1-Reduce Methane Emissions by NiceTime

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									      1. Reduce Methane Emissions From the Exploration and
                    Production of Oil and Gas

Measure overview
This measure would require the use of proven, ―no regrets‖ technologies to reduce
methane emissions from common sources in oil and gas exploration and production.
We propose to define ―no regrets‖ technologies for this sector to be those that result in a
simple payback period for operators of 24 months or less and address key emissions
sources up to and including the processing phase.

Background
Methane is a potent greenhouse gas and the second-largest contributor to climate
change after carbon dioxide. Methane has a warming potential 25 times that of carbon
dioxide over a 100-year period. Reducing methane emissions offers one of the most
effective ways to combat climate change in the short-term because methane emissions
last only approximately 12 years in the atmosphere compared to 100 years for CO2
emissions.1 In addition to their climate impacts, methane emissions contribute to
higher global background levels of ozone pollution.2 And of particular interest in Texas,
the myriad of reactive organic gases that are often co-emitted with methane can lead to
local and regional increases in ozone levels.

Oil and gas operations are the second-largest contributor to U.S. methane emissions,
accounting for 23% percent of methane emissions in the United States, or 2% percent of
the total greenhouse gas emissions in the U.S. in 2007.3 In 2007, methane emissions
from oil and gas systems in the U.S. equaled 133.5 Tg CO2 equivalent or million metric
tons of CO2 equivalent (MMTCO2e).4 This is the same as the greenhouse gas emissions
emitted from roughly 24 new coal plants.5


1
    Intergovernmental Panel on Climate Change, Climate Change 2007: The Physical Science Basis, 212, table
    2.14, see note 8.
2
    Jason J. West and Arlene M. Fiore, “Global Health Benefits of Mitigating Ozone Pollution with Methane
    Emission Controls,” 103 PNAS 3988 (March 14, 2006); Arlene M. Fiore, Daniel J. Jacob, and Brendan D.
    Field, “Linking ozone pollution and climate change: The case for controlling methane,” 29, Geophysical
    Research Letters, No. 19, 1 (2002); Jason J. West and Arlene M. Fiore, “Management of Troposperic Ozone
    by Reducing Methane Emissions,” 39, Environmental Science & Technology, No. 13, 4685 (2005).
3
    EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007 ES-5 (draft 2009), available at
    http://epa.gov/climatechange/emissions/usinventoryreport.html (last visited March 6, 2009), see note 6.
4
    Ibid. These emissions are reported in volumetric terms by EPA as 331 bcf of methane in 2007, 37% of which
    is from production operations. http://www.epa.gov/gasstar/faq/index.html. These emissions are likely
    underestimated due to errors in estimation methods. See
    http://www.nytimes.com/2009/10/15/business/energy-environment/15degrees.html?_r=1.
5
    Equivalency calculated using EPA Greenhouse Gas Equivalencies Calculator, available at
    http://www.epa.gov/cleanenergy/energy-resources/calculator.html.
Methane emissions can occur throughout the production life cycle of natural gas and oil.
There are numerous individual components used throughout natural gas and oil
production systems that are prone to leaks. These components include pumps, flanges,
valves, gauges, pipe connectors and compressors, tanks as well as others. Moreover,
routine wear, rust and corrosion, improper installation or maintenance, or overpressure
of the gases or liquids in the piping can cause leaks.6 In addition to unintentional leaks,
a number of sources intentionally vent gas. Gas is often vented during well completions,
by design from pneumatic valves, from well unloading and from oil and condensate
storage tanks. Pneumatic valves, which are used throughout natural gas systems,
operate on pressurized natural gas and bleed small quantities of natural gas during
normal operation. Within the oil sector, nearly all methane emissions come from
production fields in the form of venting from oil wells, storage tanks and processing
equipment.7 EPA’s estimated U.S. emissions from this sector are illustrated below.




