Water Issues Related to Transitioning from Conventional to

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Water Issues Related to Transitioning from Conventional to Unconventional Oil Production in the Permian Basin Bridget R. Scanlon,* Robert C. Reedy, Frank Male, and Mark Walsh Bureau of Economic Geology, Jackson School of Geosciences, University of Texas at Austin, 10100 Burnet Road, Austin, Texas 78758, United States S Supporting Information *

ABSTRACT: The Permian Basin is being transformed by the “shale revolution” from a major conventional play to the world’s largest unconventional play, but water management is critical in this semiarid region. Here we explore evolving issues associated with produced water (PW) management and hydraulic fracturing water demands based on detailed well-by-well analyses. Our results show that although conventional wells produce ∼13 times more water than oil (PW to oil ratio, PWOR = 13), this produced water has been mostly injected back into pressure-depleted oil-producing reservoirs for enhanced oil recovery. Unconventional horizontal wells use large volumes of water for hydraulic fracturing that increased by a factor of ∼10−16 per well and ∼7−10 if normalized by lateral well length (2008−2015). Although unconventional wells have a much lower PWOR of 3 versus 13 from conventional wells, this PW cannot be reinjected into the shale reservoirs but is disposed into nonproducing geologic intervals that could result in overpressuring and induced seismicity. The potential for PW reuse from unconventional wells is high because PW volumes can support hydraulic fracturing water demand based on 2014 data. Reuse of PW with minimal treatment (clean brine) can partially mitigate PW injection concerns while reducing water demand for hydraulic fracturing.

1. INTRODUCTION The Permian Basin has the potential to be the largest unconventional oil play globally with up to 9−10 stacked reservoirs within a maximum vertical interval of ∼10,000 ft (∼3000 m) (Figure 1; Figure 2). The term “unconventional play” or “tight oil play” refers to a low-permeability continuous shale play that requires hydraulic fracturing (HF) with large water volumes to extract oil. A recent resource assessment in the Midland Basin within the Permian Basin (Figure 1) resulted in an estimated 20 × 109 barrels (bbl, 3.2 × 109 m3 or 3.2 km3) of technically recoverable oil from the Wolfcamp Shale, making it the largest unconventional resource evaluated by the U.S. Geological Survey to date, ∼3 times that of the Bakken play.1 For comparison, the U.S. produced 3.4 × 109 bbl (0.5 × 109 m3) of oil in 2015.2 The Wolfcamp Shale is one of a number of stacked reservoirs in the Midland and Delaware basins within the Permian Basin (Figure 2). Pioneer Natural Resources (2017) estimated potentially technically recoverable resources at ∼75 × 109 boe (bbl of oil equivalent, i.e., oil + gas expressed as bbl of oil equivalent, 11 × 109 m3) for the Midland Basin, with similar estimates for the Delaware Basin. Oil has been produced from conventional reservoirs in the Permian Basin since the 1920s. Production totaled ∼35 × 109 bbl (6 × 109 m3) since 1940, accounting for ∼18% of total U.S. production. Oil production from unconventional reservoirs has markedly increased within the past decade from ∼0.2 × 106 bbl/day (2007) to ∼1.3 × 106 bbl/day (2015) (0.03 × 106−0.21 × 106 m3/d) (Figure 3). © XXXX American Chemical Society

Production from low-permeability unconventional shales has been made possible through technological advances that combine hydraulic fracturing (HF) and horizontal drilling using water, proppant, and chemicals. During the initial exploratory phase of shale play development, vertical wells are often used, transitioning to horizontal wells over time to increase reservoir contact area.3 A slurry containing water, chemicals, and proppant (e.g., sand or ceramics) is injected at a high enough pressure to fracture the rock, and proppant is used to maintain the open fractures. Horizontal wells are fractured in stages, which represent horizontal intervals that are hydraulically isolated with packers and fractured sequentially. Oil, gas, and water are produced from the well. The initial water is mostly flowback water that reflects the water injected for HF. Over time, the percentage of water from the formation increases. Flowback and formation water are often termed “produced water”, PW. During the early stages of shale development, operators thought that freshwater was required for HF; however, advances in frac fluid chemistry allow the use of water with high total dissolved solids (TDS), up to ∼200,000 mg/L.4,5 Less treatment of PW is required: mostly removal of total suspended solids, oil, and addition of a biocide.6 This minimal treatment results in what is termed a “clean brine”. Received: April 28, 2017 Revised: July 19, 2017 Accepted: July 31, 2017

