849 5,802 22,651 

77 1,768 2,137 3,905 

78 9,234 1,027 10,261 

79 2,191 4,017 6,208 

80 0 0 0 

81 5,300 1,260 6,560 

82 1,694 2,022 3,716 

83 673 1,234 1,907 

84 313 2,651 2,964 

85 0 0 0 

86 3,883 5,211 9,094 

87 1,800 4,296 6,096 

88 1,468 3,237 4,705 

89 2,946 8,984 11,930 

90 1,059 1,715 2,774 

91 2,381 5,754 8,135 

92 882 658 1,540 

93 255 1,933 2,188 

94 742 2,356 3,098 

95 889 0 889 

96 844 3,606 4,450 

97 1,052 2,863 3,915 

98 1,006 581 1,587 

99 502 723 1,225 

100 3,470 3,079 6,549 

101 2,529 5,688 8,217 

102 4,725 3,283 8,008 

103 523 1,203 1,726 

104 2,469 5,548 8,017 

105 602 1,571 2,173 

106 812 4,782 5,594 

Total Well 

Completions 

Total Flared Gas 

(Mcf) 

Total Gas Sold 

(Mcf) 

Total Produced 

Gas 

(Mcf) 

106 267,323 349,564 616,887 

EF Calculation: 
A-4 

completion

Mcf

completions

Mcf 5,820

106

616,887 =
B-1 

APPENDIX B: SUPPLEMENTARY ANALYSES FOR LOW PRESSURE COMPLETION 

THRESHOLD 

B.1 Derivation of Density from the Ideal Gas Law 

This appendix shows how this analysis determines the density of natural gas as a function of the 

temperature and pressure using the ideal gas law. 

Ideal Gas Law

PV = nRT (Eq. B.1-1) 

Step 1 – Multiply both side by the molecular weight MW 

() () MW PV = nRT MW (Eq. B.1-2) 

Step 2 – Divide both sides by the volume 

( ) ( )

V

nRT MW

V

MW PV = (Eq. B.1-3) 

Step 3 – The volumes on the left hand side cancel.

( ) ( )

V

nRT MW P MW = (Eq. B.1-4) 

Step 4 – Knowing n(MW) is equal to the mass of the ideal gas, substitute m for n(MW) 

( ) V

mRT P MW = (Eq. B.1-5) 

Step 5 – Knowing m/V is equal to the density of ideal gas, substitute ρ for m/V 

P( ) MW = ρRT (Eq. B.1-6) 

Step 6 – Solve for ρ

( )

RT

P MW

ρ = (Eq. B.1-7) 

Nomenclature 

P = pressure of the ideal gas (Pa) 

V = volume of the ideal gas (m3

) 

R = ideal gas constant, 8.314 m3

Pa mol-1K-1 
B-2 

T = temperature of the ideal gas (K) 

n = moles of the ideal gas (moles) 

m = mass of the ideal gas (g) 

MW = molecular weight of the ideal gas (g/mol) 

ρ = density of the ideal gas (g/m3

) 
B-3 

B.2 Water Film Impact on Inner Tubing Diameter 

This appendix shows the steps taken to determine the extent to which water plated on the tubing 

wall restricts the cross sectional area of the tubing that is available for gas flow. The purpose of 

the appendix is to show that the restriction in cross sectional area is negligible, which in turn has 

a negligible effect on the change in flow velocity. The appendix calculates the thickness of a film 

of water deposited along the walls of a well tubing based on the percent of water by volume in 

the tubing. Since water is expected to adhere to the walls of the tubing, this analysis assumes that 

the largest film thickness occurs where all the water in the tubing is plating on the inner tubing 

wall rather than remaining in the bulk flow. The following equations determine the thickness of 

this film of water on the inner tubing wall. 

Step 1a ்ܸ ൌ ܸௐ ൅ ܸீ (Eq. B.2-1a) 

Step 1b ݂௅ ൌ ܸௐ

்ܸ

ൌ ܸௐ

ܸௐ ൅ ܸீ

(Eq. B.2-1b) 

Step 1c ܸௐ ൌ ݂௅ܸீ

1 െ ݂௅

(Eq. B.2-1c) 

Step 2 ்ܸ ൌ ൬ ݂௅

1 െ ݂௅

൰ ܸீ ൅ ܸீ (Eq. B.2-2) 

்ܦߨ 3 Step

ଶ

4 ൌ ൬1 ൅ ݂௅1 െ ݂௅

൰

ீܦߨ

ଶ

4 (Eq. B.2-3) 

்ܦ 4 Step

ଶ ൌ ൬ 1

1 െ ݂௅

ீܦ൰

ଶ (Eq. B.2-4) 

Step 5 ܦீ ൌ ටܦ்

ଶሺ1 െ ݂௅ሻ (Eq. B.2-5) 

Step 6 ߜ௪௔௧௘௥ ൌ ܦ் െ ܦீ

2 (Eq. B.2-6) 

