# Oil and Natural Gas Indus try Estimated Reasonab ly Available Control

Technology Emission Reductio ns and Cost of Control

1.0 INTRODUCTION

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

nonattainment (NA) areas must include reasonab ly 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 in clude RACT for volatile organic compound (VOC)

emission sources covered by contro l 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 tr ibal air agencies (air agencies) with

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

industry emission sources. During the developmen t 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 contro l approaches to reduce these em issions, including the costs of

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

pneumatic controllers, natural gas-driven pneuma tic 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 recomm ended 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, requirement s 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 an d natural gas industry. It provides only recommendations for air agencies

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

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

based on a snapshot of the existing oil and na tural 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 imp act of the RACT requirements ultimately

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

reductions and net expenditures required by the in dustry 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 appr oximately $76 million dollars based on the CTG

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

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

three thousand tpy.

The assessment provides a reasonable estima te of the magnitude of expected emission

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

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

dimensions. For example, while the analysis atte mpts to include existi ng state regulations, the

2012 snapshot may not fully account for state perm it limits for individual s ources that meet or

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

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

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

result of the CTG. Also, air agen cies have the flexibility of de termining RACT that may differ

from what the EPA recommends. This flexibility allows them to potentia lly 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 c ontrol or may affect a lower number of sources

than were included in the anal ysis 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 a bout the moderate or higher ozone NA and

OTR areas impacted by RACT.

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

sources, baseline emissions, emi ssion 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 reduc tions and costs.

# 3 

# Table 1-1. Summary of the Oil and Natura l 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 existin g 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 mode rate or higher ozone NA area and OTR area

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

RACT recommendations, we obtained informati on 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 th is analysis is presente d in Attachment 1 to

this memorandum. The OTR areas included in th is 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 Distri ct of Columbia).

3 INFORMATION USED TO DETE RMINE THE NUMBER OF SOURCES

IMPACTED BY RACT, RACT-IMPACT ED AREA BASELINE EMISSIONS AND

EMISSION REDUCTIONS AND COSTS BASED ON RACT

Activity data, baseline emissions and emi ssion 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 informati on 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, locati on and capacities of gas processing plants

worldwide. Discussed further below.

 Emissions information and counts for variou s emission sources were obtained from

facility-level data submitted to the Gr eenhouse 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 sour ces 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 base line 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 va rious 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 calculati ons 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 collecte d by DrillingInfo, Inc. consists of oil and natural gas well

information that provides parameters desc ribing the location, opera tor, and production

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

population of all wells with gas or hydrocar bon 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 iden tify oil and natural ga s wells in production

in 2012 in RACT-impacted areas using Federal In formation 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 barre l over the lifetime of the well,

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

standard cubic feet per barrel ove r 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 pr oduction but no liquids

production, it was classi fied as a gas well.

As a result of this analysis, for all pr oducing 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 we lls) were identified in OTR areas. An

estimated 22,426 oil and gas wells (1,249 oil we lls 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 highe r 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 well s 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 o il and gas data and statisti cal 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 produ cing wells and individual well sites with

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

moderate or higher ozon e NA areas (as noted),

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

ozone NA areas (assuming one storage vessel per well 12 

# ),

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

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

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

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

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

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

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

Production)

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

reflect capacities for 2012) was used to obtain location informa tion 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 na tural gas processing plants were located in OTR

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

processing plants in moderate or higher ozone NA areas were locat ed 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 natu ral gas processing plants in OTR and

moderate or higher ozone NA areas,

 estimate the number of processing segmen t compressors and pneumatic controllers

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

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

areas), and

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

or higher ozone NA areas (using the averag e 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 of ten more than one storage vessel per well site. However, for emissions

calculation purposes, we assumed that a ll 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 met hodologies used to estimate RACT-impacted

area baseline emissions, emission re ductions and costs for storage ve ssels, 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 emissi on 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 es timated 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 stor age vessels by costs per storage vessel.

4.1.2 RACT-Impacted Population of Storage Vessels

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

RACT, we conducted an analysis using the following procedures:

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

2012 (assuming one controlled storage ve ssel 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 subj ect to and presumed to be controlled at

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

potentially be impacted by RACT,

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

established under the NSPS 13 

# 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 recomme nded 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 t py that would also be subjec t 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 ve ssels 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 in clude the RACT-impacted storage vessel

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

Table 4-1. RACT-Impacted Po pulation of Storage Vessels

Emission

Source Number of RACT-Impac ted 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 emissi on factors based on well production rate

brackets developed under the NSPS 14 

# and 2012 DI Desktop production information, we

calculated the RACT-impacted number of storage vessels an d 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 cap ture and recovery. Using VOC to methane and

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

Composition memorandum, we estimated methan e and HAP baseline emissions and emission

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

baseline emissions. RACT-impacted storage vess el 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 CH 4 

# HAP VOC CH 4 

# HAP VOC CH 4 

# HAP

Storage

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

# 11 

# Table 4-3. RACT-Impacted Storag e Vessel Emission Reductions a



# 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 CH 4 

# HAP VOC CH 4 

# HAP VOC CH 4 

# 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 c ontrol 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 pe rcent 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 co sts and annual costs used for a VRU used was $171,538 and

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

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

valued at $4 per Mcf of recovered natural gas. No gas savings was attri buted 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).12Table 4-4. RACT-Impacted Storage Vessel CostsaEmissionPointModerate or Higher Ozone NA AreasOutside of OTR AreasOTR AreasModerate or Higher Ozone NA Areas/OTRAreasCapital ($)Annual w/osavings($/yr)Annual w/savings($/yr)Capital ($)Annual w/osavings($/yr)Annual w/savings($/yr)Capital ($)Annual w/osavings($/yr)Annual w/savings($/yr)StorageVessel$257,902,585 $55,365,741 $55,176,698 $1,157,410 $248,469 $247,688 $259,059,995 $55,614,210 $55,424,387aAssumes 94 percent of sources will use a combustion control device and 6 percent will use a VRU to comply with the recommendedRACT.

# 13 

# 4.2 Natural Gas-Driven Pneumatic Controllers

4.2.1 Approach

RACT-impacted natural gas-driven pneuma tic controller baseline emissions and

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

natural gas-driven) by emissions and emission reductions per controll er. 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 pro cessing segment nationall y. 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 GH G 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 lo cated in RACT-impacted areas.

