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November 23, 2010

Lisa Jackson, Administrator U.S. Environmental Protection Agency Ariel Rios Bldg. 1200 Pennsylvania Ave., NW Washington, D.C. 20460

Re: Opportunities to Reduce Methane Em issions from Oil and Gas Operations through the New Source Performance Standards, EPA-HQ-OAR-2010-0505-

0001

Dear Administrator Jackson:

Enclosed please find an expert report detailing the tremendous opportunities to reduce methane emissions from the oil and gas sector under th e Clean Air Act. The U.S. Environmental Protection Agency (“EPA”) is currently re viewing whether to update the New Source Performance Standards (“NSPS”) and Nationa l Emissions Standards for Hazardous Air Pollutants (“NESHAP”), and whether to promulgate residual risk standards for the oil and gas

sector. See Docket EPA-HQ-OAR-2010-0505-0001. It is our hope that this report can guide the Agency as it completes its review and proposes future action, particularly with regards to the

NSPS.

The report, which was prepared by Cindy Copeland and Megan Williams 1 for Earthjustice on

behalf of WildEarth Guardians and San Juan Ci tizens Alliance, provides a critical roadmap for achieving at least a 90% reduction in methane, if not greater, from oil and gas operations nationwide using demonstrated practices and te chnologies. Such reductions promise a number of benefits: reduced greenhouse gas emissions, in creased savings for industry, decreased safety risks, and a number co-benefits, including reductions in air toxics, ozone precu rsors, and greater overall protection for public hea lth and welfare. Above all, th ese reductions would just make good business sense. They would encourage grea ter efficiency, reward those companies that have already mobilized methane reduction practi ces and technologies, and fuel the creation of jobs within the air pollution cont rol sector. The benefits canno t be overstated. A 90% reduction in methane emissions from the oil and gas sector has the potential to recover more than $1 billion in lost value every year.

We urge you to take into consideration the findings of this report and to se ize this opportunity to achieve significant, sector-wide reductions in me thane through the NSPS. Specifically, we urge you to set concrete limits on methane emissions ba sed on the available cont rol technologies and

1 See CVs for Ms. Copeland and Ms. Williams, attached.Letter to Administrator Jackson re: Opportunities to Reduce Methane Emissions from Oil and Gas Sector Page 2 November 23, 2010

practices outlined in the enclos ed report. We further urge you to set a nationwide goal of reducing methane emissions by 90% or more from the oil and gas sector. The EPA’s duty and authority to establish such st andards and goals is firmly s upported by the Clean Air Act.

As you know, the Administrator has a duty to addr ess the issue of methan e emissions through the NSPS. It is already recognized that the o il and gas source category releases ai r pollution anticipated to endanger public he alth and welfare. Furthermore, the EPA has definitively found that greenhouse gases, including methane, pose an endangerment to public health and welfare.

See 74 Fed. Reg. 66496 (Dec. 15, 2009). In light of these facts, the Administrator has clear authority to promulgate “a standard for emissi ons of [methane] which reflects the degree of

emission limitation achievable thro ugh the application of the best system of emission reduction

which ... the Administrator determines has b een adequately demonstrated.” 42 U.S.C. § 7411(a)(1).

The Administrator also has a duty to regulate methane emissi ons from existing sources in accordance with Section 111(d) of the Clean Air Act. See 42 U.S.C. §§ 7411(d)(1)(A)(i) and (ii); 40 C.F.R. § 60.21(a). Therefore, we urge th e Administrator to ensure that existing sources

of methane are addressed as a ppropriate under Section 111(d).

We appreciate your attention to this issue and your commitment to comprehensively reviewing the opportunities available for contro lling harmful air pollution from the oil and gas sector. It is

fortunate that there exists a w ealth of proven options to cost-e ffectively control emissions. We urge you to ensure that any revised NSPS ensure c oncrete reductions in methane consistent with what we know works. If you or your staff have any questions about this report, please contact me at 303-996-9622. Thank you.

Sincerely,

Edward B. Zukoski, Staff Attorney

Attorney for WildEarth Guardian s and San Juan Citizens Alliance

Cc: Gina McCarthy, Deputy Admi nistrator for Air and Radiation Bruce Moore, Senior Technical Advisor, Oil and Natural Gas Sector, Office of Air Quality Planning and Standards

Encs. (1) Report; (2) Cindy Copeland CV; and (3) Megan Williams CV.

## METHANE CONTROLS

FOR THE OIL AND GAS PRODUCTION SECTOR

prepared by Megan Williams and Cindy Copeland November 23, 2010

I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS

Due to rapidly increasing and widespread oil an d gas development across the country and due to the extraordinarily high levels of greenhouse ga ses and air pollutants emitted from this development, there is an urgent need for strong protective standards to be established for the oil and natural gas sector.

Oil and natural gas production are included in the EPA’s priority list of categories set forth at 40 CFR § 60.16, pursuant to section 111(b)(1)(A ) of the Clean Air Act, which in the Administrator’s judgment, cause or contribute “significantly to, air pollution which may reasonably be anticipated to enda nger public health or welfare.” 1 On June 24, 1985, EPA promulgated New Source Performance Standard s (NSPS) for Equipment Leaks of volatile organic compounds (VOCs) from Onshore Natu ral Gas Processing Plan ts (40 CFR part 60, subpart KKK) and on October 1, 19 85, EPA promulgated a NSPS for SO 2 emissions from Onshore Natural Gas Processing (40 CFR part 60, subpart LLL). EPA has failed to promulgate more comprehensive standards for the much br oader source category of oil and natural gas production (including both onshore and offshore development) and has failed to update, as required by law, the two standards it did promul gate. In response to a January 14, 2009 lawsuit brought by WildEarth Guardians and San Juan C itizens Alliance, EPA agreed to a consent decree whereby it would review and propose necessa ry revisions and expansions to the NSPS for the oil and natural gas production sector by January 31, 2011, and fi nalize standards by November 30, 2011. 2

A critical component of EPA’s re view and revision of the NSPSs for oil and gas operations is the development of standards for the reduction of methane emissions from the oil and gas sector. Methane is a potent greenhouse gas, roughly 20 time s more powerful at warming the atmosphere than carbon dioxide by weight, and with a relatively short a tmospheric lifetime of about 12 years. Methane, thus, is a prime contributor to short-term climate change over the next few

decades.

There are many proven technologies and practices already available to re duce significantly the methane emissions from oil and gas operations. Th ese technologies also offer opportunities for significant cost-savings from recovered methane gas. Methane is often expressly exempt from state regulations since greenhouse gases (GHGs) are not yet federally regulated as an air pollutant. EPA must fill this void by proposing comprehensive regulations for methane. EPA’s inclusion of methane performance standards and operating practices for oil and gas would be a!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 1 42 U.S.C. § 7411(b)(1)(A).

2 See Consent Decree, WildEarth Guardians v. Jackson , 1:09-cv-00089-CKK (D.D.C), Dkt. Entry # 25 (Feb. 4, 2010)." cornerstone in a comprehensive regulatory fr amework for methane emissions reductions across

the U.S.

We respectfully urge EPA to expeditiously develop and apply New Source Performance Standards for new and modified oil and gas sour ces that achieve at least a 90% reduction in methane emissions. EPA’s own voluntary Natura l Gas STAR program provides an excellent opportunity to build from the wealth of knowle dge and information regarding methane reduction control technologies for every co mponent of the oil and gas sect or. Based on the demonstrated effectiveness of many of thes e key control technologies, EP A should require at least 90%

reduction in methane emissions from sources am ong this sector, and in some cases reductions greater than 90% are warranted. A framework to achieve at leas t a 90% reduction in methane emissions from oil and gas source s is laid out in this report.

As the oil and gas sector conti nues to grow, more sources of me thane emissions are added each year. These new emissions sources include a cert ain percentage that re place existing sources ( e.g. , new compressor engines that replace old ones) a nd a certain percentage that add to the total population. Progress in reducing em issions through standards fo r new and modified sources depends on the rate at which new emissions sour ces are added to the pop ulation and on the level of reductions implemented. The higher the leve l of control required, the sooner meaningful

emissions reductions will be achieved. A 90% sect or-wide reduction in emi ssions might still take years to achieve depending on how quickly new sources penetrate the source population. Therefore, it is imperative that EPA establish th e highest level of emi ssions reductions possible

for new and modified sources in the oil and gas sector.

There are numerous existing control technologies for oil and gas emission sources that achieve a 90% or greater control efficiency for reducing methane emissions. For example, compressor rodpacking technologies can reduce methane emissi ons by more than 90%, the use of no bleed pneumatic devices can practically eliminate methane emissions, the use of dry seals in centrifugal compressors can re duce methane emissions by 99%, zero emission dehydrators virtually eliminate methane emissions, and the us e of vapor recovery un its at crude oil and condensate storage tanks can reduce methane emi ssions by at least 98%. In addition, there are multiple examples of existing emissions re duction programs at the state, county, and international levels that require methane emissions reductions of 90% or greater from oil and gas

sources.

The following is a listing of the methane contro l technologies and measur es recommended in this report. These controls were chosen because they would achieve the maximum emission reductions possible using availabl e technologies or practices. The recommendations are listed by major oil and gas source type.

Recommended methane controls for pneumatic devices:

! Require Pneumatic Devices That Use Instrume nt Air or Mechanical Controls, Nitrogen Gas, or Electric Valve Controllers in Place of Gas Powered Pneumatic Devices

! Require Low-Bleed Pneumatic Devices for New Installations and Require Modified Sources to Retrofit High-Bleed Devices with Low-Bleed Devices# Recommended methane controls for compressors:

! Require the Use of State-of-the-Art Compressor Rod-Packing Technology

! Require the Use of Dry Seals in Centrifugal Compressors

! Require the Use of Air or Electric Starters Instead of Gas Starters

! Require the Use of State- of-the-Art Compressor Cyli nder Unloader Technology and Require Regular Replacement

! Require Operating Practices That Elimin ate or Reroute Gas Leakage When Taking Compressors Off-line

! Require Direct Inspection and Main tenance at Compressor Stations

! Require Isolation Valves To Be Installed in Close Proximity to Compressors For All New

Installations

Recommended methane controls for dehydrators:

! Require the Use of Zero Emission Dehydrators

! Require the Use of Solid Desiccant Dehydr ators in Cases Where Zero Emission Dehydrators Are Not Feasible

! Require Glycol Dehydrators to Use Vapor Recovery Units

! Require the Use of Flash Tank Separators

! Require Circulation Rate Adjustment Practices for All Glycol Pumps

! Require Glycol Dehydrators to Use Portable Desiccant Dehydrators During Maintenance

! Require Installation of BASO ® Valves

Recommended methane controls for tanks:

! Require the Use of Vapor Recovery Units With at least 98% Control Efficiency for All New Crude Oil and Condensate Storage Tanks

Recommended methane controls for wells:

! Require the Use of Reduced Emissions Completions or Green Completions

! Require the Installati on of Plunger Lift Systems and th e Development of Operational

Practices that Minimize Methane Emissions

! Require the Installation of Downhole Separator Pu mps, Where Applicable

! Require Mud Degassing Vents Be Routed to a Vapor Recovery Unit

Recommended methane controls for pipelines:

! Require the Use of Gas Main Fl exible Liners and State-of-the -Art Pipeline Material and Protective Coatings

! Require Maintenance Practices for Pipelines

! Require the Installation of Excess Flow Valves on All Gas Service Lines

Recommended methane controls for flares:

! EPA should require producers to reduce emissions by instituti ng a gas utilization program, such as sending emissions to a vapor recovery unit, rather than flaring and venting.$ Recommended methane controls for directed inspection and maintenance practices:

! EPA should require that operators implem ent directed inspection and maintenance programs and good work practices in all possibl e sectors in order to detect and reduce

methane emissions.

There is a large body of scientif ic work documenting the adverse impacts to public health and welfare from climate change caused by GHG emissions, such as methane. More recently,

scientific studies have also demonstrated that these same methane emissions contribute to the formation of ground-level ozone, a harmful air pollu tant that impacts the health of millions of

Americans. 3 Specifically, the U.S. Climate Change Science Program recently reported that methane reductions accomplish the dual goal of addressing climate change and ozone pollution. 4
Methane reductions achieved through new source performance standards and practices will have a direct impact on both climat e change and ozone pollution.

Many of the methane emission controls for th e oil and gas sector also reduce VOCs and hazardous air pollutants (HAPs), while some contro ls also have the added benefit of improving safety at the sources. State, local and interna tional programs that aim to reduce VOCs and HAPs and are reviewed in this report because of th e co-benefit any such reductions would have for reducing methane emissions. Any strategy to lim it the amount of VOC or HAP emissions from oil and gas processes would also reduce me thane emissions. And conversely, regulatory

reductions in methane emissions will also reduc e VOC and HAP emissions. The associated air quality benefits that result fr om reductions in VOC and HAP emissions are a huge co-benefit of methane reduction technologies.

VOCs are an important component in the forma tion of ozone. Ozone pollution causes breathing problems, chest pain and even permanent lung damage after repeated exposure. Oil and gas sources are major contributors to ozone problems in areas of highly concentrated development, such as western Wyoming, where sparsely popu lated Sublette County is a proposed ozone

nonattainment area. 5 Most of the VOCs emitted from oil and gas sources are also hazardous air pollutants. HAPs present in oil and gas developm ent include benzene, toluene, ethylbenzene, xylene and n-hexane, which cause a wide array of adverse health impacts, including cancer and

other serious illnesses. 6!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 3 See, e.g. , Arlene M. Fiore et al. , “Characterizing the Tropospheric Ozone Response to Methane Emission Controls and the Benefits to Climate and Air Quality,” Journal of Ge ophysical Research Vol. 113, April 30, 2008, p.1 (“[I]n the presence of nitrogen oxides (NO

x ), tropospheric CH4 [methane] oxidation leads to the formation of O 3 [ozone].”)

4 See Hiram Levy II et al. , U.S. Climate Change Science Program Synthesis and Assessment Product 3.2, “Climate Projections Based on Emissions Scenarios for Long-Lived and Short-Lived Radiatively Active Gases and Aerosols”, September 2008, p. 65, http://www.climatescience.gov/Library/sap/sap3-2/final-report/ (finding that reducing methane emissions “lead[s] to reduced levels of atmos pheric ozone, thereby improving air quality” and “lead[s] to reduced global warming”).

5 See Wyoming Department of Environmental Quality at http://deq.state.wy.us/aqd/Ozone% 20Nonattainment%20Information.asp

6 see EPA, http://www.epa.gov/airquality/oilandgas/basic.html% California’s Proposed Greenhouse Gas Reduction Plan is an Example of a Comprehensive Mandatory Approach to Greenhouse Gas Reductions

California is currently working to require GHG emissions reducti ons in a broad sweeping plan. In 2011, the California Air Resources Board (CARB) will consider a historic proposal to limit GHG emissions from every sector in the state. If approved, this measure will be implemented in

2012. 7 CARB’s Climate Change Scoping Plan aims to achieve greenhouse gas reductions in oil and gas extraction and transmission. These strate gies will use proven te chnologies from EPA’s Natural Gas STAR program, but the program w ill be mandatory rather than voluntary. The control measures for the oil and gas extraction sector will include “imp roving operating practices to reduce emissions when compressors are take n off-line; installing compressor rod packing systems; substituting high bleed with low bleed pneumatic devices; improving leak detection; installing electronic flare ignition devices; repl acing older equipment (flanges, valves, and fittings); and installing vapor re covery devices.” The GHG contro l technologies for the oil and gas transmission sector will include “improving operating practices to reduce emissions when compressors along the pipeline are taken off-line, as well as installing compressor rod packing systems and replacing older equipment (flange s, valves and fittings) along the pipelines.” 8

California’s oil and gas sector includes onshore and offshor e operations. The Oil and Gas Extraction GHG Emission Reduction measure target s fugitive emissions (which are mostly methane) from extraction sources; these emissions are estimated to be 0.3 million metric tons

CO 2 equivalent (MMTCO 2 e) in 2020 and currently account for approximately 5% of the GHG

emissions from this sector. With these estima tes, CARB acknowledges that while historical trends are used for calculations, this sector could see even more growth in the future with

increased oil extraction as a result of increase d crude oil prices. The oil and gas extraction emission reduction measures are pr ojected to result in a 0.2 MMTCO 2 e emissions decrease per year beginning in 2015, a 67% reduction in emissions. 9 The 2020 inventory projections for the oil and gas transmission category are 1.7 MMTCO 2 e and the implementation of the scoping plan will reduce emissions by 0.9 MMTCO 2 e, a greater than 50% reduction in emissions. 10 These planned GHG emission reduction measures will result in significant economic benefits. The cost savings for the oil and gas GHG reduction extracti on measures are expected to be $3.7 million annually, while the reduction measures for oil and gas transmission are projected to save $17 million annually. 11

California’s efforts to reduce GHG emissions from all sources acro ss the state is evidence that technology standards and practices are avai lable to support mandatory reductions.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 7 California Air Resources Board, Scoping Plan Measures Implementation Timeline, July 1, 2010, http://www.arb.ca.gov/cc/sc opingplan/sp_measures_imp lementation_timeline.pdf.

& “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework for change,” California Air Resources Boar d, December 2008, pp. C-153 and C-154, http://www.arb.ca.gov/cc/scopingplan/doc ument/appendices_volume1.pdf#page=184.

' Id. p. C-153.

10 Id . pp. C-153 and C-154.

11 Id.( II. REVIEW OF METHANE EMISSION S CONTROLS BY MAJOR OIL AND GAS

SOURCE TYPE

This section provides a review of currently available technolog ies and practices, as well as existing regulatory initiatives, to reduce methan e emissions for each of the following major oil and gas source types: pneumatics, compressors, dehydrators, tanks, wells, pipelines and flares. The section ends with a more general sec tion on the value of di rected inspection and maintenance practices.

In general, methane emissions occur across all s ectors of the natural gas industry ( i.e.

, production, processing, transmission and distribution) in both ons hore and offshore applications. Emissions occur during normal opera tions and routine maintenance ev ents and also as a result of leaks and system upsets. Fugitive emissions occu r as a result of both intentional venting and unintentional leakage. In addition to natural gas operations, methan e emissions also occur in the oil industry, primarily from field production operations ( e.g. , the venting of associated gas from oil wells), oil storage tanks, a nd production-related equipment ( e.g. , gas dehydrators and pneumatic devices). The following subsections discuss the multiple control technologies available to significantly reduce the meth ane emissions of a particular source ( e.g. , venting from the device, leaks, offshore applications, etc.).

A. Pneumatic Devices

Pneumatic devices are used in all sectors of the oil and natural gas industry for liquid level controllers, pressure regulators and valve controllers. Such de vices are typically powered by natural gas, although some are powered by electricity or comp ressed air. The natural gas powered devices vent large amounts of methane to the atmosphere as part of their normal operations. There are 3 main types of pneumatic de vices in use in the natural gas industry, which include: (1) continuous bleed devi ces that generally bleed natura l gas continuously and act to modulate flow, liquid level or pr essure; (2) actuating or intermitt ent bleed devices that open and close, releasing gas to the atmo sphere periodically; and (3) self -contained controllers that do not release any gas to the atmosphere, sending the gas downstream instead. The Natural Gas STAR Program defines any pneumatic device that bleeds over 6 standard cubic fe et per hour (scfh) of natural gas as a high-bleed device. Th e Natural Gas STAR Program states:

In general, the bleed rate will also vary with the pne umatic gas supply pressure, actuation frequency, and age or condition of the equipment. Due to the need for precision, controllers that must operate qui ckly will bleed more gas than slower operating devices. The condition of a pneuma tic device is a stronger indicator of emission potential than age; well-ma intained pneumatic devices operate efficiently for many years. 12

The production sector includes by far the larges t number of gas powered pneumatic devices, estimated at around 400,000. 13 Pneumatic devices are the larges t source of methane emissions!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 12 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the Natural Gas Industry,” October 2006, p. 4, http ://www.epa.gov/gasstar/docum ents/ll_pneumatics.pdf.

