Oil and Natural Gas Industry Estimated Reasonably Available Control 

Technology Emission Reductions and Cost of Control

1.0 INTRODUCTION 

The Clean Air Act (CAA) provides that state implementation plans (SIPs) for ozone 

nonattainment (NA) areas must include reasonably available control technology (RACT) for 

sources of emissions, and stipulates that for moderate (and higher) ozone nonattainment (NA) 

areas, states must revise their SIPs to include RACT for volatile organic compound (VOC) 

emission sources covered by control techniques guidelines (CTG).1 Furthermore, the CAA 

requires that SIPs for states in ozone transport regions (OTRs) must comply with and implement 

RACT with respect to all sources of VOC in the state covered by a CTG.2 The proposed Control 

Techniques Guidelines for the Oil and Natural Gas Industry, henceforth the CTG, proposes 

recommendations for RACT for select emission sources in the oil and natural gas industry.3

The proposed CTG provides state, local and tribal air agencies (air agencies) with 

information to assist them in determining RACT for VOC from select oil and natural gas 

industry emission sources. During the development of the guidelines, the U.S. Environmental 

Protection Agency (EPA) evaluated the sources of VOC emissions from the oil and natural gas 

industry and the available control approaches to reduce these emissions, including the costs of 

the evaluated approaches. The EPA is recommending RACT for compressors, natural gas-driven 

pneumatic controllers, natural gas-driven pneumatic pumps, storage vessels, equipment leaks at 

natural gas processing plants and fugitive emissions at well sites and compressor stations in the 

oil and natural gas industry. Table 1-1 presents a summary of the recommended RACT level of 

control for each of these sources. 

Air agencies can use the recommendations in the CTG to inform their own determination 

as to what constitutes RACT for VOC emissions for the oil and natural gas industry sources 

included in the CTG. The information contained in the CTG is provided only as guidance. The 

CTG does not change, or substitute for, requirements specified in applicable sections of the CAA 

or the EPA’s regulations; nor is it a regulation itself. The CTG does not impose any requirements 

on facilities in the oil and natural gas industry. It provides only recommendations for air agencies 

to consider when they determine RACT. Air agencies are free to implement other technicallysound approaches that are consistent with the CAA and the EPA’s implementing regulations. 

To understand the potential impact of the CTG, the EPA conducted a scoping analysis 

based on a snapshot of the existing oil and natural gas industry. While the CTG itself does not 

require facilities in the oil and natural gas industry to adopt specific control technologies, 

assessing the emission reductions and costs of the case where recommended RACTs were 

 

1 CAA Section 172(c)(1) and Section 182(b)(2)(A). 

2

 CAA Section 184(b)(1)(B). 

3

 U.S. Environmental Protection Agency. Proposed Control Techniques Guidelines for the Oil and Natural Gas 

Industry. August 2015 
2 

adopted by oil and natural gas emission sources in moderate and higher ozone NA areas and the 

OTR provides a reasonable basis for the impact of the RACT requirements ultimately 

determined by air agencies. Therefore, this document presents an assessment of the emission 

reductions and net expenditures required by the industry in the case where all affected oil and 

natural gas emission sources that existed in 2012 adopt the recommended RACT. It is estimated 

that in this case VOC emissions would be reduced by approximately 82 thousand tpy at an 

annualized net cost to the industry of approximately $76 million dollars based on the CTG 

recommended RACT. Additionally, the recommended RACT is estimated to reduce methane 

emissions by approximately 220 thousand tpy and hazardous air pollutant (HAP) emissions by 

three thousand tpy. 

The assessment provides a reasonable estimate of the magnitude of expected emission 

reductions and net costs to the source category associated with the proposed CTG; however there 

are limitations, including some that suggest the cost estimates may be conservative in some 

dimensions. For example, while the analysis attempts to include existing state regulations, the 

2012 snapshot may not fully account for state permit limits for individual sources that meet or 

exceed the recommended RACT level of control. Thus, the percentage of existing sources that 

are already achieving the recommended RACT level of control may be underestimated which 

would lead to fewer emission reductions and lower expected costs for owners and operators as a 

result of the CTG. Also, air agencies have the flexibility of determining RACT that may differ 

from what the EPA recommends. This flexibility allows them to potentially take advantage of 

their local conditions and implement a tailored RACT which may lower the costs for sources in 

their jurisdiction. This analysis is based on industry averages and does not account for 

heterogeneity in sources that affect the costs or emission reductions. The resulting state and local 

regulations may also require a lower level of control or may affect a lower number of sources 

than were included in the analysis presented here. The focus on a 2012 snapshot of existing 

sources may include some sources that are no longer in use. However, any small changes to the 

existing universe of sources it is not expected to notably change the magnitude of the estimates 

in this analysis. 

The document is organized as follows: 

 Section 2 presents a short discussion about the moderate or higher ozone NA and 

OTR areas impacted by RACT. 

 Sections 3 presents a summary of the information used to determine the number of 

sources, baseline emissions, emission reductions and costs. 

 Section 4 presents the methodology used to estimate baseline emissions, emission 

reductions and costs. 

 Section 5 presents a summary of the VOC RACT emission reductions and costs. 

 
3 

Table 1-1. Summary of the Oil and Natural Gas Industry Emission Sources and 

Proposed Recommended RACT 

Emission Source Applicability RACT Recommendations 

1. Storage Vessels Individual storage vessel 95 percent reduction of VOC emissions from 

storage vessels with a potential to emit (PTE) 

greater than or equal to 6 tpy 

2. Natural Gas-Driven 

Pneumatic Controllers 

Individual continuous bleed, 

natural gas-driven pneumatic 

controller located at a natural gas 

processing plant 

Natural gas bleed rate of zero scfh (unless there 

are functional needs, including but not limited to 

response time, safety and positive actuation, 

requiring a bleed rate greater than zero scfh). 

Individual continuous bleed 

natural gas-driven pneumatic 

controller located from the 

wellhead to the natural gas 

processing plant or point of 

custody transfer to an oil pipeline 

Natural gas bleed rate less than or equal to 6 scfh 

(unless there are functional needs, including but 

not limited to response time, safety and positive 

actuation, requiring a bleed rate greater than 6 

scfh). 

3. Natural Gas-Driven 

Pneumatic Pumps 

Individual natural gas-driven 

chemical/methanol and diaphragm 

pump located at a natural gas 

processing plant 

Zero natural gas emissions 

Individual natural gas-driven 

chemical/methanol and diaphragm 

pump at locations other than 

natural gas processing plants from 

the well site to the point of 

custody transfer to the natural gas 

transmission and storage segment. 

-If there is an existing control device at the 

location of the pneumatic pump, reduce VOC 

emissions from each gas-driven 

chemical/methanol and diaphragm pump at the 

location by 95 percent or greater. 

- If there is no existing control device at the 

location of the pneumatic pump, submit a 

certification that there is no device. 

4. Compressors 

(Centrifugal and 

Reciprocating) 

Individual reciprocating 

compressor located between the 

wellhead and point of custody 

transfer to the natural gas 

transmission and storage segment. 

Reduce VOC emissions by replacing 

reciprocating compressor rod packing after 

26,000 hours of operation or 36 months since the 

most recent rod packing replacement. 

Alternatively, route rod packing emissions to a 

process through a closed vent system under 

negative pressure. 

Individual reciprocating 

compressor located at a well site, 

or an adjacent well site and 

servicing more than one well site 

RACT would not apply. 

Individual centrifugal compressor 

using wet seals that is located 

between the wellhead and point of 

custody transfer to the natural gas 

Reduce VOC emissions from each centrifugal 

compressor wet seal fluid gassing system by 95 

percent or greater. 
4 

Emission Source Applicability RACT Recommendations 

transmission and storage segment. 

Individual centrifugal compressor 

using wet seals located at a well 

site, or an adjacent well site and 

servicing more than one well site 

RACT would not apply. 

Individual centrifugal compressor 

using dry seals 

RACT would not apply. 

5. Equipment Leaks Equipment components in VOC 

service located at a natural gas 

processing plant 

Implement the 40 CFR part 60, subpart VVa 

LDAR program for natural gas processing plants 

constructed or modified on or before August 23, 

2011. 

6. Fugitive Emissions Individual well site with wells that 

produce, on average, greater than 

15 barrel equivalents per day per 

well 

Implement a semiannual optical gas imaging 

(OGI) monitoring and repair program. 

Individual compressor station 

located from the wellhead to the 

point of custody transfer to the 

natural gas transmission and 

storage segment or point of 

custody transfer or to an oil 

pipeline 

Implement a semiannual OGI monitoring and 

repair program. 
5 

2 MODERATE OR HIGHER OZONE NA AND OTR AREAS 

 In order to estimate the potential moderate or higher ozone NA area and OTR area 

(referred to collectively as “RACT-impacted areas”) emission reduction impacts for the proposed 

RACT recommendations, we obtained information on U.S. ozone NA areas from the EPA’s 

Greenbook as of January 30, 2015 (http://www.epa.gov/oaqps001/greenbk/ancl.html). The list of 

the moderate or higher ozone NA areas included in this analysis is presented in Attachment 1 to 

this memorandum. The OTR areas included in this analysis are the States of Connecticut, 

Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, 

Pennsylvania, Rhode Island, Vermont and the CMSA that includes the District of Columbia). 

3 INFORMATION USED TO DETERMINE THE NUMBER OF SOURCES 

IMPACTED BY RACT, RACT-IMPACTED AREA BASELINE EMISSIONS AND 

EMISSION REDUCTIONS AND COSTS BASED ON RACT 

Activity data, baseline emissions and emission reductions per source were estimated 

based on information obtained from the following sources: 

 2012 DI Desktop U.S. oil and natural gas wells information (2012 DI Desktop).4 

Includes location and production information for oil and gas wells in the U.S. 

Discussed further below. 

 Oil and Gas Journal (OGJ). Worldwide Gas Processing (Capacities as of January 1, 

2013, and average production). June 3, 2013. (2012 Gas Processing Survey). 

Includes information on the number, location and capacities of gas processing plants 

worldwide. Discussed further below. 

 Emissions information and counts for various emission sources were obtained from 

facility-level data submitted to the Greenhouse Gas Reporting Program (GHGRP) and 

data used to calculate national emissions in the Inventory of U.S. Greenhouse Gas 

Emissions and Sinks. The published data from 2013 was used in this analysis. For the 

purposes of this document these data sources are referred to as "GHGRP" and “GHG 

Inventory”.5,6

 The proposed Control Techniques Guidelines for the Oil and Natural Gas Source 

Industry (CTG).7 Includes information on the baseline VOC emissions per unit, VOC 

emission reductions per unit, and VOC cost of control per unit used in this analysis. 

 The TSD for the 2015 proposed NSPS standards is referred to in this document as the 

“2015 NSPS TSD”.8

 

4 DI Desktop. 2012. Drilling Info. Inc. 5

 U.S. Environmental Protection Agency (2014). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2012. U.S. Environmental Protection Agency, Washington D.C. EPA 430-R-15-004 Available online at: 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.