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

pneumatic controllers.

Table 4-5. RACT-Impacted Population of Na tural 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 Pn eumatic Controller Baseline Emissions,

Emission Reductions and Costs

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

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

VOC, methane and HAP baseline em issions 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 contro ller. For processing segment natural gas-driven

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

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

we used the emission reductions and costs asso ciated with the replacem ent 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 th e 2011 Gas Composition memorandum, we estimated

RACT-impacted natural gas-driven pneumatic c ontroller 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. Ta bles 4-8 and 4-9 present the RACT-impacted

natural gas-driven pneum atic controller costs.15Table 4-6. RACT-Impacted Natural Gas-DrivenPneumatic Controller Baseline EmissionsSegmentBaseline Emissions Per NaturalGas-Driven Pneumatic Controller(tpy)RACT-Impacted Pneumatic Controller Baseline Emissions (tpy)Moderate or Higher Ozone NAAreas Outside of OTR AreasOTR AreasModerate or Higher Ozone NAAreas /OTR AreasVOCCH4HAPVOCCH4HAPVOCCH4HAPVOCCH4HAPOil and NaturalGas Production1.5 5.3 0.055 15,057 54,162 567 17,189 61,831 647 32,246 115,993 1,214ProcessingPlants0.28 1.0 0.01 2.5 8.9 0.9 0.62 2.2 0.02 3.1 11 0.12Table 4-7. RACT-Impacted Natural Gas-DrivenPneumatic Controller Emission ReductionsSegmentType ofControlEmission Reductions PerPneumatic Controller (tpy)RACT-Impacted Pneumatic Controller Emission Reductions (tpy)Moderate or Higher OzoneNA Areas Outside of OTRAreasOTR AreasModerate or Higher OzoneNA Areas/OTR AreasVOCMethaneHAPVOCCH4HAPVOCCH4HAPVOCCH4HAPOil andNatural GasProductionReplace w/Low Bleed1.4 5.10 0.05 14,444 52,118 546 16,489 59,498 623 30,933 111,616 1,169ProcessingPlantsExistingInstrumentAir System0.28 1.0 0.01 2.5 8.9 0.09 0.62 2.2 0.02 3.1 11 0.1216Table 4-8. Total Annual Costs and VOC Cost of Control Per Natural Gas-Driven Pneumatic ControllerSegmentNaturalGasSavingsPerSource(Mcf)Total Valueof NaturalGas SavingsPer Source($/yr)Total CapitalCosts PerSource ($)Total Annual CostsPer Source ($/yr)VOC Cost of Control ($/ton ofVOC reduced)w/o savingsw/ savingsw/o savingsw/ savingsOil and Gas Production 296 $1,184 $2,698 $296($886)$210($627)Processing Plants 58 $232 $2,000 $285 $53 $1,018 $190Table 4-9. RACT-Impacted Natural Gas-Driven Pneumatic Controller CostsSegmentModerate or Higher OzoneNA Areas Outside of OTRAreasOTR AreasModerate or Higher Ozone NA Areas/OTRAreasCapital ($)Annual w/osavings ($yr)Annual w/savings($/yr)Capital ($)Annual w/osavings($/yr)Annual w/savings ($/yr)Capital ($)Annual w/osavings($/yr)Annual w/savings ($/yr)Oil and GasProduction$27,571,450 $3,027,197($9,054,192)$31,475,544 $3,455,846($10,336,259)$59,046,994 $6,483,043($19,390,451)ProcessingPlants$17,822 $2,540 $474 $4,455 $635 $118 $22,277 $3,175 $592

# 17 

# 4.3 Natural Gas-Driven Pneumatic Pumps

4.3.1 Approach

RACT-impacted natural gas-driven pneuma tic pump baseline emissions and emission

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

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

gas-driven pneumatic pump costs were estima ted 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 diaphr agm 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 pum ps to be piston pumps. Based on these

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

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

pumps in the production segment nationally. Th e 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-i mpacted 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 Pneuma tic 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-dr iven 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 develo ped 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 develope d for the oil and natural gas industry as

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

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

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

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

natural gas-driven pneumatic pump costs.19Table 4-11. RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseline EmissionsEmissionSourceBaseline Emissions Per Natural GasDriven Pneumatic Pump (tpy)RACT-Impacted Natural Gas-Driven Pneumatic Pump Baseline Emissions (tpy)Moderate or Higher NA AreasOutside of OTR AreasOTR AreasModerate or Higher Ozone NAAreas/OTR AreasVOCCH4HAPVOCCH4HAPVOCCH4HAPVOCCH4HAPDiaphragm 0.96 3.5 0.04 1,966 7,087 74 2,245 8,091 85 4,211 15,178 159Piston 0.11 0.38 0.004 225 776 8.1 256 885 9.3 481 1,661 17Table 4-12. RACT-Impacted Natural Gas-Driven Pneumatic Pump Emission ReductionsEmissionSourceType ofControlEmission Reductions Per NaturalGas-Drven Pneumatic Pump (tpy)RACT-Impacted Natural Gas-Driven Pneumatic Pump Emission Reductions (tpy)Moderate or Higher NAAreas Outside of OTRAreasOTR AreasModerate or Higher OzoneNA Areas/OTR AreasVOCMethaneHAPVOCCH4HAPVOCCH4HAPVOCCH4HAPDiaphragmExistingCombustionDevice0.91 3.3 0.034 1,872 6,733 70 2,137 7,686 80 4,008 14,419 151PistonExistingCombustionDevice0.10 0.36 0.0038 205 737 7.7 234 841 8.8 439 1,578 1720Table 4-13. Total Annual Costs and VOC Cost ofControl Per Natural Gas-Driven Pneumatic PumpEmission SourceNaturalGasSavingsPerSource(Mcf)Total Valueof NaturalGas SavingsPer Source($/yr)Total Capital CostsPer Source ($)Total Annual Costs Per Source($/yr)VOC Cost of Control ($/tonof VOC reduced)w/o savingsw/ savingsw/o savingsw/ savingsDiaphragm 0 $0 $2,000 $285 $285 $312 $312Piston 0 $0 $2,000 $285 $285 $2,840 $2,840Table 4-14. RACT-Impacted Natural Gas-Driven Pneumatic Pump CostsEmissionPointModerate or Higher NA Areas Outside ofOTR AreasOTR AreasModerate or Higher Ozone NA Areas/OTRAreasCapital($)Annual w/osavings ($/yr)Annual w/savings($/yr)Capital($)Annual w/osavings ($/yr)Annual w/savings($/yr)Capital($)Annual w/osavings ($/yr)Annual w/savings ($/yr)Diaphragm $4,096,598 $583,765 $583,765 $4,676,673 $666,426 $666,426 $8,773,271 $1,250,191 $1,250,191Piston $4,082,385 $581,740 $581,740 $4,660,447 $664,114 $664,114 $8,742,833 $1,245,854 $1,245,854