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(SWD) wells.10 Concern about PW management is increasing in many regions because of linkages between PW disposal into deep, nonproducing geologic intervals, such as the Arbuckle Formation near the basement in Oklahoma, and increases in induced seismicity.12,13 Although PW cannot be injected directly into low permeability unconventional reservoirs, it can be reused to hydraulically fracture subsequent unconventional wells. The objective of this study was to address the following questions using the Permian Basin as a case study: 1. How much water is used for and produced from conventional and unconventional vertical wells? 2. What are the spatial and temporal trends in PW volumes and HF water demand for unconventional horizontal wells? 3. How does the water intensity of oil and gas production vary spatially and temporally? 4. What is the potential for reusing PW to reduce water issues related to PW disposal and sourcing HF water? The Permian Basin has a long history of production from conventional reservoirs along with rapidly increasing production from unconventional reservoirs. Water issues related to conventional oil production were examined to provide context for more recent unconventional production. The entire water budget of the Permian Basin was quantified, including PW volumes and related management along with water used for HF using well by well data for the period 2005 through 2015. Quantifying spatiotemporal variability in PW and HF water volumes is a critical prerequisite for assessing water management options. The potential for PW reuse was examined by comparing spatiotemporal variability in PW disposal volumes relative to HF water demands. Although we recognize that water contamination related to oil and gas production is very important,14 contamination is outside the scope of this study. This comprehensive assessment of the water budget provides insights for identifying opportunities that inform future development through optimization of water management. This study differs from many previous studies that focus exclusively on unconventional plays7−9,15 by describing the evolving water issues with transitioning from conventional to unconventional development. The water budget analyzed in this study builds on the national studies of produced water10,16−18 by providing more detail on produced water sources and management. The paper is organized into the following sections. Section 2 provides background information on the Permian Basin (Section 2.1) and on data sources and analyses (Section 2.2). The Results include the water budget for conventional vertical wells (Section 3.1) to provide context for unconventional wells (Section 3.2), including vertical and horizontal wells. Most of the paper focuses on unconventional horizontal wells (Section 3.2.2), including PW volumes (Section 3.2.2a) and HF water use (Section 3.2.2b). Water intensities (both PW and HF water) relative to oil and gas production were evaluated (Section 3.2.2c). Historical approaches to managing PW and assessing opportunities for reusing PW are described in Section 3.3. Future work to fill existing data gaps is described in Section 3.4.

Figure 1. Permian Basin extends over 65,000 mi2 (168,000 km2) in all or part of 47 counties in West Texas and 5 counties in SE New Mexico. Unconventional plays are found mostly in the Midland Basin (14,100 mi2, 36,500 km2) and the Delaware Basin (12,200 mi2, 31,600 km2). Oil well density in the Permian Basin is based on ∼162,000 producing wells during the 2005−2015 period. High well densities (50−144 wells/mi2; 19−56 wells/km2) around the margins of the Midland and Delaware basins and in the Central Basin Platform between the basins reflect primarily conventional reservoirs. Low densities in the Midland and Delaware basin floors represent mostly unconventional wells. Separate maps of the distribution of oil wells, gas wells, and conventional fields are provided in Figure S1. A total of 44,700 conventional wells were drilled and completed or recompleted between 2005 and 2015 (Table S3) with 128,000 producing conventional wells in 2015 (Table S4). Unconventional wells totaled ∼33,000 (2005−2015): two-thirds vertical wells (∼22,800) and onethird horizontal wells (∼10,200).

