Article pubs.acs.org/EF
Energy Intensity and Greenhouse Gas Emissions from Tight Oil Production in the Bakken Formation Adam R. Brandt,*,† Tim Yeskoo,‡ Michael S. McNally,§ Kourosh Vafi,† Sonia Yeh,∥,¶ Hao Cai,⊥ and Michael Q. Wang⊥ †
Department of Energy Resources Engineering, Stanford University, Stanford, California 94305-2220, United States Department of Civil and Environmental Engineering, Stanford University, Stanford, California 94305-2220, United States § Kennedy School of Government, Harvard University, Cambridge, Massachusetts 02138, United States ∥ Institute of Transportation Studies, University of California, Davis, California 95616, United States ⊥ Systems Assessment Group, Energy Systems Division, Argonne National Laboratory, Argonne, Illinois 60439, United States ‡
S Supporting Information *
ABSTRACT: The Bakken formation has contributed to the recent rapid increase in U.S. oil production, reaching a peak production of >1.2 × 106 barrels per day in early 2015. In this study, we estimate the energy intensity and greenhouse gas (GHG) emissions from 7271 Bakken wells drilled from 2006 to 2013. We model energy use and emissions using the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) model, supplemented with an open-source drilling and fracturing model, GHGfrack. Overall well-to-refinery-gate (WTR) consumption of natural gas, diesel, and electricity represent 1.3%, 0.2%, and 0.005% of produced crude energy content, respectively. Fugitive emissions are modeled for a “typical” Bakken well using previously published results of atmospheric measurements. Flaring is a key driver of emissions: wells that flared in 2013 had a mean flaring rate that was ≈500 standard cubic feet per barrel or ≈14% of the energy content of the produced crude oil. Resulting production-weighted mean GHG emissions in 2013 were 10.2 g of CO2 equivalent GHGs per megajoule (henceforth, gCO2eq/MJ) of crude. Between-well variability gives a 5−95% range of 2−28 gCO2eq/MJ. If flaring is completely controlled, Bakken crude compares favorably to conventional U.S. crude oil, with 2013 emissions of 3.5 gCO2eq/MJ for nonflaring wells, compared to the U.S. mean of ≈8 gCO2eq/MJ. crude oil.7 A study by IHS CERA, using the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) model of Stanford University, found that Bakken crude oil emits 9.1 gCO2eq/MJ of crude oil produced.8,9 To put these figures in context, current “baseline” estimates of GHG intensity of U.S. mean crude oil is 7−8 gCO2eq/MJ, including imports.10,11 Prior studies have noted that Bakken crude’s emissions come primarily from flaring of associated gas, though little detailed analysis has been performed. Empirical scientific studies in the Bakken region are rare. One satellite-based remote sensing study found elevated methane emissions over the region encompassing the Bakken formation,12 while another found no such signal.13 Recent airborne sampling work suggests that nonsputtering flares in the Bakken have high methane destruction efficiencies of >99%.14 Other recent work has found, using airplane-based mass-balance modeling, that up to 6% of the methane produced in the Bakken is lost as fugitive emissions.15,16 In order to improve the understanding of Bakken crude oil GHG intensity, this paper collects data and models the energy intensity and GHG emissions of Bakken crude oil production. The system boundary is the same as OPGEE: emissions and energy use from primary exploration wells to the refinery
1. INTRODUCTION At the end of 2014, North Dakota produced over 1.2 × 106 barrels of crude oil per day (bbl/day),1 of which over 90% was from the Bakken formation.2 Bakken production requires large numbers of horizontal wells which are stimulated via highvolume hydraulic fracturing. The Bakken formation extends over parts of North Dakota, Montana, South Dakota, Saskatchewan, and Manitoba, but most development has occurred in the central Bakken region of North Dakota.3 The central Bakken formation lies 10 000−11 000 feet (ft) deep, although the edges of the basin are much shallower. Rapid development occurred until the recent oil price declines: a record high of ≈2400 wells were drilled in 2014.4 Bakken crude is typically produced from the more porous Middle Bakken and Three Forks strata, which lie between and below, respectively, the source rock strata of Upper and Lower Bakken shales.5 Little information exists about the greenhouse gas (GHG) impacts of oil production in the Bakken. Some work for the California Air Resources Board has examined the GHG intensity of Bakken crude oil, finding emissions on the order of 10.2 g of CO2 equivalent GHGs per megajoule (MJ), lower heating value basis (LHV) of crude oil produced (henceforth, gCO2eq/MJ and always LHV basis unless specified).6 Work by the United States Department of State has suggested that extraction of Bakken crude oil may be 20% more GHGintensive compared to the 2005 National Energy Technology Laboratory U.S. crude oil baseline, which includes imported © 2016 American Chemical Society
