Emissions from Natural Gas Production in the Barnett Shale Area 

and Opportunities for Cost-Effective Improvements

report by: 

Al Armendariz, Ph.D. 

Department of Environmental and Civil Engineering 

Southern Methodist University 

P.O. Box 750340 

Dallas, Texas, 75275-0340 

for: 

Ramon Alvarez, Ph.D. 

Environmental Defense Fund 

44 East Avenue 

Suite 304 

Austin, Texas 78701 

Version 1.1 

January 26, 2009 
1

1.0 EXECUTIVE SUMMARY

Natural gas production in the Barnett Shale region of Texas has increased rapidly since 1999, and as of 

June 2008, over 7700 oil and gas wells had been installed and another 4700 wells were pending. Gas 

production in 2007 was approximately 923 Bcf from wells in 21 counties. Natural gas is a critical 

feedstock to many chemical production processes, and it has many environmental benefits over coal as a 

fuel for electricity generation, including lower emissions of sulfur, metal compounds, and carbon dioxide. 

Nevertheless, oil and gas production from the Barnett Shale area can impact local air quality and release 

greenhouse gases into the atmosphere. The objectives of this study were to develop an emissions 

inventory of air pollutants from oil and gas production in the Barnett Shale area, and to identify costeffective emissions control options. 

Emission sources from the oil and gas sector in the Barnett Shale area were divided into point sources, 

which included compressor engine exhausts and oil/condensate tanks, as well as fugitive and intermittent 

sources, which included production equipment fugitives, well drilling and fracing engines, well 

completions, gas processing, and transmission fugitives. The air pollutants considered in this inventory 

were smog-forming compounds (NOx and VOC), greenhouse gases, and air toxic chemicals. 

For 2009, emissions of smog-forming compounds from compressor engine exhausts and tanks were 

predicted to be approximately 96 tons per day (tpd) on an annual average, with peak summer emissions of 

212 tpd. Emissions during the summer increase because of the effects of temperature on volatile organic 

compound emissions from storage tanks. Emissions of smog-forming compounds in 2009 from all oil and 

gas sources were estimated to be approximately 191 tpd on an annual average, with peak summer 

emissions of 307 tpd. The portion of those emissions originating from the 5-counties in the D-FW 

metropolitan area with significant oil and gas production was 165 tpd during the summer. 

For comparison, 2009 emission inventories recently used by state and federal regulators estimated smogforming emissions from all airports in the Dallas-Fort Worth metropolitan area to be 16 tpd. In addition, 

these same inventories had emission estimates for on-road motor vehicles (cars, trucks, etc.) in the 9-

county Dallas-Fort Worth metropolitan area of 273 tpd. The portion of on-road motor vehicle emissions 

from the 5-counties in the D-FW metropolitan area with significant oil and gas production was 121 tpd, 

indicating that the oil and gas sector likely has greater emissions than motor vehicles in these counties. 

The emission rate of air toxic compounds (like benzene and formaldehyde) from Barnett Shale activities 

was predicted to be approximately 6 tpd on an annual average, and 17 tpd during peak summer days. The 

largest contributors to air toxic emissions were the condensate tanks, followed by the engine exhausts. 

In addition, predicted 2009 emissions of greenhouse gases like carbon dioxide and methane were 

approximately 33,000 tons per day of CO2 equivalent. This is roughly equivalent to the expected 

greenhouse gas impact from two 750 MW coal-fired power plants. The largest contributors to the Barnett 

Shale greenhouse gas impact were CO2 emissions from compressor engine exhausts and fugitive CH4

emissions from all source types. 

Cost effective control strategies are readily available that can substantially reduce emissions, and in some 

cases, reduce costs for oil and gas operators. These options include: 

x use of "green completions" to capture methane and VOC compounds during well completions, 

x phasing in electric motors as an alternative to internal-combustion engines to drive compressors, 

x the control of VOC emissions from condensate tanks with vapor recovery units, and 

x replacement of high-bleed pneumatic valves and fittings on the pipeline networks with no-bleed 

alternatives. 
2

2.0 BACKGROUND 

2.1 Barnett Shale Natural Gas Production

The Barnett Shale is a geological formation that the Texas Railroad Commission (RRC) estimates to 

extend 5000 square miles in parts of at least 21 Texas counties. The hydrocarbon productive region of the 

Barnett Shale has been designated as the Newark East Field, and large scale development of the natural 

gas resources in the field began in the late 1990's. Figure 1 shows the rapid and continuing development 

of natural gas from the Barnett Shale over the last 10 years.(1)

0

200

400

600

800

1000

1200

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Natural Gas Production (billion cf)

Figure 1. Barnett Shale Natural Gas Production, 1998-2007.

In addition to the recent development of the Barnett Shale, oil and gas production from other geologic 

formations and conventional sources in north central Texas existed before 1998 and continues to the 

present time. Production from the Barnett Shale is currently the dominant source of hydrocarbon 

production in the area from oil and gas activities in the area. Emission sources for all oil and gas activities 

are considered together in this report. 

The issuance of new Barnett Shale area drilling permits has been following the upward trend of increasing 

natural gas production. The RRC issued 1112 well permits in 2004, 1629 in 2005, 2507 in 2006, 3657 in 

2007, and they are on-track to issue over 4000 permits in 2008. The vast majority of the wells and permits 

are for natural gas production, but a small number of oil wells are also in operation or permitted in the 

area, and some oil wells co-produce casinghead gas. As of June 2008, over 7700 wells had been 

registered with the RRC, and the permit issuance rates are summarized in Table 1-1.(1) Annual oil, gas, 

condensate, and casinghead gas production rates for 21 counties in the Barnett Shale area are shown in 

Table 1-2.(1) The majority of Barnett Shale wells and well permits are located in six counties near the city 

of Fort Worth: Tarrant, Denton, Wise, Parker, Hood, and Johnson Counties. Figure 2 shows a RRC map 

of wells and well permits in the Barnett Shale.(2) 
3

The top three gas producing counties in 2007 were Johnson, Tarrant and Wise, and the top three 

condensate producing counties were Wise, Denton, and Parker. 

Nine (9) counties surrounding the cities of Fort Worth and Dallas have been designated by the U.S. EPA 

as the D-FW ozone nonattainment area (Tarrant, Denton, Parker, Johnson, Ellis, Collin, Dallas, Rockwall, 

and Kaufman ). Four of these counties (Tarrant, Denton, Parker, and Johnson) have substantial oil or gas 

production. In this report, these 9 counties are referred to as the D-FW metropolitan area. The areas 

outside these 9-counties with significant Barnett Shale oil or gas production are generally more rural 

counties to the south, west, and northwest of the city of Fort Worth. The counties inside and outside the 

D-FW metropolitan area with oil and gas production are listed in Table 1-3. 

Table 1-1. Barnett Shale Area Drilling Permits Issued, 2004-2008.(1) 

Table 1-2. Hydrocarbon Production in the Barnett Shale Area in 2007.(1) 

County

Gas Production 

(MCF)

Condensate 

(BBL)

Casinghead Gas 

(MCF)

Oil Production 

(BBL)

Johnson 282,545,748 28,046 0 0

Tarrant 246,257,349 35,834 0 0

Wise 181,577,163 674,607 6,705,809 393,250

Denton 168,020,626 454,096 934,932 52,363

Parker 80,356,792 344,634 729,472 11,099

Hood 32,726,694 225,244 40,271 526

Jack 16,986,319 139,009 2,471,113 634,348

Palo Pinto 12,447,321 78,498 1,082,030 152,685

Stephens 11,149,910 56,183 3,244,894 2,276,637

Hill 7,191,823 148 0 0

Erath 4,930,753 11,437 65,425 5,073

Eastland 4,129,761 130,386 754,774 259,937

Somervell 4,018,269 6,317 0 0

Ellis 1,715,821 0 17,797 10

Comanche 560,733 1,584 52,546 7,055

Cooke 352,012 11,745 2,880,571 2,045,505

Montague 261,734 11,501 3,585,404 1,677,303

Clay 261,324 12,046 350,706 611,671

Hamilton 162,060 224 0 237

Bosque 135,116 59 0 0

Kaufman 0 0 3,002 61,963

year new drilling

permits

2004 1112

2005 1629

2006 2507

2007 3657

2008 4000+
4

Table 1-3. Relationship Between the D-FW Metropolitan Area and Counties Producing Oil/Gas in the 

Barnett Shale Area

D-FW 9-County 

Metropolitan 

Area 

D-FW Metro. 

Counties 

Producing 

Barnett Area 

Oil/Gas 

Rural 

Counties 

Producing 

Barnett Area 

Oil/Gas 

Tarrant 

Denton 

Parker 

Johnson 

Ellis 

Collin 

Dallas 

Rockwall 

Kaufman 

Tarrant 

Denton 

Parker 

Johnson 

Ellis 

Wise 

Hood 

Jack 

Palo Pinto 

Stephens 

Hill 

Eastland 

Somervell 

Comanche 

Cooke 

Montague 

Clay 

Hamilton 

Bosque 

Figure 2. Texas RRC Map of Well and Well Permit Locations in the Barnett Shale Area (red = gas wells, 

green = oil wells, blue = permits. RRC district 5, 7B, & 9 boundaries shown in black.) 
5

2.2 Air Pollutants and Air Quality Regulatory Efforts 

Oil and gas activities in the Barnett Shale area have the potential to emit a variety of air pollutants, 

including greenhouse gases, ozone and fine particle smog-forming compounds, and air toxic chemicals. 

The state of Texas has the highest greenhouse gas (GHG) emissions in the U.S., and future federal efforts 

to reduce national GHG emissions are likely to require emissions reductions from sources in the state. 

The three anthropogenic greenhouse gases of greatest concern, carbon dioxide, methane, and nitrous 

oxide, are emitted from oil and gas sources in the Barnett Shale area. 

At present, air quality monitors in the Dallas-Fort Worth area show the area to be in compliance with the 

1997 fine particulate matter (PM2.5) air quality standard, which is 15 micrograms per cubic meter (μg/m3

) 

on an annual average basis. In 2006, the Clean Air Scientific Advisory Committee for EPA recommended 

tightening the standard to as low as 13 μg/m3 to protect public health, but the EPA administrator kept the 

standard at the 1997 level. Fine particle air quality monitors in the Dallas-Fort Worth area have been 

above the 13 μg/m3

 level several times during the 2000-2007 time period, and tightening of the fine 

particle standard by future EPA administrators will focus regulatory attention at sources that emit fine 

particles or fine particle-forming compounds like NOx and VOC gases. 

2.3 Primary Emission Sources Involved in Barnett Shale Oil and Gas Production

There are a variety of activities that potentially create air emissions during oil and gas production in the 

Barnett Shale area. The primary emission sources in the Barnett Shale oil and gas sector include 

compressor engine exhausts, oil and condensate tank vents, production well fugitives, well drilling and 

hydraulic fracturing, well completions, natural gas processing, and transmission fugitives. Figure 3 shows 

a diagram of the major machinery and process units in the natural gas system.(3) 

2.3.1 – Point Sources 

i. Compressor Engine Exhausts 

Internal combustion engines provide the power to run compressors that assist in the production of natural 

gas from wells, pressurize natural gas from wells to the pressure of lateral lines, and power compressors 

that move natural gas in large pipelines to and from processing plants and through the interstate pipeline 

network. The engines are often fired with raw or processed natural gas, and the combustion of the natural 

gas in these engines results in air emissions. Most of the engines driving compressors in the Barnett Shale 

area are between 100 and 500 hp in size, but some large engines of 1000+ hp are also used. 

ii. Condensate and Oil Tanks 

Fluids that are brought to the surface at Barnett Shale natural gas wells are a mixture of natural gas, other 

gases, water, and hydrocarbon liquids. Some gas wells produce little or no condensate, while others 

produce large quantities. The mixture typically is sent first to a separator unit, which reduces the pressure 

of the fluids and separates the natural gas and other gases from any entrained water and hydrocarbon 

liquids. The gases are collected off the top of the separator, while the water and hydrocarbon liquids fall 

to the bottom and are then stored on-site in storage tanks. The hydrocarbon liquid is known as condensate. 
6

Figure 3. Major Units in The Natural Gas Industry From Wells to Customers. (3)

The condensate tanks at Barnett Shale wells are typically 10,000 to 20,000 gallons and hydrocarbons 

vapors from the condensate tanks can be emitted to the atmosphere through vents on the tanks. 

Condensate liquid is periodically collected by truck and transported to refineries for incorporation into 

liquid fuels, or to other processors. At oil wells, tanks are used to store crude oil on-site before the oil is 

transported to refiners. Like the condensate tanks, oil tanks can be sources of hydrocarbon vapor 

emissions to the atmosphere through tank vents. 

2.3.2 – Fugitive and Intermittent Sources 

i. Production Fugitive Emissions 

Natural gas wells can contain a large number of individual components, including pumps, flanges, valves, 

gauges, pipe connectors, compressors, and other pieces. These components are generally intended to be 

tight, but leaks are not uncommon and some leaks can result in large emissions of hydrocarbons and 

methane to the atmosphere. The emissions from such leaks are called "fugitive" emissions. These fugitive 

emissions can be caused by routine wear, rust and corrosion, improper installation or maintenance, or 

overpressure of the gases or liquids in the piping. In addition to the unintended fugitive emissions, 

pneumatic valves which operate on pressurized natural gas leak small quantities of natural gas by design 

during normal operation. Natural gas wells, processing plants, and pipelines often contain large numbers 

of these kinds of pneumatic valves, and the accumulated emissions from all the valves in a system can be 

significant. 

 

ii. Well Drilling, Hydraulic Fracturing, and Completions 

Oil and gas drilling rigs require substantial power to from wellbores by driving drill bits to the depths of 

hydrocarbon deposits. In the Barnett Shale, this power is typically provided by transportable diesel 

engines, and operation of these engines generates exhaust from the burning of diesel fuel. After the 

wellbore is formed, additional power is needed to operate the pumps that move large quantities of water, 
7

sand/glass, or chemicals into the wellbore at high pressure to hydraulically fracture the shale to increase 

its surface area and release natural gas. 