6 Note that the EPA’s GHGRP plans to release additional activity data in the fall of 2015 from its Petroleum and 

Natural Gas Systems source category. These data covers oil and gas operations reporting to the GHGRP in 2011, 

2012, 2013 and 2014. These new activity data will be reviewed prior to finalization of the CTG and incorporated 

into this analysis if appropriate. 7 See reference 3. 

8

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

Natural Gas Production, Transmission, and Distribution - Background Technical Support Document for the 

Proposed Amendments to the New Source Performance Standards. June 2015. 
6 

 The gas composition memorandum that was developed during the NSPS process 

which characterizes an analysis of data to determine the gas composition and develop 

ratios for natural gas composition for the various segments of the oil and natural gas 

industry. This document is referred to in this document as the "2011 Gas Composition 

Memorandum".9

 All of the calculations supporting the analyses in this document are included in the 

CTG docket (Docket ID. EPA-HQ-OAR-2015-0216) in the form of spreadsheets. 

2012 DI Desktop Data 

The EPA obtained well production data from the DI Desktop database dated February, 

2014.10 The DI Desktop data collected by DrillingInfo, Inc. consists of oil and natural gas well 

information that provides parameters describing the location, operator, and production 

characteristics. The DI Desktop data extract from the DrillingInfo, Inc. database included the 

population of all wells with gas or hydrocarbon liquid production during 2010 to 2012 and with a 

recorded completion year of 2010 to the date of the extract (February, 2014). 11

The 2012 DI Desktop data was queried to identify oil and natural gas wells in production 

in 2012 in RACT-impacted areas using Federal Information Processing Standards (FIPS) codes 

for the respective areas. Gas wells were defined as those wells with an average gas to liquids 

ratio greater than or equal to 100,000 standard cubic feet per barrel over the lifetime of the well, 

and oil wells were defined as those wells with an average gas to liquids ratio less than 100,000 

standard cubic feet per barrel over the lifetime of the well. If a well had liquids production but no 

gas production, it was classified as an oil well, and if a well had gas production but no liquids 

production, it was classified as a gas well. 

 

As a result of this analysis, for all producing wells, 101,464 oil and gas wells (63,936 oil 

wells and 37,528 gas wells) were identified in moderate or higher ozone NA areas and 90,232 oil 

and gas wells (24,169 oil wells and 66,063 gas wells) were identified in OTR areas. An 

estimated 22,426 oil and gas wells (1,249 oil wells and 21,177 gas wells) were located in OTR 

areas that were also located in moderate or higher ozone NA areas. For producing wells that 

produce, on average, greater than 15 barrel equivalents per day, 25,212 oil and gas wells (13,336 

oil wells and 11,876 gas wells) were identified in moderate or higher ozone NA areas and 4,642 

oil and gas wells (277 oil wells and 4,365 gas wells) were identified in OTR areas. An estimated 

932 oil and gas wells (232 oil wells and 700 gas wells) were located in OTR areas that were also 

located in moderate or higher ozone nonattainment areas. States that had wells with RACTimpacted areas include California, Maryland, New York, Pennsylvania, Texas and Virginia. 

 

9

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

Oil and Natural Gas Sector Rulemaking. July 2011. Docket ID EPA-HQ-OAR-2010-0505-0084. 10 DrillingInfo is a private organization specializing in oil and gas data and statistical analysis. The DrillingInfo 

database is focused on historical oil and gas production data and drilling permit data. 11 Memorandum to Mark de Figueiredo, U.S EPA from Casey MacQueen and Jessica Gray, P.E., ERG. 2013 

GHGRP Subpart W and NSPS/NESHAP DrillingInfo Processing Methodology. August 27, 2014. 
7 

This information was used to: 

 estimate the number and location of all producing wells and individual well sites with 

wells that produce, on average, greater than 15 barrel equivalents per day in OTR and 

moderate or higher ozone NA areas (as noted), 

 estimate the number and location of storage vessels in OTR and moderate or higher 

ozone NA areas (assuming one storage vessel per well12), 

 estimate the number of production segment pneumatic controllers and pumps located 

in OTR and moderate or higher ozone NA areas (using the percentage of the number 

of wells located in each of the respective areas), and 

 estimate the number of gathering and boosting stations located in OTR and moderate 

or higher ozone NA areas (using the average of the percentage of wells and the 

percentage of total natural gas processing plants located in each respective areas). 

OGJ Worldwide Gas Processing Survey (Capacities as of January 1, 2013, and Average 

Production) 

The OGJ Gas Processing Survey reflecting capacities as of January 1, 2013 (which would 

reflect capacities for 2012) was used to obtain location information of natural gas processing 

plants in OTR and moderate or higher ozone NA areas. Of the estimated 606 natural gas 

processing plants in the U.S., an estimated 10 natural gas processing plants were located in OTR 

areas and 40 were located in moderate or higher ozone NA areas. None of the 40 natural gas 

processing plants in moderate or higher ozone NA areas were located in OTR areas. States that 

had processing plants with RACT-impacted areas include California, Pennsylvania and Texas. 

This information was used to: 

 estimate the number and location of natural gas processing plants in OTR and 

moderate or higher ozone NA areas, 

 estimate the number of processing segment compressors and pneumatic controllers 

located in OTR and moderate or higher ozone NA areas (using the percentage of the 

number of gas processing plants located in OTR and moderate or higher ozone NA 

areas), and 

 estimate the number of gathering and boosting stations located in OTR and moderate 

or higher ozone NA areas (using the average of the percentage of wells and the 

percentage of gas processing plants located in OTR and moderate or higher ozone NA 

areas). 

 

12 The EPA is aware that there is often more than one storage vessel per well site. However, for emissions 

calculation purposes, we assumed that all storage vessels are likely manifolded together or could reasonable be 

manifolded together such that there is a single emission point for all storage vessels on the well site. Thus, we count 

one storage vessel per well site for emission calculation purposes because only one emission point would need to be 

controlled. 
8 

4 METHODOLOGY USED TO ESTIMATE RACT-IMPACTED AREA BASELINE 

EMISSIONS, EMISSION REDUCTIONS AND COSTS 

 The following paragraphs present the methodologies used to estimate RACT-impacted 

area baseline emissions, emission reductions and costs for storage vessels, pneumatic controllers, 

pneumatic pumps, compressors, equipment leaks at natural gas processing plants and fugitive 

emissions at well sites and compressor stations. 

4.1 Storage Vessels 

4.1.1 Approach 

RACT-impacted baseline emissions and emission reductions from storage vessels were 

calculated by multiplying the number of estimated uncontrolled storage vessels by emission 

factors based on oil and condensate production and production information from the 2012 DI 

Desktop database. Emission reductions were estimated by multiplying the emissions calculated 

for each storage vessel by 95 percent. The RACT-impacted area costs were estimated by 

multiplying the number of RACT-impacted storage vessels by costs per storage vessel. 

4.1.2 RACT-Impacted Population of Storage Vessels 

In order to estimate the number of storage vessels that would potentially be impacted by 

RACT, we conducted an analysis using the following procedures: 

 Estimated the number of wells in existence and located in RACT-impacted areas in 

2012 (assuming one controlled storage vessel per well) based on 2012 DI Desktop 

location information. 

 Subtracted the wells completed in 2012 from this number (assuming that these 

storage vessels would be subject to the NSPS). 

 Subtracted the number of storage vessels subject to and presumed to be controlled at 

baseline under state air regulations from the number of storage vessels that would 

potentially be impacted by RACT, 

 Used the emission factor from a typical storage vessel within each throughput bracket 

established under the NSPS13 to estimate emissions based on 2012 DI Desktop 

production information. 

 Determined the number of storage vessels that would likely have VOC emissions 

greater than or equal to the RACT recommended applicability threshold of 6 tons per 

year (tpy). 

 Estimated the number of storage vessels that would likely have VOC emissions 

greater than or equal to 6 tpy that would also be subject to and controlled under state 

air regulations. 

 

13 Heather Brown, EC/R Incorporated to Moore, B., EPA/OAQPS/SPPD/FIG. Revised Analysis to Determine the 

Number of Storage Vessels Projected to be Subject to New Source Performance Standards for the Oil and Natural 

Gas Sector. April 8, 2013. 
9 

 Using information on state environmental regulations developed for the CTG, we 

subtracted the number of storage vessels subject to and controlled under state air 

regulations from the number of storage vessels with VOC emissions greater than or 

equal to 6 tpy to determine the number of storage vessels that would potentially be 

impacted by RACT. 

Attachments 2 and 3 to this memorandum include the RACT-impacted storage vessel 

population and baseline emissions analysis. Table 4-1 presents the estimated number of RACTimpacted storage vessels. 

Table 4-1. RACT-Impacted Population of Storage Vessels 

Emission 

Source 

Number of RACT-Impacted Storage Vessels 

Moderate or Higher Ozone 

NA Areas Outside of OTR 

Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas/OTR Areas 

Storage 

Vessels 2,451 11 2,462 

4.1.3 RACT-Impacted Storage Vessel Baseline Emissions, Emission Reductions and Costs 

Using average storage vessel VOC emission factors based on well production rate 

brackets developed under the NSPS14 and 2012 DI Desktop production information, we 

calculated the RACT-impacted number of storage vessels and baseline VOC, methane and 

HAP emissions. RACT-impacted storage vessel emission reductions were estimated by 

multiplying the calculated baseline emissions per storage vessel by the 95 percent reduction 

efficiency attributable to combustion or capture and recovery. Using VOC to methane and 

VOC to HAP ratios developed for the oil and natural gas industry as presented in the 2011 Gas 

Composition memorandum, we estimated methane and HAP baseline emissions and emission 

reductions for storage vessels. Table 4-2 presents the estimated RACT-impacted storage vessel 

baseline emissions. RACT-impacted storage vessel emission reductions are provided in Table 

4-3. 

 

14 Ibid. 
10 

Table 4-2. RACT-Impacted Storage Vessel Baseline Emissions 

Emission 

Source 

RACT-Impacted Storage Vessel Baseline Emissions (tpy) 

Moderate or Higher Ozone 

NA Areas Outside of OTR 

Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas /OTR Areas 

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP 

Storage 

Vessels 24,515 5,704 769 101 21 3 24,617 5,095 773 
11 

Table 4-3. RACT-Impacted Storage Vessel Emission Reductionsa 

Emission 

Source 

Type of 

Control 

 

RACT-Impacted Storage Vessel Emission Reductions (tpy) 

Moderate or Higher Ozone 

NA Areas Outside of OTR 

Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas/OTR Areas 

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP 

Storage 

Vessel 

95% 

Control 23,290 4,820 731 96 20 3 23,386 4,840 734 

a Assumes 94 percent of sources will use a combustion control device and 6 percent will use a VRU to comply 

with the recommended RACT. 

Using the retrofit costs for a combustor or VRU developed for the CTG, we multiplied 

these costs by the number of RACT-impacted storage vessels, assuming 94 percent of the 

storage vessels would use combustion and 6 percent would use a vapor recovery unit (VRU).15

The capital costs and annual costs used for a combustion device was $100,986 and $22,228, 

respectively. The capital costs and annual costs used for a VRU used was $171,538 and 

$28,230, respectively. Gas savings is individual to production and emission rate class. Gas 

savings was estimated for storage vessels using a VRU only, assuming gas recovered would be 

valued at $4 per Mcf of recovered natural gas. No gas savings was attributed to storage vessels 

using combustion control. Attachment 2 presents the VRU and combustion cost analysis. Table 

4-4 presents the estimated RACT-impacted storage vessel costs.

