Life Cycle Water Consumption for Shale Gas and Conventional

Article pubs.acs.org/est

Life Cycle Water Consumption for Shale Gas and Conventional Natural Gas Corrie E. Clark,* Robert M. Horner, and Christopher B. Harto Environmental Science Division, Argonne National Laboratory, 955 L’Enfant Plaza SW, Suite 6000, Washington, D.C. 20024, United States S Supporting Information *

ABSTRACT: Shale gas production represents a large potential source of natural gas for the nation. The scale and rapid growth in shale gas development underscore the need to better understand its environmental implications, including water consumption. This study estimates the water consumed over the life cycle of conventional and shale gas production, accounting for the different stages of production and for flowback water reuse (in the case of shale gas). This study finds that shale gas consumes more water over its life cycle (13−37 L/GJ) than conventional natural gas consumes (9.3−9.6 L/ GJ). However, when used as a transportation fuel, shale gas consumes significantly less water than other transportation fuels. When used for electricity generation, the combustion of shale gas adds incrementally to the overall water consumption compared to conventional natural gas. The impact of fuel production, however, is small relative to that of power plant operations. The type of power plant where the natural gas is utilized is far more important than the source of the natural gas.

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for disclosure of hydraulic fluid constituents, well bore integrity testing, and proper disposal of produced water. However, the quantity of water consumed by shale gas development is also of concern, especially for areas experiencing water stress. The quantity of water required for shale gas development has received little attention in the peer-reviewed literature. Estimates of water use for hydraulic fracturing vary with median values of 10 600 m3 per horizontal well for the Barnett play, 16 100 m3 for the Eagle Ford play, 21 500 m3 for the Texas portion of the Haynesville play, and 17 000 m3 for the Marcellus play.3,4 While statewide water use for shale gas development is expected to be less than 1% of total water withdrawals in Texas, local impacts may vary depending upon seasonal water availability, wastewater management strategies, and competing demands.3,4 Water use across the life cycle of shale gas was not examined. With a significant anticipated shift in the pathway of U.S. natural gas production from conventional to shale sources, the overall life cycle impacts of natural gas use may be affected. The overall objective of this study is to examine life cycle water consumption from the use of shale gas and conventional natural gas. Water consumption for shale gas development focused on four plays: Marcellus, Haynesville, Fayetteville, and Barnett.

INTRODUCTION The Energy Information Administration (EIA) projects that natural gas from shale formations will be the primary driver of growth in domestic natural gas production through 2035; shale gas is expected to grow from 23% of supply in 2010 to 49% in 2035, more than offsetting declining production from conventional sources.1 However, there is a high degree of uncertainty regarding the size of U.S. shale resources. In 2011, the EIA estimated 23.4 trillion cubic meters (827 trillion cubic feet) of unproved technically recoverable resource (TRR), but it reduced the estimate in 2012 by approximately 40%, to 13.6 trillion cubic meters (482 trillion cubic feet).1 The decline was largely due to decreased TRR estimates for the Marcellus shale based on increased availability of production data.1 Shale plays that are considered to be important in the United States include the Marcellus, Haynesville, Fayetteville, Barnett, Eagle Ford, and Bakken. Other major U.S. plays include the Antrim, Utica, Niobrara, New Albany, and Woodford (Supporting Information (SI) Figure S1). In response to the recent surge in shale gas development, federal, state, and local governments are developing policies and regulations to ensure protection of human health and the environment.2 Production of unconventional gas from shale plays requires hydraulic fracturing, a technique that pumps fluid downhole at a sufficient rate and pressure to create networks of fractures in the target shale formation and enables gas to flow freely. Many recent policies have focused on water quality concerns associated with the technique, including requirements © XXXX American Chemical Society

Received: March 29, 2013 Revised: August 28, 2013 Accepted: September 4, 2013

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dx.doi.org/10.1021/es4013855 | Environ. Sci. Technol. XXXX, XXX, XXX−XXX

0.20

0.2 0.20

L flowback/L/ job L recycled/L flowback L/GJ L/GJ L/m3

a

6 3 0.67−0.94

6 3 0.67−0.94

14 00 000−25 400 000

6 3 0.67−0.94

0.00

0.05

12 900 000−33 400 000

140 000

30 80 (40−97) 1 for low EUR, 3 for high EUR 98−180 1 080 000

Haynesville

Marcellus

6 3 0.67−0.94

0.95

0.1

9 900 000−22 000 000

90 000

30 80 (40−97) 1 for low EUR, 3 for high EUR 39−150 670 000

Not applicable. Hydraulic fracturing was not assumed for the conventional nonassociated natural gas life cycle pathway.