Source: EPA, http://www.epa.gov/gasstar/basic-information/index.html

Proven, cost-effective technologies exist to reduce routine and nonroutine emissions of
methane during oil and gas exploration and production. The U.S. Environmental
Protection Agency (EPA), in conjunction with oil and gas companies, have developed
and tested more than 100 ways to reduce methane emissions while substantially
increasing revenues.8 Methane emissions are unique in that they are the equivalent of
lost product—as well as being harmful greenhouse gases and air pollutants. Methane is
the primary component of natural gas and every time an operator intentionally vents
methane, or equipment results in fugitive methane emissions, a valuable source of
energy is being wasted. The flip side to these losses is that the methods to capture or
prevent fugitive emissions and venting also result in a greater amount of gas sent to
pipelines. More gas produced equals greater profits, which in turn yield greater state tax


6
     Al Armendariz, Ph.D., Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities
     for Cost-Effective Improvements, 6, (January 26, 2009).
7
     U.S. EPA, Addendum To U.S. Methane Emissions 1990-2020: 2001 Update For Inventories, Projections And
     Opportunities For Reductions, 8, (May 27, 2004).
8
     See U.S. EPA, Natural Gas STAR Program, available at http://www.epa.gov/gasstar/.


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revenues and increased royalty payments, as well as decreased dependence on foreign
energy.

Although companies must make an initial upfront investment to install methane capture
or reduction technologies, the return on investment in many cases is quite short—
sometimes months—and almost always within a single year. Some of the most cost-
effective technologies and practices for reducing methane emissions are:

      Replacement of high-bleed pneumatics with low- or no-bleed ones;
       ―Green‖ well completions (or reduced emissions completions);
      Optimization of glycol circulation rates;
      Well automation, including plunger lifts to reduce well unloading methane
      emissions;
      Use of vapor recovery units on condensate and crude oil storage tanks.
      Directed inspection and maintenance programs at compressor stations;
      Replacement of compressor rod packing on reciprocating compressors or wet
      seals on centrifugal compressors; and
      Installation of BASO valves on heater treaters, dehydrator reboilers and process
      heaters at exploration and production sites.

Even though one would expect the benefit of increased profits from additional gas
savings to result in widespread implementation of all available cost-effective mitigation
technologies and practices, market failures have historically prevented such a rational
outcome. The oil and gas industry includes many small and independent operators who
are traditionally wary of participation in government programs, even voluntary ones,
and lack access to capital.9 Internal company policies and profit measurements often
operate to reward immediate profit maximization over investment aimed at longer-term
returns. These market failures, in light of the economic, energy, environmental and
public health benefits realizable from the implementation of methane emissions
controls, underscore the need for state, regional and federal policies aimed at reducing
methane emissions from the oil and gas industry. The evaluation – and eventual
implementation – of no-regrets measures in Texas represents an innovative approach to
achieving this policy shift.

There are also important policy grounds for this proposed measure in addition to the
―no-regrets‖ arguments presented herein. Preventing low pressure leaks is not a
difficult task. Not only are off-the-shelf technologies available today, there exists an
opportunity to improve current technologies. Gas plants and large production facilities
have a low pressure vent header (piping) that captures all venting sources into one
manifold. This piping is then vented or flared in a safe manner (to minimize local
venting on property). A similar approach should be used for oil and gas exploration and
production. By designing facilities to have such piping, it is straightforward to monitor,
quantify, and control the amount of gas vented.

9
    Small and midsize independent operators produce more than two-thirds of the natural gas in the lower 48
    states. Roger Fernandez, Robin Petrusak, et al, “Cost-effective Methane Emissions Reductions for Small and
    Midsize Natural Gas Producers,” June 2005.


