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Recent Trends in Water Use and Production for California Oil Production Kate Tiedeman, Sonia Yeh, Bridget R Scanlon, Jacob Teter, and Gouri Shankar Mishra Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.6b01240 • Publication Date (Web): 13 May 2016 Downloaded from http://pubs.acs.org on May 16, 2016
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Environmental Science & Technology
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Recent Trends in Water Use and Production for California
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Oil Production
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Kate Tiedeman1,2*, Sonia Yeh1,3, Bridget R Scanlon4, Jacob Teter1,5, Gouri Shankar Mishra1,6
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Institute of Transportation Studies, University of California, Davis. Davis, CA, USA
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2
Graduate Group in Ecology, University of California, Davis. Davis, CA, USA
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3
Department of Energy and Environment, Chalmers University of Technology, Gothenburg,
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Sweden 4 Bureau of Economic Geology, Jackson School of Geosciences, University of Texas at
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Austin. Austin, TX USA
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International Energy Agency, Paris, France
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Precourt Energy Efficiency Center, Stanford University, USA
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* Corresponding author. One Shields Ave, Davis, CA 95616. Tel: (650) 465-4181. Email:
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[email protected].
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Word count: 5,788 words text + 4 figures x 300 words (each) = 6,988 words
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Keywords: Petroleum, Conventional Oil, Hydraulic Fracturing, Fracking, Freshwater, Water
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Intensity, Produced Water
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ABSTRACT
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Recent droughts and concerns about water use for petroleum extraction renew the need to
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inventory water use for oil production. We quantified water volumes used and produced by
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conventional oil production and hydraulic fracturing (HF) in California. Despite a 25% decrease
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in conventional oil production from 1999 to 2012, total water use increased by 30% though much
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of that increase was derived from re-use of produced water. Produced water volumes increased
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by 50%, with increasing amounts disposed in unlined evaporation ponds or released to surface
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water. Overall freshwater use (constituting 1.2% of the state’s non-agricultural water
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consumption) increased by 46% during this period due to increased freshwater-intensive tertiary
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oil production. HF has been practiced in California for more than 30 years, accounting for 1% of
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total oil production in 2012 from mostly directional and vertical wells. Water use intensity for
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HF wells in California averaged at 3.5 vol water/vol oil production in 2012 and 2.4 vol/vol in
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2013, higher than the range from literature estimates, and net water use intensity of conventional
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production (1.2 vol/vol in 2012). Increasing water use and disposal for oil production have
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important implications for water management and have potentially adverse health,
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environmental, and ecological impacts.
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INTRODUCTION
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Water is critically important for oil production, particularly in extraction and refining stages.
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However, water resources are severely constrained in many regions, where competition for water
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is intense.1 Recent droughts have greatly reduced water supplies, particularly in California, and
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are projected to intensify with climate change.2 Increasing demand for water, particularly for
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municipalities,3 will compete with water required for energy production. Though it is not yet
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clear how climate change will impact future water availability, decreased snowpack will result in
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depleted supply, while climate change is also projected to increase demand for water in
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California.4,5,6 Studies suggest that the majority of California’s 58 counties will be moderately or
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severely water stressed by 2025,7 though the entire state is already severely water constrained
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due to the current drought.
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Studies on water use for conventional oil production are limited and outdated. Data on
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conventional oil production are difficult to obtain because many states lack sufficient reporting
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requirements to support detailed evaluation of water use and water disposal for conventional
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production.
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California oil production decreased by about 50% since its peak of 394×106 barrels (bbls)
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(62.6×109 L) in 1985 to 199×106 bbls (31.6×109 L) in 2013.8 In 2013, California ranked third in
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terms of oil production in the U.S., accounting for 7% of total U.S. production, after Texas
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(34%) and North Dakota (12%).8 The Energy Information Administration (EIA) estimates that
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2.9×109 bbls of proven reserves still remain in the state as of 2013.9
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The objective of this study was to quantify total water use and water use intensity relative to oil
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production for oil extracted in California using conventional methods as well as hydraulic
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fracturing. Hydraulic fracturing (HF) has been applied to extract energy from tight or shale oil
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and gas (O&G) resources. Tight and shale O&G are among the so-called “unconventional” or
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continuous resources, which also include oil sands, oil shale, and coal bed methane. Many recent
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studies have focused on water used for horizontal drilling and HF for shale and tight O&G
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production.10–12 HF has been practiced in California for more than 30 years, principally to ensure
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that conventional wells attain maximum production.13–15
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California is the third largest oil producing state, and releases publicly available data on water
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use and production from O&G operations.16,17 We detail trends on water use for conventional oil
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production in California, and derive total and net water use intensity relative to oil production to
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fill the existing data gaps. In addition, we quantify flowback-produced (FP) water use intensity
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of conventional and HF oil production. The results of this analysis provide context for
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developing an improved understanding of current impacts of water use for O&G production and
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impacts on water resources.