13 Id., p. 2.) from the oil and natural gas production sector, to taling an estimated 43 Bcf—or 35 percent— of all production-based emissions (based on 2009 data). 14 In this sector, cont rollers are used to regulate temperature in dehydrator regenerators, regulate pressure in flash tanks and control and monitor gas and liquid flows and levels in dehydra tors and separators. The transmission sector is the second largest sector for methane emissions from pneumatic devices , with an estimated 85,000 devices used to “actuate isolation valves and regulate gas flow and pressure at compressor stations, pipelines, and storage facilities.” 15 Pneumatic devices in the transmission sector account for an estimated 11 Bcf of methane annually (based on 2009 data). 16 Around 13,000 of the pneumatic devices are used in the processing sector at gas gathering and booster stations for compressor and glycol dehydration c ontrol and at processing plants for isolation

valves. 17

Emissions from natural gas driven pneumatic valve and pump devices are known to be major contributors to fugitive emissions from the o il and gas production sector. Yet, the emission

factors used to estimate overall emissions fr om pneumatic devices may underestimate emissions from this source category. Reported uncerta inties can range from ±33% to ±407%. 18 In addition to the uncertainty in inventor y estimates, the sheer number of pneumatic devices makes this a particularly important source category to focus on. Emissions reductions from the hundreds of thousands of pneumatic devices used throughout the oil and gas sector have the potential to greatly influence overall emissions and associat ed impacts. The magnitude and importance of this emissions source should also drive a greater emphasis on compliance via direct measurement ( e.g. , metering), rather than compliance based on engineering estimates ( e.g. , Original Equipment Manufacturer (OEM) emi ssion factors). EPA should requir e installation of gas meters

at new installations in order to monitor instru ment gas consumption a nd provide an accurate

determination of methane emissions.

1. Existing State Programs to Reduce Methane Emissions from Pneumatic

Devices

The following state programs demonstrate that mandatory controls for reducing methane emissions are possible. EPA should consider these standards as minimum requirements for regulating sources under the NSPS. Regulations aimed at reducing VOCs and HAPs are relevant to consider because of the corresponding reducti ons in methane emissions that are achievable through implementation of these cont rol technologies and practices.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 14 EPA Natural Gas STAR, http://www.epa.gov/ga sstar/basic-information/index.html#sources.

15 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the Natural Gas Industry,” October 2006, p. 2.

16 EPA Natural Gas STAR, http://www.epa.gov/ga sstar/basic-information/index.html#sources.

17 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the Natural Gas Industry,” October 2006, p. 2.

18 See, e.g., API Compendium of Greenhouse Gas Emissions Methodologies For the Oil and Natural Gas Industry, August 2009, Table 5-15, pages 5-68 and 5-69, http://www.api.org/ehs/climate/new /upload/2009_GHG_COMPENDIUM.pdf.& Colorado

The Colorado Department of Public Health and Environment’s Air Po llution Control Division addresses oil and gas related ozone issues in Regulation Number 7, which controls VOCs and nitrogen oxides (NO X ) for the 1-hour and 8-hour ozone nonatt ainment or attainment/maintenance areas, as well as statewide. Unde r these regulations, all new pneuma tic devices are required to be low-bleed and existing high-bleed (any device that emits more than 6 standard cubic feet per hour (scfh)) pneumatic devices must be replaced or retrofitted to meet the state’s low-bleed specifications of 6 or fewer scfh of natural gas. 19 This regulation is aimed at reducing VOC emissions, but methane emissions are reduced as a co-benefit of the requirements. 20 For the rest of the state, new, replaced or repaired pneumatic devices are requi red to install low-bleed valves, where technically feasible. 21

Wyoming

The Wyoming Department of Environmental Qual ity’s permitting requirements cover pneumatic pumps and controllers. While the main goal of the state’s rules is to reduce VOC and HAP emissions, methane reductions are a co-benefit of the controls. Wyoming’s most restrictive requirements for pneumatic pumps apply to the J onah and Pinedale Anticline Development Area, where pneumatic heat trace pumps and other pneuma tic pumps at all new and modified facilities must meet a 98% control require ment for VOC and HAP emissions. 22

In addition, Wyoming’s requirements for new faci lities with natural ga s operated pneumatic controllers, or new natural gas operated pneumatic c ontrollers at modified facilities, dictate that

such controllers must be low or no-bleed (where low bleed is 6 sc fh or less) or the controller discharge stream must be routed to a closed loop system. For m odifications at facilities with existing pneumatic controllers, the devices must be replaced or converted in order to meet the same requirements for new facilities within 60 days of modification. 23

California

CARB’s proposed GHG rules (described above) in clude control measures for pneumatics to replace high-bleed devices w ith low-bleed bleed devices. 24!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 19 There are certain exceptions to these requirements for hi gh-bleed pneumatic controllers that need to remain in place due to safety issues.

20 Colorado Department of Public Health and Environment, Air Quality Control Commission, Regulation Number 7,

“Control of Ozone Via Ozone Precurso rs (Emissions of Volatile Organic Compounds and Nitrogen Oxides),” 5

CCR 1001-9.

21 Colorado Code of Regulations, 2 CCR 404- 1 “Practice and Procedure,” §805 b(2)E, http://www.sos.state.co.us/CCR.

22 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, p. 19.

23 Id, 10, 19.

24 “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework for change,” California Air Resour ces Board, December 2008, C-153, http://www.arb.ca.gov/cc/scopingplan/doc ument/appendices_volume1.pdf#page=184.' 2. Available Proven Technologies for Pneumatic Devices

EPA’s own Natural Gas STAR program demonstrat es that there are many currently available, technically feasible, and cost-eff ective technologies that can greatly reduce methane emissions from pneumatic devices. EPA should, at a mini mum, require the follo wing technologies and operating practices as part of its revise d NSPS for oil and natural gas systems.

Require Pneumatic Devices That Use Instrument Air or Mechanical Controls, Nitrogen Gas, or

Electric Valve Controllers in Place of Gas Powered Pneumatic Devices

The installation of pneumatic cont rols that use instrument air ra ther than gas powered low-bleed

or no-bleed devices can achieve 100% methane emission reductions. Many Natural Gas STAR partners have realized economic benefits from switching to instrument air. This technology can be used where electrical power is available, or to further reduce ener gy demands and to expand possible usage, instrument air devices can be converted to solar-powered, battery-operated devices. Several Natural Gas STAR partne rs have had success with this option. 25

In addition to economic benefits from using instru ment air, natural gas co mpanies can achieve an extended life for control devices and improve operational efficiencies beyond that of gas powered devices. Significant safety improvements are also realized sinc e flammable natural gas is no longer used for this proce ss, which is of particular importance at offshore operations where there are greater risks from fl ammable and hazardous materials. 26

Pneumatic controllers can also employ mechanical control, nitrogen gas, or electric valve controllers. Some Natural Gas STAR partners have reported success with the use of mechanical controls in remote, non-electrif ied production, processes, transm ission and distribution sites.

“The most common mechanical control device is a level controller, which translates the position of a liquid-level float to the dr ain valve position with mechanical linkages. There is no gas usage in either the process measurement or valv e actuation, and reliability is very high.” 27 Use of nitrogen gas or electric valve controllers are additional alternatives to gas pneumatics, although they each present significant limitations. 28

CARB lists replacing gas powered pneumatic devi ces with compressed air systems or nitrogen gas as a Best Management Practice (BMP) for oil and gas sources. 29 EPA should require that all new pneumatic device installations use instrument air, powered either by electricity of solar energy or use mechanical controls, nitrogen gas or el ectric valves if instrument air is not feasible. All modified sources should be required to c onvert gas powered pneuma tic control devices to!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 25 EPA, “Solar Power Applications for Methane Emissi ons Mitigation: Lessons Learned from the Natural Gas STAR Program,” 8/31/2009, 15-23.

26 Id. 5,6.

27 Lessons Learned, Natural Gas STAR Partners, “Convert Pneumatics to Mechanical Controls,” September 2004, p.

1 & 2.

28 Lessons Learned, Natural Gas STAR Partners, “Convert Gas Pneumatic Controls to Instrument Air,” October 2006, p. 15.

29 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.*+ meet the standards for new sources. Reductions in methane emissions of 100% would be expected from this technology.

Require Low-Bleed Pneumatic Devices for New Installations and Require Modified Sources to Retrofit High-Bleed Devices with Low-Bleed Devices

Methane emission reductions can be achieved by requiring low-bleed devi ces in place of highbleed natural gas powered pneuma tic devices, and by improving main tenance in order to reduce methane emissions. Installing low-bleed pneumatic devices instead of hi gh-bleed devices is a cost-effective methane reduction strategy. Depe nding on the device installed, annual savings from emission reductions can vary from $315 to $1820 and the cost of installation is often recovered in one year. 30 For example, the installation of a lo w-bleed liquid level controller, at an initial $513 for the unit, would save $1165 annually. 31 For any new and modified installations where non-gas powered pneumatic devices are not feasible, EPA should require the use of lowbleed devices.

For modified sources, switching high-bleed pneuma tic devices to low-bleed involves replacing, retrofitting and maintaining the de vices and using all or one of these strategies in order to

achieve the low-bleed rate of less than 6 scfh na tural gas (over 50 Mcf/yea r). Significant savings and methane emission reductions have been achieved by Natural Gas STAR partners who have implemented these strategies. 32 Replacing, retrofitting and main taining pneumatic devices also has the added benefit of increasing operationa l efficiencies for the devices by improving both system-wide performance and reliability, and mo nitoring of parameters such as gas flow, pressure, or liquid level. 33

EPA should require that any new pneumatic devices that must be gas-powered be low-bleed or that modified devices be replaced or retrofitted to meet low-bl eed criteria. As discussed above, the states of Colorado and Wy oming already have programs in place for requiring low-bleed pneumatic devices and California is currently cons idering this strategy as part of its greenhouse gas reduction plan. In addition, both the Bureau of Land Management (BLM) and CARB list the use of low-bleed pneumatics as a BMP for oil and gas sources. 34 This proven best management practice should be required for all new pneum atic devices in order to achieve emission

reductions of 98% for these units.

3. Summary Recommendations for Pneumatic Devices

EPA should implement the following technology st andards and operating practices for all new pneumatic devices:!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 30 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the Natural Gas Industry,” October 2006, p. 4.

31 Id. , p. 7.

32 Id. , p. 1.

33 Id., p

. 4.

34 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.** ! Require Pneumatic Devices That Use Instrume nt Air or Mechanical Controls, Nitrogen
Gas, or Electric Valve Controllers in Place of Gas Powered Pneumatic Devices EPA should require that all new pneumatic de vice installations us e instrument air, powered either by electricity of solar energy or use mechanical controls, nitrogen gas or

electric valves if instrument air is not feasib le. All modified sources should be required to convert gas powered pneumatic control device s to meet the standards for new sources.

Reductions in methane emissions of 100% would be expected from this technology.

! Require Low-Bleed Pneumatic Devices fo r New Installations and Require Modified Sources to Retrofit High-Bleed D evices with Low-Bleed Devices

, PA should require that any new pneumatic de vices that must be gas-powered be lowbleed or that modified devices be replaced or retrofitted to meet low-bleed criteria.

B. Compressors

Fugitive methane emissions from compressors ( e.g. , from compressor seals) are a significant

source of methane emissions from the natural gas processing sector. Compressors are also integral in the transmission of natural gas from field production and proces sing to the distribution sector. Compressor station facilities are used to transport gas th rough the network of transmission lines throughout the United States. Fugitive methane emissions from these compressor stations account for a significant po rtion of all emissions from the transmission sector. Compressors housed at storage facilities are also a large source of fugitive methane emissions. At these facilities, natural gas is stored during periods of low demand ( e.g. , in summer), and subsequently processed and di stributed during periods of high demand ( e.g. , in winter).

According to U.S. Greenhouse Gas Inventory da ta, compressor fugitive emissions, venting and engine exhaust account for about 12 Bcf—or about 10 percent—of methane emissions from the production sector. Reciprocating compressors a ccount for another 16 Bcf and 41 Bcf—or about 50 percent and 40 percent—of methane emissions from the processing and transmission sectors, respectively. All told, methane emissions from compressors reportedly account for at least one fifth of all methane emissions from oil and gas systems.

These estimates, however, may underestimate actual emissions. According to EPA’s recent rulemakings for the Mandatory Reporting of Greenhouse Gases program, several emissions sources are believed to be “significantly underestimated” in the U.S. GHG Inventory (EPA/GRI/Radian, 1996). 35,36 Specifically, EPA identifies the following sources of underreported emissions: (1) well venting for liquids unloading; (2) gas well venting during well completions; (3) gas well venting during well wo rkovers; (4) crude oil and condensate storage tanks; (5) centrifugal compressor wet seal degassing venting ; and (6) flaring. According to EPA,

the emissions estimates for these sources “do not correctly reflect the operational practices of!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 35 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry . Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

36 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.*" today” and, in fact, EPA believes “that emissions from some sources may be much higher than currently reported in the U.S. GHG Inventory.” 37 EPA includes revised em ission factors for four of these underestimated sources, including the add ition of a factor for centrifugal compressor wet seal degassing venting of 233 metric tons per y ear, or 12 million cubic feet per year (MMcf/yr). 38
Overall, the revisions to just th ese four sources results in a more than 100% increase in estimated emissions from the oil and gas production sector and a 67% increase in es timated emissions from the transmission and storage sector. 39 These enormous underestimates alone are enough of a reason to insist on rigorous performance standa rds and work practices for these particular categories. However, there is even more evidence that the emissions estimates for these and other

sources remain uncertain and contin ue to be greatly underestimated.

Preliminary findings from an EP A-funded project at the Univer sity of Texas indicate that fugitive methane emissions from compressor engine s can be substantially higher than expected from the currently accepted emission factors. 40 Specifically, current emission factor estimates do not distinguish compressor seal emissions by comp ressor type (reciprocati ng or centrifugal) and do not distinguish between emissions from the s eal face and emissions from seal oil degassing. 41

It is worth noting that direct measurement of emissions from both recipr ocating and centrifugal compressors is possible as a means to accurate ly demonstrate compliance with performance standards established by EPA. EPA proposed di rect measurement methods for determining reported emissions under the Manda tory Reporting Rule (MRR). 42

1. Existing State and International Pr ograms to Reduce Methane Emissions from Compressors

The following state and international programs dem onstrate that mandatory controls for reducing methane emissions are possible. EPA should cons ider these standards as minimum requirements for regulating sources under the NSPS. Regula tions aimed at reducing VOCs and HAPs are

relevant to consider because of the corresponding reductions in methane emissions that are achievable through implementation of these control technologies and practices.

California

The state of California proposed greenhouse ga s rules (described in the Introduction and Summary Recommendations secti on above) that include control measures for compressors to improve operating practices and therefore reduce emissions when compressors are taken off-line!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 37 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

38 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 8, Table 1.

39 Id. at 9.

40 University of Texas (Cooperative Agreement number XA-83376101-0).

41 Quality Assurance Project Plan, Greenhouse Ga s (GHG) Emission Factor Development Project Cooperative Agreement number XA-83376101-0, January 30, 2008, Dr. David T. Allen (Principal Investigator) and Cyril Durrenberger (Project Quality A ssurance Officer) Center for Energy and Environmental Resources University of Texas J.J. Pickle Research Campus 10100 Burnet Road, Mail Code R7100 Austin, Texas 78758, p.8.

42 75 FR 18608, April 12, 2010.*# and install compressor rod packing systems. This would apply to compressors in both the oil and natural gas extraction an d transmission sectors. 43

Cherkasytransgas

Cherkasytransgas, a Ukrainian natural gas tran smission company with a capacity to transmit 120

billion cubic meters of natura l gas annually, implemented a directed inspection and maintenance program at its compressor stations in 2002. Since then the company has achieved huge

reductions in methane emissions from these sources through monitoring, leak repair, and equipment and valve sealant upgrades. In 2002, th e company identified and repaired leaks, reducing methane emissions by 1.9 million cubic meters per year. In 2006, the company again conducted repairs and installed high efficiency equipment, reducing emissions by 5.9 million cubic meters annually. During the last round of repairs in 2008-2009, the company upgraded the

sealant on 174 valves at transmi ssion stations, distribution stat ions and linear pipes. These improvements reduced annual methane emissions by 3.5 million cubic meters. 44

2. Available Proven Technologies for Compressors

EPA’s own Natural Gas STAR program provide s evidence that there are many available, technically feasible, and cost-eff ective technologies that can greatly reduce methane emissions from gas compression activities. These options include both: (1) technology standards for compressor equipment; and (2) improving ope rating practices to reduce emissions ( e.g. , when compressors are taken off-line). EPA should, at a minimum, require the following technologies and operating practices as part of its revi sed NSPS for oil and natural gas systems.

Require the Use of Stat e-of-the-Art Compressor Rod-Packing Technology

EPA should require the use of state-of-the-art rod-packing technology and identify a replacement threshold for replacing packing rings and piston rods as a practical method to reduce methane emissions from reciprocating compressors. Both the BLM and CARB already list compressor rod-packing technology as a BM P for oil and gas sources. 45

Leakage can be reduced through a requirement to develop a proper monitoring plan and a costeffective schedule for replacing packing rings and piston rods. Monitoring and replacing compressor rod packing systems on a regular basi s can greatly reduce methane emissions from compressors. According to EPA Natural Gas STAR partner reports, as pack ing deteriorates, leak rates can increase to the level at which repl acing packing rings more frequently can be!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 43 “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework for change,” California Air Resources Bo ard, December 2008, C-153 and C-154, http://www.arb.ca.gov/cc/scopingplan/doc ument/appendices_volume1.pdf#page=184.

44 Methane to Markets, Oil & Gas Methane Reduction Proj ect Opportunity, “Directed Inspection and Maintenance and Valve Sealant Updgrades,” Cherka sytransgas, Cherkassy, Ukraine, http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1152.

45 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.*$ economically justified. 46 In addition, more frequent ring re placement might actually extend the life of the compressor rod. EPA should require operators to establish baseline leakage rates and monitor changes in leakage ra tes to establish an emissi on threshold and corresponding replacement frequency similar to EPA’s “economi c replacement threshold” analysis promoted through its Natural Gas STAR program. 47

For example, conventional bronze-metallic packi ng rings require replacement about every “three to five years,” 48 but a more precise monitoring program will allow individual applications to optimize replacement so as to extend the life of the equipment and reduce increasing emissions. Requiring an aggressive monitoring and replaceme nt schedule is an essential component of a comprehensive performance standard for this s ource. In addition to monitoring leakage rates, operators should be required to regularly monitor appropriate lubr ication and cooling parameters to help minimize wear on packing rings.

The most advanced ring materials and desi gns for packing cases should guide EPA’s performance standard for this so urce. New packing ring materials ( e.g. , high-performance nonmetallics and polymers), types, and entirely ne w packing systems are available and becoming

more common. There are many examples of companies that provide new low emission packing rings and packing case assemblies. 49 EPA should consider all available emission-lowering rod packing technologies when setting the performance standard for this source.

EPA reports there are 51,000 reci procating compressors operating in the U.S. natural gas industry (2006), accounting for about 72.4 Bcf/yr of methane gas emissions. 50 EPA further reports that new rod packing sy stems, properly installed and operated, lose approximately 12 scfh compared with emissions that range from te ns of scfh to hundreds of scfh for aged systems (EPA uses an example of 900 scfh). 51 If, as reported by EPA, economic replacement of rods and rings for applications demanding a payback of less than one year would mean replacing equipment when leak rates reach a level of 376 scfh, then these sy stems would see a 97%

reduction in emissions. 52 New state-of-the-art rod packing technology required to emit no more than 12 scfh at installation would still represen t a 90% reduction in methane emissions compared!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 46 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Compressor Rod Packing Systems”, October 2006, http://www.epa. gov/gasstar/documen ts/ll_rodpack.pdf.

47 Id.

48 Id at 3.

49 Specific examples include: (1) Compressor Engineering Corp (CECO) Low Emission Packing (LEPTM), see http://www.tryceco.com/ceco-parts-and-re pair/rings-rider-b and-rod-packing/lep-low-em ission-packing.htm; (2) Cook Compression’s “COOK CLEAN emission-control so lutions,” “Seal Assist SystemTM, the ultimate in emissions control,” and “ [v]ented and buffered cases specially desi gned for your application to reduce fugitive emissions,” see http://www.cookcompression .com/index.cfm/lev2/813/Packing.Cases ; (3) Hoerbiger’s “BCD balanced cap design” which the company promotes as a “n ew low emission packing ri ng that operates at low temperatures and maintains the seal even during compressor shutdown,” see company materials at http://www.hoerbiger.com/Packing-rings.14186.0.html?&L =33; (4) Aavolyn Corporation’s ring and packing assemblies made of various materials (bronze, cast iron and Teflon blends) that “keep gas from leaking from the cylinder to the atmosphere” and “prevent leakage of gas along the rod when the compressor is shut down under the load” and include “Green Compressor Packing” t echnology, see http://www.a avolyn.com/cg020001.htm.

