Water

A comprehensive and objective understanding of water resource risks and risk management in the production and processing of natural gas is vital to sound decision-making. With many areas of the U.S. experiencing drought conditions from severe to exceptional ^{Footnote †} , water resources are already under stress. Fresh water is a valuable resource, and many aquifers are overstressed by both drought and competition for domestic, agricultural, and industrial water needs, including water needed for hydraulic fracturing operations. Groundwater depletion—a situation in which water is withdrawn from aquifers faster than it can be replenished—is occurring in many areas where there are shale plays. Depletion not only reduces the quantity of available water, it can also result in an overall deterioration of water quality. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42}

All phases of shale gas development have the potential to affect either the quantity or quality of local water resources. ^{Reference Horner, Halldorson and Slutz53–Reference Vidic, Brantley, Vandenbossche, Yoxtheimer and Abad54} We focus on water management practices that can lead to environmental impacts versus reviewing the specific environmental impacts that may arise as a consequence of fracking. EPA describes potential water impacts of hydraulic fracturing as occurring during five stages: water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and waste disposal. ^{Footnote ‡} Water quantity concerns are primarily associated with the water acquisition phase, as large volumes of water are required for hydraulic fracturing operations over a short period of time. Water quality concerns are mainly associated with the remaining four phases. Figure 3 illustrates that the variety of water quantity and quality risks shale gas development could pose for local water resources.

Figure 3.

Overview of risks to water resources throughout various phases of shale gas development. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42}

Quantity related risks depend on the number of wells drilled, water use per well, amount of recycling or nonpotable water use that occurs to offset freshwater demands, and local water availability. Water use per well is dependent on well characteristics such as depth, horizontal drilling distance, and local geological conditions. As shale gas development continues to grow rapidly across the United States, the total demand for water used during site operations is projected to increase in many areas. ⁵⁵ Drilling and fracking operations involved in shale gas development require millions of gallons of water per well that must be acquired and transported to sites to fracture the shale formations. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42,Reference Vengosh, Warner, Jackson and Darrah56-57} These requirements bring shale gas development into direct competition with domestic and agricultural uses of fresh water. Figure 4 provides a sense of the scale of the water required per fractured well in various plays for a particular year—along with the fairly large levels of uncertainty or error in the estimates.

Figure 4.

Water use (and error bars) per fracture on selected wells in the year 2011. Note: Low and high error bars represent minimum and maximum reported water usage per well, respectively. Upper and lower ends of boxes represent 75th and 25th percentile, respectively. Horizontal lines in boxes represent medians. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42}

It is worth putting in perspective the relative amount of water used during natural gas production, whether conventional or unconventional, compared to what is used during the generation of electricity by various types of natural gas power plants, as well as power plants using other fuels. Figure 5 shows that the water consumption for natural gas production is a relatively small percentage of total water consumption for most types of natural gas power plant operations. This is due to the large water requirements associated with traditional power plant cooling technologies. Water consumption differences associated with fuel production from different sources are small relative to the differences between fuel production and power plant cooling water requirements, with the exception of natural gas combustion turbines (NGCT), regardless of prime mover type and cooling system type. Figure 6 compares life cycle water consumption among different electricity generating technologies and fuel types. Modern natural gas power plants generally consume less water than other thermal electricity technologies, and only require more water on a life cycle basis than wind and photovoltaic technologies, when normalized for electricity output (Fig. 6).

Figure 5.

Water consumption rates in liters per kilowatt-hour (L/kWh) for the life cycle stages of natural gas generation. ^{Reference Clark, Horner and Harto58} Note: NGST is natural gas steam turbine, NGCT is natural gas combustion turbine, NGCC is natural gas combined-cycle, RC is recirculating cooling, and OT is once-through cooling.

Figure 6.

Water consumption rates in gallons/megawatt-hour (MWh) for the life cycle stages of electricity generating technologies. ^{Reference Meldrum, Nettles-Anderson, Heath and Macknick59}

It should be noted that life cycle water use rates that are amortized to total lifetime energy output cannot capture the temporal nature of natural gas water usage. For unconventional oil and gas development, all the water required for well production occurs over a small number of days, whereas the water required for coal or uranium mining and processing occurs throughout the lifetime of the mine. This temporal asymmetry in when water usage occurs can lead to localized water stresses resulting from oil and gas development that are not captured through these static metrics.

