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Natural Gas STAR Partner Update

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In this issue:

• Partner Profile—Chesapeake Energy Shares Implementation Experiences
• Prospective Projects Spotlight—Capture Additional Sources with Storage Tank Vapor Recovery Unit
• Methane’s Near-Term Climate Change Impact: Greater or Equal to Carbon Dioxide
• Climate Policy Update
• In the News
• Workshop Summaries
• Upcoming Events
• Natural Gas STAR Contacts

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Partner Profile
Chesapeake Energy Shares Implementation Experiences

Partner company Chesapeake Energy has closely integrated its Natural Gas STAR participation with its core business activities and as a result has realized significant efficiency improvements, methane emissions reductions, and corresponding increases in sales.

Chesapeake is comprised of three operating divisions spanning 17 U.S. states from the east coast to the mid continent. It is the top producer of U.S. natural gas, with an estimated 2009 net production of 2.4 billion cubic feet (Bcf) per day and is the most active U.S. driller with 94 rigs operating as of mid- June, 2009.

Chesapeake co-sponsored the May 14, 2009, technology transfer workshop in Oklahoma City and hosted the event at its headquarters. At the workshop, Chesapeake explained its integrated approach to Natural Gas STAR. Chesapeake has formed a strong and cross-functional implementation team, and this structure has realized a number of successful project types, including a leak inspection and repair program and development of lean burn gas dehydrators.

Approach to Natural Gas STAR

Chesapeake joined the Natural Gas STAR Program and formed an operations driven implementation team in October, 2007. The team consists of an engineer from each operating district as well as representatives from purchasing and its environment, health, and safety department. The implementation team initially reviewed current and past activities applicable to Natural Gas STAR, identified new project ideas, educated field personnel, and set district-specific goals in an effort to establish a highly successful program.

Chesapeake’s implementation team drew from the resources and case studies available on the Natural Gas STAR website. Following careful review of this information, the team identified 21 Best Management Practices (BMPs) currently in use, with many methane-saving activities dating back to 2001. Organizing information on these historical activities for its Natural Gas STAR annual report helped Chesapeake identify ways to expand this work as well as identify new BMPs. Chesapeake’s implementation has also benefited from buy-in at the individual level, where team members have provided initiative and insight while upholding day-to-day obligations.

Use of Apogee Leak Detection System (LDS) for Pipeline Fugitives

Through its involvement with Natural Gas STAR, Chesapeake has seen the benefits of methane leak detection and repair and employs a number of methods to detect fugitives. Chesapeake’s Eastern Division has successfully used the Apogee LDS to survey gathering lines in several operating areas within the Appalachian Basin.

The Apogee LDS unit can be mounted in various vehicle types, including helicopter, pickup, or all-terrain vehicle. It measures gas concentrations by continuously capturing samples of ambient air using a blower. The sample is analyzed with a series of mirrors and lasers to detect any appreciable hydrocarbon gases. Concentration measurements occur approximately 20 times per second with methane, total hydrocarbon, and carbon dioxide measured separately.

Concentration data is relayed to a connected laptop running Apogeedeveloped software that records and graphs the results according to global positioning system (GPS) location. Some of Chesapeake’s lines are in close proximity to other emissions such as coal bed methane releases, and comparison of survey data to other concentration signatures can rule out pipeline leaks. The software’s point of interest function allows tracking of other infrastructure issues such as slips, encroachments, and exposed lines in streams, maximizing the efficiency of each survey and helping Chesapeake eliminate line damage on a more proactive basis.

Chesapeake’s decision to use Apogee LDS was based on a demonstration in December, 2007, and subsequent cost/ benefit analysis for surveying forested and mountainous terrain such as in the Appalachia Basin. Chesapeake purchased a unit for use in the operating districts of its Eastern Division, contracted a flight service company experienced in using the unit, and prioritized pipeline segments to survey.

Chesapeake has thousands of miles of gathering lines in the Appalachian Basin, and segments can be as old as 100 years. Traditional means of inspection and maintenance have been employed successfully within this old gathering system, but these methods are not nearly as efficient as the Apogee LDS proved to be in this forested and mountainous environment.

