EPA POLLUTION PREVENTER '
                                SPRING 2011
Partner Profile:
                 Noble Energy
Noble Energy (Noble) joined Natural Gas STAR in 2005 as a production sector Partner with a
commitment to cost-effectively reduce methane emissions. Noble has reserves of 1.1
billion barrels of oil equivalent, with core operations in the Denver-Julesburg Basin, deepwater
Gulf of Mexico, offshore Eastern Mediterranean, and offshore West Africa.
Noble's participation in Natural Gas STAR over the
years has included activities such as directed
inspection and maintenance, reduced emission
completions, installing plunger lifts, installing low
bleed pneumatic controllers, retiring gas pneumatic
chemical injection pumps, and vapor recovery. These activities have resulted in cumulative
Natural Gas STAR methane emissions reductions of over 1 billion cubic feet. The company also
gave two presentations at the 2010 Annual Implementation Workshop on several initiatives.

All of these efforts are part of Noble's complementary greenhouse gas (GHG) emissions
awareness programs which also include Noble's Corporate Social Responsibility Policy and its
Climate Change Committee. The Climate Change Committee meets periodically to review the
research, policy and regulatory elements of climate change. The committee provides oversight
of Noble's GHG emissions inventory, which was first prepared in 2006, and identifies potential
reduction initiatives. An example of Noble's initiative in reducing methane emissions includes
participation in the Carbon Disclosure Project (an independent non-profit organization operating
a climate change reporting system) in 2009 and 2010.

Noble is expanding on these accomplishments via two projects—incorporating emissions
reductions into the design of production facilities in Israel, and removing carbon dioxide (CO2)
during gas well completions in Oklahoma.

Design Phase Emissions Reductions - Tamar Project, Israel
Through its GHG emissions awareness programs, Noble noticed that many of its reduction
projects were "lagging strategies" adopted in response to existing issues and existing
infrastructure. Rather than react, Noble took "leading strategies" approach with the goal of
introducing GHG emissions as a design parameter to consider during the early phases of a

The Tamar project in the Eastern Mediterranean Sea is one execution of leading strategies
where the Environmental Engineering department has been closely involved since the
conceptual phase. The Tamar project is the development of a natural gas field 52 miles off the
coast of Israel (Exhibit 1). The field was discovered in 1999 and has an estimated 8.4 trillion
           Partner Update
           Spring 2011

cubic feet in gross reserves. Noble is currently designing the gas and liquids receiving facilities,
both offshore and onshore, with first production expected between 2012 and 2013. Processes at
the receiving facilities will include compression, electricity generation, glycol dehydration, dew
point control (via Joule-Thomson valve), stabilization, and vapor recovery.
  Exhibit 1: Tamar gas field off the shore of Israel in
  the Eastern Mediterranean Sea.
                                            As part of the design process, Noble
                                            characterized baseline GHG emissions using
                                            ESS Essential Suite version 7.3.3, a GHG
                                            management software. The baseline emissions
                                            estimate was eye-opening to the design team
                                            and served as a key numerical result
                                            demonstrating the magnitude of methane
                                            emissions and showing that value can be
                                            derived from its capture and use.

                                            Successes using the leading strategies
                                            approach in the Tamar project will include
                                            maximized vapor recovery by taking potential
                                            vent streams and routing to compression. The
                                            design also minimizes the flow rate of
purge/sweep gas to the atmosphere to prevent backflow of air into the process. As a result of
the baseline emissions estimate which quantifies methane leaks based on component counts,
the Tamar project design has also minimized the number of valves and other components so
that fugitive emissions are more readily managed with a planned directed inspection and
maintenance program.

Involvement of the Environmental Engineering department helped to establish that emission
reductions are more effective during the design phase than lagging controls and that GHG
emissions inventory management can be used as an aide during the design of a major
construction project.