After the wellbore is formed and the shale fractured, an initial mixture of gas, hydrocarbon liquids, water, 

sand, or other materials comes to the surface. The standard hardware typically used at a gas well, 

including the piping, separator, and tanks, are not designed to handle this initial mixture of wet and 

abrasive fluid that comes to the surface. Standard practice has been to vent or flare the natural gas during 

this "well completion" process, and direct the sand, water, and other liquids into ponds or tanks. After 

some time, the mixture coming to the surface will be largely free of the water and sand, and then the well 

will be connected to the permanent gas collecting hardware at the well site. During well completions, the 

venting/flaring of the gas coming to the surface results in a loss of potential revenue and also in 

substantial methane and VOC emissions to the atmosphere. 

iii. Natural Gas Processing 

Natural gas produced from wells is a mixture of a large number of gases and vapors. Wellhead natural gas 

is often delivered to processing plants where higher molecular weight hydrocarbons, water, nitrogen, and 

other compounds are largely removed if they are present. Processing results in a gas stream that is 

enriched in methane at concentrations of usually more than 80%. Not all natural gas requires processing, 

and gas that is already low in higher hydrocarbons, water, and other compounds can bypass processing. 

Processing plants typically include one or more glycol dehydrators, process units that dry the natural gas. 

In addition to water, the glycol absorbent usually collects significant quantities of hydrocarbons, which 

can be emitted to the atmosphere when the glycol is regenerated with heat. The glycol dehydrators, 

pumps, and other machinery used in natural gas processing can release methane and hydrocarbons into 

the atmosphere, and emissions also originate from the numerous flanges, valves, and other fittings. 

iv. Natural Gas Transmission Fugitives 

Natural gas is transported from wells in mostly underground gathering lines that form networks that can 

eventually collect gas from hundreds or thousands of well locations. Gas is transported in pipeline 

networks from wells to processing plants, compressor stations, storage formations, and/or the interstate 

pipeline network for eventual delivery to customers. Leaks from pipeline networks, from microscopic 

holes, corrosion, welds and other connections, as well as from compressor intake and outlet seals, 

compressor rod packing, blow and purge operations, pipeline pigging, and from the large number of 

pneumatic devices on the pipeline network can result in large emissions of methane and hydrocarbons 

into the atmosphere and lost revenue for producers. 

2.4 Objectives

Barnett Shale area oil and gas production can emit pollutants to the atmosphere which contribute to ozone 

and fine particulate matter smog, are known toxic chemicals, or contribute to climate change. The 

objectives of this study were to examine Barnett Shale oil and gas activities and : (1) estimate emissions 

of volatile organic compounds, nitrogen oxides, hazardous air pollutants, methane, carbon dioxide, and 

nitrous oxide; (2) evaluate the current state of regulatory controls and engineering techniques used to 

control emissions from the oil and gas sector in the Barnett Shale; (3) identify new approaches that can be 

taken to reduce emissions from Barnett Shale activities; and (4) estimate the emissions reductions and 

cost effectiveness of implementation of new emission reduction methods. 
8

3.0 TECHNICAL APPROACH 

3.1 Pollutants

Estimates were made of 2007 and 2009 emissions of smog forming, air toxic, and greenhouse gas 

compounds, including nitrogen oxides (NOx), volatile organic compounds (VOCs), air toxics a.k.a. 

hazardous air pollutants (HAPs), methane (CH4), nitrous oxide (N2O), and carbon dioxide (CO2). Volatile 

organic compounds are generally carbon and hydrogen-based chemicals that exist in the gas phase or can 

evaporate from liquids. VOCs can react in the atmosphere to form ozone and fine particulate matter. 

Methane and ethane are specifically excluded from the definition of VOC because they react slower than 

the other VOC compounds to produce ozone and fine particles, but they are ozone-causing compounds 

nonetheless. The HAPs analyzed in this report are a subset of the VOC compounds, and include those 

compounds that are known or believed to cause human health effects at low doses. An example of a HAP 

compound is benzene, which is an organic compound known to contribute to the development of cancer. 

Emissions of the greenhouse gases CO2, CH4, and N2O were determined individually, and then combined 

as carbon dioxide equivalent tons (CO2e). In the combination, CH4 tons were scaled by 21 and N2O tons 

by 310 to account for the higher greenhouse gas potentials of these gases.(4) 

Emissions in 2009 were estimated by examining recent trends in Barnett Shale hydrocarbon production, 

and where appropriate, extrapolating production out to 2009. 

State regulatory programs are different for compressor engines inside the D-FW 9-county metropolitan 

area compared to outside. Engine emissions were determined separately for the two groups. 

3.2 Hydrocarbon Production

Production rates in 2007 for oil, gas, casinghead gas, and condensate were obtained from the Texas 

Railroad Commission for each county in the Barnett Shale area.(5) The large amount of production from 

wells producing from the Barnett Shale, as well as the smaller amounts of production from conventional 

formations in the area were taken together. The area was analyzed in whole, as well as by counties inside 

and outside the D-FW 9-county metropolitan area. Production rates in 2009 were predicted by plotting 

production rates from 2000-2007 and fitting a 2nd-order polynomial to the production rates via the leastsquares method and extrapolating out to 2009. 

3.3 Compressor Engine Exhausts - Emission Factors and Emission Estimates

Emissions from the natural-gas fired compressor engines in the Barnett Shale were calculated for two 

types of engines: the generally large engines that had previously reported emissions into the TCEQ's Point 

Source Emissions Inventory (PSEI) prior to 2007 (a.k.a. PSEI Engines), and the generally smaller engines 

that had not previously reported emissions (a.k.a. non-PSEI Engines). Both these engine types are located 

in the D-FW 9-county metropolitan area (a.k.a. D-FW Metro Area), as well as in the rural counties 

outside the metropolitan area (a.k.a. Outside D-FW Metro Area). The four categories of engines are 

summarized in Figure 4 and the methods used to estimate emissions from the engines are described in the 

following sections. 
9

Figure 4. Engine Categories. 

i. Non-PSEI Engines in D-FW Metropolitan Area 

Large natural gas compressor engines, located primarily at compressor stations and also some at well 

sites, have typically reported emissions to the Texas Commission on Environmental Quality (TCEQ) in 

annual Point Source Emissions Inventory (PSEI) reports. However, prior to 2007, many other stationary 

engines in the Barnett Shale area had not reported emissions to the PSEI and their contribution to regional 

air quality was unknown. In late 2007, the TCEQ conducted an engine survey for counties in the D-FW 

metropolitan area as part as efforts to amend the state clean air plan for ozone. Engine operators reported 

engine counts, engine sizes, NOx emissions, and other data to TCEQ. Data summarized by TCEQ from 

the survey was used for this report to estimate emissions from natural gas engines in the Barnett Shale 

area that had previously not reported emissions into the annual PSEI.(6) Data obtained from TCEQ 

included total operating engine power in the metropolitan area, grouped by rich vs. lean burn engines, and 

also grouped by engines smaller than 50 hp, between 50 - 500 hp, and larger than 500 hp. 

Regulations adopted by TCEQ and scheduled to take effect in early 2009 will limit NOx emissions in the 

D-FW metropolitan area for engines larger than 50 horsepower.(7) Rich burn engines will be restricted to 

0.5 g/hp-hr, lean burn engines installed or moved before June 2007 will be restricted to 0.7 g/hp-hr, and 

lean burn engines installed or moved after June 2007 will be limited to 0.5 g/hp-hr. For this report, 

emissions in 2009 from the engines in the metropolitan area subject to the new rules were estimated 

assuming 97% compliance with the upcoming rules and a 3% noncompliance factor for engines 

continuing to emit at pre-2009 levels. 

Emissions for 2007 were estimated using NOx emission factors provided by operators to TCEQ in the 

2007 survey.(6) Emissions of VOCs were determined using TCEQ-determined emission factors, and 

emissions of HAPs, CH4, and CO2 were determined using emission factors from EPA's AP-42 

document.(8,9) In AP-42, EPA provides emission factors for HAP compounds that are created by 

incomplete fuel combustion. For this report only those factors which were judged by EPA to be of high 

quality, "A" or "B" ratings, were used to estimate emissions. Emission factors for the greenhouse gas N2O 

were from an emissions inventory report issued by the American Petroleum Institute.(10) 

Beginning in 2009, many engines subject to the new NOx limits are expected to reduce their emissions 

with the installation of non-selective catalytic reduction units (NSCR), a.k.a. three-way catalysts. NSCR 

units are essentially modified versions of the "catalytic converters" that are standard equipment on every 

gasoline-engine passenger vehicle in the U.S. 

A likely co-benefit of NSCR installation will be the simultaneous reduction of VOC, HAP, and CH4

emissions. Emissions from engines expected to install NSCR units were determined using a 75% 

emissions reduction factor for VOC, HAPs, and CH4. Conversely, NSCR units are known to increase N2O 

emissions, and N2O emissions were estimated using a 3.4x factor increase over uncontrolled emission 

factors.(10) Table 2 summarizes the emission factors used to calculate emissions from the compressor 

engines identified in the 2007 survey. 

Non-PSEI Engines in 

D-FW Metro Area 

PSEI Engines in 

D-FW Metro Area 

PSEI Engines 

Outside D-FW Metro 

Area 

Non-PSEI Engines 

Outside D-FW 

Metro Area 
10

Table 2. Emission Factors for Engines Identified in the D-FW 2007 Engine Survey

Table 2-1. Emission Factors for 2007 Emissions 

engine 

type 

engine 

size 

NOx

(g/hp-hr)a

VOC 

(g/hp-hr)b

HAPs 

(g/hp-hr)c

CH4

(g/hp-hr)d

CO2 (ghp-hr)e 

N2O (ghp-hr)f

rich <50 13.6 0.43 0.088 0.89 424 0.0077 

rich 50-500 13.6 0.43 0.088 0.89 424 0.0077 

rich >500 0.9 0.43 0.088 0.89 424 0.0077 

lean <500 6.2 1.6 0.27 4.8 424 0.012 

lean >500 0.9 1.6 0.27 4.8 424 0.012 

Table 2-2. Emission Factors for 2009 Emissions 

engine 

type 

engine 

size 

NOx

(g/hp-hr)i

VOC 

(g/hp-hr)j

HAPs 

(g/hp-hr)k

CH4

(g/hp-hr)l

CO2 (ghp-hr)m 

N2O (ghp-hr)n

rich <50 13.6 0.43 0.088 0.89 424 0.0077 

rich 50-500 0.5 0.11 0.022 0.22 424 0.026 

rich >500 0.5 0.11 0.022 0.22 424 0.026 

leang <500 0.62 1.6 0.27 4.8 424 0.012 

leanh <500 0.5 1.6 0.27 4.8 424 0.012 

leang >500 0.7 1.45 0.27 4.8 424 0.012 

leanh >500 0.5 1.45 0.27 4.8 424 0.012 

notes: 

a: email from TCEQ to SMU, August 1, 2008, summary of results from 2007 engine survey 

(reference 6). 

b: email from TCEQ to SMU, August 6, 2008 (reference 8). 

c: EPA, AP-42, quality A and B emission factors; rich engine HAPs = benzene, formaldehyde, 

toluene; lean engine HAPs = acetaldehyde, acrolein, xylene, benzene, formaldehyde, methanol, 

toluene, xylene (reference 9). 

d: EPA, AP-42 (reference 9). 

e: EPA, AP-42 (reference 9). 

f: API Compendium Report (reference 10). 

g: engines installed or moved before June 2007 - TCEQ regulations establish different regulatory 

limits for engines installed or moved before or after June 2007 (reference 7). 

h: engines installed or moved after June 2007 - TCEQ regulations establish different regulatory 

limits for engines installed or moved before or after June 2007 (reference 7). 

i: rich (<50) factor from email from TCEQ to SMU, August 1, 2008 (reference 6); rich (50-500), 

rich (>500), lean (<500, post-2007), lean (>500, pre-2007), and lean (>500, post-2007) from 

TCEQ regulatory limits (reference 7); lean (<500, pre-2007) estimated with 90% control. 

j: rich (<50) from email from TCEQ to SMU (reference 8); rich (50-500) and rich (>500) 

estimated with 75% NSCR control VOC co-benefit; lean EFs from email from TCEQ to SMU 

(reference 8). Large lean engine VOC emission factor adjusted from 1.6 to 1.45 to account for 

the effects of NSPS JJJJ rules on VOC emissions. 

k: EPA, AP-42 (reference 9); rich (50-500) and rich (>500) estimated with 75% control co-benefit. 

l: EPA, AP-42 (reference 9); rich (50-500) and rich (>500) estimated with 75% control co-benefit. 

m: EPA, AP-42 (reference 9). 

n: API Compendium Report (reference 10); rich (50-500) and rich (>500) estimated with 3.4x 

N2O emissions increase over uncontrolled rate. 
11

Annual emissions from the engines identified in the 2007 survey were estimated using the pollutantspecific emission factors from Table 1 together with Equation 1, 

ME,i = 1.10E-06 * Ei * Pcap * Fhl (1) 

where ME,i was the mass emission rate of pollutant i in tons per year, Ei was the emission factor for 

pollutant i in grams/hp-hr, Pcap is installed engine capacity in hp, and Fhl is a factor to adjust for annual 

hours of operation and typical load conditions. 