Step 7 ߜ௪௔௧௘௥ ൌ

்ܦට െ ்ܦ

ଶሺ1 െ ݂௅ሻ

2

(Eq. B.2-7) 

Step 8 ߜ௪௔௧௘௥ ൌ 2.875 െ ඥ2.875ଶሺ1 െ 0.05ሻ

2 ൌ 0.036 ݅݊. (Eq. B.2-8) 
B-4 

Step 9 

2ߜ௪௔௧௘௥

்ܦ

ൈ 100 ൌ 2.5% (Eq. B.2-9) 

According to the result from Step 8, given the volume of water in the tubing is 5 percent of the 

total volume the thickness of the film of water is about 0.035 inches. Therefore, as shown in 

Step 9, above, the percent of the inner tubing diameter that is displaced by the film of water is 

about 2.5%. 

Nomenclature 

VW = total volume of water in tubing, cubic inches 

VG = total volume of gas in tubing, cubic inches 

VT = total volume of tubing, cubic inches 

DT = inner diameter of the tubing, in inches 

DG = diameter of the gas in tubing, in inches

fL = fraction of water-sand mixture in fluid, by volume, in flowback fluid, unitless

δwater = thickness of water film along tubing wall, in inches 
B-5 

B.3 Determination of Turbulent Flow 

This analysis assumes that gas wells are in turbulent flow during steady vapor flow condition of 

a flowback following a hydraulic fracture. The Reynolds number is defined as the ratio of fluid 

momentum force to viscous shear force and shown in Equation C-1 below. The Reynolds 

number can be used as a parameter to distinguish between laminar and turbulent fluid flow. 

ܰோ௘ ൌ ߩݑܦ

ߤ) Eq. B.3-1) 

where, 

NRe = Reynolds Number 

D = inner diameter of tubing, in meters 

ρ = fluid density, in kilograms per cubic meter 

μ = fluid viscosity, Pascal-seconds

The change from laminar to turbulent flow occurs at a Reynolds numbers around 2,100 for flow 

in a circular pipe. By inspection of a friction factor versus Reynolds number diagram52, for 

circular pipes, the Reynolds number needs to be above 104 for the flow to be in the turbulent 

regime. 

To prove the Reynolds number falls in the turbulent regime for most gas wells, the Reynolds 

number was calculated for a range of flowing pressures and velocities assuming a conservatively 

constant diameter and gas viscosity. Appendix B.1 shows that the gas density is calculated as a 

function of the molecular weight, temperature, pressure, and the compressibility factor. 

Therefore, the density is calculated assuming the temperature of the gas is 200 °F, the molecular 

weight is 0.016 kilograms per mole, and calculating the compressibility factor using the BrillBeggs correlation. The gas viscosity is also a function of the pressure and temperature, and it is 

calculated using the Carr, Kobayashi, and Burrows correlation from the Natural Gas 

Engineering Handbook53. The tubing diameter was assumed to be 2.875 inches, which is equal to 

0.073 meters. The resulting Reynolds numbers are shown in Table B.3-1 below. The pressures 

and velocities in Table B.3-1 were selected because they fall within a range of the conditions 

experienced by gas wells during hydraulic completion flowback. 

Table B.3-1. Reynolds Numbers for Various Gas Velocities and Pressures 

P (psia) u (ft/s) NRe

500 10 3.043E+05

1000 20 1.174E+06

1500 10 8.463E+05

2000 20 2.159E+06

2500 10 1.284E+06

 

52 Perry, R.H. (1963). Perry's Chemical Engineers' Handbook (4th Edition). McGraw-Hill. pg. 5-20. 53 Guo, B. Ghalambor, A. (2005) Natural Gas Engineering Handbook.Gulf Publishing Company. pg. 17 
B-6 

3000 20 2.913E+06

3500 10 1.596E+06

4000 20 3.410E+06

4500 10 1.784E+06

5000 20 3.675E+06

All the Reynolds numbers in Table B.3-1 are well above the region for laminar flow indicating 

that for natural gas pressures and velocities common in gas wells turbulent flow is most often the 

case. 

 
B-7 

B.4 Alternative Method for Calculating the Compressibility Factor for Natural Gas 

For further comparison, this appendix tests the accuracy of the Brill-Beggs correlation chosen for 

this pressure model using another method to estimate the compressibility factor. This method 

uses a correlation developed by Pitzer and others54 for the second virial coefficient B in a 

common form of the truncated equation of state shown below: 

ܼൌ1൅ ஻௉

ோ்

ൌ1൅ܤሶ

௉ೝ

்ೝ

 (Eq. B.4-1)

Where ܤሶ

 is a reduced second virial coefficient given by ܤሶ ൌ ܤܲ௖/ܴܶ௖. Pitzer proposed a 

correlation to yield values for ܤሶ

: 

ܤሶ ൌ ܤ ൅ ଴ܤݓଵ (Eq. B.4-2)

