Article pubs.acs.org/est
Evaluating the Climate Benefits of CO2‑Enhanced Oil Recovery Using Life Cycle Analysis Gregory Cooney* Associate, Booz Allen Hamilton, 651 Holiday Drive, Foster Plaza 5, Suite 300, Pittsburgh, Pennsylvania 15220, United States
James Littlefield Associate, Booz Allen Hamilton, 651 Holiday Drive, Foster Plaza 5, Suite 300, Pittsburgh, Pennsylvania 15220, United States
Joe Marriott Lead Associate, Booz Allen Hamilton, 651 Holiday Drive, Foster Plaza 5, Suite 300, Pittsburgh, Pennsylvania 15220, United States
Timothy J. Skone Senior Environmental Engineer, National Energy Technology Laboratory, 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, Pennsylvania 15236, United States S Supporting Information *
ABSTRACT: This study uses life cycle analysis (LCA) to evaluate the greenhouse gas (GHG) performance of carbon dioxide (CO2) enhanced oil recovery (EOR) systems. A detailed gate-to-gate LCA model of EOR was developed and incorporated into a cradle-to-grave boundary with a functional unit of 1 MJ of combusted gasoline. The cradle-to-grave model includes two sources of CO2: natural domes and anthropogenic (fossil power equipped with carbon capture). A critical parameter is the crude recovery ratio, which describes how much crude is recovered for a fixed amount of purchased CO2. When CO2 is sourced from a natural dome, increasing the crude recovery ratio decreases emissions, the opposite is true for anthropogenic CO2. When the CO2 is sourced from a power plant, the electricity coproduct is assumed to displace existing power. With anthropogenic CO2, increasing the crude recovery ratio reduces the amount of CO2 required, thereby reducing the amount of power displaced and the corresponding credit. Only the anthropogenic EOR cases result in emissions lower than conventionally produced crude. This is not specific to EOR, rather the fact that carbon-intensive electricity is being displaced with captured electricity, and the fuel produced from that system receives a credit for this displacement.
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INTRODUCTION
The application of CO2-EOR has been growing steadily over the past decade. In 2012, CO2-EOR accounted for 41% of total U.S. EOR crude production, compared to 25% in 2000.2 Total U.S. EOR production in 2013 totaled 276 thousand barrels per day (3.6% of U.S. total domestic production and 1.8% of total U.S. crude consumption).3 Almost two-thirds of EOR crude production occurs in the Permian Basin of West Texas, with the remainder split between the Rocky Mountain, Gulf Coast, and
Enhanced oil recovery (EOR) is a generic term for tertiary crude recovery techniques that increase the amount of crude that can be extracted from a given field. EOR techniques increase the recovery of crude through the use of heat, chemicals, or solvents and are utilized after primary (utilization of underground pressure to produce oil to the surface via natural drive and artificial lift) and secondary (gas/water flooding to maintain reservoir pressure) techniques have already been deployed. For this analysis, EOR refers to a specific technique that injects carbon dioxide (CO2) into the well to improve the recoverability of crude oil by reducing viscosity, swelling crude oil, and lowering interfacial tension.1 © 2015 American Chemical Society
Received: Revised: Accepted: Published: 7491
February 9, 2015 May 14, 2015 May 20, 2015 May 20, 2015 DOI: 10.1021/acs.est.5b00700 Environ. Sci. Technol. 2015, 49, 7491−7500
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Environmental Science & Technology
Figure 1. LCA System Boundaries for Evaluating EOR.