Received: August 3, 2016 Revised: October 19, 2016 Published: October 20, 2016 9613
DOI: 10.1021/acs.energyfuels.6b01907 Energy Fuels 2016, 30, 9613−9621
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Energy & Fuels
definition that includes both crude oil plus lease condensate. DMR statistics include gas production and disposition in units of raw produced gas (i.e., preprocessing volumes, not line specification gas volumes). Monthly operations data were collected from 2006 to 2013, inclusively. Monthly DMR production data were purchased and compiled for all wells in North Dakota, and non-Bakken wells were removed, leaving 7271 Bakken wells. See Tables S1−S3 for a detailed description of data sets. See Section S1.2 for the description of methods to separate Bakken wells and remove erroneous data. All data associated with a given well are compiled into a master SQL database that links properties of a well (e.g., production casing depth or volume of fracturing fluids) with production volumes and other monthly operating data. In cases where data are missing, a central estimate is applied across multiple wells. Such methods are applied to most data inputs for at least some of the wells, although generally, the proportion is small (e.g., 2840 wells were assumed to have mean fracturing water injection due to lack of data). See the Supporting Information for the number of default settings for each input parameter. In cases where a default is required, the following logic was used to choose an indicator value: • The production-weighted mean is used where an intensive quantity should not be averaged because of large differences in the denominator of the intensive measure (e.g., scf of gas per bbl of oil). • The mean is used in cases where an extensive measure is (by visual inspection) not highly skewed. • The median is assumed to be a better measure of typical behavior if the distribution (by visual inspection) is skewed. 2.1. Data and Modeling: Well Geometry, Well Drilling, and Well Stimulation. Casing diameters and lengths for each well were gathered from DMR data sets4,26 for various segments including conductor, surface casing, production casing, and laterals (up to 3 laterals). GHGfrack requires both the drilling total depth (DTD) and the true vertical depth (TVD); the TVD is rarely reported in DMR data sets. See the Supporting Information for methods to estimate TVD, including significant cross-checking and supplementation with public fracturing data set FracFocus.27 Reported DMR casing diameters are adjusted to the nearest API standard casing diameter28 if a nonstandard diameter is reported. The common well configuration assumed in all Bakken wells is shown in Figure 1. The distribution of well total depths is shown in Figure 2, showing early variability and a transition over time toward laterals of length ≈10 000 ft (note that since Bakken formation is ≈10 000 ft TVD, a well with a 10 000 ft lateral will have DTD of 20 000 ft).
entrance gate (henceforth, well-to-refinery or WTR). Coproducts (sold gas and LPG) are accounted for using coproduction displacement credits. Also included in the OPGEE model results is fuel cycle energy required to supply on-site consumed diesel and other energy products. This work began as part of an effort sponsored by the U.S. Department of Energy to estimate emissions from tight oil production and incorporate these improved estimates into the GREET model developed at Argonne National Laboratory.17,18 Because horizontal drilling and hydraulic fracturing of the Bakken constitute a new method of resource development, we perform significant extensions of prior OPGEE drilling modeling using the GHGfrack model, an open-source drilling and fracturing energy estimation tool.19 We also examine in detail the emissions from flaring on a well-by-well basis using a flaring efficiency model to estimate emissions of methane due to incomplete combustion in flares. We first outline the methods for collecting and analyzing data for wells in the Bakken formation. Then, we discuss modeling efforts to estimate energy use. We next describe methods of estimating lost associated gas to vented and fugitive emissions sources. In the Results section, we first illustrate and discuss results for the energy intensity of crude oil production in the Bakken. Finally, we present results of per-well productivities, per-barrel energy intensities, and GHG intensities.