Increasing production from unconventional reservoirs raises challenges related to: (1) large volumes of water required for HF upfront during well completion, and (2) limitations to disposal of PW in these low permeability unconventional shale reservoirs. Many studies have emphasized water scarcity concerns related to large water requirements for HF of unconventional reservoirs, particularly in semiarid regions, such as the Eagle Ford play (Texas), Permian Basin play (Texas and SE New Mexico), and the Niobrara play in Colorado.7−9 While HF water demands are an issue, there is also increased concern about the large volumes of PW. The U.S. generated ∼10 times more PW than oil from combined conventional and unconventional reservoirs in 2012.10 Large PW volumes have been managed in the past primarily by injection into pressuredepleted conventional reservoirs for enhanced oil recovery (EOR), mostly using water flooding.10,11 In contrast, increasing volumes of PW from unconventional reservoirs cannot be directly injected into these low permeability reservoirs but are generally disposed into non-oil-producing geologic intervals. In 2012, ∼45% of PW in the U.S. was injected into producing horizons for EOR, and 40% of PW was injected into nonproducing geologic intervals using salt water disposal

2. MATERIALS AND METHODS 2.1. Permian Basin. The Permian Basin in West Texas and SE New Mexico includes two main sub-basins out of a total of seven regions, the Midland Basin in the east and the Delaware Basin in the west, representing ∼40% of the Permian Basin area B

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Figure 2. East−west cross section along the southern margin of the Permian Basin. The dominant unconventional reservoirs include Wolfcamp and Bone Spring in the Delaware Basin and Wolfcamp and Spraberry in the Midland Basin. These reservoirs are much thicker in the Delaware Basin than in the Midland Basin. The Central Basin Platform includes predominantly conventional reservoirs. The arrows are used to schematize the inputs and production data. Arrow sizes are used to approximate relative volumes. For example, conventional wells generate ∼13 times more produced water (PW) than oil; however, most of this water is recycled by injecting into EORI wells for water flooding. PW from conventional wells accounts for ∼90% of total PW volume. Water injection for hydraulic fracturing (HF) is shown in blue arrows. HF water volumes for unconventional horizontal wells are ∼2 times higher than oil production (Figure S11). PW from unconventional wells is ∼3 times oil production and is injected into saltwater disposal (SWD) wells in shallow horizons (e.g., San Andres in Midland Basin or Delaware Mtn. Grp. in Delaware Basin) or in deeper units (e.g., Ellenburger unit near the basement). The Dockum Aquifer is shown near the surface. See Figure S3 for a more detailed version of this figure. Location of the cross section is also provided in Figure S3. The corresponding stratigraphic column can be found in Figure S4.

included acid fracturing of the rock with small volumes of water, typically much less than ∼10,000 bbl/well (1600 m3/ well). Vertical wells in predominantly unconventional reservoirs use higher volumes of water than in conventional reservoirs and also use proppant, typically sand. In this study, we set the cutoff between conventional and unconventional vertical wells at 10,000 bbl (1600 m3) of water per well and 400,000 lbs (180,000 kg) of proppant. Vertical wells are often used during the early phase of unconventional play development as in the Barnett Shale play.3 In contrast to unconventional vertical wells, unconventional horizontal wells generally require much larger volumes of water and proppant for HF. The Permian unconventional reservoirs are much thicker and more complex than other unconventional oil reservoirs in the U.S., such as the Bakken and Eagle Ford plays, because of up to 9−10 stacked shale intervals in the Permian Basin relative to 1 or 2 in the other oil plays. The Energy Information Administration (EIA) lists six primary unconventional formations in the Permian Basin (Figure S6b). The Wolfcamp consists of several stacked reservoirs, termed Wolfcamp A, B, C, and D.20 The Wolfcamp and Spraberry are found in the Midland Basin and have been termed the Wolfberry play20 (Figure 2, Figure S3, Figure S4). In the Delaware Basin, the Wolfcamp and overlying Bone Springs are sometimes referred

(Figure 1). The Permian Basin is named for the geologic age of the dominant producing geologic intervals. The Delaware Basin has a much thicker vertical interval with interbedded organicrich mudrocks (∼10,000 ft, 3000 m) than the Midland Basin (∼3000 ft, 900 m), with multiple stacked shale reservoirs in each basin (Figure 2). Conventional oil production (not requiring hydraulic fracturing) began in the 1920s, with production from 1340 large oil fields in 32 identified plays, each field with cumulative production exceeding 1 million bbl (Figure S1c).19 Oil production from conventional reservoirs in the Permian Basin peaked in the early 1970s and has been declining since then (Figures 3, Figure S5). The conventional fields are mostly located in the margins of the Midland and Delaware basins and in between these two basins in predominantly carbonate platforms and overlying siliciclastic sediments.20 Most conventional fields contain oil that migrated from the source rocks in the basin centers and accumulated in moderate to high permeability reservoirs. The oil is retained in these reservoirs by structural and stratigraphic traps, and the overlying halite and anhydrite deposits provide an effective seal (Figure 2). There is limited conventional oil production within the Midland and Delaware basins.19,20 There is no clear distinction between conventional and unconventional vertical wells. Conventional drilling often C