50 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Compressor Rod Packing Systems”, October 2006, http://www.epa. gov/gasstar/documen ts/ll_rodpack.pdf.

51 Id.

52 Id at 8.*% to systems operating with leak rates of only 120 scfh.

To achieve a 90% reduction in emissions from this source, EPA should require new technology standards and operating practices th at prescribe initial leakage rates no greater than 12 scfh and replacement of compressor rod packing when leakage rates exceed 120 scfh, 53 or when indicated by an established source-specific replacement threshold that maximizes methane reductions while also considering cost-effectiveness.

Require the Use of Dry Seal s in Centrifugal Compressors

Centrifugal compressors are common in the prod uction and transmission sectors of natural gas systems. Replacing wet seals (oil seals) used on the rotating shafts of the compressors with dry seals can significantly reduce methane emissions from this source. In fact, installing two or more dry seals together, in series, is even more effective in reducing emissions. According to EPA, these types of “tandem dry seals” re sult in less than 1% of the leakage of a wet seal system that is vented to the atmosphere and “cost considerably less to operate.” 54

The use of dry seals is proven and has b een recently documented by the Global Methane

Initiative. 55 Specifically, methane emissions were show n to be 99.99% lower with the use of dry seals in an applicati on in Mexico in 2010. 56 In 2006, EPA reported that 90% of all new compressors are already equipped with dry gas seal systems. In addition, both the BLM and CARB list the use of dry seals as a BMP for oil and gas sources. 57

This technology is also an eff ective means of reducing methane emissions at offshore oil and gas operations. A recent paper on offshore platform me thane reduction strategies analyzed offshore oil and gas methane emissions and control strate gies, and devised an emission reduction strategy for the most significant sources at the lowest cost. The replacement of centrifugal compressor wet seals with dry seals is one of the recommen ded strategies for reducing methane emissions in offshore applications. 58

The world’s largest natural gas company, Gazpro m (with operations in Russia), has committed to replacing wet seals and dry seals at centrifuga l compressors (which to tal more than 4,000). Between 2006 and 2008, the company converted seal s at 59 compressor stations and 250 gas!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 53 120 scfm leak reduction rate would require roughly 2 years payback assuming a ga s cost of $7/Mcf, a 10% interest rate and 8,000 hours of operation.

54 Lessons Learned, Natural Gas STAR Partners, “Rep lacing Wet Seals With Dry Seals in Centrifugal Compressors”, October 2006, http://www.epa.gov/gasstar/documents/ll_wetseals.pdf.

55 See , e.g., April 2010 (http://www.epa.gov/gasstar/documents/workshops/ashgabat2010/0427_1135_compressors.pdf ), March 2010 (http://www.methanetomarkets.org/expo/docs/postexp o/oil_betancourt_2.pdf) and September 2009 (http://www.methanetomarkets.org/documents/events_o ilgas_20090914_robinson3.pdf) Methane to Markets presentations.

56 Petróleos Mexicanos (Pemex) demonstrated a reduction in emission rate from 43.11 scfm to 0.02 scfm with seal replacement, see http://www.methanetomarkets.org/expo/docs/postexpo/oil_betancourt_2.pdf.

57 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

58 Bylin, Carey et al. for Society of Petroleum Engineer s, “Designing the Ideal Of fshore Platform Methane Mitigation Strategy,” 2010, p. 1.*( pumping aggregate superchargers located at extr action facilities, gas tr ansport facilities and underground storage facilities. 59

Since dry seal conversions may not be technica lly feasible for all compressors due to housing design and/or operational requirements, EPA shoul d also investigate seal oil degassing vent recovery technology as an alternative performa nce technology requirement, where dry seal installations are not possible. 60

EPA should require the installation of tandem dr y seals on all new compressors, or seal oil degassing vent recovery devices in cases wher e dry seals are not tech nically feasible. If, according to EPA, methane emissions typically range from 40 to 200 scfm for wet seals and from 0.5 to 3 scfm for dry seals, then EPA should require methane emissions from new units to emit no more than 3 scfm from the dry seal s (representing at le ast a 92.5% reduction in emissions from this source). With demonstrated installations reporting emission reductions over 99% and rates as low as 0.02 scfm (approximately 10 Mcf/yr at 8,000 hours of operation), this

should be an achievable standard. Based on EPA’s recent estimate of 12 MMcf/yr from centrifugal compressor wet seal degassing venti ng, reductions of over 90% from this source would drop this emission factor estimate for ne w units to just over 1 MMcf/yr (or just under 3 scfm for a unit that operates 8,000 hours). 61

In addition to reducing methane emissions, repl acing wet seals with dry seals significantly reduces operating costs and increases compressor efficiency. Specifically, EPA reports that dry seals: (1) are safer to operate because there is no need to operate a high-pressure oil system; (2) are mechanically simpler; (3) consume less en ergy (90–95% less); (4) resu lt in less compressor downtime; (5) have lower maintena nce costs and last twice as long as wet seals; and (6) their use does not result in contamination of the gas str eam and degradation of the pipeline from oil

usage. 62

Require the Use of Air or Electri c Starters Instead of Gas Starters

Gas starters use natural gas to power the starte r motor and then vent the discharge gas to the atmosphere. Compressor starters that use compresse d air or electricity instead of natural gas to power the starter motor are not so urces of methane emissions. Requiri ng the use of air or electric starters instead of gas starters for all natural gas pneumatic starter motors will ensure reduced methane emissions, as well as reduced VOC and HAP emissions, from this source. A standard air starter would require a stati onary or mobile air compressor (w ith an electrical power source). Operation costs would include the cost of the electrical power needed to compress the air. Replacing starter expansion turbines with an electric motor starte r, similar to an automobile!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 59 Oil & Gas Methane Reduction Project Opportunity , Compressor Seal Conver sions, OAO Gazprom, (http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1151) and Gazprom Activities on Methane Emissions Reduction, G.S. Akopova, Laboratory of Environmental Protection and Resource Saving, Moscow 2010, at 13, (http://www.methanetomarkets.org/expo/docs/postexpo/oil_apokova.pdf).

60 See slides 11-12 from Methane to Markets April 2010 presentation (http://www.epa.gov/gasstar/documents/workshop s/ashgabat-2010/0427_1135_compressors.pdf).

61 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 8, Table 1.

62 Lessons Learned, Natural Gas STAR Partners, “Rep lacing Wet Seals With Dry Seals in Centrifugal Compressors”, October 2006, http://www.epa.gov/gasstar/documents/ll_wetseals.pdf.*) engine starter, may include a conne ction to utility electrical power, site generated power, or solar recharged batteries. Use of air and electric starters completely eliminates the venting of methane to the atmosphere and the leak age of methane through the gas shutoff valve. EPA has reported this technology as a cost-effec tive control technique in it s Natural Gas STAR program. 63

EPA has reported a 1,524 thousand cubic feet (M cf) per year average leakage rate from compressor starter lines. 64 An average methane emission factor for compressor engines used in gas processing is about 4 million cubic feet (MMcf) per year for reciprocating engines and about 8 MMcf per year for centrifugal engines. 65 Requiring air or electric starters on all applicable engines would reduce methane emissions by ro ughly 40% in new r eciprocating engine applications and 20% in new centr ifugal engine applications. CARB already lists the use of air or electric starters as a BMP for oil and gas sources. 66

Require the Use of State-of-t he-Art Compressor Cylinder Un loader Technology and Require Regular Replacement

Compressor cylinder unloaders employed in the tr ansmission sector are used to control gas volumes ( e.g. , for capacity control, to prevent an overloa d when there is an upset in the system, or to reduce the load during engi ne start-up, etc.). Unloaders ca n be a significant source of fugitive methane emissions ( e.g. , from leaking o-rings, covers a nd pressure packing) and have been identified as one of the top causes of uns cheduled shutdowns for reciprocating compressor engines. 67

EPA should thoroughly investigate the state-of-the-art technology for unloaders and require the

use of the best available technol ogies to reduce vented emissions from this source. Examples of such technologies are the use of multiple innovative sealing elements (including elastomeric sealing elements) to reduce emissions and the use of port/p lug-type designs to avoid operational problems inherent in fing er-type unloader designs. 68

In order to reduce the amount of unscheduled shutdowns and fre quent maintenance required for aging unloader systems (and the associated fugiti ve emissions that resu lt from these episodes), EPA should specify a conservative replacement period that will ensure optimal equipment performance over the life of the unloader system and parts. One possible method would be to establish an acceptable emission threshold a nd specify a corresponding replacement frequency

based on that threshold.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 63 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheet Nos. 103 and 108, http://www.epa.gov/gasstar/documents/replacegas.pdf and http://www.epa.gov/gasstar/documen ts/installelectricstarters.pdf.

64 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 8, GRI-94 /0257.23, EPA 600/R-96- 080h, June 1996, p. 58.

65 Id. at 48.

66 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

67 “Compressor Valves and Unloaders for Reciprocating Compressors - An OEM's Perspective”, S. Foreman Dresser-Rand, Painted Post, NY, USA, available at http://www.dresser-rand .com/techpapers/tp015.pdf.

68 See EPA Gas STAR Program Partner Reported O pportunities (PRO), PRO Fact Sheet No. 110, http://www.epa.gov/gasstar/doc uments/replacecylinder.pdf.*& Potential methane emission reductions from us ing the best available compressor cylinder unloader technology are not easily quantified and depend, among other things, on compressor

maintenance activities. Howeve r, it is important to include technology requirements and replacement schedules for this source since th e potential for fugitive methane emissions is significant. Fugitive methane emissions from faulty unloaders have been reported to be as high as 3.5 MMcf per compressor engine, 69 which represents a huge fraction of average annual emission rates for compressors at transmissi on sites (roughly 5.5 MMcf/yr and 11 MMcf/yr for an average reciprocating and centrifugal compressor, respectively). 70

CARB already lists the use of cylinder unloaders and their regular replacement as a BMP for oil and gas sources. 71

Require Operating Practices That Eliminate or Reroute Gas Leakage When Taking Compressors Off-line

When taking compressors offline for operational reasons, EPA should require operators to keep compressors pressurized and to connect the blowdow n vent lines to the fuel gas system in order to allow the gas that is normally vented to be used as fuel while the compressor is off-line. In situations where routing gas to the fuel gas system is not possible EPA should require the

installation of a static seal on the compressor rods to eliminate rod-packing leaks that occur during the shutdown process. Keeping compressors fully pressurized avoids significant fugitive

emissions from leaks across the unit valves.

For situations where compressors cannot remain pressurized when they are taken offline for maintenance and for system shutdowns, EPA s hould require collection and re-routing of any vented gas. Not allowing venting to the atmosphere of the high-pressure ga s that is left in the compressor when it is taken offline ( i.e. , blowdowns) will require capturing the gas and rerouting it for other use ( e.g. , to the sales line). The design of blowdown systems and emergency shutdown system practices to capture gas shoul d be required in accordance with acceptable industry safety standards ( e.g. , OSHA, API, ANSI, ASME, etc.). Rerouting highly-combustible gases has the added benefit of reduci ng safety risks in the work area.

EPA has reported huge savings by Natural Gas ST AR partners when maintaining pressurized systems during shutdowns. Keeping the system pressurized can reportedly, alone, avoid over 4 MMcf/yr of methane emissions per compressor. 72 When also requiring the rerouting of gas to the fuel system, methane emissions savings can be as high as 5.3 MMcf/yr per unit. 73 EPA-reported average emission rates for compressor blowdown va lves are an order of magnitude higher in depressurized systems than in pressurized systems (1.4 MMcf/yr for pressurized systems!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 69 Id.

70 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 8, GRI-94 /0257.23, EPA 600/R-96- 080h, June 1996, p. 52.

71 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

72 Lessons Learned, Natural Gas STAR Partners, “Reducing Emissions When Taking Compressors Off-Line”, October 2006, p. 1, http://www.epa.gov/g asstar/documents/ll_compressorsoffline.pdf.

73 Id.*' compared with over 14 MMcf/yr for depressurized systems). 74 Again, these emission rate estimates represent a substantial portion of the overall methane emission rates from compressors (roughly 5.5 MMcf/yr and 11 MMcf/yr for an averag e reciprocating and ce ntrifugal compressor, respectively). 75

Significant emissions reductions and cost saving will result from avoiding routine compressor blowdown and eliminating or rerouting leakage. EPA must require operating practices to ensure the best system of emissions reductions is established.

Require Direct Inspection and Maintenance at Compressor Stations

Direct Inspection and Maintenan ce (DI&M) is “a proven management practice for cost-effective reduction of methane emissions” that can significantly reduce fugitive methane emissions from the gas processing sector. 76 A DI&M is not the same thing as EPA’s regulatory leak detection and repair (LDAR) program for reducing VOC emissions. 77 A successful DI&M program includes a baseline survey, cost-effective repa irs and subsequent targeted surveys based on findings from the initial baseline survey. In general, the cost of the baseline survey is reportedly recovered in gas savings during the first year. 78 The costs of subsequent surveys are minimized by focusing the components that were identified through the initial baseline study as having a high potential for leakage. A variety of screening and measurement devices ( e.g. , infrared gas imaging, optical remote leak dete ction, etc.) can be used to obta in accurate leak data and high volume gas samplers can be used to identify and quantify leaks. 79 According to EPA Natural Gas STAR partners, a DI&M program should “target the five categories of equipment components that contribute to the majority of methane lo sses: block valves, cont rol valves, connectors, compressor seals, and open-ended lines.” 80 Additionally, a DI&M program should include regular inspection of blowdown valves at compre ssor stations, which can be significant methane emissions sources due to substantial pre ssure, thermal and mechanical stresses. 81!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 74 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 8, GRI-94 /0257.23, EPA 600/R-96- 080h, June 1996, p. 56. NOTE : the depressurized emission rates do not include the vented emissions from depressuring the compressor.

75 Id. at 52.

76 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf

77 See , NSPS Subpart KKK - Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing Plants.

78 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf

79 See, e.g. , Directed Inspection and Maintenance (DI&M) at Gas Processing Plants, Innovative Technologies for the Oil & Gas Industry: Product Capture, Proce ss Optimization, and Pollution Prevention, Targa Resources and the Gas Processors Association, July 27, 2006 Hobbs, NM, http://www.epa.gov/gasstar/documents/dim.pdf.

80 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations,” October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf

. 81 See EPA Natural Gas STAR Program Partner Reported Opportu nities (PRO), PRO Fact Sheet No. 601, “Inspect and Repair Compressor Station Blowdown Valves,” http://www.epa.gov/gasstar/documents/inspectandr epaircompressorstationblowdownvalves.pdf."+ A pilot study conducted by EPA and the Gas Technology Institute demonstrated a DI&M program at gas processing facilities that reduced methane emissions by up to 96%. 82 EPA should require all gas processing facilities to esta blish and implement a DI&M program to reduce fugitive methane emissions. Potential methane reductions from implementing a DI&M program will vary depending upon the operating characteristic s of the facility but EPA should prescribe a program that represents the best available practices for DI&M.

Require Isolation Valves To Be Installed in Close Proximity to Compressors For All New

Installations

When individual compressors are taken off-line, valves are used to isolate the unit and the natural gas between these valves is vented to th e atmosphere. Similarly, when real or simulated emergencies occur at compressor stations, fire gate valves are activated to stop the flow of gas into the station. Through improved compressor facil ity design, the volume of methane gas that is vented when sections of isolated equipment are bl own out or when fire gate valves are activated

can be minimized. 83 EPA should require all new compressor st ations to locate isolation valves and fire gate valves in close proximity to comp ressors in order to minimize the lengths of gasfilled piping to be vented to the atmosphere.

3. Summary Recommendations for Compressors

EPA should implement the following technology st andards and operating practices for all new compressor engines:

! Require the Use of Stat e-of-the-Art Compressor Rod-Packing Technology EPA should prescribe initial leakage rates no greater than 12 scfh and replacement of compressor rod packing when leakage rates exceed 120 scfh, or when indicated by an established source-specific replacement threshold that maximizes methane

reductions while also consid ering cost-effectiveness.

! Require the Use of Dry Seal s in Centrifugal Compressors EPA should require the installation of tandem dry seals on all new compressors, or seal oil degassing vent recovery devices in cases where dry seals are not technically feasible.

! Require the Use of Air or Electri c Starters Instead of Gas Starters EPA should require the use of air or electric starters instead of gas starters for all natural gas pneumatic starter motors.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 82 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.

83 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheets No. 606 and 608, “Design Isolation Valves to Minimize Gas Blowdown volumes” and “Move Fire Gates In to Reduce Venting at Compressor Stations,” http://www.epa.gov/gasstar/documents/designisola tionvalvestominimizegasblowdownvolumes.pdf and http://www.epa.gov/gasstar/docum ents/movefiregatesin.pdf."* ! Require the Use of State- of-the-Art Compressor Cyli nder Unloader Technology and Require Regular Replacement EPA should require the use of the best availa ble unloader technologi es to reduce vented

emissions from this source. EPA should also specify a conservativ e replacement period that will ensure optimal equipment performance and minimize methane emissions over the life of the unloader system and parts.

! Require Operating Practices That Elimi nate or Reroute Gas Leakage When Taking Compressors Off-line EPA should require operators to keep comp ressors pressurized and to connect the blowdown vent lines to the fuel gas system in order to allow the gas that is normally vented to be used as fuel while the compresso r is off-line. In situations where routing gas to the fuel gas system is not possible, EPA s hould require the installa tion of a static seal on the compressor rods to eliminate rod-p acking leaks that occur during the shutdown process. For situations where compressors ca nnot remain pressurized when they are taken offline for maintenance and for system shut downs, EPA should requir e collection and rerouting of any vented gas.

! Require Direct Inspection and Maintenance at Compressor Stations EPA should require all gas processing fac ilities to establish and implement a DI&M program to reduce fugitive methane emissions . EPA’s prescribed work practice should represent the best available practices for DI&M.

! Require Isolation Valves To Be Installed in Close Proximity to Compressors For All New

Installations EPA should require all new compressor stati ons to locate isolation valves in close proximity to compressors in order to minimi ze the lengths of gas-filled piping to be vented to the atmosphere.

C. Dehydrators

Saturated water found in produced gas must be removed prior to gas transmission. Glycol dehydrators are the most common technology used to remove water from gas. Glycol dehydrators are sources of methane emissions from the reboiler vent and from pneumatic controllers. The glycol used to absorb water from the gas stream also absorbs a small amount of methane, which is then driven off to the atmosphere (along with water vapor) through the reboiler vent. The majority of glycol dehydrators are used in the production sector, although they are also used during processing, transmission and storage. Meth ane emissions from dehydrator vent stacks are highest in the production sector du e both to the higher number of units and also to the fact that most producti on dehydrators do not operate with flash tank separators.

According to U.S. Greenhouse Gas Inventory da ta, dehydrators and pumps account for about 12 Bcf—or about 10 percent—of meth ane emissions from the producti on sector and an additional 1"" Bcf—or about 3 percent—from the processing sector. 84 These estimates are based on dehydrator population estimates made up of 95% glycol de hydrators and 5% other types of dehydrators. 85

Emission factors for glycol dehydrators are depe ndent on the existence of certain technologies, namely: (1) use of a flash tank; (2) use of stripp ing gas; (3) use of gas-driven pumps; and (4) use of vent controls routed to a burner. According to the EPA/GRI inventory, use of flash tanks can reduce methane emission rates by 98%. 86 The use of stripping gas increases methane emissions. Gas from the absorber outlet (or the flash tank) is sometimes used in the re generator to help strip the water and other absorbed comp ounds out of the glycol; the me thane that is in the stripping gas passes through the regenerator and to the atmospheric vent. These emissions can be significant. 87 According to EPA/GRI emission factors, the use of gas-driven pumps can also greatly increase methane emissions. Spent pumping gas is flashed off in the regenerator and can result in significant methane emissions (equivalent to over five times what is estimated for still vent emissions). 88 The use of combusted vent controls can reduce methane emissions and, in fact, the EPA/GRI inventory assumes no methane emissions from units that employ combustion

vent controls. 89 Although primarily used to control HAP emissions ( e.g. , benzene, toluene, ethylbenzene and xylenes (BTEX)) the methane in the vent can be used as fu el in the regenerator

burner.

EPA proposed the use of engineering measuremen ts as a means to report emissions from dehydrator vent stacks under EPA’s Manda tory Reporting Rule for GHG emissions. 90 EPA’s proposed use of estimates based on the GLYCalcTM simulation software was also supported by

the Western Climate Initiative in its recomm endations to EPA on measuring GHG emissions from the oil and gas industry. These same methods can be employed for compliance demonstration purposes, as appropriate.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 84 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 2007, USEPA, April, 2009, see http://www.epa.gov/gasstar/basic-information/index.html#sources.