Quality-related risks depend on onsite construction techniques, onsite chemical management practices, and wastewater management practices, as well as the geochemical composition of the formations being developed. During operations, there are millions of gallons of wastewater that must be stored, transported, treated, and/or disposed of. Risks may vary for any given shale gas development site. In many cases, risks to water resources extend beyond the location of the well being drilled, depending on the source location of the water and where wastewater is treated.

Vengosh et al. (2014) identified the most likely pathways for water quality degradation: groundwater contamination due to stray gas, fracking water, and/or formation water from leaking wells; surface water contamination from spills, leaks, and poor wastewater treatment practices; toxic elements that accumulate in the soil and eventually make their way into ground and surface water; and degradation through overextraction. ^{Reference Vengosh, Jackson, Warner, Darrah and Knodash60} These pathways, and corresponding levels of contamination, have been confirmed by several studies: Osborn et al. (2011) identified higher levels of thermogenic methane (i.e., methane from deep sources, consistent with shale gas, as opposed to biogenically produced surface methane) in shallow water wells closer to areas of active shale gas development. ^{Reference Osborn, Vengosh, Warner and Jackson61} At the same time, no evidence of contamination from fracking fluids or deep brines was found. The most likely mechanism for groundwater contamination was identified as leaky gas-well casings. ^{Reference Sakmar61-Reference Sakmar62} Using noble gases as a tracer, Darrah et al. (2014) were able to confirm that likely sources of leaks include faulty well casings; poorly cemented well annuli (the void that directs drilling fluid and drill cuttings back up to the surface); and improperly abandoned gas wells. ^{Reference Darrah, Vengosh, Jackson, Warner and Poreda63} Surface water can be impacted as well: Olmstead et al. (2013) found that shale gas well construction negatively affects downstream water quality as measured by total suspended solids; and that the offsite treatment of shale gas waste in permitted treatment plants raises downstream concentrations of chloride, a component of well wastewater. ^{Reference Olmstead, Muehlenbachs, Shih, Chu and Krupnick64}

Currently, best management practices (BMPs) to mitigate quantity or quality related risks have not been established by industry and stakeholder groups. Efforts have been made to encourage shale gas developers to develop industry standards to protect water resources. In its 2011 report identifying measures to reduce the environmental impact of shale gas production, the U.S. Department of Energy's Secretary of Energy Advisory Board (SEAB) identified four recommendations for the protection of water quality. Recognizing that different approaches to implementation would be required in different regions, the SEAB suggested that the responsibility for implementing these four recommendations should be at the state level, with state regulators and industry working together to develop a plan (Table 2). ⁶⁵

Table 2.

Selected recommendations from the Secretary of Energy Advisory Board. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick65-Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick66}

Various attempts have been made to define BMPs for water management. ^10,66-70 For example, prior studies have noted that quantity-related risks can be mitigated by recycling wastewaters from the fracking process for reuse in new wells, or by using other, nonfresh sources of water. Recycling of flowback water for reuse in fracking operations is increasingly being used in the industry, motivated by a variety of factors in different locations, such as economic, regulatory, freshwater availability, or social license to operate. Figure 7 shows the example of water treatment methods by proportion of water volumes treated in different manners for a series of years in Pennsylvania, where reuse jumped from 10% of wastewater volume to 80% in just three years, on a 4-fold increase in wastewater volume over the same period. This was due in part to regulatory changes in Pennsylvania, and the expense associated with transporting wastewater for disposal to the nearest treatment facilities in Ohio. ^{Reference Rahm, Bates, Bertoia, Galford, Yoxtheimer and Riha71} In other locations, low-cost freshwater acquisitions as well as relatively low-cost underground injection wastewater disposal opportunities have limited the widespread adoption of recycling activities.

Figure 7.

