Partner Update
Summer 2010
ETA POLLUTION PREVENTER
NaturalGasA
EPA POLLUTION PREVENTER r
SAVE THE DATE
2010 Annual Implementation Workshop
November 1 to 3, 2010 Ritz Carlton New Orleans, Louisiana
The Annual Implementation Workshop is an opportunity for information exchange about
cost-effective methane emissions reduction methods. It will bring together Natural Gas
STAR domestic and international Partners and industry experts to discuss the latest
technologies and practices. This year, the workshop will feature an expanded exhibitor area
in addition to the optional facility site tours highlighting various methane emissions
detection, measurement, and reduction methods at nearby operating facilities.
Conference updates, registration, and hotel information will be posted to the Natural Gas
STAR web site: epa.gov/qasstar/workshops.
For information, please contact Jerome Blackman (blackman.ierome@epa.gov).
Prospective Projects Spotlight:
			 Valve Maintenance and Leak
Mitigation
This article describes a project to begin or enhance the use of cleaners, lubricants, and
sealants on valves as part of their maintenance schedules. Valves can be a significant source
of methane emissions as scars on seating surfaces develop and create unintended pathways
across the valve, causing fugitive emissions. Valves in natural gas service are more likely to
exhibit leakage problems than valves in crude oil service for the simple reason that the oil itself
is self-lubricating and dry natural gas is not. The emissions that can result are leakage across
shut valves or venting of the line to take it out of service for valve replacement.
Major valve leakage can be mitigated by implementing a regular valve maintenance program as
a cost-effective alternative to valve replacement. This can apply to mainline valves as wells as
compressor blowdown and isolation valves. This article will give additional background on valve
leaks, describe valve maintenance and repair, and provide example implementation economics.
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Background: Methane Emissions from Valve Leaks
Exhibit 1 below shows a list of valves commonly encountered at natural gas facilities along with
average methane emissions factors. Blowdown and unit valves account for a majority of
emissions since they are associated with large gas volumes and have long service lives.
Exhibit 1: Average Fugitive Emissions Factors for Equipment Leaks from Compressor Station
Components		

Emission
source
Typical emission factor
(Mcf/Year/Component)1
a>
c
_i «m
_ a>
Unit Valve
3,566
der Main
Pressur
Blowdown Valve
207.5 (±171.4)
Open-Ended
Line (OEL)
81.8 (±79.6)
c
3
Ball/Plug Valve
5.33 (±3.71)

Gate Valve
0.61 (±0.43)
Jnder Fuel
is Pressure3
Open-Ended
Line (OEL)
2.53 (±2.19)
Ball/Plug Valve
0.51 (±0.37)
—/TO
I o
Gate Valve
0.43 (±0.36)
Source: EPA Natural Gas STAR. Lessons Learned: Directed Inspection and Maintenance at Compressor Stations.
October 2003. page 10.
1 Emission factors with associated 95 percent confidence intervals.
2Main line pressure ranges from 500 psig to 1,000 psig.
3Fuel gas pressure is typically 70 psig to 100 psig.
Regular Valve Maintenance and Repair: Major Considerations
Emissions prevention and reduction from valves can be accomplished through a combination of
routine preventative maintenance and repair with application of cleaner, lubricant, and sealant.
A major advantage of this project is that the valves can be maintained and repaired while online
and under pressure, eliminating the costs associated with shutting down a line for valve
replacement. Repair and maintenance practices are applicable for all valve sizes and types—
from small valves (-1/2") to the larger transmission valves (-60") and for ball, plug, or gate
valves
Requirements
In general, this project has only material and manpower requirements. No operating or process
changes are required to implement regular valve maintenance, and it can be incorporated into
routine operator activities. Materials required include cleaner, lubricant/sealant, heavy grade
sealant, injection guns, stem packing, fitting caps, an injection fitting adaptor kit, and an air
compressor. For a single large pipeline valve, the manpower required for this project is up to
three operators (10 hours each) for the first year and one operator (10 hours) in subsequent
years.
Description
Gas leaks occur in three main locations on the valve: 1) sealing seat (internal leakage), 2) stem
packing, and 3) valve fittings. These emission sources can be seen in Exhibit 2 of a typical ball
valve. In the diagram, the ball valve is in the closed position, with the through-port
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perpendicular to the axis of flow. In this position, gas should not be passing through the valve,
but often times it escapes through the labeled leak points.