# 21 

# 4.4 Compressors

4.4.1 Approach

RACT-impacted reciprocating compressor and wet seal centrifugal compressor baseline

emissions and emission reductions were calcula ted by multiplying the number of uncontrolled

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

emission reductions by compre ssor. The RACT-impacted reci procating compressor and wet

seal centrifugal compressor costs were esti mated by multiplying the calculated RACT VOC

emission reductions by costs per compressor.

4.4.2 RACT-Impacted Population of Reciproca ting Compressors and Wet Seal Centrifugal

Compressors

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

reciprocating compressors located at gather ing 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 loca tion information was used to estimate the

number of RACT-impacted reciprocating co mpressors 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 segm ent. The percentage of the total number of

RACT-impacted natural gas pro cessing plants based on the 2 012 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 perc entage of the total num ber 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 populat ion 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 Compresso r 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, methan e and HAP emissions per compressor. Using

the emission reductions and costs developed fo r 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 comp ressor rod packing afte r 26,000 hours of operation

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

used the emission reductions and costs associ ated 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 em issions and emission reductions.

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

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

RACT-impacted reciprocating compresso r and wet seal compressor costs.23Table 4-16. RACT-Impacted Reciprocating Compressor and Wet Seal Compressor Baseline EmissionsEmission SourceBaseline Emissions PerCompressor (tpy)RACT-Impacted CompressorBaseline Emissions (tpy)Moderate or Higher NA AreasOutside of OTR AreasOTR AreasModerate or Higher Ozone NAAreas/OTR AreasVOCCH4HAPVOCCH4HAPVOCCH4HAPVOCCH4HAPReciprocating Compressor –Gathering and BoostingStation3.4 12 0.13 7,892 28,390 297 5,375 19,377 203 13,267 47,726 500Reciprocating Compressor –Processing6.1 22 0.23 2,270 8,176 86 568 2,042 21 2,838 10,209 107Wet Seal Compressor –Processing19 211 2.2 830 9,144 96 207 2,286 24 1,037 11,430 120Table 4-17. RACT-Impacted Reciprocating Compressorand Wet Seal Compressor Emission ReductionsEmission SourceType ofControlEmission ReductionsPer Compressor (tpy)RACT-Impacted Compressor Emission Reductions (tpy)Moderate or Higher NAAreas Outside of OTRAreasOTR AreasModerate or Higher OzoneNA Areas/OTR AreasVOCMethaneHAPVOCCH4HAPVOCCH4HAPVOCCH4HAPReciprocatingCompressor –Gathering andBoosting StationReplacePacking AfterThree Years1.9 6.8 0.07 4,385 15,774 165 2,986 10,744 113 7,371 26,518 278ReciprocatingCompressor –ProcessingReplacePacking AfterThree Years4.9 18 0.18 1,814 6,525 68 453 1,631 17 2,267 8,156 85Wet Seal Compressor– Processing95 PercentControl;ExistingCombustionDevice18 200 2.1 788 8,706 91 197 2,177 23 985 10,883 11424Table 4-18. Total Annual Costs and VOC Cost of Control Per CompressorEmission SourceNaturalGasSavingsPerSource(Mcf)Total Valueof NaturalGas SavingsPer Source($/yr)Total Capital CostsPer Source ($)Total Annual Costs Per Source($/yr)VOC Cost of Control ($/tonof VOC reduced)w/o savingsw/ savingsw/o savingsw/ savingsReciprocating Compressor –Gathering and BoostingStation397 $1,587 $5,650 $2,153 $566 $1,132 $298Reciprocating Compressor –Processing1,019 $4,074 $4,280 $1,631($2,443)$334($500)Wet Seal Compressor –Processing0 $0 $23,252 $3,311 $3,311 $182 $182Table 4-19. RACT-Impacted Reciprocating Compressor and Centrifugal Compressor CostsEmission SourceModerate or Higher NA Areas Outsideof OTR AreasOTR AreasModerate or Higher Ozone NAAreas/OTR AreasCapital ($)Annual w/osavings($/yr)Annual w/savings($/yr)Capital($)Annual w/osavings($/yr)Annual w/savings ($/yr)Capital ($)Annual w/osavings($/yr)Annual w/savings($/yr)ReciprocatingCompressor –Gathering andBoosting Station$13,020,363 $4,961,431 $1,305,079$8,868,297 $3,379,279 $888,902$21,888,661 $8,340,711 $2,193,981ReciprocatingCompressor –Processing$1,588,826 $605,462($906,997)$397,207 $151,365($226,749)$1,986,033 $756,827($1,133,746)Wet SealCompressor –Processing$1,009,889 $143,804 $143,804 $252,472 $35,951 $35,951 $1,262,361 $179,756 $179,756

# 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 emi ssion reductions per plant. The RACT-impacted

equipment leaks at natural gas processing pl ants 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 ga s processing plants was obtained from

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

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

areas in 2012. Table 4-20 presents the esti mated 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 natu ral 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 emis sions 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 reduc tions and costs developed for the CTG, we

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

plants by the emission reductions and costs asso ciated with the implem entation of an LDAR

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

ratios developed for the oil a nd natural gas industry as presen ted in the 2011 Gas Composition

memorandum, we estimated HAP baseline emissi ons per natural gas processing plant.

