Methane Leakage

Overview

As the following schematic illustrates, although natural gas is less carbon dioxide (CO2)-intensive than coal at the generation stage (right figure) of the life cycle, over the entire life cycle (i.e., left to right) it is possible that the two fuels are more similar in greenhouse gas emissions. Methane (CH4) emissions at both the extraction (left figure) and transmission (middle figure) stages may sum with CO2 emissions to negate the generation-stage advantage of gas. Use of emission factors for equipment with leakage potential such as pneumatic controllers (pictured; the so-called bottom-up approach) yields certain estimates of CH4 leakage, but atmospheric CH4 determinations (the so-called top-down approach) typically result in higher leakage estimates.

 

Natural Gas Life Cycle

  • At the April 24-25, 2014 Western Interstate Energy Board annual meeting, a session concerning methane leakage in the natural gas life cycle for power generation was included. Speakers included Tom Curry, Vice President of M.J. Bradley & Associates; Dr. Gabrielle Petron, Associate Scientist at the National Oceanic & Atmospheric Administration; and Mike Silverstein, Administrator & Technical Secretary of the Colorado Air Quality Control Commission. Mr. Curry spoke about bottom-up estimation of methane leakage, Dr. Petron covered top-down estimation of leakage, and Mr. Silverstein discussed Colorado’s new regulations addressing methane leakage in the oil & gas sector. A summary of their presentations are available on the agenda beginning at 10:15 a.m. on April 24th.
  • SPSC March2015 webinar on quantification of methane emissions and their regulation. This webinar had two purposes. The first purpose was for the SPSC contractor, M.J. Bradley & Associates, to provide an update on the current state of knowledge concerning methane emissions in the life cycle of natural gas for power generation. A number of important studies have been published since the contractor last updated SPSC in October, 2014. The second purpose of the webinar was to inform the SPSC on regulation of methane emissions, at the federal level (where both a proposed rule for new sources in the oil & gas sector and expanded voluntary programs are to be released by EPA in 2015) and at the state level. Regarding state regulation, Wyoming and, more recently, Colorado have been regulating methane emissions from the oil & gas sector.
  • April 2015 – MJBradley & Associates – Methane Emissions final report and Implications for Policymakers.
  • White House: In March, 2014, the Administration released its so-called Methane Strategy, a group of initiatives to reduce methane emissions. These initiatives are focused on the landfill, coal mining, agricultural and oil and gas sectors. The Methane Strategy is a part of the President’s broader Climate Action Plan. For more information, visit: link
  • Federal regulations: There were two final rules promulgated in 2016 by federal agencies to mitigate methane emissions from the oil and gas sector.  In June, the Environmental Protection Agency (EPA) finalized a rule entitled Oil and Natural Gas:  Emission Standards for New, Reconstructed, and Modified Sources.[1]  In November of 2016, the Bureau of Land Management (BLM) finalized a rule entitled Waste Prevention, Production Subject to Royalties, and Resource Conservation.[2]  These rules were predicated on two principal findings.  First, there has been a large (approximately 2.5-fold) increase in atmospheric methane concentration between years 1750 and 2014.[3]  Second, oil and gas systems constitute the largest methane-emitting sector in the U.S., representing approximately one-third of total anthropogenic methane emissions in the U.S. Greenhouse Gas Inventory.[4]  These findings are of concern because methane is, similar to carbon dioxide, a greenhouse gas.  Furthermore, methane’s global warming potential is many-fold greater than that of carbon dioxide, thus making methane emissions of concern.  Methane is the primary component of natural gas.

The rule promulgated by EPA is restricted to new, reconstructed, or modified sources; thus, existing sources of methane emissions are not subject to this rule.  The table below summarizes several aspects of the EPA rule.  Standards of performance, prescribed as either numerical targets or technological mitigation measures, are detailed in the rule.  An example of a numerical target is for pneumatic controllers:  a natural gas bleed rate of not greater than 6 cubic feet per hour is required.  An example of a technological mitigation measure is for reciprocating compressors:  rod packing must be replaced on or before 26,000 hours or 36 months of operation.  Interestingly, an EPA rule for new sources typically precedes a rule covering those emissions from existing sources.  EPA is currently collecting information that would inform a rule covering existing sources of methane emissions.  The stated intentions of the incoming Administration, however, suggest that a rule for existing sources of methane emissions in the oil and gas sector will not be promulgated by EPA, at least in the short term.