Pressure relief
valve r-
Stem seal
1 fitting or plug
Leak point:
stem packing
Leak point:
sealing seats
Exit
Conduit
Entry
Conduit
Through
Port
Leak point:
valve fittings
Leak point:
sealing seats
fcr
Plug
Internal check
Seat sealant
injection fitting
Body vent
fitting
Exhibit 2: Typical ball valve configuration with seat rings and stem seals.
Source: Chisholm, Hugh arid Chisholm, Bruce. Sealing system helps detect leaks, curb fugitive emissions. Pipe
Line & Gas Industry, August 1999. pgs. 39 to 47.
1)	Valve seat. A lubricant or sealant is applied to one or both of the valve's sealing seats, to fill
the small gaps caused by corrosion or debris introduced during hydrostatic testing and then
normal operation. This is done by loading an injection gun and injecting lubricant/sealant into
the valve under pressure via the seat sealant injection fitting. Sealant injection fittings can be
installed either during a valve's manufacture or via a retrofit The injection procedure is similar
for ball, plug, and gate valves, differing in the amount of lubricant/sealant required. Preventative
maintenance requires the routine use of lubricant on valves, ideally every time they are
operated. This is especially important for dry gas pipelines where the gas continuously
weathers the previously-applied lubricant. Repair can include a combination of a lubricant and
sealant application. Heavy-grade sealant is used for emergency leaks and annual full service
maintenance, where it is recommended a valve be cleaned, re-lubricated, and sealed.
2)	Stem packing. Stem packing leakage can be managed cost-effectively by revisiting and
optimizing existing maintenance activities. Gate valves generally require a braided square rope
packing in the valve stem. Plug valves and some gate valves use a viscous liquid stem packing
with the consistency of putty. Ball valves generally do not require stem packing as they are
sealed with an o-ring. However, if leaks are detected then lubricant/sealant can be injected
through the stem fitting or the stem re-packed.
3)	Valve fittings. Valve fittings are another source of emissions and generally occur due to
improper installation or improper injection techniques. Examples of common fittings include
sealant injection fittings, pressure relief valves, valve bonnet flanges, body vents, and valve
flanges. Leaking fittings can be tightened while a pipeline is in service but only repaired when
the valve is isolated and no longer under pressure. Repair of one deficient fitting does not
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justify the shutdown of entire pipeline segment, so a method previously reported to Natural Gas
STAR can be used—leak locks. These are check valves that attach to the injection fittings to
prevent leaks until repairs can be made via a scheduled shutdown.
Exhibit 3: Field evaluations and repair of mainline ball valves.
Source: Chisholm, Hugh and Chisholm, Bruce. Sealing system helps detect leaks, curb fugitive emissions. Pipe
Line & Gas industry. August 1999. pages 39 to 47.
Example Implementation and Economics
Below is an example to illustrate the cost-effectiveness of routine valve maintenance. The cost
of valve replacement is reported along with the cost of a routine valve maintenance and repair
program for a 36-inch mainline ball valve. Cost advantages of maintenance and repair are
avoidance or deferral of valve replacement plus avoided methane emissions.
Valve replacement
A new 36-inch ball valve with an actuator will cost approximately $250,000 straight from the
manufacturer. Specialized equipment must be used to then transport and install the new valve.
There is a great deal of manpower associated with transportation and installation as well,
especially since a majority of pipeline valves are in remote locations. Companies must also
account for costs associated with excavating the old valve before installing a new valve. Total
installation costs can be anywhere from $200,000 to $250,000 per valve site and will only
increase with the valve's size and the site's inaccessibility.
When the new valve is being installed the entire contents of the process unit or pipeline
segment (between two unit valves) is depressurized which results in methane emissions and
product loss. Depending on how the gas is valued and if this replacement is performed during a
planned shutdown, this cost can range from $50,000 to $100,000 per valve site. Therefore, the
total costs for valve replacement range from $500,000 to $600,000. This cost alone is almost
always higher than the cost of maintenance.
Valve repair
For the same 36-inch mainline valve, the costs to consider are capital and labor/maintenance.
Initial capital costs include: injection equipment, a fittings adapter kit (with leak locks), 20 lbs of
cleaner, 20 lbs of lubricant/sealant, 20 lbs of heavy-grade sealant, and air compressor.
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Altogether these total to be approximately $20,000, for the injection instrument, adapter kit, and
air compressor. Annual material costs are for refills of cleaner, lubricant, and sealant. 20 lbs of
each will last approximately one year per large valve, assuming maintenance is performed
every three weeks. Annual labor and maintenance is estimated to be $1,600 per valve for a
three-person team, spending 10 hours per person.