Water disposal volumes and methods in Pennsylvania by reporting period from 2008–2011. ^{Reference Rahm, Bates, Bertoia, Galford, Yoxtheimer and Riha71} For the years 2008 and 2009, reporting was annual. In the years 2010 and 2011, data were reported for roughly the first and second half of each year, denoted by “a” and “b,” respectively. POTW represents publicly operated treatment works. Water drops indicate total wastewater volumes: shaded drops = 200,000 m³; open drops = 100,000 m³.

Quality-related risks can potentially be mitigated through a variety of techniques that address the possible water contamination pathways of development activities. Water-quality related risks pose additional challenges over water quantity-related risks because there are multiple processes along the development chain involving multiple operating companies that could lead to water contamination. Examples of mitigation techniques for contamination pathways include:

• • Proper well construction techniques to address faulty well casings and poorly cemented well annuli.

• • Using a closed-loop drilling system, which can minimize opportunities for spills.

• • Eliminating flowback water mixing with freshwater in open impoundments through the use of separate water tanks, which reduces spills and avoids water leaking through impoundments.

• • Using protective liners for pits and tanks to prevent water seepage.

• • Minimizing the use of toxic chemical additives in case there is an uncontained spill.

• • Proper well abandonment practices.

Although these opportunities describe generally how to prevent contamination risks, these efforts can be implemented in a variety of ways depending on company common practices, state-level requirements, and region-specific conditions. ^{Footnote §}

In the absence of specific BMPs, federal and state regulation is an alternative, though one not preferred by the industry. Currently, there is little consistency in regulations from one state to the next regarding water and wastewater management practices associated with unconventional oil and gas development. This is due, in part, to the heterogeneity in multiple dimensions found within each shale play—including geology, well performance, and a number of above-ground local issues—thus requiring diverse approaches. Geological and geochemical differences associated with each shale play indicate that some practices may be effective in some plays but not others. For example, some plays might have geological conditions that support ample disposal wells for wastewater disposal, whereas others might have different geological conditions that make underground injection in the play unfeasible, so that wastewater must be transported out of the play or otherwise treated and reused.

The regulatory frameworks governing risks to water quantity and quality are dynamic and multilayered. Regulation of water withdrawals is primarily a matter of state and local law (other than on federal lands), and the legal framework governing water rights differs from state to state, although there is some consistency along regional lines. ^{Reference Groat and Grimshaw67} There is a trend among states toward requiring operators to identify the sources of water used and to report the amount of water used in hydraulic fracturing. In addition, more states are providing incentives to promote reuse of water used in hydraulic fracturing such as by recycling flowback waters or production fluids. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42}

With respect to risks to water quality, states have primary responsibility. The process of hydraulic fracturing, other than when diesel fuel is used, is expressly excluded from federal regulation under the Safe Drinking Water Act's Underground Injection Control program. States have therefore taken the lead in regulating well construction and other aspects of hydraulic fracturing to mitigate potential risks to water quality. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42,Reference Richardson, Gottlieb, Krupnick and Wiseman44} Working across state governments, many partnerships and organizations are active in addressing water management regulatory issues. For example, according to the Secretary of Energy Advisory Board (SEAB), the State Review of Oil and Natural Gas Environmental Regulations (STRONGER) and the Ground Water Protection Council (GWPC) are two existing organizations that work to share information to improve the quality of regulatory policy and practice in the states. The budgets for these organizations are small and merit public support. Previously, federal agencies (DOE and EPA) provided funding for STRONGER and GWPC, but federal funding is currently not provided. To maintain credibility and to ensure their ability to set their own agenda, these organizations cannot rely exclusively on funding provided by companies of the regulated industry. ^65-66

EPA does have broad authority to regulate direct and indirect discharges of wastewater from point sources under the Clean Water Act and the injection of produced water into underground injection wells for disposal under the Safe Drinking Water Act. In response to a congressional request, EPA has also initiated a multiyear study to understand the potential impacts of hydraulic fracturing on drinking water resources. ⁵⁷ The study has been designed to cover the full life cycle of water in hydraulic fracturing and is scheduled for release in draft form in late 2014. When completed, the study should provide a more comprehensive understanding of the relationship between hydraulic fracturing and drinking water resources.

