## Emissions from Natural Gas Produc tion in the Barnett Shale Area and Opportunities for Co st-Effective Improvements

report by: Al Armendariz, Ph.D. Department of Environmen tal 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, 20091 

### 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 in stalled and another 4700 wells were pending. Gas production in 2007 was approximately 923 Bcf from we lls 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 em issions 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 Ba rnett Shale area were divided into point sources, which included compressor engine exhausts and o il/condensate tanks, as well as fugitive and intermittent sources, which included production equipment fug itives, well drilling and fracing engines, well completions, gas processing, and transmission fugitives. The air pollutants consider ed in this inventory were smog-forming compounds (NO

x 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-ro ad 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 great er emissions than motor vehicles in these counties.

The emission rate of air toxic compounds (like be nzene and formaldehyde) fro m Barnett Shale activities was predicted to be approximately 6 tpd on an annu al average, and 17 tpd during peak summer days. The largest contributors to air toxic emissions were th e condensate tanks, followed by the engine exhausts.

In addition, predicted 2009 emissions of gree nhouse gases like carbon dioxide and methane were approximately 33,000 tons per day of CO 2 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 CO 2 emissions from compressor engi ne exhausts and fugitive CH 4 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 g as 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 condensat e 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 Te xas counties. The hydrocarbo n 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 2007Natural Gas Production (billion cf)

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

In addition to the recent development of the Barn ett 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 th e area. Emission sources for all oil and gas activities are considered together in this report.

The issuance of new Barnett Shale area drilling permit s has been following the upward trend of increasing natural gas production. The RRC issued 1112 well perm its 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 o il 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 perm its are located in six counties near the city of Fort Worth: Tarrant, Denton, Wise, Parker, H ood, 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, Dent on, 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 Shal e 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 g as 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 Metropo litan Area and Counties Pr oducing 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 a nd Well Permit Locations in the Barnett Shale Area (red = gas wells, green = oil wells, blue = permits. RRC distri ct 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 requi re 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 Wo rth area show the area to be in compliance with the 1997 fine particulate matter (PM 2.5 ) air quality standard, which is 15 micrograms per cubic meter (μg/m 3 ) on an annual average basis. In 2006, the Clean Air Scientific A dvisory Committee for EPA recommended tightening the standard to as low as 13 μg/m 3 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/m 3 level several times during the 2000-2007 time period, and tightening of the fine particle standard by future EPA administrators w ill focus regulatory attention at sources that emit fine particles or fine particle-forming compounds like NO

x and VOC gases.

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

There are a variety of activities that potentially creat e 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 ta nk 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 pr ocess 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 th e 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 pr ocessed natural gas, and the combustion of the natural gas in these engines results in air emissions. Most of the engines driving compresso rs 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 we lls 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 ot her gases from any entrained water and hydrocarbon liquids. The gases are collected off the top of the sep arator, while the water and hydrocarbon liquids fall

to the bottom and are then stored on-site in stor age tanks. The hydrocarbon liquid is known as condensate.6 Figure 3. Major Units in The Natural Ga s Industry From Wells to Customers. (3)

The condensate tanks at Barnett Shale wells are ty pically 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 an d 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 ta nks, 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 indi vidual components, including pumps, flanges, valves, gauges, pipe connectors, compressors, and other pi eces. 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 corr osion, 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 accumulate d 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 pow er is typically provided by transportable diesel engines, and operation of these engines generates ex haust from the burning of diesel fuel. After the wellbore is formed, additional power is needed to ope rate the pumps that move large quantities of water,7 sand/glass, or chemicals into the wellbore at high pr essure to hydraulically fr acture 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 prac tice 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 la rgely free of the water and sand, and then the well will be connected to the permanent gas collecting ha rdware at the well site. During well completions, the venting/flaring of the gas coming to the surface re sults 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 la rge number of gases and vapors. Wellhead natural gas is often delivered to processing plants where higher molecular weight hydrocar bons, water, nitrogen, and other compounds are largely removed if they are pr esent. 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 hydrocar bons, 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 usuall y 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 pro cessing 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 unde rground 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 st ations, storage formations, and/or the interstate pipeline network for eventual delivery to customer s. 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 fr om 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 polluta nts to the atmosphere wh ich contribute to ozone and fine particulate matter smog, are known toxic ch emicals, or contribute to climate change. The objectives of this study were to examine Barnett Sh ale 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 re gulatory controls and engineering techniques used to control emissions from the oil and gas sector in the Barn ett Shale; (3) identify new approaches that can be

taken to reduce emissions from Barnett Shale activiti es; and (4) estimate the emissions reductions and cost effectiveness of implementati on 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 (NO

x ), volatile organic compounds (VOCs), air toxics a.k.a. hazardous air pollutants (HAPs), methane (CH 4 ), nitrous oxide (N 2 O), and carbon dioxide (CO 2 ). 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 atmos phere 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 CO 2 , CH 4 , and N 2 O were determined individually, and then combined as carbon dioxide equivalent tons (CO 2 e). In the combination, CH 4 tons were scaled by 21 and N 2 O tons by 310 to account for the higher greenhouse gas potentials of these gases. (4)