The BLM-promulgated rule is narrower in regulatory scope in that it focuses on oil and gas production, given that its geographic scope is restricted leases located on federal and tribal lands.  The rule’s purpose, to minimize natural gas wasted via venting, flaring, and/or equipment leaks, is consistent with BLM’s legal and proprietary responsibilities to act as a responsible manager of natural resources on public lands.  In addition, reductions in wasted natural gas will increase royalty receipts and reduce the above-mentioned environmental effects of methane.  Notably, in 2014 approximately 30 and 80 billion cubic feet of natural gas were vented and flared, respectively, representing 4-5% of gas production on public lands.[5]  The table below summarizes several aspects of the BLM rule.  Similar to the EPA rule, numerical targets and technological mitigation measures are required to reduce methane emissions.  An example of a numerical target is for flaring:  allowable flared gas will decrease from 5400 to 750 million cubic feet per well per month over the 2018-2025 timeframe.  An example of a technological mitigation measure is for liquids unloading:  certain best practices such as use of plunger lifts must be employed.  Of note, BLM estimates that $3-$14 million per year in additional royalties, over 10 years, will result from additional captured natural gas. 

The EPA rule has been challenged by one group of states and two individual states, as well as by a group of oil and gas sector trade associations, in the U.S. Court of Appeals for the DC Circuit.  Recently (January 5, 2017), the DC Circuit consolidated these challenges and challenges to earlier EPA rulemakings addressing oil and gas sector emissions.  The BLM rule has also been the subject of litigation.  A pair of oil and gas sector trade associations have filed a lawsuit in the U.S. Federal District Court for the District of Wyoming, as have three Western states (Montana, North Dakota, Wyoming).  Two other Western states (California, New Mexico) have intervened on behalf of the BLM in the latter case.  In addition, the possibility of congressional override of the BLM rule is present.  The Congressional Review Act (CRA), although rarely employed historically, could be used by Congress to override federal agency rules finalized after June 13, 2016.  Thus, the BLM rule would be vulnerable under the CRA, while the EPA rule would presumably not be vulnerable.

An expressed criticism of the BLM rule is that it duplicates the EPA rule in the cases of methane emissions from new, reconstructed, and modified oil and gas wells located on federal and tribal lands.  Furthermore, certain Western states (see below) have also promulgated rules intended to reduce methane emissions from the oil and gas sector.  The BLM has, however, allowed for oil and gas operators to instead comply with the EPA rule.[6]  Operators can also comply with state regulations in lieu of those of BLM.  In order to instead comply with a state rule, an operator must request a variance from BLM and the state requirements must be at least as stringent as those of BLM.[7]

 

 

EPA Rule

BLM Rule

Air Pollutant Emissions Addressed

Methane, VOCs*

Methane

 

Emission Sources (Major)

Production, processing, transmission, storage

Production only

Key Emission-Reducing Provisions

1. Hydraulically-fractured oil well completions, pneumatic pumps, other fugitive emissions now regulated (all formerly unregulated for either methane or VOCs)

2. Hydraulically-fractured gas well completions, other fugitive emissions now regulated (formerly regulated for only VOCs)

3. All pneumatic controllers, centrifugal and reciprocating compressors[8] now regulated (formerly regulated for only VOCs and for only for a subset of such equipment) 

1. Venting prohibited[9]

2. Flaring reduced via:

(a) increased capture of previously-flared gas

(b) decreased allowable flared gas

3. Leaks from equipment decreased

4. Venting from equipment (e.g., pneumatic controllers and pumps) and practices (e.g., liquids unloading) decreased    

Estimated Emission Reductions

510,000 T methane (11 million T CO2 Eq.), 210,000 T VOCs, both in year 2025

175,000-180,000 T per year (over 10-year period)

Net Benefits (Benefits – Costs) in

Year 2025 (EPA)[10] or 2026 (BLM)[11]

 

$170 million

$125-$193 million

Regulatory Authority

Clean Air Act §111(b)