B0

 and B1 are approximate values that are functions of reduced temperature only. Therefore, by 

combining Equations D-1 and D-2 above, the equation used to estimate the compressibility 

factor for comparison to Brill-Beggs was: 

ೝ௉ ଴ܤ൅1ൌܼ

்ೝ

ೝ௉ ଵܤݓ ൅

்ೝ

 (Eq. B.4-3)

where: 

ܤ ଴ൌ 0.083 െ ଴.ସଶଶ

்ೝ

భ.ల

 (Eq. B.4-4) 

ܤଵ ൌ 0.139 െ ଴.ଵ଻ଶ

்ೝ

ర.మ

 (Eq. B.4-5)

The equations for B0

 and B1, along with the accentric factor w, represent an approximation of the 

reduced second virial coefficient ܤሶ

. Using the reduced temperature (which was assumed constant 

throughout the well), reduced pressure (calculated incrementally using the pressure at each well 

depth), and the accentric factor for methane, a compressibility factor was calculated for each 

segment of the vertical well. This allowed for a side-by-side comparison of the compressibility 

factor at each well depth using both the Brill-Beggs method and Pitzer correlation. The two 

methods showed agreement for lower pressures between 500 and 2000 pound per square inch. 

Table D-1 below compares the compressibility factors for the Brill-Beggs correlation used in this 

analysis and the Pitzer compressibility factor correlation. 

Table B.4-1. Compressibility Factor for Various Pressures at 200°F 

P (psia) Compressibility 

Factor (Brill-Beggs) 

Compressibility 

Factor (Pitzer) 

500 0.98 0.98 

1000 0.96 0.96 

1500 0.95 0.94 

 

54 J.M. Smith, H.C. Van Ness, M.M. Abbott. (2005). Introduction to Chemical Engineering Thermodynamics. 

McGraw-Hill. 
B-8 

2000 0.94 0.92 

2500 0.94 0.90 

3000 0.94 0.87 

3500 0.95 0.85 

4000 0.96 0.83 

4500 0.98 0.81 

5000 1.01 0.79 

The Pitzer correlation for the second virial coefficient was chosen because of its relative 

simplicity as a quick method to validate the calculations of the more involved Brill-Beggs 

method. However, it is worth noting that this correlation only estimates the properties of pure 

gases. Thus, pure methane was assumed in this analysis because natural gas primarily consists of 

methane. In addition, this simplest form of the virial equation has validity at low to moderate 

pressures where the compressibility factor is linear in pressure, which explains the increase in 

disagreement between the compressibility factors at higher pressures. 
C-1 

APPENDIX C: COST AND EMISSION SPREADSHEETS OF THE LDAR ANALYSE

The tables in this appendix provide a summary of the emissions calculations using the subpart VV and VVa emisUniform Standards document, and a summary of the capital and annual costs of implementing the subpart VV anLDAR programs using cost data from the Uniform Standards memorandum. 
C-2 

Summary of Cost Effectiveness of the Subpart VV and Subpart VVa LDAR Programs for Well Pads

Average Model Plant Cost Effectiveness Summary for Well Pads w/o Recovery Credits

Model Plant

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/o

Recovery

Credits ($/yr)

Total CH4Emissions

(Tons/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emissions

(Tons/yr)

Total VOC

Emission

Reductions

VOC Cost

Effectiveness

($/Ton)

T

E

(

Model Plant 1 (Based on 1‐Wellhead)

Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 0.330 ‐‐‐‐‐ ‐‐‐‐‐ 0.0916 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $25,704 $32,169 $32,169 0.206 0.123 $260,914 0.0573 0.0343 $938,538 VVa $25,762 $32,258 $32,258 0.0810 0.249 $129,786 0.0225 0.0691 $466,856 

Model Plant 2 (Based on 5 Wellheads)

Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 64.04 ‐‐‐‐‐ ‐‐‐‐‐ 17.80 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $101,100 $55,365 $55,365 39.03 25.01 $2,214 10.85 6.95 $7,964 VVa $102,543 $57,534 $57,534 35.99 28.05 $2,051 10.01 7.80 $7,379 Model Plant 3 (Based on 48 Wellheads)

Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 672 ‐‐‐‐‐ ‐‐‐‐‐ 187 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $820,109 $278,139 $278,139 410 262.1 $1,061 114 72.86 $3,818 VVa $835,227 $300,812 $300,812 378 294.0 $1,023 105 81.7 $3,681 

1 Annual LDAR includes no recovery credits.

Average Model Plant Cost Effectiveness Summary for Well Pads w/ Recovery Credits

Model Plant

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/

Recovery

Credits ($/yr)

Total CH4Emissions

(Tons/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emissions

(Tons/yr)

Total VOC

Emission

Reductions

VOC Cost

Effectiveness

($/Ton)

T

E

(

Model Plant 1 (Based on 1‐Wellhead)

Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 0.330 ‐‐‐‐‐ ‐‐‐‐‐ 0.0916 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $25,704 $32,169 $29 $32,141 0.206 0.123 $260,682 0.0573 0.0343 $937,704 VVa $25,762 $32,258 $58 $32,201 0.0810 0.249 $129,554 0.0225 0.0691 $466,022 

