Article pubs.acs.org/est
State-Scale Perspective on Water Use and Production Associated with Oil and Gas Operations, Oklahoma, U.S. Kyle E. Murray* Oklahoma Geological Survey, The University of Oklahoma, 100 East Boyd Street Norman, Oklahoma 73019-0628, United States S Supporting Information *
ABSTRACT: A common goal of water and energy management is to maximize the supply of one while minimizing the use of the other, so it is important to understand the relationship between water use and energy production. A larger proportion of horizontal wells and an increasing number of hydraulically fractured well bores are being completed in the United States, and consequently increasing water demand by oil and gas operations. Management, planning, and regulatory decisions for water, oil, and gas are largely made at the statelevel; therefore, it is necessary to aggregate water use and energy production data at the state-scale. The purpose of this paper is to quantify annual volumes of water used for completion of oil and gas wells, coproduced during oil and gas production, injected via underground injection program wells, and used in water flooding operations. Data from well completion reports, and tax commission records were synthesized to arrive at these estimates for Oklahoma. Hydraulic fracturing required a median fluid volume of 11 350 m3 per horizontal well in Oklahoma. Median fluid volume (∼15 774 m3) and volume per perforated interval (15.73 m3 m−1) were highest for Woodford Shale horizontal wells. State-scale annual water use for oil and gas well completions was estimated to be up to 16.3 Mm3 in 2011 or less than 1% of statewide freshwater use. Statewide annual produced water volumes ranged from 128.5 to 146.6 Mm3, with gas wells yielding an estimated 72.4% of the total coproduced water. Volumes of water injected into underground injection control program wells ranged from 206.8 to 305.4 Mm3, which indicates that water flooding operations may use up to 167.0 Mm3 per year. State-scale water use estimates for Oklahoma could be improved by requiring oil and gas operators to supplement well completion reports with water use and water production data. Reporting of oil and gas production data by well using a unique identifier (i.e., API number) would also allow for refinement of produced water quantity information. Reporting of wastewater disposal and water flooding volumes could be used to further develop state-scale water accounting and best management practices.
1. INTRODUCTION Water is withdrawn and consumed throughout the life cycle of an energy source; likewise, energy is consumed when moving water from source to consumer. In the sustainability picture, water and energy resources are fundamentally connected1 and have created what some refer to as the water-energy nexus.2,3 Poor management or inefficiencies when using one resource can negatively affect sustainability of the other; therefore, a common goal of water and energy management is to maximize the supply of one while minimizing the use of the other.4 As we develop conventional, unconventional, or alternative sources of energy it is important to understand the driving forces within and feedback relationships between the water and energy cycles. Advances in horizontal drilling, hydraulic fracturing, and seismic technology have allowed for development of oil and gas from United States (U.S.) reserves in many unconventional plays, such as shales. Oil and gas production has increased in some parts of the U.S. because it is now possible to tap formations such as the Bakken, Barnett, Eagle Ford, Haynes© 2013 American Chemical Society
ville, Marcellus, Mississippian, and Woodford that were previously not economically recoverable. Natural gas development from unconventional sources increased 10-fold between 2001 and 2011.5,6 It is projected that natural gas will continue to increase and account for 28% of primary energy consumption in the US by 2040.7 Development of oil and gas from unconventional plays via horizontal drilling and hydraulic fracturing is no exception to the water-energy nexus because substantial volumes of water are used relative to conventional drilling and completion techniques.8,9 In addition to the water used for high-pressure hydraulic fracturing, large volumes of coproduced water (i.e., water extracted from subsurface geologic formations containing oil and gas) return to the surface. Coproduced water may contain copious amounts of salts, metals, and naturally Received: Revised: Accepted: Published: 4918
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Figure 1. Geologic provinces, major geologic structures, and horizontal wells completed in Oklahoma between 2000 and 2011. [n] represents number of well completion reports available for each producing formation.