Once this relationship is understood, a first step in developing BMPs for reducing risks to water resources in shale gas development is to evaluate the efficacy and technological potential of various water risk management practices. Further examination of BMPs could assist developers in evaluating important water management questions—such as whether installing protective liners at pad sites or reducing use of certain chemical additives would have a greater impact on reducing risks to water resources in specific regions. Such analysis of BMPs could also provide greater insight into opportunities and risks for regulators, policymakers, and other stakeholders, as well as GHG emissions. ⁷² In some cases, recycling wastewaters can be more expensive than other waste management options as it involves energy for treatment along with costs associated with storing water, transport of water, and transport and disposal of the solid wastes removed from the treated water. Further research is needed to better understand these trade-offs.

An additional area of needed research is to evaluate the extent to which certain water risk management practices are applicable or effective across multiple types of formations. As noted above, some practices might be less appropriate or cost-effective than others under certain geochemical conditions. For example, using recycled flowback or produced water for secondary fracking operations may be a challenge in certain areas because this water may contain high concentrations of undesirable impurities.

Comprehensive analyses of water risks are hindered by a lack of reliable, publicly available data. Data are not publicly available for many regions for total water withdrawals, total wells drilled, water recycling techniques, wastewater management, and other management practices. There are no international, national, or state-level disclosure initiatives to track or evaluate the success of BMP implementation. For example, it is difficult to determine how many operators are currently using (and with what success) the widely discussed BMP to use closed-loop drilling practices because operators are not required to report this information. These data would assist in developing appropriately flexible and adaptive BMPs. In the absence of such reporting, data collection efforts would likely require close collaboration with multiple industry partners operating in a variety of locations.

Based on research by JISEA (2012), ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42} the following BMPs were identified as being important for minimizing risks related to water quality and quantity:

• • Measure and publicly report the composition of water stocks and flow throughout the fracturing and cleanup process.

• • Adopt standardized requirements for baseline water quality testing.

• • Use a closed-loop drilling system.

• • Fully disclose hydraulic fracturing fluid additives, with greater clarity on trade secret exemptions.Footnote **

• • Eliminate flowback water mixing with fresh water in open impoundments.

• • Use protective liners at pad sites.

• • Minimize use of chemical additives and promote the development and use of more environmentally benign alternatives.

• • Optimize recycling of flowback water.

A criticism of best practice studies to date has been the lack of data that supports the efficacy of these practices for reducing risk and the lack of accountability. ^{Reference Kemp73-74} The list presented above is not described by any of the references with data showing how effective these practices are at producing the expected benefits. Equally important is that no economic analyses are provided that allow business decisions to be made assuming several options are available (including doing nothing). In addition to the lack of characterization of the recommended practices, it is not clear which of these will provide the greatest benefit for risk management. For example, research is needed to determine the benefit of protective liners at pad sites. Would it be better to concentrate on recycling flowback water or installing liners? Assuming finite resources, some sort of methodology for associating practices with risks is needed.

Because BMPs are not legally binding, the potential for lack of accountability is a concern. The publicly available reports tend to use words such as “encourage,” “strive,” and “should consider” regarding these practices leading to the possible conclusion that these are the “right” things to do and they should be implemented in one form for all to follow, yet there is no legal requirement to do so. When properly applied, “best practices” are most often adopted with thorough and detailed economic and efficacy data, allowing stakeholders including industry, regulators, researchers, environmental groups, and the public to understand what practices are currently in use, how effective they are at reducing the risk of water impacts, and where improvements are needed. When BMPs are not properly applied—or in the case of the shale gas industry, are unclear and inconsistently applied—stakeholders are likely to hear calls for binding regulation.

With little success, attempts were made in the preparation of this publication to collect data regarding the character and use of the recommended practices from industry and public databases including FracFocus (www.fracfocus.org). Disclosure of fracturing fluid chemicals on fracfocus.org is now in place in Colorado, Wyoming, and Texas and is being considered in several other states. The specific reporting requirements of proposed legislation with regard to what types of chemicals would have to be disclosed; where the disclosure would be published; whether volumes of chemicals would be required; and how trade secret chemicals would be addressed can differ greatly from state to state. ^{Reference Richardson, Gottlieb, Krupnick and Wiseman44,Reference Pless75} While initiatives like FracFocus are highly valuable for improving transparency and accessibility of data sets, much more data by many more players need to be disclosed for the data to be useful. For example, important recommended practices such as closed-loop drilling and baseline water quality testing do not have disclosure requirements and therefore are not accessible from public databases. Industry collaboration will be needed to gather much of the data related to the current use of recommended practice.