One Apogee LDS flight in its Southeast District covered 616 miles in 64 hours, while a comparable ground patrol would require 3200 staff hours plus vehicles and fuel. This time savings also expedites leak repair and increases gas savings.

As of May, 2009, Chesapeake estimates a line loss recovery and leak repair of nearly 1500 thousand cubic feet (Mcf) of natural gas per day. At a value of $4 per Mcf, this equates to a gross annual savings approximating $2.2 million. Costs for the survey and repair work include purchasing an Apogee LDS, helicopter rates (approximately $750 per hour), and the leak repair itself.

The next step for Chesapeake is to add gyro stabilized high definition video for leak survey documentation and to verify leak location. Video can also assist in identifying areas to target with additional walking surveys using instruments such as Chesapeake’s FLIR infrared camera.

Employing Lean Burn Glycol Dehydrators

Chesapeake has also examined glycol dehydration from an air emissions standpoint and developed a comprehensive solution. The lean burn system, designed and implemented by Chesapeake, has the combined effect of reducing methane emissions as well as other air emissions such as VOCs and BTEX. It consists of a flash tank separator, 12-volt solar thermostat, low pressure and low temperature burner, Natco oversized still condenser, shortened stack to draw in less air, and the Patton Burner Management System (PBMS). The primary aim of the lean burn system is to minimize air pollutants throughout the glycol dehydration process, and the methane savings are realized in several ways:

• capture of flash gas as fuel,
• reduced fuel gas consumption,
• reduced methane in the combustion exhaust through burner management, and
• use of electronic thermostat in place of the typical continuous bleed gas pneumatic device.

The lean burn system was initially piloted at Chesapeake’s Kovar facility near Marlow, Oklahoma. Based on the successful pilot, Chesapeake has been employing this technology in existing units on a case-by-case basis and as resources allow. All new and planned units are equipped with this technology upon startup.

Capture of flash gas into the fuel system results in a fuel gas savings of approximately 5 standard cubic feet (scf) gas per gallon of glycol circulated for Kimray pumps, or 1 scf per gallon circulated via electric pumps. This typically equates to a range between 14,000 and 166,000 scf per day depending on reboiler size. Reduced fuel gas consumption is also realized with an oversized still condenser and a continuously operating (rather than intermittent) burner that provides VOC and BTEX abatement and heat energy to the fire tube. Thus total external fuel gas needs are reduced by approximately 36,000 scf per day (with typical incinerator usage). For a new burner installation, incremental costs are $100 to $500 excluding the PBMS. The cost to upgrade/retrofit an existing burner is $500 to $1,200. The PBMS costs $7,500 installed. Payout will vary by project and is calculated for each unit under study.

Additional benefits of the Chesapeake lean burn dehydrator are: continuous destruction of VOC and BTEX, less thermal stress on the system due to lower burner temperatures, lower noise (40 to 60 decibels), eliminating the need for purchased electricity through use of 12 volt solar power, and convenient telemetry management through PBMS.

Conclusion

Chesapeake’s structured approach to methane emissions reductions has resulted in a number of cost-effective innovations, including aerial leak detection and glycol dehydrator optimization.

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Prospective Projects Spotlight

Capture Additional Sources with Storage Tank Vapor Recovery Unit

Oil and natural gas facilities, both upstream and downstream, share similar types of methane emissions sources such as vents and blowdowns. These releases may individually go unnoticed but collectively represent a significant product loss and often offer an economic capture opportunity. Emissions from tanks can be captured with a vapor recovery unit. This article describes a project concept that extends vapor recovery duty solely from tanks to these other methane emissions sources.

Operators have explored capture projects for discrete sources ranging from open-ended lines to compressor blowdowns; this project concept explores the versatility of vapor recovery units to accommodate the combination of such emissions that may be present at a typical facility. The potential savings from capturing source types that may be present at any type of facility is estimated to be a minimum of about 4400 Mcf/year, an amount sufficient to accommodate a vapor recovery unit or spare capacity of existing units.

Background: Methane Emissions

In Exhibit 1 below, Natural Gas STAR has compiled a list of candidate methane emissions sources for additional vapor recovery common to a variety of facility types (from production through transmission) along with typical emission factors. This list can be used to estimate the vapor recovery unit capacity and the magnitude of a location’s potentially recoverable methane emissions.