Mid-Continent regions.4 EOR production is projected to grow at an average annual rate of 3.5% to 740 thousand barrels per day by 2040, representing 10% of U.S. total domestic production and 4.9% of U.S. total crude consumption.3 The primary function of EOR is the recovery of additional crude from a formation; however, EOR also sequesters CO2 in the process with potential climate benefits.5,6 CO2 is an effective fluid for EOR, because it is miscible in oil−it mixes with oil and brings it to the surface. The injection of CO2 is often alternated with the injection of brine in a wateralternating-gas (WAG) tertiary injection scheme, to prevent the undesired channeling of CO2, which can result in bypassing the stored oil.7 The formation sequesters a fraction of the injected CO2 and produces a mixture of brine, crude oil, light hydrocarbons, known as natural gas liquid (NGL), and the remainder of the CO2 that is not sequestered. The portion of CO2 that is not sequestered is processed along with the other products and is reinjected into the well with additional makeup CO2 from a pipeline. The combined production stream is processed above ground to separate gas, water, and crude. The resulting gas mixture can be processed by various methods to separate NGLs from CO2. The sequestration of CO2 in the process of recovering crude oil has focused attention on EOR as a potential component of a national greenhouse gas (GHG) emission reduction strategy. Historically, approximately 90% of EOR production in the U.S. utilized natural sources of CO2.8 The use of anthropogenic CO2 for EOR would be necessary to realize a climate benefit based on the sequestration of that CO2. Although CO2 for EOR can be sourced from many anthropogenic sources, including natural gas processing and ammonia production, the greatest near-term opportunity for CO2 capture from power plants is postcombustion capture.9,10 Postcombustion technologies use chemical solvents to remove CO2 from flue gas and can be
applied to new or existing coal- or natural gas-fired power plants. This analysis will focus on CO2 that is sourced from natural domes and postcombustion capture at greenfield fossil fuel power plants. The potential life cycle impacts of EOR have been examined in the literature. Suebsiri et al. examined the production of EOR crude from the Weyburn unit in Saskatchewan, Canada.11 Khoo and Tan investigated four methods for CO2 capture from a pulverized coal power plant along with various methods for sequestration, including EOR in the North Sea oil fields.12 Jaramillo et al. examined the connection of an IGCC power plant with EOR operations in five particular fields in North America.13 Hussain et al. evaluated various sources of CO2 for EOR, including anthropogenic and biogenic sources.14 Some of the studies have incomplete boundaries and do not account for the upstream acquisition emissions associated with the CO2, while others rely on an aggregated estimate for the emissions that occur as part of the actual EOR operations. Most of the studies focus on anthropogenic sources of CO2, which is not representative of current operations which rely primarily on CO2 produced from a natural dome. All of the studies assume that the EOR process is much more efficient than average U.S. operations indicate. The efficiency of the EOR process is defined as barrels of produced crude per tonne of CO2 sequestered (i.e., tonne of CO2 purchased as makeup). This paper will illustrate that the value assumed for this parameter is key in determining the life cycle results for the EOR supply chain. Jaramillio et al.13 assumed a range of 4.6−6.5 bbl/tonne over various EOR projects studied, while Hussain et al.14 referenced the same source model and used a default value of 4.6 bbl/tonne, combined with a range of 4.2−6.5 bbl/tonne for sensitivity analysis. Recent production data suggests that these recovery ratios are too high to represent U.S. national average production. In 2013, crude recovery ranged from a low of 7492
DOI: 10.1021/acs.est.5b00700 Environ. Sci. Technol. 2015, 49, 7491−7500
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The final set of boundaries is further expanded to include anthropogenic sources of CO2 and the steps associated with transporting the crude to a refinery, refining it to finished gasoline, and combusting the gasoline. The functional unit for this cradle-to-grave boundary is 1 MJ of combusted gasoline. The choice of gasoline as the finished fuel was made for the purposes of calculating the impacts downstream from crude production; the conclusions would hold true if the functional unit was diesel or jet fuel. NETL has detailed life cycle models for the CO2 sources, crude oil transport, crude oil refining, and fuel combustion processes, illustrated in Figure 1.10,17−21 The total carbon dioxide equivalents (CO2e) was calculated using 100-year global warming potentials (GWP), with CH4 having a GWP that is 36 times greater than CO2 as prescribed by IPCC’s Fifth Assessment Report (AR5).22
0.73 bbl/tonne in the Gulf Coast to a high of 2.68 bbl/tonne in the Mid-Continent; yielding a weighted average recovery of approximately 2 bbl/tonne for the entire U.S.4 This value is similar to the crude recovery calculated for 2010 from different data sources (see the SI for more information) as should be expected since total EOR crude production was relatively flat between 2010 and 2013.8,15 This analysis includes two scenarios for the crude recovery ratio: 2 bbl/tonne CO2 is used to represent current operations in the U.S., whereas 4.35 is used to represent advanced EOR based on the implementation of best practices.7 Further, this analysis builds upon existing work by modeling the process level impacts of EOR through the creation of a bottom-up, engineering-based gate-to-gate model inclusive of CO2 injection through gas processing and crude production that is combined with predictive reservoir modeling results produced by the National Energy Technology Laboratory (NETL).7,16 The gate-to-gate model allows for the identification of key processes and parameters that contribute to the emissions for the EOR process as well as the examination of alternative gas processing technologies. That model is incorporated into a larger cradle-to-grave system that examines the impacts of various sources of CO2, including current natural dome operations, the implications of coproduct management, and the crude production efficiency on the resulting life cycle GHG emissions.