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Greenhouse Gas Emissions
The Texas Railroad Commission reports that total natural gas production in Texas was
7.3 trillion cubic feet (tcf) in 2008, with 43 billion cubic feet (bcf) of natural gas vented
or flared. http://www.rrc.state.tx.us/data/production/gaswellcounts.php We believe
the amount of methane lost during the production and processing of natural gas is
closer to 1% of the total volume sold (see below), meaning that approximately 73 bcf of
gas were released in 2008 during natural gas exploration and production. Emissions of
methane from storage tanks used in crude oil production have recently been estimated
by TCEQ to be 5 bcf (other aspects of oil production may also result in methane
emissions but are not included in our calculations).
(http://www.tceq.state.tx.us/implementation/barnettshale/bshale-faq) Combining
emissions from natural gas exploration and production with crude oil storage tanks
yields an estimate for total methane emissions in Texas in 2008 of 78 bcf, or 1.5 million
metric tons of methane. Converting this to equivalent tons of CO2, it means that
methane releases from oil and gas systems in Texas are roughly 37 MMTCO2e.
Reducing these emissions by 30-50% over the next 10 years is an achievable target for
Texas and would result in emissions reductions between 11.1 and 18.5 MMTCO2e.

Proposed Approach for Texas
This measure would require the use of proven, ―no regrets‖ technologies to reduce
methane emissions from common sources in oil and gas exploration and production.
This measure would ensure the most cost-effective reductions are made at the facilities
with the greatest opportunity to reap the benefits. We propose the following process to
identify what technologies are no-regrets and when they would be employed.

First, the SB184 Advisory Committee make a determination that, for this sector, any
technology that results in a simple payback period for operators of 24 months or less
qualifies as ―no regrets.‖ Subsequently, specific technologies qualifying as ―no regrets‖
and the criteria needed to determine when they have to be employed would be identified
through a deliberative process during the second phase of the SB 184 Implementation
Plan. The EPA’s Natural Gas STAR program would serve as the primary data source for
this deliberative process.

For example, take the case of vapor recovery for storage tanks. The criteria needed to
determine whether installing a vapor control unit meets the 24-month simple payback
include: current and projected venting rates, composition and Btu content of vent gas,
market value of the recovered gas and liquids, and capital cost of the equipment. A
simple look-up table could be developed that identified the situations when the
equipment would lead to simple paybacks of less than 24 months.

Related actions in other states
Note: We offer these examples as illustrations of the ready availability and use of
technologies to reduce methane emissions. While not all of these will qualify as ―no
regrets,‖ many of them will if an appropriate economic analysis is conducted.

New Mexico, historically the largest contributor of methane emissions from the oil and
gas industry in the Intermountain West, has taken a number of steps to reduce methane


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emissions from its oil and gas industry. These steps include: 1) adoption of a goal to
reduce greenhouse gas emissions from the state’s oil and gas industry by 20% by 2020
(with a regulatory backstop); and 2) implementation of a mandatory greenhouse gas
reporting rule that requires reporting from large natural gas compressor stations, gas
processing plants and potentially from other oil and gas sources, including the
numerous pieces of equipment in the production sector. The New Mexico Environment
Department has been working with the Western Climate Initiative to develop a
reporting protocol for the exploration, production and natural gas processing sectors,
and anticipates that such sources will begin reporting greenhouse gas emissions in 2011.

Colorado recently passed comprehensive rules to mitigate the impacts associated with
its oil and gas industry. These reforms include important emissions limitations and
control technology requirements that will result in lower methane and VOC emissions
from oil and gas exploration and production activities. The following table illustrates the
differences in the air quality rules in Colorado’s Denver-Julesburg basin and the
Piceance and San Juan basins:10 In particular, we note the required use of green
completions in parts of the state. While this requirement was adopted to address
nuisance odor issues, the economics of the technology are such that they produce net
cost savings.