Model Plant 2 (Based on 5 Wellheads)

Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 64.04 ‐‐‐‐‐ ‐‐‐‐‐ 17.80 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $101,100 $55,365 $5,797 $49,569 39.03 25.01 $1,982 10.85 6.952 $7,130 VVa $102,543 $57,534 $6,501 $51,033 35.99 28.05 $1,820 10.01 7.797 $6,545 Model Plant 3 (Based on 48 Wellheads)

Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 672 ‐‐‐‐‐ ‐‐‐‐‐ 187 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $820,109 $278,139 $60,750 $217,388 410 262.1 $830 114 72.86 $2,984 VVa $835,227 $300,812 $68,143 $232,669 378 294.0 $791 105 81.7 $2,847 

1 Recovery credits calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf.
C-3 

Well Pad Emission Summary

Model Plant 1 ‐ Single Wellhead

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connectors

Open‐

Lin

Uncontrolled 9 37 1 0 0.032 0.037 0.022 0.000 0.092 0.001 0.001 

V 9 37 1 0 0.019 0.037 0.001 0.000 0.057 0.034 0.001 0.001 

VV 9 37 1 0 0.019 0.037 0.001 0.000 0.057 0.034 0.001 0.001 

VVa 9 37 1 0 0.008 0.014 0.001 0.000 0.023 0.069 0.000 0.001 

Model Plant 2 ‐ Five Wellheads

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connectors

Open‐

Lin

Uncontrolled 235 863 29 10 0.842 0.867 0.644 15.450 17.803 0.032 0.033 

V 235 863 29 10 0.508 0.867 0.021 9.455 10.851 6.952 1.92E‐02 3.27E‐02 7

VV 235 863 29 10 0.508 0.867 0.021 9.455 10.851 6.952 1.92E‐02 3.27E‐02 7

VVa 235 863 29 10 0.201 0.329 0.021 9.455 10.006 7.797 7.57E‐03 1.24E‐02 7

Model Plant 3

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connectors

Open‐

Lin

Uncontrolled 2,454 9,080 299 105 8.791 9.119 6.641 162.226 186.776 0.331 0.344 

V 2,454 9,080 299 105 5.308 9.119 0.212 99.282 113.921 72.856 0.200 0.344 

VV 2,454 9,080 299 105 5.308 9.119 0.212 99.282 113.921 72.856 0.200 0.344 

VVa 2,454 9,080 299 105 2.097 3.463 0.212 99.282 105.055 81.722 0.079 0.131 

VOC Emission Factors

Uncontrolled(kg/hr/comp)

V

_

VV

(kg/hr/comp)

VVa

(kg/hr/comp)

Valves 0.000371 0.000224 0.0000885Connectors 0.000104 0.000104 0.0000395OEL 0.0023 0.0000734 0.0000734PRV 0.16 0.09792 0.09792Emission factors obtained from Memorandum from Cindy Hancy, RTI to Jodi Howard, EPA, Analysis of Emisson Reduction Techniques for Equipment Leaks, December 21, 2011. [EPA‐HQ‐OAR‐2002‐0037‐01

Monitoring

Model Plant Component Count VOC Emissions (Tons/yr) HAP E

Monitoring

Model Plant Component Count VOC Emissions (Tons/yr) HAP E

Monitoring

Model Plant Component Count VOC Emissions (Tons/yr) HAP E
C-4 

Well Pad Model Plant 2

Subpart V

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 235 23.80 5799.69 12 1.50 4230.00 0.0118 2.77 1.18 33.28 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 863 1.10 949.30

Pressure Relief Devices

* Disks 10 122.11 1221.10 0 2.00 0.00 25.00 

* Disk holders, valves,etc. 10 6374.29 63742.90 5.00 3200.00 

Open‐Ended Lines 29 140.92 4086.68 5.00 203.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 1137

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $101,100 $29,670 $4,230 $3,428 $132.74 

Capi tal Costs $101,100

Annualized Capi tal Costs $19,428

Annual Expenses $35,937

Annual Fixed Costs ($/yr) $45,370

Annual Variable Costs ($/yr) $9,995

Total Annual Costs ($/yr) $55,365

Well Pad Model Plant 2

Controlled ‐ Subpart VVa

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 235 23.80 6635.21 12 1.50 4230.00 0.0595 13.98 1.91 53.86 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 863 1.10 1556.92 0.25 2.50 539.38 0.0170 14.67 0.81 1.75 75 0.17 66.24 2.77 25 2.00 

Pressure Relief Devices

* Disks 10 122.11 1221.10 0 2.00 0.00 25.00 

* Disk holders, valves,etc. 10 6374.29 63742.90 5.00 3200.00 

Open‐Ended Lines 29 140.92 4086.68 5.00 203.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 1137

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $102,543 $29,670 $4,769 $3,428 $135.51 