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MATERIALS AND METHODS The gate-to-gate analysis models the following EOR activities: (1) injection and recovery (2) bulk separation and storage, including gas/liquid separation, crude oil storage, and brine water storage and injection (3) gas separation via four different processing schemes (4) supporting processes, including venting and flaring and gas combustion for process heat (5) land use The expansion of the boundaries for the larger cradle-to-grave system includes the following activities in addition to those listed above: (6) source and transport of CO2 to the EOR site (7) transport of the produced crude to a refinery (8) refining of the crude to produce gasoline (9) transport of the refined gasoline to the end user (10) gasoline combustion The cradle-to-gate boundary for extracted crude comparison includes activities 1−6. Each of the main activities are discussed below. A more detailed discussion is available in the SI. Sources of CO2. As shown in Figure 1, there are two main sources of CO2 that are evaluated in this analysis: natural and anthropogenic. Geologic formations with naturally occurring CO2 are the predominant source of natural CO2 utilized for EOR. Anthropogenic sources include industrial processes and future power plants with carbon capture systems that have concentrated CO2 streams. This analysis considers future power plants with carbon capture given the potential supply of CO2 that those systems would make available for EOR. Natural CO2 domes are reservoirs that contain high-purity CO2. Existing CO2 domes include McElmo, Sheep Mountain, Jackson, and Bravo domes. These four domes account for over 95% of current natural CO2 extraction in the U.S.8 The data for natural CO2 domes are based on an environmental impact statement by Kinder Morgan for four CO2 extraction sites in Colorado.23 The greatest near-term opportunity for CO2 capture from power plants is postcombustion capture.9 Postcombustion technologies use chemical solvents to remove CO2 from flue gas and can be applied to new or existing coal- or natural gasfired power plants once the technology is commercially demonstrated. This analysis includes scenarios for carbon capture from supercritical pulverized coal (SCPC) and natural gas combined cycle (NGCC) power plants as detailed in NETL’s baseline study for advanced power plants.24 Details
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SYSTEM BOUNDARY AND FUNCTIONAL UNIT This study uses life cycle analysis (LCA) to evaluate the GHG performance of EOR systems, allowing the identification of key contributors to system burdens and opportunities for improvement. Figure 1 illustrates the three different boundaries examined in this study. EOR is just one piece of a complex system with multiple pathways and products. EOR can utilize different sources of CO2, such as natural dome and captured fossil power, and several petroleum products can be derived from EOR crude. The intermediate and final products from the EOR life cycle include captured CO2, crude oil, finished fuels, and electricity. The first boundary is drawn around the EOR facility and is referred to as a gate-to-gate analysis. This system does not consider the impacts associated with the source of the CO2 or the use of the produced crude. The inputs to the system are CO2 and energy (natural gas and electricity). This system produces two products: crude oil and NGLs. While limited in scope, the choice of this boundary allows for the closer inspection of the most important processes associated with EOR. The analysis of the gate-to-gate system points to key environmental drivers specific to the EOR process. The single box representing EOR in Figure 1 is actually a collection of unit processes that account for all of the operations from injection of CO2 through production of crude ready for pipeline transport. All of these processes are shown in Supporting Information (SI) Figure SI-1. The model consists of parameters that can be tuned to represent different operations. The functional unit for this boundary is 1 barrel of produced crude. The second set of boundaries expands upon the first set to include the source of CO2 (natural dome) and transport to the EOR site. This cradle-to-gate boundary allows for the comparison of EOR crude with other methods of extraction. The functional unit for this cradle-to-gate boundary is 1 barrel of produced crude. 7493
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gates the undesired channeling of CO2, which can result in bypassing the stored oil. The formation sequesters some fraction of the injected CO2 as it displaces the brine and crude oil present in reservoir. The EOR process is a net producer of brine as shown in SI Table SI-2. The produced brine is usually sent to nearby EOR sites for further use. Artificial fluid lifting is often required for EOR wells to yield production levels that are economical.7 It is assumed that a maximum of one percent of the stored CO2 eventually migrates to the surface and is released to the atmosphere over a 100-year monitoring period. This conservative assumption is consistent with other NETL reports on carbon capture and storage and is used to bracket the current range of potential loss until measurement data from operating storage sites can validate this loss factor.21 There is no measured data to currently support an expected migration of 