Although much work is being done to identify sources and pathways of water resource contamination, our current understanding of water-related risks and risk mitigation techniques in shale gas developments leaves important questions unanswered. A full characterization of the sources and the mechanisms of contamination is needed, followed by an examination of effective practices and procedures to eliminate or mitigate the risks of contamination of water resources. Additional analysis is needed to quantify the costs and benefits of shale gas development in light of the identified risks and the costs of mitigation, ^{Reference Olmstead, Muehlenbachs, Shih, Chu and Krupnick64} as well as for remediation of contamination that has already occurred. This type of analysis will be critical to establishing those BMPs and government regulations, where needed, which will ensure that shale gas can be responsibly and sustainably produced.

In summary, water related science and analysis indicates the following at this time:

• • All phases of shale gas development have the potential to affect either the quantity or quality of local water resources. ^{Reference Horner, Halldorson and Slutz53-Reference Vidic, Brantley, Vandenbossche, Yoxtheimer and Abad54}

• • Water resources in many areas where shale plays exist are already experiencing groundwater depletion due to drought conditions and consumption exceeding recharge rates by domestic, agricultural, and industrial sectors. ⁵²

• • Water resources in many areas where shale plays exist are already experiencing water resource contamination tied to hydraulic fracturing activities. ^{Reference Osborn, Vengosh, Warner and Jackson61}

• • Industry and stakeholder groups have established no standard set of BMPs for managing water use or water quality; further, there is little consistency in regulations from one state to the next regarding water and wastewater management practices associated with unconventional oil and gas development.

• • A full characterization of the sources and the mechanisms of actual and potential contamination is needed, followed by an examination of practices and procedures to eliminate or mitigate the risks of depletion and contamination of water resources.

• • Based on findings, producers might consider developing and adopting cost-effective, appropriately flexible, and adaptive BMPs or a set of strong principles. Accountability reporting, measurement, and verification standards will assure adherence to generally recognized BMPs and the principles to safeguard water supplies and water quality, adapted to their region and their specific situations.

Greenhouse gas emissions

A comprehensive and objective understanding of GHG emissions from the production, processing, and transmission of natural gas is vital to understanding the potential role of natural gas in mitigating climate change. The GHG impacts of gas—particularly in comparison with coal as well as diesel and gasoline for many markets—affect decisions on future power sector developments, industrial practices, regulatory policy, and sectoral applications. Figure 8 illustrates such a comparative life cycle assessment (LCA) for power generation after methodological harmonization. The current understanding of GHG emissions from natural gas systems leaves important questions unanswered and has resulted in considerable technical debate. ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76} Scientific studies fall into two categories: bottom-up assessments estimate GHG emissions from natural gas systems based on component-level emission profiles and counts; top-down assessments use measurements of methane in the atmosphere, and then estimate a portion attributable to natural gas systems. EPA categorizes the air pollution impacts this way:

• • Emissions from trucks and drilling equipment [noise, particulates, SO₂, NO _x , non-methane volatile organic compounds (NMVOCs), and CO].

• • Emissions from natural gas processing and transportation (noise, particulates, SO₂, NO _x , NMVOC, and CO).

• • Evaporative emissions of chemicals from waste water ponds.

• • Emissions due to spills and well blowouts (dispersion of drilling or fracturing fluids combined with particulates from the deposit). ⁷²

Figure 8.