Capi tal Costs $102,543

Annualized Capi tal Costs $19,633

Annual Expenses $37,901

Annual Fixed Costs ($/yr) $45,575

Annual Variable Costs ($/yr) $11,959

Total Annual Costs ($/yr) $57,534
C-5 

Summary of Cost Effectiveness of the Subpart VV and Subpart VVa LDAR Programs for Gathering & Bo

Average Model Plant Cost Effectiveness Summary for Gathering & Boosting Stations w/o Recovery Credits

Model Plant

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/o

Recovery

Credits ($/yr)

Total CH4Emissions

(Tons/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emissions

(Tons/yr)

Total VOC

Emission

Reductions

VOC Cost

Effectiveness

($/Ton)

T

E

(

Model Plant 1Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 179 ‐‐‐‐‐ ‐‐‐‐‐ 49.6 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $236,278 $94,682 $94,682 109 69.3 $1,367 30.4 19.26 $4,917 VVa $239,435 $99,500 $99,500 103 75.7 $1,314 28.6 21.05 $4,728 Model Plant 2Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 295 ‐‐‐‐‐ ‐‐‐‐‐ 82.1 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $374,334 $135,821 $135,821 181 114.5 $1,186 50.3 31.84 $4,265 VVa $379,571 $143,807 $143,807 170 125.2 $1,148 47.3 34.81 $4,131 Model Plant 3Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 412 ‐‐‐‐‐ ‐‐‐‐‐ 115 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $512,390 $176,960 $176,960 252 159.8 $1,107 70 44.43 $3,983 VVa $519,707 $188,114 $188,114 238 174.8 $1,076 66 48.58 $3,872 

1 Annual LDAR includes no recovery credits.

Average Model Plant Cost Effectiveness Summary for Gathering & Boosting Stations w/ Recovery Credits

Model Plant

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/

Recovery

Credits ($/yr)

Total CH4Emissions

(Tons/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emissions

(Tons/yr)

Total VOC

Emission

Reductions

VOC Cost

Effectiveness

($/Ton)

T

E

(

Model Plant 1Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 179 ‐‐‐‐‐ ‐‐‐‐‐ 49.6 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $236,278 $94,682 $16,058 $78,625 109 69.27 $1,135 30.4 19.26 $4,083 VVa $239,435 $99,500 $17,549 $81,951 103 75.7 $1,082 28.6 21.05 $3,894 Model Plant 2Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 295 ‐‐‐‐‐ ‐‐‐‐‐ 82.1 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $374,334 $135,821 $26,554 $109,268 181 114.5 $954 50.3 31.84 $3,431 VVa $379,571 $143,807 $29,030 $114,778 170 125.2 $917 47.3 34.81 $3,297 Model Plant 3Baseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 412 ‐‐‐‐‐ ‐‐‐‐‐ 115 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $512,390 $176,960 $37,050 $139,911 252 159.8 $875 70 44.43 $3,149 VVa $519,707 $188,114 $40,510 $147,605 238 174.8 $845 66 48.58 $3,038 

1 Recovery credits calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf.
C-6 

Gathering Station Emission Summary

Model Plant 1

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connectors

Open‐

Lin

Uncontrolled 547 1,723 51 29 1.960 1.730 1.133 44.805 49.628 0.074 0.065 

V 547 1,723 51 29 1.183 1.730 0.036 27.421 30.370 19.257 0.045 0.065 

VV 547 1,723 51 29 1.183 1.730 0.036 27.421 30.370 19.257 0.045 0.065 

VVa 547 1,723 51 29 0.467 0.657 0.036 27.421 28.582 21.046 0.018 0.025 

Model Plant 2

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connectors

Open‐

Lin

Uncontrolled 906 2,864 83 48 3.246 2.876 1.843 74.160 82.126 0.122 0.108 

V 906 2,864 83 48 1.960 2.876 0.059 45.386 50.281 31.845 0.074 0.108 

VV 906 2,864 83 48 1.960 2.876 0.059 45.386 50.281 31.845 0.074 0.108 

VVa 906 2,864 83 48 0.774 1.092 0.059 45.386 47.312 34.814 0.029 0.041 

Model Plant 3

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connectors

Open‐

Lin

Uncontrolled 1,265 4,005 115 67 4.532 4.022 2.554 103.516 114.623 0.171 0.152 

V 1,265 4,005 115 67 2.736 4.022 0.082 63.351 70.191 44.432 0.103 0.152 

VV 1,265 4,005 115 67 2.736 4.022 0.082 63.351 70.191 44.432 0.103 0.152 

VVa 1,265 4,005 115 67 1.081 1.528 0.082 63.351 66.042 48.582 0.041 0.058 

VOC Emission Factors

Uncontrolled(kg/hr/comp)

V

_

VV

(kg/hr/comp)

VVa

(kg/hr/comp)