85 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 14, GRI-94 /0257.31, EPA 600/R-96- 080n, June 1996, p. 2.

86 The reported emission factor for a dehydrator with a flash tank is 3.57 scf of methane per MMscf throughput compared to the emission factor for a dehydrator without a flash tank, which is 175.10 scf of methane per MMscf throughput. The emission factor for a dehydrator with a flash tank is 98% less than that without a flash tank (175.10 – 3.57 / 175.10 = 0.98). Id at Appendix A.

87 EPA ORD, “Methane Emissions from The Natural Gas Industry,” Volume 14, GRI-94 /0257.31, EPA 600/R-96- 080n, June 1996. This report estimates an incremental methane emission rate for dehydrators with stripping gas of 670 scf of methane per MMscf throughput. Compared with total emission rates from dehydrators without flash tanks of 175 scf of methane per MMscf throughput, these additional methane emissions from the use of stripping gas can be quite significant (over 3 times that from dehydrator reboiler vent emissions from units without flash tanks).

88 EPA ORD, “Methane Emissions from The Natural Gas Industry,” Volume 15, GRI-94 /0257.33, EPA 600/R-96- 080o, June 1996, p. 14. This report estimates an emission factor for gas-assisted glycol pumps at production sites of 992 scf of methane per MMscf throughput, which is over 5 times higher than the emission factor for dehydrators without flash tanks of 175 scf of methane per MMscf throughput (found in Volume 14).

89 EPA ORD, “Methane Emissions from The Natural Gas Industry,” Volume 14, GRI-94 /0257.31, EPA 600/R-96- 080n, June 1996, Appendix A.

90 75 FR 18608, April 12, 2010. Note, EPA proposed engineering estimates as the means for demonstrating compliance for conventional well completions and conventional well workovers."# 1. Existing Federal, State and County Programs to Reduce Methane Emissions from Dehydrators

The following federal, state and county program s demonstrate that mandatory controls for reducing methane emissions are possible. EPA should consider these standards as minimum requirements for regulating sources under the NS PS. Regulations aimed at reducing VOCs and

HAPs are relevant to consider because of the corresponding reductio ns in methane emissions that are achievable through implementation of thes e control technologies and practices.

Federal NESHAP Requirements

EPA’s National Emission Standards for Hazardous Air Pollutants (NESHAP) for Oil and Natural Gas Production Facilities (40 CFR 63 Subpart HH) and for Oil and Gas Transmission and Storage Facilities (40 CFR 63 Subpart HHH) require installation of equi pment to either: (1) reduce HAPs from dehydrator vents by 95 percent us ing either closed-vent control systems or by implementing process modifications; or (2) combust HAPs below 20 ppm

v . 91 These NESHAPs are applicable to production facilities with a th roughput floor of 3MMscf/day and to transmission and storage facilities with a throughput floor of 10MMscf/day. These NESHAP requirements are also triggered if total benzene emissions exceed one ton per year. Many of the same technologies used to meet the NESHAP requirements ( e.g. , installing flash tank separa tors) are also applicable methane control techniques that EPA should consid er as technically feas ible and cost-effective options for methane performance standards. In addition to these federal requirements, some states have implemented certain control requir ements and operating prac tices for reducing VOC and HAP emissions from dehydrators that are disc ussed in more detail below. EPA should also

take into account these state program requirements when considering methane performance standards from the oil and gas sector.

Wyoming

Permitting rules in Wyoming address VOC and HAP emissions from dehydration units with a tiered approach that requires tighter controls in the most concentrated development area (the

Jonah and Pinedale Anticline De velopment area). For this area , 98% control efficiency is required for all dehydration unit process vent s at all new or modified facilities. 92 The statewide and Concentrated Development Area require that al l oil and gas operators must follow one of the two scenarios laid out in guida nce for reducing emissions from dehydration units. Under scenario 1, 98% control efficiency is required for all ne w and modified facilities. Combustion units used can be removed after one year on all units with still vent condensers in stalled that are under 6 tons per year (tpy). Scenario 2 requires that in stallation of glycol flas h separators and reboiler

still vents at all new or modified facilities. If potential uncontrolled VOC emissions are equal to or greater than 8 tpy, 98 % control efficiency must be achieved on all units within 30 days of first date of production or upon the da te of modification. Combustion uni ts used can be removed after one year on all units with flash separators and stil l vent condensers instal led that are under 8 tpy. All non-condensable still vent and glycol flas h separator vapors must be routed to the

combustion unit for 98% control of VOC and HA P emissions or used as fuel for process!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 91 66 FR 34548, June 29, 2001.

92 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, p. 18."$ equipment burners in facilities were a combusti on unit is required. When a combustion unit is not required, glycol flash separator vapors must be collected and used as fuel in process equipment burners. Any excess vapors not used may then be vented to the atmosphere. 93

Colorado

The state of Colorado’s air polluti on regulations include 90% cont rol efficiency requirements for natural gas dehydrators at oil and gas explor ation and production opera tions, natural gas compressor stations, drip stations or gas processing plants statewide. Any single dehydrator or grouping of dehydrators with VOC emissions ex ceeding 15 tpy (on a rolling 12-month basis) must meet this control requirement. For groups of dehydrators that exceed the 15 tpy threshold, all single dehydrators over 2 t py are subject to the 90% cont rol efficiency requirement. 94

In 2008, Colorado’s Air Pollution Control Division proposed a more stringent control strategy for dehydrators. The strategies considered were to increase the required control efficiency from 90% to 98% and to reduce the app licability threshold from the ex isting 15 tpy down to 2 tpy in the ozone nonattainment area and 5 tpy for the re st of the state. The state also considered requiring optimization of lean glycol pump circul ation rates, requiring th e installation of flash tank separators and the control of emissions on new dehydration systems, and requiring the use of portable desiccant dehydrators.

Part of the rationale for increas ing the control effici ency was that, “[m]an y control technologies already in place achieve control effi ciencies of at least 98 percent, such as vapor recovery units, enclosed smokeless combustion devices ( e.g. , thermal vapor incinerators, boilers, or process heaters), and smokeless flares.” 95 However, this more stringent approach was not adopted by the

state since these additional contro ls were not needed to demons trate attainment of the 8-hour ozone standard. In addition, the oil and gas industr y believed that the 90% level of control could be achieved using a condenser rather than having to install a combustion device, which would be necessary if the required control efficiency were 98%. 96

The Colorado Oil and Gas Conservation Commissi on also regulates VOC emissions from natural gas dehydrators in three counties 97 with high volumes of oil and gas production that are outside

of the ozone nonattainment or a ttainment/maintenance areas. Any de hydrator with a potential to emit (pte) VOC of 5 tpy or greater, that is loca ted within 1⁄4 mile of cer tain public facilities or areas, must use control devices that can achieve 90% control efficiency and have an appropriate state permit. 98!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 93 Id, 6-7 & 12-13.

94 Colorado Department !-.!/01234!567289!7:;!,:<3=-:>6: 8?!@3=!A07238B!C-:8=-2!C->>3DD3 -:?!E6F02783-:! G0>16=!)?!HIIJ5!7:;!HKIIJLJ!M6N7= 786!D6483-:D!7=6!3:420;6;!3:!8 96!=026D!.-=!-O-:6!:-:78873:>6:8!7=67D!-=! 78873:>6:8P>73:86:7:46!7=67D!7:;!.-=!D8786!-:2B!=6Q03=6>6:8D!10 8!896!748072!=6Q03=6>6:8D!7=6!3;6:83472J!

95 Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 RAQC Meeting, Colorado Air

Pollution Control Division.

96 Email communication with Christopher Laplante, Oil & Gas Team Permitting Supervisor, Air Pollution Control Division, Colorado Dept. of Public Health and Environment, October 27, 2010.

97 Garfield, Mesa & Rio Blanco Counties.

98 Colorado Code of Regulations, §805 b(2)C, http://www.sos.state.co.us/CCR."% Ventura County, California

In 1994, the Ventura County Air Pollution Control District adopted a rule targeting Reactive Organic Compound (ROC) emissions from glycol re generator vents. Unde r the rule, operators can chose from several options that would all achieve a 95% reduction in ROC emissions from glycol regenerator vents. The first option requires the collecti ng and condensing of all ROC by a condenser/separator system that directs all uncondensed ROC to a va por recovery/disposal system. The vapor disposal system can use any method with a removal ef ficiency of at least 95%. The second option under this rule is the use of a flare or inci nerator that is operated in a specified manner so as to decrease ROC emissi ons and the third option allows for any other control mechanism that would achieve the 95% removal efficiency. 99

2. Available Proven Technologies for Dehydrators

EPA’s own Natural Gas STAR program provide s evidence that there are many available, technically feasible and cost-eff ective technologies that can greatly reduce methane emissions from dehydrators. These options include both: (1) tec hnology standards for dehydrators; and (2) improving operating practices to reduce emissions . EPA should, at a minimum, consider the following technologies and operating practices as cost-effective standards for reducing methane emissions from oil and natural gas systems.

Require the Use of Zero Emission Dehydrators Zero emission dehydrators combine several te chnologies to virtually eliminate methane emissions from the dehydration process by r ecovering methane from the still column, eliminating the need for gas strippers and usi ng electricity to power the circulation pumps. Specifically, non-condensable vapors collected from th e glycol still column are used as fuel for the reboiler, a water exhauster is used in place of a gas stripper and an electric pump is used to circulate the glycol solution. According to EPA, “[c]apital costs of a zero emissions dehydrator are similar to installing a conventiona l dehydrator with a thermal oxidizer.” 100 The Four Corners Air Quality Task Force report of Oil and Gas Mitigation Options i ndicated that the zero emission dehydrator could, in fact, be used as a mandatory technology in areas e xperiencing air quality problems and would achieve large reducti ons in VOC, HAP and methane emissions. 101
According to this same report, “[o]perating a nd [m]aintenance costs ar e greater than $1,000 per year, but lower than the maintenance costs fo r conventional glycol de hydrators” and “EPA estimates the payback to occur in less than a year.” 102 EPA should require the use of zero emission dehydrator technology for all new installations.

EPA’s Environmental Technology Verification (ETV ) program has evaluated the performance of a zero emission dehydrator called the Quan tum Leap Dehydrator (QLD). The QLD, manufactured by Engineered Concepts, LLC, uses a series of heat exchangers, condensers,!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 99 Ventura County Air Pollution Control District, Rule 71.5 Glycol Dehydrators, adopted 12/13/94, http://www.vcapcd.org/Rulebook/Rule4.htm.

100 See EPA Natural Gas STAR Program Partner Reported Op portunities (PRO), PRO Fact Sheet No. 206, “Zero Emissions Dehydrators”, http://www.epa.gov/gasstar/documents/zeroemissionsdehy.pdf.

101 Four Corners Air Quality Task Force Report of Mitigation Options, November 1, 2007, pp. 91-93.

102 Id."( separators and electric pumps to recover still column vapors. In 2003, the ETV program certified certain performance and environmental perfor mance criteria for a QLD unit installed in Brighton, Colorado and did not detect methane c oncentrations during any of the test periods. 103
The HAP destruction efficiency was calcu lated at greater th an 99.74 ± 0.01 percent. 104 EPA’s ETV program was designed to facilitate the use of “innovative or improved environmental technologies through performance verification an d information dissemination.” According to EPA, “[t]he ETV program goal is to furthe r environmental protect ion by accelerating the acceptance and use of improved a nd cost-effective technologies.” 105 EPA should therefore consider the zero emission dehydrator as a tec hnically and economically feasible option for all new dehydrator installations.

Require the Use of Solid Desicc ant Dehydrators in Cases Where Zero Emission Dehydrators Are

Not Feasible

Natural Gas STAR partners have found that solid desiccant dehydrat ors (using adsorption) reduce methane, VOC, and HAP emissions by 99 pe rcent compared with gl ycol dehydrators and also have lower operating and maintenance costs. 106 Solid desiccant dehydrator technology uses a drying bed of desiccant tablets to remove wa ter from the produced gas stream. The tablets extract moisture from the gas as it passes through the bed of tablets. A solid desiccant dehydrator operates as a fully enclosed system with esse ntially no emissions. A small amount of emissions occur when the vessel is opened fo r maintenance or other reasons ( e.g. , desiccant tablets that dissolve over time need to be replaced periodica lly). Solid desiccant dehydrators are very simple devices with no moving parts and no external power supply needs. They are appropriate for use in a wide variety of applicati ons, including for use at remote s ites and for portable applications.

The amount of moisture that can be removed from the produced gas stream by a solid desiccant dehydrator is dependent on the type of desiccant used, as well as the temperature and pressure of the gas stream. EPA should consider the latest available desiccant technology when determining the applicability of th is technology to all types of new in stallations. For example, calcium

chloride is the most common and the least e xpensive desiccant but has more limited operating ranges than other desiccants. A ccording to EPA Natural Gas STAR Partners, “calcium chloride can achieve pipeline-quality moisture contents at temperatures below 59 o F and pressures above 250 psig.” 107 Lithium chloride is a more expensive desiccant but has a much wider operating range ( i.e. , up to 70 o F and above 100 psig). Some desiccants (aside from calcium chloride) can be re-generated and re-used. A cursory review of currently-availabl e desiccant dehydrator technology shows that there are se veral companies offering units th at can effectively operate at high temperatures ( e.g. , as high as 200 o F) and at high pressure ( e.g. , max allowable working!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 103 ETV Joint Verification Statement, Quantum Leap Dehydrator, pp. S-4 and S-5, available online at http://www.epa.gov/etv/pubs/03_vs_quantum.pdf. The minimum detection limit was 0.1 ppmvd so methane concentrations were < 0.1 ppmvd (or < 0.00004 lb/hr).

104 Id at S-5.

105 Id.

106 Lessons Learned, Natural Gas STAR Partners, “Repl acing Glycol Dehydrators w ith Desiccant Dehydrators”, October 2006, http://www.epa.gov/gasstar/documents/ll_desde.pdf.

107 Id.") pressures as high as 2220 psig) and are market ed for “environmentally sensitive applications.” 108
Silica gel type desiccants can be designed to al so extract marketable liquid hydrocarbons from the dehydration process. 109 These examples are evidence that EPA must seriously consider solid desiccants as a technically feasib le standard for dehydration units.

While replacement cost of the desiccant is slig htly higher than the glyc ol used in a glycol dehydration system (because the desiccants themse lves need regular replacement whereas the glycol is re-circulated), this is the only O&M co st for these systems. In a recent Global Methane Initiative presentation, comparison of costs for in stallation of a solid desi ccant dehydrator versus a glycol dehydrator showed slightly higher costs for installation, operation and maintenance of a glycol system than for a solid desiccant system. 110 EPA lists desiccant dehydrators as a costeffective technology with a payback of 1-3 years. 111 This is evidence that EPA should consider this technology to be a cost-effective option fo r dehydration. CARB already lists the use of desiccant dehydrators as a BM P for oil and gas sources. 112

EPA should require all new dehydrators to firs t use zero emission dehydrator technology and use solid desiccant technology in a pplications where zero dehydrator technology is not feasible. If, after thorough consideration of existing state-of-the art techno logy, EPA determines that zero emission dehydration and solid desiccant dehydrati on are not universally applicable, then EPA should require it where possibl e and also require specific t echnology standards and operating practices for glycol dehydration units where zer o dehydration and solid de siccant dehydration are not technically feasible.

Require Glycol Dehydrators to Use Vapor Recovery Units

Requiring that flash tank separators and other ve nts be piped to a vapor recovery unit (VRU) will

result in less methane emissions vented from the reboiler. The VRU can then increase the recovered gas pressure enough to inject it into a fuel gas sy stem or gathering/sales line. According to a recent proposal by the Colorado Air Pollution Control Division to increase control device efficiencies on dehydrator units from 90% to 98%, “many vapor recovery units and combustion devices already have contro l efficiencies of at least 98 percent.” 113 EPA should!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 108 See , e.g., Emerson Process Management’s Bettis Molecular Sieve Desiccant Dehydrator For Natural Gas with a regenerable desiccant bed and opera ting temperature range from -80 o F to 200 o F, http://www2.emersonpro cess.com/siteadmincenter/PM%20Valve%20Automation%20Documents/Bettis/Brochure/ MolecularSieve.pdf; see also Cameron’s Natco Desi-Dri Desiccant Deh ydration, “emissions-free” natural gas dehydration system that uses propriet ary desiccants and is “environmentally safe and reduces capital costs, as well as operating and compliance costs,” http://www.c-a-m .com/Forms/Product.aspx?prodID=fdee24ed-c860-40bb947a-fb917fcafe92.

109 http://www.kwintl.com/glycol-dehydrators.html.

110 Methane to Markets slide presentation, “Production/Pr ocessing Best Practices: Na tural Gas Dehydrator and Pneumatic Controller Optimization for Methane Emissi on Reductions”, Oil & Gas Subcommittee, Technology Transfer Workshop, January 28, 2009 Monterrey, Mexico, slide 24, http://methanetomarkets.org/documents/events_oilgas_20090127_techtrans_day2_plauchu1_en.pdf.

111 http://www.epa.gov/gasstar/tools/recommended.html.

112 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

113 Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 Regional Air Quality Council Meeting, “APCD OZ ISSUE PAPER oil and gas all strategies .doc,” Prepared by the Co lorado Air Pollution Control Division, Contact: Rose Waldman, available at"& require the use of vapor recovery units with c ontrol efficiencies of at least 98%, or other technology or operational practice that would achi eve a similar or greater reduction in methane emissions. CARB already lists the use of use of va por recovery units at glycol dehydrators as a BMP for oil and gas sources. 114

This technology is also an eff ective means of reducing methane emissions at offshore oil and gas operations. In a paper on offshore platform meth ane reduction strategies, the authors analyzed offshore oil and gas methane emissions and contro l strategies to devise an emission reduction strategy for the most significant sources at the lo west cost. The use of vapor recovery units at dehydrators is one of the recommended strategi es for reducing methane emissions in offshore applications. 115

Jatco Incorporated’s Ja tco Vapor Recovery Unit (JVR) is an example of an available technology designed to recover vapors with use of a Venturi valve. Accord ing to manufacturer information, the JVR unit can be used in remote field appl ication with no electrica l power requirement and has wide-ranging applications including glycol dehydrators a nd storage tank vapors. 116 This technology has been successfully applied by an EPA Natural Gas STAR partner in the DenverJulesburg Basin in Colorado to reduce methane, VOC and BTEX emissions. 117

Additional benefits of VRUs include the economic benefit of the recovered salable gas as well as

reductions in vented VOC and HAP emissions from the reboiler.

Require the Use of Flash Tank Separators For Glycol Dehydrators

Requiring the use of flash tank se parators on glycol dehydrators is a cost-effective way to reduce methane emissions. Recovered gas can be recycl ed and used as a fuel for the reboiler or compressor engine. EPA Natural Gas STAR economic analyses show flash tank separators installed on dehydration units can payb ack costs in less than one year. 118 Operation of a flash tank can capture approximately 90% of methane entrained by the glycol. 119 EPA should require the use of flash tank separators on all glycol dehydration units. CARB al ready lists the use of flash tank separators for glycol dehydr ators as a BMP for oil and gas sources. 120

In addition to reduced methane emissions, use of flash tank separators will result in VOC and HAP emissions reductions, as well. The flash tank separator can capture approximately 10%-!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! http://www.cdphe.state.co.us/ap/ozone/R egDevelop/IssuePapers/February22- 08/APCDOZISSUEPAPEROGdehydrators_000.pdf.

114 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

115 Bylin, Carey et al. for Society of Petroleum Engineer s, “Designing the Ideal Of fshore Platform Methane Mitigation Strategy,” 2010, p. 1.

116 Jatco Inc, http://www.jatcoinc.com/products/jat co-vapor-recovery-unit/jat co-vapor-recovery-unit.

117 See , “Methane Reduction from Natural Gas Dehydration in the DJ Basin,” Producers Technology Transfer Workshop, EPA’s Natural Gas STAR Program Glenwood Springs, CO September 11, 2007, http://www.epa.gov/gasstar/documents/workshop s/2008-tech-transfer/rocksprings9.pdf.

118 Lessons Learned, Natural Gas STAR Partners, “Optimize Glycol Circulation and Install Flash Tank Separators in Glycol Dehydrators,” October 2006, http://www.e pa.gov/gasstar/documents/ll_flashtanks3.pdf.