2. METHODS OPGEE model version 1.1d20 is used to model emissions from oil and gas extraction in the Bakken. OPGEE is a engineering-based life cycle assessment model (LCA) that models energy use and emissions associated with oil production, including emissions from primary exploration up to delivery of crude oil to the refinery inlet gate.20,21 OPGEE takes in engineering and geologic data about a particular oil field and uses these to estimate the per-barrel or per-megajoule emissions associated with on-site energy use as well as energy use offsite required to provide energy to the site. The system boundaries of the analysis include all activities between drilling of wells to delivery of crude oil to refinery inlet and delivery of associated gas as pipeline-specification gas to long-distance transport pipelines. We include all direct energy consumption on site to drill wells, produce and/or lift fluids, process fluids, and transport fluids and gases to refineries or processing plants. Transport energy use includes local trucking as well as long-distance transport via pipeline or train. We do not include indirect energy consumed to manufacture and transport materials to the drilling site. We include directly reported flaring rates to compute emissions from flared associated gas. Prior work has explored uncertainty in OPGEE estimates, finding that only a small number of input parameters are of primary importance in driving emissions and that uncertainty in examining a “basket” of crudes is much smaller than examining a single crude.22−24 The excellent data availability in the Bakken is likely to lead to reasonable uncertainty ranges (see additional discussion below). Data specific to Bakken geology and drilling engineering were collected from the regulatory and technical literature. Key sources include the North Dakota Department of Mineral Resources (DMR) and Society of Petroleum Engineers (SPE) publications. OPGEE uses geologic data such as depth, pressure, and formation productivity, as well as engineering data such as well geometry, lifting technology, and processing configuration. Energy requirements to drill wells are estimated using the GHGfrack model.19 This model estimates the fuel requirements of mud circulation, drill string rotation, and pumping of hydraulic fracturing fluids. After initializing geologic and engineering data are gathered, OPGEE is used to estimate monthly operating emissions associated with producing and processing of crude oils. In this case, each well was assessed separately using monthly public production statistics from DMR.1,4,25,26 All DMR statistics used here report “crude oil” with a
Figure 1. Bakken well diagram with key depth markers listed. 9614
DOI: 10.1021/acs.energyfuels.6b01907 Energy Fuels 2016, 30, 9613−9621
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the largest unique value found consistently for the same well in both data sets). If no data are available in either data set, the mean value of 2.6 × 106 gal/well is used (for 2840 wells). Water use per well is plotted in Figure 3a. Sand (proppant) consumption generally scales with water consumption, so outliers in sand/water ratio were reassigned sand quantities using the mean sand/water ratio of 1.07 lb/gal and reported water injection rate. Sand use is plotted in Figure 3b. The injection pressure for fracturing is computed from well TVD and mean Bakken fracturing gradient (0.78 psi/ft; see the Supporting Information for details). GHGfrack considers wellbore friction during injection, including dynamic lateral length in multistage fracturing. The GHGfrack friction model was found to agree well with commercial pipe flow simulators.19 See S1.4 for more details. In order to account for land use efficiency of multiwell pads, the OPGEE land use calculations are set to the minimum land use disturbance setting. Future work using GIS analysis, while considered beyond the scope of this paper, could examine in more detail the land disturbed per unit of oil production. 