Emissions in 2009 were estimated by examining r ecent trends in Barnett Shale hydrocarbon production, and where appropriate, extrapol ating 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 we re determined separately for the two groups.

3.2 Hydrocarbon Production

Production rates in 2007 for oil, gas, casinghead g as, 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 th e 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 2 nd -order polynomial to the production rates via the leastsquares method and extrapolating out to 2009.

3.3 Compressor Engine Exhausts - Em ission Factors and Emission Estimates

Emissions from the natural-gas fired compressor engi nes in the Barnett Shale were calculated for two types of engines: the generally large engines that ha d previously reported emissions into the TCEQ's Point Source Emissions Inventory (PSEI) pr ior 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 estim ate emissions from the engi nes 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 primar ily 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 Inventor y (PSEI) reports. However, prior to 2007, many other stationary engines in the Barnett Shale area had not reported emi ssions to the PSEI and their contribution to regional air quality was unknown. In late 2007, the TCEQ conduc ted 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, NO

x emissions, and other data to TCEQ. Data summarized by TCEQ from the survey was used for this repor t to estimate emissions from natural gas engines in the Barnett Shale area that had previously not repor ted 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, be tween 50 - 500 hp, and larger than 500 hp.

Regulations adopted by TCEQ and scheduled to take effect in early 2009 will limit NO

x 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 befo re June 2007 will be restri cted to 0.7 g/hp-hr, and lean burn engines installed or moved after June 200 7 will be limited to 0.5 g/hp-hr. For this report, emissions in 2009 from the engines in the metropolita n 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 NO

x emission factors provided by operators to TCEQ in the 2007 survey. (6) Emissions of VOCs were determined usi ng TCEQ-determined emission factors, and emissions of HAPs, CH 4 , and CO 2 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 t hose factors which were judged by EPA to be of high quality, "A" or "B" ratings, were used to estimat e emissions. Emission factors for the greenhouse gas N 2 O were from an emissions inventory report issu ed by the American Petroleum Institute. (10)

Beginning in 2009, many engines subject to the new NO

x limits are expected to reduce their emissions with the installation of non-selective catalytic reduc tion units (NSCR), a.k.a. three-way catalysts. NSCR units are essentially modified versions of the "catalyt ic 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 CH 4 emissions. Emissions from engines expected to in stall NSCR units were determined using a 75% emissions reduction factor for VOC, HAPs, and CH 4 . Conversely, NSCR units are known to increase N 2 O emissions, and N 2 O 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 Area10 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 NO

x (g/hp-hr) a VOC (g/hp-hr) b HAPs (g/hp-hr) c CH 4 (g/hp-hr) d CO 2 (ghp-hr) e N 2 O (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 NO

x (g/hp-hr) i VOC (g/hp-hr) j HAPs (g/hp-hr) k CH 4 (g/hp-hr) l CO 2 (ghp-hr) m N 2 O (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

lean g <500 0.62 1.6 0.27 4.8 424 0.012

lean h <500 0.5 1.6 0.27 4.8 424 0.012

lean g >500 0.7 1.45 0.27 4.8 424 0.012

lean h >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, acrol ein, xylene, benzene, formaldehyde, methanol, toluene, xylene (reference 9). d: EPA, AP-42 (reference 9). e: EPA, AP-42 (reference 9). f: API Compendium Re port (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-benef it; lean EFs from email from TCEQ to SMU (reference 8). Large lean engine VOC emission f actor 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

N 2 O emissions increase over uncontrolled rate.11 Annual emissions from the engines identified in th e 2007 survey were estimated using the pollutantspecific emission factors from Table 1 together with Equation 1,

M

E,i = 1.10E-06 * E i * P cap * F hl

(1)

where M E,i was the mass emission rate of pollutant i in tons per year, E i was the emission factor for pollutant i in grams/hp-hr, P cap is installed engine capacity in hp, and F hl

is a factor to adjust for annual hours of operation and typical load conditions.