water for gas processing water for pipeline operation water for electricity for gas compression

0.1

6 800 000−23 500 000

L/job

70 000

water for hydraulic fracturing flowback fraction (0−10 days) recycled fraction

100 000

L/well

Fayetteville 30 80 (40−97) 1 for low EUR, 3 for high EUR 48−73 640 000

water for cement

30 80 (40−97) 1 for low EUR, 3 for high EUR 39−84 920 000

Barnett

million m3/well L/well

years % jobs/well

unit

well lifetime bulk gas methane content hydraulic fracturing jobs per well estimated ultimate recovery water for drilling

parameter

shale play

Table 1. Key Parameters for Life Cycle Water Analysis Associated with Natural Gas

27 000−37 000

22−35 300 000−410 000

30 85 (69−95) −a

conventional, nonassociated onshore source

ref 21 ref 21 ref 22

ref 20

ref 20

Shale: refs 9, 10.Conv.: refs 11, 12 assumptions based upon well designs: refs 13−17 assumptions based upon well designs: refs 13−17 ref 18, 19

industry and Argonne assumption ref 8 Argonne assumption

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For the EUR of a conventional nonassociated onshore natural gas well, we assumed an average production rate over the lifetime of the well based upon production data from the EIA and well compositional makeup from the EPA, recognizing that production rates typically decline over time.11,12 We estimated a base case EUR of 28 million cubic meters (1.0 BCF), which is comparable to a value from an analysis of Texas wells prior to large-scale shale gas production.25 When comparing EURs, one must take into consideration that shale gas recovery typically uses horizontal drilling to access large rock volumes, whereas conventional gas recovery often uses multiple vertical wells, each accessing a smaller rock volume. To account for these differences and enable comparison, the analysis evaluates impacts on a per GJ basis. In the case of conventional gas, it may be that the highly productive wells have ceased production and modern wells return relatively less gas, as shown by the fall in the EUR for Texas over the years.25 As the large-scale recovery of natural gas from shale plays is a relatively new pursuit, the EUR may not reflect future conditions when the technologies that support large-scale shale gas recovery are more mature. Well Design, Drilling, and Construction. The drilling phase of the natural gas life cycle requires the use of drill rigs, fuel, and materials, including the casing, cement, liners, mud constituents, and water. Water is used during the well construction stage in drilling fluids, for cementing the casing in place, and for hydraulically fracturing the well in the case of shale gas. Well designs developed to estimate water requirements for drilling and cementing were based on designs for the 4H, 5H, and 6H Carol Baker wells for shale gas wells and upon a typical casing program found in the Mississippi Smackover Trend, for the conventional nonassociated onshore natural gas well (see SI Table S1).13−17 Horizontal wells are drilled vertically to a point about 300 m (900 ft) above the shale formation, at which point the drilling follows a large-radius turn of approximately 90 degrees so that the well runs laterally (horizontally) through the shale for up to 2000 m (6000 ft) or more (see SI Figure S3). This long lateral reach enables a horizontal well to access more of the shale resource than a vertical well would be able to. Vertical wellswhich are common in conventional natural gas production and which were assumed for the conventional scenariodraw from a much smaller area within a play, and thus typically produce less gas than horizontal wells. The total volume of drilling muds (fluids) used to lubricate and cool the drill bit, maintain downhole hydrostatic pressure, and convey drill cuttings from the bottom of the hole to the surface depends upon the volume of the borehole (which is dependent upon the depth of the formation and the length of the lateral) and the physical and chemical properties of the formation. The ratio of barrels (bbl) of drilling mud to bbl of annular void used in this assessment was 5:1, based upon data obtained from the literature.26 For this analysis, we assumed use of water-based fluids for the Barnett and Haynesville plays. For the Marcellus and Fayetteville plays, we assumed the use of air drilling through the upper portion of the wells through the first two casing strings to a depth of 119 m (392 ft) for the Marcellus (94 m (307 ft) for the Fayetteville) and water drilling below that depth.27 For the water-based drilling muds, a ratio of 1 bbl of water to 1 bbl of drilling mud was assumed. Hydraulic Fracturing. Unlike conventional geological formations containing natural gas deposits, shale has low permeability, which naturally limits the flow of gas. Hydraulic

Water consumption for conventional gas plays focused on Texas, the state that produces the largest volume of natural gas in the United States.5 This work builds upon the life cycle assumptions described by Burnham et al. and Clark et al.6,7 Water use for both pathways of natural gas production was evaluated and then compared to that of other transportation fuels. The impact of fuel source on life cycle water consumption for electricity production from natural gas was also evaluated.