Synthesis of prior estimate of life cycle GHG emissions from natural gas (conventionally produced and unconventionally) and coal used for electricity generation after methodological harmonization. ^{Reference Logan, Heath, Paranhos, Boyd, Carlson and Macknick42}

According to the 2010 U.S. Greenhouse Gas Emissions Inventory, ⁷² the natural gas industry ^{Footnote ††} represented nearly a third of total methane emissions in the United States in 2010, the largest single category, and is also the fourth largest category of CO₂ emissions. ^{Footnote ‡‡} EPA, which produces the U.S. GHG inventory, significantly increased estimates of methane emissions from the natural gas industry for the 2009 inventory year, resulting from a change in its assessment of emissions from four activities, the most important of which were well venting from liquids unloading (attributed only to conventional ^{Footnote §§} wells by EPA), gas well venting during completions, and gas well venting during well workoversFootnote ***. ⁷² The sum of these changes more than doubled the estimate of methane emissions from natural gas systems from the 2009 inventory compared to the 2008 inventory. EPA acknowledges what is well understood—the estimates of GHG emissions from the natural gas sector are highly uncertain, with a critical lack of empirical data to support GHG emission assessments. ⁷² This is especially acute for production of unconventional gas resources. Data gathering to support reassessment of EPA's U.S. GHG inventory and potential regulations is underway. Brandt et al. found overall natural gas system emissions to be “…about 25–75% higher than EPA estimate[s].” ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76}

The practice of “green” completions ^{Footnote †††} has been introduced to reduce volatile organic compound (VOC) emissions, yielding co-benefits for methane emission reductions. EPA's 2012 New Source Performance Standards and Hazardous Air Pollutant regulations for oil and gas production include green completion requirements and other controls that will reduce emissions of VOCs and certain hazardous air pollutants. ⁷⁷ These regulations will have the co-benefit of reducing fugitive methane emissions associated with natural gas production. ⁷⁸ As EPA notes, “A key component of the final rules is expected to yield a nearly 95% reduction in VOCs emitted from more than 11,000 new hydraulically fractured gas wells each year. The estimated revenues from selling the gas that currently goes to waste are expected to offset the costs of compliance, while significantly reducing pollution from this expanding industry. The EPA's analysis of the rules shows a cost savings of $11 million to $19 million when the rules are fully implemented in 2015.” ⁷⁸ A number of states, various stakeholders, and the SEAB have also called for additional New Source Performance Standards regulations directed specifically at the problem of fugitive methane emissions from unconventional natural gas production. ⁷⁷ Colorado has recently become the first state in the country to adopt regulations that directly address methane emissions from oil and gas production. ⁷⁹

With respect to methane emissions from the midstream and downstream segments of the natural gas supply chain (transmission, storage, and distribution), there are no current federal or state regulatory programs that directly address such emissions even though studies indicate that these segments account for the majority of emissions from the sector. ^{Footnote ‡‡‡} The Federal Pipeline & Hazardous Materials Safety Administration (PHMSA), for example, does not currently consider methane emissions due to pipeline leaks when promulgating pipeline standards for leak detection and repair. ^{Footnote §§§} The Federal Energy Regulatory Commission (FERC) does not currently consider direct GHG impacts of new natural gas pipelines in exercising its authority over the siting of interstate pipelines.Footnote **** And EPA does not currently regulate leaks or emissions from natural gas transmission or storage under its Clean Air Act authority. Likewise, state authorities that regulate intrastate pipelines and local distribution systems have not directly addressed methane leaks and emissions from those systems, although a number of states have adopted pipeline modernization and replacement programs. ^{Footnote ††††}

More widely, the EPA uses the Natural Gas STAR program, a voluntary partnership with recommended actions looking across the gas sector in the areas of:

Gas production and processing.

• • Perform reduced emission completions.

• • Install plunger lifts (improves well production while reducing gas losses).

• • Aerial leak detection using laser and/or infrared technology.

• • Eliminate unnecessary equipment and/or systems.

Oil production.

• • Install vapor recovery units on crude oil storage tanks.

• • Route casing head gas to vapor recovery unit or compressor for recovery and use or sale.

Gas storage.

• • Convert gas pneumatic controls to instrument air.

• • Replace bidirectional orifice metering with ultrasonic meters.

• • Reduce methane emissions from compressor rod packing systems.

Gas transmission.

• • Directed inspection and maintenance at compressor stations.

• • Use fixed/portable compressors for pipeline pumpdown.

• • Install vapor recovery units on pipeline liquid/condensate tanks.

Gas distribution.

• • Directed inspection and maintenance at surface facilities.