Mineral Leasing Act §188-287 and others

Table Acronyms: EPA, Environmental Protection Agency; BLM, Bureau of Land Management; VOCs, volatile organic compounds; T, tons; CO2 Eq., carbon dioxide equivalents (assumed global warming potential for methane at 100 years = 25 times that for CO2); * VOCs are precursors for ozone formation, as well as hazardous air pollutants in some cases (e.g., benzene)

  • State regulations:

    (a) Colorado:  The Colorado Department of Public Health & Environment promulgated a 2014 rule that was aimed at reducing both methane and VOC emissions from the state’s oil and gas production sector.  Partial motivation for the rule was that certain areas of the state are not in attainment for the EPA standard for ozone.[12]  In a collaborative approach to rulemaking, negotiations during development of the rule included representatives of both the oil and gas and environmental sectors.  Annual costs of the rule were estimated to be $42 million; benefits include reductions in methane (64,000 T per year) and VOCs (94,000 T per year). 

    Leak detection and repair (LDAR) of equipment at wells and compressor stations was a focus of the rule.  It also tightened pre-existing control requirements at facilities such as storage tanks, glycol dehydrators, and pneumatic controllers, as well as including a requirement to minimize emissions during well maintenance.

    (b) Wyoming:  Similar to Colorado, certain areas of Wyoming are not in attainment of the EPA ozone standard.  The Wyoming Department of Environmental Quality’s (DEQ) principal motivator for its rule, then, was to reduce VOC emissions; reductions in methane emissions are co-benefits of regulation.  Even minor sources of VOCs are required to install control technology to reduce VOC emissions.  As in Colorado, facilities such as storage tanks, dehydrators, and pneumatic pumps and controllers are regulated in addition to wells.  Equipment-specific requirements are included in the Wyoming DEQ’s oil and gas permitting guidance.

    (c) Alberta:  Compared to the U.S., methane emissions from the oil and gas sector represent a greater proportion (nearly three-quarters) of total anthropogenic emissions in Alberta.  For this reason and others, in November, 2016, the provincial government announced the Climate Leadership Plan.  A pillar of this plan is a 45% reduction in oil and gas sector methane emissions by year 2025.  Emission design standards for new Alberta oil and gas facilities (similar to the above-described EPA rule for new, reconstructed, and modified sources), improved measurement and reporting of methane emissions (and LDAR requirements), and emission design standards for existing oil and gas facilities (similar to the potential EPA rule for existing sources), to be effective in year 2020, will be employed to achieve this reduction.[13]  A collaborative rulemaking approach similar to that described for Colorado will be used to develop the emission design standards for existing facilities.  Currently, only carbon offset programs are available to incent methane emission reductions in the Alberta oil and gas sector; that is, oil and gas facilities can register with the Alberta Emissions Offset Registry to sell greenhouse gas (carbon) offsets.[14]

[1] Environmental Protection Agency.  Oil and Natural Gas Sector:  Emission Standards for New, Reconstructed, and Modified Sources.  Fed. Reg. 81, 35824-35942 (June 3, 2016).

[2] Department of the Interior, Bureau of Land Management.  Waste Prevention, Production Subject to Royalties, and Resource Conservation.  Fed. Reg. 81, 83008-83089 ( November 18, 2016).

[3] Supra note 1, at 35836.

[4] Id., at 35838.

[5] Supra note 2, at 83010.

[6] Id., at 83013.  

[7] Id., at 83013.

[8] Excludes compressors at well sites.

[9] Certain specified conditions (e.g., emergencies) are exceptions to this prohibition.

[10] Net benefit values are derived using a 3% discount rate.  Benefits only include climate-related benefits associated with methane emission reductions.  EPA was unable to monetize benefits of VOC emission reductions.

[11] Net benefit values are derived using a 3% discount rate.  Benefits include sale of additional captured natural gas and climate-related benefits associated with methane emission reductions.

[12] As noted above, VOCs represent a precursor for ozone formation.