Extend Vapor Recovery to Capture Additional Methane Emissions: Major Considerations

Capture of emissions from these source types must address several operating requirements. First, a vapor recovery unit is required, either as a new installation or as the spare capacity of an existing unit. Each emissions source should be routed to oil/condensate tank ullage as a flow rate buffer for the vapor recovery compressor: the tank space and its working pressure (a few ounces per square inch) will provide some level of moderation to unsteady emission rates and protect the compressor from excessive on/off cycling.

The ability to capture blowdowns of compressors, vessels, or fuel gas systems with this project may require a change in operating practice. A blowdown lasting on the order of 1 to 5 minutes may need to occur as a more gradual bleed down through a restriction orifice so that a gas surge cannot overwhelm the vapor recovery compressor and activate overpressure protection in the tank.

The vapor recovery compressor must also be designed for a location’s specific emissions sources. An analysis of the steady and the intermittent emissions sources is required for proper compressor capacity and turndown ratio or to establish suitability of an existing vapor recovery unit. Existing vapor recovery installations are also constrained by available spare operating time since vapor recovery compressors may not be designed for near-continuous operation to capture steady emissions sources.

Depending on the emissions sources to be captured, gas quality may also be a factor in vapor recovery compressor selection. Sources such as glycol dehydrator reboiler vent gas may require a still condenser to remove water vapor.

Sources such as compressor seals or rod packing may require a coalescer or filter to remove oil mists, depending on the vapor recovery compressor type.

Sources such as pigging emissions may also require similar treatment of the gas stream to limit flow rate and/or remove liquids.

This project must also consider the differing pressures of each emissions source. Higher pressure streams such as from blowdowns or casinghead gas will require the addition of a flow/ pressure restrictor orifice and shutoff valve before the stream enters the tank or joins other low pressure sources. Other streams such as compressor seal degassing or pneumatic pump discharges cannot accommodate significant backpressure.

Including gas-driven pneumatic devices into this type of capture project will require additional design work and consultation with vendors for a practical way to connect an instrument’s gas discharge to piping so that it can function properly with a slightly variable discharge pressure.

Each methane emissions source to be captured must be sufficiently proximate to a vapor recovery unit because the low pressure streams limit the gas flow distance, and additional piping can be a significant expense.

Example Implementation and Economics

To illustrate this project concept, a surrogate facility was created and its emissions estimated. Exhibit 2 depicts a surrogate capture project with several types of methane emissions sources broadly applicable to many oil and natural gas facilities, the equipment count for each source, and the emissions rate.

Units are provided as Mcf methane/year as a consistent basis for continuous and intermittent emissions, since intermittent emission factors from literature are aggregated to an annual basis to reflect blowdown frequencies. Total gas to be captured from continuous and intermittent sources is 4382 Mcf/year, or about $30,700/year at $7/Mcf. Thus, 12 continuous sources and 2 intermittent sources are readily identifiable, in close proximity, and constitute a significant revenue stream.

Exhibit 2 shows example economics for the surrogate facility at different gas values. The gas volume is assumed to be captured by existing vapor recovery unit capacity; typical vapor recovery unit capacities range from 10 to over 500 Mcf/day (3,650 to 182,500 Mcf/ year). For scoping purposes, piping is estimated at $15/foot installed cost for 2 inch diameter lines, with each source requiring a run of 150 feet. For 14 emissions sources to capture, piping cost is $31,500. Incremental compressor power cost is represented as the fuel gas required and is determined from vapor recovery unit product literature to be 715 Mcf/year or $5,000 at $7/Mcf.

Many natural gas facilities have equipment sized for initial rates, and throughput declines over time. The decline may move main line compressors out of their optimal performance ranges or require that gas be recycled to maintain sufficient feed rate. Capture of additional methane emissions sources can help eliminate this inefficiency by collecting new gas sources.

Conclusion

Oil and natural gas facilities from the wellhead to the compressor station contain a variety of methane emissions sources that can be routed to vapor recovery after confirming their emissions rates and proximity. Collectively, these sources represent a methane emissions capture project with potentially significant returns on the investment and environmental benefit.