Controls                  Denver-Julesburg Basin                     Piceance and San Juan
                                                                     Basins
                 Condensate tanks that
                                                                     Condensate, crude oil and
                 cumulatively emit ≥ 30 tons
                                                                     produced water tanks with the
                 per year of VOCs (―tpy
                                                                     potential to emit ≥ 5 tpy VOCs
Condensate Tanks VOCs‖) must reduce
                                                                     within 0.5 miles of designated
                 emissions up to 81% in
                                                                     public places must control
                 summer and 70% in non-
                                                                     emissions by 95%.
                 ozone seasons.
                          Equipment that emits ≥ 15 tpy              Equipment with potential to emit
Glycol                    VOCs must reduce emissions by              ≥5 tpy VOCs located within 0.5
Dehydrators               90%.                                       miles of designated public places
                                                                     must control emissions by 90%.
                          New devices must be low
                          bleed, and existing devices                Operators must use low- or no-
Pneumatic                 must be retrofitted so that                bleed pneumatic devices for all
Devices                   emissions are ≤ low-bleed                  new, repaired or replacement
                          devices where technically                  devices where technically feasible.
                          feasible.
                                                                     Yes. Various specific practices to
Green                                                                reduce emissions are required
                          None
Completions                                                          where technically and
                                                                     economically feasible. Best

10
     CO Reg. XII; COGCC Final Rule Amendments, § 805, et seq. (2009). Note that statewide requirements are
     not included since they are generally less stringent than those imposed in the ozone nonattainment area and the
     Piceance and San Juan Basins.


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Controls                    Denver-Julesburg Basin                    Piceance and San Juan
                                                                      Basins
                                                                      management practices to reduce
                                                                      emissions required if green
                                                                      completion is not feasible.
                                                                      New pits with potential to emit ≥5
                                                                      tpy VOCs cannot be located within
Pits                        None
                                                                      ¼ mile of designated public
                                                                      places

Wyoming has a comprehensive best available control technology (BACT) program that
reduces VOCs and methane emissions from permitted oil and gas activities. Specifically,
Wyoming requires all dehydration unit emissions > 15 tons per year (tpy) of VOCs and
flash emissions > 20 tpy of VOCs from hydrocarbon liquid storage tanks and
pressurized vessels to be controlled by at least 98% statewide. Wyoming also requires
the use of ―green completions‖ on all new wells and the use of low- or no-bleed
pneumatic pumps in the rapidly developing Jonah-Pinedale basin.11 Wyoming’s focus on
reducing VOC emissions from new oil and gas sources is an important strategy for
improving air quality in the state and cost-effectively reducing methane emissions.

California’s Climate Change Scoping Plan proposes to address fugitive emissions from
the extraction process of the state’s large oil and gas industry, including on and off-
shore sources. These emissions are from well and process equipment venting: leaks of
flanges, valves and other fittings on the wells and equipment; and from separation and
storage units such as sumps and storage tanks. Controls for the fugitive sources range
from applying simple fixes to existing technologies, to deploying new technologies to
replace inefficient equipment and detect leaks and would include: improving operating
practices to reduce emissions when compressors are taken off-line; installing
compressor rod packing systems; substituting high bleed with low bleed pneumatic
devices; improving leak detection; installing electronic flare ignition devices; replacing
older equipment (flanges, valves, and fittings); and installing vapor recovery devices.
These are proven technologies according to the U.S. EPA’s Natural Gas STAR program,
which will pay back investments in a short period of time through saleable gas savings.
California’s proposal is expected to reduce fugitive methane emissions by approximately
0.2 MMTCO2e per year, beginning in 2015.

Montana is expected to experience a boom in natural gas development, especially in
coal-bed methane, over the next several years. All new minor sources must undergo a
BACT analysis, requiring that VOC vapors greater than 500 British thermal units per
cubic foot from wellhead equipment and oil and condensate storage tanks with the
potential to emit 15 tpy or greater be routed to a capture or control device such as a
pipeline or flare.12


11
       For a description of “green completions” see chapter 2 in this report, “Sources of methane emissions and cost-
       effective best management practices and technologies to reduce them.”
12
       For specific BACT requirements see MT Admin. Rules § 17.8.1603.


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Costs & Savings
According to the California Air Resources Board, California’s proposed measure in their
Climate Change Scoping Plan to address fugitive emissions from the upstream oil and
gas sector is estimated to result in short term capital costs of $795,000; total annualized
costs in 2020 will be $400,000, which is the sum of annual operating costs of $217,000
and annualized capital costs of $183,645. Annual savings from reduced natural gas
waste are estimated to be $4.1 million, which yields a net cost savings of $3.7 million
annually.

