United States
Environmental Protection
Agency
PARTNER UPDATE
EPA POLLUTION PREVENTER
SUMMER 2009
In This Issue:
Partner Profile.
Prospective Projects Spotlight.
Methane's Near-Term Climate Impact 2
Climate Policy Update.
In the News.
Workshop Summaries.
Calendar.
Partner Profile
Chesapeake Energy Shares Chesapeake
»** ICNIKGY
Implementation Experiences
Partner company Chesapeake
Energy has closely integrated
its Natural Gas STAR partici-
pation with its core business activities
and as a result has realized significant
efficiency improvements, methane
emissions reductions, and correspond-
ing 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
Continued on page 5
Prospective Projects Spotlight
Capture Additional Sources with
Storage Tank Vapor Recovery Unit
Cil and natural gas facilities,
both upstream and down-
stream, share similar types
of methane emissions sources such as
vents and blowdowns. These releases
may individually go unnoticed but col-
lectively represent a significant product
loss and often offer an economic cap-
ture 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 proj-
ects for discrete sources ranging from
open-ended lines to compressor blow-
downs; this project concept explores
the versatility of vapor recovery units
to accommodate the combination of
such emissions that may be present
Continued on page 4
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Methane's Near-Term Climate Change Impact:
Greater or Equal to Carbon Dioxide
Two estimates show that meth-
ane emissions have a climate
impact similar to carbon diox-
ide 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 cli-
mate change impact reinforce the sig-
nificance of methane and its role as a
powerful greenhouse gas.
The Intergovernmental Panel on
Climate Change (IPCQ's Fourth
Assessment Report examines meth-
ane'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 persis-
tence 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.
Global Warming
Potentials:
EPA typically uses the 100-year GWPs
listed in the IPCC's Second Assessment
Report (SAR) to be consistent with
the international standards under the
United Nations Framework Convention
on Climate Change (UNFCCC).
According to the SAR, the 100-year
GWP of methane is 21.
Exhibit 1. Integrated RF of year 2000 emissions over a 20 year time horizon, Watts per square meter per
year. Methane's RF over this time period is approximately equal to that of carbon dioxide. Source: IPCC
CVI
CO,
greenhouse gases
|— N2O |- CFCs
CH4
_SF6
PFCs
+ HFCS
"- HCFCs
CO, NMVOC + NOX
Black carbon (FF)
Cloud albedo •
Short-lived gases
Aerosols and aerosol
precursors
-2
-1012
Integrated radiative forcing (W nr2yr1)
GWPs are derived from another mea-
sure 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 meth-
ane. The Fourth Assessment Report
examines the separate RF compo-
nents associated with each long-lived
greenhouse gas. Over the 20 year
time horizon following year 2000 emis-
sions, 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 find-
ing 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 reduc-
tion 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 meth-
ane (compared to a "business as usual"
Continued on page 7 * * *
Useful Resources:
International Panel on Climate Change: Forth Assessment Report: ipcc-wg1.ucar.edu/
wg1/Report/AR4WG1 _Print_Ch02.pdf
Pew Center on Global Climate Change: Multi-gas Contributors to Global Climate Change:
Climate Impacts and Mitigation Costs of Non-C02 Gases: pewclimate.org/docUploads/
Multi-Gas.pdf
2 Natural Gas STAR Partner Update * Summer 2009
-------
elow 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 reduc-
tion 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.
EPA Greenhouse Gas
Reporting Rule Update
On April 10, 2009, the proposed
greenhouse gas reporting rule was
published in the Federal Register
under Docket ID No. EPA-HQ-
OAR-2008-0508. Two public hear-
ings were held during the comment
period, one on April 6 to 7, 2009,
in Arlington, VA, and the second on
April 16, 2009, in Sacramento, CA.
Comments were accepted through
June 9, 2009, 60 days following pub-
lication in the Federal Register. EPA
is reviewing all comments and will
respond by early autumn.
Method 21 Alternative
Work Practice -
Elements of Interest
The winter 2008 Partner Update report-
ed on the Alternative Work Practice
(AWP) for Method 21. The AWP allows
use of gas imaging instruments for
monitoring of volatile organic com-
pound 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.