Valves 0.000371 0.000224 0.0000885Connectors 0.000104 0.000104 0.0000395OEL 0.0023 0.0000734 0.0000734PRV 0.16 0.09792 0.09792Emission factors obtained from Memorandum from Cindy Hancy, RTI to Jodi Howard, EPA, Analysis of Emisson Reduction Techniques for Equipment Leaks, December 21, 2011. [EPA‐HQ‐OAR‐2002‐0037‐01

Monitoring

Model Plant Component Count VOC Emissions (Tons/yr) HAP E

Monitoring

Model Plant Component Count VOC Emissions (Tons/yr) HAP E

Monitoring

Model Plant Component Count VOC Emissions (Tons/yr) HAP E
C-7 

Gathering & Boosting Model Plant 2

Subpart V

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 906 23.80 22359.66 12 1.50 16308.00 0.0118 10.69 1.18 128.29 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 2864 1.10 3150.40

Pressure Relief Devices

* Disks 48 122.11 5861.28 0 2.00 0.00 120.00 

* Disk holders, valves,etc. 48 6374.29 305965.92 5.00 15360.00 

Open‐Ended Lines 83 140.92 11696.36 5.00 581.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 3901

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $374,334 $29,670 $16,308 $16,061 $132.74 

Capi tal Costs $374,334

Annualized Capi tal Costs $58,701

Annual Expenses $77,121

Annual Fixed Costs ($/yr) $94,822

Annual Variable Costs ($/yr) $41,000

Total Annual Costs ($/yr) $135,821

Gathering & Boosting Model Plant 2

Controlled ‐ Subpart VVa

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 906 23.80 25580.84 12 1.50 16308.00 0.0595 53.91 1.91 207.66 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 2864 1.10 5166.89 0.25 2.50 1790.00 0.0170 48.69 0.81 5.80 75 0.17 66.24 2.77 25 2.00 

Pressure Relief Devices

* Disks 48 122.11 5861.28 0 2.00 0.00 120.00 

* Disk holders, valves,etc. 48 6374.29 305965.92 5.00 15360.00 

Open‐Ended Lines 83 140.92 11696.36 5.00 581.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 3901

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $379,571 $29,670 $18,098 $16,061 $135.51 

Capi tal Costs $379,571

Annualized Capi tal Costs $59,445

Annual Expenses $84,363

Annual Fixed Costs ($/yr) $95,566

Annual Variable Costs ($/yr) $48,242

Total Annual Costs ($/yr) $143,807
C-8 

Summary of the Incremental Cost Effectiveness of the Subpart VVa LDAR Programs for Processing Plan

Processing Plant Cost Effectiveness SummaryLDAR Programs

LDAR Program

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/o

Recovery

Credits ($/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emission

Reductions

VOC Cos

Effectivene

($/Ton)

Subpart VVa $8,041 $12,261 $12,261 16.4 $748 4.56 $2,

LDAR Program

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/

Recovery

Credits ($/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emission

Reductions

VOC Cos

Effectivene

($/Ton)

Subpart VVa $8,041 $12,261 $3,800 $8,462 16.4 $516 4.56 $1,

1 Recovery credits calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf.

Cost Effectiveness w/o Recovery 

Cost Effectiveness w/ Recovery 
C-9 

Natural Gas Processing Plant Emission Summary

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total CH4Emissions Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions Valves 

VV 1,392 4,392 134 29 10.8 15.9 0.3 98.6 125.7 3.01 4.41 0.095 27.42 34.9 0.114 

VVa 1,392 4,392 134 29 4.3 6.0 0.3 98.6 109.3 1.19 1.68 0.095 27.42 30.4 0.045 

VOC Emission Factors

VV

(kg/hr/comp)

VVa

(kg/hr/comp)

Valves 0.000224 0.0000885Connectors 0.000104 0.0000395OEL 0.0000734 0.0000734PRV 0.09792 0.09792

Monitoring

Model Plant Component Count Methane Emissions (Tons/yr) VOC Emissions (Tons/yr) 
C-10 

Processing Model PlantBaseline ‐ Subpart VV

Type of Component

Number of

Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 1,392 23.80 34353.91 12 1.50 25056.00 0.0118 16.43 1.18 197.11 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 4392 1.10 4831.20

Pressure Relief Devices

* Disks 29 122.11 3541.19 0 2.00 0.00 72.50 

* Disk holders, valves,etc. 29 6374.29 184854.41 5.00 9280.00 

Open‐Ended Lines 134 140.92 18883.28 5.00 938.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 5947

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $271,764 $29,670 $25,056 $10,291 $132.74 

Capi tal Costs $271,764

Annualized Capi tal Costs $43,899

Annual Expenses $80,007

Annual Fixed Costs ($/yr) $75,370

Annual Variable Costs ($/yr) $48,536

Total Annual Costs ($/yr) $123,906

Processing Model PlantControlled ‐ Subpart VVa

Type of Component

Number of

Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 1,392 23.80 39303.02 12 1.50 25056.00 0.0595 82.82 1.91 319.05 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 4392 1.10 7923.53 0.25 2.50 2745.00 0.0170 74.66 0.81 8.89 75 0.17 66.24 2.77 25 2.00 