# 26 

# Tables 4-21 and 4-22 present the RACT-imp acted equipment leaks at natural gas

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

RACT-impacted equipment leaks at na tural gas processing plants costs.27Table 4-21. RACT-Impacted Natural Gas ProcessingPlant Equipment Leaks Baseline EmissionsEmission SourceBaseline Emissions Per NaturalGas Processing Plant (tpy)RACT-Impacted Natural Gas Processing Plant Baseline Emissions (tpy)Moderate or Higher NA AreasOutside of OTR AreasOTR AreasModerate or Higher OzoneNA Areas/OTR AreasVOCCH4HAPVOCCH4HAPVOCCH4HAPVOCCH4HAPNatural Gas ProcessingPlants - EquipmentLeaks35 126 1.3 1,397 5,027 53 349 1,257 13 1,747 6,284 66Table 4-22. RACT-Impacted Natural Gas ProcessingPlant Equipment Leaks Emission ReductionsEmission SourceType ofControlEmission Reductions PerNatural Gas Processing Plant(tpy)RACT-Impacted Natural Gas ProcessingPlant Emission Reductions (tpy)Moderate or Higher NAAreas Outside of OTRAreasOTR AreasModerate or HigherOzone NA Areas/OTRAreasVOCMethaneHAPVOCCH4HAPVOCCH4HAPVOCCH4HAPNatural GasProcessing Plants -Equipment LeaksSubpart VVa 4.6 16 0.17 182 656 7 46 164 2 228 820 928Table 4-23. Total Annual Costs and VOC Cost ofControl Per Natural Gas Processing PlantEmission SourceNaturalGasSavingsPerSource(Mcf)Total Valueof NaturalGas SavingsPer Source($/yr)Total Capital CostsPer Source ($)Total Annual Costs Per Source($/yr)VOC Cost of Control ($/tonof VOC reduced)w/o savingsw/ savingsw/o savingsw/ savingsNatural Gas ProcessingPlants - Equipment Leaks950 $3,800 $8,499 $12,959 $9,159 $2,844 $2,010Table 4-24. RACT-Impacted Natural Gas Processing Plant Equipment Leaks CostsEmission PointModerate or Higher NA Areas Outsideof OTR AreasOTR AreasModerate or Higher Ozone NAAreas/OTR AreasCapital($)Annual w/osavings ($/yr)Annual w/savings($/yr)Capital($)Annual w/osavings ($/yr)Annual w/savings($/yr)Capital($)Annual w/osavings ($/yr)Annual w/savings($/yr)Natural GasProcessing Plants -Equipment Leaks$339,960 $518,366 $366,379 $84,990 $129,591 $91,595 $424,950 $647,957 $457,974

# 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 a nd 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 S ites 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 aver age, greater than 15 barrel equivalents per day.

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

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

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

be subject to RACT by dividing the number of wells by two (assu ming 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 av erage of the percentage of the total RACTimpacted number of natural gas processing plan ts based on the 2012 Gas Processing Survey and

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

Desktop location information was used to estim ate 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 Popul ation 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 nu mber 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 estim ated methane and HAP baseline emissions

and emission reductions.

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

gathering and boosting station baseline fugitiv e 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.31Table 4-26. RACT-Impacted Oil and Natural Gas Well Site and Gathering and Boosting Station Baseline Fugitive EmissionsEmission SourceBaseline Emissions Per NaturalGas Processing Plant (tpy)RACT-Impacted Oil and Gas Well Site and Gathering and Boosting Station Baseline FugitiveEmissions (tpy)Moderate or Higher NA AreasOutside of OTR AreasOTR AreasModerate or Higher Ozone NAAreas/OTR AreasVOCCH4HAPVOCCH4HAPVOCCH4HAPVOCCH4HAPNatural Gas WellSites1.3 4.5 0.05 7,051 25,365 266 2,754 9,907 104 9,805 35,272 369Oil Well Sites 0.30 1.1 0.01 1,981 7,125 75 42 151 2 2,203 7,276 76Gathering andBoosting Stations9.8 35 0.37 5,003 17,999 188 3,408 12,259 128 8,411 30,258 317Table 4-27. RACT-Impacted Oil and Natural Gas Well Siteand Gathering and Boosting Station Fugitive EmissionReductionsEmissionSourceType ofControlEmission Reductions PerNatural Gas ProcessingPlant (tpy)RACT-Impacted Oil and Gas Well Site and Gathering and Boosting Station FugitiveEmission Reductions (tpy)Moderate or Higher NAAreas Outside of OTR AreasOTR AreasModerate or Higher OzoneNA Areas/OTR AreasVOCCH4HAPVOCCH4HAPVOCCH4HAPVOCCH4HAPNatural GasWell SitesSemiannualOGI0.76 2.7 0.03 4,231 15,219 159 1,652 5,944 62 5,883 21,163 222Oil Well SitesSemiannualOGI0.18 0.65 0.01 1,188 4,275 45 25 90 1 1,214 4,366 46Gathering andBoostingStationsSemiannualOGI5.9 21 0.22 3,002 10,799 113 2,045 7,356 77 5,047 18,155 19032Table 4-28. Total Annual Costs and VOC Cost of Control Per Well Site/StationEmission SourceNatural GasSavings PerSource(Mcf)Total Valueof NaturalGas SavingsPer Source($/yr)Total Capital CostsPer Source ($)Total Annual Costs Per Source($/yr)VOC Cost of Control ($/tonof VOC reduced)w/o savingsw/ savingsw/o savingsw/ savingsNatural Gas Well Sites 158 $631 $801$2,230 $1,599 $2,945 $2,111Oil Well Sites 38 $151 $801 $2,230 $2,079 $12,294 $11,460Gathering and BoostingStations1,222 $4,888 $10,993 $15,881 $10,993 $2,710 $1,876Table 4-29. RACT-Impacted Oil and Natural Gas Well Site andGathering and Boosting Station Fugitive Emission CostsEmissionPointModerate or Higher NA Areas Outside ofOTR AreasOTR AreasModerate or Higher Ozone NAAreas/OTR AreasCapital($)Annual w/osavings($/yr)Annual w/savings($/yr)Capital($)Annual w/osavings($/yr)Annual w/savings ($/yr)Capital ($)Annual w/osavings($/yr)Annual w/savings($/yr)Natural GasWell Sites$4,475,582 $12,460,517 $8,932,579$1,748,024 $4,866,693 $3,488,789 $6,223,605 $17,327,210 $12,421,368Oil WellSites$5,247,675 $14,610,112 $13,619,076 $110,928 $308,837 $287,888 $5,358,604 $14,918,949 $13,906,964GatheringandBoostingStations$5,630,384 $8,133,758 $5,630,384$3,834,910 $5,539,982 $3,834,910 $9,465,294 $13,673,740 $9,465,294