Alaska Climate Change Policy Update
Alaska's climate change strategy development process continues to move forward with
study of policy options for different economic sectors and quantification of approximate
policy option costs and greenhouse gas emissions reductions. In 2007, Alaska created a
sub-cabinet to advise the governor on the preparation and implementation of an Alaska
climate change strategy. Two advisory groups—mitigation and adaptation—were formed
to make recommendations to the sub-cabinet. The Mitigation Advisory Group (MAG)
is examining greenhouse gas emissions reduction methods for different sectors of the
economy. Oil and natural gas industry greenhouse gas mitigation options under study
include fuel consumption conservation practices, fugitive methane emissions reduction,
energy efficiency, and sequestration. Draft narrative descriptions of the policy options,
including estimates of the cost-effectiveness, were discussed at the May 14, 2009,
meeting of the MAG. The recommendations of the sub-cabinet will be presented to the
governor later this year. Details are available at akclimatechange.us/index.cfm.
* 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 locat-
ed a distance away from a measured
gas release, not to be exceeded dur-
ing the leak survey. The gas release
through a flow meter must be view-
able by the instrument and recorded.
For bi-monthly monitoring, the mea-
sured 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 annu-
ally using Method 21. Subsequent
Method 21 monitoring must be con-
ducted 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 identi-
fied. Records for the daily instrument
check include the distance, flow
meter reading, and video. Additional
records include the equipment cho-
sen 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 low-
est mass fraction of chemicals that
are detectable.
Natural Gas STAR Partner Update * Summer 2009 3
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Capture Additional Sources
with Vapor Recovery
Continued from page l
at a typical facility. The potential sav-
ings 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 meth-
ane 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
Exhibit 1: Candidate Sources for Additional Vapor
Recovery, Upstream through Downstream
Emissions source,
continuous
Casinghead gas
Dehydrator flash tank
Dehydrator reboiler vent
Pneumatic device
Pneumatic pump
Pig trap valve leak (as
open ended line)
Compressor rod packing
open ended line
Centrifugal compressor
wet seals
Emissions source,
intermittent
Vessel blowdown
Compressor starts
Compressor blowdown
Pigging emissions
Typical emission
factor, Mcf methane
/year
3,004
146
12
125
90
821
8651
44,1 501
Typical annual
emission factor for
intermittent events,
Mcf methane / year
/unit
0.08
8
4
not quantified
Unless noted, values taken from API Compendium of
Greenhouse Gas Emissions Methodologies for the Oil
and Gas Industry, February 2004.
1 Natural Gas STAR Lessons Learned Studies.
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 instal-
lation 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 compres-
sor 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 dehy-
drator 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.
Continued on page 7 if if *
Natural Gas STAR Partner Update * Summer 2009
-------
Partner Profile
Continued from page 1
a number of successful project fypes,
including a leak inspection and repair
program and developmenf of lean burn
gas dehydrafors.
Approach to Natural Gas STAR
Chesapeake joined fhe Natural Gas
STAR Program and formed an opera-
tions 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 activi-
ties 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 stud-
ies 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 activ-
ities 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 meth-
May 14, 2009 technology transfer workshop in Oklahoma City, sponsored by Chesapeake Energy and
Devon Energy
ods 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 heli-
copter, pickup, or all-terrain vehicle. It
measures gas concentrations by con-
tinuously capturing samples of ambient
air using a blower. The sample is ana-
lyzed with a series of mirrors and lasers
to detect any appreciable hydrocarbon
gases. Concentration measurements
occur approximately 20 times per sec-
ond with methane, total hydrocarbon,
and carbon dioxide measured sepa-
rately. Concentration data is relayed to
a connected laptop running Apogee-
developed 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 proac-
tive 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 pur-
chased a unit for use in the
operating districts of its Eastern Division,
contracted a flight service company
experienced in using the unit, and priori-
tized 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
Continued on page 6
Natural Gas STAR Partner Update * Summer 2009 5
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Partner Profile
Continued from page 5
the Apogee LDS proved to be in this
forested and mountainous environ-
ment. 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 sav-
ings also expedites leak repair and
increases gas savings.
As of May, 2009, Chesapeake esti-
mates 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 approximat-
ing $2.2 million. Costs for the survey
and repair work include purchasing an
Apogee LDS, helicopter rates (approxi-
mately $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 instru-
ments such as Chesapeake's FLIR
infrared camera.
Employing Lean Burn Glycol
Dehydrators
Chesapeake has also examined gly-
col dehydration from an air emissions
standpoint and developed a compre-
hensive solution. The lean burn sys-
tem, 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, short-
ened 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 pollut-
ants 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 manage-
ment, 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 sys-
tem results in a fuel gas savings of
approximately 5 standard cubic feet
(scf) gas per gallon of glycol circulated
Helicopter mounted Apogee LDS
6 Natural Gas STAR Partner Update * Summer 2009
for Kimray pumps, or 1 scf per gal-
lon 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 approxi-
mately 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: continu-
ous destruction of VOC and BTEX,
less thermal stress on the system due
to lower burner temperatures, lower
noise (40 to 60 decibels), eliminat-
ing 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 detec-
tion and glycol dehydrator optimization.