1.0% of the CO2 to the atmosphere. In our model, a 0% loss rate is equally probable. Geologic formations with a potential loss rate greater than 1% would be considered infeasible for CO2-EOR operations. The expected parameter value for the model (0.5%) was selected as the midpoint between the maximum leakage rate of 1% and no leakage from the formation.21 Bulk Separation and Storage. The production wells at an EOR site yield a mixture of crude oil, brine, and gas. These products must be separated to produce marketable crude, brine that can be reinjected into the formation, and gas that can be sent to CO2 removal and hydrocarbon processing. Volatile organic compounds (VOC) are released due to pressure changes, including flashing operations and loading of streams into separation and storage vessels. VOC emissions are recovered and may be flared or released to the atmosphere, depending on the use and efficiency of emission-control equipment. Crude oil is stored in tanks at EOR sites. The flashing and working losses of crude oil storage tanks result in VOC emissions that are recovered and sent to venting or flaring. CO2 is entrained in the crude oil produced by EOR, but the series of liquid and gas separation processes that immediately follow crude oil extraction are designed to remove CO2 and other gases. EOR operators pay for makeup CO2, so there is an economic case for recovering CO2 from the crude oil product stream. This analysis assumed a negligible amount of CO2 in the produced crude oil. Gas Separation. Gas separation is necessary for EOR operations, because it recovers CO2 that can be reinjected in the EOR flood and separates hydrocarbon streams that can be sold or used as plant fuel. The NETL EOR life cycle model accounts for four different gas processing technologies: (1) refrigeration, (2) refrigeration with fractionation, (3) RyanHolmes, and (4) membrane. The choice of technology is driven by site-specific parameters including the composition of the produced gas, the desired purity of CO2 for injection into the formation, and the economics associated with recovering the NGLs. These different processes are discussed in the SI. Supporting Processes. The supporting processes at the EOR site include the venting and flaring of recovered vapor and the combustion of gas streams for the generation of process heat. Venting is necessary for the safe release of gas that builds up in a system. Flaring is the combustion of vented gas and converts hydrocarbons to CO2. Flaring reduces the environmental impacts of vented gas. The flaring of methane converts it to CO2, which has a lower GWP than methane. Natural gas is
regarding the design and operations of these plants are included in the SI. CO2 Transport. CO2 for use in EOR must be compressed to supercritical conditions and delivered to the end user via pipeline. The power plant models evaluated in this analysis include compression within the plant battery limits. However, additional compression is required for the natural sources of CO2. Data for the compression of CO2 to pipeline pressure are based on compression equations developed by the Institute of Transportation Studies at the University of California Davis25 and emission factors that account for gas losses through compressor seals.26 The model also accounts for boost compression along the pipeline to maintain the CO2 at supercritical conditions and for fugitive emissions from the pipelines. Data for emissions from pipelines are based on methane emissions from natural gas pipelines, adjusted according to the physical properties of CO2 in comparison to natural gas.27 The model also accounts for emissions that result from the venting of pipeline sections to support regular inspection or pigging. EOR Reservoir Modeling. The key data source of this analysis is An Assessment of Gate-to-Gate Environmental Life Cycle Performance of Water-Alternating-Gas CO2-Enhanced Oil Recovery in the Permian Basin, published by NETL in 2010.7 All variables that directly affect the performance of an EOR site are based on this data source and are representative of EOR facilities in the Permian Basin of West Texas. These variables include geological characteristics, crude properties, and operating practices; they are discussed in depth in the SI. The EOR efficiency is a function of all of these parameters and can be expressed in terms of barrels of produced crude per tonne of CO2 sequestered. This analysis includes two scenarios for the crude recovery ratio: 2 bbl/tonne CO2 is used to represent current operations, while 4.35 is used to represent advanced EOR.4,7 The oil recovery and CO2 sequestration rates are based on outputs of the CO2 Prophet model, a model developed by oil field experts for the Department of Energy (DOE).7 This analysis does not attempt to recreate the Prophet simulations, but rather uses only the sequestration and production rates already calculated by Prophet. Variables such as formation depth, thickness, pore volume, well drilling pattern, and injection pressure are not used in this analysis; instead, they are embedded in the overall CO2 sequestration and crude oil recovery rates. Properties of the produced crude and NGLs are provided in the SI. CO2 and Brine Injection. The CO2 injection pressure is an important operating parameter that affects the performance of an EOR site and must be controlled to avoid fracturing the geological formations that confine the oil bearing reservoir.7 For current practices, the CO2 injection pressure is 1800 psig.28 The injected CO2 stream is a combination of makeup CO2 from a pipeline and recycled CO2 from the gas processing plant. Makeup CO2 is purchased to replace CO2 that is sequestered in the formation. At pipeline conditions, liquid CO2 forms at a pressure of 1,070 psig. The pipeline pressure is maintained above this critical point to ensure that all CO2 remains in the liquid state. Recycle CO2 from the gas plant is assumed to be at a pressure of 50 psig. Both streams need to be compressed/pumped to the required injection pressure of 1800 psig at the wellhead. The injection of CO2 is often alternated with brine in a water-alternating-gas injection scheme.7 Brine injection miti7494