Pressure Relief Devices

* Disks 29 122.11 3541.19 0 2.00 0.00 72.50 

* Disk holders, valves,etc. 29 6374.29 184854.41 5.00 9280.00 

Open‐Ended Lines 134 140.92 18883.28 5.00 938.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 5947

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $279,805 $29,670 $27,801 $10,291 $135.51 

Capi tal Costs $279,805

Annualized Capi tal Costs $45,041

Annual Expenses $91,126

Annual Fixed Costs ($/yr) $76,512

Annual Variable Costs ($/yr) $59,655

Total Annual Costs ($/yr) $136,168
C-11 

Summary of Cost Effectiveness of the Subpart VV and Subpart VVa LDAR Programs for Transmission a

Average Model Plant Cost Effectiveness Summary for Transmission & Storage Facilities w/o Recovery Credits

Model Plant

Total Capital

Investment

Annual LDAR

Cost ($/yr)

Recovery

Credits ($/yr)1

Annual LDAR

Cost w/

Recovery

Credits ($/yr)

Total CH4Emissions

(Tons/yr)

Total CH4

Emission

Reductions

CH4 Cost

Effectiveness

($/Ton)

Total VOC

Emissions

(Tons/yr)

Total VOC

Emission

Reductions

VOC Cost

Effectiveness

($/Ton)

T

E

(

Model Plant TransmissionBaseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 75.7 ‐‐‐‐‐ ‐‐‐‐‐ 2.09 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $151,669 $78,728 N/A N/A 50.3 25.4 $3,103 1.39 0.702 $112,127 VVa $156,332 $85,601 N/A N/A 21.5 54.1 $1,581 0.596 1.50 $57,144 Model Plant StorageBaseline ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ ‐‐‐‐‐ 401 ‐‐‐‐‐ ‐‐‐‐‐ 11.1 ‐‐‐‐‐ ‐‐‐‐‐ 

V/VV $571,841 $206,513 N/A N/A 127 274 $753 3.51 7.59 $27,201 VVa $582,574 $222,970 N/A N/A 62.8 338 $659 1.74 9.36 $23,819 

1 Recovery credits calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf.
C-12 

Transmission and Storage Emission Summary

Model Plant 1 ‐ Transmission

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total CH4Emissions Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connecto

Uncontrolled 704 3,068 7 15 34.92 25.80 9.61 5.32 75.66 0.966 0.714 0.266 0.147 2.09 ‐‐ 0.0287 0.0

V 704 3,068 7 15 21.09 25.80 0.14 3.26 50.29 0.584 0.714 0.004 0.090 1.39 0.0173 0.0

VV 704 3,068 7 15 21.09 25.80 0.14 3.26 50.29 0.584 0.714 0.004 0.090 1.39 0.70 0.0173 0.0

VVa 704 3,068 7 15 8.33 9.80 0.14 3.26 21.53 0.231 0.271 0.004 0.090 0.60 1.50 0.0068 0.0

Model Plant 1 ‐ Storage

Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total CH4Emissions Valves Connectors

Open‐Ended

Lines

Pressure

Relief Valves

Total VOC

Emissions

Emission

reduction Valves Connecto

Uncontrolled 1,898 5,660 367 68 94.15 47.60 235.18 24.12 401.05 2.606 1.317 6.508 0.668 11.10 0.0774 0.0

V 1,898 5,660 367 68 56.85 47.60 7.51 14.76 126.72 1.573 1.317 0.208 0.409 3.51 0.0467 0.0

VV 1,898 5,660 367 68 56.85 47.60 7.51 14.76 126.72 1.573 1.317 0.208 0.409 3.51 7.59 0.0467 0.0

VVa 1,898 5,660 367 68 22.46 18.08 7.51 14.76 62.81 0.622 0.500 0.208 0.409 1.74 9.36 0.0185 0.0

Methane Emission Factors ‐ Transmission & Storage

Uncontrolled

(ton/yr/comp)

V

_

VV

(ton/yr/comp)

VVa

(ton/yr/comp) V _ VV VVa

Valves 0.0496 0.0300 0.0118 39.6% 76.1%Connectors 0.0084 0.0084 0.0032 0.0% 62.0%OEL 0.6408 0.0205 0.0205 96.8% 96.8%PRV 0.3547 0.2171 0.2171 38.8% 38.8%Calculated from Table 4‐17 and Table 4‐24 of Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks

The emission factors for V_VV and Vva were estimated using the emission reductions that were obtained for the various components from the Uniform Standards data.