Due to the nature of this proposed measure, which includes numerous technologies
applied in a variety of operating conditions, we are providing general information to
support a conclusion that the measure qualifies as ―no-regrets.‖ As the review process
proceeds, we would welcome the opportunity to work with CPA staff to develop more
specific quantification.

The CPA should also note that the proposed methane reduction measures – in addition
to creating valuable revenues for producers – will also result in two important co-
benefits. First, the state will receive increased revenues from natural gas production
taxes and/or royalty payments. And second, there will be fewer emissions of VOC
(volatile organic compounds, often co-emitted with methane) released to the air.

A recent study estimated that methane losses during well completions, production,
processing and transmission in the Barnett Shale alone were 13 billion cubic feet
annually (Bcf/yr), or about 1% of total gas production.13 At $5.00/thousand cubic feet
(Mcf), this amounts to $65 million per year in lost revenues for producers and $4.9
million in lost severance tax payment to Texas. The numbers would be much larger if all
of the natural gas production in Texas was considered (Barnett Shale is about 25% of
statewide production) as well as natural gas associated with oil production. Assuming a
50% reduction from baseline methane emissions of 78 Bcf (39 Bcf), total savings (i.e.,
revenues for producers) would reach $390 million per year at a natural gas price of
$5/Mcf.

General
EPA’s Natural Gas STAR Program provides a wealth of information about dozens of
specific ways to reduce emissions from the oil and gas sector. http://www.epa.gov/gasstar/
We do not believe it would be productive to reproduce all of the technical and economic
information provided on their website. Instead, we are providing CPA staff with
synthesis information, and illustrative examples for key emissions sources and control
options, to make the case why reducing methane from oil and gas production and
processing is ―no regrets.‖

First, we offer a 1-page table entitled ―Cost-effective methane reduction opportunities,‖
prepared by EDF to summarize over a dozen concrete ways to reduce methane
emissions with paybacks of less than 24 months. Links to the Natural Gas STAR website

13
     Al Armendariz, Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for
     Cost-Effective Improvements (January 26, 2009).


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with more information on each of the listed measures are provided as footnotes on the
back of the table.

Second, an article in the Oil and Gas Journal posted on the Natural Gas STAR website
also provides a number of examples of the costs and benefits of implementing such
measures, many of which have simple paybacks of less than 24 months. See especially
Table 2: http://www.epa.gov/gasstar/documents/ogj_article110707.pdf (note this article is
copyrighted and is only available as a read-only file).

Finally, below we offer several examples of potential "no regrets" technologies in this
sector to illustrate the broad potential for economic and environmental benefits in
Texas.

Reduced Emissions Well Completions
Devon Energy, the largest producer in the Barnett Shale has won several awards from
the US EPA’s Natural Gas STAR program for its work to reduce methane emissions
using the kinds of practices recommended here. A representative from Devon told the
Texas Senate Committee on Natural Resources during a September 9, 2008 interim
hearing that it had captured 10.7 Bcf of gas since 2004 by employing ―reduced emissions
completions.‖ Across all of its production operations, using reduced emission
completions and other technologies, Devon claims it prevented more than 6.4 bcf of
methane from being released in 2007 alone, generating an additional $38 million in
revenue from increased sales of natural gas.14 Between 1990 and 2008, Devon reports
total natural gas savings of 42 Bcf, with a value of roughly $125 million.15

A Colorado cost-benefit analysis cites a presentation by Williams Production RMT at the
2007 Natural Gas STAR Production Technology Transfer Workshop, which included
cost information associated with green completions conducted in the Piceance Basin
from 2002 through 2006. The average methane recovery cost was 17.41 million dollars
(please note, the presentation indicates these are units of thousand dollars, however,
that was a typo). The average total revenue was 159.13 million dollars. That means that
for every dollar spent on green completions, they received a payback of $9.14.