119 Id.

120 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm."' 90% of the VOCs entrained by the glycol. 121 And in particular, BTEX emission reductions with flash tank separator use can be significant for large dehydrators. 122 Dehydration units that have flash tank separators in combin ation with a condenser on the re boiler vent result in overall improved efficiency of the condenser.

Require Circulation Rate Adjustme nt Practices for All Glycol Pumps

Methane emissions from a glycol dehydrator are directly propor tional to the amount of glycol circulated through the system; the higher the circulation rate the more methane is vented from the reboiler. Over time, producti on rates at the wellhead decline and circulation rates designed for the initial well production rate exceed those required for a mature well. According to EPA Natural Gas STAR partners, circul ation rates “are often two to th ree times higher than the level needed to remove water from natural gas,” wh ich means methane emissions are two to three times higher than necessary. 123 Both the BLM and CARB list the optimization of circulation rates as a BMP for oil and gas sources. 124 EPA should require operating practices that reduce

circulation rates in order to reduce methane emi ssions. This practice can be implemented without affecting dehydration efficiency and without add itional cost to the operator. EPA should require operators to review and adjust glycol circulation ra tes to optimize efficiency. Operators should also be required to incorporat e circulation rate adjustments into regular O&M practices.

Require Glycol Dehydrators to Use Portable Desiccant De hydrators During Maintenance

During complete shutdowns for maintenance of gl ycol dehydrators, prod uction wells can either be shut in or vented to the atmosphere. EPA should require the use of portable solid desiccant dehydrators in place of a glycol dehydrator during ma intenance to avoid venting of methane to the atmosphere. The State of Colorado has pr oposed requiring the use of portable desiccant dehydrators at new installations. 125

Require Installation of BASO ® Valves

EPA should require that all new gas dehydrators employ BASO ® valve technology to shut-off the gas flow in the event that pilot lights are extinguished ( e.g. , from high winds, etc.). This is a simple, cost-effective technology that prevents meth ane emissions that resu lt when the pilot light is extinguished in any air-aspirated burner.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 121 Lessons Learned, Natural Gas STAR Partners, “Produce r and Processor Best Management Practices”, July 23, 2008, http://www.epa.gov/gasstar/documents/w orkshops/2008-tech-transfer/midland7.ppt.

122 Lessons Learned, Natural Gas STAR Partners, “Optimize Glycol Circulation and Install Flash Tank Separators in Glycol Dehydrators”, October 2006, http://www .epa.gov/gasstar/documents/ll_flashtanks3.pdf.

123 Id.

124 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

125 Colorado Air Pollution Control Division, Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 RAQC Meeting.#+ 3. Summary Recommendations for Dehydrators

Zero emission dehydrators virtually eliminate me thane emissions from the dehydration process. The State of Wyoming’s existing requirements for dehydrators and the State of Colorado’s recent proposed control strategy for dehydrators are evidence that 98% control of emissions— including methane emissions—from dehydrator units is technically and economically feasible. The fact that solid desiccant dehydrator tec hnology can achieve 99% reduction in methane emissions and the use of flash tank separators a nd vapor recovery units in glycol dehydration systems can achieve 98% reduction in methan e emissions means that EPA should call for nothing less than 98% reduction in methane emi ssions when considering technology standards and operation practices for this emissions source.

Specifically, EPA should propose the following tec hnology standards and operating practices for dehydration units:

! Require the Use of Zero Emission Dehydrators EPA should require the use of zero em ission dehydrator technology for all new

installations.

! Require the Use of Solid Desiccant Dehy drators in Cases Where Zero Emission Dehydrators Are Not Feasible EPA should require all new dehydrators to first use zero emissi on dehydrator technology and use solid desiccant technology in applic ations where zero dehydrator technology is not feasible. Solid desiccant dehydration should reduce methane emissions by 99%. If, after thorough consideration of existing state-of-t he art technology, EPA determines that zero emission dehydration and solid desiccant dehydration are not universally applicable then EPA should require it where possible and also specific technology standards and operating practices for glycol dehydration units where zero emi ssion dehydration and solid desiccant dehydration ar e not technically feasible.

! Require Glycol Dehydrators to Use Vapor Recovery Units EPA should require the use of vapor recovery un its with control efficiencies of at least 98%, or other technology or ope rational practices that would achieve a similar or greater

reduction in methane emissions.

! Require the Use of Flash Tank Separators EPA should require the use of flash tank sepa rators on all glycol dehydration units to ensure reduction of methane emissions by at least 98%.

! Require Circulation Rate Adjustme nt Practices for All Glycol Pumps EPA should require operators to review and ad just glycol circulat ion rates to optimize efficiency. Operators should also be required to incorporate circulation rate adjustments into regular O&M practices.#* ! Require Glycol Dehydrators to Use Portable Desiccant Dehydrators During

Maintenance EPA should require the use of portable solid de siccant dehydrators in place of a glycol dehydrator during maintenance to avoid ve nting of methane to the atmosphere.

! Require Installation of BASO ® Valves EPA should require that all new gas dehydrators employ BASO ® valve technology to shut-off the gas flow in the event that p ilot lights are extinguish ed (e.g., from high winds, etc.).

D. Tanks

Onshore production and processing storage tanks and transmission storage tanks are sources of methane emissions from the oil and gas sector. Storage tanks provide for the temporary storage of liquids prior to when produced liquids ar e moved off-site for processing. Emissions of methane from storage activities occur through several mechanisms: (1) flashing losses that result when pressure is reduced in th e tank; (2) working losses that re sult when filling and emptying of the storage tank occurs; and (3) breathing (or stan ding) losses that result when the tank gas volume expands and contracts in response to environmental conditions ( e.g. , changes in temperature and pressure).

According to U.S. Greenhouse Gas Inventory da ta, storage tank venting accounts for about 5 Bcf—or about 4 percent—of methane emissions from the production sector. 126 These estimates, however, may grossly underestimate actual emissi ons from this source. According to EPA’s recent rulemakings for the Mandatory Reporting of Greenhouse Gases program, several emissions sources are believed to be “signifi cantly underestimated” in the U.S. GHG Inventory (EPA/GRI/Radian, 1996). 127,128 Specifically, EPA identifies crude oil and condensate storage tanks as a source of under-reported emissions wh ere the true magnitude of emissions may be over five times greater than previous estimates. According to EPA, the emissions estimates for these under-reported sources “do no t correctly reflect the operationa l practices of today” and, in fact, EPA believes “that emissions from some sources may be much higher than currently reported in the U.S. GHG Inventory.” 129 EPA includes revised emission factor for all of the underestimated sources except the categories of crude oil and condens ate storage tanks and flares, for which “no new reliable data are available.” 130 The uncertainty in the degree to which!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 126 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 2007, USEPA, April, 2009, see http://www.epa.gov/gasstar/basic-information/index.html#sources.

127 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry . Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

128 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.

129 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

130 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7, also see Footnote 4: “EPA did consider the data available from two new studies, TCEQ (2009) and TERC (2009). However, it was found that the data available from the two studies raise several questions regarding the magnitude of#" storage tank emissions are underestim ated is sufficient reason to insist on rigorous performance standards and work practices for this particular category. However, there is even more evidence

that the emissions estimates for this and other sources remain uncertain and continue to be greatly underestimated.

A study prepared for the Texas Environmental Re search Consortium measured emissions rates

from several oil and condensate tanks in Texas and developed average em ission factors based on direct measurement of vent gas flow rates. 131 The U.S. GHG Inventory mentions this study but indicates that “[b]ecause of the limited dataset and unexpected jumps in data points which can be attributed to non-flashing emissi on affects, the United States deci ded that further investigation would be necessary before updati ng the inventory emission factor.” 132 The study determined “the direct measurement approach to be the most accurate for estimating oil and condensate storage tank emissions at wellhead and gathering sites; ho wever, other, less accurate, approaches appear to be much more commonly used.” EPA proposed the use of modeling (using “E&P Tank”) to calculate emissions from storag e tanks in the GHG Mandatory Re porting Rule. Yet, the TSD for that rulemaking acknowledges significan t weaknesses with this approach. 133 And, in fact, the Western Climate Initiative recommended major changes to EPA’s proposed reporting requirements for this source category. 134 Due to the uncertainty in the emissions from this source,

EPA must commit to careful consideration of this source’s contribution to overall emissions of methane from the oil and gas sector and should consider implementation of the best available performance standards and operating practices in order to achieve methane reductions from this important source.

1. Existing State, County and International Programs to Reduce Methane

Emissions from Tanks

The following state, county, and international pr ograms demonstrate that mandatory controls for reducing methane emissions are possible. EPA should consider these standards as minimum requirements for regulating sources under the NS PS. Regulations aimed at reducing VOCs and

HAPs are relevant to consider because of the corresponding reductio ns in methane emissions that are achievable through implementation of thes e control technologies and practices.

Colorado

Colorado has several requirements applicable to condensate tanks or tank batteries in the Denver 8-hour ozone nonattainment area. Any condensat e tank or tank battery controlled with a combustion device must be equipped with auto-ign ition upon startup at first date of production or!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! emissions from tanks and hence were not found appropriate fo r any further analysis until the issues are satisfactorily understood and/ or resolved by the authors and covered parties.”

131 Hendler A., Nunn J., Lundeen J., McKaskle R., “VOC Emissions from Oil and Condensate Storage Tanks Final Report”, April 2, 2009 , available online at http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf.

132 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, Chapter 3, p. 3-47.

133 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 134.

134 See , http://www.westernclim ateinitiative.org/component/remosito ry/Reporting-Committee-Documents/.## after any new tank installation or modification. 135 In addition, surveillance systems must be used at all existing condensate tanks with uncontro lled actual emissions over 100 tpy or greater. 136 Air pollution control equipment at new and modifi ed condensate tanks must meet 95% control efficiency requirements for the first 90 days of operation. If complian ce with the system-wide

limits can be met afte r initial 90-day period, then the c ontrol equipment may be removed. 137

For the system-wide control strategy, which applies to all condensate tanks greater than 2 tpy of actual uncontrolled VOC, Colorado is using a tiered approach (with tighter controls during the summertime high ozone season) th at ratcheted down VOC emi ssions from condensate tanks starting in 2005 with a 37.5% emission reduction required. All required reductions apply to actual uncontrolled emissions. For May 1, 2010 through April 30, 2011, 85% reductions are required between May 1 and September 30 and 70% reductions are required for October 1 through April 30. For May 1, 2011 through April 30, 2013, 90% reductions are required between May 1 and September 30 and 70% reductions are required for October 1 through April 30. 138 In 2008, the Colorado Air Quality Control Commission considered a 95% system-wide control but decided to defer decisionmaking on that increased requireme nt at the time. 139,140

Colorado has an additional state-only, statewid e requirement that all condensate tanks with

actual uncontrolled VOC emissions greater than 20 tpy must control emissions by 95%. This rule was effective in May 2008. 141

The Colorado Oil and Gas Conservation Comm ission also regulates VOC emissions at condensate tanks and crude oil and pr oduced water tanks in three counties 142 with high volumes of oil and gas production that are outside of the ozone nonattainment or attainment/maintenance areas. Any condensate tanks or crude oil and produced water tanks with a potential to emit VOCs of 5 tpy or greater, that are located within 1⁄4 mile of certain public facili ties or areas, must use

control devices that can achieve 95% control efficiency and have an appropriate state permit. 143

Wyoming

The state of Wyoming controls flashing emissions from tanks with statewide requirements and more stringent requirements for the Concentrat ed Development Area and the Jonah and Pinedale Anticline Development Area. Under these rule s, “all vapor streams containing VOC or HAP components from all storage tanks ( e.g. , oil, condensate, produced water with oil or condensate carryover) and all se paration vessels ( e.g. , gun barrels, production and te st separators, production!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 135 CDPHE, Colorado Regulation 7, XII.C.1.e.

136 Id , XII.C.1.f.

137 Id, XII.D.1.

138 Id , XII.D.2.

139 Id, p. 96.

140 The goal of the 2008 rulemaking was to approve a plan that shows modeled attainment of the 8-hour ozone standard; 95% system-wide reductions for condensate tanks were was not necessary under the state’s modeling

scenarios.

141 Colorado Regulation 7, XVII.C.

142 Garfield, Mesa & Rio Blanco Counties.

143 Colorado Code of Regulations, 2 CCR 404-1 “Practice and Procedure,” §805 b(2)A & B, http://www.sos.state.co.us/CCR.#$ and test treaters, water knockouts, gas boots, flash separators, drip pots, etc.) at a facility which are or may be vented to the atmosphere shall be considered.” 144 The statewide requirements for new facilities or modified facilities with new and existing flashing emissions require 98% control when flashing emissions are equal to or greater than 10 tpy VOC. 145 In the Concentrated Development Area the requirements are more stringe nt, with all new multiple well facilities and modified facilities with new or existing flash em issions required to meet 98% control for flashing emissions, regardless of annual VOC emissions. For single new well facilities or single modified well facilities in this area, any flashing emissi ons equal to or greater than 8 tpy VOC must be controlled by 98%. 146 For the Jonah and Pinedale Anticline Development Area the rules are even more stringent, requiring that all new or modi fied facilities apply 98% controls for flash

emissions. 147

Wyoming also has a 98% VOC control efficiency requirement that applies to the Concentrated Development Area and the Jonah an d Pinedale Anticline Developm ent area. Under both sets of requirements new and modified facilities must control VOC and HAP emissions from all active produced water tanks by 98%. 148 Open-top or blowdown tanks are not allowed to be used as active produced water tanks but can be used during emergency or upset conditions, in which case the 98% control requirements does not apply. 149

Montana

Montana's requirements to control VOC emissi ons from wellhead assemblies, dehydrators and

tanks also result in methane emissions reductions at these sources. The state's rules require that vented gas at larger sources ( i.e. , PTE > 15 TPY) be captured and routed to: (1) a gas pipeline; (2) a smokeless combustion device (equipped with an electronic ignition device or a continuous burning pilot system) operating at a 95% or greater control effici ency; or (3) an air pollution control device with equal or greater control efficiency th an a smokeless combustion device. 150

India

A planned project in India at th e Uran oil and natural gas proce ssing plant, operated by the Oil & Natural Gas Corporation, would in stall vapor recovery units on st orage tanks. The new units are expected to be operational by December 2010. 151!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 144 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, p. 5.

145 Id.

146 Id, 11.

147 Id , 18.

148 The only the difference between these 2 sets of requirements is that the CDA rules are slightly less stringent for new single well facilities, where 98% control efficiency is requi red within 60 days of first date of production at sites

where 98% control of flashi ng emissions is required.

149 Wyoming DEQ, March 2010, 16 & 20.

150 Montana Administrative Rules §17.8.1711, “Oil or Gas We ll Facilities Emission Control Requirements,” April 7, 2006. http://www.mtrules.org/gateway/ruleno.asp?RN=17%2E8%2E1711.

151 Methane to Markets, Oil & Gas Methane Reduction Proj ect Opportunity, Oil & Natural Gas Corporation, Uran Oil and Natural Gas Processing Plant, http://www.met hanetomarkets.org/projects/projectDetail.aspx?ID=1146.#% Ventura County, California

The Ventura County Air Pollution Control Distri ct crude oil production and separation rule applies to equipment used in the production, ga thering, storage, proces sing, and separation of crude oil and natural gas. The requirements for st orage tanks under this ru le require that vapor recovery systems be installed and meet rem oval efficiencies of 90% for reactive organic compounds, or “[a] system which dir ects all vapors to a fuel gas system, a sales gas system, or to a flare that combusts reactive organic compounds” must be in place. 152

Ventura County also has a rule fo r the storage that appl ies to any equipment used to store crude oil or ROC liquids with a modified Reid vapor pressure greater th an 0.5 psia. These rules include specifications for storage tanks based on thei r capacities, with requirements for vapor loss control devices, such as the use of an external fl oating roof, an internal floating roof, or a vapor recovery system. An acceptable vapor loss control de vice can also be any other system that has a control efficiency of 95% for ROC. 153

2. Available Proven Technologies for Tanks

EPA’s own Natural Gas STAR program provides evidence that vapor re covery units are a technically feasible and cost-eff ective technology that can reduce methane emissions by at least 95% from storage tanks. EPA should consider vapor recovery units as a cost-effective technology for reducing methane emissions from oil and natural gas systems.

Require the Use of Vapor Recovery Units With at least 98% Control Efficiency for All New Crude Oil and Condensate Storage Tanks

Vapor recovery units are relatively simple system s that can recover over 95% of vapors for sale or for use as fuel on-site. According to EPA, “v apor recovery can provide generous returns due to the relatively low cost of the technology.” 154 As is evident by the longstanding local requirements in Ventura County, California and in the newer state regulations in Colorado, Wyoming and Montana, installati ons of vapor recovery units (V RUs) on all new crude oil and condensate tanks can easily be expected to achieve an efficiency of 95 percent.

EPA should investigate the feasibility of re quiring even higher control efficiencies ( e.g. , 98%) in line with the requirement in Wyoming for c ontrolling VOC emissions from produced water tanks. In fact, Colorado has proposed 98% contro l of vapors from dehydrator VRUs, indicating that “many vapor recovery units and combustion de vices already have contro l efficiencies of at least 98 percent.” 155!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 152 Ventura County Air Pollution Control District, Rule 71.1- Crude Oil Production and Separation, last revised 6/16/92, http://www.vcapcd.org/Rulebook/Rule4.htm.

153 Ventura County Air Pollution Control District, Rule 71.2- Storage of Reactive Organic Compound Liquids, last revised 9/26/89, http://www.vcapcd.org/Rulebook/Rule4.htm.

154 Lessons Learned, Natural Gas STAR Partners, “Installi ng Vapor Recovery Units on Crude Oil Storage Tanks”, October 2006, http://www.epa.gov/ga sstar/documents/ll_final_vap.pdf.

155 Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 Regional Air Quality Council Meeting, “APCD OZ ISSUE PAPER oil and gas all strategies .doc”, Prepared by the Co lorado Air Pollution Control Division, Contact: Rose Waldman, available online at#( The vapor recovery unit industry has seen recent advances in t echnology. In addition to so-called “conventional” vapor recovery units ( e.g. , rotary compressor type systems and newer scroll compressors) there are other technologies evolvi ng that may make VRUs even more cost

effective for new installations . Namely, Vapor Jet technology 156 and Venturi ejector vapor recovery units (EVRUTM) 157 both have no moving parts and ha ve shown to be effective in specific applications with reduced O&M costs. 158 Vapor recovery towers (VRT) include a separation vessel that insulates the vapor reco very unit from gas surges and provides for stabilized pressure to allow more effective VRU performance. 159 These cost-saving and performance-enhancing technology advancements further support the universal use of vapor recovery technology to effectivel y control methane emissions from crude oil and condensate storage tanks.

EPA’s Environmental Technology Verification (ETV ) program has evaluated the performance of Comm Engineering USA’s environmental vapor recovery unit (EVRUTM). The EVRUTM is a closed loop system designed to reduce or e liminate emissions of GHGs (methane and CO 2 ), VOCs, and HAPS. The test EVRUTM was used to co llect low-pressure vent gas from condensate storage tanks. The ETV program certified certain performance and environmental performance

criteria for an EVRUTM unit installed in McAllen, Texas. 160 The EPA’s ETV program was designed to facilitate the use of “innovative or improved environmen tal technologies through performance verification and information dissem ination.” According to the EPA, “[t]he ETV program goal is to further environmental prot ection by accelerating the acceptance and use of improved and cost-effective technologies.” 161 EPA should therefore consider the venturi-type EVRUTM as a technically and ec onomically feasible option for all new tank installations.

In addition to reducing methane, vapor recovery units also capture HAPs and, according to EPA, “can reduce operator emissions below actionable le vels specified in Title V of the Clean Air

Act.” 162

Methane emissions also occur when methane and VOCs flash or evaporate into the air that is displaced during the load ing process. EPA should require that all new installa tions include the use of a recycle line to recover gas from conde nsate loading operations that use mobile tanks ( e.g. , trucks or railroad). Recovered gas can then either be sent to a sales line or used for lease!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! http://www.cdphe.state.co.us/ap/ozone/R egDevelop/IssuePapers/February22- 08/APCDOZISSUEPAPEROGdehydrators_000.pdf.

156 Patented technology by Hy-Bon Engineering.

157 Patented technology by COMM Engineering.

158 See, e.g. , Lessons Learned, Natural Gas STAR Partner Presentation, “Vapor Recovery Tower/VRU Configuration”, Producers Technology Transfer Workshop, Long Beach, CA, August 21, 2007, http://www.epa.gov/gasstar/documents/vrt_vru_configuration_08_21_07.pdf.