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to as the Wolfbone play. The recently discovered Alpine High in the southern Delaware Basin (Reeves County) includes older units in the Barnett and Woodford shales in addition to the Wolfcamp and Bone Spring units. The climate in the Permian Basin is semiarid with mean annual precipitation of 17.3 in. (440 mm; 1980−2010) (Figure S7). The Permian Basin region includes three major aquifers: the Ogallala, Edwards-Trinity Plateau, and Pecos Valley aquifers, and also four minor aquifers (Figure S8). Land use is dominated by shrubland (68%) and grassland (14.5%) with limited cropland (12%) (Figure S9). Irrigation is the primary water use in the Permian Basin, accounting for an average of 91% of the total water use (2000−2014), followed by municipal water use (6%), and other (livestock, industrial, 2%). The main urban centers in the region include Lubbock (population 229,500) and Midland-Odessa (population 236,700) (United States Census Bureau, 2010). 2.2. Data Sources and Analyses. Detailed information on data sources, along with URLs, and analyses are provided in Supporting Information (SI), Section 1. A flowchart is used to describe the various types of data and analyses used in this study (Figure S10). Historical oil and associated gas monthly production data are reported by oil field lease to the Railroad Commission of Texas but are applied to individual wells in the IHS database using an internal algorithm. Water production is not reported by operators but is estimated by IHS from annual production tests. Management of PW included injection into producing geologic intervals for EOR and into nonproducing intervals through SWD wells with data derived from IHS data.

Figure 3. Permian Basin a) oil and b) produced water (PW) generation during the period 1980−2015. Respective total values for conventional and unconventional formations are shown for the period 2000−2015. See Figure S5 and S19 for more detailed information.

Table 1. Selected Values for Unconventional Horizontal Wells for the Entire Permian Basin (Including Midland, Delaware, Northwestern, Northern, and Eastern Regions) and Midland and Delaware Referring Only to these Sub-basins (Figure 1)a

a

Values represent medians for the periods indicated unless otherwise noted except for EUR values, which represent means. An expanded version of this table is provided in the Supporting Information (Table S1). D

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Environmental Science & Technology Data on past water use for HF were obtained primarily from the IHS database and compared to reported data in the FracFocus database (www.fracfocus.org). Data analysis included evaluation of PW from conventional wells relative to oil and gas production, and management approaches for PW by comparing with volumes of water injected into EOR injection (EORI) wells and SWD wells. Spatiotemporal variability in HF water use for unconventional vertical wells and water, oil, and gas production were also evaluated. Most of the analysis focused on unconventional horizontal wells, characterizing PW and HF water volumes and related SWD injection volumes. Decline curves were developed for oil, gas, and PW volumes from unconventional wells to determine the estimated ultimate recovery (EUR) over a 20 yr lifetime of the well (SI, Section 2). The water intensity per unit of energy production was estimated by dividing the PW and HF water volumes by the oil and gas production volumes (12 month production and EUR), and is referred to as the PW to oil ratio (PWOR) and the HF water to oil ratio (HFWOR). Various management strategies for PW were considered, including injection into SWD wells and reuse/recycling of PW for HF. Reported well completion data (including HF water use, proppant use, down-hole well surveys, and perforated intervals) and production data (including oil, gas, and produced water) were aggregated for individual wells based on (10-digit) American Petroleum Institute (API) numbers. Completion data were checked for internal consistency, and outliers were identified by comparison with overall population distributions. Ratios between selected parameters (e.g., vol HF/length of lateral, mass of proppant/volume of HF) were calculated, and outlier values were identified and corrected where possible. Values for PW volumes, which are estimated monthly from annual well production tests, were aggregated at the basin level, and the annual total values were compared with reported values of injected water in both SWD and EORI wells for the same period.