have not previously been summarized by formation or at the state-scale. In addition to water used for well completions, unknown volumes of water are coproduced with oil and gas. The OCC does not presently require volumes of water that are coproduced with oil and gas to be reported, but does obtain monthly estimates of injection volumes for disposal wells. The Oklahoma Water Resources Board (OWRB) recently updated Oklahoma’s Comprehensive Water Plan (OCWP) and projected water demand in various sectors including the oil and gas sector. In the OCWP, water use for oil and gas operations are projected to increase from 51.9 Mm3 in 2010 to142.6 Mm3 in 2060, which comprises 5% of the total 2060 water demand.19 The OCWP also presents an aggressive goal of maintaining statewide water use at current levels through 2060.19 Because there is an increasing proportion of horizontal wells and greater frequency of hydraulic fracturing, higher volumes of water are expected to be used by oil and gas operations in Oklahoma. Consequently, it is imperative to quantify volumes of water handled and used by the oil and gas sector so that sustainable water management practices can be implemented at the statescale. Objectives of this study were to quantify annual volumes of water used for completion of oil and gas wells, coproduced during oil and gas production, injected via underground injection program wells, and used in water flooding operations.
occurring radioactive material (NORM) such as uranium (U), thorium (Th), and radium (Ra).9 Due to the poor quality of coproduced water it is, in most cases, subsequently disposed via deep subsurface wastewater injection wells. Coproduced water volumes are reported in some areas, but must be estimated from water to oil/gas ratios in others.10 Water use by U.S. oil and gas operations is projected to increase, along with an increased possibility for groundwater contamination if wastewater is not properly managed.11 Water resources and oil and gas activity are often regulated by individual states because natural resources and economic or cultural factors affecting the industries may vary considerably across state boundaries.12 Many U.S. states (e.g., Colorado, Kansas, New Mexico, Oklahoma, Texas, and Wyoming) that have abundant reserves of oil and gas are also subject to water scarcity due to uneven spatial and temporal distribution of rainfall.13 In these states it is important to assess water use for oil and gas extraction, recycle fluids whenever possible,12 and factor water use into long-term water resources planning. A recent paper by Nicot and Scanlon14 examined water use for shale-gas production in Texas, the leading producer of oil and gas in the U.S. The oil and gas industry in Texas is often credited with launching the technology to develop the Barnett Shale in the Dallas-Ft. Worth area.5 Water use in Texas’ oil and gas industry is expected to peak in the mid-2020s for developing gas reserves.14 However, Texas’ increase in water use for oil and gas extraction could be offset by water savings that may result from switching coal-fired power plants to natural gas combined cycle plants.15 Unfortunately, obtaining water and energy data may be difficult in other states because disparate data are aggregated at differing scales, and may require substantial processing from their raw form to a format that is useful to the public.2 Despite a steady decline by more than two-thirds from 1967’s peak oil production,16 Oklahoma consistently ranks among the top five states for oil and gas production in the U.S.17 In recent years, the annual proportion of oil and gas wells completed horizontally in Oklahoma increased from less than 5% in 2002 to nearly 30% in 2010, with a majority of the wells producing from the Woodford and Mississippian.18 Water used for hydraulically fracturing wells in Oklahoma is generally reported to the Oklahoma Corporation Commission (OCC) as part of well completion reports. However, volumes per well
2. MATERIALS AND METHODS Data from various sources including industry partners, the OCC, and U.S. Geological Survey (USGS) were compiled, evaluated by well and formation, then used to estimate water use or production associated with oil and gas operations in Oklahoma. Based on a review of drilling and well completion activity, eight formations were identified as the most active plays and analyzed at the formation-scale for water use when possible. Producing formations with a substantial number of recent (2000 to 2011) horizontal well completions (i.e., active plays) include the Tonkawa, Cleveland, Desmoinesian, Hartshorne, Mississippian, Woodford, Misener-Hunton-Viola, and Arbuckle shown in the legend of Figure 1 in descending stratigraphic order.18 2.1. Compile Volumes of Oil and Gas Produced. Volume of oil and gas produced in the state of Oklahoma are reported to the Oklahoma Tax Commission (OTC) when tax 4919
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Figure 2. Oil and gas production in Oklahoma, 2000 to 2011.
Figure 3. Well completions and number of oil or gas producing wells in Oklahoma, 2000 to 2011.