Installed engine capacity in 2007 was determined for six type/size categories using TCEQ estimates from 

the 2007 engine survey - two engine types (rich vs. lean) and three engine size ranges (<50, 50-500, >500 

hp) were included.(6) TCEQ estimates of the average engine sizes and the numbers of engines in each size 

category were used to calculate the installed engine capacity for each category, as shown in Table 3. The 

Fhl factor was used to account for typical hours of annual operation and average engine loads. A Fhl value 

of 0.5 was used for this study, based on 8000 hours per year of average engine operation (8000/8760 = 

0.91) and operating engine loads of 55% of rated capacity, giving an overall hours-load factor of 0.91x 

0.55 = 0.5.(11)

Table 3. Installed Engine Capacity in 2007 D-FW Engine Survey by Engine Type and Size

engine type engine size 

(hp) 

number of 

enginesq

typical sizeq 

(hp) 

installed 

capacityr (hp) 

rich <50 12 50 585 

rich 50-500 724 140 101,000 

rich >500 200 1400 280,000 

leano <500 14 185 2540 

leanp <500 13 185 2400 

leano >500 103 1425 147,000 

leanp >500 103 1425 147,000 

notes: 

o: engines installed or moved before June 2007 - TCEQ regulations establish different regulatory 

limits for engines installed or moved before or after June 2007 (reference 7). 

p: engines installed or moved after June 2007 - TCEQ regulations establish different regulatory 

limits for engines installed or moved before or after June 2007 (reference 7). 

q: rich (<50) installed capacity based on HARC October 2006 H68 report which found that small 

rich burn engines comprise no more than 1% of engines in East Texas; rich (50-500) and rich 

(>500) installed capacity from email TCEQ to SMU in August 1, 2008 (reference 6); lean burn 

installed capacity from email TCEQ to SMU in August 1, 2008 (reference 6) along with RRC 

data suggesting that 50% of engines in 2009 will be subject to the post-June 2007 NOx rule. 

r: installed capacity = number of engines x typical size 

ii. PSEI Engines in D-FW Metropolitan Area 

In addition to the engines identified in the 2007 TCEQ survey of the D-FW 9-county metropolitan area, 

many other stationary engines are also in use in the area. These include engines that had already been 

reporting annual emissions to TCEQ in the PSEI, which are principally large engines at compressor 

stations.(12)
12

Emissions of NOx from large engines in the D-FW metropolitan area that were reporting to the TCEQ 

PSEI were obtained from the 2006 Annual PSEI, the most recent calendar year available.(12) Emissions for 

2007 and 2009 were estimated by extrapolating 2006 emissions upward to account for increases in gas 

production and compression needs from 2006-2009. For NOx emissions in 2006 and 2007, an average 

emission factor of 0.9 g/hp-hr was obtained from TCEQ.(8) Emissions in 2009 were adjusted by 

accounting for the 0.5 g/hp-hr TCEQ regulatory limit scheduled to take effect in early 2009 for the D-FW 

metropolitan area.(7) 

Unlike NOx emission, emissions of VOC were not taken directly from the PSEI. Estimates of future VOC 

emissions required accounting for the effects that the new TCEQ engine NOx limits will have on future 

VOC emissions. A compressor engine capacity production factor of 205 hp/(MMcf/day) was obtained 

from TCEQ that gives a ratio of installed horsepower capacity to the natural gas production. The 205 

hp/(MMcf/day) factor was based on previous TCEQ studies of gas production and installed large engine 

capacity. The factor was used with 2006 gas production values to estimate installed PSEI engine 

capacities for each county in the Barnett Shale area.(8) Engine capacities were divided between rich burn 

engines smaller and larger than 500 hp, and lean burn engines. To estimate 2009 emissions, rich burn 

engines smaller than 500 hp are expected to have NSCR units by 2009 and get 75% VOC, HAP, and CH4

control. Table 4 summarizes the VOC, HAP, and greenhouse gas emission factors used for the PSEI 

engines in the D-FW metropolitan area. Table 5 summarizes the estimates of installed engine capacity for 

each engine category. 

Table 4. VOC, HAP, GHG Emission Factors for PSEI Engines in D-FW Metropolitan Area 

Table 4-1. Emission Factors for 2007 Emissions

engine type 

engine 

size 

VOC EFs 

(g/hp-hr)s

HAPs EF 

(g/hp-hr)t

CH4 EF 

(g/hp-hr)u

CO2 EF 

(g/hp-hr)v

N2O (g/hphr)w

rich <500 0.43 0.088 0.89 424 0.0077 

rich >500 0.11 0.022 0.22 424 0.026 

lean all 1.6 0.27 4.8 424 0.012 

Table 4-2. Emission Factors for 2009 Emissions

engine 

type 

engine 

size 

VOC EFs 

(g/hp-hr)s

HAPs EF 

(g/hp-hr)t

CH4 EF 

(g/hp-hr)u

CO2 EF 

(g/hp-hr)v

N2O 

(g/hp-hr)w

rich <500 0.11 0.022 0.22 424 0.026 

rich >500 0.11 0.022 0.22 424 0.026 

lean all 1.47 0.27 4.8 424 0.012 

notes: 

s: email from TCEQ to SMU, August 6, 2008; 75% reductions applied to 2007 rich (>500), 2009 

rich (>500) and 2009 rich (<500) engines (reference 8). Large lean engine VOC emission factor 

adjusted from 1.6 to 1.47 to account for the effects of NSPS JJJJ rules on VOC emissions. 

t: EPA, AP-42 (reference 9); 75% reductions applied to 2007 rich (>500), 2009 rich (>500) and 

2009 rich (<500) engines (reference 9). 

u: EPA, AP-42 (reference 9) ; 75% reductions applied to 2007 rich (>500), 2009 rich (>500) and 

2009 rich (<500) engines (reference 9). 

v: EPA, AP-42 (reference 9). 

w: API Compendium Report; 2007 rich (>500), and 2009 rich (>500) and 2009 rich (<500) 

engines estimated with 3.4x N2O emissions increase over uncontrolled rate (reference 10). 
13

Table 5. Installed Engine Capacity in 2007 for PSEI Engines Inside D-FW Metropolitan Area 

engine 

type 

engine size 

(hp) 

installed 

capacity 

(%)x

installed 

capacity 

(hp)y

rich <500 0.14 59,500 

rich >500 0.52 221,000 

lean all 0.34 144,000 

notes: 

x: distribution of engine types and sizes estimated from October 2006 HARC study (reference 13). 

y: estimated as the installed capacity (%) x the total installed capacity based on the TCEQ 

compressor engine capacity production factor of 205 hp/(MMcf/day) (references 5,8). 

iii. PSEI Engines Outside D-FW Metropolitan Area 

Emissions of NOx from large engines outside the D-FW metropolitan area reporting to the TCEQ were 

obtained from the 2006 PSEI.(12) Emissions for 2007 and 2009 were estimated by extrapolating 2006 

emissions upward to account for increases in gas production from 2006-2009. Unlike engines inside the 

metropolitan area, the engines outside the metropolitan area are not subject to the new D-FW engine rules 

scheduled to take effect in 2009. 

In addition to the D-FW engine rules, in 2007 the TCEQ passed the East Texas Combustion Rule that 

limited NOx emissions from rich-burn natural gas engines larger than 240 hp in certain east Texas 

counties. Lean burn engines and engines smaller than 240 hp were exempted. The initial proposed rule 

would have applied to some counties in the Barnett Shale production area, including Cooke, Wise, Hood, 

Somervell, Bosque, and Hill, but in the final version of the rule these counties were removed from 

applicability, with the exception of Hill, which is still covered by the rule. Since gas production from Hill 

County is less than 3.5% of all the Barnett Shale area gas produced outside the D-FW metropolitan area, 

the East Texas Combustion Rule has limited impact to emissions from Barnett Shale area activity. 

Emissions of VOC, HAPs, and greenhouse gases for large engines outside the D-FW metropolitan area 

were not obtained from the 2006 PSEI. A process similar to the one used to estimate emissions from large 

engines inside the metropolitan area was used, whereby the TCEQ compressor engine capacity production 

factor, 205 hp/(MMcf/day), was used along with actual 2007 production rates to estimate total installed 

engine capacity as well as installed capacity in each county for different engine categories. Pollutantspecific emission factors were applied to the capacity estimates for each category to estimate emissions. 

Table 6 summarizes the emission factors used to estimate emissions from engines in the PSEI outside the 

D-FW metropolitan area. The engine capacities used to estimate emissions are shown in Table 7. 

Table 6. VOC, HAP, GHG Emission Factors for PSEI Engines Outside D-FW Metropolitan Area 

engine 

type 

engine 

size 

VOC 

(g/hp-hr)z

HAPs 

(g/hp-hr)aa

CH4

(g/hp-hr)aa

CO2 (ghp-hr)bb 

N2O (ghp-hr)cc

rich <500 0.43 0.088 0.89 424 0.0077 

rich >500 0.11 0.022 0.22 424 0.026 

lean all 1.45 0.27 4.8 424 0.012 

notes: 

z: email from TCEQ to SMU, August 6, 2008; 75% control applied to rich (>500) engines 

(reference 8). Large lean engine VOC emission factor adjusted from 1.6 to 1.45 to account for 

the effects of NSPS JJJJ rules on VOC emissions. 

aa: EPA, AP-42; 75% control applied to rich (>500) engines (reference 9). 
14

bb. EPA, AP-42 (reference 9). 

cc. API Compendium Report; rich (>500) engines estimated with 3.4x N2O emissions increase 

over uncontrolled rate (reference 10). 

Table 7. Installed Engine Capacity in 2007 for PSEI Engines Outside D-FW Metropolitan Area 

engine 

type 

engine size 

(hp) 

installed 

capacity 

(%)dd

installed 

capacity 

(hp)ee

rich <500 0.14 17,000 

rich >500 0.52 62,000 

lean all 0.34 41,000 

notes: 

dd: distribution of engine types and sizes estimated from October 2006 HARC study (reference 

13). 

ee: estimated as the installed capacity (%) x the total installed capacity based on the TCEQ 

compressor engine capacity production factor of 205 hp/(MMcf/day) (references 5,8). 

iv. Non-PSEI Engines Outside the D-FW Metropolitan Area 

The Point Source Emissions Inventory (PSEI) only contains emissions from a fraction of the stationary 

engines in the Barnett Shale area, principally the larger compressor engines with emissions above the 

PSEI reporting thresholds. The 2007 TCEQ engine survey of engines inside the D-FW metropolitan area 

demonstrated that the PSEI does not include a substantial fraction of total engine emissions. Most of the 

missing engines in the metropolitan area were units with emissions individually below the TCEQ 

reporting thresholds, but the combined emissions from large numbers of smaller engines can be 

substantial. The results of the 2007 survey indicated that there were approximately 680,000 hp of installed 

engine capacity in the D-FW metropolitan area not previously reporting to the PSEI.(6) 

Natural gas and casinghead gas production from metropolitan counties in 2007 was approximately 1,000 

Bcf . A "non-PSEI" compressor engine capacity production factor of 226 hp/(MMcf/day) was determined 

for the Barnett Shale area. This capacity factor accounts for all the small previously hidden engines that 

the 2007 survey showed come into use in oil and gas production activities in the area. This production 

factor was used along with 2007 gas production rates for the counties outside the D-FW metropolitan area 

to estimate non-PSEI engine emissions from these counties. The new production factor accounts for the 

fact that counties outside the metro area likely contain previously unreported engine capacity in the same 

proportion to the unreported engine capacity that was identified during the 2007 engine survey inside the 

metro area. Without a detailed engine survey in the rural counties of the same scope as the 2007 survey 

performed within the D-FW metropolitan counties, use of the non-PSEI production factor provides a way 

to estimate emissions from engines not yet in state or federal inventories. The capacity of non-PSEI 

reporting engines in the rural counties of the Barnett Shale was determined by this method to be 132,000 

hp. Emission factors used to estimate emissions from these engines, and the breakdown of total installed 

engine capacity into engine type and size categories, are shown in Tables 8 and 9. 
15

Table 8. Emission Factors for Non-PSEI Engines Outside D-FW Metropolitan Area 

engine 

type 

engine 

size 

NOx

(g/hp-hr)ff

VOC 

(g/hphr)gg

HAPs 

(g/hphr)hh

CH4

(g/hphr)hh

CO2 (ghp-hr)ii 

N2O (ghp-hr)jj

rich <50 13.6 0.43 0.088 0.89 424 0.0077 

rich 50-500 10.3 0.43 0.088 0.89 424 0.0077 

rich >500 0.89 0.11 0.022 0.22 424 0.026 

lean <500 5.2 1.45 0.27 4.8 424 0.012 

lean >500 0.9 1.6 0.27 4.8 424 0.012 

notes: 

ff: email from TCEQ to SMU, August 1, 2008 (reference 6). Rich burn engines 50-500 hp NOx 

emission factor adjusted from 13.6 to 10.3 to account for the effects of NSPS JJJJ rules on NOx 

emissions and the effect of the TCEQ East Texas Combustion Rule on Hill County production. 

Rich burn engines >500 adjusted from 0.9 to 0.89 to account for the effect of the TCEQ East 

Texas Combustion Rule on Hill County production. Lean burn <500 hp engine post-2007 

emission factor adjusted from 6.2 to 5.15 to account for the effects of NSPS JJJJ rules on NOx 

emissions. 

gg: email from TCEQ to SMU, August 6, 2008; rich (>500) based on 75% control (reference 8). 

Small lean engine VOC emission factor adjusted from 1.6 to 1.45 to account for the effects of 

NSPS JJJJ rules on VOC emissions. 

hh: EPA, AP-42; rich (>500) based on 75% control (reference 9). 

ii: EPA, AP-42 (reference 9). 

jj: API Compendium Report; rich (>500) estimated with 3.4x N2O emissions increase over 

uncontrolled rate (reference 10). 

Table 9. Installed Engine Capacity for Non-PSEI Engines Outside Metropolitan Area by Engine Type/Size

engine type engine size 

(hp) 

installed 

capacity (%) 

installed 

capacity (hp) 

rich <50 0.01 110 

rich 50-500 15 20,000 

rich >500 41 55,000 

lean <500 0.73 970 

lean >500 43 57,000 

3.2 Condensate and Oil Tanks - Emission Factors and Emission Estimates

Condensate and oil tanks can be significant emitters of VOC, methane, and HAPs. A report was published 

in 2006 by URS Corporation which presented the results of a large investigation of emissions from 

condensate and oil tanks in Texas.(14) Tanks were sampled from 33 locations across East Texas, including 

locations in the Barnett Shale area. Condensate tanks in the Barnett Shale were sampled in Denton and 

Parker Counties, and oil tanks were sampled in Montague County. The results from the URS investigation 

were used in this study to calculate Barnett Shale-specific emission factors for VOC, CH4, HAPs, and 

CO2, instead of using a more general Texas-wide emission factor. The URS study was conducted during 

daylight hours in July 2006, when temperatures in North Texas are significantly above the annual 

average. Therefore, the results of the URS investigation were used to calculate "Peak Summer" emissions. 