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Table 1. Key EOR Modeling Parameters; Low and High Values Are Based on Life Cycle GHG Emissions, Not the Magnitude of the Individual Parametera EOR parameter
low
expected
high
crude recovery ratio CO2 injection pressure CO2 sequestration loss rate electricity mix for EOR operations electricity displacement mix and LC GHG emission factor
advanced EOR: 4.35 bbl/tonne CO2 1400 psig 0.0% 2013 U.S. Mix (611 CO2e/kWh)
N/A 1800 psig 0.5% ERCOT Mix (650 g CO2e/kWh)
current EOR: 2 bbl/tonne CO2 2200 psig 1.0% gas turbine, simple cycle (746 g CO2e/kWh)
fleet coal power (1123 g CO2e/kWh)
2013 U.S. Mix (611 CO2e/kWh)
AEO 2040 U.S. Mix (593 g CO2e/kWh)
a
For example, crude recovery ratio has an inverse releationship with GHG emissions, thus the low value in the table is actually the high value of the parameter.
impossible to compare the studied system to alternative systems that produce the same products, but in different proportions. A solution is to draw boundaries so only one product, the functional unit, exits the system. This can be accomplished by including processes that consume coproducts or by assuming that coproducts displace alternative production routes. Allocation is an alternative to system expansion and uses a physical or economic basis for apportioning burdens. For example, if all products can be expressed in terms of energy, the fraction of environmental burdens allocated to a particular product is equal to the product’s share of the total energy of all coproducts. This analysis has two instances of coproduction. The EOR facility coproduces crude and NGLs, which is an example of similar coproducts from a single facility. In contrast, when CO2 is captured at power plants and used for EOR, electricity is produced at the power plant and liquid fuel is produced downstream from the EOR facility, which is an example of disparate products exiting at different points of connected supply chains. These two instances of coproduction require different coproduct management methods. Allocation is appropriate for managing the coproduction of crude oil and NGLs by an EOR facility. Mass allocation was chosen as the allocation method for crude oil and NGLs. Energy allocation could be a more appropriate basis; however, crude and NGLs have potentially different end uses (fuels versus chemical feedstock). Managing the coproduction of electricity and liquid fuel is not as straightforward as allocating between crude oil and NGL. Allocation cannot be used to split burdens between electricity and captured CO2 at the power plant boundary, because there is not a physical basis for comparing electrical energy to a mass of CO2. Energy can be used as a basis for allocating between the electricity and liquid fuel that exit boundary of the entire system. However, doing so requires a comparison of two forms of energy−electricity and heat of combusted fuel (e.g., gasoline). Further, a MJ of electricity accounts for the efficiency losses of power generation, while, within the boundaries of this analysis, one MJ of combustion heat does not account for the efficiency of converting heat to useful work. Since a MJ of electricity and a MJ of heat from combusted fuel are not providing equivalent services, it is hard to defend the use of energy allocation in this case. In this analysis, the system boundaries can be expanded to encompass electricity, which is then accounted for within the boundary via the displacement of similar electricity. This analysis expands the boundaries of the system to include displacement of conventional power production. With displacement, the functional unit receives a credit for the GHGs emitted by the electricity production that it displaces. This
combusted to produce heat used by oil/water separation vessels and separation column reboilers. The air emissions for natural gas combustion are based on the Environmental Protection Agency’s (EPA) emission factors.29 Land Use. The land use metrics used for this analysis quantify the land area that is transformed from its original state due to production of crude oil, including supporting facilities. The transformation of land causes the direct emission of GHG emissions due to changes in above-ground biomass and soil carbon. There are a total of 20 wells modeled for the entire EOR facility based on 1 injection well and 1 production well per pattern and 10 patterns per EOR facility.7 Each well has a footprint of approximately 2.5 acres.19,30 The gas processing facility has a footprint of 20 acres. GHG emissions due to land use change were evaluated based upon the U.S. EPA’s method for the quantification of GHG