	Exhibit 4: Summary of major project costs and economics	
Project Summary: Regular Valve Maintenance & Repair of a Single 36-
inch Mainline Ball Valve
Operating Requirements
•	Evaluation of existing leaks
•	Repair materials and labor
•	Continued monitoring and maintenance
Capital Costs (per valve)
$1,0001
Annual Labor & Maintenance
Costs (per valve)
$1,600'
Methane Saved (per valve)
Internal leakage: 207.5J Mcf/year
Stem packing: 924 Mcf/year
Fittings (4): 2.43 Mcf/year
Avoided blowdowns: 322.5s Mcf/year
Gas Price per Mcf
$3
$7
$10
Value of Gas Saved (per
valve)
$1870
$4370
$6245
Payback Period in Years
3.8
0.4
0.2
Approximate capital cost per valve, assuming the $20,000 cost for injection instrument, adapter kit, and air
compressor is shared amongst 20 valves.
2Annual labor and maintenance costs consist of refills for cleaner, lubricant, and sealant as well as 10 hours of labor.
3EPA Natural Gas STAR. Lessons Learned: Directed Inspection and Maintenance at Compressor Stations. Exhibit
4. page 10.
4EPA Natural Gas STAR. Lessons Learned: Directed Inspection and Maintenance at Gate Stations and Surface
Facilities. Exhibit 6. page 11.
5 EPA Natural Gas STAR. Lessons Learned: Reducing Emissions When Taking Compressor Off-Line. Exhibit 2.
page 5.
Gas savings from leaks and avoided blowdowns range from a few hundred cubic feet per year
to several million cubic feet per year, depending on the size of the valve and length of the
pipeline segment. In nearly all cases the payback period is less than one year. In emergency
repair cases where heavy grade sealant is injected to avoid an unplanned shutdown, hundreds
of thousands of dollars can be saved by preventing a large diameter valve from having to be
replaced. The highest cost savings are in the prevention of line shut down. Past projects have
shown that by saving just one valve in a critical location a company can afford a complete valve
maintenance program, including training and capital equipment costs.
Conclusion
Re-visiting and optimizingvalve repair practices can be cost-effective, helping generate revenue
from avoided emissions and avoided replacement costs. 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, please contact Scott Bartos [bartos.scott@epa.gov or
(202) 343-9167],
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Technology Spotlight:

¦ J^I'¦ MWjMsWig11MngClean Development Mechanism Flare and
Vent Reduction Projects
The Winter 2009 Partner Update described developments associated with the Kyoto Protocol's
Clean Development Mechanism (CDM) project methodology to reduce fugitive methane
emissions at gas transmission stations, AM0023. In addition to this approved methodology,
there are a number of others applicable to the oil and gas industry including AM0009, AM0037,
AM0043, and AM0077. AM0009 addresses the recovery and utilization of flared or vented gas
from oil wells, and it has the greatest number of implemented projects. This article focuses on
AM0009 and summarizes how it is important to help reduce emissions from the oil and gas
CDM is an arrangement under the Kyoto Protocol that allows industrialized countries (Annex I
countries) to achieve compliance with their reduction commitments. Through this mechanism,
Annex I countries can establish emission reduction projects in developing countries as an
alternative to more expensive emission reductions in their own countries. This is designed to
allow for global GHG emission reductions at a lower global cost. After a validation and
registration process, certified emission reductions (CERs) are issued where 1 CER = 1 tonne of
carbon dioxide equivalent (tC02e).
Each CDM project undertaken is based on an Approved Methodology (AM) that describes a
specific procedure for obtaining CERs. In particular, AM0009 is a methodology of specific
relevance to the activities of Natural Gas STAR Partners. It outlines the "recovery and
utilization of gas from oil wells that would otherwise be flared or vented." AM0009 describes a
procedure for companies looking to recover and utilize associated gas and/or lift gas and
transport it to treatment facilities and then markets.
The methodology first establishes the requirements to start a new project activity. It then lays
out a baseline procedure by defining project boundaries and giving a stepwise process for
demonstrating additionality. The quantity of reductions over the life span of the project equates
to the total amount of CERs.
There are currently seven AM0009 projects around the globe that have been registered by the
CDM Executive Board (EB). An additional nine AM0009 projects are also at validation, which is
part of the approval process. The registered projects are estimated to reduce 8,207,000
tC02e/year. By 2012, it is estimated that the seven AM0009 projects will have accumulated
42,464,000 tC02e.