The HAPs identified in the URS study included n-hexane, benzene, trimethylpentane, toluene, 

ethylbenzene, and xylene. The emission factors used to calculate peak summer emissions from Barnett 
16

Shale condensate and oil tanks are shown in Table 10-1. Figure 5 shows a condensate tank battery from 

the 2006 URS study report. 

Figure 5. Example Storage Tank Battery (left), Separators (right), and Piping.(14)

Computer modeling data were provided during personal communications with a Barnett Shale gas 

producer who estimated VOC, CH4, HAPs, and CO2 emissions from a number of their condensate 

tanks.(15) The tanks were modeled with ambient temperatures of 60 F, which the producer used to 

represent annual hourly mean temperatures in the D-FW area. These modeling results were used in this 

report to predict annual average condensate tank emission factors for the Barnett Shale area. The annual 

average emission factors are shown in Table 10-2. 
17

Table 10. Condensate and Oil Tank Emission Factors for the Barnett Shale. 

Table 10-1. Peak Summer Emission Factors.(14)

 VOC 

(lbs/bbl) 

HAPs 

(lbs/bbl) 

CH4

(lbs/bbl) 

CO2

(lbs/bbl) 

condensate 48 3.7 5.6 0.87 

oil 6.1 0.25 0.84 2.7 

Table 10-2. Annual Average Emission Factors.(15)

 VOC 

(lbs/bbl) 

HAPs 

(lbs/bbl) 

CH4

(lbs/bbl) 

CO2

(lbs/bbl) 

condensate 10 0.20 1.7 0.23 

oil 1.3 0.013 0.26 0.70 

Emissions for 2007 were calculated for each county in the Barnett Shale area, using condensate and oil 

production rates from the RRC.(5) Emissions for 2009 were estimated with the extrapolated 2000-2007 

production rates for the year 2009. Emissions were calculated with Equation 2, 

MT,i = Ei * Pc * C / 2000 (2) 

where MT,i was the mass emission rate of pollutant i in tons per year, Ei was the emission factor for 

pollutant i in lbs/bbl, Pc was the production rate of condensate or oil, and C was a factor to account for the 

reduction in emissions due to vapor-emissions controls on some tanks. For this report, the use of vaporemissions controls on some tanks was estimated to provide a 25% reduction in overall area-wide 

emissions. 

3.3 Production Fugitives - Emission Factors and Emission Estimates

Fugitive emissions from production wells vary from well to well depending on many factors, including 

the tightness of casing heads and fittings, the age and condition of well components, and the numbers of 

flanges, valves, pneumatic devices, or other components per well. A previous study published by the Gas 

Research Institute and U.S. EPA investigated fugitive emissions from the natural gas industry, including 

emissions from production wells, processing plants, transmission pipelines, storage facilities, and 

distribution lines.(15) Fugitive emissions of natural gas from the entire natural gas network were estimated 

to be 1.4% of gross production. Production fugitives, excluding emissions from condensate tanks (which 

are covered in another section of this report), were estimated by the GRI/EPA study to be approximately 

20% of total fugitives, or 0.28% of gross production. 

Production fugitive emissions from Barnett Shale operations in 2007 were estimated as 0.28% of gross 

natural gas and casinghead gas production of 1098 Bcf/yr. Volume emissions were converted to mass 

emissions with a density of 0.0483 lb/scf. Multiple Barnett Shale gas producers provided gas 

composition, heat content data, and area-wide maps of gas composition. The area-wide maps of gas 

composition were used to estimate gas composition for each producing county. These county-level data 

were weighted by the fraction of total area production that originated from each county to calculate areawide emission factors. Table 11 presents the production fugitives emission factors. 
18

Table 11. Production Fugitives Emission Factors for the Barnett Shale. 

VOC 

(lbs/MMcf) 

HAPs 

(lbs/MMcf) 

CH4

(lbs/MMcf)

CO2

(lbs/MMcf)

11 0.26 99 1.9 

Emissions were calculated with Equation 3, 

MF,i = Ei * Pg / 2000 (3) 

where MF,i was the mass emission rate of pollutant i in tons per year, Ei was the emission factor for 

pollutant i in lbs/MMcf, and Pg was the production rate of natural and casinghead gas. The area-wide 

unprocessed natural gas composition based on data from gas producers was 74% CH4, 8.2% VOC, 1.4% 

CO2, and 0.20% HAPs, on a mass % basis. HAPs in unprocessed natural gas can include low levels of nhexane, benzene, or other compounds. 

3.4 Well Drilling, Hydraulic Fracturing Pump Engines, and Well Completions - Emission Factors and 

Emission Estimates

Emissions from the diesel engines used to operate well drilling rigs and from the diesel engines that 

power the hydraulic fracturing pumps were estimated based on discussions with gas producers and other 

published data. Well drilling engine emissions were based on 25 days of engine operation for a typical 

well, with 1000 hp of engine capacity, a load factor of 50%, and operation for 12 hours per day. 

Hydraulic fracturing engine emissions were based on 4.5 days of operation for a typical well, with 1000 

hp of capacity, a load factor of 50%, and operation for 12 hours per day. Some well sites in the D-FW are 

being drilled with electric-powered rigs, with electricity provided off the electrical grid. Engines emission 

estimates in this report were reduced by 25% to account for the number of wells being drilled without 

diesel-engine power.

In addition to emissions from drilling and fracing engines, previous studies have examined emissions of 

natural gas during well completions. These studies include one by the Williams gas company, which 

estimated that a typical well completion could vent 24,000 Mcf of natural gas.(18) A report by the EPA 

Natural Gas Star program estimated that 3000 Mcf could be produced from typical well completions.(19) A 

report by ENVIRON published in 2006 describes emission factors used in Wyoming and Colorado to 

estimate emissions from well completions, which were equivalent to 1000 to 5000 Mcf natural 

gas/well.(20) Another report published in the June 2005 issue of the Journal of Petroleum Technology 

estimated that well completion operations could produce 7,000 Mcf. (21) Unless companies bring special 

equipment to the well site to capture the natural gas and liquids that are produced during well 

completions, these gases will be vented to the atmosphere or flared. 

Discussions with Barnett Shale gas producers that are currently employing “green completion” methods 

to capture natural gas and reduce emissions during well completions suggests that typical well 

completions in the Barnett Shale area can release approximately 5000 Mcf of natural gas/well. This value, 

which is very close to the median value obtained from previous studies (References 18-21), was used to 

estimate well completion emissions in this report. 

The number of completed gas wells reporting to the RRC was plotted for the Feb. 2004 – Feb. 2008 time 

period.(22) A least-squares regression line was fit to the data, and the slope of the line provides the 
19

approximate number of new completions every year. A value of 1042 completions/year was relatively 

steady throughout the 2004-2008 time period (linear R2

 = 0.9915). Emissions in 2007 and 2009 from well 

completions were estimated using 1000 new well completions/year for each year. Emission estimates 

were prepared for the entire Barnett Shale area, as well as inside and outside the D-FW metropolitan area. 

The data from 2004-2008 show that 71 percent of new wells are being installed in the D-FW metropolitan 

area, 29 percent of new wells are outside the metropolitan area, and the rate of new completions has been 

steady since 2004. Emissions of VOC, HAPs, CH4, and CO2 were estimated using the same natural gas 

composition used for production fugitive emissions.

Some gas producers are using green completion techniques to reduce emissions, while others destroy 

natural gas produced during well completions by flaring. To account for the use of green completions and 

control by flaring, natural gas emission estimates during well completions were reduced by 25% in this 

report. 

 

3.5 Processing Fugitives - Emission Factors and Emission Estimates

Fugitive emissions from natural gas processing will vary from processing plant to processing plant, 

depending on the age of the plants, whether they are subject to federal rules such as the NSPS Subpart 

KKK requirements, the chemical composition of the gas being processed, the processing capacity of the 

plants, and other factors. A previous study published by the Gas Research Institute and U.S. EPA 

investigated fugitive emissions from the natural gas industry, including emissions from production wells, 

processing plants, transmission pipelines, storage facilities, and distribution lines.(15) Fugitive emissions of 

natural gas from the entire natural gas industry were estimated to be 1.4% of gross production. Processing 

fugitives, excluding compressor engine exhaust emissions that were previously addressed in this report, 

were estimated to be approximately 9.7% of total fugitives, or 0.14% of gross production. 

Processing fugitive emissions from Barnett Shale operations in 2007 were estimated as 0.14% of the 

portion of gas production that is processed, estimated as 519 Bcf/yr. Emission factors for VOC, HAPs, 

CH4, and CO2 were estimated with an area-wide natural gas composition, excluding the gas from areas of 

the Barnett Shale that does not require any processing. Volume emissions were converted to mass 

emissions with a natural gas density of 0.0514 lb/scf. Table 12 presents the processing fugitives emission 

factors. 

Table 12. Processing Fugitives Emission Factors for the Barnett Shale. 

VOC 

(lbs/MMcf) 

HAPs 

(lbs/MMcf) 

CH4

(lbs/MMcf)

CO2

(lbs/MMcf)

14 0.3 45 1.0 

Processing fugitive emissions were calculated with Equation 4, 

MP,i = Ei * Pg / 2000 (4) 

where MP,i was the mass emission rate of pollutant i in tons per year, Ei was the emission factor for 

pollutant i in lbs/MMcf, and Pg was the production rate of natural and casinghead gas. The composition of 

the natural gas produced in the Barnett Shale that is processed was estimated to be 65% CH4, 1.5% CO2, 

20% VOC, and 0.48% HAPs, on a mass % basis. Not all natural gas from the Barnett Shale area requires 

processing. 
20

3.6 Transmission Fugitives - Emission Factors and Emission Estimates

Fugitive emissions from the transmission of natural gas will vary depending on the pressure of pipelines, 

the integrity of the piping, fittings, and valves, the chemical composition of the gas being transported, the 

tightness of compressor seals and rod packing, the frequency of blow down events, and other factors. A 

previous study published by the Gas Research Institute and U.S. EPA investigated fugitive emissions 

from the natural gas industry, including emissions from production wells, processing plants, transmission 

pipelines, storage facilities, and distribution lines.(15) Fugitive emissions of natural gas from the entire 

natural gas industry were estimated to be 1.4% of gross production. Transmission fugitives, excluding 

compressor engine exhaust emissions that were previously addressed in this report, were estimated to be 

approximately 35% of total fugitive emissions, or 0.49% of gross production. Transmission includes the 

movement of natural gas from the wells to processing plants, and the processing plants to compressor 

stations. It does not include flow past the primary metering and pressure regulating (M&PR) stations and 

final distribution lines to customers. Final distribution of gas produced in the Barnett Shale can happen 

anywhere in the North American natural gas distribution system, and fugitive emissions from these lines 

are beyond the scope of this report. 

Transmission fugitive emissions from Barnett Shale operations in 2007 were estimated as 0.49% of gross 

natural gas and casinghead gas production of 1098 Bcf/yr. Emission factors for VOC, HAPs, CH4, and 

CO2 were developed considering that a significant portion of the gas moving through the network does 

not require processing, while the portion of the gas with higher molecular weight compounds will go 

through processing. In addition, all gas will have a dry (high methane) composition after processing as it 

moves to compressor stations and then on to customers. Overall area-wide transmission fugitive 

emissions were calculated with a gas composition of 76% CH4, 5.1% VOC, 1.4% CO2, and 0.12% HAPs, 

by mass %. Table 13 presents the transmission fugitives emission factors. 

Table 13. Transmission Fugitives Emission Factors for the Barnett Shale. 

VOC 

(lbs/MMcf) 

HAPs 

(lbs/MMcf) 

CH4

(lbs/MMcf)

CO2

(lbs/MMcf)

12 0.28 175 3.3 

Transmission fugitive emissions were calculated with Equation 5, 

Mtr,i = Ei * Pg / 2000 (5) 

where Mtr,i was the mass emission rate of pollutant i in tons per year, Ei was the emission factor for 

pollutant i in lbs/MMcf, and Pg was the production rate of natural and casinghead gas. 
21

4.0 RESULTS 

4.1 Point Sources

i. Compressor Engine Exhausts 

Emissions from compressor engines in the Barnett Shale area are summarized in Tables 14 and 15. 

Results indicate that engines are significant sources of ozone and particulate matter precursors (NOx and 

VOC), with 2007 emissions of 66 tpd. Emissions of NOx are expected to fall 50% from 32 to 16 tpd for 

engines in the Dallas-Fort Worth metropolitan area because of regulations scheduled to take effect in 

2009 and the installation of NSCR units on many engines. Large reductions are unlikely because of the 

growth in natural gas production. For engines outside the D-FW metropolitan area counties, NOx

emissions will rise from 19 tpd to 30 tpd because of the projected growth in natural gas production and 

the fact that engines in these counties are not subject to the same regulations as those inside the 

metropolitan area. 

Emissions of volatile organic compounds are expected to increase from 15 to 21 tpd from 2007 to 2009, 

because of increasing natural gas production. The 2009 engine regulations for the metropolitan area 

counties do have the effect of reducing VOC emissions from some engines, but growth in production 

compensates for the reductions and VOC emissions from engines as a whole increase. 

HAP emissions, which include toxic compounds such as formaldehyde and benzene, are expected to 

increase from 2.7 to 3.6 tpd from 2007 to 2009. 

Greenhouse gas emissions from compressor engines are shown in Table 15. Emissions in 2007 as carbon 

dioxide equivalent tons were approximately 8900 tpd, and emissions are estimated to increase to nearly 

14,000 tpd by 2009. Carbon dioxide contributed the most to the greenhouse gas emissions, accounting for 

approximately 90% of the CO2 equivalent tons. The methane contribution to greenhouse gases was 

smaller for the engine exhausts than for the other sources reviewed in this report. 