# 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 centrifuga l compressors, natural gas processing plant

equipment leaks, and fugitive emissions at well sites and gathering and boosting stations.34Table 5-1. Summary of the Oil and Natural Gas Industry VOC RACT EmissionReductions and CostsVOC Methane HAP w/osavings w/savings VOC Methane HAP Capital($1000)Annualw/osavings($1000/yr)Annualw/savings($1000/yr)FugitiveEmissions‐GasWellSites(WithWellsthatProduceGreaterthan15BarrelEquivalentsPerDay)SemiannualOGI 0.76 2.70 0.03 $2,900 $2,100 5,900 21,000 220 6,200 17,000 12,000FugitiveEmissions‐OilWellSites(WithWellsthatProduceGreaterthan15BarrelEquivalentsPerDay)SemiannualOGI 0.18 0.65 0.01 $12,000 $11,000 1,200 4,400 46 5,400 15,000 14,000FugitiveEmissions‐GatheringandBoostingStationsSemiannualOGI 5.90 21.00 0.22 $2,700 $1,900 5,000 18,000 190 9,500 14,000 9,500EquipmentLeaks‐ProcessingPlantsNSPSSubpartVVa 4.60 16.00 0.17 $2,800 $2,000 230 820 9 420 650 460ReciprocatingCompressors‐GatheringandBoostingStationsReplacePackingAfter3Years1.90 6.80 0.07 $1,100 $300 7,400 27,000 280 22,000 8,300 2,200ReciprocatingCompressors‐ProcessingReplacePackingAfter3Years4.90 18.00 0.18 $330($500)2,300 8,200 85 2,000 760(1,100)Centri figalCompressorsw/WetSeals‐Processing95%Control,ExistingCombustionDevice18.00 200.00 2.10 $180 $180 990 11,000 110 1,300 180 180NaturalGas‐DrivenPneumaticControllers‐OilandGasProductionReplacew/LowBleed1.40 5.10 0.05 $210($630)31,000 110,000 1,200 59,000 6,500(19,000)NaturalGas‐DrivenPneumaticControllers‐ProcessingExistingInstrumentAirSystem0.28 1.00 0.01 $1,000 $190 3 11 0 22 3.2 0.59NaturalGas‐DrivenPneumaticPumps‐Production‐Diaphram95%Control,ExistingCombustionDevice0.91 3.30 0.03 $310 $310 4,000 14,000 150 8,800 1,300 1,300NaturalGas‐DrivenPneumaticPumps‐Production‐Piston95%Control,ExistingCombustionDevice0.10 0.36 0.004 $2,800 $2,800 430 1,600 17 8,700 1,200 1,200StorageVessels95%Control,Combustion/VRUba a a a a 23,000 4,800 730 260,000 56,000 55,000Total82,000 220,000 3,000 380,000 120,000 76,000b‐Assumesthat94percentofownersandoperatorswouldcomplybyusingacombustiondeviceand6percentwouldcomplybyusingaVRU.Note:Minordifferencesmayresultfromroundingto2significantfigures.a‐Thereareawidevarietyofstoragevesselsizes,aswellasratesofthroughputforeachstoragevessel.Emissionsandcostsaredirectlyrelatedtothethroughputofliquidsforagivenstoragevessel.Inlieuofusingemissionreductionsandcostsperstoragevessel,weusedproductionratebracketsdevelopedbytheU.S.EnergyInformationAdministration(EIA)forouremissionestimatesandcosts(seeAttachments2and3).EmissionSourceTypeofControl EmissionReductionPerUnit(tpy)VOCCostofControl($/ton)EmissionReductions(tpy) RACTVOCCostofControl($)