We would like to hear from you on your implementation experiences. If your company has already implemented this project or wishes to further explore this concept further, please contact Jerome Blackman [Blackman.Jerome@ epa.gov or (202) 343-9630], EPA.

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Methane’s Near-Term Climate Change Impact:
Greater or Equal to Carbon Dioxide

Two estimates show that methane emissions have a climate impact similar to carbon dioxide when considered over a short-term time horizon. Methane’s long term atmospheric effects over a 100 year period have been a basis of analysis in the past. Studies on short-term climate change impact reinforce the significance of methane and its role as a powerful greenhouse gas.

The Intergovernmental Panel on Climate Change (IPCC)’s Fourth Assessment Report examines methane’s potential to contribute to climate change. Global Warming Potentials (GWPs) are one measure of climate change impact. Scientific modeling of GWPs is based on chemical persistence in the atmosphere and radiative effects, and GWPs are dependent on factors such as the time horizon under study, the type of greenhouse

gas, and its atmospheric lifetime. The Fourth Assessment Report estimates that the 20-year GWP of methane is 72, more than three times higher than the 100- year GWP. This means that methane is 72 times more effective at trapping heat in the atmosphere when compared to the same mass of carbon dioxide over a 20 year period.

GWPs are derived from another measure of overall climate change impact, radiative forcing (RF). Methane’s RF is expressed by the change in the net irradiance in the atmosphere due to a change in the concentration of methane. The Fourth Assessment Report examines the separate RF components associated with each long-lived greenhouse gas. Over the 20 year time horizon following year 2000 emissions, methane’s impact is modeled to be approximately equal to that of carbon dioxide (see the top two bars in Exhibit 1). This is a significant finding given that globally, methane is only about 1 percent of greenhouse gases by mass while carbon dioxide is about 99 percent. This means that targeting the fewer methane emissions for reduction can have substantial near term climate change results.

Similarly, a study completed for the Pew Center on Global Climate Change by the Massachusetts Institute of Technology modeled a scenario of 50 percent emissions reductions in methane (compared to a “business as usual” scenario) by 2050. The methane case results in a slightly greater decrease in temperature for this short-term case (see the first and third bars in Exhibit 2).

In cases depicting a longer time frame, maintaining the 50 percent reductions in both carbon dioxide and methane through 2100 results in carbon dioxide having a larger temperature effect, though methane’s climate change impact over this time horizon is still significant.

Together, IPCC and Pew/MIT studies show that in addition to the economic benefits of methane savings, reducing methane emissions may have powerful effects on climate change goals, especially in the near term. For more information on proven methane-reducing project opportunities, visit the Natural Gas STAR Web site at epa.gov/gasstar.

 

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Climate Policy Update

Below is a summary of recent climate policy developments related to the natural gas industry and methane emissions reductions.

Economic Analysis of Draft Waxman-Markey Bill

On June 26, 2009, the United Sates House of Representatives passed the American Clean Energy and Security Act. The draft bill was released on March 31, 2009, by Henry A. Waxman of the Energy and Commerce Committee and Chairman Edward J. Markey of the Energy and Environment Subcommittee and Select Committee on Global Warming. At the request of the Committee, EPA conducted a preliminary economic analysis of the draft bill. EPA’s analysis focused on the Title III market-based emission reduction program and did not address all of its provisions. Key findings of the core analysis are made on energy efficiency, renewable energy penetration, carbon capture and storage technology, and emission allowances. More information on the draft bill and EPA’s analysis can be found at epa.gov/climatechange/ economics/economicanalyses.html#wax.

Method 21 Alternative Work Practice – Elements of Interest

The winter 2008 Partner Update reported on the Alternative Work Practice (AWP) for Method 21. The AWP allows use of gas imaging instruments for monitoring of volatile organic compound fugitive emissions. Below are several elements of interest in the AWP; refer to the code of federal regulations parts 60, 63, and 65 for the entire AWP final rule.