queries were used to attribute the producing formation of each well completion record as one of the eight most active plays, Formation Not Reported, or Other. Queries of the relational database were designed to summarize the number of wells completed horizontally versus completed vertically per year and per producing formation. 2.3. Tabulate Volumes of Water Used for Well Completion. Reported volumes of water used for hydraulic fracturing were selected from the Test Treatment table of the relational database. Well completion records were then grouped by horizontal or vertical drilling direction and by formation. Hydraulic fracturing volumes for each formation/drilling direction combination were evaluated in quartiles so that the 25th, 50th (median), and 75th percentiles were obtained for hydraulic fracturing volume by formation. 2.4. Estimate Volumes of Produced Water. Reported volumes of water, oil, and gas produced during a production
revenue from sales of oil and gas are collected. Data from the OTC are compiled by the OCC and by many operators and service industry professionals. State-scale, annual oil and gas production was obtained from OCC annual reports.20 Countyscale, monthly oil and gas production and number of producing oil and gas wells in the state were provided by an industry partner.21,22 2.2. Compile Well Completion Data. Data from well completion reports (i.e., Form 1002A) submitted to OCC are frequently appended to a commercial database by a data management company.23 Using the Oklahoma Geological Survey’s (OGS) subscription to the IHS database, five data tables (header, formation, test, test perforation, and test treatment) were exported for wells completed on or after January 1, 2000. These data tables were imported into a relational database and related to one another by a unique identifier (i.e., API Number) for each completed well. Update 4920
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Figure 4. Water volumes used for hydraulically fracturing horizontal wells in Oklahoma. [n] represents number of well completion reports with hydraulic fracturing volume data for each formation.
reported to OCC, the lowest during the 2000 to 2011 time frame. Drilling activity and number of wells completed are highly sensitive to the price of the products (i.e., oil and gas) rather than oil and gas production rates or water availability.14 The proportion of horizontal well completions increased to a maximum of 43.4% in 2011 (Figure 3). The Hartshorne, a coalbed methane (CBM) resource, was one of the most active for horizontal well installations with ∼1137 wells completed from 2000 to 2006 (Supporting Information (SI), A). More recently, the Woodford Shale was the most active formation for horizontal well completions, with a total of ∼1707 wells completed from 2007 to 2011 (SI, A). Of the ∼6804 horizontal wells completed from 2000 to 2011 (SI, A), ∼2963 had volume of hydraulic fracturing fluid reported in the Test Treatment table of well completion reports. Figure 4 shows the 25th, 50th (median), and 75th percentiles of volumes reported when hydraulically fracturing horizontal wells. Median volume of water used for hydraulically fracturing a horizontal well was 11.350 m3 (∼71 388 bbl) and for a vertical well was 238.5 m3 (∼1500 bbl). Oil and gas markets have favored production of oil in Oklahoma since 2009 and led to increased activity in oil producing formations. The Mississippian is a relatively shallow, predominantly carbonate formation located in northern Oklahoma and throughout Kansas that is an oil-bearing unit, especially in the Cherokee Platform (Figure 1). Due to a relatively high natural fracture network and permeability, the Mississippian requires far less water for hydraulic fracturing than other formations such as the Woodford Shale, a lowpermeability shale. Horizontal wells completed in the Woodford required the highest volumes of water for hydraulic fracturing, with a median volume of 15 774 m3 (∼99 216 bbl). These volumes are reasonable in comparison to medians of ∼12 500 m3 in the Marcellus Shale, 10 600 m3 in the Barnett Shale, 16 100 m3 in the Eagle Ford, and 21 500 m3 in the TXHaynesville.5,14
test (PT) or initial potential (IP) test were selected from the Test table of the relational database. Ratio of water:oil and water:gas was calculated for each well completion record and collectively evaluated in quartiles so that the 25th, 50th (median), and 75th percentiles of the ratios could be used as multipliers. Median ratio of water:oil and water:gas were multiplied by the annual oil and gas production rates, respectively, to estimate produced water volumes. 2.5. Summarize Volumes of Water Reported to UIC Program. A database was constructed for monthly well injection volumes reported to OCC under the Underground Injection Control (UIC) program.24 Injection volumes were grouped and summed by year to represent the total statewide (Oklahoma) UIC volume.
3. RESULTS AND DISCUSSION 3.1. Oil and Gas Production in Oklahoma. Minimum, mean, and maximum annual oil production were 8.5, 9.0, and 9.7 million tonnes (MTO), respectively, between 2000 and 2011 (Figure 2). Oil production remained relatively constant between 2000 and 2011 because a long history of production has achieved a balance between rate of depletion of reserves and improved recovery from well-defined traps.17 Minimum, mean, and maximum annual gas production were 35.3, 40.5, and 43.9 million tonnes of oil equivalent (MTOE), respectively between 2000 and 2011 (Figure 2). Decreased gas production from 2009 to 2011 is attributed to decreasing gas prices and a strategic shift of new well completions into Oklahoma’s Cherokee Platform that favors oil production. Number of wells reported to have produced oil, gas, or oil and gas varied from a minimum of ∼125 270 in 2005 to a maximum of ∼135 970 in 2011 (Figure 3). 3.2. Water Use for Well Completions. During the 2000 to 2011 time frame, well completion rate was highest in 2008 with ∼4790 well completions reported to OCC (Figure 3). In the next year (2009) only ∼2606 well completions were 4921
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Figure 5. Estimated water use for vertical and horizontal well completions in Oklahoma. VW represents vertical wells, HW represents horizontal wells.