One example AM0009 project is the Rang Dong oil field in Vietnam. This CDM project has
been in effect since December 2001 and generates 677,000 tC02e/year in emissions
reductions. By the end of its 10-year life span, it will have attained 6,770,000 total CERs.
Another AM0009 project currently undergoing validation is the Guneshli oil and gas field in
Azerbaijan. It is projected to save 1,114,000 tC02e through 2012 by recovering and
transporting previously vented associated gas.
Assuming a CER price of $10, over $424 million in revenue will have been generated from the
seven registered AM0009 projects alone at the close of 2012. These projects illustrate one of
the several ways that methane emissions can be valued and make capture/reduction projects a
productive investment of capital.
industry.
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More information on AM0009 is available at
cdm.unfccc.int/methodoloaies/DB/42X5O8TG3PI07L6WX4YVQNV4ZB12X9/view.html
The list of approved methodologies is available at
cdm.unfccc.int/methodologies/PAmethodologies/approved.html
More information on the use of AM0009 at the Rang Dong oil field in Vietnam is available at
cdm.unfccc.int/Proiects/DB/DNV-CUK1133472308.56
More information on the use of AM0009 at the Guneshli oil and gas field in Azerbaijan is
available at
cdm.unfccc.int/Proiects/Validation/DB/0XPKHKKIRQAEH8U9ZFLFHKGQ6HTY7N/view.html
Climate Policy Update:
| Approval of a New Carbon Offset
Methodology for the U.S. Oil and Gas Industry
On March 29, 2010 the American Carbon Registry (ACR) announced its approval of the first
carbon offset methodology in the U.S. that applies to methane emissions in the oil & gas
industry. Specifically, this methodology will allow oil & gas companies to generate carbon
credits by retrofitting or replacing existing high-bleed pneumatic devices with low-bleed
alternatives. This article summarizes the new methodology.
The conversion of high-bleed pneumatics to low-bleed has been a gradual process in the oil &
gas industry. Voluntary replacements and retrofits have been encouraged by the Natural Gas
STAR Program since its inception because high-bleed devices are among the largest sources of
vented methane in the oil & gas industry. As of April 2010, Natural Gas STAR Partners have
saved 22.7 billion cubic feet (Bcf) by converting high-bleed devices to low-bleed1.
Although economically favorable, progress has been hampered largely because of companies'
affinity for the status quo and a "if it's not broke, don't fix it" mentality. Reasons stated in the
baseline methodology report include: high-bleed devices already work well, the complexity of
company-wide retrofits, and the smaller economic value of the retrofits compared to other
investment opportunities.
The ACR's approval of a pneumatic device methodology is aimed to provide more incentive for
U.S. companies previously unwilling to convert their high-bleeds. Earning carbon credits will
now allow companies to profit from the combined revenue streams of selling credits and the
economic return of converting pneumatic devices. The new methodology only focuses on the
retrofit of existing high bleed infrastructure and specifically excludes new well-sites installation
where the use of low bleed controllers can be considered common practice.
Devon Energy Corporation and Verdeo Group, Inc. worked collaboratively to develop this new
ACR methodology. It is the first in a suite of methodologies being developed that focus on
reducing methane emissions from oil and gas infrastructure. Its approval has encouraged
Devon to undertake a company-wide retrofit of its high-bleed pneumatic devices.
1 EPA. 2010 U.S. Greenhouse Gas Inventory Report, epa.gov/climatechange/emissions/usinventoryreport.htnil.
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The ACR is a non-profit, voluntary U.S. carbon market registry. Many of its members are
Fortune 500 companies as well as mission-driven institutions and non-profit organizations.
Companies that enroll new reduction projects in the ACR are called Project Proponents.
Members of the ACR have access to its registry and technical services, where the ultimate goal
of the ACR is to provide transparency and clear ownership
Carbon offsets are measured in emission reduction tons (ERTs, where 1 ERT = 1 tonne carbon
dioxide equivalent [tC02e]) and are granted through company projects that follow the structure
of a selected ACR standard or methodology. Similar to the Clean Development Mechanism
(CDM) under the Kyoto Protocol, companies can create emission reduction projects based on
established methodologies, or they can modify/create a new methodology. The ACR has
seven other methodologies in development.
To register a project, a company can consult an existing ACR standard or methodology, which
includes a general outline of what information and procedures are required. A project protocol
is then developed and submitted for verification. Once verified, the project is then registered,
project documents are posted, and the approved amount of ERTs is added to the company's
account. Every project requires additional verification no less than once every five years, where
companies must submit verification statements to confirm their amount of ERTs generated.