 

15 U.S. Environmental Protection Agency. Greenhouse Gas Reporting Program – Petroleum and Natural Gas 

Systems (Subpart W) Analysis: Onshore Production Storage Tanks (Reporting Year: 2013 Data). 
12 

Table 4-4. RACT-Impacted Storage Vessel Costsa

Emission 

Point 

Moderate or Higher Ozone NA Areas 

Outside of OTR Areas OTR Areas Moderate or Highe

Capital ($) 

Annual w/o 

savings 

($/yr) 

Annual w/ 

savings 

($/yr) 

Capital ($) 

Annual w/o 

savings 

($/yr) 

Annual w/ 

savings 

($/yr) 

Capital ($) 

An

s

Storage Vessel $257,902,585 $55,365,741 $55,176,698 $1,157,410 $248,469 $247,688 $259,059,995 $55

a Assumes 94 percent of sources will use a combustion control device and 6 percent will use a VRU to comply with the recommended 
13 

4.2 Natural Gas-Driven Pneumatic Controllers 

4.2.1 Approach 

RACT-impacted natural gas-driven pneumatic controller baseline emissions and 

emission reductions were calculated by multiplying the number of uncontrolled natural gasdriven pneumatic controllers reported in the 2012 GHG Inventory (assuming that they were 

natural gas-driven) by emissions and emission reductions per controller. The RACT-impacted 

area costs were estimated by multiplying the calculated RACT VOC emission reductions by 

costs per controller. 

 

4.2.2 RACT-Impacted Population of Natural Gas-Driven Pneumatic Controllers 

Based on information in the 2012 GHG Inventory, there were an estimated 135 natural 

gas-driven pneumatic controllers in the processing segment nationally. The percentage of 

natural gas processing plants located in RACT-impacted areas based on the 2012 Gas 

Processing Survey was used to estimate the number of RACT-impacted natural gas-driven 

pneumatic controllers. 

Similarly, based on information in the 2012 GHG Inventory, there were an estimated 

165,372 high bleed natural gas-driven pneumatic controllers installed in the production 

segment nationally. The percentage of wells located in RACT-impacted areas based on 2012 

DI Desktop location information was used to estimate the number of high bleed natural gasdriven pneumatic controllers located in RACT-impacted areas. 

Table 4-5 presents the estimated population of RACT-impacted natural gas-driven 

pneumatic controllers. 

Table 4-5. RACT-Impacted Population of Natural Gas-Driven Pneumatic Controllers 

Segment 

Number of RACT-Impacted Sources 

Moderate or Higher 

Ozone NA Areas 

Outside of OTR Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas/OTR Areas 

Oil and Natural Gas 

Production 10,219 11,666 21,885 

Processing Plants 9 2 11 
14 

4.2.3 RACT-Impacted Natural Gas-Driven Pneumatic Controller Baseline Emissions, 

Emission Reductions and Costs 

RACT-impacted natural gas-driven pneumatic controller baseline emissions were 

estimated by multiplying the population of natural gas-driven pneumatic controllers and the 

VOC, methane and HAP baseline emissions per natural gas-driven pneumatic controller. Using 

the cost and emission reductions developed for the CTG, we estimated emission reductions and 

costs by multiplying the number of natural gas-driven pneumatic controllers by the emission 

reductions and costs per natural gas-driven controller. For processing segment natural gas-driven 

pneumatic controllers, we used the emission reductions and costs associated with the use of an 

existing instrument air system. For production segment natural gas-driven pneumatic controllers, 

we used the emission reductions and costs associated with the replacement of an existing high 

bleed controller with a low bleed controller. Using methane to HAP ratios developed for the oil 

and natural gas industry as presented in the 2011 Gas Composition memorandum, we estimated 

RACT-impacted natural gas-driven pneumatic controller HAP baseline emissions and emission 

reductions. 

Tables 4-6 and 4-7 present the RACT-impacted natural gas-driven pneumatic controller 

baseline emissions and emission reductions. Tables 4-8 and 4-9 present the RACT-impacted 

natural gas-driven pneumatic controller costs. 
15 

Table 4-6. RACT-Impacted Natural Gas-Driven Pneumatic Controller Baseline Emission

Segment 

Baseline Emissions Per Natural 

Gas-Driven Pneumatic Controller 

(tpy) 

RACT-Impacted Pneumatic Controller Baseline Emis

Moderate or Higher Ozone NA 

Areas Outside of OTR Areas OTR Areas Moder

A

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP VOC 

Oil and Natural Gas Production 1.5 5.3 0.055 15,057 54,162 567 17,189 61,831 647 32,246 Processing Plants 0.28 1.0 0.01 2.5 8.9 0.9 0.62 2.2 0.02 3.1 

Table 4-7. RACT-Impacted Natural Gas-Driven Pneumatic Controller Emission Reductio

Segment 

Type of 

Control 

Emission Reductions Per 

Pneumatic Controller (tpy) 

RACT-Impacted Pneumatic Controller Emission R

Moderate or Higher Ozone 

NA Areas Outside of OTR 

Areas 

OTR Areas Mo

N

VOC Methane HAP VOC CH4 HAP VOC CH4 HAP VO

Oil and Natural Gas Production 

Replace w/ 

Low Bleed 1.4 5.10 0.05 14,444 52,118 546 16,489 59,498 623 30,

Processing Plants 

Existing 

Instrument 

Air System 

0.28 1.0 0.01 2.5 8.9 0.09 0.62 2.2 0.02 3
16 

Table 4-8. Total Annual Costs and VOC Cost of Control Per Natural Gas-Driven Pneumatic Co

Segment 

Natural 

Gas 

Savings 

Per 

Source 

(Mcf) 

Total Value 

of Natural 

Gas Savings 

Per Source 

($/yr) 

Total Capital 

Costs Per 

Source ($) 

Total Annual Costs Per Source ($/yr) VOC C

w/o savings w/ savings w/o sa

Oil and Gas Production 296 $1,184 $2,698 $296 ($886) $21Processing Plants 58 $232 $2,000 $285 $53 $1,0

Table 4-9. RACT-Impacted Natural Gas-Driven Pneumatic Controller Costs

Segment 

Moderate or Higher Ozone 

NA Areas Outside of OTR 

Areas 

OTR Areas Moderate or High

Capital ($) Annual w/o savings ($yr) Annual w/ savings ($/yr) Capital ($) Annual w/o savings ($/yr) Annual w/ savings ($/yr) Capital ($) Ann

sa

(

Oil and Gas Production $27,571,450 $3,027,197 ($9,054,192) $31,475,544 $3,455,846 ($10,336,259) $59,046,994 $6,4Processing Plants $17,822 $2,540 $474 $4,455 $635 $118 $22,277 $
17 

4.3 Natural Gas-Driven Pneumatic Pumps

4.3.1 Approach 

RACT-impacted natural gas-driven pneumatic pump baseline emissions and emission 

reductions were calculated by multiplying the number of uncontrolled natural gas-driven 

pneumatic pumps reported in the 2012 GHG Inventory (assuming they were all natural gasdriven pumps) by emissions and emission reductions per pump. The RACT-impacted natural 

gas-driven pneumatic pump costs were estimated by multiplying the calculated RACT VOC 

emission reductions by costs per pump. 

4.3.2 RACT-Impacted Population of Natural Gas-Driven Pneumatic Pumps 

Based on information in the 2012 GHG Inventory for oil production, there were an 

estimated 14,408 diaphragm pumps and 14,293 piston pumps. The number of pneumatic 

pumps reported in the 2012 GHG Inventory for gas production was an estimated 37,477 

pneumatic pumps (for both diaphragm and piston pumps). Similar to the assumption used in 

the 2015 NSPS TSD, we assumed that 50 percent of the gas production inventory pumps to be 

diaphragm pumps and 50 percent of the pumps to be piston pumps. Based on these 

assumptions, and assuming that all of the reported pumps were natural gas-driven, we 

estimated that there were 33,147 diaphragm and 33,032 piston natural gas-driven pneumatic 

pumps in the production segment nationally. The percentage of RACT-impacted wells based 

on 2012 DI Desktop location information was used to estimate the number of RACT-impacted 

high bleed natural gas-driven pneumatic pumps. 

The 2012 GHG Inventory did not estimate emissions from pneumatic pumps for the 

natural gas processing segment. 

Table 4-10 presents the estimated RACT-impacted population of natural gas-driven 

pneumatic pumps. 
18 

Table 4-10. RACT-Impacted Population of Natural Gas-Driven Pneumatic Pumps 

Pneumatic 

Pump Type 

Number of RACT-Impacted Sources 

Moderate or Higher 

Ozone NA Areas Outside 

of OTR Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas/OTR Areas 

Diaphragm 2,048 2,338 4,387 

Piston 2,041 2,330 4,371 

 

4.3.3 RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseline Emissions, Emission 

Reductions and Costs 

RACT-impacted natural gas-driven pneumatic pump baseline emissions were estimated 

by multiplying the population of natural gas-driven pneumatic pumps and the VOC, methane 

and HAP baseline emissions per diaphragm and piston natural gas-driven pneumatic pump. 

Using the emission reductions and costs developed for the CTG, we estimated the emission 

reductions and costs by multiplying the number of natural gas-driven pneumatic pumps by the 

emission reductions and costs associated with routing emissions to an existing combustion 

device. Using methane to HAP ratios developed for the oil and natural gas industry as 

presented in the 2011 Gas Composition memorandum, we estimated RACT-impacted natural 

gas-driven pneumatic pump HAP baseline emissions and emission reductions. 