Table 14. Emissions from Compressor Engine Exhausts. 

NOx VOC HAPs CH4 CO2e NOx VOC HAPs CH4 CO2e

D-FW Metro Engines 32 13 2.2 35 7261 16 16 2.9 49 11294

Outside Metro Engines 19 2.5 0.45 7.4 1649 30 3.8 0.70 12 2583

Engines Total 51 15 2.7 43 8910 46 19 3.6 61 13877

2007 2009

Pollutant (tpd) Pollutant (tpd)

Table 15. Greenhouse Gas Emissions Details.

CO2 CH4 N2O CO2e CO2 CH4 N2O CO2e

D-FW Metro Engines 6455 35 0.20 7261 10112 49 0.28 11294

Outside Metro Engines 1475 7.4 0.062 1649 2310 12 0.10 2583

Engines Total 7930 43 0.26 8910 12422 61 0.38 13877

2007 2009

Pollutant (tpd) Pollutant (tpd)
22

ii. Oil and Condensate Tanks 

Emissions from condensate and oil tanks are shown in Tables 16-1 and 16-2. Annual average emissions 

are shown in Table 16-1, and peak summer emissions are shown in Table 16-2. 

On an annual average, emissions of VOCs from the tanks were 19 tpd in 2007, and emissions will 

increase to 30 tpd in 2009. Because of the effects of temperature on hydrocarbon liquid vapor pressures, 

peak summer emissions of VOC were 93 tpd in 2007, and summer emissions will increase to 146 tpd in 

2009. 

Substantial HAP emissions during the summer were determined for the tanks, with 2007 emissions of 7.2 

tpd and 2009 emissions of 11 tpd. Greenhouse gas emissions from the tanks are almost entirely from CH4, 

with a small contribution from CO2. Annual average greenhouse gas emissions were 95 tpd in 2007, and 

will increase to 149 tpd in 2009. 

Table 16. Emissions from Condensate and Oil Tanks. 

Table 16-1. Annual Average Tank Emissions 

VOC HAPs CH4 CO2e VOC HAPs CH4 CO2e

D-FW Metro Tanks 8.9 0.18 2.1 44 14 0.28 3.2 69

Outside Metro Tanks 10 0.21 2.4 51 16 0.32 3.8 80

Tanks Total 19 0.39 4.5 95 30 0.60 7.0 149

2009

Pollutant (tpd)

2007

Pollutant (tpd)

Table 16-2. Peak Summer Tank Emissions 

VOC HAPs CH4 CO2e VOC HAPs CH4 CO2e

D-FW Metro Tanks 43 3.3 6.7 142 67 5.2 10 222

Outside Metro Tanks 50 3.8 7.8 166 79 6.0 12 261

Tanks Total 93 7.2 15 308 146 11 23 483

2009

Pollutant (tpd)

2007

Pollutant (tpd)

4.2 Fugitive and Intermittent Sources

i. Production Fugitives 

Emissions from fugitive sources at Barnett Shale production sites are shown in Table 17. Production 

fugitives are significant sources of VOC emissions, with VOC emissions expected to grow from 2007 to 

2009 from 17 to 26 tpd. Production fugitives are also very large sources of methane emissions, leading to 

large CO2 equivalent greenhouse gas emissions. Greenhouse gas emissions were 3100 tpd in 2007 and 

will be 4900 tpd in 2009. 

Table 17. Emissions from Production Fugitives. 

VOC HAPs CH4 CO2e VOC HAPs CH4 CO2e

D-FW Metro Production Fugitives 11 0.27 102 2147 18 0.43 160 3363

Outside Metro Production Fugitives 5.2 0.12 46 971 8.1 0.19 72 1521

Production Fugitives Total 17 0.40 148 3118 26 0.62 232 4884

2007

Pollutant (tpd)

2009

Pollutant (tpd)
23

ii. Well Drilling, Hydraulic Fracturing, and Well Completions 

Emissions from well drilling engines, hydraulic fracturing pump engines, and well completions are shown 

in Table 18. These activities are significant sources of the ozone and fine particulate precursors, as well as 

very large sources of greenhouse gases, mostly from methane venting during well completions. 

Greenhouse gas emissions are estimated to be greater than 4000 CO2 equivalent tons per year. Based on 

2000-2007 drilling trends, approximately 71% of the well drilling, fracing, and completion emissions will 

be coming from counties in the D-FW metropolitan area, with the remaining 29% coming from counties 

outside the metropolitan area. 

Table 18. Emissions from Well Drilling, Hydraulic Fracturing, and Well Completions. 

NOx VOC HAPs CH4 CO2e NOx VOC HAPs CH4 CO2e

D-FW Metro Well Drilling and Well 

Completion 3.9 15 0.35 130 2883 3.9 15 0.35 130 2883

Outside Metro Well Drilling and Well 

Completions 1.6 6.1 0.14 53 1178 1.6 6.1 0.14 53 1178

Well Drilling and Completions 

Emissions Total 5.5 21 0.49 183 4061 5.5 21 0.49 183 4061

2007 2009

Pollutant (tpd) Pollutant (tpd)

iii. Natural Gas Processing 

Processing of Barnett Shale natural gas results in significant emissions of VOC and greenhouse gases, 

which are summarized in Table 19. Emissions of VOC were 10 tpd in 2007 and are expected to increase 

to 15 tpd by 2009. Greenhouse gas emissions, largely resulting from fugitive releases of methane, were 

approximately 670 tpd in 2007 and will be approximately 1100 tpd in 2009. 

Table 19. Emissions from Natural Gas Processing.

VOC HAPs CH4 CO2e VOC HAPs CH4 CO2e

D-FW Metro Processing Fugitives 6.7 0.16 22 464 10 0.26 35 727

Outside Metro Processing Fugitives 3.0 0.07 10 210 4.7 0.12 16 329

Processing Fugitives Total 10 0.24 32 674 15 0.37 50 1056

2007

Pollutant (tpd)

2009

Pollutant (tpd)

iv. Transmission Fugitives 

Transmission of Barnett Shale natural gas results in significant emissions of greenhouse gases and VOC. 

Greenhouse gas emissions from transmission fugitives are larger than from any other source category 

except compressor engine exhausts. Emissions of VOC in 2007 from transmission were approximately 18 

tpd in 2007 and are estimated to be 28 tpd in 2009. Greenhouse gas emissions from methane fugitives 

result in emissions of approximately 5500 tpd in 2007 and 8600 tpd in 2009. Emissions are summarized 

in Table 20. 

Table 20. Emissions from Natural Gas Transmission Fugitives. 

VOC HAPs CH4 CO2e VOC HAPs CH4 CO2e

D-FW Metro Transmission Fugitives 12 0.29 181 3799 19 0.46 283 5952

Outside Metro Transmission Fugitives 5.5 0.13 82 1718 8.6 0.21 128 2691

Transmission Fugitives Total 18 0.43 262 5517 28 0.67 411 8643

2007

Pollutant (tpd)

2009

Pollutant (tpd)
24

4.3 All Sources Emission Summary

Emissions from all source categories in the Barnett Shale area are summarized in Table 21-1 on an annual 

average basis, and are summarized in Table 12-2 on a peak summer basis. Annual average emissions for 

2009 of ozone and particulate precursors (NOx and VOC) were approximately 191 tpd, and peak summer 

emissions of these compounds were 307 tpd. The portion of those emissions originating from the 5-

counties in the D-FW metropolitan area with significant oil and gas production was 133 tpd during the 

summer (Tarrant, Denton, Parker, Johnson, and Ellis). 

Estimates of greenhouse gas emissions from the sector as a whole were quite large, with 2009 emissions 

of approximately 33,000 tpd. The greenhouse gas contribution from compressor engines was dominated 

by carbon dioxide, while the greenhouse gas contribution from all other sources was dominated by 

methane. Emissions of HAPs were significant from Barnett Shale activities, with emissions in 2009 of 6.4 

tpd in 2009 on an annual average, and peak summer emissions of 17 tpd. 

Table 21. Emissions Summary for All Source Categories. 

Table 21-1. Annual Average Emissions from All Sources. 

NOx VOC HAPs CH4 CO2e NOx VOC HAPs CH4 CO2e

Compressor Engine Exhausts 51 15 2.7 43 8910 46 19 3.6 61 13877

Condensate and Oil Tanks 0 19 0.39 4.5 95 0 30 0.60 7.0 149

Production Fugitives 0 17 0.40 148 3118 0 26 0.62 232 4884

Well Drilling and Completions 5.5 21 0.49 183 4061 5.5 21 0.49 183 4061

Gas Processing 0 10 0.24 32 674 0 15 0.37 50 1056

Transmission Fugitives 0 18 0.43 262 5517 0 28 0.67 411 8643

Total Daily Emissions (tpd) 56 100 4.6 673 22375 51 139 6.4 945 32670

2007 2009

Pollutant (tpd) Pollutant (tpd)

Table 21-2. Peak Summer Emissions from All Sources.

NOx VOC HAPs CH4 CO2e NOx VOC HAPs CH4 CO2e

Compressor Engine Exhausts 51 15 2.7 43 8910 46 19 3.6 61 13877

Condensate and Oil Tanks 0 93 7.2 15 308 0 146 11 23 483

Production Fugitives 0 17 0.40 148 3118 0 26 0.62 232 4884

Well Drilling and Completions 5.5 21 0.49 183 4061 5.5 21 0.49 183 4061

Gas Processing 0 10 0.24 32 674 0 15 0.37 50 1056

Transmission Fugitives 0 18 0.43 262 5517 0 28 0.67 411 8643

Total Daily Emissions (tpd) 56 174 11 683 22588 51 255 17 961 33004

2007 2009

Pollutant (tpd) Pollutant (tpd)

Emissions of nitrogen oxides from oil and gas production in the Barnett Shale were dominated by 

emissions from compressor engines, with a smaller contribution from well drilling and fracing pump 

engines. All source categories in the Barnett Shale contributed to VOC emissions, but the largest group of 

VOC sources was condensate tank vents. Figure 6 presents the combined emissions of NOx and VOC 

during the summer from all source categories in the Barnett Shale. 
25

Figure 6. Summer Emissions of Ozone & Fine Particulate Matter Precursors (NOx and VOC) from Barnett 

Shale Sources in 2009. 

4.4 Perspective on the Scale of Barnett Shale Air Emissions

Barnett Shale oil and gas production activities are significant sources of air emissions in the north-central 

Texas area. To help put the levels of Barnett Shale emissions into context, recent government emissions 

inventories for the area were reviewed, and emission rates of smog precursor emissions were examined. 

 

The Dallas-Fort Worth area is home to two large airports, Dallas Love Field and Dallas-Fort Worth 

International Airport, plus a number of smaller airports. A recent emissions inventory has estimated 2009 

NOx emissions from all area airports to be approximately 14 tpd, with VOC emissions at approximately 

2.6 tpd, resulting in total ozone and particulate matter precursor emissions of approximately 16 tpd. (22-24) 

For comparison, emissions of VOC + NOx in summer 2009 from just the compressor engines in the 

Barnett Shale area will be approximately 65 tpd, and summer condensate tanks emissions will be 

approximately 146 tpd. In 2009, even after regulatory efforts to reduce NOx emissions from certain 

compressor engine types, Barnett Shale oil and gas emissions will be many times the airports' emissions. 

Recent state inventories have also compiled emissions from on-road mobile sources like cars, trucks, etc., 

in the 9-county D-FW metropolitan area.(25) By 2009, NOx + VOC emissions from mobile sources in the 

9-county area were estimated by the TCEQ to be approximately 273 tpd. The portion of on-road motor 

vehicle emissions from the 5-counties in the D-FW metropolitan area with significant oil and gas 

production was 121 tpd (Denton, Tarrant, Parker, Johnson, and Ellis). As indicated earlier, summer oil 

and gas emissions in the 5-counties of the D-FW metropolitan area with significant oil and gas production 

was estimated to be 165 tpd, indicating that the oil and gas sector likely has greater emissions than motor 

vehicles in these counties (165 vs. 121 tpd). 

Emissions of NOx and VOC in the summer of 2009 from all oil and gas sources in the Barnett Shale 21-

county area will exceed emissions from on-road mobile sources in the D-FW metropolitan area by more 

than 30 tpd (307 vs. 273 tpd). 

Transmission 

Fugitives = 28 tpd

Condensate and 

Oil Tanks = 146 tpd

Gas Processing = 

15 tpd

Well Drilling and 

Completions = 26 

tpd

Compressor 

Engines = 65 

Production Fugitives = 26 tpd

summer total =

307 tpd
26

Figure 7 summarizes summer Barnett Shale-related emissions, plus TCEQ emission estimates from the 

airports and on-road mobile sources. Figure 8 presents annual average emissions from these sources. 

Figure 7. Barnett Shale Activity, D-FW Area Airports, & Mobile Sources (Summer 2009 Emissions). 

0

50

100

150

200

250

300

350

All Airports DͲFW Metro

OnͲRoad

Mobile Sources

DͲFW OnͲRoad

Mobile Sources

in Five Counties

with Oil/Gas

Barnett Sources

w/in DͲFW Five

Counties with

Oil/Gas

Barnett 21Ͳ

County Engines

and Tanks

Barnett 21Ͳ

County All

Oil/Gas Sources

16

273

121

165

212

307

2009NOx and VOC

Emissions (tpd)
27

Figure 8. Barnett Shale Activity, D-FW Area Airports, & Mobile Sources (Annual Average 2009 Emissions). 

0

50

100

150

200

250

300

350

All Airports DͲFW Metro

OnͲRoad

Mobile Sources

DͲFW OnͲRoad

Mobile Sources

in Five Counties

with Oil/Gas

Barnett Sources

w/in DͲFW Five

Counties with

Oil/Gas

Barnett 21Ͳ

County Engines

and Tanks

Barnett 21Ͳ

County All

Oil/Gas Sources

16

273

121 112

96

191

2009NOx and VOC

Emissions (tpd)
28

5.0 EMISSIONS REDUCTION OPPORTUNITIES

The previous sections of this report have estimated the emission rates of ozone and particulate matter 

precursor compounds, air toxic compounds, and greenhouse gases from different oil and gas sources in 

the Barnett Shale area. For several of these source categories, off-the-shelf options are available which 

could significantly reduce emissions, resulting in important air quality benefits. Some of these emissions 

reductions would also result in increased production of natural gas and condensate, providing an 

economic payback for efforts to reduce emissions. 