# ATTACHMENT 1

Moderate or High er Ozone NA Areas

# A1 - 2 

# Moderate or High er 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 Count y 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 Provid ence (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 Emissi ons, 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-Impa cted 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 80,611A2-4Table A2-3. RACT-Impacted Oil Storage Vessel Baseline EmissionsWell Productivity Bracket (bbls/dayrange)Representative(bbls/day)Average Baseline Emissions per Unit(tpy/unit)Nationwide Baseline Emissions2012VOCMethaneHAPVOCMethaneHAP>0-1 0.385 0.083 0.017 0.003 0 0 0.0001-2 1.34 0.287 0.059 0.009 0 0 0.0002-4 2.66 0.570 0.118 0.018 0 0 0.0004-6 4.45 0.953 0.197 0.030 0 0 0.0006-8 6.22 1.33 0.28 0.04 0 0 0.0008-10 8.08 1.73 0.36 0.05 0 0 0.00010-12 9.83 2.11 0.44 0.07 0 0 0.00012-15 12.1 2.59 0.54 0.08 0 0 0.00015-20 15.4 3.31 0.68 0.10 0 0 0.00020-25 19.9 4.27 0.88 0.13 0 0 0.00025-30 24.3 5.22 1.08 0.16 0 0 0.00030-4030.56.541.350.216,7491,39721240-50 39.2 8.41 1.74 0.26 4,033 835 12750-100 61.6 13.2 2.7 0.4 9,470 1,960 297100-200 120 25.6 5.3 0.8 2,524 522 79200-400 238 51.0 10.6 1.6 611 126 19400-800 456 97.7 20.2 3.1 0 0 0.000800-1600 914 196.0 40.6 6.2 0 0 0.0001600-3200 1,692 362.9 75.1 11.4 0 0 0.0003200-6400 3,353 719.1 148.8 22.6 0 0 0.0006400-12800 6,825 1463.7 302.9 45.9 0 0 0.000TOTAL23,386 4,840 734A2-5Table A2-4. RACT-Impacted Condensate Storage Vessel Baseline EmissionsWell Productivity Bracket(bbls/day range)Representative(bbls/day)Average Baseline Emissions per Unit (tpy/unit)Nationwide Baseline Emissions 2012VOCMethaneHAPVOCMethaneHAP>0-1635 0.038 0.008 0.001 0 0 01-2349 0.168 0.037 0.005 0 0 02-4648 0.318 0.070 0.009 0 0 04-6766 0.573 0.126 0.017 0 0 06-8640 0.82 0.18 0.02 0 0 08-10525 1.04 0.23 0.03 0 0 010-12408 1.37 0.30 0.04 0 0 012-15564 1.53 0.34 0.04 0 0 015-20758 2.10 0.46 0.06 0 0 020-25674 3.32 0.73 0.10 0 0 025-30531 3.85 0.85 0.11 0 0 030-40927 5.33 1.17 0.16 0 0 040-507477.591.670.2200050-1002,691 11.7 2.6 0.3 0 0 0100-2003,800 25.4 5.6 0.7 0 0 0200-4002,705 49.8 11.0 1.5 0 0 0400-8001,165 92.3 20.3 2.7 0 0 0800-1600348 142.2 31.3 4.2 0 0 01600-320069 310.7 68.5 9.1 0 0 03200-640037 489.9 107.9 14.4 0 0 06400-128005 1864.4 410.8 54.7 0 0 0>128000 0 0 0 0 0 0A2-6Table A2-5. RACT-Impacted Oil Storage Vessel Emission ReductionsWell ProductivityBracket(bbls/day range)Representative(bbls/day)Average Emission ReductionsPer Unit (tpy) Assuming 95%ReductionNationwide Emissions Reductions2012Natural GasSavedMcf/yr/unitTotalNatural GasSavedMcf/yrVOCMethaneHAPVOCMethaneHAP>0-1 0.385 0.078 0.016 0.002 0 0 0.000 2.7 01-2 1.34 0.272 0.056 0.009 0 0 0.000 9.2 02-4 2.66 0.542 0.112 0.017 0 0 0.000 18.3 04-6 4.45 0.906 0.187 0.028 0 0 0.000 30.6 06-8 6.22 1.27 0.26 0.04 0 0 0.000 42.9 08-10 8.08 1.65 0.34 0.05 0 0 0.000 55.7 010-12 9.83 2.00 0.41 0.06 0 0 0.000 67.8 012-15 12.1 2.46 0.51 0.08 0 0 0.000 83.2 015-20 15.4 3.14 0.65 0.10 0 0 0.000 106.3 020-25 19.9 4.05 0.84 0.13 0 0 0.000 137.1 025-30 24.3 4.96 1.03 0.16 0 0 0.000 167.7 030-4030.56.211.290.2067551398212210.12284740-50 39.2 7.99 1.65 0.25 4033 835 127 270.3 1363850-100 61.6 12.5 2.6 0.4 9470 1960 297 424.2 32028100-200 120 24.4 5.0 0.8 2524 522 79 823.9 8536200-400 238 48.5 10.0 1.5 611 126 19 1638.9 2065400-800 456 92.8 19.2 2.9 0 0 0.000 3139.0 0800-1600 914 186.2 38.5 5.8 0 0 0.000 6297.8 01600-3200 1,692 344.8 71.4 10.8 0 0 0.000 11660.3 03200-6400 3,353 683.2 141.4 21.4 0 0 0.000 23105.8 06400-12800 6,825 1390.5 287.8 43.6 0 0 0.000 47028.1 0TOTAL23,3924,84273479,114A2-7Table A2-6. RACT-Impacted Condensate Storage Vessel Emission ReductionsWell ProductivityBracket (bbls/dayrange)Representative(bbls/day)Average Emission ReductionsPer Unit (tpy) assuming 95%reductionNationwide Emissions Reductions2012Natural GasSavedMcf/yr/unitTotalNatural GasSavedMcf/yrVOCMethaneHAPVOCMethaneHAP>0-16350.036 0.008 0.001 0 0 0 1.15101-23490.159 0.035 0.005 0 0 0 5.05102-46480.302 0.067 0.009 0 0 0 9.55804-67660.545 0.120 0.016 0 0 0 17.25206-86400.78 0.17 0.02 0 0 0 24.81808-105250.99 0.22 0.03 0 0 0 31.423010-124081.30 0.29 0.04 0 0 0 41.27012-155641.46 0.32 0.04 0 0 0 46.16015-207581.99 0.44 0.06 0 0 0 63.11020-256743.15 0.70 0.09 0 0 0 99.91025-305313.65 0.81 0.11 0 0 0 115.68030-409275.07 1.12 0.15 0 0 0 160.4040-507477.211.590.21000228.4050-1002,69111.1 2.5 0.3 0 0 0 352.60100-2003,80024.1 5.3 0.7 0 0 0 7630200-4002,70547.3 10.4 1.4 0 0 0 14980400-8001,16587.7 19.3 2.6 0 0 0 27770800-1600348135.1 29.8 4.0 0 0 0 427701600-320069295.1 65.0 8.7 0 0 0 934603200-640037465.4 102.5 13.6 0 0 0 1473706400-1280051771.2 390.3 51.9 0 0 0 560860>1280000.0 0.0 0.0 0 0 0 0.0000A2-8Table A2-7. RACT-Impacted Oil Storage Vessel VRU and Combustor CostsWellProductivityBracket(bbls/dayrange)Route Emissions to a VRURoute Emissions to a CombustorTotal CapitalCost Per Unit($)Total Annual Cost PerUnit ($/yr)VOC Cost of Control($/ton)Total CapitalCost PerUnit ($)Total Annual CostPer Unit ($/yr)VOC Cost of Control($/ton)w/osavingsw/ savingsw/osavingsw/ savingsw/osavingsw/savingsw/osavingsw/ savings>0-1$171,538$28,230$28,219 $359,638 $359,503$100,986$22,228$22,228 $283,175 $283,1751-2$171,538$28,230$28,193 $103,714 $103,579$100,986$22,228$22,228 $81,663 $81,6632-4$171,538$28,230$28,157 $52,104 $51,969$100,986$22,228$22,228 $41,026 $41,0264-6$171,538$28,230$28,107 $31,170 $31,035$100,986$22,228$22,228 $24,543 $24,5436-8$171,538$28,230$28,058 $22,261 $22,126$100,986$22,228$22,228 $17,528 $17,5288-10$171,538$28,230$28,007 $17,144 $17,009$100,986$22,228$22,228 $13,499 $13,49910-12$171,538$28,230$27,959 $14,092 $13,957$100,986$22,228$22,228 $11,096 $11,09612-15$171,538$28,230$27,897 $11,478 $11,342$100,986$22,228$22,228 $9,037 $9,03715-20$171,538$28,230$27,805 $8,986 $8,851$100,986$22,228$22,228 $7,075 $7,07520-25$171,538$28,230$27,682 $6,963 $6,828$100,986$22,228$22,228 $5,483 $5,48325-30$171,538$28,230$27,559 $5,692 $5,557$100,986$22,228$22,228 $4,482 $4,48230-40$171,538$28,230$27,390$4,544$4,409$100,986$22,228$22,228$3,578$3,57840-50$171,538$28,230$27,149 $3,532 $3,397$100,986$22,228$22,228 $2,781 $2,78150-100$171,538$28,230$26,533 $2,251 $2,115$100,986$22,228$22,228 $1,772 $1,772100-200$171,538$28,230$24,934 $1,159 $1,024$100,986$22,228$22,228 $912 $912200-400$171,538$28,230$21,675 $583 $447$100,986$22,228$22,228 $459 $459400-800$171,538$28,230$15,674 $304 $169$100,986$22,228$22,228 $239 $239800-1600$171,538$28,230$3,039 $152 $16$100,986$22,228$22,228 $119 $1191600-3200$171,538$28,230-$18,411 $82 -$53$100,986$22,228$22,228 $64 $643200-6400$171,538$28,230-$64,193 $41 -$94$100,986$22,228$22,228 $33 $336400-12800$171,538$28,230-$159,882 $20 -$115$100,986$22,228$22,228 $16 $16A2-9Table A2-8. RACT-Impacted CondensateStorage Vessel VRU and Combustor CostsWellProductivityBracket(bbls/dayrange)Routing Emissions to a VRURouting to a CombustorTotal CapitalCost Per Unit($)Total Annual Cost PerUnit ($/yr)VOC Cost Effectiveness($/ton)Total CapitalCost Per Unit($)Total Annual CostPer Unit ($/yr)VOC Cost Effectiveness($/ton)w/osavingsw/ savingsw/osavingsw/ savingsw/osavingsw/savingsw/osavingsw/ savings>0-1$171,538$28,230$28,225 $776,897 $776,770$100,986$22,228$22,228 $611,720 $611,7201-2$171,538$28,230$28,210 $176,996 $176,870$100,986$22,228$22,228 $139,365 $139,3652-4$171,538$28,230$28,192 $93,529 $93,402$100,986$22,228$22,228 $73,643 $73,6434-6$171,538$28,230$28,161 $51,817 $51,690$100,986$22,228$22,228 $40,800 $40,8006-8$171,538$28,230$28,131 $36,020 $35,893$100,986$22,228$22,228 $28,362 $28,3628-10$171,538$28,230$28,104 $28,449 $28,322$100,986$22,228$22,228 $22,400 $22,40010-12$171,538$28,230$28,065 $21,663 $21,537$100,986$22,228$22,228 $17,057 $17,05712-15$171,538$28,230$28,045 $19,367 $19,240$100,986$22,228$22,228 $15,249 $15,24915-20$171,538$28,230$27,978 $14,166 $14,039$100,986$22,228$22,228 $11,154 $11,15420-25$171,538$28,230$27,830 $8,948 $8,821$100,986$22,228$22,228 $7,045 $7,04525-30$171,538$28,230$27,767 $7,727 $7,601$100,986$22,228$22,228 $6,085 $6,08530-40$171,538$28,230$27,588 $5,573 $5,446$100,986$22,228$22,228 $4,388 $4,38840-50$171,538$28,230$27,316$3,914$3,787$100,986$22,228$22,228$3,082$3,08250-100$171,538$28,230$26,820 $2,535 $2,409$100,986$22,228$22,228 $1,996 $1,996100-200$171,538$28,230$25,177 $1,171 $1,045$100,986$22,228$22,228 $922 $922200-400$171,538$28,230$22,239 $597 $470$100,986$22,228$22,228 $470 $470400-800$171,538$28,230$17,120 $322 $195$100,986$22,228$22,228 $253 $253800-1600$171,538$28,230$11,122 $209 $82$100,986$22,228$22,228 $165 $1651600-3200$171,538$28,230-$9,152 $96 -$31$100,986$22,228$22,228 $75 $753200-6400$171,538$28,230-$30,717 $61 -$66$100,986$22,228$22,228 $48 $486400-12800$171,538$28,230-$196,116 $16 -$111$100,986$22,228$22,228 $13 $13>12800$171,538$28,230$28,230 $0 $0$100,986$22,228$22,228 $0 $0A2-10Table A2-9. RACT-Impacted Oil Storage Vessel Nationwide CostsWell Productivity Bracket(bbls/day range)Representative(bbls/day)Total Nationwide CostsCapital ($)Annual w/o savings($/yr)Annual w/ savings ($/yr)>0-1 0.385 $0 $0 $01-2 1.34 $0 $0 $02-4 2.66 $0 $0 $04-6 4.45 $0 $0 $06-8 6.22 $0 $0 $08-10 8.08 $0 $0 $010-12 9.83 $0 $0 $012-15 12.1 $0 $0 $015-20 15.4 $0 $0 $020-25 19.9 $0 $0 $025-30 24.3 $0 $0 $030-4030.5$117,473,197$24,821,102$24,729,71540-50 39.2 $54,517,590 $11,519,110 $11,464,55650-100 61.6 $81,571,106 $17,235,291 $17,107,178100-200 120 $11,193,068 $2,365,002 $2,330,858200-400 238 $1,361,319 $287,635 $279,375400-800 456 $0 $0 $0800-1600 914 $0 $0 $01600-3200 1,692 $0 $0 $03200-6400 3,353 $0 $0 $06400-12800 6,825 $0 $0 $0TOTAL $266,116,280 $56,228,139 $55,911,683A2-11Table A2-10. RACT-Impacted Condensate Storage Vessel Nationwide CostsWell Productivity Bracket(bbls/day range)Representative(bbls/day)Total Nationwide CostsCapital ($)Annual w/o savings ($/yr)Annual w/ savings ($/yr)>0-1635 $0 $0 $01-2349 $0 $0 $02-4648 $0 $0 $04-6766 $0 $0 $06-8640 $0 $0 $08-10525 $0 $0 $010-12408 $0 $0 $012-15564 $0 $0 $015-20758 $0 $0 $020-25674 $0 $0 $025-30531 $0 $0 $030-40927 $0 $0 $040-50747$0$0$050-1002,691 $0 $0 $0100-2003,800 $0 $0 $0200-4002,705 $0 $0 $0400-8001,165 $0 $0 $0800-1600348 $0 $0 $01600-320069 $0 $0 $03200-640037 $0 $0 $06400-128005 $0 $0 $0>128000 $0 $0 $0TOTAL$0 $0 $0