Tables 4-11 and 4-12 present the RACT-impacted natural gas-driven pneumatic pump 

baseline emissions and emission reductions. Tables 4-13 and 4-14 present the RACT-impacted 

natural gas-driven pneumatic pump costs. 
19 

Table 4-11. RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseline Emissions 

Emission 

Source 

Baseline Emissions Per Natural GasDriven Pneumatic Pump (tpy) RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseli

Moderate or Higher NA Areas 

Outside of OTR Areas OTR Areas Moder

A

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP VOC 

Diaphragm 0.96 3.5 0.04 1,966 7,087 74 2,245 8,091 85 4,211 Piston 0.11 0.38 0.004 225 776 8.1 256 885 9.3 481 

Table 4-12. RACT-Impacted Natural Gas-Driven Pneumatic Pump Emission Reduction

Emission 

Source 

Type of 

Control 

Emission Reductions Per Natural 

Gas-Drven Pneumatic Pump (tpy) 

RACT-Impacted Natural Gas-Driven Pneumatic Pump E

Moderate or Higher NA 

Areas Outside of OTR 

Areas 

OTR Areas Mo

VOC Methane HAP VOC CH4 HAP VOC CH4 HAP V

Diaphragm 

Existing 

Combustion 

Device 

0.91 3.3 0.034 1,872 6,733 70 2,137 7,686 80 4,

Piston 

Existing 

Combustion 

Device 

0.10 0.36 0.0038 205 737 7.7 234 841 8.8 4
20 

Table 4-13. Total Annual Costs and VOC Cost of Control Per Natural Gas-Driven Pneumatic 

Emission Source 

Natural 

Gas 

Savings 

Per 

Source 

(Mcf) 

Total Value 

of Natural 

Gas Savings 

Per Source 

($/yr) 

Total Capital Costs 

Per Source ($) 

Total Annual Costs Per Source 

($/yr) 

VOC 

w/o savings w/ savings w/o s

Diaphragm 0 $0 $2,000 $285 $285 $3Piston 0 $0 $2,000 $285 $285 $2

Table 4-14. RACT-Impacted Natural Gas-Driven Pneumatic Pump Costs

Emission 

Point 

Moderate or Higher NA Areas Outside of 

OTR Areas OTR Areas Moderate or Highe

A

Capital 

($) 

Annual w/o 

savings ($/yr) 

Annual w/ 

savings 

($/yr) 

Capital 

($) 

Annual w/o 

savings ($/yr) 

Annual w/ 

savings 

($/yr) 

Capital 

($) 

Annu

saving

Diaphragm $4,096,598 $583,765 $583,765 $4,676,673 $666,426 $666,426 $8,773,271 $1,25Piston $4,082,385 $581,740 $581,740 $4,660,447 $664,114 $664,114 $8,742,833 $1,24
21 

4.4 Compressors 

4.4.1 Approach 

RACT-impacted reciprocating compressor and wet seal centrifugal compressor baseline 

emissions and emission reductions were calculated by multiplying the number of uncontrolled 

compressors based on information reported in the 2012 GHG Inventory by emissions and 

emission reductions by compressor. The RACT-impacted reciprocating compressor and wet 

seal centrifugal compressor costs were estimated by multiplying the calculated RACT VOC 

emission reductions by costs per compressor. 

4.4.2 RACT-Impacted Population of Reciprocating Compressors and Wet Seal Centrifugal 

Compressors 

Based on information in the 2012 GHG Inventory, there were an estimated 36,066 

reciprocating compressors located at gathering and boosting stations. The average of the 

percentage of the total number of RACT-impacted natural gas processing plants based on the 

2012 Gas Processing Survey and the percentage of the total number of RACT-impacted oil and 

natural gas wells based on 2012 DI Desktop location information was used to estimate the 

number of RACT-impacted reciprocating compressors located at gathering and boosting 

stations. 

Based on information in the 2012 GHG Inventory, there were an estimated 5,624 

reciprocating compressors in the processing segment. The percentage of the total number of 

RACT-impacted natural gas processing plants based on the 2012 Gas Processing Survey was 

used to estimate the number of RACT-impacted reciprocating compressors in the processing 

segment. 

Based on information in the 2012 GHG Inventory, there were an estimated 658 wet seal 

compressors in the processing segment. The percentage of the total number of RACT-impacted 

natural gas processing plants based on the 2012 Gas Processing Survey was used to estimate 

the number of RACT-impacted reciprocating compressors in the processing segment. 

Table 4-15 presents the estimated population of RACT-impacted reciprocating 

compressors and wet seal compressors. 
22 

Table 4-15. RACT-Impacted Population of Reciprocating Compressors and Wet Seal 

Compressors 

Emission Source 

Number of RACT-Impacted Sources 

Moderate or Higher 

Ozone NA Areas 

Outside of OTR Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas/OTR Areas 

Reciprocating 

Compressors - 

Gathering/Boosting 

Stations 

2,305 1,570 3,874 

Reciprocating 

Compressors - 

Processing Plants 

371 93 464 

Centrifugal 

Compressors - Wet 

Seals Processing 

Plants 

43 11 54 

4.4.3 RACT-Impacted Reciprocating Compressor and Wet Seal Centrifugal Compressor 

Baseline Emissions, Emission Reductions and Costs 

 RACT-impacted compressor baseline emissions were estimated by multiplying the 

population of compressors and the VOC, methane and HAP emissions per compressor. Using 

the emission reductions and costs developed for the CTG, we estimated emission reductions 

and costs by multiplying the number of compressors by the emission reductions and costs per 

compressor. For reciprocating compressors, we used the emission reductions and costs 

associated with replacing reciprocating compressor rod packing after 26,000 hours of operation 

or 36 months since the most recent rod packing replacement. For wet seal compressors, we 

used the emission reductions and costs associated with routing emissions to an existing 

combustion device. Using methane to HAP ratios developed for the oil and natural gas industry 

as presented in the 2011 Gas Composition memorandum, we estimated natural gas-driven 

pneumatic pump HAP baseline emissions and emission reductions. 

Tables 4-16 and 4-17 present the RACT-impacted reciprocating compressor and wet 

seal compressor baseline emissions and emission reductions. Tables 4-18 and 4-19 present the 

RACT-impacted reciprocating compressor and wet seal compressor costs. 
23 

Table 4-16. RACT-Impacted Reciprocating Compressor and Wet Seal Compressor Baseline Em

Emission Source 

Baseline Emissions Per 

Compressor (tpy) 

RACT-Impacted Compressor Baseline Emission

Moderate or Higher NA Areas 

Outside of OTR Areas OTR Areas Moder

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP VOC 

Reciprocating Compressor – Gathering and Boosting Station 

3.4 12 0.13 7,892 28,390 297 5,375 19,377 203 13,26

Reciprocating Compressor – Processing 6.1 22 0.23 2,270 8,176 86 568 2,042 21 2,838 Wet Seal Compressor – Processing 19 211 2.2 830 9,144 96 207 2,286 24 1,037 

Table 4-17. RACT-Impacted Reciprocating Compressor and Wet Seal Compressor Emission Re

Emission Source 

Type of 

Control 

Emission Reductions 

Per Compressor (tpy) 

RACT-Impacted Compressor Emission Redu

Moderate or Higher NA 

Areas Outside of OTR 

Areas 

OTR Areas M

VOC Methane HAP VOC CH4 HAP VOC CH4 HAP V

Reciprocating Compressor – Gathering and Boosting Station 

Replace 

Packing After 

Three Years 

1.9 6.8 0.07 4,385 15,774 165 2,986 10,744 113 7

Reciprocating Compressor – Processing 

Replace 

Packing After 

Three Years 

4.9 18 0.18 1,814 6,525 68 453 1,631 17 2

Wet Seal Compressor – Processing 

95 Percent 

Control; Existing 

Combustion 

Device 

18 200 2.1 788 8,706 91 197 2,177 23 9
24 

Table 4-18. Total Annual Costs and VOC Cost of Control Per Compressor 

Emission Source 

Natural 

Gas 

Savings 

Per 

Source 

(Mcf) 

Total Value 

of Natural 

Gas Savings 

Per Source 

($/yr) 

Total Capital Costs 

Per Source ($) 

Total Annual Costs Per Source 

($/yr) 

VOC 

w/o savings w/ savings w/o s

Reciprocating Compressor – Gathering and Boosting Station 

397 $1,587 $5,650 $2,153 $566 $1

Reciprocating Compressor – Processing 1,019 $4,074 $4,280 $1,631 ($2,443) $3Wet Seal Compressor – Processing 0 $0 $23,252 $3,311 $3,311 $

Table 4-19. RACT-Impacted Reciprocating Compressor and Centrifugal Compressor Co

Emission Source 

Moderate or Higher NA Areas Outside 

of OTR Areas OTR Areas Moderate o

Area

Capital ($) 

Annual w/o 

savings 

($/yr) 

Annual w/ 

savings 

($/yr) 

Capital 

($) 

Annual w/o 

savings 

($/yr) 

Annual w/ 

savings ($/yr) Capital ($) 

An

s

Reciprocating Compressor – Gathering and Boosting Station 

$13,020,363 $4,961,431 $1,305,079 $8,868,297 $3,379,279 $888,902 $21,888,661 $8

Reciprocating Compressor – Processing 

$1,588,826 $605,462 ($906,997) $397,207 $151,365 ($226,749) $1,986,033 $

Wet Seal Compressor – Processing 

$1,009,889 $143,804 $143,804 $252,472 $35,951 $35,951 $1,262,361 $
25 

4.5. Equipment Leaks at Natural Gas Processing Plants

4.5.1 Approach 

RACT-impacted equipment leaks at natural gas processing plants baseline emissions 

and emission reductions were calculated by multiplying the number of natural gas processing 

plants and the baseline emissions and emission reductions per plant. The RACT-impacted 

equipment leaks at natural gas processing plants costs were estimated by multiplying the 

emission reductions by costs per natural gas processing plant. 

4.5.2 RACT-Impacted Population of Natural Gas Processing Plants 

The number of RACT-impacted natural gas processing plants was obtained from 

information in the 2012 Gas Processing Survey. There were 40 natural gas processing plants 

located in moderate or higher ozone NA areas and 10 natural gas processing plants in OTR 

areas in 2012. Table 4-20 presents the estimated RACT-impacted population of natural gas 

processing plants. 

Table 4-20. RACT-Impacted Population of Natural Gas Processing Plants 

Emission Source 

Number of RACT-Impacted Sources 

Moderate or Higher NA 

Areas Outside of OTR 

Areas 

OTR Areas 

Moderate or Higher 

Ozone NA Areas/OTR 

Areas 

Natural Gas 

Processing Plants 40 10 50 

4.5.3 RACT-Impacted Equipment Leaks at Natural Gas Processing Plants Baseline Emissions, 

Emission Reductions and Costs 

 RACT-impacted equipment leaks at natural gas processing plants baseline VOC, 

methane and HAP emissions were estimated by multiplying the population of natural gas 

processing plants and the methane and VOC emissions per plant. The baseline assumes that 

existing natural gas processing plants currently implement an LDAR program equivalent to 40 

CFR part 60 subpart VV. Using the emission reductions and costs developed for the CTG, we 

estimated emission reductions and costs by multiplying the number of natural gas processing 

plants by the emission reductions and costs associated with the implementation of an LDAR 

program equivalent to 40 CFR part 60 subpart VVa (subpart VVa). Using methane to HAP 

ratios developed for the oil and natural gas industry as presented in the 2011 Gas Composition 

memorandum, we estimated HAP baseline emissions per natural gas processing plant. 
26 

Tables 4-21 and 4-22 present the RACT-impacted equipment leaks at natural gas 

processing plants baseline emissions and emission reductions. Tables 4-23 and 4-24 present the 

RACT-impacted equipment leaks at natural gas processing plants costs. 
27 

Table 4-21. RACT-Impacted Natural Gas Processing Plant Equipment Leaks Baseline Emis

Emission Source 

Baseline Emissions Per Natural 

Gas Processing Plant (tpy) 

RACT-Impacted Natural Gas Processing Plant Baseline 

Moderate or Higher NA Areas 

Outside of OTR Areas OTR Areas Mod

N

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP VOC 

Natural Gas Processing Plants - Equipment Leaks 

35 126 1.3 1,397 5,027 53 349 1,257 13 1,74

Table 4-22. RACT-Impacted Natural Gas Processing Plant Equipment Leaks Emission Redu