5.1 Compressor Engine Exhausts

Compressors in oil and gas service in the Barnett Shale perform vital roles, to either help get oil and gas 

out of the shale, to increase pressures of gas at the surface, and to provide the power for the large 

interstate pipeline systems that move high volumes of gas from production to processing and to 

customers. At present, most of the work to operate the compressors comes from natural gas-fired internal 

combustion engines, and these engines can be significant sources of emissions. 

New TCEQ rules are scheduled to become effective in early 2009 and they will reduce NOx, VOC, and 

other emissions from a subset of the engines in the Barnett Shale – those that are currently in the D-FW 

metropolitan area that had typically not reported into the Texas point source emissions inventory for 

major sources. These rules are a good first step in addressing emissions from these sources, which had 

previously gone unnoticed in state emission inventory and regulatory efforts. 

However, engines outside the D-FW metropolitan area are not subject to the rule. And even within the 

metropolitan area, the rule will not have the effect of greatly reducing emissions in 2009 compared to 

2007 levels, since growth in oil and gas production (and the new engines that are going to be required to 

power the growth) will begin to overtake the benefits that come from reducing emissions from the pre2009 fleet (see Table 14). 

Two available options for reducing emissions from engines in the Barnett Shale area are: (1) extending 

the TCEQ 2009 engine regulation to all engines in the Barnett Shale, and (2) replacing internal 

combustion engines with electric motors as the sources of compression power. 

i. Extending the 2009 Engine Rule to Counties Outside the D-FW Metropolitan Area 

Regulations adopted by TCEQ for the D-FW metropolitan area and scheduled to take effect in early 2009 

will limit NOx emissions from engines larger than 50 horsepower.(7) Rich burn engines will be restricted 

to 0.5 g/hp-hr, lean burn engines installed or moved before June 2007 will be restricted to 0.7 g/hp-hr, and 

lean burn engines installed or moved after June 2007 will be limited to 0.5 g/hp-hr. Applying these rules 

to engines outside the metropolitan area would reduce 2009 NOx emissions from a large number of 

engines, in particular, rich burn engines between 50 to 500 hp. Emissions of NOx in 2009 from the 

engines outside the metropolitan area would drop by approximately 6.5 tpd by extending the D-FW 

engine rule, an amount greater than mobile source emissions in all of Johnson County (4 tpd), or more 

than 50% of the emissions from Dallas-Fort Worth International Airport (12.6 tpd). 

Extending the D-FW engine rule to counties outside the metropolitan area would likely result in many 

engine operators installing NSCR systems on rich burn engine exhausts. These systems would not only 

reduce emissions of NOx, but they would also be expected to reduce emissions of VOC, the other ozone 

and particulate matter precursor, by approximately 75% or greater.(26a) Additional co-benefits of NSCR 

installations would include lower emissions of organic HAP compounds like benzene and formaldehyde, 

lower emissions of methane, and lower emissions of carbon monoxide. The level of HAP, methane, and 
29

carbon monoxide control would also be expected to be 75% or greater with typical NSCR 

installations.(26a)

Analyses of NSCR installations and operating costs by numerous agencies have indicated that the 

technology is very cost effective. For example, the Illinois Environmental Protection Agency estimated in 

2007 that NSCR could control NOx from 500 hp engines at approximately $330/ton.(26b) The U.S. EPA in 

2006 estimated that NSCR could control NOx from 500 hp engines at approximately $92 to 105/ton.(27) A 

2005 report examining emissions reductions from compressor engines in northeast Texas estimated NOx

cost effectiveness for NSCR at $112-183/ton and identified VOC reductions as an important cobenefit.(28) These costs are well under the cost effectiveness values of $10,000 to $20,000 per ton often 

used as upper limits in PM2.5, ozone, and regional haze (visibility) regulatory programs. The simultaneous 

HAPs and methane removal that would occur with NSCR use provide further justification for extending 

the D-FW engine rule to counties outside the metropolitan area. 

ii. Electric Motors Instead of Combustion Engines for Compressor Power 

When considering NOx, VOC, HAPs, and greenhouse gas emissions from compressor engines, it is 

important to understand that the work to move the gas in the pipelines is performed by the compressors, 

which by themselves produce no direct combustion emissions. The emissions come from the exhaust of 

the internal combustion engines, which are fueled with a small amount of the available natural gas. These 

engines provide the mechanical power to run the compressors. The 2007 TCEQ engine survey and the 

most recent point source emissions inventory indicate that installed compressor engine capacity 

throughout the Barnett Shale was approximately 1,400,000 hp in 2007, and capacity is likely to increase 

to over 2,100,000 hp by 2009. 

As an alternative to operating the compressors in the Barnett Shale with millions of hp of natural gas 

burning-engines, the compressors could be operated with electrically-driven motors. The electrification of 

the wellhead and compressor station engine fleet in the Barnett Shale area has the potential to deliver 

significant reductions in emissions in North Central Texas. The use of electric motors instead of internal 

combustion engines to drive natural gas compressors is not new to the natural gas industry, and numerous 

compressors driven by electric motors are operational throughout Texas. Unfortunately, current 

regulations have not yet required their use in the Barnett Shale. 

 

A few of the many examples of electrically-driven natural gas compressors, positive technical 

assessments, and industrial experience with their use in Texas and throughout the U.S., include: 

x The Interstate Natural Gas Association of America: "One advantage of electric motors is they 

need no air emission permit since no hydrocarbons are burned as fuel. However, a highly reliable 

source of electric power must be available, and near the station, for such units to be considered 

for an application." (29)

x The Williams natural gas company: "The gas turbine and reciprocating engines typically use 

natural gas from the pipeline, where the electric motor uses power from an electric transmission 

line. Selection of this piece of equipment is based on air quality, available power, and the type of 

compressor selected. Typically electric motors are used when air quality is an issue." (30)

x JARSCO Engineering Corp.: "The gas transmission industry needs to upgrade equipment for 

more capacity. The new high-speed electric motor technology provides means for upgrading, at a 

fraction of the life cycle costs of conventional gas powered equipment."(31)

x Pipeline and Gas Journal, June 2007: "Important factors in favor of electric-driven compressor 

stations that should be considered in the feasibility analysis include the fact that the fuel gas for 
30

gas turbine compressor stations will be transformed into capacity increase for the electricallydriven compressor station, and will therefore add revenue to this alternative..." (32)

x Prime mover example: Installations in 2007 at Kinder Morgan stations in Colorado of +10,000 hp 

electric-driven compressor units. (33)

x Wellhead example: Installations in Texas of wellhead capacity (5 to 400 hp) electrically-driven 

compressors. (34,35)

x Mechanical Engineering Magazine, December 1996: "Gas pipeline companies historically have 

used gas-fired internal-combustion engines and gas turbines to drive their compressors. However, 

this equipment emits nitrogen oxides....According to the Electric Power Research Institute, it is 

more efficient to send natural gas to a combined-cycle power plant to generate electricity 

transmitted back to the pipeline compressor station than to burn the natural gas directly in gasfired compressor engines."(36)

x The Dresser-Rand Corporation: "New DATUM-C electric motor-driven compressor provides 

quiet, emissions free solution for natural gas pipeline applications – An idea whose time had 

come." (37)

x Occidental Oil and Gas Corporation: "Converting Gas-Fired Wellhead IC Engines to Electric 

Motor Drives: Savings $23,400/yr/unit." (38)

The use of an electric motor instead of a gas-fired engine to drive gas compression eliminates combustion 

emissions from the wellhead or compressor station. Electric motors do require electricity from the grid, 

and in so far as electricity produced by power plants that emits pollutants, the use of electric motors is not 

completely emissions free. However, electric motor use does have important environmental benefits 

compared to using gas-fired engines. 

Modern gas-fired internal-combustion engines have mechanical efficiencies in the 30-35% range, values 

that have been relatively static for decades. It is doubtful that dramatic increases in efficiency (for 

example, to 80 or 90%) are possible anytime in the near future. This means that carbon dioxide emissions 

from natural gas-fired engines at wellheads and compressor stations are not likely to drop substantially 

because of efficiency improvements. In addition, the scrubbing technology that is used in some large 

industrial applications to separate CO2 from other gases also is unlikely to find rapid rollout to the 

thousands of comparatively-smaller exhaust stacks at natural gas wellheads and compressor stations. The 

two facts combined suggest that the greenhouse gas impacts from using internal combustion engines to 

drive compressors are likely to be a fixed function of compression demand, with little opportunity for 

large future improvements. 

In contrast, the generators of grid electric power are under increasing pressure to lower greenhouse gas 

emissions. Wind energy production is increasing in Texas and other areas. Solar and nuclear power 

projects are receiving renewed interest from investors and regulators. As the electricity in the grid is 

produced by sources with lower carbon dioxide emissions, so then the use of electric motors to drive 

natural gas pipelines becomes more and more climate friendly. 

Stated another way, carbon dioxide emissions from gas-fired engines are unlikely to undergo rapid 

decreases in coming years, whereas the electricity for operating electric motors is at a likely carbonmaximum right now. Electric-powered compression has a long-term potential for decreased climate 

impact, as non-fossil fuel alternatives for grid electricity generation expand in the future. 
31

Costs: Estimates were made of the costs were switching from IC engines to electric motors for 

compression. Costs at sites in the Barnett Shale are highly time and site specific, depending on the cost of 

electricity and the value of natural gas, the numbers of hours of operation per year, the number and sizes 

of compressors operated, and other factors. 

For this report, sample values were determined for capital, operating and maintenance, and operating 

costs of 500 hp of either IC engine capacity or electric motor capacity for a gas compressor to operate for 

8000 hours per year at a 0.55 load factor. Electric power costs were based on $8/month/kW demand 

charge, $0.08/kWh electricity cost, and 95% motor mechanical efficiency. Natural gas fuel costs were 

based on $7.26/MMBtu wellhead natural gas price and a BSFC of 0.0085 MMBtu/hp-hr. 

With these inputs, the wellhead value of the natural gas needed to operate a 500 hp compressor with an IC 

engine for 1 year is approximately $136,000. This is lower than the costs for electricity to run a 

comparable electric motor, which would be approximately $174,000. In addition to these energy costs, it 

is important to also consider operating and maintenance (O&M) and capital costs. With an IC engine 

O&M cost factor of $0.016/hp in 2009 dollars, O&M costs would be approximately $35,000. With an 

electric motor O&M cost factor of $0.0036/kWh in 2009 dollars, O&M costs would be approximately 

$6200, providing a savings of nearly $30,000 per year in O&M costs for electrical compression, nearly 

enough to compensate for the additional energy cost incurred from the additional price premium on 

electricity in Texas compared to natural gas. 

With an IC engine capital cost factor of $750/hp in 2009 dollars, the cost of a 500 hp compressor engine 

would be approximately $370,000. With an electric motor cost factor of $700/kW, the cost of 500 hp of 

electrically-powered compression would be approximately $260,000. 

The combined energy (electricity or natural gas), O&M, and capital costs for the two options are shown in 

Table 22, assuming a straight 5-year amortization of capital costs. The data show that there is little cost 

difference in this example, with a slight cost benefit of around $12,000/year for generating the 

compression power with an electric motor instead of an IC engine. While this estimate would vary from 

site to site within the Barnett Shale, there appears to be cost savings, driven mostly by reduced initial 

capital cost, in favor of electrical compression in the Barnett Shale. In addition to the potential cost 

savings of electrical compression over engine compression, the lack of an overwhelming economic driver 

one way or the other allows the environmental benefits of electric motors over combustion engines to be 

the deciding factor on how to provide compression power in the area. 

Table 22. Costs of IC Engine and Electric Motor Compression 

[example of 500 hp installed capacity].

IC Engine 

($/year)

Electric Motor 

($/year)

energy (NG or electricity) 174,000 136,000 

O&M 35,000 6,200 

capital 74,000 52,000 

Total 245,000 232,000 
32

5.2 Oil and Condensate Tanks

Oil and condensate tanks in the Barnett Shale are significant sources of multiple air pollutants, especially 

VOC, HAPs, and methane. Multiple options exist for reducing emissions from oil and condensate tanks, 

including options that can result in increased production and revenue for well operators.(14) This section 

will discuss two of these options: flares and vapor recovery units. 

i. Vapor Recovery Units 

Vapor recovery units (VRU) can be highly effective systems for capturing and separating vapors and 

gases produced by oil and condensate tanks. Gases and vapors from the tanks are directed to the inlet side 

of a compressor, which increases the pressure of the mixture to the point that many of the moderate and 

higher molecular weight compounds recondense back into liquid form. The methane and other light gases 

are directed to the inlet (suction) side of the well site production compressors to join the main flow of 

natural gas being produced at the well. In this way, VRU use increases the total production of gas at the 

well, leading to an increase in gas available for metering and revenue production. In addition, liquids 

produced by the VRU are directed back into the liquid phase in the condensate tank, increasing 

condensate production and the income potential from this revenue stream. Vapor recovery units are 

estimated to have control efficiencies of greater than 98%.(14)

The gases and vapors emitted by oil and condensate tanks are significant sources of air pollutants, and the 

escape of these compounds into the atmosphere also reduces income from hydrocarbon production. With 

a wellhead value of approximately $7/MMBtu, the 7 tpd of methane that is estimated to be emitted in 

2009 from condensate tanks in the Barnett Shale have a value of over $800,000 per year. Even more 

significantly, a price of condensate at $100/bbl makes the 30 tpd of VOC emissions in 2009 from the 

tanks in the Barnett Shale potentially worth over $10 million per year. 