Table 2. Selected Ratios between Hydraulic Fracturing Water, Produced Water (PW), and Oil Production, Including Field Total for 2005−2015, 12-Month Representing the First 12 Month Total Production, and Estimated Ultimate Recovery (EUR) Volumesa

a

EURs are based on 20-yr decline curves. The Permian Basin column represents the entire Permian Basin, and Midland and Delaware basins represent sub-basins within the Permian Basin (mo is month, EUR is estimated ultimate recovery, PW is produced water, and HF water is water volume for hydraulic fracturing). An expanded version of this table is provided in the Supporting Information (Table S2).

5. Unconventional horizontal wells use about 5 times more water per well for HF than unconventional vertical wells (Section 3.2.2b). HF water use varies spatially by a factor of 8 (5th− 95th percentiles) throughout the basin (2015 data, Table S8). HF water use markedly increased over time, by a factor of 7−10 in terms of median per unit of lateral well length in the Midland and Delaware basins (2008−2015) (Figure 6a). Proppant loading increased by similar amounts (Figure 6b). 6. The HF water to oil ratio (HFWOR) increased by factors of 4−10 with time because oil production did not increase as much as HF water use in the Midland and Delaware basins (2008−2015) (Table 2, Section 3.2.2c). 7. There is a high potential for reuse of PW because treatment requirements are minimal (clean brine). In addition, PW from unconventional wells disposed in SWD wells is sufficient to meet HF water requirements based on analysis of 2014 data, with SWD/HF water ratios of 1.7 (Midland) and 2.6 (Delaware), SWD/HF ratios >1 in all counties except one, and in most 5 mile grid cells (Figure 7, Section 3.3b). 8. Challenges to PW reuse are low costs of fresh and brackish groundwater, low costs of PW disposal, and legal and logistical issues (Section 3.3c). 3.1. Conventional Wells. Conventional reservoirs have extremely high well densities around the margins of the Midland and Delaware basins and in the Central Basin Platform between the two basins (Figure 1). Low water volumes are used for drilling and completion and acid fracturing some wells. High PW volumes from conventional reservoirs in the Permian Basin total 40 × 109 bbl (6.4 × 109 m3; 2005−2015), accounting for 90% of total PW in the basin (Figure 4, Table S5). PW volumes generally increased since the 1950s and 1960s (Figure S5). Although conventional wells generate large volumes of PW, most of this PW is recycled for pressure

3. RESULTS Many of the results described in this section are summarized in Table 1, Table 2, and figures in the SI. The main results are as follows: 1. Conventional wells account for 90% of the PW with a high PW to oil ratio (PWOR = ∼13), with PW mostly injected into pressure-depleted oil reservoirs for EOR using water flooding (Figure 4, Figure 5, Section 3.1). 2. Unconventional wells account for the remaining 10% of PW, with a much lower PW to oil ratio (PWOR = 2.6−2.8) than conventional wells (Figure 4, Figure 5, Section 3.2). However, PW from unconventional wells cannot be reinjected into the low permeability shale reservoirs but is injected into non-oil-producing geologic intervals using SWD wells that could result in overpressuring and induced seismicity. 3. Unconventional vertical wells were drilled mostly during the exploratory phase of unconventional development, with well numbers peaking in 2012 and declining by 70% since then (Figure S13, Section 3.2.1). 4. Unconventional horizontal wells generate 2.8 times more PW in the Delaware Basin than in the Midland Basin (2015 data, bbl/ft, 12 mo, and EUR) (Table 1, Figure S21, Section 3.2.2a). There is no substantial temporal variation in PW volumes. E