Installed engine capacity in 2007 was determined fo r 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 si zes 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

F

hl

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

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 cap acity, 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 engines q typical size q (hp) installed capacity r (hp)

rich <50 12 50 585 rich 50-500 724 140 101,000 rich >500 200 1400 280,000

lean o <500 14 185 2540

lean p <500 13 185 2400

lean o >500 103 1425 147,000

lean p >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 SM U 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 TC EQ 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, wh ich are principally large engines at compressor

stations. (12)12 Emissions of NO

x from large engines in the D-FW metropolita n 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 2 006 emissions upward to account for increases in gas production and compression needs from 2006-2009. For NO

x 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 NO

x emission, emissions of VOC were not taken di rectly from the PSEI. Estimates of future VOC emissions required accounting for the effects that the new TCEQ engine NO

x 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 horsepow er 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 pr oduction 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 CH 4 control. Table 4 summarizes the VOC, HAP, and gr eenhouse gas emission factors used for the PSEI engines in the D-FW metropolitan area. Table 5 summari zes 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 CH 4 EF (g/hp-hr) u CO 2 EF (g/hp-hr) v N 2 O (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 CH 4 EF (g/hp-hr) u CO 2 EF (g/hp-hr) v N 2 O (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 (ref erence 8). Large lean engi ne 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) engi nes (reference 9). u: EPA, AP-42 (reference 9) ; 75% reductions applied to 2007 rich (>500), 2009 rich (>500) and

2009 rich (<500) engi nes (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 N 2 O emissions increase over uncon trolled 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 th e 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 NO

x 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 pr oduction from 2006-2009. Unlike engines inside the metropolitan area, the engines outside the metropolitan ar ea 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 th e TCEQ passed the East Texas Combustion Rule that

limited NO

x emissions from rich-burn natural gas engin es larger than 240 hp in certain east Texas counties. Lean burn engines and engines smaller th an 240 hp were exempted. The initial proposed rule would have applied to some counties in the Barne tt Shale production area, including Cooke, Wise, Hood, Somervell, Bosque, and Hill, but in the final vers ion 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, wher eby the TCEQ compressor engine capacity production factor, 205 hp/(MMcf/day), was used along with actua l 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 estim ate 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 CH 4 (g/hp-hr) aa CO 2 (ghp-hr) bb N 2 O (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 f actor 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 N 2 O 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 Outsid e the D-FW Metropolitan Area

The Point Source Emissions Inventory (PSEI) only cont ains 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 TC EQ engine survey of engines inside the D-FW metropolitan area

demonstrated that the PSEI does not include a substan tial 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 metr opolitan counties in 2007 w as approximately 1,000 Bcf . A "non-PSEI" compressor engine capacity producti on factor of 226 hp/(MMcf/day) was determined for the Barnett Shale area. This cap acity factor accounts for all the small previously hidden engines that the 2007 survey showed come into use in oil an d 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 cont ain previously unreported engine capacity in the same proportion to the unreported engine capacity that was id entified during the 2007 engine survey inside the metro area. Without a detailed engine survey in th e rural counties of the same scope as the 2007 survey performed within the D-FW metropolitan counties, u se 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 NO

x (g/hp-hr) ff VOC(g/hphr) gg HAPs(g/hphr) hh CH 4(g/hphr) hh CO 2 (ghp-hr) ii N 2 O (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 th e 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 productio n. Lean burn <500 hp engine post-2007 emission factor adjusted from 6.2 to 5.15 to account for th e effects of NSPS JJJJ rules on NOx

emissions. gg: email from TCEQ to SMU, August 6, 2008; ri ch (>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 N 2 O emissions increase over

uncontrolled rate (reference 10).

Table 9. Installed Engine Capacity for Non-PSEI Engi nes Outside Metropolitan Ar ea 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 - Emis sion 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 re sults 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 Mont ague County. The results from the URS investigation were used in this study to calculate Barne tt Shale-specific emission factors for VOC, CH 4 , HAPs, and

CO 2 , instead of using a more general Texas-wide em ission 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 investiga tion were used to calculate "Peak Summer" emissions. The HAPs identified in the URS study included n-he xane, benzene, trimethylpentane, toluene, ethylbenzene, and xylene. The emission factors used to calculate peak summer emissions from Barnett16 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 (l eft), Separators (r ight), and Piping. (14)

Computer modeling data were pr ovided during personal communications with a Barnett Shale gas producer who estimated VOC, CH 4 , HAPs, and CO 2 emissions from a number of their condensate

tanks. (15) The tanks were modeled with ambient temper atures 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 emis sion factors for the Barnett Shale area. The annual average emission factors are shown in Table 10-2.17 Table 10. Condensate and Oil Tank Emis sion Factors for the Barnett Shale.