Flowback Gas Capture Using CO2 Membrane Technology- Ellis County, Oklahoma
In some fracturing operations in Ellis County, Oklahoma, Noble Energy uses CO2 during
hydraulic fracture. Although effective for well productivity, this practice causes the initial
flowback gas to contain high amounts of CO2, and this gas must be sent to flare for several days
until the energy content of the flowback gas is pipeline quality and/or is suitable for blending. To
decrease methane emissions and increase the volume of gas sold, Noble Energy conducted a
pilot project using CO2 membrane technology. A membrane unit mounted on a trailer separates
flowback gas into two streams, a methane-rich residue stream that meets pipeline
specifications, and a CO2-rich permeate stream which is vented. Exhibit 2 illustrates how the
membrane separation process functions.
The CO2 membrane system shown in Exhibit
3 was tested on ten wells. A total of nine tests
took place, eight of which were flowbacks
from a single well completion, and one of
which was a commingled stream from two
well flowbacks. Once the pilot project was
complete, an approximate total of 175 MMcf
of gas was sold instead of flared. The total
cost of the pilot project was about $325,000,

—"•—•—'    Spring 2011
                                            (Flowback Gas)

                                                                          (CO2 Rich)
                                            Exhibit 2:  Membrane separation process, creating
                                            hydrocarbon and CO2 rich streams.

including equipment rental and labor. Using an assumed gas sales price of $3.12/million BTU,
the total net profit of the pilot project came to about $340,000, which is an average net profit of
$34,000 per flowback. The potential for carbon credits is another advantage to utilizing this
membrane system. In this pilot project, selling the natural gas that would have been traditionally
                                         sent to flare resulted in an estimated carbon
                                         savings of 1,300 to 5,300 tonnes of CO2
                                         equivalent per well.

                                         The project resulted in the reduction of methane
                                         emissions and provided economic advantages of
                                         selling gas that under normal circumstances
                                         would have been sent to flare. Commodity prices
                                         and the practicality of commingling the flowback
                                         gas from different wells will be important in
                                         determining future use. Commingling the
                                         flowback gas can double the gas savings for the
                                         same rental and set-up costs.
    Exhibits: CO2 separation unit (portable
    membrane system) at a gas well site.
Further Down the Road
Noble's leading strategies for methane emissions management identify methane emissions
before they occur, allowing the company to take action to keep more methane in its systems.
Noble is planning to include these activities in its annual report to Natural Gas STAR and to
continue to identify cost-effective methods to minimize methane emissions.
Technology Spotlight*
                           Addressing Emissions via Internal
Pipeline Coating and Pipeline Monitoring

Methane emissions from pipeline leaks can be attacked on two fronts: prevention and
remediation. Internal pipeline coatings can minimize internal pipeline corrosion and fugitives
while providing other benefits such as improved fluid flow. Inspecting and repairing pipeline
leaks, on the other hand, can cost-effectively address existing leaks. These technologies are
applicable to pipelines in all segments of the natural gas industry, although the benefits will
likely be greater for larger, higher-pressure pipelines.

Internal pipeline coatings (shown in Exhibit 1) typically consist of a liquid epoxy or fusion-
bonded epoxy that creates a thin barrier between the  internal pipeline wall and the transported
material.  Internal pipeline coatings offer protection against corrosive materials transported  in
the gas such as water, oxygen, hydrogen sulfide, carbon dioxide, or chlorides. This, in turn,
mitigates the long term occurrence of pipeline leaks and pipeline repair procedures such as
pipeline blowdowns resulting in methane emissions. An internal pipeline coating also reduces
the friction forces experienced by the transported material along the pipeline wall.  Less friction
reduces the horsepower necessary to transport the material and consequently reduces fuel
consumption and combustion emissions from the pumps and compressors transporting the fluid.
—"•—•—'    Spring 2011

                Corroded pipe.
Pipe after coating.
                      Exhibit 1: Corroded Pipeline and Internally Coated Pipeline
                                (IntraCoat Pipeline Services, Inc.)