159 Methane to Markets Presentation, Reducing Methane Emissions With Vapor Recovery on Storage Tanks, January 28, 2009, Monterrey, Mexico, http://methanetomarkets.org/documents/events_oilgas_20090127_techtrans_day2_richards_en.pdf.

160 ETV Joint Verification Statement, Quantum Leap Dehydrator, pp. S-4 and S-5, available online at http://www.epa.gov/etv/pubs/03_vs_quantum.pdf. The minimum detection limit was 0.1 ppmvd so methane concentrations were < 0.1 ppmvd (or < 0.00004 lb/hr).

161 Id.

162 Lessons Learned, Natural Gas STAR Partners, “Installi ng Vapor Recovery Units on Crude Oil Storage Tanks”, October 2006, http://www.epa.gov/ga sstar/documents/ll_final_vap.pdf.#) fuel. A vapor recovery line and the appropriate c onnections should be designed to attach the line to the storage tank or a VRU. This operating pr actice has been shown to be cost-effective, particularly when the recovered gas is sent to a sales or fuel line. 163 This practice will also result

in reduced VOC and HAP emissions.

Gas recovery is possible at any gas gathering station and processing pl ant that frequently removes condensed liquids from its upstream gath ering lines. In these situations, recovering the flash gas from pressurized liquid storage tanks prior to atmospheri c storage can reduce emissions and add more gas to the sales line. EPA should require this practice, where applicable. For example, systems where pressurized condensate is collected from “pigging” operations and stored in atmospheric tanks ( i.e. , storage tanks receiving condensate removed from launching/receiving pigging operatio ns) should include vapor recovery controls to reduce vented

emissions. 164

This technology is also an eff ective means of reducing methane emissions at offshore oil and gas operations. In a paper on offshore platform meth ane reduction strategies, the authors analyzed offshore oil and gas methane emissions and contro l strategies to devise an emission reduction strategy for the most significant sources at the lo west cost. The use of vapor recovery units for storage tanks is one of the r ecommended strategies for reducin g methane emissions in offshore applications. 165

3. Summary Recommendations for Tanks

EPA should implement the following fo r all new storage tank installations:

! Require the Use of Vapor Recovery Units With at least 98% Control Efficiency for All New Crude Oil and Condensate Storage Tanks EPA should require that all new installa tions include a VRU with a 98% control efficiency and should require the use of a recycle line to recover gas from condensate loading operations that use mobile tanks ( e.g. , trucks or railroad). EPA should also require recovery of gas from pipeline pigging operations.

E. Wells

Methane emissions from well venting ( e.g. , from liquids unloading, well completion and well workover) are a significant source of emissi ons from the natural gas production sector. According to U.S. Greenhouse Gas Inventory data , well venting and flaring account for about 7 Bcf—or just over 5 percent—of methane emissions from the production sector. These estimates,!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 163 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheet No. 503, “Recycle Line Recovers Gas During Condensate Loading”, http://w ww.epa.gov/gasstar/documen ts/recyclelinerecovers.pdf.

164 See , e.g., EPA Natural Gas STAR Program Partner Repo rted Opportunities (PRO), PRO Fact Sheet No. 507, “Recover Gas From Pipeline Pigging Operations”, October 2004, http://www.epa.gov/gasstar/documents/pigging.pdf and Lessons Learned, Natural Gas STAR Partner Presentation, “Efficient Pigging of Gathering Lines”, Processor Technology Transfer Workshop, April 22, 2005, http://www.epa.gov/gasstar/documents/pigging_lines.ppt.

165 Bylin, Carey et al. for Society of Petroleum Engineer s, “Designing the Ideal Of fshore Platform Methane Mitigation Strategy,” 2010, p. 1.#& however, may grossly underestimate actual emissi ons from this source. According to EPA’s recent rulemakings for the Mandatory Reporting of Greenhouse Gases program, several emissions sources are believed to be “signifi cantly underestimated” in the U.S. GHG Inventory (EPA/GRI/Radian, 1996). 166,167 Specifically, EPA identifies well venting for liquids unloading, gas well venting during well completions and gas well venting during well workovers as three sources of under-reported emi ssions. According to EPA, the emissions estimates for these sources “do not correctly reflect the operational practices of to day” and, in fact, EPA believes “that emissions from some sources may be much higher than currently re ported in the U.S. GHG Inventory.” 168 EPA includes revised emission factors for all of these underestimated well venting sources, as follows: (1) an emission factor for well venting for liquids unloading that is 11 times higher; (2) an emission factor for venting dur ing completions that is 35 times higher for conventional wells and almost 9,000 times higher for unconventional wells; and (3) an emission factor for gas well venting during well workove rs that is 3,500 times higher for unconventional

wells. 169 Overall, the revisions to these and the revi sed factor for centrifugal compressor wet seal degassing venting results in a more than 100% in crease in estimated emissions from the oil and gas production sector. 170 These enormous underestimates, alone , are enough of a reason to insist on rigorous performance standards and work practic es for these particular categories. However,

there is even more evidence that the emissions estimates for these and other sources remain

uncertain and continue to be greatly underestimated.

An area of particular uncertain ty appears to be gas well completions and well workovers. As EPA notes in the preamble to the proposed mandatory reporting rule:

[N]o body of data has been identified that can be summarized into generally applicable emissions factors to characte rize emissions from these sources [(i.e., from well completion venting and well workover venting)] in each unique field. In fact, the emissions factor being us ed in the 2008 U.S. GHG Inventory is believed to significantly underestimate em issions based on industry experience as included in the EPA Natural Gas STAR Program publicly available information (http://www.epa.gov/gasstar/). In ad dition, the 2008 U.S. GHG Inventory emissions factor was developed prior to the boom in unconventional well drilling (1992) and in the absence of any field data and does not capture the diversity of well completion and workover operations or the variance in emissions that can be expected from different hydrocar bon reservoirs in the country. 171!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 166 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

167 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.

168 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

169 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 8, Table 1.

170 Id. at 9.

171 75 FR 18621, April 12, 2010.#' As noted, there is believed to be a significant underestimate in emissions from well completions based on industry experience as reported th rough EPA’s Natural Gas STAR program. The 2008 U.S. GHG Inventory emphatically states that “[n]atural gas we ll venting due to unconventional well completions and workovers, as well as conv entional gas well blowdo wns to unload liquids have already been identified as sources for wh ich Natural Gas STAR reported reductions are significantly larger than the estimated inventory emissions.” 172 And EPA has indicated that “[p]resently, [reduced emission completions (R EC)] reductions reported in the Natural Gas STAR body of work is larger than well completion venting in the inventory on an annual

basis.” 173 Specifically, the U.S. GHG I nventory is based on an emissi on factor of a little over three thousand standard cubic feet (3 Mcf) per gas well drilled and completed. 174 Yet, Natural Gas STAR program partner experience shows several cases where emission factors were thousands of times higher than that shown in the 2008 inventory. Examples include: (1) a BP project employing green completions at 106 well s and reporting 3,300 Mcf of gas recovered per well; 175 (2) a Devon Barnett Shale project employing green completions at 1,798 wells between 2005 and 2008 and reporting 6,300 Mcf of gas recovery per well; 176 and (3) a Williams project employing green completions at 1,064 wells in the Piceance Basin reporting 22,000 Mcf of gas recovered per well. 177 All of these examples include ga s recovery estimates more than 1,000 times higher than the 3 Mcf of gas per well estim ated in the U.S. GHG Inventory for 2008. These data are consistent with the unconventional gas well completion and workover data presented in EPA’s TSD for the MRR revisions (April 2010). Specifically, the technical support document includes four examples from the Natural Gas STAR program with gas completion rates of 6,000 Mcf, 10,000 Mcf, 700 Mcf and 20,000 Mcf per completion. 178 EPA used an average of these four data points for its emission factor for this source ( i.e. , 9,175 Mcf/completion). Using this factor resulted in estimated emissions from comple tions and well workover from conventional and

unconventional wells of 120 billion standard c ubic feet (Bcf). In comparison, the U.S. GHG Inventory reports emissions of just 0.1 Bcf of gas from drilling and well completions. 179

More generally, Natural Gas STAR partners reported rec overing between 7 and 12,500 Mcf (average of 3,000 Mcf) of natural gas from each cleanup with the potential for an estimated 25!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 172 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, p. 3-47.

173 See “Environmental Defense Fund (EDF) Questions & USEPA Answers – June 1, 2010” posted to the Docket for EPA’s MRR revisions to Subpart W on June 2, 2010, Docket ID EPA-HQ-OAR-2009-0923-0070.

174 Table A- 118: 2008 Data and CH 4 Emissions (Mg) for the Natural Gas Production Stage, p. A-144, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006.

175 See Natural Gas STAR Program Recommended Te chnologies and Practices for Wells at http://www.epa.gov/gasstar/tools/recommended.html, and specifically http://www.epa.gov/gasstar/docum ents/green_c.pdf, slide 11.

176 See attached 2009 workshop presentation by Devon, s lides 3 and 13. 6,300 Mcf = 11.4 Bcf / 1,798 wells.

177 See Natural Gas STAR Program Recommended Te chnologies and Practices for Wells at http://www.epa.gov/gasstar/tools/recommended.html, and specifically http://www.epa.gov/gasstar/docum ents/vincent.pdf, slide 14.

178 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, Appendix B on pp. 79-82.

179 See Table A-125: CH 4 Emission Estimates from the Natural Gas Production Stage Excluding Reductions from the Natural Gas STAR Program and NESHAP regulations (Gg), p. A-151, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006. Drilling and Well Completion (2008) = 2.05 Gg. (2.05 Gg * 0.052 ft 3 /g = 0.1 Bcf)$+ Bcf of natural gas recovery from green comple tions annually in 2005 compared with the annual U.S. GHG Inventory total for “Drilling and Well Completion” of just 0.1 Bcf in 2008. 180,181 And more recently, EPA’s Natural Gas STAR program at tributed 45 Bcf of gas to reduced emissions completions (RECs) in 2008 (representing 50 per cent of EPA’s Natural Gas STAR program’s annual total reductions). 182 If, in fact, the emission factor fo r well completions is at least 1,000 times higher than what is reporte d in the U.S. GHG Inventory ( e.g. , if it is at least 3,000 Mcf instead of 3 Mcf) this would add 100 Bcf to the total estimated emissions from natural gas systems, raising the total from 240 Bc f to 340 Bcf in 2008 (a 40% increase). 183

A New York Times article published on Oct ober 15, 2009, reports that EPA is currently reviewing and revising methane emissions from U.S. gas wells. According to the article:

An E.P.A. review of methane emissions from gas wells in the United States strongly implies that all of th ese figures may be too low. In its analysis, the E.P.A. concluded that the amount emitted by r outine operations at gas wells—not including leaks like those seen near Franklin—is 12 times the agency’s longtime

estimate of nine billion cubic feet. In h eat-trapping potential, that new estimate equals the carbon dioxide emitted annually by eight million cars. 184

In fact, the TSD for the April 2010 MRR includes an estimate of 120 Bcf for U.S. completion and workover venting. As previously discussed, th is estimate is based on an emission factor of 9,175 Mcf per completion or workover. Given the spar se data (4 data poin ts) and the enormously wide range of potential emissi on factor values from this source (ranging from 700 to 20,000 Mcf) even the recently revised estimates may very well continue to underestimate emissions

from this source.

The statistical representation of the U.S. GHG I nventory data includes a 95% range within which emissions from this source category are likely to fall for the year 2008. This range, for Natural Gas Systems, includes a lower bound of -24% and an upper bound of +43%. 185 As noted in the uncertainty analysis, “[t]he hete rogeneous nature of the natural gas industry makes it difficult to sample facilities that are completely re presentative of the entire industry.” 186 And as a result, basing an emission factor on only a few “represe ntative” sources when considering the highly!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 180 See http://www.epa.gov/gasstar/documen ts/green_c.pdf, slides 9 and 5.

181 See Table A-125: CH 4 Emission Estimates from the Natural Gas Production Stage Excluding Reductions from the Natural Gas STAR Program and NESHAP regulations (Gg), p. A-151, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006. Drilling and Well Completion (2008) = 2.05 Gg.

182 See 2009 EPA Natural Gas STAR Program Accomplishments, available online at http://www.epa.gov/gasstar/documents/ngstar_accomplishments _2009.pdf. Total sector re ductions (2008) = 89.3 Bcf of which 50% are the result of RECs (50% of 89.3 Bcf = 45 Bcf).

183 See Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10- 006, Chapter 3, Table 3-38 CH4 Emissions from Natural Gas Systems (Gg), p. 3-45. Total emissions in Bcf: 4,591 Gg * 0.052 ft 3 /g = 240 Bcf.

184 See www.nytimes.com/2009/10/15/business/energy-environment/15degrees.html#.

185 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, Chapter 3, Table 3-41, p. 3-46.

186 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, Chapter 3, p. 3-46.$* variable rates measured among these sources, results in a potentially high degree of uncertainty as reflected in the reported uncertainty range.

We are hopeful that the EPA-acknowledged disc repancies between the inventory emissions reported to-date and the Natural Gas STAR reported reductions and the high degree of uncertainty in both of these data sources will be reconciled with a rigorous reporting rule for the oil and gas sector and, in particular, for vented emissions from wells. We also hope that EPA will employ rigorous performance standards for this critical source that is likely a much more significant source of emissions than what is reflected in the U.S. GHG inventory.

It is worth noting that direct measurement of emissions from well venting for liquids unloading as well as during unconventional well completions and well workovers is possible as a means to accurately demonstrate compliance with perf ormance standards established by EPA. EPA proposed direct measurement methods for dete rmining reported emissions under the Mandatory Reporting Rule (MRR) for these source types. 187

1. Existing State Programs to Reduce Methane Emissions from Wells

The following state programs demonstrate that mandatory controls for reducing methane emissions are possible. EPA should consider these standards as minimum requirements for regulating sources under the NSPS. Regulations aimed at reducing VOCs and HAPs are relevant to consider because of the corresponding reducti ons in methane emissions that are achievable through implementation of these cont rol technologies and practices.

Colorado

The Colorado Oil and Gas Conservation Commi ssion requires that green completions be

installed at all wells in the state that meet a threshold requirement, except in cases where green completions are not technically or economically practical. Green completions are also not required on exploratory wells. “Gr een completion practices are re quired on oil and gas wells where reservoir pressure, formation productivity, a nd wellbore conditions are likely to enable the well to be capable of naturally flowing hydrocar bon gas in flammable or greater concentrations

at a stabilized rate in excess of five hundred (500) MCFD to the surface against an induced surface backpressure of five hundred (500) psig or sales line pressure, whichever is greater.” 188
Sand traps, surge vessels, separators and tanks must be used during flowback and cleanout operations, with a few exceptions. The aforementi oned control devices must be used when the well effluent containing more than ten barrels per day of condensate or within two hours after first encountering hydrocarbon gas of salable quality. With this process, sand, hydrocarbon liquids, water, and gas are safely separated to ensure that the, “s alable products are efficiently

recovered for sale or conserved and that non-sa lable products are disposed of in a safe and environmentally responsible manner.” 189 If green completions are deemed not feasible, then the!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 187 75 FR 18608, April 12, 2010. Note, EPA proposed engineering estimates as the means for demonstrating compliance for conventional well completions and conventional well workovers.

*&& Colorado Code of Regulations, 2 CCR 404-1 “Practice and Procedure,” §805 b(3)B, http://www.sos.state.co.us/CCR.

189 Id.$" operator must use other BMPs in order to mini mize emissions, such as limiting the amount of flaring and venting. 190

Wyoming

As per Wyoming’s oil and gas production facil ities permitting guidance, all operators must submit permit applications that apply best management practices for well completions or recompletions. The permits completed for the Jonah and Pinedale Anticline Development Area are the models to be used. The Wyoming Air Quality Division provides a samp le well completion or green completion permit. The permits state: “The operator shall follow the operational plan for Best Management Practices described in the appli cation for this permit to eliminate to the extent practicable emissions of volatile organic compounds and hazardous air pollutants associated with flaring and venting of hydrocarbon fluids r ecovered during well completion/re-completion

activities.” 191 Conditions under which it is unacceptable to se nd gas to the flare are listed in this permit. The permits also must include mon itoring, recordkeeping, notification and reporting requirements. The Air Quality Division’s Well Co mpletion Emission Spreadsheet must be used to calculate estimates of VOC, total HAPs, NO X and CO. 192

Montana

Montana's requirements to control VOC emissi ons from wellhead assemblies also result in

methane emissions reductions at these sources. The state's rules require that vented gas at larger sources (i.e., PTE > 15 TPY) be captured and routed to: (1) a gas pi peline; (2) a smokeless combustion device (equipped with an electronic ignition device or a continuous burning pilot system) operating at a 95% or greater control effi ciency; or (3) an air pollution control device with equal or greater control effici ency than a smokeless combustion device. 193

2. Available Proven Technologies for Wells

EPA’s own Natural Gas STAR program provide s evidence that there are many available, technically feasible and cost-eff ective technologies that can greatly reduce methane emissions from wells. These options include both: (1) technology standards for wells; and (2) improving operating practices to reduce emissions. EPA should, at a minimum, require the following technologies and operating practices as part of its revised NSPS for oil and natural gas systems.

Require the Use of Reduced Emission Completions or Green Completions

During a reduced emission completion (REC) or “green completion” the produced natural gas from a well completion or well workover is recovere d for salable use instead of being vented to the atmosphere (or flared). Produced gas conde nsate can also be rec overed. This method of!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 190 Id., §805 b(3)C & D.

191 “Example Well Completions (“Green Completions”) Pe rmit,” Wyoming Department of Environmental Quality, March 2010, p. 1.

192 Id.

193 Montana Administrative Rules §17.8.1711, “Oil or Gas We ll Facilities Emission Control Requirements,” April 7, 2006. http://www.mtrules.org/gateway/ruleno.asp?RN=17%2E8%2E1711.$# reducing methane emissions during gas production has been proven to be cost-effective by partners in EPA’s Natural Gas STAR program for over five years. 194 RECs require additional equipment to convert the otherwise-vented gas to salable gas. Additional portable equipment is required and may include tanks, portable separators, sand traps, and portable gas dehydration devices. The equipment would be moved from well to well, as needed. Even with the additional capital costs for this equipment, EPA Natural Ga s STAR partners report payback periods of less than a year for reduced emission completions. 195 EPA Natural Gas STAR partners also report recovering up to 89% of total gas produced dur ing well completions and workovers (average of 53%) from high-pressure wells. 196 And, in fact, at least one Natural Gas STAR partner has reported 100% recovery of completion gas. 197 Other, more generalized, estimates of methane reduction efficiency based on EPA’s Natural Ga s STAR partner data are around 70% for green completions. 198 Certainly, higher efficienci es can be expected from the best available technology and design. Technology advances have also made recovery of gas from low-pressure wells possible. For example, the use of portable compre ssors can be used when the reservoir pressure is too low to enter the gas sales line. 199

EPA should require the use of reduced emission completions for all new wells unless deemed unsafe, as demonstrated and documented by the operator. EPA should also require 90%, or better, recovery. Both the BLM and CARB list green completions as a BMP for oil and gas

sources. 200 This proven, best management practice shoul d be required for all new wells in order to achieve greater emission reductions.

EPA should also require the use of portable desi ccant dehydrators to s upport green completions. RECs can employ solid desiccant dehydrators that are brought on site to process vented gas (from well completions and workovers) before sending it to the sales line.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 194 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheet No. 703, “Green Completions”, September 2004, http://www.epa.gov/gasstar/documents/greencompletions.pdf and Lessons Learned, Natural Gas STAR Partners, “Reduced Emission Completions (Green Completions)”, October 26, 2005, http://www.epa.gov/gasstar/documents /green_c.pdf and “Reducing Methane Emissions During Completion Operations”, 2006 Natural Gas STAR Annual Implementation Workshop, Houston, TX, October 24, 2006, http://www.epa.gov/gasstar/documents/vin cent.pdf and Lessons Learned, Natu ral Gas STAR Partners, “Reducing Methane Emissions from Production Wells: Reduced Emission Completions”, May 11, 2010, http://epa.gov/gasstar/documents/workshops/far mington-2010/08_recs_farmington_nm_final.pdf.

195 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Production Wells: ReducedEmission Completions”, May 11, 2010, http://epa.gov/gasstar/documents/workshops/farmington2010/08_recs_farmington_nm_final.pdf.