# ATTACHMENT 3

Oil and Natural Gas CTG – Storage Ve ssels 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 RA CT-equivalent or greater level of control. The

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

control was subtracted from the number of storag e 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 analys is (e.g., based on case-by-case permit limits).EPA_WELL_TYPEEPA_PROD_BRACKETCACAStateCoveredCACTGCoveredCANotCoveredMDMDCTGCoveredNYNAANYCTGCoveredOTRNYCTGCoveredCombinedNYCTGCovered01.0‐1 7,364 0 0 7,364 0 3,216 0 0 002.1‐2 5,798 0 0 5,798 0 65 0 0 003.2‐4 8,039 0 0 8,039 0 33 0 0 004.4‐6 5,550 0 0 5,550 0 1 0 0 005.6‐8 3,906 0 0 3,906 0 0 0 0 006.8‐10 3,013 0 0 3,013 0 1 0 0 007.10‐12 2,407 0 0 2,407 0 1 0 0 008.12‐15 2,668 0 0 2,668 0 0 0 0 009.15‐20 2,968 0 0 2,968 0 0 0 0 010.20‐25 1,882 0 0 1,882 0 0 0 0 011.25‐30 1,183 0 0 1,183 0 0 0 0 012.30‐40 1,409 423 986 0 0 0 0 0 0 013.40‐50 658 197 461 0 0 0 0 0 0 014.50‐100 930 279 651 0 0 0 0 0 0 015.100‐200 148 44 104 0 0 0 0 0 0 016.200‐400 18 5 13 0 0 0 0 0 0 017.400‐800 0 0 0 0 0 0 0 0 0 018.800‐1600 0 0 0 0 0 0 0 0 0 019.1600‐3200 0 0 0 0 0 0 0 0 0 01.OilTotal 47,941 949 2,214 44,778 0 0 3,317 0 0 0No1.OilallnonenonesomesomeNONEWYORKCALIFORNIA MARYLANDWellsinNAAWellsinOTRWellsinbothNAAandOTRStateRegulationsallnonenoneYesnoneA3-401.0‐1 844 0 0 844 1 0 7,074 0 0 002.1‐2 20 0 0 20 0 0 0 0 0 003.2‐4 11 0 0 11 0 0 0 0 0 004.4‐6 600600000005.6‐8 300300000006.8‐10 2 0 0 2 0 0 0 0 0 007.10‐12 0 0 0 0 0 0 0 0 0 008.12‐15 2 0 0 2 0 0 0 0 0 009.15‐20 1 0 0 1 0 0 0 0 0 010.20‐25 1 0 0 1 0 0 0 0 0 011.25‐30 0 0 0 0 0 0 0 0 0 012.30‐40 0 0 0 0 0 0 0 0 0 013.40‐50 0 0 0 0 0 0 0 0 0 014.50‐100 0 0 0 0 0 0 0 0 0 015.100‐200 0 0 0 0 0 0 0 0 0 016.200‐400 0 0 0 0 0 0 0 0 0 017.400‐800 0 0 0 0 0 0 0 0 0 018.800‐1600 0 0 0 0 0 0 0 0 0 019.1600‐3200 0 0 0 0 0 0 0 0 0 02.GasTotal 890 0 0 890 1 0 7,07402,363 4,7112.GasA3-5EPA_WELL_TYPEEPA_PROD_BRACKETPANAAPACTGCoveredOTRPACTGCoveredCombinedPACTGCoveredTXTXStateCoveredTXCTGCoveredTXNotCoveredVAVACTGCovered01.0‐1 18,593 0 0 0 5,380 0 0 5,380 2402.1‐2 915 0 0 0 1,948 0 0 1,948 103.2‐4 160 0 0 0 2,357 0 0 2,357 004.4‐6 23 0 0 0 600 0 0 600 005.6‐8 9 0 0 0 313 0 0 313 006.8‐10 48 0 0 0 299 0 0 299 007.10‐12 11 0 0 0 173 0 0 173 008.12‐15 27 0 0 0 185 0 0 185 009.15‐20 34 0 0 0 175 0 0 175 010.20‐25 15 0 0 0 120 0 0 120 011.25‐30 16 0 0 0 107 0 0 107 012.30‐40 3 0 0 3 97 0 97 0 0 013.40‐50 5 0 0 5 39 0 39 0 0 014.50‐100 3 0 0 3 101 0 101 0 0 015.100‐200 0 0 0 0 20 20 0 0 0 016.200‐400 0 0 0 0 16 16 0 0 0 017.400‐800 0 0 0 0 2 2 0 0 0 018.800‐1600 0 0 0 0 0 0 0 0 0 019.1600‐3200 0 0 0 0 1 1 0 0 0 01.OilTotal 19,862 0 0 11 11,933 39 237 11,657 25 01.OilallnonenoneYesTEXAS VIRGINIAnonesomesomeNoPENNSYLVANIAnoneallnoneNoWellsinNAAWellsinOTRWellsinbothNAAandOTRStateRegulationsA3-601.0‐1 52,109 0 0014,241 0 0 14,241 5,86402.1‐2 32 0 0 0 205 0 0 205 003.2‐4 26 0 0 0 90 0 0 90 004.4‐6 10 0 0 0 32 0 0 32 005.6‐8 5 0 002 0 02006.8‐10 6 0 0 0 4 0 0 4 007.10‐12 7 0 0 0 2 0 0 2 008.12‐15 3 0 0 0 2 0 0 2 009.15‐20 0 0 0 0 4 0 0 4 010.20‐25 0 0 0 0 1 0 0 1 011.25‐30 0 0 0 0 0 0 0 0 012.30‐40 0 0 0 0 1 0 0 1 013.40‐50 0 0 0 0 0 0 0 0 014.50‐100 0 0 0 0 0 0 0 0 015.100‐200 0 0 0 0 0 0 0 0 016.200‐400 0 0 0 0 0 0 0 0 017.400‐800 0 0 0 0 0 0 0 0 018.800‐1600 0 0 0 0 0 0 0 0 019.1600‐3200 0 0 0 0 0 0 0 0 02.GasTotal 52,198035,957 16,241 14,584 0 0 14,584 5,8642.Gas