An internal pipeline coating could also reduce the number of compressors required to move
material through a pipeline, particularly for long transmission pipelines under high pressure.
Eliminating compressors along a pipeline will reduce subsequent compressor-related fugitive
and vented methane emissions such as potential methane emissions from reciprocating
compressor rod packing or centrifugal compressor wet seals, compressor blowdowns, and unit
and/or blowdown valve leakages. At the 2010 Natural Gas STAR Annual Implementation
Workshop (epa.qov/qasstar/workshops/annualimplementation/2010.html), El Paso presented
Ruby: the First Carbon Neutral Pipeline, which showcased the benefits of internal pipeline
coatings on a 680-mile pipeline with a 1.5 billion cubic-foot design capacity. El Paso estimated
the total horsepower (HP) requirements for this pipeline to be about 127,000 HP without the
internal pipeline coating and 115,000 HP with the internal pipeline coating. This reduction in
horsepower could potentially reduce the number of compressors required for the process.

Internal pipeline coatings can be applied at the design phase or in situ for existing pipelines.
The first step in the in situ coating process includes cleaning the internal pipeline wall with
abrasive blasting and chemical cleaning to smooth out and remove material deposits. This
ensures the pipeline coating will properly adhere to the pipeline wall.  Service providers
including IntraCoat Pipeline Services, Inc. offer an in situ coating process that utilizes a pig to
clean, prepare, and apply the coating to the inner wall of the pipeline.  Exhibit 2 shows a
diagram of the in situ coating process and photographs of the inside of a pipeline before and
after the in situ coating application. Applying internal pipeline coatings, however, is an
expensive solution to pipeline leaks in the short term and is typically justified by the additional
benefits rather than by methane savings alone.
                             SOUEEGE£ PIGS
                                                 COAJING PIGS
                                                 APPLYING IHf
                                                 EPOXY COATING
                                   Exhibit 2: In Situ Pipeline
                                (IntraCoat Pipeline Services, Inc.)
—"•—•—'    Spring 2011

Pipeline Monitoring
An alternative for preventing existing pipeline leaks is periodically monitoring pipelines using a
combination of ground transportation and the appropriate hydrocarbon leak detection device.
This combination increases measurement speed and effectiveness when performing mobile
inspections of large networks of gathering, transmission, and distribution pipelines. The Apogee
Leak Detection System (LDS) that was featured in the summer issue of the 2009 Partner
Update (epa.gov/gasstar/newsroom/partnerupdate.html) can be mounted on various vehicle
types, including a truck or all-terrain vehicle.  Exhibit 3 shows the Apogee truck-mounted leak
detection system.
                      Exhibit 3: Apogee Truck-Mounted Leak Detection System

The LDS 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.

Another method used by Heath Consultants is to mount an optical methane detector to a vehicle
(e.g. trucks and all-terrain vehicles) and perform the pipeline leak detection from the vehicle.
Exhibit 4 demonstrates a few examples of vehicles equipped with optical methane detectors.
                            Exhibit 4: Heath Optical Methane Detector

The ground-based pipeline leak detection method, as opposed to air-borne leak detection, is
less costly. However, this method is limited to pipelines on navigable and passable land.
Walking surveys are also feasible using optical and infrared leak detection devices; however,
they can be time consuming and tedious for long stretches of pipeline.
—"•—•—'    Spring 2011

The use of internal pipeline coatings and monitoring will reduce greenhouse gas emissions.
Internal pipeline coatings mitigate corrosion preventing pipeline leaks in the long term and
immediately, albeit indirectly, reducing pump and/or compressor combustion emissions. In the
short term, operators can also implement a directed inspection and maintenance (DI&M)
program on their pipelines to reduce methane losses from pipeline leaks. Through a
combination of internal pipeline coating application and ground-based pipeline leak detection,
companies can prevent methane and potentially other air pollutant emissions from their pipeline
Prospective Projects Spotlight*
                                       rtificial Muscle Technology
As gas wells mature, liquids begin to accumulate in the well bore impeding the flow of gas. Gas
flow is maintained by removing accumulated fluids through the use of a sucker rod pump or
other remedial treatments (see sidebar). These fluid removal techniques may result in
significant costs and/or methane emissions to the atmosphere.
                                                            Existing Well Liquids
                                                            Removal Options
                                                             • Sucker rod pumps
                                                             • Plunger lifts
                                                             • Swabbing
                                                             • Soaping
                                                             • Velocity tubing strings
                                                             • Gas Lift
                                                             • Venting
                                                             • Electric Submersible
                                                               Pumps (ESPs)
A prospective alternative explored in this article is the
combination of artificial muscle technology with existing
hydraulic downhole deliquification pumps.