196 Lessons Learned, Natural Gas STAR Partners, “Reduced Emission Completions (Green Completions)”, October 26, 2005, http://www.epa.gov/gasstar/documents/green_c.pdf.

197 See Williams Production RMT, Piceance Basin Operatio ns, “Reducing Methane Emi ssions During Completion Operations”, 2006 Natural Gas STAR Annual Implementation Workshop, Houston, TX, October 24, 2006, http://www.epa.gov/gasstar/d ocuments/vincent.pdf.

198 Robinson, D.R., Fernandez, R., Kant amaneni, R. K., “Methane Emissions Mitigation Options in the Global Oil and Natural Gas Industries, Table 2, http://www.coalinfo.net.cn/coalbed/meeting/2203/papers/naturalgas/NG020.pdf.

199 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Production Wells: ReducedEmission Completions”, May 11, 2010, http://epa.gov/gasstar/documents/workshops/farmington2010/08_recs_farmington_nm_final.pdf.

200 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.$$ In addition to reducing methane emissions, RECs produce an additional reve nue stream from the recovery of produced natural gas and gas liquids. RECs also result in less solid waste and water pollution and safer operating conditions.

Require the Installation of Plunger Lift System s in Gas Wells to Reduce Methane Emissions From Blowdown Operations

Venting of a mature well to the atmosphere (w ell blowdown) in order to remove accumulated fluids can be a significant sour ce of methane emissions. Instead of venting gas wells to force out accumulated well bore fluids, a plunger lift uses th e well’s energy to efficiently push the fluids out of the well. According to EP A, plunger lift systems are a cost -effective alternative to other lift technologies and to well bl owdowns and “can significantly re duce gas losses, eliminate or reduce the frequency of future well tr eatments, and improve well productivity.” 201 EPA lists this technology as having a less than one-year payback. 202 Since there are certai n technical feasibility considerations for these systems ( e.g. , the well shut-in pressure has to be sufficiently higher than the sales line pressure), EPA should require the use of plunger lift systems at all gas wells unless the operator can adequately demonstrate that th e well will not operate with sufficient shut-in pressure or production rate to be able to us e such a system. EPA should also review the feasibility of requiring the use of pumpjacks and fo aming agents when there is insufficient buildup in reservoir pressure to opera te a plunger lift system and the us e of velocity tubing strings for wells operating with higher reservoir pressure. 203

Use of the latest information technology ( e.g. , online data management, satellite communications, etc.) can help reduce management costs ( e.g. , operator visits) of these systems and help optimize operational practices. In fact, one partner’s experience is that “[t]echnology is only a piece of the solution—most significant recent reductions are due to revised operational practices.” 204 This partner reported an ov er 80% reduction in venting. 205 EPA should require the installation of automated well monitoring system s to help optimize plunger lift and blowdown operations. “Smart Automation” system s monitor well production parameters ( e.g. , pressure, flow rate, plunger velocities, etc.) and use remote telemetr y coupled with site-specific operational data to improve well and venting pe rformance. These types of automated systems have enabled significant reductions in ga s venting volumes along with production improvements. 206 The BLM lists the use of “Smart Automation” systems as a BMP. 207 Other operational practices include well -specific practices such as op timizing well blowdown times by!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 201 Lessons Learned, Natural Gas STAR Partners, “Installing Plunger Lift Systems in Gas Wells”, October 2006, http://www.epa.gov/gasstar/doc uments/ll_plungerlift.pdf.

202 See http://www.epa.gov/gasstar/tools/recommended.html.

203 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheet Nos. 706, 707, and 704 “Use Foaming Agents”, “Install Pumpjacks on Low Wa ter Production Gas Wells” and “Install Velocity Tubing Strings”, http://www.epa.gov/gasstar/documents/usefoamingagents.pdf , http://www.epa.gov/gasstar/documents/gaswells.pdf and http://www.epa.gov/gasstar/documents/installvelocitytubingstrings.pdf.

204 EPA Natural Gas STAR Presentation, “Plunger Well Vent Reduction Project, G.P. (Skip) Desaulniers, BP, 2006 Natural Gas Star Workshop, http://www.epa .gov/gasstar/documents/desaulniers.pdf.

205 Id. See Southern San Juan Quarterly Vent Volumes (slide 16).

206 See EPA Natural Gas STAR Program Partner Reported Op portunities (PRO), PRO Fact Sheet No. 709, “Gas Well “Smart” Automation System”, http://www.epa.gov/gasstar/documents/smart_automation.pdf.

207 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov.$% monitoring well flow conditions. 208 EPA should require all operato rs to develop an operational plan, based on the above practices, for managing the plunger lift systems so as to minimize venting.

Other benefits of plunger lift installations incl ude gas savings from avoided blowdowns as well as increased gas production following plunger lift inst allations. According to EPA, benefits from increased gas production are “well- and rese rvoir-specific and will vary considerably.” 209 EPA Natural Gas STAR partners have reported reduc tions in other air pollu tants, as well, with installation of plunge r lift technology. 210 Both the BLM and CARB list the installation of plunger lifts as a BMP for oil and gas sources. 211 Wyoming also has a BMP that requires VOC and HAP emissions from manual and automated blowdown and venting episodes be minimized to the maximum extent practicable. 212

Require the Installation of Downhole Separator Pumps, Where Applicable

Downhole separator pumps, or hydrocyclones, ar e used for gas-liquid se paration. The pumps are installed upon well completion or well workover a nd are designed to separate gas from water below the surface and then inject the water into a lower lying aquifer for disposal while sending the methane gas to the surface. 213 Use of these pumps eliminates methane emissions from produced water storage. EPA should require th e installation of downhol e separator pumps in applications where there is a lower lying water disposal aquifer.

Require Mud Degassing Vents Be Routed to a Vapor Recovery Unit

Mud degassing systems are used to remove en trained formation gas from the drilling mud (drilling fluid) to maintain higher mud density for well control. Drilling mud degassing units extract entrained gas from the mud at the surface and vent this ga s directly into the atmosphere. EPA should require that these vents be routed to a vapor recovery unit to reduce methane

emissions.

A recent paper on offshore platform methane reduc tion strategies analyzed offshore oil and gas methane emissions and control strategies and de vised an emission reduction strategy for the most significant sources at the lowest cost. Using a vapor recovery unit to capture mud degassing emissions is one of the recommended strategies for reducing methane emissions in offshore applications. 214!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 208 See EPA Natural Gas STAR Program Partner Reported Op portunities (PRO), PRO Fact Sheet No. 708, “Gas Well Unloading Time Optimization”, http://www.epa.gov/gasstar/documents/unloading_time508.pdf

209 Lessons Learned, Natural Gas STAR Partners, “Installing Plunger Lift Systems in Gas Wells”, October 2006, http://www.epa.gov/gasstar/doc uments/ll_plungerlift.pdf.

210 ExxonMobil reported that their plunger lift system in the Big Piney Field in Wyoming “reduced the venting of ethane (6 percent by volume), C3 hydrocarbons + VOCs (5 percent), and inerts (2 percent).” Id.

211 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, 988NRPPSSSJ7=1J47JF-<P44P:-:T4-"T4 267=3:F9-0D6P:-: T4-"T4267=3:F 9-0D6J98>J

212 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, 10, 17 & 21.

213 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheet No. 705, “Install Downhole Separator Pumps”, http://www.epa.gov/gasst ar/documents/installdownholeseparatorpumps.pdf.

214 Bylin, Carey et al. for Society of Petroleum Engineer s, “Designing the Ideal Of fshore Platform Methane$( 3. Summary Recommendations for Wells

EPA should implement the following technology st andards and operating practices for all new

wells:

! Require the Use of Reduced Emission s Completions or Green Completions EPA should require the use of reduced emi ssion completions for all new wells unless deemed unsafe, as demonstrated and documented by the operator. EPA should also require 90%, or better, recove ry. EPA should also require the use of portable desiccant dehydrators to support green completions.

! Require the Installation of Plunger Lift Sy stems and the Development of Operational

Practices that Minimi ze Methane Emissions EPA should require the use of plunger lift syst ems at all gas wells unless the operator can adequately demonstrate that the well will not op erate with sufficient shut-in pressure or production rate to be able to use such a syst em. EPA should also requ ire all opera tors to develop an operational plan for managing th e plunger lift systems so as to minimize venting.

! Require the Installation of Downhole Separator Pumps, Where Applicable EPA should require the installation of downhol e separator pumps in applications where there is a lower lying water disposal aquifer.

! Require Mud Degassing Vents Be Routed to a Vapor Recovery Unit EPA should require that mud dega ssing vents be routed to a va por recovery unit to reduce

methane emissions.

F. Pipelines

Natural gas produced from gas fields is transpor ted through pressurized pipelines to distribution systems. These pipelines require regular repair and maintenance as a re sult of corrosion (to both interior and exterior surfaces), leaks, materials failures, and damage caused by external factors. According to U.S. Greenhouse Gas Inventory da ta, pipeline leaks account for about 8 Bcf—or about 8 percent—of methane emissions from the transmission sector. 215

1. Planned State Programs to Reduce Methane Emissions from Pipelines

Under CARB’s Climate Change Scoping Plan, the st ate is considering a requirement for oil and gas operators to replace older equipment, such as flanges, valves and fittings, along pipelines. 216!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! Mitigation Strategy,” 2010, p. 1.

215 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 2007, USEPA, April, 2009, see http://www.epa.gov/gasstar/basic-information/index.html#sources.

216 “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework for change,” California Air Resources Boar d, December 2008, pp. C-153 and C-154, http://www.arb.ca.gov/cc/scopingplan/doc ument/appendices_volume1.pdf#page=184.$) 2. Available Proven Technologies for Pipelines

EPA’s own Natural Gas STAR program provide s evidence that there are many available, technically feasible and cost-e ffective technologies and operating practices that can greatly reduce methane emissions from pipelines. These op tions include both: (1) technology standards; and (2) improving operating practic es to reduce emissions. EPA should, at a minimum, consider the following technologies and operating practic es as cost-effective standards for reducing methane emissions from oil and natural gas systems.

Require the Use of Gas Main Flexible Liners and State-of-the-Art Pipeline Material and Protective Coatings

Cast iron and steel piping ma terials used in underground gas distribution systems have the highest leakage factors of a ll distribution piping materials. 217 According to EPA, plastic pipe has the lowest leakage rate. 218 EPA should require the use of the plastic pipe wherever feasible. Where the use of plastic pipe is not feasible EPA should require the use of flex ible plastic insert liners. These types of plastic liners use the out er material for support but provide for the low leakage rates of plastic piping.

For pipelines that would be designed to have a protective coating, EPA s hould require the use of the best available coating tec hnology to ensure maximum protec tion of piping materials. For example, PRITEC® is a protective coating made of a mixture of butyl adhesive and polyethylene that, according to EPA, is desi gned to “withstands exposure to w eather and ultraviolet radiation for prolonged periods without degradation”. 219 With increasing demand for oil and gas, pipelines are being installed in ever-more difficult enviro nments. The pipeline coatings industry is reporting market developments and technology and materials innovations to meet the demands of today’s applications. 220 Degradation of coatings due to exposure to the sun and to water ( e.g. , in marine environments) can result in pipe corro sion and leaks. Requiri ng the use of the best available coating technology will help to minimi ze this potential source of methane emissions from pipelines. CARB already lists the replacement of cast iron and steel piping as a BMP for oil and gas sources. 221

Require Several Operating and Maintenance Practices for Pipelines

In 2004, an estimated 12 Bcf of methane was vent ed to the atmosphere during routine pipeline maintenance and pipeline upsets. EPA should requi re that during routine maintenance, operators!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 217 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact SheetsNo. 403, “Insert Gas Main Flexible Liners”, http://www.epa.gov/ga sstar/documents/insertgasmainflexibleliners.pdf.

218 Id.

219 See EPA Natural Gas STAR Program Partner Reported Opportu nities (PRO), PRO Fact SheetsNo. 406, “Use of Improved Protective Coating at Pipeline Canal Crossings”, http://www.epa.gov/gasstar/documents/useofimproved.pdf.

220 See , e.g., the following October 20, 2010 News Report, “Pipeline Coatings Makers Face Historic Demands”, http://www.paintsquare.com/new s/article_news. cfm?id=4507.

221 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.$& be required to use pump-down techniques to reduce the gas line pressure in the pipeline before venting. Alternatively, operators could opt to use an ejector or use inert gases and pigs to purge pipelines. 222 All of these methods would reduce vented gas and can recover up to 90% of the gas

in the line. 223 Operators can use in-line compressors or portable compressors to lower the gas line pressure (or ejectors) and should also be required to incorporat e in-line compressor pump-downs into emergency procedures. In addition to reduc ing methane emissions, na tural gas that would have been vented to the atmosphere can be recovered and sold. In the case of production pipelines, the gas stream might also cont ain valuable heavy hydrocarbons. Pump down techniques also reduce odor and noise pollu tion and virtually eliminate HAP emissions. 224

Recent success of Natural Gas STAR Partner Tr ansCanada’s pump-down practices has resulted in the company’s purchase of eight portable comp ressor units for use mainly on its high-pressure lines in Canada. Future possibilities include e xpanding its fleet of portable compressor units and implementing pump-down practices company-wide (36,500 miles of pipeline). TransCanada has reported increased revenue and decreased meth ane emissions from its pump-down practices. 225

EPA should also consider requiring operating prac tices that reduce distribution system pressure. According to EPA, nearly all distribution sect or methane losses are a result of unidentified fugitive leaks. 226 Systems that operate under higher than necessary pressure increase the amount of leakage that occurs. If operators are required to adjust system pressures at shorter intervals they can better match the current demand and reduce the amount of time the system operates under peak demand pressures. EPA should require ope rators to install auto mated control systems to regulate pressure. These automated systems will help ensure lower leak rates and less

maintenance.

EPA should also require the use of hot taps for in-service pipeline connections. Hot tapping allows for a new pipeline connection while keeping the pipeline in service. Hot tapping avoids product loss, methane emissions, and di sruption of service to customers. 227 According to EPA, “hot tapping has been found to be more cost effective than shutdown interconnects” and “recent design improvements have reduced the complica tions and uncertainty operators might have experienced in the past.” 228

EPA should require regular inspec tion of all flowlines in the production sector. The flowlines that transport natural gas from wells to tran smission compressor stations or processing plant!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 222 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheets No. 404 and 405, “Install Ejector” and “Use Inert Gases and Pigs to Perform Pipeline Purges”, http://www.epa.gov/gasstar/documents/installejector.pdf and http://www.epa.gov/gasstar/documents/useinertgases.pdf.

223 Lessons Learned, Natural Gas STAR Partners, “Using Pipeline Pump-Down Techniques to Lower Gas Line Pressure Before Maintenance”, October 2006, h ttp://www.epa.gov/gasstar/documents/ll_pipeline.pdf.

224 Id.

225 EPA Natural Gas STAR Partner Update, Fall 2009, http://www.epa.gov/gasstar/newsroo m/partnerupdatefall09.html.

226 EPA Natural Gas STAR “Reducing Distri bution System Pressure” Presentation, http://www.epa.gov/gasstar/documen ts/red_of_pressure_part1.ppt.

227 Lessons Learned, Natural Gas STAR Partners, “Using Hot Taps for In Service Pipeline Connections”, October 2006, http://www.epa .gov/gasstar/documents/ll_hottaps.pdf.

228 Id.$' booster stations are normally buried and, according to EPA, “can leak methane as a result of internal corrosion (particularly in wet, sour ga s service), external corrosion, and abrasion from thermal cycling.” 229 EPA estimates that methane leakage fr om flowlines is “one of the largest sources of emissions in the gas industry.” 230 These underground leaks can be detected using ultrasound or digital radiography.

Require the Installation of Excess Flow Valves on All Gas Service Lines

EPA should require that excess flow valves be tested and proven at the time of installation and at periodic intervals not to exceed one year. 231 Gas line breaks can result in unexpected gas releases into the atmosphere. Methane emissions can be avoided by ensuring an automated shutoff of any ruptured gas service line through requir ed installation of excess flow valves.

3. Summary Recommendations for Pipelines

EPA should implement the following fo r all new pipeline installations:

! Require the Use of Gas Main Flexible Liners and State-of-the-Art Pipeline Material and Protective Coatings EPA should require the use of the plastic pipe wherever feasible. Where the use of plastic pipe is not feasible EPA shoul d require the use of flexible plastic insert liners. EPA should require the use of the best availa ble coating technology to ensure maximum protection of piping materials.

! Require Maintenance Practices for Pipelines EPA should require that during routine maintenance, operators be required to use pumpdown techniques to reduce the gas line pressure in the pipelin e (or ejectors or use inert gases and pigs to purge pipeli nes) before venting. EPA should also require that in-line compressor pump-down techniques be incorp orated into emergency procedures. EPA should require operators to install automate d control systems to regulate pressure to ensure lower fugitive leak rates. EPA should also require the use of hot taps for in-service pipeline connections. EPA should require re gular inspection of a ll flowlines in the production sector.

! Require the Installation of Excess Flow Valves on All Gas Service Lines EPA should require that excess flow valves be tested and proven at the time of installation and at periodic inte rvals not to exceed one year.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 229 See EPA Natural Gas STAR Program Partner Reported Opportu nities (PRO), PRO Fact Sheet No. 407, “Inspect Flowlines Annually”, http://www.epa.gov/g asstar/documents/inspectflowlines.pdf.

230 Id.

231 See EPA Natural Gas STAR Program Partner Reported Oppor tunities (PRO), PRO Fact Sheet No. 610, “Install Excess Flow Valves”, http://www.epa.gov/gasst ar/documents/installexcessflowvalves.pdf.%+ G. Flaring

Flares are widely used in the oil and gas industr y to combust unsalable ga s or to dispose of gas released for safety measures or du ring testing. According to EPA,

Flares in general can be categorized into two main types; continuous and

intermittent. Continuous flares combust cas ing head gas, associated gas, well testing gas, and gas from equipment that generate a continuous waste gas stream (such as glycol dehydrators, storage ta nks, and pneumatic devices). Intermittent

flares combust releases that are not con tinuous in nature such as streams from equipment/ vessel/ site blowdowns and pressure relief valves. 232

Although sending emissions to flares (rather than venting those em issions) eliminates methane, other air pollutants, including CO 2 are released into the atmosphere. The U.S. Energy

Information Administration estimated CO 2 emissions from natural gas flaring to be 1,187.48

MMT in 2006. 233 In order to reduce methane emissi ons without increasing additional air pollution, alternatives to flari ng should be required by EPA.

These emission estimates for flaring may grossl y underestimate actual emissions from this source. According to EPA’s recent rulemakings for the Mandatory Reporting of Greenhouse Gases program, several emissions sources are beli eved to be “significan tly underestimated” in the U.S. GHG Inventory (EPA/GRI/Radian, 1996). 234,235 According to EPA, the emissions estimates for these under-reported sources “do not correctly reflect the op erational practices of today” and, in fact, EPA believes “that emissions from some sources may be much higher than currently reported in the U.S. GHG Inventory.” 236 EPA includes revised emission factors for all of the underestimated sources excep t the categories of crude oil a nd condensate storage tanks and

flares for which “no new reliable data are available.” 237

EPA should avoid flaring as a control option fo r vented emissions, relying on vapor recovery technologies and operating practi ces that minimize vented emi ssions instead. A comprehensive plan to improve the environment through the redu ction in methane emissions should not increase other air pollutant or greenhouse gas emissions . And, in fact, there are several existing international programs aimed at reducing th e use of flaring as a control technique.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 232 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, Appendix I.

233 U.S. Energy Information Administration, International Energy Annual 2006: World Carbon Dioxide Emissions from the Use of Fossil Fuels , Table H.3co2, http://www.eia.doe.gov/iea/carbon.html.

234 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry . Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

235 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.

236 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

237 Id. p. 7.%* 1. Existing International Programs to Reduce Flaring

The following international progr ams demonstrate that mandatory methane reduction programs can be implemented in parallel with program s aimed at eliminating or reducing flaring.