The selling of credits is performed outside of the ACR between the Project Proponent and the
buyer. Once an amount of credits and price have been agreed upon, the transaction takes
place and the number of ERTs sold is logged into the Proponent's account. Typical buyers
include large utility companies who want to get a head start on a possible future cap-and-trade
regulation by acquiring pre-compliance reduction tons. These "early movers" are acting now
with one potential reason being that the demand for credits is relatively low.. Meanwhile,
Proponents have the benefit of additional revenue from ERT sales for reducing their emissions.
Since 2005, the ACR has issued over 30,300,000 ERTs to its members. These ERTs have all
been granted as a result of projects that have undergone a verification process required by the
ACR. This verification process is conducted by a third party that has been approved by the
ACR, which can also include Kyoto's Accredited Independent Entities under Joint
Implementation (JI) and Designated Operational Entities under CDM. Proposed federal
legislation, including the recently released Kerry-Lieberman bill, identifies projects that reduce
fugitive or vented methane emissions in the oil and gas industry as eligible for generating
tradable carbon offset credits. Projects must use an established methodology, have third-party
verification, and be registered with an accepted program.
A Gas STAR Partner, Anadarko, currently has two projects registered in the ACR. They are
both enhanced oil recovery (EOR) projects and were developed from the ACR methodology for
carbon capture and storage (CCS). In 2008, they accounted for over 2,600,000 ERTs and since
their start in 2006, they have been issued a combined 6,100,000 ERTs. From this total,
Anadarko has sold nearly 2,700,000 of their ERTs. Details on becoming an ACR member like
Anadarko and starting a pneumatics conversion project can be found in the links below.
More information on ACR standards and methodologies can be found at
www.americancarbonregistrv.org/carbon-accounting/american-carbon-registrv-standards-and-
methodoloqies	
The list of current ACR projects is available at
www.americancarbonreqistrv.org/carbon-reqistrv/proiects	
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More information on the Baseline Monitoring Methodology for the Conversion of High-Bleed
Pneumatic Controllers in Oil and Natural Gas Systems is available at
www.americancarbonreqistrv.orq/carbon-accountinq/methodoloqy-for-conversion-of-hiqh-bleed-
pneumatic-controllers-in-oil-natural-qas-svstems	
In the News
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008
In mid-April, EPA finalized and submitted the 2010 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 decreased by 2.9
percent from 2007 to 2008. 2008 methane emissions from natural gas systems are reported as
96.4 teragrams carbon dioxide equivalent and decreased by 3.1 percent from 2007 to 2008. For
this reporting year, key changes to the natural gas systems sector included updating activity
factor calculation methods. The inventory reflects 46.3 teragrams carbon dioxide equivalent of
methane emissions reductions by Natural Gas STAR Partners in 2008. 2008 methane
emissions from petroleum systems are reported as 29.1 teragrams carbon dioxide equivalent
and increased by 1.0 percent from 2007 to 2008. The calculation methodology remained the
same as the previous year's inventory, though activity data was updated for the 2008 reporting
year.
For more information, the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008
is available at epa.qov/climatechanqe/emissions/usinventorvreport.html.
2010 Society of Petroleum Engineers Conference
April 12 to 14, 2010—Rio de Janeiro, Brazil
The Society of Petroleum Engineers (SPE) held its annual International Conference on "Health,
Safety, and Environment (HSE) in Oil and Gas Exploration and Production" this past spring from
April 12th to 14th in Rio de Janeiro, Brazil. This conference has been ongoing for more than
eighteen years and has highlighted numerous HSE best practices and challenges. Over 150
technical presentations were given that addressed the state of current global HSE programs,
sharing innovations, products, and services with all conference attendees. Nearly 40 exhibitors
were in attendance, among which were Natural Gas STAR Partners. EPA presented paper
126964: "Designing the Ideal Offshore Platform Methane Mitigation Strategy" in the April 12th
Air Emissions afternoon session. This paper presented a strategy for methane mitigation
including three examples using actual offshore platform data. For more information, visit the
SPE conference website at spe.orq/events/hse.