Although it is common for wells to produce some water and/or
hydrocarbon condensate, it is not a problem until the liquids
begin to accumulate in the well bore and impede production.
For most wells, the gas is flowing fast enough that the liquids
blow out as droplets and accumulate in the separator at the
surface. For mature or depleting wells, the velocity of the gas flow in the well bore declines
which results in a lower ability to  carry the liquids. As a result, liquids begin to accumulate, and
production volumes suffer.

To maintain productivity, profitability and extend the well's life, operators will determine which
liquids unloading method is most applicable to the specific well based on individual well
characteristics. As the well becomes more mature, the flow of gas may become too low to use a
liquids unloading option that does not involve adding energy to the reservoir. Adding energy to
the reservoir requires additional costs. Under these circumstances, a downhole pump or gas lift
is usually employed. Eventually, as the well  continues to mature, it will be shut  in and
abandoned. This decision is based on an economic evaluation which determines when the
investment required to maintain productivity exceeds the revenue from the well. Often, gas will
remain in the reservoir, but a well is shut in because it is no longer economic to attempt to
extract the remaining gas.
One company is currently focusing on
combining technology used in military
applications, called Shape Memory Alloy
(SMA), with existing hydraulic downhole
deliquification pumps (see Exhibit 1). This
new deliquification system, called SmartLift,
            Partner Update
            Spring 2011
                                          Exhibit 1: A high-pressure pump powered by a Shape
                                          Memory Alloy

would be electrically powered and is projected to be less costly than existing artificial lift
technologies. By applying an electric potential through the alloy, the metal will take a shape that
it has stored (as if by memory). When the electric potential is no longer applied, the metal
returns to its original shape. Use of this technology for a pump driver results in a piston syringe
pump being driven by an electric muscle. A significant advantage of this type of pump is its
ability to create a linear pumping motion with only two moving parts. This technology could also
be combined with numerous existing hydraulic pumps.

Emissions reductions will vary for each individual application depending on  well and reservoir
characteristics. Based on a Natural Gas STAR Partner experience, it is estimated that
emissions reductions resulting from the installation of a downhole pump could be as high as 973
thousand cubic feet (Mcf) per year per well1. Exhibit 2 illustrates a comparison of emissions
reductions and capital/installation costs for three possible scenarios: a) no liquids removal, b)
typical downhole pump, and c) a Shape Memory Alloy pump.

Exhibit 2: Cost Estimate and Potential Savings Comparison
PROJECT SUMMARY: SmartLift vs. Typical Downhole Pump
Type of Artificial Lift
Annual Emissions from Liquids
Unloading (Mcf per year per well)
Capital & Installation Costs Ratio
Gas Production
Methane Saved (Mcf per year per well)
Typical Downhole
Pump (Pump Jack)
Shape Memory
Alloy Pump
a In general, the cost of a system using a Shape Memory Alloy pump is 55% that of a comparable downhole pump system.
As shown in Exhibit 2 above, the reduction in emissions from implementation of a system using
Shape Memory Alloy technology is equivalent to reductions from a typical downhole pump. The
system using new technology requires an investment that is projected to be approximately 45
percent lower. Both types of artificial lift will extend the useful life of the well by efficiently
unloading liquids that build up in the well bore resulting in additional revenue from gas sales.
The difference, however, is that the new technology is projected to be more cost-effective as
illustrated in Exhibit 3.  Because the new technology requires a smaller investment to install, it is
possible that a larger population of wells could benefit from the installation of an artificial lift

As illustrated in Exhibit 3, a system  using this new technology could be more cost-effective than
some downhole pump options because both installation and operation are simpler.  The
equipment is much smaller and lighter than a sucker rod pump and will be installed from a reel
rather than using a pulling unit. The new artificial lift system, which employs the SMA
technology, has demonstrated reliability and long service life in other applications and could
potentially operate longer than a typical downhole pump, reducing annual operating and
maintenance (O&M) costs.
1 Partner Reported Opportunity Fact Sheet No. 707. "Install Pumpjacks on Low Water Production Gas Wells':
January 2004. Available at: http://epa.gov/gasstar/documents/gaswells.pdf
             Partner Update
             Spring 2011