The World Bank’s Global Gas Flaring Reduction (GGFR) Partnership is a public-private partnership started in 2002, with the goal of recovering natural ga s that would normally be sent

to flares or vented to the at mosphere. The GGFR partners incl ude countries, organizations and gas companies, including the U.S. The GGFR developed a Voluntary Standard for Global Gas Flaring and Venting Reduction with the primary objectives of “eliminating routine sources of venting and eliminating or reducing the large so urces of flaring. These goals can be achieved through investment in gas utiliza tion projects that encourage the use of gas that would otherwise

be flared or vented.” 238

Norway is said to be the world’s leader when it comes to restrictions for flaring, and this country is a member of the GGFR. In 1996, the Petroleu m Activities Act was passed, requiring that, “[b]urning of petroleum in excess of the quantities needed for nor mal operational safety shall not be allowed unless approved by the Ministry.” 239 And according to the World Bank, routine flaring is not normally allowed in Norway under any economic conditions. 240

In Alberta, Canada, the Energy Resources Conser vation Board regulates fl aring, incinerating and venting at oil and gas operations under, Directive 060: Upstream Pe troleum Industry Flaring, Incinerating, and Venting. This measure addresses upstream op erations as well as transmission facilities. These regulations and guidelines are broad and sw eeping, and include detailed requirements for flaring, incinerating and venting at many emission points. 241 Directive 060 includes well test flaring, incinerating and venting duration limits; the testing time limit for gas

wells is 72 hours in order to limit emissions from flaring and venting. In addition to the duration limits for testing, the rules require that in-line testing be used when it is economic and feasible. 242
Other sources of emissions, including gas batterie s, dehydrators, compresso r stations, gas plants and pipelines are required to limit flaring, incine rating and venting through such measures as

volume limits. 243!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 238 World Bank, GGFR Partnership, http://web.worldbank.org/WBSITE/EXTERNAL/TOPIC S/EXTOGMC/EXTGGFR/0,,contentMDK:20297378~men uPK:6296802~pagePK:64168427~piPK:64168435~theSitePK:578069,00.html.

239 Norway Petroleum Activities Act No. 72, Section 4-4, 29 November 1996, last amended by Act 19 June 2009, No 104, http://www.npd.no/en/Regulations/Acts/Petroleum-activities-act/.

240 World Bank, Comparison of Associated Gas Flaring Regulations: Alberta & Norway, http://web.worldbank.org/WBSITE/EXTERNAL/TOPIC S/EXTOGMC/EXTGGFR/0,,contentMDK:21840526~men uPK:5221283~pagePK:64168445~piPK:64168309~theSitePK:578069,00.html.

241 “ Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting,” Energy Resources Conservation Board, Alberta, November 16, 2006.

242 Id , p. 21-3.

243 Id. passim

.%" 2. Available Proven Technologies for Flaring

As described above, gas utilization projects can be implemented to eliminate flaring or venting. CARB lists the use of associated gas that woul d otherwise be vented or flared as a BMP. “Instead of venting or flaring, emissions can be reduced by using the associated gas for reinjection into the field for enhanced oil rec overy, or for consumption within the facility.” 244

3. Summary Recommendations for Flaring

EPA should require producers to reduce emissions by instituting a gas utili zation program, such as sending emissions to a vapor recovery unit, rather than flaring a nd venting. While flaring eliminates methane emissions, CO 2 and other air pollutant emissi ons are increased with the practice.

H. Directed Inspection and Maintenance

In addition to methane reduction technologies fo r the numerous emission sources at oil and gas operations, directed inspection and maintenance (DI&M) and other work practices can bring about large methane reductions. As previously desc ribed in this report under the “Compressors” section, DI&M is “a proven management pract ice for cost-effective reduction of methane emissions” that can significantly reduce fugitiv e methane emissions from the gas processing

sector. 245 A DI&M program is not the same thing as EPA’s regulatory leak detection and repair (LDAR) program for reducing VOC emissions. 246 A successful DI&M program includes a baseline survey, cost-effective repairs and subs equent targeted surveys based on findings from the initial baseline survey. In general, the cost of the baseline survey is reportedly recovered in gas savings during the first year. 247 The costs of subsequent surveys are minimized by focusing the components that were identified through the initial baseline study as having a high potential for leakage. A variety of scr eening and measurement devices (e .g., infrared gas imaging, optical remote leak detection, etc.) can be used to obtain accurate leak data and high volume gas samplers can be used to identify and quantify leaks. 248 According to EPA Natural Gas STAR partners, a DI&M program should “target the fi ve categories of equipment components that contribute to the majority of methane losses: block valves, control valves, connectors, compressor seals, and open-ended lines.” 249!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 244 The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

245 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.

246 See , NSPS Subpart KKK - Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing Plants.

247 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.

248 See, e.g ., Directed Inspection and Maintena nce (DI&M) at Gas Processing Pl ants, Innovative Technologies for the Oil & Gas Industry: Product Capture, Process Optimization, and Pollution Prevention, Targa Resources and the Gas Processors Association, July 27, 2006 Hobbs, NM, http://www.epa.gov/gasstar/documents/dim.pdf

249 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf

.%# The use of a DI&M program is also an eff ective means of reducing methane emissions at offshore oil and gas operations. In a paper on offs hore platform methane reduction strategies, the authors analyzed offshore oil and gas methane em issions and control stra tegies to devise an emission reduction strategy for the most sign ificant sources at the lowest cost. The implementation of a directed inspection and maintenance program to target fugitive emissions is one of the recommended strategies for reducing methane emissions in offshore applications. 250 In
addition, both the BLM and CARB list the use of directed inspection and maintenance programs as a BMP for oil and gas sources. 251

1. Existing International Programs to Reduce Methane Emissions Using Directed Inspection and Maintenance

As described above under the “Compressors” secti on of this report, the Ukrainian natural gas transmission company, Cherkasytransgas, implem ented a directed inspection and maintenance program at its compressor stations in 2002 w ith huge success in reducing methane emissions. The last round of repairs, in 2008-2009, redu ced annual methane emissions by 3.5 million cubic meters when the company upgraded the sealant on 174 valves at transmission stations,

distribution stations and linear pipes. 252

2. Available Proven Technologies/Met hods for Directed Inspection and

Maintenance

In addition to the DI&M program described a bove for compressor stations, there are several other promising technologies availabl e to further reduce methane emissions.

Directed Inspection and Maintenance at Gate Stations and Surface Facilities and Gas Processing Plants and Booster Stations

Gate stations are the gas transfer point from transmission pipeline to the distribution system, where the gas is depressurized. The surface facili ties contain heaters and pressure regulators.

“Gate stations and surface faci lities contain equipment compone nts such as pipes, valves, flanges, fittings, open-ended lines, meters, and pn eumatic controllers to monitor and control gas

flow.” 253 Methane emissions from leaking meters and regulating equipment at gate stations and

surface facilities account for around 27 MMcf. Usi ng a DI&M program, operators use a baseline survey of the gate stations a nd surface facilities to direct further inspection and maintenance!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 250 Bylin, Carey et al. for Society of Petroleum Engineer s, “Designing the Ideal Of fshore Platform Methane Mitigation Strategy,” 2010, p. 1.

251 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov

and The California Air Resources Board’s Clearinghouse of non-CO 2 Greenhouse Gas Emission Control Technologies, http://www.arb.ca.gov/cc/non-co2- clearinghouse/non-co2-clearinghouse.htm.

252 Methane to Markets, Oil & Gas Methane Reduction Proj ect Opportunity, “Directed Inspection and Maintenance and Valve Sealant Updgrades,” Cherka sytransgas, Cherkassy, Ukraine, http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1152.

253 Lessons Learned, Natural Gas STAR Partners, “Direct ed Inspection and Maintenance at Gate Stations and Surface Facilities,” October 2003, p. 2, http://www.epa .gov/gasstar/documents/ll_dimgatestat.pdf.%$ measures. Likewise, a DI&M program can also be used at gas processi ng plants and booster stations to reduce methane emissions, which emit an estimated 36 Bcf annually. 254

The same leak detection practices can be utilized at gate stations and surface facilities as well as gas processing plants and booster st ations. Several options for leak screening techniques exist, including soap bubble screening, electronic screening using hand- held gas detectors equipped with catalytic oxidation and th ermal conductivity sensors, orga nic vapor analyzers and toxic vapor analyzers which are also portable devices with hydrocarbon sensors, and portable acoustic

leak detection devices. Leak measurement tec hniques are another important component to a DI&M program. Options for leak measuring in clude: organic vapor analyzers and toxic vapor analyzers used to estimate mass leak rates, “b agging techniques” where the leak or leaking component is covered with a bag or tent to co llect and measure the gas, high volume samplers collect and accurately quantify leak emission rate s, and rotameters and other high volume meters are used to measure large leaks. 255

Directed Inspection and Maintenance Using Infrared Laser Detection

There are several leak detection options under th is category. Live leak imaging cameras provide real time and video recordings of gas leaks using infrared technology to detect otherwise invisible gas. Aerial leak surv eys are performed by helicopter to detect large leaks at remote facilities. There are also infrared laser techniqu es available to use lase r beam to scan methane

leaks. 256 Dynegy Midstream Service, LLP, has had great success in reducing methane leaks using a DI&M program that involves aerial optical su rveying and handheld optical surveying. Using the aerial screening method, Dynegy was able to identify and repair leak s in its pipelines, reducing its annual methane emissions. Dynegy also used handheld optical devices to further

reduce methane emissions. 257

Work Practices

In addition to a DI&M program, Natural Gas ST AR partners have achieved methane reductions through work practice techniques. These work practices include e liminating unnecessary equipment and/or systems, optimizing processes, decreasing the time between fugitive emissions “walking” surveys and requiring improvements in the quality of gas received from producers. 258

3. Summary Recommendations for Dire cted Inspection and Maintenance

EPA should require that operators implement DI &M programs and good work practices in all possible sectors in order to dete ct and reduce methane emissions.!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 254 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants and Booster Stations”, October 2003, p. 1.

255 Id., pp. 3-7.

256 US EPA’s Natural Gas STAR: Directed Inspection and Maintenance (DI&M) Using Infrared Laser Detection, http://www.epa.gov/gasstar/d ocuments/leak_detect.pdf.

257 Natural Gas STAR Partner Update, Fall 2005, p. 2, http://www.epa.gov/gasstar/documents/ngstar_fall2005.pdf.

258 http://www.epa.gov/gasstar/tools/recommended.html#other.%% III. CONCLUSION

Oil and gas extraction and producti on emit significantly large quant ities of GHGs and other air pollutants, and U.S. oil and gas production is expected to grow rapidly. The oil and gas industry’s significant emissions of GHGs and othe r air pollutants and forecasted growth warrant significant action on the part of EPA. Oil and gas production has exploded in places like the Rocky Mountain West, contributing to rising gr eenhouse gas emissions as well as unprecedented air pollution levels.

Given that:

(1) methane emissions from oil and gas devel opment in the U.S. constitute a significant, often underestimated and growing portion of the overall greenhouse gas mix; and

(2) methane is a potent greenhouse gas with a re latively short atmospheric lifetime, making it a prime candidate for impacting climate change in the short-term; and

(3) methane emissions contribute to ozone pollution; and

(4) there are already many proven technologies a nd practices available to significantly reduce methane emissions from oil and gas systems; and

(5) these technologies also offer opportunities fo r significant cost-savi ngs in the form of recovered methane gas;

the need for meaningful perfor mance and operating standards to reduce methane emissions from the oil and gas source category is vital to ensure that increasin g energy production does not occur

at the cost of our nation’s air quality and public health.

EPA has failed to date to implement and mainta in comprehensive standards for the oil and gas sector, despite the fact that our understanding of the adverse impacts of methane emissions on public health and welfare has improved—in partic ular with regard to methane’s significant contribution to climate change and ozone po llution. We urge EPA to issue comprehensive regulations for the oil and gas sector, includi ng standards and practices targeted at achieving meaningful methane emissions reductions. New source standards and operating practices should

be based on the available methane reduction a nd reuse technologies that reflect best demonstrated technologies and practices.

EPA must also adopt comprehensive monitoring, reporting and recordkeeping requirements to support new and revised NSPS for the oil and gas sector. These compliance demonstration techniques should be aligned with the recently finalized reporting requi rements for the oil and gas industries in Subpart W of 40 CFR Part 98. 259 Under EPA’s mandatory reporting requirements, facilities are required to quan tify GHG emissions, including methane emissions, according to a range of methods that include th e direct measurement of emissions, engineering estimation methods ( e.g. , simulation models, engineering ca lculations, original equipment!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! 259 Administrator Jackson signed the rule on November 8, 2010 (Federal Register citation pending).%( manufacturer emission factors, default emission fact ors, etc.), leak detec tion and leaker emission factors as well as equipment count and populati on emission factors. We urge EPA to develop mechanisms to move the newly-established repor ting system steadily towards the most accurate and precise reporting methods possible which will mean moving towards the use of more direct measurement methods and will also mean systema tically and periodically auditing and reviewing the reporting requirements to en sure continuous improvement in the reported data. EPA should commit to a rigorous periodic statistical samp ling and audit program in order to ensure continuous improvement in the data collect ed under the MRR and in the compliance demonstration techniques used in support of NSPS. EPA should establish as part of this rulemaking comprehensive compliance demonstration methods and a plan for periodically updating these methods as improvements in the t echniques for monitoring methane emissions from oil and gas sources occur. Rigorous monito ring techniques that are based on the latest measurement methods will be a key compone nt of NSPS for the oil and gas sector.Megan M. Williams Page 1 of 2 Megan M. Williams

756 Cottage Lane • Boulder, CO 80304 • 303

- 630

- 9620 • megan@sevenfivesix.org

SKILLS

Over 1 0 years of experience working on air quality issues

Technical and Policy areas of expertise • Analyzing and charact erizing air emissions from a variety of air pollution sources • Determining air emissions reduction potentials from control technology scenarios • Reviewing public lands management actions taken under the National Environmental Policy Act (e.g.,

E nvironmental Impact Statements, Environmental Assessments, Resource Management Plans, Travel Management Plans, etc.) • Reviewing new, existing and modified state air quality regulations to determine if they meet federal Clean Air Act requirements • Reviewing proposed federal and state air quality rules and policy to determine if they are as rigorous and stringent as possible • Thorough understanding of the requirements of the nonattainment new source review and prevention of significant d eterioration construction permit programs and Title V operating permit program

Computer skills • Highly proficient in MS Windows and Macintosh • Experienced with numerous standard software packages • Experienced writing programs to perform data analysi s ( e.g. , Excel macros, etc.)

Communication skills • Experienced and thorough in writing both technical and policy documents

• Presented half

- day technical seminars on Indoor Air Quality (to teachers, maintenance staff, etc.)

• A ctive in EPA’s Environm ental Education Council (1998

- 2000)

Completed numerous technical and policy courses offered by the EPA Education and Outreach Program

PROFESSIONAL EXPERIENCE

VARIOUS ENVIRONMENTAL AND GOVERNMENT ORGANIZATIONS Boulder, CO July 2003

– present

Air Qu ality Consultant • Provide a variety of technical and policy analyses related to national, regional and local air quality and energy issues. I nclude s technical and policy research, the production of written documents and

reports , quantitative dete rminations and qualitative assessments

.Megan M. Williams Page 2 of 2

U.S. ENVIRONMENTAL PROTECTION AGENCY Denver, CO
January 1998

– November 2002 Environmental Engineer , May 2000

– November 2002 Air Quality Planning Group • Region 8 lead for nonattainment new source review and prevention of significant deterioration policy development and planning analyses (2001

– 2002) • Reviewed state rules and rule changes related to new source review permitting to determine if they met federal Clean Air Act requirements
• Prep ared official documents to approve or disapprove state implementation plan revisions

• Reviewed PM 10 redesignation requests and prepared official documents for redesignating PM 10 nonattainment areas to attainment • Primary contact for Wyoming air is sues (2001

– 2002) • Compiled EPA

- approved implementation plan for Wyoming

• Co

- led a national working group to re

- examine EPA’s existing policy on redefining “baseline areas” under the Clean Air Act. Planned and hosted national workgroup meeting in D enver to develop criteria for approving baseline area redesignations. Co

- author ed a Technical Memo to EPA’s Office of Air Quality Planning & Standard’s Director proposing use of the new criteria • Received Superior Accomplishment Recognition for technical and policy work on an air quality dispersion modeling analysis of Prevention of Significant Deterioration (PSD) increment consumption in North Dakota and eastern Montana (report available upon request). Regional Indoor Air Quality Pro gram Manager , January 1998

– May 2000 • Managed EPA Region 8’s voluntary Indoor Air Quality Program • Provided technical assistance and outreach to schools, state/local officials and the general public • Initiated and managed research projects to assess i ndoor air quality interventions • Developed and maintained regional IAQ website • Received Superior Accomplishment Recognition for working with schools to voluntarily implement EPA’s Indoor Air Quality Tools for Schools program • Received regional award for Excellence in Environmental Education

WISCONSIN DEPARTMENT OF NATURAL RESOURCES Madison, WI Air Management Engineer , January 1997

– December 1997 • Wrote Title V Operating Permits for sources in northwest Wisconsin ( e.g. , power plants, paper m ills, breweries, and military operations) Air Management Intern , August 1995

– December 1996

(part

- time position in conjunction with the Air Resources Management graduate program at UW

- Madison) • Wrote Title V Operating Permits for sources in northw est Wisconsin • Developed statewide general Title V Operating Permits for small heating units and ethylene oxide

sterilizers

EDUCATION

UNIVERSITY OF WISCONSIN

– MADISON

Institute for Environmental Studies Master of Science, Air Resources Manage ment, December 1996

UNIVERSITY OF COLORADO

– BOULDER College of Engineering and Applied Sciences Bachelor of Science, Applied Mathematics (emphasis Mechanical Engineering), May 1995Cindy S. Copeland

1



### CINDY S. COPELAND

1071 Tantra Park Circle · Boulder, CO 80305 · 303

- 520

- 8248 · cindy copeland 5 @ gmail.com

F OCUS A REA

Outstanding background in environmental policy with a focus on air quality and climate change. Extensive experience with ai r pollution reduction control strategies and scenarios.

S KILLS

Over 10 years of experience working on air quality issues

Technical and Policy areas of expertise

• Analyzing and characterizing air emissions from a variety of air pollution sources

• Determining air emissions reduction potentials from control technology scenarios

• Reviewing new, existing and modified state air quality regulations to determine if they meet federal Clean Air Act requirements

• Reviewing proposed federal and state air quality rules and policy to determine if they are as rigorous and stringent as possible

• Thorough experience with the requirements of particulate matter control through state implementation plan requirements under the Clean Air Act

Communication skills

• Numerous presentatio ns made to state and tribal air quality officials

• Extensive experience in negotiations over highly technical and politicized issues

• Experienced and thorough in writing both technical and policy documents

• Testified at hearings for federal and state rulemak ings

• Experience with press statements and presentations

• Preparing briefings for high level management

E XPERIENCE

Environmental Consultant. (January 2006

- present)

• Extensive policy and technical analyses of federal and state actions concerning air qual ity

and climate

• Represent environmental groups at stakeholder meetings

Program Associate. Environmental Defense, Boulder, Colorado (March 2004

- September 2005)

• Assisted with a variety of policy and technical air quality reviews

• Coordinated and contributed to official organization reports on air quality and climate

• Represented organization in s tate stakeholder and rulemaking processes

• Authored extensive regulatory and technical letters commenting on EPA and state actions

• Testified at s tate and federal regula tory hearings on proposed rule changesCindy S. Copeland

2

Teaching Assistant. University of Colorado, Boulder, Colorado (Spring Semester 2003)

• Instructed two undergraduate sections of a weather lab

• Graded student work products

Environmental Protection Specialist. U.S. Environmental Protection Agency, Region 8, Denver, Colorado (January 1998

- August 2002)

• Acted as the Environmental Protection Agency Region 8 Particulate Matter Program Manager

• Participated in development of air pollution control regulations for Colorado, Montana, Utah, Wyoming, North Dakota, Sou th Dakota and 27 local Tribal governments

• Represented all EPA Regions as the Regional lead on particulates and collaborated with the EPA's headquarters office on policy development and implementation

• Received the EPA Bronze award for being the lead program person on the redesignation of

the Denver PM 10 nonattainment area to attainment/maintenance.

• Presented information updates and issues to State and Tribal environmental divisions, including State Air Directors and State Air Quality Boards

• Presented public outreach on outdoor air, indoor air, and asthma

• Reviewed, evaluated and approved state air quality plan revisions

• Responded to s tate, local and private inquiries to re quirements and implementation of the

Clean Air Act

• Coordinated and conducted internal and external meetings to evaluate, resolve, and implement solutions to issues with technical, legal, and managerial personnel

• Served on the Region 8 agricultural task team

E DUCATION

Master of Science. Universit y of Colorado Environmental Studies Program (2004)

Thesis: Facing Climate Change in New Mexico

Bachelor of Arts. Willamette University, Salem, Oregon (1997) Major: Politics

Minor: Environmental Science

Senior Thesis: Global Climate Change: The Intern ational and United States Responses