2.2. Data and Modeling: Properties and Volumes of Produced Fluids. After the well fracturing is completed, “flowback” occurs. Flowback of injected hydraulic fracturing fluids, primarily water and sand, occurs during the initial days to weeks of production, gradually transitioning to flow of oil and gas. Gas produced during flowback can cause GHG emissions if vented to the atmosphere.28−30 Data reported to the U.S. EPA GHGRP and analyzed by the Environmental Defense Fund suggests that flowback gases in the Bakken are flared,37 so we assume similarly here. Additional discussion of justification of flowback assumptions is given in the Supporting Information. A common approach to modeling flowback volumes is to scale initial production volumes by a correction factor to account for the first days of flared production. Prior studies calculate ranges from 3 to 4.5 days equivalent of initial production28,30,37 (see the Supporting Information for more discussion). In order to model gas flowback in Bakken, we take initial production test (IPT) gas volumes25 for 5505 wells and scale them to 3 days of equivalent IPT production. One outlier was removed: it was 50 times larger than the next largest observation and would have resulted in flaring of millions of dollars of gas (considered a likely database error). Note that our method based on IPT flow rates results in larger flowback volumes than scaling the first months production rate, which was done in prior studies.28,30 This is because fluid production declines rapidly from Bakken wells, so IPT volumes on a per-day basis are larger than the well’s first month production divided by the number of operating days in the first month. Nevertheless, the resulting flowback volumes are small when pro-rated over the life of
Figure 2. Drilling total depth for wells in database as a function of time. Most wells have TVD of 10 000 ft, so DTD less than 10 000 ft is the approximate lateral length. Before Jan. 2007, a mix of lateral lengths prevailed. Between Jan. 2007 and Jan. 2010, roughly equal numbers of wells with 5000 ft laterals (DTD ∼ 15 000) and 10 000 ft laterals (DTD ∼ 20 000) existed. After 2010, most new wells had a lateral length of 10 000 ft (DTD ∼ 20 000). Bakken-specific values for drilling input parameters are derived from engineering literature. Drilling is assumed to be performed with a combination of top-drive and mud motor, with typical bit rotation speeds of 200−275 rpm.20,21 The rate of penetration (ROP) is assumed in GHGfrack to be 110 ft/h (literature range is between 50 and 220 ft/h) in the vertical sections and 80 ft/h (range 40−120) in the horizontal segments.29−32 Torque is lower in the vertical segment (9000 ft-lb, range 8000−10 000) than the horizontal segment (12 000 ft-lb, range 9000−13 000).31,33−35 The mud motor is powered by high mud flow rates of hundreds of gallons (gal) per minute (vertical: 200 gal per min, range 150−400; horizontal: 500 gal per min, range 420− 550) and a large pressure drop (vertical: 500 psi, range 450−550; horizontal: 700 psi, range 400−1200).31,36 Hydraulic fracturing is modeled using GHGfrack, assuming that all fracturing fluid is injected at the mean Bakken fracturing gradient given the computed TVD for that well. The energy required to inject fracturing fluids in the Bakken is typically more than the energy requirement to drill a well.19 Volumes of water and mass of proppant sand are gathered from DMR and FracFocus data sets.26,27 Where water volumes are reported from both datsets, we use the larger of the two data sets to be conservative. If the larger reported volume is above 20 × 106 gal/well, we use the smaller of the two values (20 × 106 gal is
Figure 3. Distribution of (a) water use and (b) proppant in hydraulic fracturing. Water consumption values represent one-time consumption during initial fracturing and are not indicative of ongoing operating water intensity. See above for methods of computation of average value and removal of outliers. Some values are to the right of the edge of the plot. 9615
DOI: 10.1021/acs.energyfuels.6b01907 Energy Fuels 2016, 30, 9613−9621
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Energy & Fuels Table 1. Well Property Input Data Summary property
median
mean
std. dev.
units
API gravity true vertical depth (TVD) drilling total depth (DTD) fracturing gradient fracturing pressure fracturing sand consumption (one-time) fracturing water consumption (one-time)
41.90 10 533 20 154 0.79 8315 2 533 560 2 280 096
41.93 10 352 19 397 0.79 8149 2 598 586 2 615 134
2.05 806 2141 0.23 2519 1 559 650 1 816 970
[deg. API] [ft] [ft] [psi/ft] [psi] [lb] [gal]
the field and have little impact on overall GHG emissions: median flowback volume is 7 standard cubic feet per barrel (scf/bbl) of estimated ultimate recovery (EUR), and the mean is 15 scf/bbl EUR (compared to the mean of ≈500 scf/bbl for wells that flare). See S1.9 for more information. The API gravity of associated crude oil was reported for 5349 wells. Wells with multiple API tests were averaged after converting to specific gravity. The mean of all observations is applied to those wells with no API gravity tests reported (1922 wells). See S1.6 for more information and plotted API gravity distributions. The produced gas composition is only reported for ≈700 wells in the Bakken. Because this is