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Figure 4. Total production of oil (green), gas (orange), and produced water (PW, gray) from 2005−2015 from conventional wells and unconventional vertical and horizontal wells. Water use for hydraulic fracturing (HF, blue) is also included. Total injection/disposal of produced water (red) is shown below production, including enhanced oil recovery injection (EORI) and salt water disposal (SWD). Numbers in parentheses refer to metric equivalent (109 m3). Water volumes are dominated by PW from conventional wells, accounting for 90% of total PW (40 × 109 bbl/44 × 109 bbl) with unconventional wells accounting for the remaining 10% (4 × 109 bbl). Estimated PW volumes (44 × 109 bbl) are 14% less than EORI + SWD volumes (51.4 × 109 bbl). Most PW from conventional wells is recycled for EORI using water flooding. PW from unconventional wells is disposed using SWD wells. Note that volumes of HF water (blue) are similar to volumes of oil produced (green) for unconventional wells. An expanded version of this figure is provided in Figure S11. Time series of PW volumes, injected water volumes in the Permian Basin, and SWD volumes by formation depths are provided in Figure S26.

Figure 6. Median (a) hydraulic fracturing (HF) water and (b) proppant use normalized by lateral length for horizontal unconventional wells in the Midland and Delaware basins. Data on HF water use are provided in Table S8 and proppant loading in Table S9.

Figure 5. Permian Basin water intensities for conventional, unconventional vertical, and unconventional horizontal wells for the period 2005−2015, including the hydraulic fracturing water to oil ratios (HFWOR) and produced water to oil ratios (PWOR). The water intensities (PWOR and HFWOR) are based on the cumulative field totals. For example, the PWOR for conventional wells of 13 is based on 40 × 109 bbl PW divided by 3 × 109 bbl (Figure 4), whereas the ratio is much lower for unconventional wells (2.8 for verticals and 2.6 for horizontals). Water intensities relative to oil and gas ratios are provided in Figure S11. The intensity data are provided in Table S16 and Table S17.

Figure 7. Ratio of produced water volumes disposed in saltwater disposal (SWD) wells relative to water use for hydraulic fracturing expressed as a percent within a 5 mile grid based on 2014 data. SWD/ HF ratios ≥100% indicate grids with sufficient PW being disposed in SWD wells to support HF (yellow and red grids), whereas SWD/HF ratios HF, and many cells with SWD < HF are often located proximal to cells with SWD > HF (Figure 7). Some areas have concentrated SWD < HF, such as the southeastern portion of the Midland Basin. Evaluating results on a per well basis indicates that PW/ HF water ratios are 2.0−4.4 times higher for unconventional vertical wells than for unconventional horizontal wells (2005− 2015) (Table S19a). Considering 12-mo PW/HF water for horizontal wells results in ratios of 0.4 (Midland) to 1.5 (Delaware) (2005−2015; Table S19b). While the results suggest that there may not be sufficient PW to support HF in the Midland Basin in the future if relying solely on horizontal wells, it also means that there is less PW to manage from these wells. The potential for future water reuse to support HF is difficult to determine at this stage because oil and gas resource estimates have not been determined, and the future pace and extent of unconventional well drilling are uncertain. 3.3c. Challenges to Reusing/Recycling Produced Water. There are various challenges to reusing/recycling PW for HF, including HF water costs, PW disposal costs, PW quality and treatment costs, and legal and logistical issues. Currently operators indicate that low costs to obtain fresh or brackish groundwater and lay flat pipe to transport water to the site act as a deterrent to reuse of PW. For example, University Lands reports a water cost of $0.35 per bbl for fresh or brackish H