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

VOC (lbs/bbl) HAPs (lbs/bbl) CH 4 (lbs/bbl) CO 2 (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) CH 4 (lbs/bbl) CO 2 (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,

M

T,i = E i * P

c * C / 2000 (2)

where M T,i was the mass emission rate of pollutant i in tons per year, E i was the emission factor for pollutant i in lbs/bbl, P

c was the production rate of condensate or oil, and C was a factor to account for the reduction in emissions due to vapor-e missions 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 we ll 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 compone nts per well. A previous study published by the Gas Research Institute and U.S. EPA investigated fugitiv e 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 emi ssions 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 Barn ett Shale operations in 2007 we re 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. Mu ltiple 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 datawere weighted by the fraction of total area production that originated from each county to calculate areawide emission factors. Table 11 presents th e production fugitives emission factors.18 Table 11. Production Fugitives Emission Factors for the Barnett Shale.

VOC (lbs/MMcf) HAPs (lbs/MMcf) CH 4 (lbs/MMcf) CO 2 (lbs/MMcf)

11 0.26 99 1.9

Emissions were calculated with Equation 3,

M

F,i = E i * P g / 2000 (3)

where M F,i was the mass emission rate of pollutant i in tons per year, E i was the emission factor for pollutant i in lbs/MMcf, and P g was the production rate of natural and casinghead gas. The area-wide unprocessed natural gas composition based on data from gas producers was 74% CH 4 , 8.2% VOC, 1.4%

CO 2 , and 0.20% HAPs, on a mass % basis. HAPs in unpr ocessed natural gas can include low levels of nhexane, benzene, or other compounds.

3.4 Well Drilling, Hydraulic Fracturing Pump Engi nes, 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 em issions 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 electrici ty 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 drilli ng and fracing engines, previous st udies 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 Mc f 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 we re 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 natu ral 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 ar e currently employing “green completion” methods to capture natural gas and reduce emissions duri ng well completions suggests that typical well completions in the Barnett Shale area can release approxi mately 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 th e RRC was plotted for the Feb. 2004 – Feb. 2008 time period. (22) A least-squares regression line was fit to the da ta, and the slope of the line provides the19 approximate number of new completions every year . A value of 1042 completions/year was relatively steady throughout the 2004-2008 time period (linear R 2 = 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 metropolita n area, and the rate of new completions has been steady since 2004. Emissions of VOC, HAPs, CH 4 , and CO 2 were estimated using the same natural gas composition used for production fugitive emissions.

Some gas producers are using green completion techni ques to reduce emissions, while others destroy natural gas produced during well completions by flari ng. To account for the use of green completions and control by flaring, natural gas emission estimates dur ing 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 va ry from processing plant to processing plant, depending on the age of the plants, whether they ar e 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 pub lished by the Gas Research Institute and U.S. EPA investigated fugitive emissions from the natural g as industry, including emissions from production wells, processing plants, transmission pipelines, st orage 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 oper ations 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,

CH 4 , and CO 2 were estimated with an area-wide natural g as 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 Emissi on Factors for the Barnett Shale.

VOC (lbs/MMcf) HAPs (lbs/MMcf) CH 4 (lbs/MMcf) CO 2 (lbs/MMcf)

14 0.3 45 1.0

Processing fugitive emissions were calculated with Equation 4,

M

P,i = E i * P g / 2000 (4)

where M P,i was the mass emission rate of pollutant i in tons per year, E i was the emission factor for pollutant i in lbs/MMcf, and P g was the production rate of natural a nd casinghead gas. The composition of the natural gas produced in the Barnett Shale that is processed was estimated to be 65% CH 4 , 1.5% CO 2 , 20% VOC, and 0.48% HAPs, on a mass % basis. Not a ll 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 ch emical composition of the gas being transported, the tightness of compressor seals and rod packing, the fre quency of blow down events, and other factors. A previous study published by the Gas Research Ins titute 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 previous ly addressed in this report, were estimated to be approximately 35% of total fugitiv e emissions, or 0.49% of gross pr oduction. Transmission includes the movement of natural gas from the wells to processi ng plants, and the processing plants to compressor stations. It does not include flow past the primary metering and pressure regulat ing (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 distri bution system, and fugitive emissions from these lines are beyond the scope of this report.

Transmission fugitive emissions from Barnett Shale ope rations in 2007 were estimated as 0.49% of gross natural gas and casinghead gas production of 1 098 Bcf/yr. Emission factors for VOC, HAPs, CH 4 , and

CO 2 were developed considering that a significant po rtion of the gas moving through the network does not require processing, while the portion of the g as 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% CH 4 , 5.1% VOC, 1.4% CO 2 , and 0.12% HAPs, by mass %. Table 13 presents the transmission fugitives emission factors.