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1.1
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Conventional oil is extracted using primary, secondary, or tertiary recovery techniques. Primary
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recovery is used when natural pressures in the oil reservoir are sufficient to bring oil to the
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surface, while secondary recovery is used as the reservoir pressure declines.18 Secondary
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recovery, typically referred to as water flooding, represents the majority of U.S. conventional oil
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recovery. In this method, separate wells are drilled to inject water into the formation to stimulate
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crude oil production. In tertiary recovery, or enhanced oil recovery (EOR), the viscosity of the
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oil is reduced by injecting steam, gas or chemicals into the reservoir to recover the remaining oil,
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sometimes using wells previously used in secondary recovery.
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Water use intensity (WUI) is expressed as water use per unit of energy production, and varies
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with recovery technology. Primary recovery is the least water intensive with an estimated water
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use per unit of oil recovery (water to oil ratio, WOR, in vol water/vol oil) of 0.21 (i.e. 0.21 liters
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[L] or gallons [gal] of freshwater per L or gal of crude oil recovered).19 This value is cited
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throughout recent literature with few independent estimates to corroborate it.20–22 The WUI of
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secondary recovery varies by location and technology, but the most referenced estimate is an
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average WOR value of 8.6 over the lifetime of a well, based on analysis of 84 wells in Oklahoma
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in the 1960s.19,23 Tertiary WUI is also highly variable with a wide range of WORs from 1.9 to
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343.19
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In oil production, water is produced along with O&G and results in a produced water intensity
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(PWI) relative to energy production, or “water cut”, produced water relative to total fluids (oil
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and water).24 The produced water is subsequently either injected using Class II wells into
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producing formations for additional recovery (including secondary, tertiary recovery, or HF) or
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for disposal, discharged in evaporation ponds, or returned to the watershed for use by other
Conventional Oil Production
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sectors such as agriculture (often referred to as the “beneficial use” of produced water). In
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addition, there is evidence of adverse health and ecological impacts of surface water disposal and
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secondary (“beneficial”) uses of produced water for crop irrigation, livestock watering, stream
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flow augmentation, and municipal and industrial uses.25–29
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1.2
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The volume of produced water generated by a specific O&G well can vary significantly due to
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many factors, including: reservoir geology, field depth and age, well age, and recovery
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technology used.26–31 The geology and field depth determine the geologic formations which have
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variable ratios of water to oil (i.e. variable water saturations). The age of O&G wells and the
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fields they are located on also influence the amount of water produced. As oil wells age, water
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volumes increase, as oil removed from the formation is displaced by water flowing in from
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surrounding formations. Consequently, oil production decreases and produced water volumes
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increase, resulting in increasing produced water/oil ratios with time.30,33–36 Older oil fields
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produce more than five times the volume of water produced by younger oil fields.32
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1.3
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HF is an O&G well completion technique in which water (≥90%),37 a proppant material, and
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various chemicals are pumped under high pressure into the producing formation to open a
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network of fractures that allow O&G to flow into the well. The fracturing fluids are injected
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through perforations into the rock formation at sufficient pressure to promote fracturing of the
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rock or expansion and extension of existing fractures and to allow fluids to flow out into the
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fractures when HF pressure is relieved. Proppant materials are designed to keep the fractures
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open.38
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In California, unlike other states, HF is principally used to increase production from
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conventional wells.13,14 These are generally vertical wells, which are fractured only tens to
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hundreds of meters from the well.14 Most other states, such as Texas and North Dakota, use
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horizontally drilled wells to access shale and other tight rocks. Estimates of water use for
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hydraulic fracturing in California are much lower at 0.49×106 to 0.79×106 L per well,39,15,40 than
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estimates from Texas, where Nicot and Scanlon (2012) reported a median of 10.6×106 L per well
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in 2010 for horizontal wells, and 4.5×106 L per well for vertical wells in the Barnett shale.11
Produced Water Intensity for Conventional Oil Production
Hydraulic Fracturing
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Recent studies indicate that HF volumes range from 1.5×106 L for vertical wells and about
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10×106 L for horizontal wells.11,12,41 In the Eagle Ford Shale, average water use is about 18×106
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L (water oil equivalent ratio of 1.4 in the oil zone and 0.6 in the gas zone) and is lower in the
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Bakken Shale (7.6×106 L per well [WOR of 0.4]).24 Water use for drilling and cementing wells
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is generally a small percentage of water used for HF, ~10% in the Texas Eagle Ford Shale. 24
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1.4
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The mixture of fracturing fluid combined with extracted O&G resources produced during early
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production (days to months) is commonly referred to as flowback water and is referred to as
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produced water from the formation during later stages of production.42 We do not distinguish
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between flowback and produced water and use the term flowback-produced water (FP). FP water
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can be treated for beneficial use, left in surface storage ponds or tanks, disposed of in UIC Class
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II injection wells, or recycled for additional HF. The rate at which FP water returns to the surface
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is highly dependent on the geology of the formation. The disposition of FP is also dependent on
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the formation. In the Marcellus Shale play, operators recycle ~95% of the FP water, whereas in
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the Barnett and Fayetteville plays, operators typically recycle