Emission Source 

Type of 

Control 

Emission Reductions Per 

Natural Gas Processing Plant 

(tpy) 

RACT-Impacted Natural Gas Processing Plant Emi

Moderate or Higher NA 

Areas Outside of OTR 

Areas 

OTR Areas 

VOC Methane HAP VOC CH4 HAP VOC CH4 HAP 

Natural Gas Processing Plants - Equipment Leaks 

 Subpart VVa 4.6 16 0.17 182 656 7 46 164 2 
28 

Table 4-23. Total Annual Costs and VOC Cost of Control Per Natural Gas Processing Pla

Emission Source 

Natural 

Gas 

Savings 

Per 

Source 

(Mcf) 

Total Value 

of Natural 

Gas Savings 

Per Source 

($/yr) 

Total Capital Costs 

Per Source ($) 

Total Annual Costs Per Source 

($/yr) 

VOC 

w/o savings w/ savings w/o s

Natural Gas Processing Plants - Equipment Leaks 950 $3,800 $8,499 $12,959 $9,159 $2

Table 4-24. RACT-Impacted Natural Gas Processing Plant Equipment Leaks Costs

Emission Point 

Moderate or Higher NA Areas Outside 

of OTR Areas OTR Areas Moderate o

Area

Capital 

($) 

Annual w/o 

savings ($/yr) 

Annual w/ 

savings 

($/yr) 

Capital 

($) 

Annual w/o 

savings ($/yr) 

Annual w/ 

savings 

($/yr) 

Capital 

($) 

Ann

savin

Natural Gas Processing Plants - Equipment Leaks 

$339,960 $518,366 $366,379 $84,990 $129,591 $91,595 $424,950 $6
29 

4.6 Fugitive Emissions at Well Sites and Compressor Stations 

4.6.1 Approach 

RACT-impacted fugitive emissions at well sites that produce, on average, greater than 15 

barrel equivalents per day per well, and gathering and boosting stations baseline emissions and 

emission reductions were calculated by multiplying the number of well sites and gathering and 

boosting stations by the baseline emissions and emission reductions per site/station. The 

RACT-impacted well site and gathering and boosting station costs were estimated by 

multiplying the calculated RACT VOC emission reductions by costs per well site/gathering and 

boosting station. 

4.6.2 RACT-Impacted Population of Wells Sites and Gathering and Boosting Stations 

The DI Desktop database was used to obtain information on the number of oil and natural 

gas wells in 2012 in the U.S that produce, on average, greater than 15 barrel equivalents per day. 

The number of natural gas wells in RACT impacted areas was estimated to be 15,541. The 

number of oil wells in RACT-impacted areas was estimated to be 13,381. Using information 

developed for the 2015 NSPS TSD and CTG, we estimated the number of well sites that would 

be subject to RACT by dividing the number of wells by two (assuming a national average of two 

wells per well site). 

Based on information in the 2015 NSPS TSD, we estimated that there would be 8,015 

gathering and boosting stations nationally. The average of the percentage of the total RACTimpacted number of natural gas processing plants based on the 2012 Gas Processing Survey and 

the percentage of the total RACT-impacted number of oil and natural gas wells based on 2012 DI 

Desktop location information was used to estimate the number of RACT-impacted gathering and 

boosting stations. 

Table 4-25 presents the estimated population of RACT-impacted well sites and gathering 

and boosting stations. 
30 

Table 4-25. RACT-Impacted Population of Oil and Natural Gas Well Sites and Gathering 

and Boosting Stations 

Emission 

Source 

Number of RACT-Impacted Sources 

Moderate or Higher NA 

Areas Outside of OTR 

Areas 

OTR Areas Moderate or Higher Ozone 

NA Areas/OTR Areas 

Natural Gas 

Well Sites 5,588 2,183 7,771 

Oil Well Sites 6,552 139 6,691 

Gathering and 

Boosting 

Stations 

512 349 861 

4.6.3 RACT-Impacted Oil and Natural Gas Well Site and Gathering and Boosting Station 

Fugitive Emissions, Fugitive Emission Reductions and Costs 

 RACT-impacted oil and natural gas well site and gathering and boosting station 

baseline fugitive emissions were estimated by multiplying the population of oil and gas well 

sites and gathering and boosting stations and VOC baseline emissions per site/station. Using 

the emission reductions and costs developed for the 2015 NSPS TSD and CTG, we estimated 

emission reductions and costs by multiplying the number of oil and gas well sites and gathering 

and boosting stations by the emission reductions and costs per well site/station. Using VOC to 

methane and VOC to HAP ratios developed for the oil and natural gas industry as presented in 

the 2011 Gas Composition Memorandum, we estimated methane and HAP baseline emissions 

and emission reductions. 

Tables 4-26 and 4-27 present the RACT-impacted oil and natural gas well site and 

gathering and boosting station baseline fugitive emissions and fugitive emission reductions. 

Tables 4-28 and 4-29 present the RACT-impacted oil and gas well site and gathering and 

boosting station costs. 
31 

Table 4-26. RACT-Impacted Oil and Natural Gas Well Site and Gathering and Boosting Station Baseline 

Emission Source 

Baseline Emissions Per Natural 

Gas Processing Plant (tpy) 

RACT-Impacted Oil and Gas Well Site and Gathering and Boosting S

Emissions (tpy) 

Moderate or Higher NA Areas 

Outside of OTR Areas OTR Areas Moder

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP VOC 

Natural Gas Well Sites 1.3 4.5 0.05 7,051 25,365 266 2,754 9,907 104 9,805 Oil Well Sites 0.30 1.1 0.01 1,981 7,125 75 42 151 2 2,203 Gathering and Boosting Stations 9.8 35 0.37 5,003 17,999 188 3,408 12,259 128 8,411 

Table 4-27. RACT-Impacted Oil and Natural Gas Well Site and Gathering and Boosting Station Fug

Reductions 

Emission 

Source 

Type of 

Control 

Emission Reductions Per 

Natural Gas Processing 

Plant (tpy) 

RACT-Impacted Oil and Gas Well Site and Gathering and B

Emission Reductions (tpy) 

Moderate or Higher NA 

Areas Outside of OTR Areas OTR Areas Mo

VOC CH4 HAP VOC CH4 HAP VOC CH4 HAP VO

Natural Gas Well Sites 

Semiannual 

OGI 0.76 2.7 0.03 4,231 15,219 159 1,652 5,944 62 5,8

Oil Well Sites Semiannual OGI 0.18 0.65 0.01 1,188 4,275 45 25 90 1 1,2Gathering and Boosting Stations 

Semiannual 

OGI 5.9 21 0.22 3,002 10,799 113 2,045 7,356 77 5,0
32 

Table 4-28. Total Annual Costs and VOC Cost of Control Per Well Site/Station 

Emission Source 

Natural Gas 

Savings Per 

Source 

(Mcf) 

Total Value 

of Natural 

Gas Savings 

Per Source 

($/yr) 

Total Capital Costs 

Per Source ($) 

Total Annual Costs Per Source 

($/yr) 

VOC 

w/o savings w/ savings w/o s

Natural Gas Well Sites 158 $631 $801 $2,230 $1,599 $2Oil Well Sites 38 $151 $801 $2,230 $2,079 $12Gathering and Boosting Stations 1,222 $4,888 $10,993 $15,881 $10,993 $2

Table 4-29. RACT-Impacted Oil and Natural Gas Well Site and Gathering and Boosting Station Fugitiv

Emission 

Point 

Moderate or Higher NA Areas Outside of 

OTR Areas OTR Areas Moderate or 

Areas

Capital 

($) 

Annual w/o 

savings 

($/yr) 

Annual w/ 

savings 

($/yr) 

Capital 

($) 

Annual w/o 

savings 

($/yr) 

Annual w/ 

savings ($/yr) Capital ($) 

An

s

Natural Gas Well Sites $4,475,582 $12,460,517 $8,932,579 $1,748,024 $4,866,693 $3,488,789 $6,223,605 $17Oil Well Sites $5,247,675 $14,610,112 $13,619,076 $110,928 $308,837 $287,888 $5,358,604 $14Gathering and Boosting Stations 

$5,630,384 $8,133,758 $5,630,384 $3,834,910 $5,539,982 $3,834,910 $9,465,294 $13
33 

5 SUMMARY OF THE VOC RACT EMISSION REDUCTIONS AND COSTS 

 Table 5-1 presents a summary of the VOC RACT emission reductions and costs for 

storage vessels, natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, 

reciprocating compressors, wet seal centrifugal compressors, natural gas processing plant 

equipment leaks, and fugitive emissions at well sites and gathering and boosting stations. 
34 

Table 5-1. Summary of the Oil and Natural Gas Industry VOC RACT Emission Reductions 

VOC Methane HAP w/o savings w/ savings VOC Methane HAP Capital ($1000)

Fugitive Emissions ‐ Gas Well

Sites (With Wells that ProduceGreater than 15 Barrel

Equivalents Per Day)

Semiannual OGI 0.76 2.70 0.03 $2,900 $2,100 5,900 21,000 220 6,200 

Fugitive Emissions ‐ Oil Well

Sites (With Wells that ProduceGreater than 15 Barrel

Equivalents Per Day)

Semiannual OGI 0.18 0.65 0.01 $12,000 $11,000 1,200 4,400 46 5,400 

Fugitive Emissions ‐ Gathering

and Boosting Stations

Semiannual OGI 5.90 21.00 0.22 $2,700 $1,900 5,000 18,000 190 9,500 

Equipment Leaks ‐ Processing

Plants NSPS Subpart VVa 4.60 16.00 0.17 $2,800 $2,000 230 820 9 420 

Reciprocating Compressors ‐ Gathering and Boosting Stations

Replace Packing

After 3 Years 1.90 6.80 0.07 $1,100 $300 7,400 27,000 280 22,000 

Reciprocating Compressors ‐ Processing

Replace Packing

After 3 Years 4.90 18.00 0.18 $330 ($500) 2,300 8,200 85 2,000 

Centri figal Compressors w/ Wet

Seals ‐ Processing

95% Control,

Existing

Combustion Device

18.00 200.00 2.10 $180 $180 990 11,000 110 1,300 

Natural Gas‐Driven Pneumatic

Controllers ‐ Oil and GasProduction

Replace w/ Low

Bleed 1.40 5.10 0.05 $210 ($630) 31,000 110,000 1,200 59,000 

Natural Gas‐Driven Pneumatic

Controllers ‐ Processing

Existing Instrument

Air System 0.28 1.00 0.01 $1,000 $190 3 11 0 22 

Natural Gas‐Driven Pneumatic

Pumps ‐  Production ‐ Diaphram

95% Control,

Existing

Combustion Device

0.91 3.30 0.03 $310 $310 4,000 14,000 150 8,800 

Natural Gas‐Driven Pneumatic

Pumps ‐  Production ‐ Piston

95% Control,

Existing

Combustion Device

0.10 0.36 0.004 $2,800 $2,800 430 1,600 17 8,700 

Storage Vessels

95% Control,

Combustion/VRUb a a a a a 23,000 4,800 730 260,000 

Total 82,000 220,000 3,000 380,000 

b ‐ Assumes that 94 percent of owners and operators would comply by using a combustion device and 6 percent would comply by using a VRU.

