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Projecting the Water Footprint Associated with Shale Resource Production: Eagle Ford Shale Case Study Svetlana Ikonnikova, Frank Male, Bridget R Scanlon, Robert C. Reedy, and Guinevere McDaid Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.7b03150 • Publication Date (Web): 25 Aug 2017 Downloaded from http://pubs.acs.org on September 2, 2017
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Projecting the Water Footprint Associated with Shale Resource Production: Eagle Ford Shale Case Study
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Svetlana A. Ikonnikova*ᵻ, Frank Male*, Bridget R. Scanlon*, Robert C. Reedy*, Guinevere McDaid*
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*
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Austin, TX 78713-8924
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ᵻ
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Abstract
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Production of oil from shale and tight reservoirs accounted for almost 50% of 2016 total U.S.
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production and is projected to continue growing. The objective of our analysis was to quantify the water
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outlook for future shale oil development using the Eagle Ford Shale as a case study. We developed a
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water outlook model that projects water use for hydraulic fracturing (HF) and flowback and produced
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water (FP) volumes based on expected energy prices; historical oil, natural gas, and water-production
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decline data per well; projected well spacing; and well economics. The number of wells projected to be
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drilled in the Eagle Ford through 2045 is almost linearly related to oil price, ranging from 20,000 wells at
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$30/barrel (bbl) oil to 97,000 wells at $100/bbl oil. Projected FP water volumes range from 20% to 40%
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of HF across the play. Our base reference oil price of $50/bbl would result in 40,000 additional wells and
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related HF of 265×109 gal and FP of 85×109 gal. The presented water outlooks for HF and FP water
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volumes can be used to assess future water sourcing and wastewater disposal or reuse, and to inform
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policy
The Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin,
Corresponding author:
[email protected] discussions.
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Introduction
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In 2016 shale-oil supply accounted for about half of U.S. crude oil production, with almost 5×106
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barrels/day (bbl/d); it is a critical part of the U.S. energy balance1. High oil prices led to intensive
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development of unconventional oil plays, including the Eagle Ford, Bakken, and Permian Basin. Each well
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requires several million gallons (1gal≈3.8L) of water for hydraulic fracturing (HF) and those volumes
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increase over time because of the lengthening of wells, higher proppant loads, and changes in
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completion technology2,3. A portion of HF water flows back together with the formation water (FP
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water), requiring recycling or disposal3. The increase in this “water footprint”—the term used here, as in
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previous studies, in a general way to refer to HF and FP water volumes3,4—gives rise to concerns
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regarding local water availability, FP water management, and potential infrastructure bottlenecks.
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Furthermore, the spatial variability in drilling intensity changes with energy prices; price-specific HF and
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FP water-outlook projections are required on an annual basis for each square mile of a play, rendering
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previous studies with multiyear period projections per county or play insufficient3,4,5. Improved
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granularity would help infrastructure planners identify local bottlenecks and develop timely solutions for
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water disposal. Regulators could address environmental, ecological, and economic concerns with a
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better understanding of how they may change over time with the market environment.
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The primary driver for shale resource production is energy prices: after a sharp increase, oil prices fell
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from ~$100/bbl in mid-2014 to ~$30/bbl in early 20166, as did the production in some plays, including
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the Eagle Ford and Bakken. Yet production in the economically more resilient Permian Basin continued
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to grow. Drilling depends on play economics and market environment, capturing the relationship
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between resource characteristics, production, economic attractiveness, and energy prices. Oil prices
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affect profitability of individual wells and thus the producer’s choice of drilling locations: at higher
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prices, drilling occurs over a wider geographic area, whereas at lower prices producers limit drilling to
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more productive and economically viable locations, possibly drilling fewer wells7,8. Each well location is
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characterized by different rock and fluid properties such as water saturation, pressure, and resource-in-
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place that affect productivity and completion-design choice. Previous studies offer a number of insights
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about spatial and temporal variability in per-well production and HF and FP water volumes2,5,9-11. While
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that knowledge about historical HF and FP water trends enables estimation of HF water demand and FP
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water volumes, lack of understanding of the link between resource-production dynamics and energy
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prices results in limited granularity in projections of year-to-year water use that would support water-
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management solutions.
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This study offers an approach to projecting the following on a square mile basis and depending on energy prices:
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individual well HF water volumes and their geographic distribution
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individual well FP water production over time
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intensity and geographic distribution of expected drilling
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These projections, combined over time and geographic play extent, allow us to build long-term water
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outlooks. We demonstrate the approach and its results using the Eagle Ford play data.
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Novel aspects of this study relative to previous projections11-13 include: consideration of variation in
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oil prices and their effect on the choice of well locations and drilling intensity; incorporation of geologic
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and petrophysical reservoir properties; use of a larger well population with HF water data and with
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longer histories of FP water volumes, together with the corresponding oil and natural gas production
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data; and employment of a production-decline model to project water, natural gas, and oil for each
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individual well. To the best of our knowledge, none of the publically available projections of shale
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resource production incorporates spatiotemporal variability in HF and FP water into a shale oil or gas, or
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water, outlook model. Studies of technically and economically recoverable oil resources14-21 lack details
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about HF and FP water volumes and expected drilling locations.
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The choice of the Eagle Ford play provides several advantages: about 7 years of data history, with
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energy prices changing from high to low; almost two-thirds of the play area with production data
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coverage; and water production from a reservoir with a wide range of thermal maturity from oil to gas.
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Hence, the methodology developed and tested in this study provides a template for similar analyses in
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other plays in the United States and globally.
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2. Materials and Methods
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2.1 Background Information
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Water is an integral part of shale oil and gas development, serving as a primary input for resource
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production. As reported by the Railroad Commission of Texas, about 100 wells were completed in the
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Eagle Ford play in 2009 and more than 4,000 in 201422. The oil-price drop in 2014 led to a slowdown in
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drilling: only ~2,800 wells were drilled in 2015 and ~2,000 in 2016, with drilling concentrated in the light
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oil window of the play, particularly in Karnes County, raising questions about a concomitant drop in HF
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water use and decline of FP water future dynamics in water footprint if high oil prices return.
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In shale formations, and in the Eagle Ford in particular, production of water as well as hydrocarbons
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varies with hydrocarbon-pore-volume (HPV), thermal maturity, water saturation, depth, and pressure.
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Previous studies also mention the importance of fluid properties, in particular viscosity, for well 3 ACS Paragon Plus Environment
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production16,23,24. Based on its geologic and reservoir characterization, the Eagle Ford play can be divided
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into three regions: the Maverick Basin to the west, the Eagleville region in the center, and the Karnes
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trough in the northeast. Stratigraphically, the Eagle Ford Formation is generally divided into Lower and
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Upper units, with the majority of wells completed in the Lower unit, which has a higher hydrocarbon-in-
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place density and represents the majority of the vertical interval. The Upper Eagle Ford thickness is 40 to
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20 ft outside the Maverick Basin, compared to 120–200 ft in the Lower Eagle Ford. The formation depth
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increases from northwest to southeast, ranging from 17,000 ft in the south,
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with associated pressure varying from 14,000 psi25. Reservoir maturity increases with
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depth, going from heavy oil, with API gravity of