• • Identify and replace high-bleed pneumatic devices.

• • Survey and repair leak.

An emerging literature has attempted to estimate GHG emissions from unconventional natural gas production, based on the limited available information. Measurement of GHGs in the atmosphere, if they could be reliably attributed to specific sources, would be the ideal methodological approach. However, such measurements are expensive, attribution is challenging, and only a few studies have been published to date, such as Pétron et al. (2014). ^{Reference Pétron, Karion, Sweeney, Miller, Montzka, Frost, Trainer, Tans, Andrews, Kofler, Helmig, Guenther, Dlugokencky, Lang, Newberger, Wolter, Hall, Novelli, Brewer, Conley, Hardesty, Banta, White, Noone, Wolfe and Schnell80} Many other studies use engineering-based modeling, based on as much empirical information as is possible to assemble. Much of this emerging literature is guided by the methods of LCA, which in this context aims at estimating all GHG emissions attributable to natural gas used for a particular function: electricity, transportation, or primary energy content (e.g., heat). Attributable emissions are those from any activity in the process chain of producing the natural gas—from exploration and well pad preparation to drilling and completion—processing it to pipeline quality, transporting it to the location of end use, and combustion. In addition, the construction, operation and maintenance, and end-of-life decommissioning of the end use technology are also considered.

LCAs are typically performed for the purpose of comparing the results from one system to another. ^{Footnote ‡‡‡‡} Natural gas, once processed for pipeline transmission to end use customers, is a homogenous product, undifferentiated by source. End-use combustion of the natural gas has by far the largest contribution to life cycle GHG emissions (as is true for any fossil-fueled combustion technology). It is not a point of differentiation between conventional and unconventional natural gas, but remains a significant factor relative to the use of coal, nuclear, or renewable energy options as well as for transportation. Therefore, the attention here focuses on the activities associated with production of natural gas because they are the points of potential differentiation between unconventional and conventional natural gas. Given current regulatory and scientific attention to emissions from the natural gas industry and opportunity provided by the unique data sources used in this report, we additionally focus on emissions from natural gas processing. We rely on the multitude of previously published LCAs of conventionally produced natural gas, ^{Reference O’Donoughue, Heath, Dolan and Vorum81-Reference Brandao, Heath and Cooper86} updated for recent changes in understanding and harmonized for methodological inconsistency, for comparison to the results of this study. We also compare these results to those for coal-fired electricity generation based on a systematic review and harmonization of that LCA literature, because coal has been the largest energy source for electricity in the United States over the last 50-plus years. ^{Reference O’Donoughue, Heath, Dolan and Vorum81}

Prior research comparing life cycle GHG emissions of electricity generated from shale gas to conventional gas and other energy sources has been inconclusive and remains uncertain. Both the magnitude and direction of difference reported in these publications vary. See, for example, Howarth et al. (2011) ^{Reference Howarth, Santoro and Ingraffea82} ; Jiang et al. (2011) ^{Reference Jiang, Griffin, Hendrickson, Jaramillo, VanBriesen and Venkatesh83} ; and Stephenson et al. (2011). ^{Reference Stephenson, Valle and Riera-Palou84} This is despite their reliance on very similar data sources (mostly EPA's GHG emission inventory and supporting documentation). Uncertainty in the underlying data sources drives the uncertainty in published results. Furthermore, inconsistent approaches to data use and other assumptions thwart direct comparison of the results of these studies and the development of collective understanding. Separately, Heath et al. have examined this literature using a meta-analytical technique called harmonization that clarifies the collective results of this emerging literature by adjustment to more consistent methods and assumptions. ^{Reference Heath, O’Donoughue, Arent and Bazilian85-Reference Brandao, Heath and Cooper86} In these publications, the authors elucidate differences between previously published estimates of life cycle GHG emissions from combustion of shale gas for power production and key sensitivities identified in the literature. Key sensitivities include estimated ultimate recovery (EUR) and lifetime (years) of wells; emissions and emissions reduction practices from well completion and workover; and emissions and emission reduction practices from well liquids unloading, all of which vary from basin to basin and from operator to operator. A key conclusion from the assessment of previous estimates of unconventional gas life cycle GHG emissions is that given current uncertainties, it is not possible to discern with a high level of confidence whether more GHGs are emitted from the life cycle of shale gas or conventional gas used for electricity generation.