While flaring emissions from tanks in the Barnett Shale would provide substantial environmental 

benefits, especially in terms of VOC and methane emissions, capturing these hydrocarbons and directing 

them into the natural gas and condensate distribution systems would provide both an environmental 

benefit and a very large potential revenue stream to oil and gas producers. 

ii. Enclosed Flares 

Enclosed flares are common pollution control and flammable gas destruction devices. Enclosed flares get 

their name because the flame used to ignite the gases is generated by burner tips installed within the stack 

well below the top. The flames from enclosed flares are usually not visible from the outside, except 

during upset conditions, making them less objectionable to the surrounding community compared to open 

(unenclosed) flares. 

Using a flare to control emissions from tanks involves connecting the vents of a tank or tank battery to the 

bottom of the flare stack. The vapors from oil and condensate tanks are sent to the flare, and air is also 

added to provide oxygen for combustion. The vapors and air are ignited by natural gas pilot flames, and 

much of the HAP, VOC, and methane content of the tank vapors can be destroyed. The destruction 

efficiency for flares can vary greatly depending on residence time, temperature profile, mixing, and other 

factors. Properly designed and operated flares have been reported to achieve 98% destruction efficiencies. 

Applying 98% destruction efficiency to the Barnett Shale oil and condensate tanks emissions estimates 

shown in Table 16 results in potential emission reductions of 30 tpd of VOC, 0.6 tpd of HAPs, and 7 tpd 

of methane. These reductions are substantial and would provide large benefits to the ozone and PM 

precursor, HAPs, and greenhouse gas emission inventory of the Barnett Shale area. The use of flares, 
33

however, also has several drawbacks. One of these is that tank vapor flares need a continuous supply of 

pilot light natural gas, and reports have estimated pilot light gas consumption at around 20 scfh/flare.(14) 

Table 23 presents a summary of the results of an economic analysis performed in 2006 by URS 

Corporation for using flares or vapor recovery units to control emissions from a tank battery in Texas.(14) 

Capital costs were estimated by URS with a 5-year straightline amortization of capital. Flow from the 

tank battery was 25Mscf/day and VOC emissions were approximately 211 tpy. Costs were in 2006 

dollars. 

Table 23. Economics of Flares and Vapor Recovery Units. 

Control Option

Total Installed 

Capital Cost ($)

Annual Installed 

Operating Cost 

($/yr)

Operating Cost 

($/yr)

Value Recovered 

($/yr)

VOC Destruction Cost 

Effectiveness ($/ton 

VOC)

Enclosed Flare 40,000 8000 900 NA 40

VRU 60,000 12000 11,400 91,300 ($320)*

*VRU produces positive revenue, resulting in zero cost for VOC control, after accounting for value of recovered products.

The URS analysis indicated that flares were able to cost effectively reduce VOC emissions at $40/ton, 

while VRU units produced no real costs and quickly generated additional revenue from the products 

recovered by VRU operation. There was a less-than 1 year payback on the use of a VRU system, followed 

by years of the pollution control device becoming steady revenue source. 

5.3 Well Completions

Procedures have been developed to reduce emissions of natural gas during well completions. These 

procedures are known by a variety of terms, including "the green flowback process" and "green 

completions." (39,40) To reduce emissions, the gases and liquids brought to the surface during the 

completion process are collected, filtered, and then placed into production pipelines and tanks, instead of 

being dumped, vented, or flared. The gas cleanup during a "green" completion is done with special 

temporary equipment at the well site, and after a period of time (days) the gas and liquids being produced 

at the well are directed to the permanent separators, tanks, and piping and meters that are installed at the 

well site. Green completion methods are not complex technology and can be very cost effective in the 

Barnett Shale. The infrastructure is well-established and gathering line placement for the initial collection 

of gas is not a substantial risk since wells are successfully drilled with a very low failure rate. 

Emissions during well completions depend on numerous site-specific factors, including the pressure of 

the fluids brought to the surface, the effectiveness of on-site gas capturing equipment, the control 

efficiency of any flaring that is done, the chemical composition of the gas and hydrocarbon liquids at the 

drill site, and the duration of drilling and completion work before the start of regular production. 

Some recent reports of the effectiveness of green completions in the U.S. are available, including one by 

the U.S. EPA which estimated 70% capture of formerly released gases with green completions, and 

another report by Williams Corporation which found that 61% to 98% of gases formerly released during 

well completions were captured with green completions.(40-41) Barnett Shale producer Devon Energy is 

using green completions on its wells, and they reported $20 million in profits from natural gas and 

condensate recovered by green completed wells in a 3 year period.(42)

If green completion procedures can capture 61% to 98% of the gases formerly released during well 

completions, the process would be a more environmentally friendly alternative to flaring of the gases, 

since flaring destroys a valuable commodity and prevents its beneficial use. Green completions would 

also certainly be more beneficial than venting of the gases, since this can release very large quantities of 
34

methane and VOCs to the atmosphere. Another factor in favor of capturing instead of flaring is that 

flaring can produce carbon dioxide (a greenhouse gas), carbon monoxide, polycyclic aromatic 

hydrocarbons, and particulate matter (soot) emissions. 

5.4 Fugitive Emissions from Production Wells, Gas Processing, and Transmission

Fugitive emissions from the production wells, gas processing plants, gas compressors, and transmission 

lines in the Barnett Shale can be minimized with aggressive efforts at leak detection and repair. Unlike 

controlling emissions from comparatively smaller numbers of engines or tanks (numbering in the 

hundreds or low thousands per county), fugitive emissions can originate from tens of thousands of valves, 

flanges, pump seals, and numerous other leak points. While no single valve or flange is likely to emit as 

much pollution as a condensate tank or engine exhaust stack, the cumulative mass of all these fugitives 

can be substantial. There are readily-available measures that can reduce fugitive emissions. 

i. Enhanced Leak Detection and Repair Program 

The federal government has established New Source Performance Standards for natural gas processing 

plants a.k.a. NSPS Subpart KKK.(43) These standards require regularly scheduled leak detection, and if 

needed, repair activities for items such as pumps, compressors, pressure-relief valves, open-ended lines, 

vapor recovery systems, and flares. The NSPS applies to plants constructed or modified after January 20, 

1984. The procedures and standards in the processing plant NSPS are generally based on the standards 

developed for the synthetic organic manufacturing chemicals industry.(44)

Fugitive emissions from oil and gas wells, separators, tanks, and metering stations are not covered by the 

processing plant NSPS. Nonetheless, the leak detection and repair protocols established in the NSPS 

could certainly be used to identify fugitive emissions from these other items. Leak detection at processing 

plants covered by the NSPS is performed using handheld organic vapor meters (OVMs), and inspections 

are required to be done on a specified schedule. These same procedures could be used at every point 

along the oil and gas system in the Barnett Shale to identify and reduce emissions of VOCs and methane. 

Doing so would reduce emissions, and by doing so, increase production and revenue to producers. 

It is difficult to estimate the exact degree of emission reductions that are possible with fugitive emission 

reduction programs. The large and varied nature of fugitive emission points (valves, fittings, etc.) at 

production wells, processing plants, and transmission lines means that each oil and gas related facility in 

the Barnett Shale will have different options for reducing fugitive emissions. In general, leak detection 

and repair programs can help identify faulty units and greatly reduce their emissions. 

 

ii. Eliminating Natural Gas-Actuated Pneumatic Devices 

The State of Colorado is currently adopting and implementing VOC control strategies to reduce ambient 

levels of ozone in the Denver metropolitan area and to protect the numerous national parks and wilderness 

areas in the state. As part of this effort, the state investigated the air quality impacts of oil and gas 

development, including the impacts of the pneumatically-controlled valves and other devices that are 

found throughout gas production, processing, and transmission systems. The State of Colorado confirmed 

the basic conclusions arrived at earlier by EPA and GRI in 1995, that these pneumatic devices can be 

substantial sources of CH4, VOC, and HAP emissions.(45,46) Much of the following information on these 

devices and the strategies to control emissions is based on a review of the recent work in Colorado. 

Valves and similar devices are used throughout the oil and gas production, processing, and transmission 

systems to regulate temperature, pressure, flow, and other process parameters. These devices can be 

operated mechanically, pneumatically, or electrically. Many of the devices used in the natural gas sector 
35

are pneumatically operated. Instrument air (i.e. compressed regular air) is used to power pneumatic 

devices at many gas processing facilities, but most of the pneumatic devices at production wells and along 

transmission systems are powered by natural gas.(46) Other uses of pneumatic devices are for shutoff 

valves, for small pumps, and with compressor engine starters. 

As part of normal operation, most pneumatic devices release or “bleed”gas to the atmosphere. The release 

can be either continuously or intermittently, depending on the kind of device. In 2003 U.S. EPA estimated 

that emissions from the pneumatic devices found throughout the production, processing, and transmission 

systems were collectively one of the largest sources of methane emissions in the natural gas industry. 

Some U.S. natural gas producers have reduced natural gas emissions significantly by replacing or 

retrofitting "high-bleed" pneumatic devices. High-bleed pneumatic devices emit at least 6 standard cubic 

feet gas per hour.(46) Actual field experience is demonstrating that up to 80 percent of all high-bleed 

devices in natural gas systems can be replaced or retrofitted with low-bleed equipment. 

The replacement of high-bleed pneumatic devices with low-bleed or no-bleed devices can reduce natural 

gas emissions to atmosphere by approximately 88 or 98 percent, respectively.(21, 47) Anadarko Petroleum 

Corporation estimated that VOC emissions from their pneumatic devices will be reduced by 464 tpy once 

548 of their pneumatic controllers are retrofitted in Colorado.(46)

It may not be possible, however, to replace all high-bleed devices with low or no bleed alternatives. In the 

state of Colorado, it was estimates that perhaps up to 20 percent of high-bleed devices could not be 

retrofitted or replaced with low-bleed devices. Some of these included very large devices requiring fast 

and/or precise responses to process changes which could not yet be achieved with low-bleed devices. 

But even for these devices that appear to require high-bleed operation, alternatives are available. Natural 

gas emissions from both high bleed and low bleed devices can be reduced by routing pneumatic discharge 

ports into a fuel gas supply line or into a closed loop controlled system. Another alternative is replacing 

the natural gas as the pneumatic pressure fluid with pressurized air. Instrument pressurized air systems are 

sometimes installed at facilities that have a high concentration of pneumatic devices, full-time operator 

presence, and are on a power grid. In an instrument pressurized air system, atmospheric air is compressed, 

stored in a volume tank, filtered, and dried. The advantage of a pressurized air system for operating 

pneumatic devices is that operation is the same whether they air or natural gas is used. Existing pneumatic 

gas supply piping, control instruments, and valve actuators can be reused when converting from natural 

gas to compressed air. 

The U.S. EPA runs a voluntary program, EPA Natural Gas STAR, for companies adopting strategies to 

reduce their methane emissions. Experience from companies participating in the program indicates that 

strategies to reduce emissions from pneumatic devices are highly cost effective, and many even pay for 

themselves in a matter of months.(46) EPA reports that one company replaced 70 high-bleed pneumatic 

devices with low-bleed devices and retrofitted 330 high-bleed devices, which resulted in an emission 

reduction of 1,405 thousand cubic meters per year. At $105/m3

, this resulted in a savings of $148,800 per 

year. The cost, including materials and labor for the retrofit and replacement, was $118,500, and 

therefore, the payback period was less than one year. Early replacement (replacing prior to projected endof-service-life) of a high-bleed valve with a low-bleed valve is estimated to cost $1,350. Based on $3/m3

gas, the payback was estimated to take 21 months. For new installations or end of service life 

replacement, the incremental cost difference of high-bleed devices versus low-bleed devices was $150 to 

$250. Based on $3 per Mcf gas, the payback was estimated to take 5 to 12 months.(46) 

Overall, cost-effective strategies are available for reducing emissions and enhance gas collection from 

pneumatic devices in Barnett Shale area operations. These strategies include: 
36

• Installing low- or no-bleed pneumatic devices at all new facilities and along all new 

transmission lines; 

• Retrofitting or replacing existing high-bleed pneumatic devices with low- or no-bleed 

pneumatic devices; 

• Ensuring that all natural gas actuated devices discharge into sales lines or closed 

loops, instead of venting to the atmosphere; 

• Using pressurized instrument air as the pneumatic fluid instead of natural gas. 
37

6.0 CONCLUSIONS

Oil and gas production in the Barnett Shale region of Texas has increased rapidly over the last 10 years. 

The great financial benefits and natural resource production that comes from the Barnett Shale brings 

with it a responsibility to minimize local, regional, and global air quality impacts. This report examined 

emissions of smog forming compounds, air toxic compounds, and greenhouse gases from oil and gas 

activity in the Barnett Shale area, and identified methods for reducing emissions. 

Emissions of ozone and fine particle smog forming compounds (NOx and VOC) will be approximately 

191 tons per day on an annual average basis in 2009. During the summer, VOC emissions will increase, 

raising the NOx + VOC total to 307 tpd, greater than the combined emissions from the major airports and 

on-road motor vehicles in the D-FW metropolitan area. 

Emissions in 2009 of air toxic compounds from Barnett Shale activities will be approximately 6 tpd on an 

annual average, with peak summer emissions of 17 tpd. 

Emissions of greenhouse gases like carbon dioxide and methane will be approximately 33,000 CO2

equivalent tons per day. This is roughly comparable to the greenhouse gas emissions expected from two 

750 MW coal-fired power plants. 

Cost effective emission control methods are available with the potential to significantly reduce emissions 

from many of the sources in the Barnett Shale area, including 

x the use of "green completions" to capture methane and VOC compounds during well 

completions, 

x phasing in of electric motors as an alternative to internal-combustion engines to drive gas 

compressors, 

x the control of VOC emissions from condensate tanks with vapor recovery units, and 

x replacement of high-bleed pneumatic valves and fittings on the pipeline networks with no-bleed 

alternatives. 