Table 13. Transmission Fugitives Emi ssion Factors for the Barnett Shale.

VOC (lbs/MMcf) HAPs (lbs/MMcf) CH 4 (lbs/MMcf) CO 2 (lbs/MMcf)

12 0.28 175 3.3

Transmission fugitive emissions we re calculated with Equation 5,

M

tr,i = E i * P g / 2000 (5)

where M tr,i was the mass emission rate of pollutant i in tons per year, E i was the emission factor for pollutant i in lbs/MMcf, and P g 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 Barne tt Shale area are summarized in Tables 14 and 15. Results indicate that engines are significant sources of ozone and particulate matter precursors (NO

x and VOC), with 2007 emissions of 66 tpd. Emissions of NO

x are expected to fall 50% from 32 to 16 tpd for engines in the Dallas-Fort Worth metropolitan area b ecause of regulations scheduled to take effect in 2009 and the installation of NSCR units on many engi nes. Large reductions are unlikely because of the growth in natural gas production. For engines outside the D-FW metropolitan area counties, NO

x 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 subj ect 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 emissi ons 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 ar e shown in Table 15. Emissions in 2007 as carbon dioxide equivalent tons were appr oximately 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 CO 2 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 th e 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 20 07, and summer emissions will increase to 146 tpd in

2009.

Substantial HAP emissions during th e summer were determined for the tanks, with 2007 emissions of 7.2 tpd and 2009 emissions of 11 tpd. Greenhouse gas em issions from the tanks are almost entirely from CH 4 , with a small contribution from CO 2 . 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 pr oduction sites are shown in Table 17. Production fugitives are significant sources of VOC emissions, w ith VOC emissions expected to grow from 2007 to 2009 from 17 to 26 tpd. Production fugitives are also ve ry large sources of methane emissions, leading to large CO 2 equivalent greenhouse gas emissions. Greenhou se 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 fractur ing pump engines, and well completions are shown in Table 18. These activities are significant sources of th e 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 CO 2 equivalent tons per year. Based on 2000-2007 drilling trends, appr oximately 71% of the well drilling, fr acing, 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, Hydr aulic 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, largel y 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 transm ission 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 emissi ons 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 Sh ale area are summarized in Table 21-1 on an annual average basis, and are summarized in Table 12-2 on a peak summer basis. Annua l average emissions for 2009 of ozone and particulate precursors (NO

x and VOC) were approximately 191 tpd, and peak summer emissions of these compounds were 307 tpd. The por tion of those emissions originating from the 5- counties in the D-FW metropolitan area with signi ficant 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 contri bution from all other sources was dominated by methane. Emissions of HAPs were significant from Barn ett 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 V OC HAPs CH4 CO2e NOx V OC 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 V OC HAPs CH4 CO2e NOx V OC 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 prod uction in the Barnett Shale were dominated by emissions from compressor engines, with a sm aller contribution from well drilling and fracing pump engines. All source categories in the Barnett Shale c ontributed to VOC emissions, but the largest group of VOC sources was condensate tank vents. Figur e 6 presents the combined emissions of NO

x and VOC during the summer from all source categories in the Barnett Shale.25 Figure 6. Summer Emissions of Ozone & Fi ne Particulate Matter Precursors (NO

x 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 signifi cant sources of air emissions in the north-central Texas area. To help put the levels of Barnett Shal e 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 ai rports. A recent emissions inventory has estimated 2009

NO

x emissions from all area airports to be approxima tely 14 tpd, with VOC emissions at approximately 2.6 tpd, resulting in total ozone and particulate ma tter precursor emissions of approximately 16 tpd. (22-24)
For comparison, emissions of VOC + NO

x 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 NO

x emissions from certain compressor engine types, Barnett Shale oil and gas em issions 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, NO

x + VOC emissions from mobile sources in the 9-county area were estimated by the TCEQ to be a pproximately 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 NO

x 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

En g ines = 65 Production Fugitives = 26 tpd summer total =
307 tpd26 Figure 7 summarizes summer Barnett Shale-related emissions, plus TCEQ emission estimates from the airports and on-road mobile sources. Figure 8 presen ts 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 D

Ͳ FW Metro

On

Ͳ Road

Mobile Sources D

Ͳ FW On

Ͳ Road

Mobile Sources

in Five Counties

with Oil/Gas Barnett Sources w/in D

Ͳ FW Five

Counties with Oil/Gas Barnett 21

Ͳ County Engines

and Tanks Barnett 21

Ͳ County All Oil/Gas Sources 16 273

121 165 212 3072009NOxandVOCEmissions(tpd)27 Figure 8. Barnett Shale Ac tivity, D-FW Area Airports, & Mobile So urces (Annual Averag e 2009 Emissions).