• A daily instrument check is required to confirm that the gas imaging instrument can detect leaks at the necessary sensitivity level. For the check, the instrument is to be located a distance away from a measured gas release, not to be exceeded during the leak survey. The gas release through a flow meter must be viewable by the instrument and recorded. For bi-monthly monitoring, the measured gas release rate is 60 grams per hour. The daily instrument check is to be repeated for each instrument configuration used in the monitoring, such as for each lens type used.
• During monitoring, the instrument must provide an image of both the leak and the leak source.
• When the AWP is used, equipment must also be monitored annually using Method 21. Subsequent Method 21 monitoring must be conducted every 12 months from the initial period.
• AWP recordkeeping includes a video with time and date stamp of leak survey results where each piece of regulated equipment can be identified. Records for the daily instrument check include the distance, flow meter reading, and video. Additional records include the equipment chosen to be surveyed under the AWP, the chosen detection sensitivity level based on monitoring frequency, and the analysis to determine the piece of equipment in contact with the lowest mass fraction of chemicals that are detectable.

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In the News

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

In mid-April, EPA finalized and submitted the 2009 U.S. Greenhouse Gas Inventory to the United Nations Framework Convention on Climate Change (UNFCCC). The inventory is prepared annually by EPA, in collaboration with other federal agencies, and tracks annual greenhouse gas emissions. This inventory of anthropogenic greenhouse gas emissions provides a common and consistent mechanism through which parties to the UNFCCC can estimate emissions and compare the relative contribution of individual sources, gases, and nations to climate change. As reported in the inventory, overall emissions increased by 1.4 percent from 2006 to 2007. 2007 methane emissions from natural gas systems are reported as 104.7 teragrams carbon dioxide equivalent and decreased by 0.1 percent from 2006 to 2007. For this reporting year, key changes to the natural gas systems sector included updating activity factor calculation methods. The inventory reflects 47.8 teragrams carbon dioxide equivalent of methane emissions reductions by Natural Gas STAR Partners in 2007. 2007 methane emissions from petroleum systems are reported as 28.8 teragrams carbon dioxide equivalent and increased by 2 percent from 2006 to 2007. Calculation methodology remained the same as the previous year’s inventory, though activity data was updated for the 2007 reporting year.

For more information the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007 is available at epa.gov/climatechange/emissions/ usinventoryreport.html.

Two Environmental Technology Verification (ETV) Programs to Test Airborne Leak Detection

The United States EPA Environmental Technology Verification Program (ETV) Advanced Monitoring Systems (AMS) Center and ETV Canada are planning joint verification testing of airborne natural gas leak detection technologies. The test will involve field testing under a variety of conditions. Test collaborators are being sought. A teleconference will be conducted on Monday, July 20, 2009, from 1:00 to 3:00 p.m. eastern

time, to present an outline of the test design to interested technology vendors. Although the focus of the call is joint U.S./Canada verification test design, vendors interested in U.S.-only or Canada-only verification are also welcome and can be considered for verification. Please contact

Ken Cowen (cowenk@battelle.org), Battelle, at (614) 424-5547, or Mona El Hallak (melhallak@etvcanada.ca), ETV Canada, at (905) 822-4133 ext. 23 , with questions or interest in participating on the teleconference by no later than Wednesday, July 15.

The Federation of Indian Chambers ofCommerce and Industry Launches Methane to Markets India Web Portal

Project network member Federation of Indian Chambers of Commerce and Industry (FICCI) has launched a web portal of India’s Methane to Markets resources and projects. The website includes India sector profiles, Methane to Markets projects, methane emissions reduction technologies, case studies, and events, and it is available at methanetomarketsindia.com/index.html.

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Workshop Summaries

Methane to Markets
Partnership-wide and Steering Committee Meeting
January 27 to 29, 2009
Monterrey, Mexico

Methane to Markets began 2009 with a partnership-wide meeting that brought together diverse organizations for the purpose of identifying and developing methane emissions reduction projects. The meeting began with tours of active oil and gas, agricultural, coal, and landfill project sites that showed the successful partnership between member countries and experts from the Methane to Markets project network. The oil and gas tour visited a modern gas processing plant operated by PEMEX. The second day of the meeting included technical workshops discussing the latest advances in methane capture and use. Topics discussed during the oil and gas technical workshop included methods for reducing emissions from production wells, oil and condensate storage and holding tanks, reciprocating and centrifugal compressors, and natural gas transmission pipelines. The oil and gas technical program also covered ideas for financing emissions reduction projects through carbon markets. The last day of the meeting included steering committee and technical subcommittee meetings. For more information, including a full agenda and presentations visit methanetomarkets.org/events/past.htm.