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MATERIALS AND METHODS For the LCA of shale gas and conventional natural gas, the system boundary included the establishment of well infrastructure, fuel recovery, fuel processing, and fuel use, as well as transportation and distribution of fuels (SI Figure S2). The primary purpose of this analysis is to track freshwater consumption across the life cycle of natural gas. It is recognized that gas production coproduces brines over the lifetime of a well; however, produced brines are only tracked in this analysis to the extent that they are used in lieu of freshwater for hydraulic fracturing of shale gas wells. Functional units for LCA directly affect the meaning of the results. For this study of life cycle water use, three functional units were used: liters (L) of water per gigajoule (GJ) of gas, liters of water per liter of gasoline equivalent (LGE), and liters of water per kilowatt hour (kWh) lifetime energy output. The use of the units LGE and kWh enables comparison with liquid transportation fuels and fuels for electricity generation. Table 1 summarizes the key parameters that are discussed in the following subsections and are included in the natural gas pathways. Estimated Ultimate Recovery. Given that the primary difference between the pathways for conventional and shale gas occur on a per-well basis, it was necessary to determine the estimated ultimate recovery (EUR) of gas from a well from the four plays of interest to amortize water consumed over the total amount of natural gas produced. The high estimates were based upon industry average−targeted EURs.9 The low estimates were based upon a review of emerging shale resources developed by INTEK, Inc.,10 for the EIA. The average shale gas well EUR is 100 million cubic meters (3.5 billion cubic feet (BCF)) for bulk gas, which is a mixture containing methane, in addition to other gases such as ethane, propane, carbon dioxide, and nitrogen. Trade-offs are likely to emerge between the number of times a well is hydraulically fractured and the EUR, with optimal production strategy for each play being refined over time based upon the economics. For this study, it was assumed that each well would be hydraulically fractured one time over the lifetime for the low estimate EUR and three times over the lifetime for the high estimate EUR. The assumption for three times over the lifetime to achieve the high estimate EUR is consistent with previous U.S. Environmental Protection Agency (EPA) assumptions for the draft New Source Performance Standard (NSPS).23 For the final NSPS rule, the EPA modified the estimate from 10 to 1%, which is consistent with the American Petroleum Institute (API) estimate that presently only 1.6% of unconventional gas wells undergo a workover.24 However, large-scale hydraulic fracturing operations were developed only recently, and unconventional wells requiring hydraulic fracturing are relatively new. It is unclear at this time whether and how often unconventional gas wells will need to be refractured to meet predicted EURs. The estimates for each play are presented in Table 1. C