0 50 100 150 200 250 300 350

All Airports D

Ͳ FW Metro

On

Ͳ Road

Mobile Sources D

Ͳ FW On

Ͳ Road

Mobile Sources

in Five Counties

with Oil/Gas Barnett Sources w/in D

Ͳ FW Five

Counties with Oil/Gas Barnett 21

Ͳ County Engines

and Tanks Barnett 21

Ͳ County All Oil/Gas Sources 16 273

121 112
96 1912009NOxandVOCEmissions(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 cat egories, off-the-shelf options are available which could significantly reduce emissions, resulting in impo rtant air quality benefits. Some of these emissions reductions would also result in increased producti on 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 vo lumes 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 ef fective in early 2009 and they will reduce NO

x , VOC, and other emissions from a subset of the engines in the Ba rnett Shale – those that ar e 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 emi ssion 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 e ngines 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 Co unties Outside the D-FW Metropolitan Area

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

will limit NO

x 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 200 7 will be limited to 0.5 g/hp-hr. Applying these rules to engines outside the metropolitan area would reduce 2009 NO

x emissions from a large number of engines, in particular, rich burn engines between 50 to 500 hp. Emissions of NO

x 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 em issions 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 outsi de the metropolitan area would likely result in many engine operators installing NSCR systems on rich bu rn engine exhausts. These systems would not only

reduce emissions of NO

x , 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, and29 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 NO

x from 500 hp engines at approximately $330/ton. (26b) The U.S. EPA in

2006 estimated that NSCR could control NO

x from 500 hp engines at approximately $92 to 105/ton. (27) A 2005 report examining emissions reductions from compressor engines in northeast Texas estimated NO

x 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 PM 2.5 , ozone, and regional haze (visibility) regulatory programs. The simultaneous

HAPs and methane removal that would occur with NS CR use provide further justification for extending the D-FW engine rule to counties outside the metropolitan area.

ii. Electric Motors Instead of Com bustion Engines for Compressor Power

When considering NO

x , VOC, HAPs, and greenhouse gas emissions from compressor engines, it is important to understand that the work to move the ga s 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 i ndicate that installed compressor engine capacity throughout the Barnett Shale was approximately 1,40 0,000 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 th e Barnett Shale with millions of hp of natural gas burning-engines, the compressors coul d 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 Tex as. 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 opera tional throughout Texas. Unfortunately, current regulations have not yet required their use in the Barnett Shale.

A few of the many examples of electrically-dri ven natural gas compressors, positive technical assessments, and industrial expe rience with their use in Texas and throughout the U.S., include:

x The Interstate Natural Gas Association of Ameri ca: "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 n ear the station, for such units to be considered for an application." (29)

x The Williams natural gas company: "The gas tu rbine and reciprocating engines typically use natural gas from the pipeline, where the electri c 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 moto r 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 for30 gas turbine compressor stations will be transformed into capacity increase for the electricallydriven compressor station, and will theref ore add revenue to th is alternative..." (32)

x Prime mover example: Installations in 2007 at Ki nder Morgan stations in Colorado of +10,000 hp electric-driven compressor units. (33)

x Wellhead example: Installations in Texas of we llhead 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 g as turbines to drive thei r compressors. However, this equipment emits nitrogen oxides....According to the Electric Power Research Institute, it is more efficient to send natural gas to a combin ed-cycle power plant to generate electricity transmitted back to the pipeline compressor stati on 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 pi peline applications – An idea whose time had

come." (37)

x Occidental Oil and Gas Corporation: "Conver ting 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 th at emits pollutants, the use of electric motors is not completely emissions free. However, electric moto r 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 comp ressor stations are not likely to drop substantially because of efficiency improvements. In addition, th e scrubbing technology that is used in some large industrial applications to separate CO 2 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 functio n of compression demand, with little opportunity for large future improvements.