-------
Methane's Near-Term
Climate Impact
Continued from page 2
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, espe-
cially in the near term. For more infor-
mation on proven methane-reducing
project opportunities, visit the Natural
Gas STAR Web site at epa.gov/gasstar.
Capture Additional Sources
with Vapor Recovery
Exhibit 2. Global mean temperature effects of a 50 percent emissions reduction between 2000 and
the date specified (i.e., 2050 or 2100). Non-GHGs include A/Ox, SOx, CO, and NMVOCs. Note that
a 50 percent reduction in methane emissions between by 2050 leads to a greater decrease in global
temperature than a 50 percent reduction in carbon dioxide over the same time period. Source: Pew
Center on Global Climate Change.
0.3
0.2
0.1
0.0
-0.2
-0.3
-0.4
-0.5
I 2050
] 2100
Notes: 1. In the reduction cases, emissions of the gases shown are reduced to 50% below reference between
2000 and 2050, and maintained at that percentage through 2100.
2. Non-CO 2 GHGs include CH 4, N 2O, PFCs, MFCs, and SF 6.
3. Non-GHG substances include NO x. SO x, CO, and NMVOCs.
Continued from page 4
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 sig-
nificant backpressure.
Including gas-driven pneumatic devices
into this type of capture project will
require additional design work and
consultation with vendors for a practi-
cal 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 natu-
ral gas facilities, the equipment count
for each source, and the emissions rate.
Continued on page 8
Natural Gas STAR Partner Update * Summer 2009 7
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Capture Additional Sources
with Vapor Recovery
Continued from page 7
Units are provided as Mcf methane/year
as a consistent basis for continuous
and intermittent emissions, since inter-
mittent 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 intermit-
tent sources are readily identifiable, in
close proximity, and constitute a signifi-
cant revenue stream.
Exhibit 2 shows example economics
for the surrogate facility at different gas
values. The gas volume is assumed to
Exhibit 2: Surrogate facility, $7/Mcf
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 emis-
sions 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 equip-
ment sized for initial rates, and through-
put 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 addition-
al 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 emis-
sions rates and proximity. Collectively,
these sources represent a methane
emissions capture project with poten-
tially significant returns on the invest-
ment 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, EPA [Blackman.Jerome®
epa.gov or (202) 343-9630].
Dehydrator flash tank
1 unit
146 Mcf/year
$1,020 savings per year
Dehydrator ReboilerVent
1 unit
12 Mcf/year
$84 savings per year
Pneumatic Device
6 units
752 Mcf/year
$5,266 savings per year
Compressor Rod Packing
4 units
3460 Mcf/year
$24,220 savings per year
Compressor Starts
1 unit
8 Mcf/year
$59 savings per year
Compressor Slowdowns
1 unit
4 Mcf/year
$26 savings per year
Tank
New Piping for
14 sources
($31,500) cost
Vapor Recovery ($5,005)
incremental power cost per year
PROJECT SUMMARY: VAPOR RECOVERY OF COMMON SOURCES
OPERATING REQUIREMENTS
CAPITAL & INSTALLATION
COSTS
ANNUAL LABOR &
MAINTENANCE COSTS
• Study of site steady and intermittent emissions rates
• Vapor recovery unit and tank ullage sized for the site
• Piping, restrictor plate, shutoff valve
• Potentially still condenser, oil mist filter
$31 ,500 for 14 piping runs, 150 feet each
$5,000 for incremental vapor recovery fuel gas at $7/Mcf
Gas Price per Mcf
Annual Value of Gas Saved
Payback Period in Years
$3
$13,100
2.9
$7
$30,700
1.2
$10
$43,800
0.9
Natural Gas STAR Partner Update * Summer 2009
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Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007
In mid-April, EPA finalized and sub-
mitted the 2009 U.S. Greenhouse
Gas Inventory to the United Nations
Framework Convention on Climate
Change (UNFCCC). The inventory is pre-
pared 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 meth-
odology remained the same as the
previous year's inventory, though activ-
ity 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 collabora-
tors are being sought. A teleconfer-
ence 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 technol-
ogy 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,
Battelle, at (614) 424-5547 or
cowenk@battelle.org, or Mona El
Hallak, ETV Canada, at (905) 822-4133
ext. 239 or melhallak@etvcanada.ca,
with questions or interest in participat-
ing on the teleconference by no later
than Wednesday, July 15.
The Federation of Indian Chambers of
Commerce and Industry Launches Methane
to Markets India Web Portal
F reject 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.