[13] More information available at:  https://www.alberta.ca/climate-methane-emissions.aspx

[14] More information available at:  http://www.csaregistries.ca/albertacarbonregistries/eor_about.cfm

  • Environmental Defense Fund (EDF): EDF, since 2012, has been coordinating a series of 16 scientific studies that have examined methane leakage at various stages of the life cycle for electric generation from natural gas. These studies have been organized into five areas:  production studies, midstream studies, local distribution studies, basin-specific studies, and other studies.  EDF’s approximately 100 partners in this effort have included oil and gas sector entities and numerous universities and other research institutions.  Two of the 16 studies are highlighted below under Additional Resources.  The Allen and colleagues study, a production area study, was the first EDF series study published in a peer-reviewed journal.  The Petron and coworkers study, a basin-specific area study, is of particular interest to regulators and policymakers in the West because it focuses on the Denver-Julesburg Basin in Colorado.  Two findings common to many, if not all, of the studies are:  1) methane leakage from oil and gas facilities is greater than EPA’s U.S. Greenhouse Gas Inventory suggests, and 2) methane leakage exhibits a so-called superemitter phenomenon, i.e., a relatively small number of facilities account for a relatively large proportion of total methane leakage.  For further information on the EDF studies, visit: https://www.edf.org/sites/default/files/methane_studies_fact_sheet.pdf
  • Brandt AR, Heath GA, Kort EA, et al. Methane leaks from North American natural gas systems. Science 343:733-735, 2014. This journal requires a subscription for access. Many academic institutions have print and/or electronic subscriptions to this journal.
    This review paper concerns the discrepancy in methane leakage estimation between bottom-up studies of leakage and those using the top-down approach. The latter, when corrected for non-oil and gas sector emissions, indicate that methane leakage attributable to the oil and gas sector is approximately 50% greater than bottom-up studies suggest. This review is especially useful in that it addresses limitations of both approaches. A key conclusion is that top-down studies, when limited to those of a national scope, show leakage that ranges from 1.25- to 1.75-fold greater than that derived from bottom-up studies.
  • Howarth RW, Santoro R, and Ingraffea A. Methane and the greenhouse-gas footprint of natural gas from shale formations. Climatic Change 106:679-690, 2011. Click here to access. This is the paper that intensified the debate about whether natural gas is less greenhouse gas-intensive than coal. The authors’ analyses also showed that methane leakage associated with unconventional natural gas extraction (i.e., shale gas) is higher than that with conventional gas extraction. The paper reported that 3.6-7.9% methane leakage occurred with unconventional gas extraction. While certain approaches used by the authors have been criticized, unique aspects of the study include the use of up-to-date global warming potential (GWP) values (higher than those typically used in climate change research) and its focus on the 20-year GWP for methane, given the urgent need for action to combat climate change.
  • Petron, G, Karion A, Sweeney C, et al. A new look at methane and non-methane hydrocarbon emissions from oil and natural gas operations in the Colorado Denver-Julesburg Basin. Journal of Geophysical Research: Atmospheres 119:6836-6852, 2014. This journal requires a subscription for access. Many academic institutions have print and/or electronic subscriptions to this journal.
    This paper is an update of the authors’ 2012 paper in the same journal that showed that a top-down estimate of methane leakage was two times that derived using a bottom-up approach. For this newer study, atmospheric sampling done during two flights across a Colorado oil and gas basin was combined with mass-balance modeling. After correction for non-oil and gas sector emissions, the difference in methane emissions between the top-down approach and a bottom-up approach was approximately three-fold. Benzene emissions were similarly analyzed, and the top-down versus bottom-up discrepancy was even greater (seven-fold greater with top-down estimation).
  • Allen DT, Torres VM, Thomas J, et al. Measurements of methane emissions at natural gas production sites in the United States. Proceedings of the National Academy of Sciences USA 110:17,768-17,773, 2013. Click here to access. This was the first of a series of several studies co-sponsored by the Environmental Defense Fund and the oil and gas sector. The study used a bottom-up approach, with values for methane leakage from various pieces of equipment with leakage potential coming from direct measurement rather than EPA emission factors. This study included data from 190 production sites in the U.S. The authors reported two notable findings. First, methane leakage associated with well completions was lower than predicted by EPA emission factors; second, leakage from certain pieces of equipment such as pneumatic controllers was higher than predicted by emission factors. Overall, methane leakage associated with natural gas extraction was found to be comparable with that estimated by bottom-up studies not using direct methane determinations (i.e., using emission factors). Like the study of Howarth and colleagues this study has been criticized, primarily for its limited and perhaps selective sampling of natural gas production sites.