In contrast, the generators of grid electric pow er 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 hi ghly time and site specific, depending on the cost of electricity and the value of natural gas, the numbe rs 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. Elect ric power costs were based on $8/month/kW demand charge, $0.08/kWh electricity cost, and 95% motor m echanical efficiency. Natu ral gas fuel costs were based on $7.26/MMBtu wellhead natural gas pr ice 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 approximate ly $174,000. In addition to these energy costs, it is important to also consider ope rating 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 electri cal 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 w ould 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 cap ital costs. The data show that there is little cost difference in this example, with a slight co st 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 th e Barnett Shale. In addition to the potential cost savings of electrical compression over engine compressi on, the lack of an overwhelming economic driver one way or the other allows the environmental benefi ts 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) 136,000 174,000

O&M 35,000 6,200
capital 74,000 52,000

Total 245,000 232,00032 5.2 Oil and Condensate Tanks

Oil and condensate tanks in the Barnett Shale are sign ificant sources of multiple air pollutants, especially VOC, HAPs, and methane. Multiple options exist fo r reducing emissions from oil and condensate tanks, including options that can result in incr eased 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 effec tive systems for capturing and separating vapors and gases produced by oil and condensate tanks. Gases and vapor s 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 tota l production of gas at the well, leading to an increase in g as 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 t pd of methane that is estimated to be emitted in

2009 from condensate tanks in the Barnett Shale ha ve 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 Barne tt 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 distribu tion 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 fla mmable gas destruction devices. Enclosed flares get

their name because the flame used to ignite the gases is generated by bu rner tips installed within the stack well below the top. The flames from enclosed flar es are usually not visible from the outside, except during upset conditions, making them less objectionabl e to the surrounding community compared to open (unenclosed) flares.

Using a flare to control emissions from tanks involves c onnecting the vents of a tank or tank battery to the bottom of the flare stack. The vapors from oil and conden sate tanks are sent to the flare, and air is also added to provide oxygen for combustion. The vapors a nd air are ignited by natural gas pilot flames, and much of the HAP, VOC, and methane content of th e tank vapors can be destroyed. The destruction efficiency for flares can vary greatly depending on r esidence 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 Barne tt Shale oil and condensate tanks emissions estimates shown in Table 16 results in potential emission reducti ons of 30 tpd of VOC, 0.6 tpd of HAPs, and 7 tpd

of methane. These reductions are substantial and wo uld 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 quick ly 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 emissi ons of natural gas during well completions. These procedures are known by a variety of terms, incl uding "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 pl aced 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 peri od 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 t echnology 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 s ite-specific factors, including the pressure of the fluids brought to the surface, the effectiven ess 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 completi on work before the start of regular production.

Some recent reports of the effectiveness of green co mpletions in the U.S. are available, including one by the U.S. EPA which estimated 70% capture of fo rmerly released gases with green completions, and another report by Williams Corporation which found th at 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 repor ted $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 environmenta lly friendly alternative to flaring of the gases, since flaring destroys a valuable commodity and prev ents its beneficial use. Green completions would also certainly be more beneficial than venting of th e gases, since this can rel ease very large quantities of34 methane and VOCs to the atmosphere. Another factor in favor of capturing instead of flaring is that flaring can produce carbon dioxide (a greenhou se 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 pro cessing plants, gas compressors, and transmission lines in the Barnett Shale can be minimized with aggr essive efforts at leak detection and repair. Unlike controlling emissions from comparatively smaller nu mbers 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. Wh ile no single valve or flange is likely to emit as much pollution as a condensate tank or engine exhaus t stack, the cumulative ma ss of all these fugitives can be substantial. There are readily-availabl e 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 sch eduled 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 organi c 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 detect ion and repair protocols established in the NSPS could certainly be used to identif y fugitive emissions from these other items. Leak detection at processing plants covered by the NSPS is perfo rmed using handheld or ganic vapor meters (OVMs), and inspections are required to be done on a specified schedule. Th ese 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 emis sions. 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 im plementing VOC control stra tegies 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 stat e investigated the air quality impacts of oil and gas development, including the impacts of the pneuma tically-controlled valves and other devices that are found throughout gas production, processing, and transm ission 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 CH 4 , VOC, and HAP emissions. (45,46) Much of the following information on these devices and the strategies to control emissions is b ased 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 sector35 are pneumatically operated. Instrument air (i.e. co mpressed 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 inte rmittently, depending on the kind of device. In 2003 U.S. EPA estimated that emissions from the pneumatic devices found th roughout 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 na tural 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 wi th 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 thei r 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 coul d 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 devi ces can be reduced by routing pneumatic discharge ports into a fuel gas supply line or into a closed loop controlled system. Anothe r 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 c oncentration of pneumatic devices, full-time operator presence, and are on a power grid. In an instrument pr essurized air system, atmospheric air is compressed, stored in a volume tank, filtered, and dried. Th e 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 actua tors can be reused when converting from natural gas to compressed air.