Vapor Recovery Units for Storage Tanks
Storage tanks are a very promising source category for ―no-regrets‖ technologies to
reduce methane. TCEQ estimates that methane emissions in 2008 from oil and gas
production storage tanks in Texas were 5.3 bcf and 3.0 bcf for crude oil production and
condensate production, respectively.
(http://www.tceq.state.tx.us/implementation/barnettshale/bshale-faq) Two studies
have been done in Texas to measure the amount of gas vented from oil and condensate
tanks. These studies identified significant releases of vent gases, with measured site-
specific values as high as 150 mcf/day.16


14
     See Devon Press release, November 12, 2008
15
     See Devon’s Natural Gas STAR Experience, Slide 18
16
     HARC, VOC Emissions from Oil and Condensate Storage Tanks, October 31, 2006, available at:
     http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf, and Hy-Bon, Upstream Oil


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A TCEQ case study presented at an oil and gas workshop (see attached) provides a case
study for capturing emission from a storage tank battery in North Texas releasing 190
mcf/day of gas, with a heat content of 2400 Btu – 2.4 times higher than standard
natural gas. Capturing the gas could have a monthly value of $68,000 (assuming
$5/mcf natural gas price adjusted for the higher heat content of the captured vent gas).
In this case, the simple payback period for a vapor recovery unit costing $32,000 would
be 14 days ($32,000/$68,000 per month = 14 days). Some vendors of vapor recovery
technology also offer alternative financing options to the outright purchase of the
equipment, including providing the equipment at no up-front cost recoup in return for a
share of the recovered product.

Replace or Retrofit Pneumatics
Pneumatic devices powered by pressurized natural gas are used widely in the natural gas
industry as liquid level controllers, pressure regulators, and valve controllers. Methane
emissions from pneumatic devices, which have been estimated at 51 billion cubic feet
(Bcf) per year in the production sector are one of the largest sources of vented methane
emissions from the natural gas industry. Reducing these emissions by replacing high-
bleed devices with low-bleed devices, retrofitting high-bleed devices, and improving
maintenance practices can be profitable. According to EPA, replacing a high-bleed
pneumatic device with a low-bleed device can yield annual savings of more than $1,000
with payback periods ranging from 1 to 14 months. See
http://www.epa.gov/gasstar/documents/ll_pneumatics.pdf (also attached).

References
  1. Appendix H: New Mexico Climate Change Advisory Group, Final Report and
     Appendices, December 2006. See http://www.nmclimatechange.us/. The
     comparable measure is ES-12, described on pages 5-13 to 5-14 of the report; and
     H-47 to H-50 and H-91 to H-93 of the Appendices.
  2. Appendix A: California Air Resource Board, "Climate Change Proposed Scoping
     Plan Appendices, Volume I: SUPPORTING DOCUMENTS AND MEASURE
     DETAIL,‖ December 2008 and ―VOLUME II: ANALYSIS AND
     DOCUMENTATION," October 2008. See:
     http://www.arb.ca.gov/cc/scopingplan/document/scopingplandocument.htm.
     The comparable measure is I-2, described on pages C-153 to C-154 of Volume I
     and pages I-32 to I-33 of Volume II. Additional materials about the
     implementation of this measure is posted at http://www.arb.ca.gov/cc/oil-
     gas/oil-gas.htm, including a December 2009 presentation providing more detail
     and initial results from an industry survey.
  3. Appendix I: Colorado Oil and Gas Conservation Commission, ―Cost-Benefit and
     Regulatory Analysis.‖ See:
     http://cogcc.state.co.us/RuleMaking/CBA/COGCC_CBA_Main_doc.pdf ,
     section on Rule 805.




    and Gas Storage Tank Project; Flash Emissions Models Estimation, July 16, 2009, see attached excerpts,
    electronic version of final report not yet posted.


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4. Appendix J: Devon Energy Corporation: 1) Press release dated November 12,
   2008; 2) Undated presentation titled ―Devon’s Natural Gas STAR Experience,‖
   see especially slides 18-25.
   http://www.window.state.tx.us/finances/noRegrets/proposals/appendices/AppendixJ.pdf




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