Note: Minor differences may result from rounding to 2 significant

figures.a ‐ There are a wide variety of storage vessel sizes, as well as rates of throughput for each storage vessel. Emissions and costs are directly related to the throughput of liquids for a give

emission reductions and costs per storage vessel, we used production rate brackets developed by the U.S. Energy Information Administration (EIA) for our emission estimates and costs 

Emission Source

Type of Control Emission Reduction Per Unit (tpy) VOC Cost of Control ($/ton) Emission Reductions (tpy) RACT V
ATTACHMENT 1 

Moderate or Higher Ozone NA Areas 
A1 - 2 

Moderate or Higher Ozone NA Areas 

State County Name NA Area Name 

CA Amador County Amador and Calaveras Cos. (Central Mountain Cos.) 

CA Calaveras County Amador and Calaveras Cos. (Central Mountain Cos.) 

CA El Dorado County Sacramento Metro 

CA Fresno County San Joaquin Valley 

CA Imperial County Imperial County Area 

CA Kern County Kern County (Eastern Kern) 

CA Kings County San Joaquin Valley 

CA Los Angeles County 

Los Angeles and San Bernardino Counties (Western 

Mojave Desert) 

CA Madera County San Joaquin Valley 

CA Mariposa County 

Mariposa and Tuolumne Cos. (Southern Mountain 

Counties) 

CA Merced County San Joaquin Valley 

CA Nevada County Nevada County (Western part) 

CA Orange County Los Angeles-South Coast Air Basin 

CA Placer County Sacramento Metro 

CA Riverside County Los Angeles-South Coast Air Basin 

CA Sacramento County Sacramento Metro 

CA San Bernardino County 

Los Angeles and San Bernardino Counties (Western 

Mojave Desert) 

CA San Joaquin County San Joaquin Valley 

CA Solano County Sacramento Metro 

CA Stanislaus County San Joaquin Valley 

CA Sutter County Sacramento Metro 

CA Tulare County San Joaquin Valley 

CA Tuolumne County 

Mariposa and Tuolumne Cos. (Southern Mountain 

Counties) 

CA Ventura County Ventura County 

CA Yolo County Sacramento Metro 

CT Fairfield County New York-N. New Jersey-Long Island Area 

CT Hartford County Greater Connecticut Area 

CT Litchfield County Greater Connecticut Area 

CT Middlesex County New York-N. New Jersey-Long Island Area 

CT New Haven County New York-N. New Jersey-Long Island Area 

CT New London County Greater Connecticut Area 

CT Tolland County Greater Connecticut Area 

CT Windham County Greater Connecticut Area 

DE Kent County Philadelphia-Wilmington-Atlantic City Area 

DE New Castle County Philadelphia-Wilmington-Atlantic City Area 
A1 - 3 

State County Name NA Area Name 

DE Sussex County Philadelphia-Wilmington-Atlantic City Area 

DC District of Columbia Washington Area 

MD Anne Arundel County Baltimore 

MD Baltimore County Baltimore 

MD Calvert County Washington Area 

MD Carroll County Baltimore 

MD Cecil County Philadelphia-Wilmington-Atlantic City Area 

MD Charles County Washington Area 

MD Frederick County Washington Area 

MD Harford County Baltimore 

MD Howard County Baltimore 

MD Montgomery County Washington Area 

MD Prince George's County Washington Area 

MD Baltimore city Baltimore 

MA Barnstable County Boston-Lawrence-Worcester (E. Mass) Area 

MA Berkshire County Springfield (W. Mass) Area 

MA Bristol County Boston-Lawrence-Worcester (E. Mass) Area 

MA Dukes County Boston-Lawrence-Worcester (E. Mass) Area 

MA Essex County Boston-Lawrence-Worcester (E. Mass) Area 

MA Franklin County Springfield (W. Mass) Area 

MA Hampden County Springfield (W. Mass) Area 

MA Hampshire County Springfield (W. Mass) Area 

MA Middlesex County Boston-Lawrence-Worcester (E. Mass) Area 

MA Nantucket County Boston-Lawrence-Worcester (E. Mass) Area 

MA Norfolk County Boston-Lawrence-Worcester (E. Mass) Area 

MA Plymouth County Boston-Lawrence-Worcester (E. Mass) Area 

MA Suffolk County Boston-Lawrence-Worcester (E. Mass) Area 

MA Worcester County Boston-Lawrence-Worcester (E. Mass) Area 

NJ Atlantic County Philadelphia-Wilmington-Atlantic City Area 

NJ Bergen County New York-N. New Jersey-Long Island Area 

NJ Burlington County Philadelphia-Wilmington-Atlantic City Area 

NJ Camden County Philadelphia-Wilmington-Atlantic City Area 

NJ Cape May County Philadelphia-Wilmington-Atlantic City Area 

NJ Cumberland County Philadelphia-Wilmington-Atlantic City Area 

NJ Essex County New York-N. New Jersey-Long Island Area 

NJ Gloucester County Philadelphia-Wilmington-Atlantic City Area 

NJ Hudson County New York-N. New Jersey-Long Island Area 

NJ Hunterdon County New York-N. New Jersey-Long Island Area 

NJ Mercer County Philadelphia-Wilmington-Atlantic City Area 

NJ Middlesex County New York-N. New Jersey-Long Island Area 
A1 - 4 

State County Name NA Area Name 

NJ Monmouth County New York-N. New Jersey-Long Island Area 

NJ Morris County New York-N. New Jersey-Long Island Area 

NJ Ocean County Philadelphia-Wilmington-Atlantic City Area 

NJ Passaic County New York-N. New Jersey-Long Island Area 

NJ Salem County Philadelphia-Wilmington-Atlantic City Area 

NJ Somerset County New York-N. New Jersey-Long Island Area 

NJ Sussex County New York-N. New Jersey-Long Island Area 

NJ Union County New York-N. New Jersey-Long Island Area 

NJ Warren County New York-N. New Jersey-Long Island Area 

NY Bronx County New York-N. New Jersey-Long Island Area 

NY Chautauqua County Jamestown 

NY Dutchess County Poughkeepsie Area 

NY Erie County Buffalo-Niagara Falls 

NY Jefferson County Jefferson County Area 

NY Kings County New York-N. New Jersey-Long Island Area 

NY Nassau County New York-N. New Jersey-Long Island Area 

NY New York County New York-N. New Jersey-Long Island Area 

NY Niagara County Buffalo-Niagara Falls 

NY Orange County Poughkeepsie Area 

NY Putnam County Poughkeepsie Area 

NY Queens County New York-N. New Jersey-Long Island Area 

NY Richmond County New York-N. New Jersey-Long Island Area 

NY Rockland County New York-N. New Jersey-Long Island Area 

NY Suffolk County New York-N. New Jersey-Long Island Area 

NY Westchester County New York-N. New Jersey-Long Island Area 

PA Allegheny County Pittsburgh-Beaver Valley 

PA Armstrong County Pittsburgh-Beaver Valley 

PA Beaver County Pittsburgh-Beaver Valley 

PA Bucks County Philadelphia-Wilmington-Atlantic City Area 

PA Butler County Pittsburgh-Beaver Valley 

PA Chester County Philadelphia-Wilmington-Atlantic City Area 

PA Delaware County Philadelphia-Wilmington-Atlantic City Area 

PA Fayette County Pittsburgh-Beaver Valley 

PA Montgomery County Philadelphia-Wilmington-Atlantic City Area 

PA Philadelphia County Philadelphia-Wilmington-Atlantic City Area 

PA Washington County Pittsburgh-Beaver Valley 

PA Westmoreland County Pittsburgh-Beaver Valley 

RI Bristol County Providence (all of RI) Area 

RI Kent County Providence (all of RI) Area 

RI Newport County Providence (all of RI) Area 
A1 - 5 

State County Name NA Area Name 

RI Providence County Providence (all of RI) Area 

RI Washington County Providence (all of RI) Area 

TX Brazoria County Houston-Galveston-Brazoria Area 

TX Chambers County Houston-Galveston-Brazoria Area 

TX Collin County Dallas-Fort Worth 

TX Dallas County Dallas-Fort Worth 

TX Denton County Dallas-Fort Worth 

TX Ellis County Dallas-Fort Worth 

TX Fort Bend County Houston-Galveston-Brazoria Area 

TX Harris County Houston-Galveston-Brazoria Area 

TX Johnson County Dallas-Fort Worth 

TX Kaufman County Dallas-Fort Worth 

TX Liberty County Houston-Galveston-Brazoria Area 

TX Montgomery County Houston-Galveston-Brazoria Area 

TX Parker County Dallas-Fort Worth 

TX Rockwall County Dallas-Fort Worth 

TX Tarrant County Dallas-Fort Worth 

TX Waller County Houston-Galveston-Brazoria Area 

TX Wise County Dallas-Fort Worth 

VA Arlington County Washington Area 

VA Fairfax County Washington Area 

VA Loudoun County Washington Area 

VA Prince William County Washington Area 

VA Alexandria city Washington Area 

VA Fairfax city Washington Area 

VA Falls Church city Washington Area 

VA Manassas city Washington Area 

VA Manassas Park city Washington Area 

WI Sheboygan County Sheboygan Area 
ATTACHMENT 2 

ONG CTG – RACT-Impacted Population of Storage Vessels and RACTImpacted Storage Vessel Baseline Emissions, Emission Reductions and Costs 
A2-2 

Table A2-1. Number of RACT-Impacted Oil Storage Vessels 

Well Productivity 

Bracket (bbls/day range) 

Representative 

(bbls/day) 

Number of RACTImpacted Storage Vessels – 

2012 

Number of Storage Vessels 

Not Impacted by RACT 

>0-1 0.385 0 34,577 

1-2 1.34 0 8,727 

2-4 2.66 0 10,589 

4-6 4.45 0 6,174 

6-8 6.22 0 4,228 

8-10 8.08 0 3,361 

10-12 9.83 0 2,592 

12-15 12.1 0 2,880 

15-20 15.4 0 3,177 

20-25 19.9 0 2,017 

25-30 24.3 0 1,306 

30-40 30.5 1,086 423 

40-50 39.2 505 197 

50-100 61.6 755 279 

100-200 120 104 64 

200-400 238 13 21 

400-800 456 0 2 

800-1600 914 0 0 

1600-3200 1,692 0 1 

3200-6400 3,353 0 0 

6400-12800 6,825 0 0 

TOTAL 2,462 80,616 
A2-3 

Total A2-2. Number of RACT-Impacted Condensate Storage Vessels 

Well Productivity Bracket 

(bbls/day range) 

Representative 

(bbls/day) 