The peer reviewed scientific literature fairly consistently indicates a significant difference in emissions from natural gas processing, transmission and distribution compared to “official” inventories. ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76} These differences will not be resolved without major effort, because current estimates are based on decades-old and inadequately sampled measurements of methane leakage. Better measurement technologies and more comprehensive sampling across the many segments, regions, operators, gas types, and technologies are necessary to ensure that bottom-up inventories and LCAs can accurately estimate the GHG emissions profile of gas.

Top-down assessments are likewise in a state of early scientific investigation [see, e.g., Pétron et al., 2014 (Ref. Reference Pétron, Karion, Sweeney, Miller, Montzka, Frost, Trainer, Tans, Andrews, Kofler, Helmig, Guenther, Dlugokencky, Lang, Newberger, Wolter, Hall, Novelli, Brewer, Conley, Hardesty, Banta, White, Noone, Wolfe and Schnell80)] and have been restricted to limited regions or slices of time. Despite disagreement in methods and interpretations, top-down assessments have repeatedly found that bottom-up emission estimates cannot explain the concentrations of methane measured in the atmosphere. ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76} This has raised questions about the true emissions profile of natural gas production and use.

The natural gas leakage rate is another critical parameter determining the climate impact of natural gas. Leakage can be defined as the proportion of produced natural gas that is released to the atmosphere either intentionally through standard practice and component/system design, or unintentionally through fugitive emissions. Alvarez et al. (2012) have calculated the maximum leakage rate for natural gas to provide climate benefit, over all time scales, compared to the fuel it would displace. ^{Reference Alvarez, Pacala, Winebrake, Chameides and Hamburg87} Their results suggest that maximum leakage rates differ significantly depending on the application. Emissions could be as high as 3.2% for benefits to be realized in the electric sector displacing coal, but only as high as 1.2% for beneficial use in the transportation sector. Preliminary emission estimates based on atmospheric research suggest that current leakage rates could be significantly higher than these tipping points. ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76,Reference Tollefson88} The increased attention to methane emissions has risen due to a combination of factors including new literature and dramatically increased production in the United States. The climate mitigation perspective was furthered by the recent update to global warming potentials by the Intergovernmental Panel on Climate Change (IPCC). ^{Reference Myhre, Shindell, Bréon, Collins, Fuglestvedt, Huang, Koch, Lamarque, Lee, Mendoza, Nakajima, Robock, Stephens, Takemura, Zhang, Stocker, Qin, Plattner, Tignor, Allen, Boschung, Nauels, Xia, Bex and Midgley89} Here, specifically, the IPCC updated the 25- and 100-year global warming potentials of methane from 84 to 86, and 28 to 34, respectively. ^{Footnote §§§§}

Atmospheric measurements may be used for verification of bottom-up assessments, but are not likely to achieve the resolution necessary to support source prioritization. Therefore, it is also critical to develop analytical approaches to reconcile bottom-up and top-down assessments, which are currently in such disagreement. Better agreement between these two approaches could be explored by improving measurement technologies, modeling downscaling techniques, and improving understanding of the gas composition profile of sources. Significantly more measurement, verification, continuous monitoring, and rapid leak repair methods and practices are needed to assure minimal methane emissions.

Recent research ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76} has explored the wider system impacts of methane leaks from the whole gas system. They discuss gas as a “potential” bridge fuel. We use their language as a bridge to Section “Implications for pathways toward a sustainable energy future,” noting a summary conclusion of Brandt et al.’s seminal article: “Our findings show that natural gas can be a bridge to a sustainable energy future, but that bridge must be traversed carefully. Current evidence suggests that leakages may be larger than official estimates, so diligence will be needed to ensure that leakage rates are actually low enough to achieve sustainability goals.” ^{Reference Brandt, Heath, Kort, O’Sullivan, Pétron, Jordaan, Tans, Wilcox, Gopstein, Arent, Wofsy, Brown, Bradley, Stucky, Eardley and Harriss76}