Figure 6. Volume of water produced per volume of oil produced from Oklahoma oil wells. [n] represents number of well completion reports with PT or IP test data for each formation.
0.12 m3 m−1 and those in the Woodford had the highest median water use of 15.73 m3 m−1 (SI, B). These measures indicate the correlation between intrinsic permeability and volume required for hydraulic fracturing. State-scale volumes of water used for hydraulic fracturing were derived by multiplying the median volume used for hydraulically fracturing each formation by the number of horizontal/vertical wells completed in that formation and summing water use for wells in all formations. The largest
Relatively small volumes of water were used for hydraulically fracturing the Hartshorne, Misener-Hunton-Viola, and Arbuckle because they are highly permeable formations of coalsandstone, sandstone-carbonate, and carbonate, respectively (Figure 4). Water use per formation can be “normalized” to adjust for the lateral length of a horizontal well by computing volume of water per length of perforated interval (m3 per m). Using this approach, horizontal wells that were hydraulically fractured in the Arbuckle had the lowest median water use of 4922
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Figure 7. Volume of water produced per volume of gas produced from Oklahoma gas wells. [n] represents number of well completion reports with PT or IP test data for each formation.
Figure 8. Estimated annual volume of produced water associated with oil and gas production in Oklahoma.
3.3. Produced Water Volumes. Although there were ∼43 536 wells completed between 2000 and 2011, well completion reports for only 12 058 wells contained data related to produced fluid ratios. Volumes from PT and IP tests for vertical and horizontal wells were combined into one comprehensive data set, with vertical well tests being more abundant (e.g., 389 PT and 9829 IP tests) and horizontal well tests less abundant (e.g., 22 PT and 2006 IP tests). Figures 6 and 7 show the 25th, 50th (median), and 75th percentiles of water:oil and water:gas, respectively, for the most active plays in Oklahoma. Based on well completion records from 2000 to 2011, the median ratio of water produced to oil produced was 3.7. Median statewide ratio of water:oil was multiplied by the volume of oil produced (Figure 2) to derive annual volume of water coproduced related to oil production (Figure 8). Based on Oklahoma’s well completion records from 2000 to 2011, the median ratio of water produced to gas produced (oil equivalent
annual volume of water used for hydraulically fracturing horizontal well completions was up to 12.0 Mm3 (∼75.2 Mbbl) in 2011 and vertical well completions was up to 1.1 Mm3 (∼7.1 Mbbl) of water in 2008 (Figure 5). Water is used for various purposes during well drilling including makeup of drilling mud.9 Because these volumes of water are not reported in Oklahoma, a median volume of 1262 m3 (∼7935 bbl) per well5,25 was multiplied by the number of horizontal and vertical well completions each year. Water use for drilling of horizontal wells was estimated to reach a maximum of 1.7 Mm3 (∼1.1 Mbbl) in 2011 and for vertical wells was estimated to reach a maximum of 5.0 Mm3 (∼3.2 Mbbl) in 2006 (Figure 5). These estimates have some inherent uncertainty, but provide volumes that can be used to compare relative water use over time as a function of number of wells completed. 4923
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use in the oil and gas sector.9 Produced water volumes are, however, more voluminous and there appears to be a substantial gap between produced water estimates and reported UIC volumes. This gap indicates, for example, that as much as 167 Mm3 may have been used for water flooding in 2010. Increased reporting requirements for coproduced water and UIC volumes would allow for more accurate statewide water accounting, and promote sustainable water management practices.