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fracturing improves the flow of gas by creating fracture pathways. The fracture fluid for shale formations is typically water based and contains a proppant and chemical additives. The amount of water and the fluid constituents used for hydraulic fracturing vary according to the geology and the specific characteristics of the fracturing techniques used, including the length of the lateral portion of the well and the number of fracture stages. Typical water volumes required for hydraulic fracturing in each play were estimated from industry-reported data obtained from the FracFocus.org Web site.18 FracFocus is a national registry of hydraulic fracturing chemical data operated by the Ground Water Protection Council (GWPC) and the Interstate Oil and Gas Compact Commission (IOGCC). FracFocus data are entered either voluntarily by operators or in accordance with state chemical disclosure laws. In addition to chemical information, FracFocus also includes the volume of water used to hydraulically fracture each well. FracFocus data are not available in an aggregated format. Data for each well are stored separately in a portable document format (PDF). This analysis relied upon a data set made available by Skytruth. The data set consists of data reported in 2012 to FracFocus, and contains hydraulic fracturing data for activities completed in 2011 and 2012.19 Wells were selected geographically by county for the four plays of interest. The data were screened to remove hydraulic fracturing jobs that may have been performed on vertical wells in the area, and to remove obvious typos or erroneous entries (included only water volumes above 500 000 gallons and below 20 000 000 gallons). The total number of wells evaluated for each play varied from 1124 for the Haynesville play to 1705 for the Barnett play (see SI Table S2 for summary statistics for each play). The range of water consumption shown in Table 1 was defined as plus or minus one standard deviation away from the average for each play (see SI Figure S4 for histograms). Overall, the average water requirements for each play estimated by this method, particularly for the Haynesville and Fayetteville plays, are slightly higher than the range of values presented by other sources.9,28 Management of Flowback Water. Another component of fracturing a well is the management of flowback water and produced water. Flowback water is the water that is produced from the well immediately after hydraulically fracturing the well and before commencing gas production; produced water is water that is produced along with the gas over the life of the well. Outside of the Marcellus play, flowback water is collected and typically disposed of through underground injection. Within the Marcellus region, however, flowback water is collected and typically reused in hydraulic fracturing activities. For the Marcellus, 95% of flowback was assumed to be recycled because of the long-distance transport requirements to dispose of the fluid via injection wells. For the other plays, where injection wells are located nearby, recycle rates were assumed to be 20% of flowback for the Barnett and Fayetteville plays and 0% for the Haynesville play.20 The total volume of recycled fluid depends on the amount of fluid that flows back up the well after hydraulic fracturing, which varies considerably among the different shale plays. For this study, flowback fractions and recycle fractions were based upon input from industry experts. Flowback fractions for the Marcellus shale fall within estimates reported by others.27,29 Data for Natural Gas Processing, Transmission, and Use. Downstream from the recovery stage, natural gas passes

through a processing stage in which it is purified for pipeline transportation. The processed natural gas enters the transmission and storage stage, where natural gas is moved long distances through high-pressure pipelines. Compressor station facilities are located along the transmission pipeline network to force the gas through the large-diameter pipes. After transmission through such pipelines, gas may be stored underground, liquefied, and stored in aboveground tanks, and/or distributed to customers for use. All of these steps consume water, primarily for cooling.30 Estimates for this water use are taken from a widely cited paper by Gleick,21 as indicated in Table 1. This paper is dated, and the values for these processes are poorly supported. However, there are few alternative sources for data on these processes. It is recognized that there is a high level of uncertainty in applying these numbers to modern practices, and new primary data are needed to better understand the water consumption from natural gas transport and processing. Because this study examines transportation as a specific end use for natural gas, water used for the compression of natural gas into vehicle tanks was also considered. To compare the energy content of natural gas to that of gasoline for transportation use (assuming 3% ethanol blend), a conversion of 32 000 GJ/LGE was used.31 Table 2 gives the parameters used to compare the impact of natural gas fuel source on water consumption for electricity generation. Table 2. Power Plant Water Use Parameters plant type

cooling type

steam turbine (ST)

once through (OT) recirculating (RC) NAc

combustion turbine (CT) combined cycle (CC)

once through (OT) recirculating (RC)

power plant efficiencya

operational water consumption (L/kWh)b

32.3

1.1−1.3 (1.2)

32.3

1.8−2.6 (2.2)

29.5

0.19

44.9

0.38

44.9

0.68−1.2 (0.91)

a

Based on higher heating value (HHV) Source: ref 32. bRange of literature values; value in parentheses is average value used in analysis. Sources: refs 21, 33−38. cNA, do not require water for cooling but often require water for emission control.

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RESULTS AND DISCUSSION OF WATER CONSUMPTION The life cycle water consumption of both shale and conventional natural gas pathways was evaluated according to three functional unitsL/GJ produced, L/LGE, and L/kWh of electricity generated. The results in L/GJ are displayed by life cycle stage, and overall water consumption in L/LGE is compared to that for other transportation fuels. The results in L/kWh are presented across natural gas fuel sources and power plant types. Parameter variability and uncertainty are discussed, and some key factors affecting water consumption estimates are identified. Water Consumption by Life Cycle Stage. An overview of water consumption for the shale gas and conventional gas life cycles per GJ is presented in Figure 1. Results are presented by life cycle stage and utilize the minimum and maximum parameter values in Table 1 to illustrate the range of uncertainty and variability among wells within each play. The D



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Figure 1. Life cycle water consumption for conventional and shale gas according to life cycle stage, accounting for use of recycled flowback water in hydraulic fracturing. Min and max scenarios show the extent of variability according to the key parameters affecting life cycle water consumption.