CTG Covered 

Vessels 2012 

Total Number of Vessels Not 

Covered by RACT 

>0-1 635 0 80,133 

1-2 349 0 257 

2-4 648 0 127 

4-6 766 0 48 

6-8 640 0 10 

8-10 525 0 12 

10-12 408 0 9 

12-15 564 0 7 

15-20 758 0 5 

20-25 674 0 2 

25-30 531 0 0 

30-40 927 0 1 

40-50 747 0 0 

50-100 2,691 0 0 

100-200 3,800 0 0 

200-400 2,705 0 0 

400-800 1,165 0 0 

800-1600 348 0 0 

1600-3200 69 0 0 

3200-6400 37 0 0 

6400-12800 5 0 0 

>12800 0 0 0 

TOTAL 0 80,611 
A2-4 

Table A2-3. RACT-Impacted Oil Storage Vessel Baseline Emissions 

Well Productivity Bracket (bbls/day 

range) 

Representative 

(bbls/day) 

Average Baseline Emissions per Unit 

(tpy/unit) 

Nationw

VOC Methane HAP VOC 

>0-1 0.385 0.083 0.017 0.003 0 

1-2 1.34 0.287 0.059 0.009 0 2-4 2.66 0.570 0.118 0.018 0 4-6 4.45 0.953 0.197 0.030 0 6-8 6.22 1.33 0.28 0.04 0 

8-10 8.08 1.73 0.36 0.05 0 

10-12 9.83 2.11 0.44 0.07 0 12-15 12.1 2.59 0.54 0.08 0 15-20 15.4 3.31 0.68 0.10 0 20-25 19.9 4.27 0.88 0.13 0 25-30 24.3 5.22 1.08 0.16 0 30-40 30.5 6.54 1.35 0.21 6,749 40-50 39.2 8.41 1.74 0.26 4,033 

50-100 61.6 13.2 2.7 0.4 9,470 

100-200 120 25.6 5.3 0.8 2,524 200-400 238 51.0 10.6 1.6 611 400-800 456 97.7 20.2 3.1 0 

800-1600 914 196.0 40.6 6.2 0 

1600-3200 1,692 362.9 75.1 11.4 0 3200-6400 3,353 719.1 148.8 22.6 0 

6400-12800 6,825 1463.7 302.9 45.9 0 

TOTAL 23,386 
A2-5 

Table A2-4. RACT-Impacted Condensate Storage Vessel Baseline Emissions Well Productivity Bracket 

(bbls/day range) 

Representative 

(bbls/day) 

Average Baseline Emissions per Unit (tpy/unit) Nationwide Baseline Emissio

VOC Methane HAP VOC Methane 

>0-1 635 0.038 0.008 0.001 0 0 

1-2 349 0.168 0.037 0.005 0 0 2-4 648 0.318 0.070 0.009 0 0 4-6 766 0.573 0.126 0.017 0 0 6-8 640 0.82 0.18 0.02 0 0 

8-10 525 1.04 0.23 0.03 0 0 

10-12 408 1.37 0.30 0.04 0 0 12-15 564 1.53 0.34 0.04 0 0 15-20 758 2.10 0.46 0.06 0 0 20-25 674 3.32 0.73 0.10 0 0 25-30 531 3.85 0.85 0.11 0 0 30-40 927 5.33 1.17 0.16 0 0 40-50 747 7.59 1.67 0.22 0 0 

50-100 2,691 11.7 2.6 0.3 0 0 

100-200 3,800 25.4 5.6 0.7 0 0 200-400 2,705 49.8 11.0 1.5 0 0 400-800 1,165 92.3 20.3 2.7 0 0 

800-1600 348 142.2 31.3 4.2 0 0 

1600-3200 69 310.7 68.5 9.1 0 0 3200-6400 37 489.9 107.9 14.4 0 0 

6400-12800 5 1864.4 410.8 54.7 0 0 

>12800 0 0 0 0 0 0 
A2-6 

Table A2-5. RACT-Impacted Oil Storage Vessel Emission Reductions 

Well Productivity 

Bracket 

(bbls/day range) 

Representative 

(bbls/day) 

Average Emission Reductions 

Per Unit (tpy) Assuming 95% 

Reduction 

Nationwide Emissions Reductions 

2012 

Natural G

Saved 

Mcf/yr/un

VOC Methane HAP VOC Methane HAP 

>0-1 0.385 0.078 0.016 0.002 0 0 0.000 2.7 

1-2 1.34 0.272 0.056 0.009 0 0 0.000 9.2 2-4 2.66 0.542 0.112 0.017 0 0 0.000 18.3 4-6 4.45 0.906 0.187 0.028 0 0 0.000 30.6 6-8 6.22 1.27 0.26 0.04 0 0 0.000 42.9 

8-10 8.08 1.65 0.34 0.05 0 0 0.000 55.7 

10-12 9.83 2.00 0.41 0.06 0 0 0.000 67.8 12-15 12.1 2.46 0.51 0.08 0 0 0.000 83.2 15-20 15.4 3.14 0.65 0.10 0 0 0.000 106.3 20-25 19.9 4.05 0.84 0.13 0 0 0.000 137.1 25-30 24.3 4.96 1.03 0.16 0 0 0.000 167.7 30-40 30.5 6.21 1.29 0.20 6755 1398 212 210.1 40-50 39.2 7.99 1.65 0.25 4033 835 127 270.3 

50-100 61.6 12.5 2.6 0.4 9470 1960 297 424.2 

100-200 120 24.4 5.0 0.8 2524 522 79 823.9 200-400 238 48.5 10.0 1.5 611 126 19 1638.9 400-800 456 92.8 19.2 2.9 0 0 0.000 3139.0 

800-1600 914 186.2 38.5 5.8 0 0 0.000 6297.8 

1600-3200 1,692 344.8 71.4 10.8 0 0 0.000 11660.3 3200-6400 3,353 683.2 141.4 21.4 0 0 0.000 23105.8 

6400-12800 6,825 1390.5 287.8 43.6 0 0 0.000 47028.1 

TOTAL 23,392 4,842 734 
A2-7 

Table A2-6. RACT-Impacted Condensate Storage Vessel Emission Reductions 

Well Productivity 

Bracket (bbls/day 

range) 

Representative 

(bbls/day) 

Average Emission Reductions 

Per Unit (tpy) assuming 95% 

reduction Nationwide Emissions Reductions 2012 

Natural G

Saved 

Mcf/yr/un

VOC Methane HAP VOC Methane HAP 

>0-1 635 0.036 0.008 0.001 0 0 0 1.151 

1-2 349 0.159 0.035 0.005 0 0 0 5.051 2-4 648 0.302 0.067 0.009 0 0 0 9.558 4-6 766 0.545 0.120 0.016 0 0 0 17.252 6-8 640 0.78 0.17 0.02 0 0 0 24.818 

8-10 525 0.99 0.22 0.03 0 0 0 31.423 

10-12 408 1.30 0.29 0.04 0 0 0 41.27 12-15 564 1.46 0.32 0.04 0 0 0 46.16 15-20 758 1.99 0.44 0.06 0 0 0 63.11 20-25 674 3.15 0.70 0.09 0 0 0 99.91 25-30 531 3.65 0.81 0.11 0 0 0 115.68 30-40 927 5.07 1.12 0.15 0 0 0 160.4 40-50 747 7.21 1.59 0.21 0 0 0 228.4 

50-100 2,691 11.1 2.5 0.3 0 0 0 352.6 

100-200 3,800 24.1 5.3 0.7 0 0 0 763 200-400 2,705 47.3 10.4 1.4 0 0 0 1498 400-800 1,165 87.7 19.3 2.6 0 0 0 2777 

800-1600 348 135.1 29.8 4.0 0 0 0 4277 

1600-3200 69 295.1 65.0 8.7 0 0 0 9346 3200-6400 37 465.4 102.5 13.6 0 0 0 14737 

6400-12800 5 1771.2 390.3 51.9 0 0 0 56086 

>12800 0 0.0 0.0 0.0 0 0 0 0.000 
A2-8 

Table A2-7. RACT-Impacted Oil Storage Vessel VRU and Combustor Costs 

Well 

Productivity 

Bracket 

(bbls/day 

range) 

Route Emissions to a VRU Route Emissions to a Co

Total Capital 

Cost Per Unit 

($) 

Total Annual Cost Per 

Unit ($/yr) 

VOC Cost of Control 

($/ton) Total Capital Cost Per 

Unit ($) 

Total Annual Cost 

Per Unit ($/yr) 

w/o 

savings w/ savings w/o savings w/ savings w/o savings w/ savings 

>0-1 $171,538 $28,230 $28,219 $359,638 $359,503 $100,986 $22,228 $22,228 

1-2 $171,538 $28,230 $28,193 $103,714 $103,579 $100,986 $22,228 $22,228 2-4 $171,538 $28,230 $28,157 $52,104 $51,969 $100,986 $22,228 $22,228 4-6 $171,538 $28,230 $28,107 $31,170 $31,035 $100,986 $22,228 $22,228 6-8 $171,538 $28,230 $28,058 $22,261 $22,126 $100,986 $22,228 $22,228 

8-10 $171,538 $28,230 $28,007 $17,144 $17,009 $100,986 $22,228 $22,228 

10-12 $171,538 $28,230 $27,959 $14,092 $13,957 $100,986 $22,228 $22,228 12-15 $171,538 $28,230 $27,897 $11,478 $11,342 $100,986 $22,228 $22,228 15-20 $171,538 $28,230 $27,805 $8,986 $8,851 $100,986 $22,228 $22,228 20-25 $171,538 $28,230 $27,682 $6,963 $6,828 $100,986 $22,228 $22,228 25-30 $171,538 $28,230 $27,559 $5,692 $5,557 $100,986 $22,228 $22,228 30-40 $171,538 $28,230 $27,390 $4,544 $4,409 $100,986 $22,228 $22,228 40-50 $171,538 $28,230 $27,149 $3,532 $3,397 $100,986 $22,228 $22,228 

50-100 $171,538 $28,230 $26,533 $2,251 $2,115 $100,986 $22,228 $22,228 

100-200 $171,538 $28,230 $24,934 $1,159 $1,024 $100,986 $22,228 $22,228 200-400 $171,538 $28,230 $21,675 $583 $447 $100,986 $22,228 $22,228 400-800 $171,538 $28,230 $15,674 $304 $169 $100,986 $22,228 $22,228 

800-1600 $171,538 $28,230 $3,039 $152 $16 $100,986 $22,228 $22,228 

1600-3200 $171,538 $28,230 -$18,411 $82 -$53 $100,986 $22,228 $22,228 3200-6400 $171,538 $28,230 -$64,193 $41 -$94 $100,986 $22,228 $22,228 

6400-12800 $171,538 $28,230 -$159,882 $20 -$115 $100,986 $22,228 $22,228 
A2-9 

Table A2-8. RACT-Impacted Condensate Storage Vessel VRU and Combustor Costs 

Well 

Productivity 

Bracket 

(bbls/day 

range) 

Routing Emissions to a VRU Routing to a Combu

Total Capital 

Cost Per Unit 

($) 

Total Annual Cost Per 

Unit ($/yr) 

VOC Cost Effectiveness 

($/ton) Total Capital Cost Per Unit 

($) 