volumes) was 2.1. Median statewide ratio of water:gas (oil equivalent volume) was multiplied by the volume of gas produced (Figure 2) to derive annual volume of coproduced water related to gas production (Figure 8). Derived volumes indicate that coproduced water from gas wells comprised ∼72% of the produced water in the state of Oklahoma between 2000 and 2011. Collectively, the annual volume of coproduced water ranged from 128.5 Mm3 (∼808 Mbbl) in 2011 to 146.6 Mm3 (∼922 Mbbl) in 2009. Produced water volumes were previously estimated by Argonne National Laboratory (Argonne) as part of nationalscale reports by following a similar approach.26 Argonne estimates for Oklahoma were 199 Mm3 (∼1253 Mbbl) in 2002 and 199 Mm3 (∼1254 Mbbl) in 2007.26,27 These estimates were substantially higher than estimates derived as part of this study (134 Mm3 or ∼842 Mbbl in 2002, and 140 Mm3 or ∼881 Mbbl in 2007) presumably because the Argonne estimates used a higher ratio of water:oil (7.5−9.5) and did not consider water produced during gas production using gas production rates or a ratio of water:gas. Some indications are that the ratio of water:oil will increase when an oil well is nearing the end of its productive life, and at some point the cost of managing the water becomes so high that the well is no longer profitable.26 Conversely, the ratio of water:gas may follow the opposite pattern because the hydrostatic pressure in the formation gradually decreases.26 Because most ratios for water:oil and water:gas used in this study were obtained from IP tests it is possible that the coproduced water volumes associated with oil production were underestimated, but the coproduced water volumes associated with gas production were overestimated. If produced water volumes were reported for the more than 125 000 oil and gas producing wells these estimates could be refined to reflect changes in fluid production ratios that are characteristic of more mature producing wells. In future iterations of these calculations, it is desirable to calculate coproduced water volumes by producing formation; however, OTC records do not itemize oil and gas production by well or formation. 3.4. UIC and Water Flood Volumes. Produced water volumes were compared to volumes of water injected (SI, C) under the UIC program, which is regulated by OCC. Statewide injection volumes totaled a minimum of 206.8 Mm3 in 2000 and a maximum of 305.4 Mm3 in 2010 (SI, D). UIC volumes are a combination of salt water coproduced from oil and gas wells, water used for water flooding (i.e., enhanced oil recovery), and other industrial wastewaters. If UIC volumes were comprised of only produced water and water flooding volumes, then an upper limit for volume of water used in water flooding would be the difference between UIC volume and produced water estimates each year (SI, D). Annual water use from 1990 to 2005 by Oklahoma’s industrial and mining sector was 36.1−52.5 Mm3 (227−330 Mbbl) or a relatively small percentage (from 1.5 to 2.7%) of freshwater use.28−30 An increased frequency of hydraulic fracturing creates the perception that large volumes of water are being used by the oil and gas industry.31 Estimates derived in this study indicate that water use for oil and gas well completions in 2000 and 2005 were 4.7 Mm3 (∼1234 Mgal) and 6.7 Mm3 (∼1757 Mgal), respectively, or 0.19 and 0.31% of freshwater use in Oklahoma. Though water use for completion of oil and gas wells represents a small proportion of total water use, water conservation, recycling/reuse, and alternative fluids such as a N2/CO2 fluid for “dry frac” could further reduce water
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ASSOCIATED CONTENT
S Supporting Information *
Supporting Information is provided by the author as reference material, and includes three tables and one figure that complement text and figures of the manuscript’s main body. This material is available free of charge via the Internet at http://pubs.acs.org.
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AUTHOR INFORMATION
Corresponding Author
*Phone: (405) 325-7502; fax: (405) 325-7069; e-mail: kyle.
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The author acknowledges several colleagues at the Oklahoma Geological Survey (OGS) for contributing to this article. Specifically, Brian Cardott is acknowledged for providing valuable input during data compilation. John Vance is also acknowledged for providing oil and gas production data compiled by Lasser Inc from tax commission records. Participants at various workshops gave feedback to shape the direction of this effort, their input is greatly appreciated. The author acknowledges the time taken by several peer reviewers and thanks them for their suggestions and thoughtful comments. Analyses presented in this article are based on information available to the author, and does not necessarily represent the views of the OGS, the University of Oklahoma (OU), their employees, or the State of Oklahoma. The accuracy of the information contained herein is not guaranteed and the mention of trade names is not an endorsement by the author, OGS, or OU.
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ABBREVIATIONS MBO million barrels oil MBOE million barrels oil equivalent MTO million tonnes oil MTOE million tonnes oil equivalent TCF trillion cubic feet bbl barrel Mbbl million barrels Mm3 million cubic meters CBM coal-bed methane API American Petroleum Institute OCC Oklahoma Corporation Commission OTC Oklahoma Tax Commission
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