Figure 2. Average life cycle water consumption for various fuels in L/LGE (shale gas water consumption accounts for use of recycled flowback water in hydraulic fracturing).22,39 Error bars show the extent of variability of water consumption according to the key parameters affecting life cycle water consumption. Corn Ethanol not shown on the graph due to scale, but water consumption ranges from 26 to 360 L/LGE.39

represents future well performance, which typically becomes more accurate as a play develops and more wells are drilled and produced. Figure 1 presents maximum and minimum water consumption for conventional and several shale gas plays accounting for multiple stages of the life cycles. For conventional natural gas, the majority of water consumption typically occurs during processing and transmission, although there is a high degree of uncertainty in these values due to limited data on these stages of the life cycle. For shale gas, the results vary by play. For the Barnett and Haynesville plays, the stage with the largest volume of water consumed per GJ for the minimum scenarios is gas processing, while for the maximum scenarios it is hydraulic fracturing. This is due to the uncertainty in EUR and the large volumes of water (6.8−33.4 million L) required to hydraulically fracture a well. For the Marcellus and Fayetteville plays, hydraulic fracturing is the stage with the largest volume of water consumed per GJ (Figure 1). The Haynesville play is perhaps the most water efficient with the lowest lifecycle consumption in the minimum

results indicate, per GJ of natural gas produced, conventional natural gas production consumes less water than production from the four shale gas plays evaluated. While life cycle water consumption for conventional natural gas production varies little (between 9.3 and 9.6 L/GJ according to our analysis), the water consumption for shale gas production across various plays and parameter estimates varies significantly (between 13 and 37 L/GJ). This variability is primarily driven by the quantity of hydraulic fracturing fluid used, the number of times a well is hydraulically fractured, and the EUR of the well. The volume of fracturing fluid required can vary for a wide range of reasons including, but not limited to the length of the lateral portion of the well, the number of fracture stages, variations in the proprietary hydraulic fracturing practices used by service providers, and geological variability within and between plays. Over a 30-year life cycle, depending upon whether a well is hydraulically fractured one or three times during that time period, construction, completion, and production of shale gas can consume between 7 800 000 and 101 400 000 L of water per well. The EUR for a play is also subject to uncertainty and E



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on the life cycle water consumption across different natural gas power plant types was evaluated and is shown in Figure 3.

scenario and the second lowest in the maximum scenario. The EUR and the volume of fracturing fluid required appear to have the greatest impact on the life cycle water consumption per unit of energy produced. While the recycling of flowback water is often cited as a means to reduce the water footprint of shale, these results show the effect to be relatively small. This holds even for the Marcellus shale where 95% of flowback water was assumed to be recycled, due to the limited quantity of flowback water recovered. These numbers could be increased if all produced water collected over the lifetime of the well were collected and reused, but this introduces the logistical challenge of collecting and aggregating smaller volumes of water from hundreds or thousands of wells across a play that may not be practical or economical. Life Cycle Water Consumption for Natural Gas versus Other Vehicle Fuels. Although natural gas can be combusted directly with no additional water consumption, additional water is likely needed if the end use of the gas is a vehicle tank. In the case of natural gas vehicles, the natural gas may first be compressed via an electric compressor prior to entering the vehicle tank. The electricity required for this compression consumes 0.6−0.8 L of water for cooling per LGE (18.3−25.5 L/GJ) for both natural gas pathways).22 This is incorporated into the total life cycle water consumption for natural gas found in Figure 2. Of the fuels evaluated, conventional natural gas consumes the least amount of water over its life cycle with 0.88−1.12 L consumed per LGE. Shale natural gas consumes slightly more, ranging from a minimum of 0.99 L/LGE in the Haynesville shale to a maximum of 2.02 L/LGE in the Fayetteville shale when not accounting for flowback water recycling (SI Table S1). Both natural gas pathways ultimately consume less water than conventional gasoline or the other alternatives reported in Figure 2. Variations in water consumption estimates for gasoline are primarily due to the crude oil production stage, where water consumption is highly dependent upon the age of the oil well, the type of recovery technology in place, and the extent that formation water or alternative water is recycled and reused.39 Because the majority of wells in Saudi Arabia are younger and require less injection water to maintain well pressure than U.S. wells, less water is consumed.39 The fuel that consumes the most water per LGE is corn ethanol due to the irrigation requirements for growing corn, which depend on location and regional climate.39 Ethanol produced from switchgrass requires considerably less water than corn ethanol due to an assumption of no irrigation. The majority of water consumption for switchgrass ethanol occurs during the production stage at the refinery. Similarly, while water is consumed for mining, washing, and transporting coal, Fischer− Tropsch diesel (FTD) produced from coal gasification consumes the majority of its water during liquids production. Although water is used directly in the Fischer−Tropsch process, the majority of water consumption for FTD is due to cooling water losses at the plant.40 Life Cycle Water Consumption for Natural Gas Electricity Generation versus Other Fuels. A large and growing quantity of natural gas is consumed for electricity generation. A few recent papers have analyzed water consumption for electricity production across technologies and have found that water consumption for natural gas power plants is on the low end of the range for conventional thermoelectric power generation.41−43 To differentiate this analysis from those studies, the impact of natural gas fuel source