2009 ARPEL Conference
April 23 to 24, 2009
Punta del Este, Uruguay

Gas Companies in Latin America and the Caribbean, held its Annual Conference, “Sustainable Development – The Role of the Oil and Gas Industry in Latin America and the Caribbean,” this spring in Punta del Este, Uruguay. The conference was an opportunity to promote dialogue between governments, goods and services suppliers, financial entities, consulting companies, universities, and nongovernmental organizations about the inter-relation among economic, environmental, and social issues and what it means to address them at the strategic, operational and management level. EPA presented infrared optical leak detection technologies for methane emissions detection in a technical panel on new and emerging technologies. For more information, visit the ARPEL Conference web site at conferenciaarpel.com.

Natural Gas STAR
Producers Technology Transfer Workshop
May 14, 2009
Oklahoma City, Oklahoma

Cosponsored by Chesapeake Energy, Devon Energy, and EPA, this workshop was attended by over 150 industry representatives. Topics discussed included Chesapeake Energy and Devon Energy’s experience in methane emission reductions, as well as a discussion of Natural Gas STAR producer best management practices. In addition, EPA staff gave an update presentation on the Mandatory Greenhouse Gas Reporting Rule. Presentations can be found at epa.gov/gasstar/workshops/ techtransfer/index.html.

Natural Gas STAR
Producers Technology Transfer Workshop
February 27, 2009
Charleston, West Virginia

This half-day workshop, held in conjunction with the Interstate Oil & Gas Compact Commission’s Source Reduction Training, focussed on methane emissions reduction opportunities for small and independent producers. Presentations can be found at epa.gov/gasstar/workshops/ techtransfer/index.html.

CDM Methodologies for Oil and Gas Industry Projects Workshop
May 6, 2009
Washington, DC

Thirteen experts, including representatives from the Methane to Markets Partnership, World Bank’s Global Gas Flaring Reduction (GGFR) initiative, the oil and gas industry, and Clean Development Mechanism (CDM) project developers, met with the purpose of discussing the relatively low representation of oil and gas industry approved methodologies in the CDM program and ways to help reduce barriers. The workgroup members agreed that most important strategies for overcoming barriers to CDM project development are methodology improvements and CDM Board member education. Moving forward, the workgroup will work primarily towards advancements in these areas. Building on input from this meeting and a similar meeting held in Paris in April, the workgroup will develop a work plan, timetable, and institutional framework, to be further discussed at the Carbon Expo in Barcelona, Spain on May 27 to 29.

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Upcoming Events

Below are scheduled Natural Gas STAR Program events. For updates and further information, visit epa.gov/gasstar/workshops or contact Suzie Waltzer (Waltzer.Suzanne@epa.gov) or (202) 343-9544. Additionally, are you a Natural Gas STAR endorser and have an event you would like listed here? Please notify Natural Gas STAR.

Technology Transfer Workshop & Subcommittee Meeting
Co-Hosted by Methaneto- Markets, U.S. EPA, and Environment Canada
Lake Louise, Canada
Sept. 14 to 16, 2009

Production and Processing Workshop
Sponsored by the Montana Petroleum Association
Billings, MT
Aug. 31, 2009

Annual Implementation Workshop
San Antonio, TX
Oct. 19 to 21, 2009

World Gas Conference 2009
Buenos Aires, Argentina
Oct. 5 to 9, 2009

Methane to Markets Partnership Expo
New Delhi, India
Mar. 2010

 

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Natural Gas STAR Contacts

Program Managers

Jerome Blackman (blackman.jerome@epa.gov)
Phone: (202) 343-9630

Carey Bylin (bylin.carey@epa.gov)
(202) 343-9669

Roger Fernandez (fernandez.roger@epa.gov)
(202) 343-9386

Suzie Waltzer (waltzer.suzanne@epa.gov)
(202) 343-9544

Natural Gas STAR Program
U.S. Environmental Protection Agency
1200 Pennsylvania Ave., NW (6207J)
Washington, DC 20460

For additional information on topics in this Update, please contact Jerome Blackman.

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