EPA Administrator's
Tour of Wyoming
Energy Production Sites
EPA Administrator Lisa P. Jackson and
Wyoming Governor Dave Freudenthal
toured several energy production sites
in Wyoming on May 20 and 21, 2009.
The tour included Jonah Field natural
gas drilling operations of Natural Gas
STAR Partner Encana. Other sites vis-
ited by the administrator and governor
included a wind farm near Cheyenne
and the Black Thunder coal mine in the
Powder River Basin.
Natural Gas STAR Partner Update * Summer 2009 9
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Workshop Summarie
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 organiza-
tions 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 suc-
cessful partnership between mem-
ber countries and experts from the
Methane to Markets project network.
The oil and gas tour visited a mod-
ern gas processing plant operated
by PEMEX. The second day of the
meeting included technical work-
shops discussing the latest advances
in methane capture and use. Topics
discussed during the oil and gas
technical workshop included meth-
ods for reducing emissions from
production wells, oil and condensate
storage and holding tanks, recipro-
cating and centrifugal compressors,
and natural gas transmission pipe-
lines. The oil and gas technical pro-
gram also covered ideas for financing
emissions reduction projects through
carbon markets. The last day of the
meeting included steering committee
and technical subcommittee meet-
ings. 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
ARPEL, the Regional Association of
Oil and Natural 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 opportu-
nity to promote dialogue between
governments, goods and services
suppliers, financial entities, consult-
ing companies, universities, and non-
governmental organizations about
the inter-relation among economic,
environmental, and social issues and
what it means to address them at the
strategic, operational and manage-
ment 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 dis-
cussed included unesapeaKe tnergy
m± and Devon Energy's experience
^^L ^f\. 3^y«9 SBflL f^ in methane emission reductions,
fc^-af! &r > $^£" as we" as a discussion of Natural
^H£ "") ri&fflmi Gas STAR producer best manage-
- -pV^fll^rY mLJ^fim merrt Practices. In addition, EPA
1 mm '-- ' ''mmm ' staff gave an update presentation
| ., • :. • " . on the Mandatory Greenhouse Gas
1 ^BH | Reporting Rule. Presentations can be
/;j- •.. ^^^^B found at epa.gov/gasstar/workshops/
^^^m^m^m^m^m^m^^ 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 oppor-
tunities for small and independent
producers. Presentations can be
found at epa.gov/gasstar/workshops/
techtransfer/index.html.
COM Methodologies for
Oil and Gas Industry
Projects Workshop
May 6, 2009
Washington, DC
Thirteen experts, including represen-
tatives from the Methane to Markets
Partnership, World Bank's Global
Gas Flaring Reduction (GGFR) initia-
tive, the oil and gas industry, and
Clean Development Mechanism
(CDM) project developers, met with
the purpose of discussing the rela-
tively 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 meth-
odology 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 fur-
ther discussed at the Carbon Expo in
Barcelona, Spain on May 27 to 29.
10 Natural Gas STAR Partner Update * Summer 2009
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UPCOMING EVENTS
Below are scheduled Natural Gas STAR Program events. For updates and further informa-
tion, visit epa.gov/gasstar/workshops or contact Suzie Waltzer at 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.
A
Mttlunt ID Mirktli
Technology Transfer Workshop
& Subcommittee Meeting
Co-Hosted by Methane-
to-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
A Annual Implementation Workshop
NaturalGasA San Antonio, TX
Oct. 19 to 21, 2009
Methane to Markets
Partnership Expo
New Delhi, India
Mar. 2010
World Gas Conference 2009
Buenos Aires, Argentina
Oct. 5 to 9, 2009
For more information, visit epa.gov/gasstar/workshops
* * * SAVE THE DATE * * *
Natural Gas STAR 2009 Annual
Implementation Workshop
October 19 to 21, 2009
Westin Riverwalk
San Antonio, Texas
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 highlight-
ing 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 later this summer: epa.gov/gasstar/workshops.
For information about sponsorship and exhibition at this high-visibility event,
please contact Jerome Blackman, blackman.jerome@epa.gov.
Natural Gas STAR
Contacts
Program Managers
Jerome Blackman * (202) 343-9630
blackman.jerome@epa.gov
Carey Bylin * (202) 343-9669
bylin.carey@epa.gov
Roger Fernandez * (202) 343-9386
fernandez.roger@epa.gov
Suzie Waltzer * (202) 343-9544
waltzer.suzanne@epa.gov
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.
United States
Environmental Protection
Agency
Natural Gas STAR Partner Update * Summer 2009 11
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