Figure 3. Impact of natural gas fuel source and power plant type on life cycle water consumption for electricity generation.

The results of this analysis show that the addition of water consumption for fuel production adds incrementally to the total life cycle impact; the effect, however, is much smaller than that of the power plant type. In most cases, the variability in water consumption from the fuel type is less than the variability in water consumption for the same power plant type shown in Table 2. While the water consumption for combustion turbines and power plants utilizing once-through cooling is on the low end, these power plants have significant drawbacks. The efficiency of combustion turbines is low, leading to much higher fuel consumption and operating costs. This makes them only suitable for short-term operation to meet peak load. Oncethrough cooling systems reduce water consumption at the cost of significant water withdrawals. High water withdrawal rates introduce their own ecological impacts, including, but not limited to, entrainment, entrapment, and increased temperatures near the discharge location. The majority of new natural gas power plants being built are high-efficiency combined-cycle plants utilizing recirculating cooling. Switching to shale gas from conventional natural gas in one of these plants would result in an average increase of 7% in life cycle water consumption. Macknick et al., however, showed that these power plants have the lowest water consumption among all power plant types utilizing recirculating cooling, with just over half the water consumption of the most water efficient coal power plants, and less than one-third the water consumption of a nuclear power plant when utilizing the same cooling technology.41 Because of this, the net effect of a shift to increased reliance on natural gas power generation from shale gas is likely to be positive in terms of overall water consumption. The incremental increase in water consumption from shale gas production should be more than offset by the significantly lower operational water consumption from natural gas power plants relative to the other power generation technologies that they are likely to displace.

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IMPLICATIONS The production of shale gas is more water intensive than conventional natural gas, primarily due to water consumption for hydraulic fracturing. How much more water intensive varies significantly both across plays and within each play. The F