Memorandum from Cindy Hancy, RTI to Jodi Howard, EPA, Analysis of Emisson Reduction Techniques for Equipment Leaks, December 21, 2011. [EPA‐HQ‐OAR‐2002‐0037‐0180]

Weight Ratios for Estimating Emissions

Transmission & Storage

VOC:Methane 0.027674689HAP:Methane 0.000821985

Monitoring

Model Plant Component Count Methane Emissions (Tons/yr) VOC Emissions (Tons/yr) 

Monitoring

Model Plant Component Count Methane Emissions (Tons/yr) VOC Emissions (Tons/yr) 
C-13 

Transmission Model Plant

Subpart V

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 704 23.80 17374.39 12 1.50 12672.00 0.0118 8.31 1.18 99.69 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 3068 1.10 3374.80

Pressure Relief Devices

* Disks 15 122.11 1831.65 0 2.00 0.00 37.50 

* Disk holders, valves,etc. 15 6374.29 95614.35 5.00 4800.00 

Open‐Ended Lines 58 140.92 8173.36 5.00 406.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 3845

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670

  ‐ Assume 340 hr per fac

TOTALS $151,669 $29,670 $12,672 $5,244 $132.74 

Capi tal Costs $151,669

Annualized Capi tal Costs $26,671

Annual Expenses $52,056

Annual Fixed Costs ($/yr) $54,076

Annual Variable Costs ($/yr) $24,651

Total Annual Costs ($/yr) $78,728

Transmission Model Plant

Controlled ‐ Subpart VVa

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 704 23.80 19877.39 12 1.50 12672.00 0.0595 41.89 1.91 161.36 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 3068 1.10 5534.92 0.25 2.50 1917.50 0.0170 52.16 0.81 6.21 75 0.17 66.24 2.77 25 2.00 

Pressure Relief Devices

* Disks 15 122.11 1831.65 0 2.00 0.00 37.50 

* Disk holders, valves,etc. 15 6374.29 95614.35 5.00 4800.00 

Open‐Ended Lines 58 140.92 8173.36 5.00 406.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 3845

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $156,332 $29,670 $14,590 $5,244 $135.51 

Capi tal Costs $156,332

Annualized Capi tal Costs $27,334

Annual Expenses $58,267

Annual Fixed Costs ($/yr) $54,738

Annual Variable Costs ($/yr) $30,863

Total Annual Costs ($/yr) $85,601
C-14 

Storage Model Plant

Subpart V

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 1,898 23.80 46841.75 12 1.50 34164.00 0.0118 22.40 1.18 268.76 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 5660 1.10 6226.00

Pressure Relief Devices

* Disks 68 122.11 8303.48 0 2.00 0.00 170.00 

* Disk holders, valves,etc. 68 6374.29 433451.72 5.00 21760.00 

Open‐Ended Lines 367 140.92 51717.64 5.00 2569.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 7993

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $571,841 $29,670 $34,164 $24,499 $132.74 

Capi tal Costs $571,841

Annualized Capi tal Costs $86,996

Annual Expenses $119,517

Annual Fixed Costs ($/yr) $129,915

Annual Variable Costs ($/yr) $76,598

Total Annual Costs ($/yr) $206,513

Storage Model Plant

Controlled ‐ Subpart VVa

Type of Component Number of Components

Initial

Moni toring Fee

or Uni t Cost

($/comp)

Initial

Monitoring

Cos ts ($/yr)

(Capital)

Initial LDAR

Admin. Costs

Frequency of

Moni toring

(times/yr)

Subsequent

Monitoring Fee

($/comp) or

Charge (%)

Annual

Monitoring

Costs ($/yr)

Annual

Maintenance

Cos ts ($/yr)

Initial Leak

Fraction

Ini tial Number

of Leaks

Subsequent

Leak Frequency

(%)

Annual

Number of

Leaks

Percent

Repaired

OnLine

Repair Time

(hours)

Labor Charge

($/hr)

Annual OnLine

Leak Repair

Cost ($/yr)

Percent

Requiring

Further Repair

Repair Time

(hours)

Valves (UU)

* Gas/vapor service 1,898 23.80 53589.89 12 1.50 34164.00 0.0595 112.93 1.91 435.02 75 0.17 66.24 132.74 25 4.00 

Connectors

* Flanges ‐ gas/vapor 5660 1.10 10211.10 0.25 2.50 3537.50 0.0170 96.22 0.81 11.46 75 0.17 66.24 2.77 25 2.00 

Pressure Relief Devices

* Disks 68 122.11 8303.48 0 2.00 0.00 170.00 

* Disk holders, valves,etc. 68 6374.29 433451.72 5.00 21760.00 

Open‐Ended Lines 367 140.92 51717.64 5.00 2569.00 

Monitoring Device 1 $10,800 $10,800

Monitoring Device ‐ Rent 0

Data Collection System 1 $14,500 $14,500Sum of components: 7993

Annual Adminstrative and Reports 250 92.72 

  ‐ Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670  ‐ Assume 340 hr per fac

TOTALS $582,574 $29,670 $37,702 $24,499 $135.51 

Capi tal Costs $582,574

Annualized Capi tal Costs $88,520

Annual Expenses $134,450

Annual Fixed Costs ($/yr) $131,439

Annual Variable Costs ($/yr) $91,531

Total Annual Costs ($/yr) $222,970