Large reductions in greenhouse gas emissions could be achieved through the use of green completion 

methods on all well completions, with the potential to eliminate almost 200 tpd of methane emissions 

while increasing revenue for producers by recovering saleable gas. In addition, the replacement of internal 

combustion engines with electric motors for compression power could reduce smog-forming emissions in 

the D-FW metropolitan area by 65 tpd. Significant emission reductions could also be achieved with the 

use of vapor recovery units on oil and condensate tanks, which could eliminate large amounts of VOC 

emissions. Vapor recovery units on condensate tanks would pay for themselves in a matter of months by 

generating additional revenue to producers from the gas and condensate that would be captured instead of 

released to the atmosphere. Fugitive emissions of methane, VOC, and HAPs could be reduced with a 

program to replace natural gas actuated pneumatic valves with units actuated with compressed air. For 

those devices in locations where compressed air is impractical to implement, connection of the bleed 

vents of the devices to sales lines also could greatly reduce emissions. 

There are significant opportunities available to improve local and regional air quality and reduce 

greenhouse gas emissions by applying readily available methods to oil and gas production activities in the 

Barnett Shale. 
38

7.0 REFERENCES

1. Railroad Commission of Texas, "Barnett Shale Information – Updated July 30, 2008." 

on-line document: http://www.rrc.state.tx.us/barnettshale/index.html

2. Railroad Commission of Texas, "Newark, East (Barnett Shale) Field – Map – April 17, 2008." RRC 

Geographic Information Systems, Austin, Texas. 

on-line database: http://www.rrc.state.tx.us/divisions/og/maps/index.html

3. U.S. Environmental Protection Agency and the Gas Research Institute, "Methane Emissions from the 

Natural Gas Industry." EPA/600/SR-96/080, GRI-94/0257. June 1996. 

on-line document: http://www.epa.gov/gasstar/documents/emissions_report/1_executiveummary.pdf and 

http://www.p2pays.org/ref%5C07/06348.pdf

4. U.S. Environmental Protection Agency, "Greenhouse Gases and Global Warming Potential Values – 

Excerpt from the Inventory of U.S. Greenhouse Emissions and Sinks: 1990-2000." 

April 2002. 

on-line document: http://www.epa.gov/climatechange/emissions/downloads/ghg_gwp.pdf

5. Railroad Commission of Texas, "Oil and Gas Production Data Query." 

on-line database: http://webapps.rrc.state.tx.us/PDQ/home.do

6. Personal communication: TCEQ to SMU, summary of results of 2007 Barnett Shale/D-FW compressor 

engine survey, August 1, 2008. 

7. Texas Commission on Environmental Quality, "Revisions to the State Implementation Plan (SIP) for 

the Control of Ozone Air Pollution – Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area 

Attainment Demonstration." Project No. 2006-013-SIP-NR. May 23, 2007. on-line document: 

http://www.tceq.state.tx.us/assets/public/implementation/air/sip/D-FW/DFW_ad_sip_2007/2006013SIPNR_ado_Intro_052407.pdf

8. Personal communication: TCEQ to SMU, compressor engine emission factors, August 6, 2008. 

9. U.S. Environmental Protection Agency, "Natural Gas-fired Reciprocating Engines." AP-42, Fifth 

Edition, Volume I. July 2000. 

on-line document: http://www.epa.gov/ttn/chief/ap42/ch03/index.html

10. American Petroleum Institute, "Compendium of Greenhouse Gas Emissions Methodologies for the 

Oil and Gas Industry." February 2004. 

on-line document: http://www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdf

11. ENVIRON International Corporation, "A Pilot Project to Assess the Effectiveness of an Emission 

Control System for Gas Compressor Engines in Northeast Texas – Final Report." November 4, 2005. 

on-line document: 

http://www.epa.gov/oar/ozonepollution/SIPToolkit/documents/NETAC_Compressor_Retrofit_Final_Rep

ort_110405.pdf

12. Texas Commission on Environmental Quality, "Point Source Emissions Inventory – 2006 Report." 

on-line document: http://www.tceq.state.tx.us/implementation/air/industei/psei/psei.html
39

13. Eastern Research Group, "Natural Gas Compressor Engine Survey for Gas Production and Processing 

Facilities – H68 Final Report." a report prepared for the Houston Advanced Research Center. October 5, 

2006. 

on-line document: http://files.harc.edu/Projects/AirQuality/Projects/H068/H068FinalReport.pdf

14. Hendler A., Nunn J., Lundeen J., McKaskle R. "VOC Emissions from Oil and Condensate Storage 

Tanks – Final Report," a report prepared for the Houston Advanced Research Center. October 31, 2006. 

on-line document: http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf

15. Personal communication with Barnett Shale gas producer – condensate tank emissions modeling 

results, 2008. 

16. George D.L. "Preparation of Natural Gas Blends Used as Calibration Standards: Sources of 

Uncertainty and Best Preparation Practices – Final Report." Southwest Research Institute, San Antonio, 

Texas. April 2003. 

on-line document: 

http://www.mms.gov/tarprojects/278/calGasAccuracy_final.pdf

17. ENVIRON International Corporation, "Ozone Precursor Emission Inventory for San Juan and Rio 

Arriba Counties, New Mexico – Final Report." a report prepared for New Mexico Environment 

Department. August 31, 2006. 

on-line document: 

http://www.nmenv.state.nm.us/aqb/projects/San_Juan_Ozone/NM_Area_Emissions_report.pdf

18. The Williams Companies, "Reducing Methane Emissions During Completion Operations." Williams 

Production RMT – Piceance Basin Operations. 2007 Natural Gas Star - Production Technology Transfer 

Workshop. September 11, 2007. 

on-line document: http://www.epa.gov/gasstar/documents/workshops/glenwood-2007/04_recs.pdf

 

19. U.S. Environmental Protection Agency, "Green Completions." PRO Fact Sheet No. 703. EPA Natural 

Gas Star, Partner Reported Opportunities for Reducing Methane Emissions. September 2004. 

on-line document: 

http://www.epa.gov/gasstar/documents/greencompletions.pdf

20. ENVIRON International Corporation, ""An Emission Inventory of Nonpoint Oil and Gas Emissions 

Sources in the Western Region," 15th Annual Emissions Inventory Conference, New Orleans, LA. May 

2006. 

on-line document: http://www.epa.gov/ttn/chief/conference/ei15/session12/russell.pdf

21. Fernandez R. et al, "Cost-Effective Methane Emissions Reductions for Small and Midsize Natural 

Gas Producers." Journal of Petroleum Technology, June 2005. 

on-line document: http://www.icfi.com/Markets/Environment/doc_files/methane-emissions.pdf 

22. Texas Commission on Environmental Quality, "Dallas-Fort Worth Eight Hour Ozone State 

Implementation Plan, Supplemental Information." letter from Susana M. Hildebrand to Thomas Diggs, 

April 23, 2008. 

on-line document: 

http://www.tceq.state.tx.us/assets/public/implementation/air/sip/D-FW/TCEQ_Response.pdf

23. Love Field Airport, "2005 Emission Inventory." November 3, 2006. 
40

24. Dallas/Fort Worth International Airport, "D-FW Emissions Forecast." March 21, 2008. 

25. ENVIRON International Corporation, "Ozone Impacts in D-FW from Revised Emission Controls in 

the 2009 Future Year – Final Report." August 31, 2007. 

on-line report: 

http://www.tceq.state.tx.us/assets/public/implementation/air/am/docs/D-FW/p1/DFW_Control_Modeling_Final_Report-20070831.pdf

26a. Colorado Department of Public Health and Environment, Air Pollution Control District, "Control of 

Compressor Engine Emissions, Related Costs and Considerations." October 31, 2003. 

on-line report: 

http://apcd.state.co.us/documents/eac/reportoct31.doc

26b. Illinois Environmental Protection Agency, "Technical Support Document for Controlling NOx 

Emissions from Stationary Reciprocating Internal Combustion Engines and Turbines." Report AQPSTR 

07-01. March 19, 2007. 

on-line report: 

http://www.epa.state.il.us/air/rules/rice/tsd-rice.pdf

27. U.S. Environmental Protection Agency, "Draft Estimates of Cost Effectiveness of Non-Selective 

Catalytic Reduction for Rich-burn IC Engines (from March 21, 2006)." information from Jaime Pagan of 

OAQPS. 

28. ENVIRON International Corporation, "Demonstration of NOx Emission Controls for Gas Compressor 

Engines – A Study for Northeast Texas." December 6, 2005. 

on-line document: 

http://www.epa.gov/air/ozonepollution/SIPToolkit/documents/12-20-05_richburn_engine_control_briefing.pdf

29. Interstate Natural Gas Association of America, "Interstate Gas Pipeline Systems - Prime 

Movers." 

on-line document: 

http://engr.smu.edu/~aja/2007-ozone-report/INGAA.pdf

30. Williams Companies, "Compressor Facility - Project Overview and Facility Design." 

on-line document: 

http://engr.smu.edu/~aja/2007-ozone-report/Williams-Gas.pdf

31. Oliver J.A., Samotyj M.J. "Electrification of Natural Gas Pipelines – A Great Opportunity for Two 

Capital Intensive Industries." IEEE Transactions on Energy Conversion, vol. 14, pp. 1502-1506, 

December 1999. 

on-line document: 

http://ieeexplore.ieee.org/search/wrapper.jsp?arnumber=815097

32. Mokhatab S. "Compressor Station Design Criteria." Pipeline and Gas Journal, June 2007. 

on-line document: 

http://findarticles.com/p/articles/mi_m3251/is_/ai_n25008106?tag=artBody;col1

33. Ranger Plant Construction Company, Inc., Abilene, Texas. 

on-line document: 

http://www.rpcabilene.com/history-1.html
41

34. Wellhead Compressors, Inc., Midland, Texas. 

on-line document: 

http://wellheadcompressors.com/products/index.html

35. EnerSource Compression Systems, Inc., Odessa, Texas. 

on-line document: 

http://www.gascompressor.com/gasgather.htm

36. Valenti M. "Gas Pipelines Go Electric." Mechanical Engineering, December 1996. 

on-line document: 

http://www.memagazine.org/backissues/december96/features/gaspipe/gaspipe.html

37. Dresser-Rand Corporation, "New Datum-C Electric Motor-Driven Compressor Provides Quiet, 

Emission-Free Solution for Natural Gas Pipeline Applications." Dresser-Rand Insights, vol. 8, no. 1, 

2005. 

on-line document: 

http://www.dresser-rand.com/insight/v8n01/art_2.asp

38. Occidental Oil and Gas Corporation, "Technical Barriers to Emissions Reductions: Gas STAR Case 

Studies." September 26, 2006. 

on-line document: 

http://www.ipieca.org/activities/climate_change/downloads/workshops/26sept_06/Session_3/Ravishanker

.pdf

39. Integrated Production Services, "Green Flowback Process." presentation at Texas A&M University – 

Corpus Christi, Improved Profits Through Best Managed Practices. 

on-line document: 

http://www.epa.gov/gasstar/documents/workshops/houston-2005/green_flowback.pdf

40. U.S. Environmental Protection Agency, "Green Completions - Methane Emissions Reductions." PRO 

Fact Sheet No. 703. EPA Natural Gas Star, Partner Reported Opportunities for Reducing Methane 

Emissions. September 2004. 

on-line document: 

http://www.epa.gov/gasstar/documents/greencompletions.pdf

41. The Williams Companies, "Reducing Methane Emissions During Completion Operations – 

Economics Volume Recovered." Williams Production RMT – Piceance Basin Operations. 2007 Natural 

Gas Star - Production Technology Transfer Workshop. September 11, 2007. 

on-line document: 

http://www.epa.gov/gasstar/documents/workshops/glenwood-2007/04_recs.pdf

42. Devon Energy, "EPA Natural Gas Star Program – Economics of FWB RECs." 

on-line document: 

http://www.spe.org/spe-site/spe/spe/meetings/EPESC/2007/GreenhouseGas_BrianWoodward.pdf

43. U.S. Environmental Protection Agency, "Standards of Performance for Equipment Leaks of VOC 

from Onshore Natural Gas Processing Plants." 40 CFR Part 60, Subpart KKK. 
42

44. U.S. Environmental Protection Agency, "Standards of Performance for Equipment Leaks of VOC in 

the Synthetic Organic Chemicals Manufacturing Industry for Which Construction, Reconstruction, or 

Modification Commenced After January 5, 1981, and on or Before November 7, 2006." 40 CFR Part 60, 

Subpart VV. 

45. ENVIRON International Corporation, "Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the Denver-Julesburg Basin." a report prepared for the Colorado Department of Public Health 

and Environment. April 30, 2008. 

46. Colorado Air Pollution Control Division, "High Bleed Pneumatic Devices." presented at the April 10, 

2008 RAQC Meeting. 

on-line document: 

http://www.cdphe.state.co.us/ap/ozone/RegDevelop/IssuePapers/April4-

08/APCDOZISSUEPAPERpneumaticdevicesRev1.pdf

47. ENVIRON International Corporation, "WRAP Area Source Emissions Inventory Projections and 

Control Strategy Evaluation Phase II - Final Report," September 2007. 

on-line document: 

http://www.wrapair.org/forums/ssjf/documents/eictts/OilGas/2007-10_Phase_II_O&G_Final)Report(v10-

07%20rev.s).pdf
43

Author's Notes: 

A draft version of this report was prepared in September 2008 and distributed for review and comment to 

oil and gas producers, state and federal regulators, authors of some of the references used in this report, 

and others. The author appreciates the comments received by those reviewers and the time they took to 

provide feedback. For the purpose of full disclosure, the author notes that he was an employee with 

Radian International LLC working on projects for several gas industry clients, including the Gas 

Research Institute and gas pipeline companies, during the time that "Methane Emissions from the Natural 

Gas Industry" (Reference 15) was published. The authors of Reference 15 were also employees of Radian 

International LLC, working as contractors for the Gas Research Institute and the Environmental 

Protection Agency. The author of this study notes that he did not work on or participate in the GRI/EPA 

project performed by the other Radian International personnel. 

Images on the cover page from the Texas Railroad Commission and the U.S. Department of Energy. 

Some typos and spreadsheet errors fixed on 2/8/2009. 

Finally, the statements and recommendations in this study are those of the author, and do not represent 

the official positions of Southern Methodist University. 
44