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(6) Burnham, A.; Han, J.; Clark, C.; Wang, M.; Dunn, J.; PalouRivera, I. Life-cycle greenhouse gas emissions of shale gas, natural gas, coal, and petroleum. Environ. Sci. Technol. 2012, 46 (2), 619−627. (7) Clark, C.; Han, J.; Burnham, A.; Dunn, J.; Wang, M. Life-Cycle Analysis of Shale Gas and Natural Gas, ANL/ESD/11−11; Argonne National Laboratory, Argonne, IL, 2011. (8) Hanle, L. Personal communication amongst Hanle (U.S. Environmental Protection Agency); Sechler, D. (ICF International); Burnham, A.; Clark, C.; Dunn, J.; Han, J. (Argonne National Laboratory), May 9, 2011. (9) Mantell, M. E. Deep shale natural gas and water use, part two: Abundant, affordable, and still water efficient. Presented at Water/ Energy Sustainability Symposium at the 2010 Ground Water Protection Council Annual Forum, Pittsburgh, PA, 2010. (10) INTEK, Inc. Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays; prepared for Energy Information Administration, Washington, DC, 2011. (11) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990− 2009, EPA 430-R-11-005; U.S. Environmental Protection Agency: Washington, DC, 2011. (12) U.S. Natural Gas Summary: Production table. http://www.eia. gov/dnav/ng/ng_sum_lsum_dcu_nus_a.htm. (13) Overbey, W. K.; Carden, R. S.; Locke, C. D.; Salamy, S. P.; Reeves, T. K.; Johnson, H. R.; Site Selection, Drilling, and Completion of Two Horizontal Wells in the Devonian Shales of West Virginia, DOE/ MC/25115−3116; Prepared for U.S. Department of Energy, 1992. (14) Bourgoyne, A. T.; Millheim, K. K.; Chenevert, M. E.; Young, F. S. Applied Drilling Engineering; Society of Petroleum Engineers: Richardson, TX, 1991. (15) Range Resources. Well Record and Completion Report: Baker Carol 5H; Pennsylvania Department of Environmental Protection, 2010; http://www.rangeresources.com/getdoc/0651ae63-6b22-49f6-91b0ba8931870094/Baker-Unit-5H.aspx. (16) Range Resources. Well Record and Completion Report: Baker Carol 4H; Pennsylvania Department of Environmental Protection, 2010; http://www.rangeresources.com/getdoc/87529e5c-c15f-4846-b450b44ae68b378f/Baker-Unit-4H.aspx. (17) Range Resources. Well Record and Completion Report: Baker Carol 6H; Pennsylvania Department of Environmental Protection, 2010; http://www.rangeresources.com/getdoc/d8bdbf42-0028-45aa-bd4c324a3a1b78f5/Baker-Unit-6H.aspx. (18) Frac Focus Chemical Disclosure Registry. http://Fracfocus.org. (19) SkyTruth. FracFocus Chemical Database Download. http:// frack.skytruth.org/fracking-chemical-database/frack-chemical-datadownload. (20) Mantell, M. E. Personal communication between Mantell (Chesapeake Energy, Oklahoma City, OK) and C. B. Harto (Argonne National Laboratory, Washington, DC), Dec. 20, 2010. (21) Gleick, P. Water and Energy. Ann. Rev. Energy Environ. 1994, 19, 267−299. (22) King, C. W.; Webber, M. E. Water Intensity of Transportation. Environ. Sci. Technol. 2008, 42 (21), 7866−7872. (23) Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution; U.S. Environmental Protection Agency, 2012; http://www.epa.gov/ airquality/oilandgas/pdfs/20120418tsd.pdf. (24) Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: Summary and Analysis of API and ANGA Survey Responses Final Report; American Petroleum Institute and America’s Natural Gas Alliance, 2012; http://www.api.org/news-and-media/ news/newsitems/2012/oct-2012/∼/media/Files/News/2012/12October/API-ANGA-Survey-Report.pdf. (25) Swindell, G. Changes in the Performance of Texas Gas Wells. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, TX, May 15−17, 2001. (26) Development Document for Effluent Limitations Guidelines and New Source Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category; EPA 821-R/93-003; U.S. Environmental Protection Agency, 1993.

primary factors affecting water consumption on a life cycle basis are the quantity of water required per hydraulic fracturing job, the productivity of the well, the number of times a well is refractured, and the quantity of flowback water recycled. This analysis did not take into account the impact of estimated water consumption by shale gas production on local watersheds, which would depend upon the number of wells under development in an area as well as the timing of well construction and hydraulic fracturing activities. Although life cycle water consumption from shale gas development is less than other fuel production practices and is not the largest consumer of water in the natural gas electricity generation life cycle, it is possible that at the watershed scale, temporal and location effects from shale gas development could be significant and require further study. The difference in consumption between conventional and shale natural gas is less significant in terms of overall water requirements for meeting our energy needs. In reality, shale gas production is not competing directly with conventional natural gas but with other conventional fuels in the transportation and electricity sectors. When used as a transportation fuel, shale gas was shown to be less water intensive than the other transportation fuels with which it competes. When used for electricity production, the incremental increase in water consumption for the fuel production stage for shale gas is more than offset by the much lower water consumption of high-efficiency combined-cycle natural gas power plants when compared to even the highest efficiency coal or nuclear power plants.

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ASSOCIATED CONTENT

S Supporting Information *

Additional tables, figures, and details relevant to this analysis are available. This material is available free of charge via the Internet at http://pubs.acs.org.

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AUTHOR INFORMATION

Corresponding Author

*(C.E.C.) Phone: 01-202-488-2419; fax: 01-202-488-2413; email: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This study was supported by the U.S. Department of Energy under Contract No. DE-AC02-06CH11357. REFERENCES

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Life Cycle Water Consumption for Shale Gas and Conventional

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