   Rod Lift
                     Exhibit 3: Replacing Large & Complex Topside Pump Jacks

Besides the intended application for downhole pumps, this technology might also be useful in
pneumatic actuators by replacing the power gas used for moving large valves. Instead of using
natural gas pressure for pneumatic controls, this technology could be used to provide the
pressure necessary for actuation of the device wherever electric power is available. As a result,
this device would effectively transform bleeding pneumatic devices into no-bleed devices. This
application would lead to significant emissions reductions as well as additional revenue from the
gas sales since less gas would bleed through the pneumatic devices.

If electric power is available on-site, this new technology could be used with downhole pumps to
increase efficiency and simplicity of installation and operation, reducing costs and methane
emissions. This technology also has the potential to be used in other applications, such as
replacing power gas to pneumatic actuators.

Development of the SmartLift system is currently supported by a contract with Linear Motion
Technologies (LMT) and the Stripper Well Consortium (www.enemy.psu.edu/swc/), which is
funded by the U. S. Department of Energy and operated by Penn  State University.  The current
objective of the SmartLift development effort is the selection of an initial sizing for a prototype
that will address the needs of a significant portion of the U.S. gas well population.
—"•—•—'    Spring 2011

Natural Gas  STAR: Annual Reporting Season  is

The Natural Gas STAR 2011 reporting season is underway.  Partners are kindly requested to
submit information on any voluntary methane emissions reduction activities undertaken in the
2010 calendar year by April 29th. 2011,
   Suggested Procedure for Identifying
   New Projects to Report to Natural
   Gas STAR:
      1.  Review operations.
      2.  Identify differences between
         your operations and current
      3.  Report emission reduction
         activities for 2010.
Natural Gas STAR Partners should have received
annual reporting information (along with login and
password information) by email at the beginning of
March. Please contact your STAR Service
representative with any reporting questions.
Partners can submit reports in hard copy, email, fax,
or electronically through a secure, password-
protected online reporting form.

Below is a suggested procedure for reporting 2010
activities to Natural Gas STAR:
1.  Review operations. Engage in discussions with field personnel who can identify recent
improvements or current challenges. Other information sources useful for identifying
opportunities include facility emission inventories, copies of process and instrumentation
diagrams, and repair/maintenance logs.

2.  Identify differences between your operations and current PROs.  Compare the
technologies and practices used in your operations to the Partner Reported Opportunities
(PROs) available on the Gas STAR website.  PROs are any practice or technology included in a
Partner's annual report that reduces methane emissions. Determine whether certain activities
are unique or are improvements on current PROs. Highlight these findings in your annual report
to notify Natural Gas STAR of a new innovative activity.

3.  Report emission reduction activities undertaken in 2010.
Review current PROs and report to Natural Gas STAR all
voluntary methane emissions reduction activities completed in
the 2010 calendar year. A complete listing of all reported PROs
can be found on the Program's Web site at
                         Submit Online at:
            Partner Update
            Spring 2011

Natural Gas STAR International Collaborates with Russian Independent Oil
and Gas Producers on Methane Mitigation Technologies and Strategies
October 4, 2010—Moscow, Russia

In the fall of 2010, the Global Methane Initiative and Natural Gas STAR International held a
seminar with independent oil and natural gas producers in Russia to discuss best practices for
methane emissions reductions on an international stage. The seminar drew participants from
companies including Lukoil, TNK-BP, and Gazprom VNIIGAZ. The one-day workshop in
Moscow addressed methane emissions from both the production and processing sectors—well
completions/workovers, liquids unloading, storage tanks, pneumatic devices, dehydrators,
reciprocating/centrifugal compressors—and covered programs such as directed inspection and
maintenance (DI&M) to help detect, prioritize, and repair leaks. Several companies also gave
presentations on their related experience in both methane mitigation technologies and GHG
accounting and reporting. More information on the workshop and presentations can be found at
epa.gov/gasstar/workshops/techtransfer/2010/moscow  en.html.
Natural Gas STAR International and Gazprom Conduct Site Tour and
Workshop on the Accounting and Control of Methane Emissions in the
Russian Gas Sector
December 14 to 16, 2010—Novy Urengoy, Russia