The U.S. EPA runs a voluntary program, EPA Natura l Gas STAR, for companies adopting strategies to reduce their methane emissions. Experience from compan ies 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/m 3 , this resulted in a savings of $148,800 per year. The cost, including materials and labor fo r 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/m 3
gas, the payback was estimated to take 21 mont hs. For new installations or end of service life replacement, the incremental cost difference of hi gh-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 fo r reducing emissions and enhance gas collection from pneumatic devices in Barnett Shale area operations. These strategies include:36 • Installing low- or no-bleed pneumatic de vices 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 de vices 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 toxi c compounds, and greenhouse gases from oil and gas activity in the Barnett Shale area, and id entified methods for reducing emissions.

Emissions of ozone and fine pa rticle 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 CO 2 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 availabl e 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 captu re methane and VOC compounds during well completions,

x phasing in of electric motors as an alternativ e to internal-combustion engines to drive gas

compressors,

x the control of VOC emissions from condensat e 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 coul d 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 compre ssion power could reduce smog-forming emissions in the D-FW metropolitan area by 65 tpd. Significant emi ssion 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 g as 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 availabl e methods to oil and gas production activities in the

Barnett Shale.38 

### 7.0 REFERENCES

1. Railroad Commission of Texas, "Barnett Shal e 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/div isions/og/maps/index.html

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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, "Revisi ons to the State Implementation Plan (SIP) for

the Control of Ozone Air Pollution – Dallas-Fo rt 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

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on-line document: http://www.tceq.state.tx.us/implemen tation/air/industei/psei/psei.html39 13. Eastern Research Group, "Natural Gas Compress or Engine Survey for Gas Production and Processing Facilities – H68 Final Report." a report prepared for the Houston Advanced Research Center. October 5,

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15. Personal communication with Barnett Shale g as producer – condensate tank emissions modeling results, 2008.

16. George D.L. "Preparation of Natural Gas Bl ends Used as Calibration Standards: Sources of Uncertainty and Best Preparation Practices – Final Re port." Southwest Research Institute, San Antonio, Texas. April 2003.

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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.

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2006.

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21. Fernandez R. et al, "Cost-Effective Methane Emissions Reductions for Small and Midsize Natural Gas Producers." Journal of Petroleum Technology, June 2005.

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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 Im pacts 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 Envi ronment, Air Pollution Control District, "Control of Compressor Engine Emissions, Related Cost s and Considerations." October 31, 2003. on-line report: http://apcd.state.co.us/docum ents/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 Ma rch 21, 2006)." information from Jaime Pagan of OAQPS.

28. ENVIRON International Corporation, "Demonstra tion 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 a nd 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.

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32. Mokhatab S. "Compressor Station Design Crite ria." Pipeline and Gas Journal, June 2007.

on-line document: http://findarticles.com/p/articles/mi_m 3251/is_/ai_n25008106 ?tag=artBody;col1

33. Ranger Plant Construction Co mpany, Inc., Abilene, Texas.

on-line document: http://www.rpcabilene.com/history-1.html41 34. Wellhead Compressors, Inc., Midland, Texas.

on-line document: http://wellheadcompressors.com/products/index.html

35. EnerSource Compression Systems, Inc., Odessa, Texas.

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36. Valenti M. "Gas Pipelines Go Electric." Mechanical Engineering, December 1996.

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37. Dresser-Rand Corporation, "New Datum-C Elect ric Motor-Driven Compressor Provides Quiet, Emission-Free Solution for Natural Gas Pipeline Appli cations." Dresser-Rand Insights, vol. 8, no. 1,

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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/dow nloads/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/wor kshops/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, Pa rtner 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/mee tings/EPESC/2007/GreenhouseGas_BrianWoodward.pdf

43. U.S. Environmental Protection Agency, "Standa rds 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, "Standard s of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Indust ry 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, "Devel opment of Baseline 2006 Emissions from Oil and Gas Activity in the Denver-Julesburg Basin." a report prepar ed for the Colorado Department of Public Health and Environment. April 30, 2008.

46. Colorado Air Pollution Control Division, "High Bl eed 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 Ar ea 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).pdf43 Author's Notes:

A draft version of this report was prepared in Sept ember 2008 and distributed for review and comment to oil and gas producers, state and federal regulators, autho rs of some of the references used in this report, and others. The author appreciates the comments recei ved by those reviewers and the time they took to provide feedback. For the purpose of full disclosu re, 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 aut hors of Reference 15 were also employees of Radian International LLC, working as contractors for th e Gas Research Institute and the Environmental Protection Agency. The author of this study notes t hat 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 Co mmission 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