Total Annual Cost 

Per Unit ($/yr) 

w/o 

savings w/ savings w/o savings w/ savings w/o savings w/ savings 

>0-1 $171,538 $28,230 $28,225 $776,897 $776,770 $100,986 $22,228 $22,228 

1-2 $171,538 $28,230 $28,210 $176,996 $176,870 $100,986 $22,228 $22,228 2-4 $171,538 $28,230 $28,192 $93,529 $93,402 $100,986 $22,228 $22,228 4-6 $171,538 $28,230 $28,161 $51,817 $51,690 $100,986 $22,228 $22,228 6-8 $171,538 $28,230 $28,131 $36,020 $35,893 $100,986 $22,228 $22,228 

8-10 $171,538 $28,230 $28,104 $28,449 $28,322 $100,986 $22,228 $22,228 

10-12 $171,538 $28,230 $28,065 $21,663 $21,537 $100,986 $22,228 $22,228 12-15 $171,538 $28,230 $28,045 $19,367 $19,240 $100,986 $22,228 $22,228 15-20 $171,538 $28,230 $27,978 $14,166 $14,039 $100,986 $22,228 $22,228 20-25 $171,538 $28,230 $27,830 $8,948 $8,821 $100,986 $22,228 $22,228 25-30 $171,538 $28,230 $27,767 $7,727 $7,601 $100,986 $22,228 $22,228 30-40 $171,538 $28,230 $27,588 $5,573 $5,446 $100,986 $22,228 $22,228 40-50 $171,538 $28,230 $27,316 $3,914 $3,787 $100,986 $22,228 $22,228 

50-100 $171,538 $28,230 $26,820 $2,535 $2,409 $100,986 $22,228 $22,228 

100-200 $171,538 $28,230 $25,177 $1,171 $1,045 $100,986 $22,228 $22,228 200-400 $171,538 $28,230 $22,239 $597 $470 $100,986 $22,228 $22,228 400-800 $171,538 $28,230 $17,120 $322 $195 $100,986 $22,228 $22,228 

800-1600 $171,538 $28,230 $11,122 $209 $82 $100,986 $22,228 $22,228 

1600-3200 $171,538 $28,230 -$9,152 $96 -$31 $100,986 $22,228 $22,228 3200-6400 $171,538 $28,230 -$30,717 $61 -$66 $100,986 $22,228 $22,228 

6400-12800 $171,538 $28,230 -$196,116 $16 -$111 $100,986 $22,228 $22,228 

>12800 $171,538 $28,230 $28,230 $0 $0 $100,986 $22,228 $22,228 
A2-10 

Table A2-9. RACT-Impacted Oil Storage Vessel Nationwide Costs 

Well Productivity Bracket 

 (bbls/day range) 

Representative 

(bbls/day) 

Total Nationwide Cos

Capital ($) Annual w/o savings ($/yr) 

>0-1 0.385 $0 $0 

1-2 1.34 $0 $0 2-4 2.66 $0 $0 4-6 4.45 $0 $0 6-8 6.22 $0 $0 

8-10 8.08 $0 $0 

10-12 9.83 $0 $0 12-15 12.1 $0 $0 15-20 15.4 $0 $0 20-25 19.9 $0 $0 25-30 24.3 $0 $0 30-40 30.5 $117,473,197 $24,821,102 40-50 39.2 $54,517,590 $11,519,110 

50-100 61.6 $81,571,106 $17,235,291 

100-200 120 $11,193,068 $2,365,002 200-400 238 $1,361,319 $287,635 400-800 456 $0 $0 

800-1600 914 $0 $0 

1600-3200 1,692 $0 $0 3200-6400 3,353 $0 $0 

6400-12800 6,825 $0 $0 

TOTAL $266,116,280 $56,228,139 
A2-11 

Table A2-10. RACT-Impacted Condensate Storage Vessel Nationwide Costs 

Well Productivity Bracket 

(bbls/day range) 

Representative 

(bbls/day) 

Total Nationwide Cos

Capital ($) Annual w/o savings ($/yr) 

>0-1 635 $0 $0 

1-2 349 $0 $0 2-4 648 $0 $0 4-6 766 $0 $0 6-8 640 $0 $0 

8-10 525 $0 $0 

10-12 408 $0 $0 12-15 564 $0 $0 15-20 758 $0 $0 20-25 674 $0 $0 25-30 531 $0 $0 30-40 927 $0 $0 40-50 747 $0 $0 

50-100 2,691 $0 $0 

100-200 3,800 $0 $0 200-400 2,705 $0 $0 400-800 1,165 $0 $0 

800-1600 348 $0 $0 

1600-3200 69 $0 $0 3200-6400 37 $0 $0 

6400-12800 5 $0 $0 

>12800 0 $0 $0 

TOTAL $0 $0 
ATTACHMENT 3 

Oil and Natural Gas CTG – Storage Vessels Covered By State Regulation 
A3-2 

 This attachment presents an analysis of state regulations that estimates the number of 

existing storage vessels that are subject to a RACT-equivalent or greater level of control. The 

number of storage vessels determined to be subject to a RACT-equivalent or greater level of 

control was subtracted from the number of storage vessels that were located in RACT-impacted 

areas that we assumed emit greater than or equal to six tpy. There may be more storage vessels 

regulated or permitted at a greater or equivalent level of control to the recommended RACT that 

have not been accounted for in this analysis (e.g., based on case-by-case permit limits). 
EPA_WELL_TY

PE

EPA_PROD_BRACKET

CA

CA State

Covered

CA CTG

Covered

CA Not

Covered MD

MD CTG

Covered NY

NAA NY

CTG

Covered

01. 0‐1 7,364 0 0 7,364 0 3,216 0 

02. 1‐2 5,798 0 0 5,798 0 65 0 03. 2‐4 8,039 0 0 8,039 0 33 0 04. 4‐6 5,550 0 0 5,550 0 1 0 05. 6‐8 3,906 0 0 3,906 0 0 0 06. 8‐10 3,013 0 0 3,013 0 1 0 07. 10‐12 2,407 0 0 2,407 0 1 0 

08. 12‐15 2,668 0 0 2,668 0 0 0 

09. 15‐20 2,968 0 0 2,968 0 0 0 

10. 20‐25 1,882 0 0 1,882 0 0 0 

11. 25‐30 1,183 0 0 1,183 0 0 0 

12. 30‐40 1,409 423 986 0 0 0 0 0 

13. 40‐50 658 197 461 0 0 0 0 0 

14. 50‐100 930 279 651 0 0 0 0 0 

15. 100‐200 148 44 104 0 0 0 0 0 16. 200‐400 18 5 13 0 0 0 0 0 17. 400‐800 0 0 0 0 0 0 0 0 18. 800‐1600 0 0 0 0 0 0 0 0 19. 1600‐3200 0 0 0 0 0 0 0 0 

1. Oil Total 47,941 949 2,214 44,778 0 0 3,317 0 

No

1. Oil

all

none

no

soso

N

CALIFORNIA MARYLAND NEW 

Wells in NAA

Wellsin OTR

Wellsinboth NAA and OTR

State Regulations

all

nonenone

Yes

none
A3-4 

01. 0‐1 844 0 0 844 1 0 7,074 0 02. 1‐2 20 0 0 20 0 0 0 0 03. 2‐4 11 0 0 11 0 0 0 0 

04. 4‐6 6006000005. 6‐8 3003000006. 8‐10 2 0 0 2 0 0 0 0 07. 10‐12 0 0 0 0 0 0 0 0 

08. 12‐15 2 0 0 2 0 0 0 0 

09. 15‐20 1 0 0 1 0 0 0 0 

10. 20‐25 1 0 0 1 0 0 0 0 

11. 25‐30 0 0 0 0 0 0 0 0 

12. 30‐40 0 0 0 0 0 0 0 0 

13. 40‐50 0 0 0 0 0 0 0 0 

14. 50‐100 0 0 0 0 0 0 0 0 

15. 100‐200 0 0 0 0 0 0 0 0 16. 200‐400 0 0 0 0 0 0 0 0 17. 400‐800 0 0 0 0 0 0 0 0 18. 800‐1600 0 0 0 0 0 0 0 0 19. 1600‐3200 0 0 0 0 0 0 0 0 

2. Gas Total 890 0 0 890 1 0 7,074 0 

2. Gas
A3-5 

EPA_WELL_TYPE

EPA_PROD_BRACKET

PA

NAA PA

CTG

Covered

OTR PA

CTG

Covered

Combined PA CTG

Covered

TX

TX State

Covered

TX CTG

Covered

TX No

Covere

01. 0‐1 18,593 0 0 0 5,380 0 0 5,380 

02. 1‐2 915 0 0 0 1,948 0 0 1,948 

03. 2‐4 160 0 0 0 2,357 0 0 2,357 

04. 4‐6 23 0 0 0 600 0 0 600 

05. 6‐8 9 0 0 0 313 0 0 313 

06. 8‐10 48 0 0 0 299 0 0 299 

07. 10‐12 11 0 0 0 173 0 0 173 

08. 12‐15 27 0 0 0 185 0 0 185 

09. 15‐20 34 0 0 0 175 0 0 175 

10. 20‐25 15 0 0 0 120 0 0 120 

11. 25‐30 16 0 0 0 107 0 0 107 

12. 30‐40 3 0 0 3 97 0 97 0 

13. 40‐50 5 0 0 5 39 0 39 0 

14. 50‐100 3 0 0 3 101 0 101 0 

15. 100‐200 0 0 0 0 20 20 0 0 

16. 200‐400 0 0 0 0 16 16 0 0 

17. 400‐800 0 0 0 0 2 2 0 0 

18. 800‐1600 0 0 0 0 0 0 0 0 

19. 1600‐3200 0 0 0 0 1 1 0 0 

1. Oil Total 19,862 0 0 11 11,933 39 237 11,657 1. Oil

all

nonenone

Yes

TEXAS 

none

somesome

No

PENNSYLVANIA

Wells in NAA

Wellsin OTR

Wells inboth NAA and OTR

State Regulations
A3-6 

01. 0‐1 52,109 0 0 0 14,241 0 0 14,241 

02. 1‐2 32 0 0 0 205 0 0 205 

03. 2‐4 26 0 0 0 90 0 0 90 

04. 4‐6 10 0 0 0 32 0 0 32 

05. 6‐8 5 0 002 0 02

06. 8‐10 6 0 0 0 4 0 0 4 

07. 10‐12 7 0 0 0 2 0 0 2 

08. 12‐15 3 0 0 0 2 0 0 2 

09. 15‐20 0 0 0 0 4 0 0 4 

10. 20‐25 0 0 0 0 1 0 0 1 

11. 25‐30 0 0 0 0 0 0 0 0 

12. 30‐40 0 0 0 0 1 0 0 1 

13. 40‐50 0 0 0 0 0 0 0 0 

14. 50‐100 0 0 0 0 0 0 0 0 

15. 100‐200 0 0 0 0 0 0 0 0 

16. 200‐400 0 0 0 0 0 0 0 0 

17. 400‐800 0 0 0 0 0 0 0 0 

18. 800‐1600 0 0 0 0 0 0 0 0 

19. 1600‐3200 0 0 0 0 0 0 0 0 

2. Gas Total 52,198 0 35,957 16,241 14,584 0 0 14,584 

2. Gas