Under the Global Methane Initiative, Natural Gas STAR
International and Gazprom, the world's largest producer of natural
gas, co-hosted a production site tour in Yamburg and a technical
seminar in Novy Urengoy, December 14 to 16.  Located above
                               the Arctic Circle,  the event
                               included a two-day tour of
                               Gazprom's Yamburg gas
                               production and processing
                               sites and a technical conference to exchange information
                               on methane emission reduction strategies and climate
                               policy.  Natural Gas STAR Program Manager, Scott
                               Bartos, also met  with senior Gazprom management in
—"•—•—'   Spring 2011

U.N. Study Says Global Warming Rate Could be Halved by Controlling Two

A recent study by the United Nations Environment Programme (UNEP), Integrated Assessment
of Black Carbon and Tropospheric Ozone, suggests that the projected rise in global
temperatures can be cut in half if both black carbon and ground-level ozone (and by extension
methane) are reduced.  Although not a greenhouse gas, black carbon exists as particles in the
atmosphere and warms the atmosphere by absorbing sunlight.  Ground-level ozone is formed
by the reaction of sunlight with ozone precursors (methane is considered an ozone precursor in
the UNEP report)  and is hazardous to human health and ecosystems. In addition to reducing
the amount of ground-level ozone, the report states that mitigating methane emissions has the
added benefit of reducing global warming.

Rather than focusing on carbon dioxide alone, this report recommends that reducing air
pollutants with short lifetimes is the most viable way to mitigate global warming over the next 20
to 30 years. One  way to control ground-level ozone covered in the report is to  reduce methane
emissions from long-distance natural gas transmission pipelines, an activity that is also
beneficial for maximizing natural gas supply. As concerns about near-term impacts of climate
change increase,  many organizations are now beginning black carbon and ground-level ozone
reduction projects located around the world (e.g., China, Brazil, and India). Additional article
details and the UNEP report are available at http://www.washingtonpost.com/wp-
BOEMRE Holds Workshop on Potential Flaring Requirement for Offshore
Petroleum Production Facilities to Reduce GHG Emissions
March 30, 2011—New Orleans, Louisiana

The Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) held a
public workshop in New Orleans to discuss the possibility of requiring existing venting of natural
gas from offshore petroleum production facilities to be directed to flare.  This issue was brought
forth by the Government Accountability Office (GAO), which recommends companies to
consider the benefits and economics of flaring natural gas vents whenever  possible. The
workshop intended to bring parties together to give recommendations on what facilities the
flaring requirement should apply to, what the emissions threshold should be, and which
equipment types require venting rather than flaring for safety reasons.  More information about
the workshop, including the agenda and presentations, will be available soon on the BOEMRE
website at boemre.gov.
            Spring 2011

Upcoming  Events
  Carbon Expo
  Barcelona, S
  June 110 3,2011
                                                        •"••-*-- •-•••-•--• •
                                                        2nd Internationa! Workshop on Methane
                                                        Emissions Reduction Tecnnctogies In the Oil and
                                                        Natural Gas Industry
                                                        Huartong, Ctiina
                                                        April 21 to 22,2011
Natural Gas STAR Contacts
                         Program Managers
                   Scott Bartos (bartos.scott@epa.gov)
                         Phone: (202) 343-9167
               Jerome Blackman (blackman.jerome@epa.gov)
                         Phone: (202) 343-9630
                    Carey Bvlin (bylin.carey@epa.gov)
                         Phone: (202) 343-9669
                Roger Fernandez (fernandez.roger@epa.gov)
                         Phone: (202) 343-9386
                 Suzie Waltzer (waltzer.suzanne@epa.gov)
                         Phone: (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.
—"•—•—'    Spring 2011