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Environmental Science & Technology groundwater.23 Disposal costs are also low (SI, Section 4). Considering the corresponding 12-mo oil production (∼66,000−124,000 bbl) at $50/bbl ($2.5 million) indicates that sourcing and disposing of water represent 5 to 15% of the oil price per bbl. Limited data on PW quality indicate that TDS range from 30,000 to ∼200,000 mg/L (up to 6 times that of seawater) throughout much of the Midland Basin and are more variable in the Delaware Basin (∼30,000−∼400,000 mg/L) (Figure S30). These data are derived from the USGS Produced Water database based on samples collected mostly from conventional reservoirs.24 Recent sampling of PW from 8 wells in the Wolfcamp shale (Midland Basin) shows TDS range from 36,000 to 163,000 mg/L.25,26 Reuse/recycling costs depend on the PW quality and level of treatment. Because “clean brines” can be used for HF, treatment requirements are minimal. A pilot test at a site in Barnhart in the Midland Basin indicates that reuse of PW that had been treated to remove total suspended solids and oil and addition of chlorine dioxide (biocide, reduces iron and organic levels) ranged from 30 to 50% of the costs of sourcing fresh or brackish groundwater and disposing of PW.1 Legal issues related to ownership may arise if PW is changed from a waste to a resource. Logistical issues include those related to storing and transporting water. Operators indicate that they are now building pits that would store 1 × 106 bbl (∼0.2 × 106 m3); however, some groups, such as University Lands, limit the use of pits to freshwater23). A typical tank holds 500 bbl, requiring an equivalent of 2000 tanks. Transport issues include right of ways to transport PW across different landowner properties. Infrastructure is expanding to transport water in some regions of the basin. Pioneer has installed a 100 mile (160 km) pipeline (36 in. [900 mm] diameter) in the Midland Basin that extends throughout their leases (Figure S31). The trade-offs related to reuse of PW relative to increased risks of contamination associated with surface spills or leaks from increased handling, storage, and transport also need to be considered. Previous studies indicate that most contamination issues associated with disposal wells were actually surface handling issues.11 3.4. Future Work. The complexity of the Permian Basin with stacked plays and large conventional and unconventional resource development resulted in gaps in our studies that should be addressed in future work. Examples include the following: (1) identifying water sources used for HF, including reuse/recycling of PW, (2) assessing groundwater availability for HF, (3) monitoring impacts of HF on groundwater resources, e.g., groundwater level monitoring, surface spills, and leaks; (4) vertical disaggregation of reporting of HF water and PW for the basins into the individual stacked plays (e.g., Wolfcamp and Spraberry in Midland Basin); (5) assessing disposal capacity of nonproducing horizons (e.g., San Andres in Midland Basin); and (6) evaluating pressure data and extent of overpressuring and potential for induced seismicity. Lack of reporting on water sources for HF and extent of PW reuse/ recycling will require acquisition of these data through surveys of operators or other approaches. Regional groundwater models provide data on physical availability of fresh groundwater for the aquifers in the region;27,28 however, the challenge lies in assessing regulatory limitations on water availability. Limited analysis suggests that current HF practices have resulted in local drawdown of some aquifers in specific regions (e.g., drawdown of up to 100 ft (∼30 m)) in the Dockum Aquifer;29,30 however, the state-based monitoring program is designed to assess

ambient groundwater availability and not impacts of HF on groundwater resources. Unit Conversions. The following unit conversions were used in this paper: 1 gal = 3.785 L 1 barrel (bbl) = 42 gal = 0.159 m3 = 159 L 1 bbl/ft = 0.522 m3/m 1 lb/gal = (1 kg/2.2 lb) × (1 gal/3.785 L) = 0.12 kg/L 1 bbl of oil = 5.8 × 106 Btu = 6.119 gigajoule 1 ×103 ft3 gas (1 MCF) = 1 × 106 Btu = 1.055 gigajoule 5.8 × 103 ft3 gas = 1 bbl of oil equivalent (boe) 1 ×106 Btu = 0.17 bbl of oil 1 bbl/106 Btu = 168 L/gigajoule water-to-oil ratio (WOR, HF water or PW volume relative to oil produced; vol/vol, unitless) equivalent to 0.172 bbl water/ 106 Btu.

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ASSOCIATED CONTENT

S Supporting Information *

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.7b02185. More detailed versions of some of the manuscript figures and tables and additional figures and tables (PDF)

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AUTHOR INFORMATION

Corresponding Author

*Phone: 512 471 8241. Fax: 512 471 0140. E-mail: bridget. [email protected]. ORCID

Bridget R. Scanlon: 0000-0002-1234-4199 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS We acknowledge the Cynthia and George Mitchell Foundation, The University of Texas at Austin Energy Institute, the Tight Oil Resource Assessment consortium, the William L. Fisher Endowed Chair in Geological Sciences, and the Jackson School of Geosciences for financial support of this study. We are very grateful to IHS and Digital H2O for access to their databases. We benefited greatly from input from operators through the Energy Water Initiative.

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REFERENCES

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DOI: 10.1021/acs.est.7b02185 Environ. Sci. Technol. XXXX, XXX, XXX−XXX