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Turkmenistan Symposium on Natural Gas System Management
April 26 to 29, 2010—Ashgabat,
Turkmenistan
Coordinated by the Department of Energy
(DOE), Environmental Protection Agency
(EPA), and the U.S. Embassy, the
Turkmenistan Symposium on Natural Gas
System Management took place in
Ashgabat, Turkmenistan's capital, from
April 26th to 29th. Chevron, ExxonMobil,
and Honeywell co-sponsored the event,
with company experts presenting on
various topics. The conference brought
together industry veterans, technical
experts, and Turkmenistan government
officials to discuss topics related to natural
gas management and operation. Altogether, fifteen participants from Turkmenistan participated,
from both industry and government. The topics covered included techniques and processes in
the gas production, gas processing, transmission and distribution sectors that help to identify
and cost-effectively reduce methane emissions. The information presented provided
Turkmenistan officials with the necessary tools for improving the life cycle of pipelines and
compressor stations. EPA presented topics in methane mitigation including: 1) gas production,
2) leak detection and measurement, 3) gas transmission pipelines, 4) compressor stations, and
5) carbon financing programs. For more information and presentations, visit the conference
website at epa.qov/qasstar/workshops/techtransfer/2010/ashgabat en.html.
Middle East & North Africa Forum on Flaring Reduction & Gas Utilization
May 10 to 11, 2010—Muscat, Oman
The World Bank-led Global Gas Flaring Reduction (GGFR) Partnership and Masdar sponsored
this event as a forum for mitigation methods in associated gas flaring. The conference took
place from May 10th to 11th in Muscat, Oman and had over 100 participants from around the
world. Those in attendance included industry heads, government officials, and expert
consultants. Some of the topics discussed included gas flaring reduction policy and regulation,
Clean Development Mechanism (CDM) carbon credits, and overcoming reduction project
barriers. EPA gave a presentation on the Methane to Markets (M2M) Partnership, outlining
reduction technologies for major fugitive and vented sources, as well as project opportunities
and feasibility studies. EPA distributed its library of methane mitigation technical documents
translated into Arabic (also posted on the EPA Natural Gas STAR website). More information
and presentations are available online at menaflarinqforum.org.
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Natural Gas STAR Producers Technology Transfer Workshop
May 11, 2010—Farmington, NM
With over 70 participants, this technology transfer
workshop addressed best management practices in
reducing methane emissions for local oil and gas
producers in the greater Farmington, New Mexico area.
The workshop preceded the biannual Four Corners Oil &
Gas Conference that took place May 12 to 13, in which
Natural Gas STAR also participated. Co-sponsored by the
New Mexico Environment Department (NMED), the New
Mexico Oil & Gas Association (NMOGA), and
ConocoPhillips Petroleum Company, the full-day workshop
covered natural gas dehydration, methane savings from
compressors, and reduced emission completions.
Presenters included representatives from ConocoPhillips,
Devon Energy and NMED who introduced New Mexico's
Voluntary Innovative Strategies for Today's Air Standards
(VISTAS), a voluntary emission control program. EPA also
gave an update on the current status of the re-proposed
Greenhouse Gas Reporting Rule, Subpart W.
Presentations are available on the Natural Gas STAR website at eDa.gov/aasstar.
&
New Gas STAR Partners
Cabot Oil & Gas Corporation
The United States Environmental Protection Agency
(EPA) is pleased to welcome Cabot Oil & Gas
Corporation as an official Partner in the Natural Gas
STAR Program. Cabot Oil & Gas Corporation is a
mid-size independent oil and gas company engaged in
the development, exploitation and exploration of oil and gas properties located in North
America. Cabot's primary focus is in developing low risk, repeatable drilling opportunities
across North America. In 2009, Cabot reported approximately 2,060 billion cubic feet equivalent
(Bcfe) of total proved reserves, including substantial shale holdings and conventional horizons,
with a primary focus in the Marcellus, Haynesviile, and Eagleford shales. Approximately 98
percent of Cabot's reserves and 95 percent of its production is natural gas. Cabot is
headquartered in Houston, Texas with a regional office in Pittsburgh, Pennsylvania as well.
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Upcoming Events
t:k;
""" T"	Methane to Markets
Annual Implementation Workshop
Oil and Gas Subcommittee Meeting
New Orleans, LA
November 1 to 3, 2010
Methane to Markets
Oil & Gas Investment Asia 2010
Singapore
October 26 to 29, 2010
Natural Gas STAR Contacts
Program Managers
Scott Bartos (bartos.scott@epa.gov)
Phone:(202) 343-9167
Jerome Blackman (blackman.jerome@epa.gov)
(202) 343-9630
Carev Bvlin (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 Scott Bartos.
A Partner Update
Summer 2010
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