emissions, in support of the Renewable Fuel Standards.31 There is additional information on the land use method and modeling assumptions in the SI. Crude Transport, Petroleum Refining, Fuel Transport, and Combustion. This analysis uses NETL’s petroleum baseline model to account for the GHG emissions associated with crude transport, petroleum refining, finished fuel transport, and gasoline combustion.20 The final stage of this analysis is the combustion of fuel in a vehicle, which is estimated using a conventional internal combustion engine in a passenger vehicle to represent gasoline combustion. This analysis uses the combustion of a 1 MJ of fuel as the basis for comparison. Ancillary Process Inputs. This life cycle model uses existing NETL unit processes and models for all ancillary inputs and activities that feed into the EOR system. Examples include coal mining, natural gas extraction, and conventional fuels production.20,30,32 Coproduct Management. The objective of LCA is to assign ownership of environmental burdens to a single function. When more than one product exits the system boundary of an LCA, it is necessary to redefine the system boundaries or apply an assignment that splits life cycle burdens between products. ISO 14040 states that inputs and outputs shall be apportioned to the different coproducts using process disaggregation, system expansion, or allocation, in that order of preference.33 ISO’s recommendations encourage the avoidance of coproducts, which is why disaggregation and system expansion are recommended before allocation. Process disaggregation is not feasible for this system because the coproducts are produced side-by-side, using the same equipment and other resources, making it impractical to apply a partitioning scheme. The remaining two coproduction management methods are system expansion and allocation. System expansion alters system boundaries to include all coproducts. The challenge with this approach is that it becomes 7495
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Figure 2. Gate-to-Gate Ryan Holmes Gas Processing Life Cycle GHG Emissions for current EOR operations (crude recovery equal to 2.0 bbl/tonne CO2) with Uncertainty Tornado Diagram Inset; The total uncertainty shown for the four most sensitive parameters in the inset figure will not sum to the total uncertainty in the total bar since the sensitivity of the parameters was determined by adjusting them one-at-a-time. There are additive effects, which result in a slightly higher total uncertainty.
the displacement factors for coproduced electricity when captured fossil power is used as the source of CO2 in the cradle-to-grave system. The low and high bounds for these parameters contribute to the low and high bounds shown by the life cycle GHG results. More details on the development and use of parameters to represent the EOR facility and the upstream sources of CO2 are provided in the SI.
analysis assumes 100% displacement of electricity, meaning that each new MWh produced displaces an existing MWh. This assumption is bolstered by three observations (1) the demand for electricity is highly inelastic, (2) no large-scale electricity storage options currently exist, and (3) electricity cannot be traded over long distances (i.e., overseas). The source of the existing MWh that is displaced is unknown, so various options (fleet coal, 2013 U.S. grid mix, EIA Annual Energy Outlook 2040 U.S. grid mix) are modeled to provide a range of displacement values. The corresponding GHG displacement values for these options are shown in Table 1. The data sources for the life cycle emissions of the different electricity displacement options are based on a series of reports published by NETL.19,32,34−39 Parameters and Uncertainty. The model has adjustable parameters that allow the use of a consistent framework for modeling multiple scenarios and evaluating the sensitivity of results to changes in variables. It also allows the use of low and high parameter values to ascribe uncertainty ranges. Table 1 provides the key parameters for the EOR operations as well as
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RESULTS AND DISCUSSION Gate-to-Gate Detailed EOR Model. The results of the gate-to-gate model indicate the source and species of emissions, suggesting potential opportunities for reductions. Four different gas processing technologies were modeled to determine the impact on gate-to-gate emissions. The results in Figure 2 are for crude oil produced from an EOR site using the Ryan-Holmes gas processing technology with a crude recovery of 2.0 bbl/ tonne CO2 (corresponding parameter values are included in SI Tables SI-1, -2, and -3) and are on a gate-to-gate basis, meaning that they do not account for the source of the CO2 or the use of the produced crude oil. For advanced EOR, the gate-to-gate 7496
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Figure 3. Cradle-to-grave comparison of life cycle GHG emissions for EOR crude produced utilizing either natural or anthropogenic sources of CO2 with conventionally produced crude on the basis of 1 MJ of combusted gasoline. Current EOR represents a crude recovery of 2.0 bbl/tonne CO2; Advanced represents 4.35 bbl/tonne CO2.
Cradle-to-Gate Extracted Crude Comparison. With the detailed gate-to-gate EOR extraction model complete, the emissions associated with the extraction of crude via EOR can be compared to the emissions associated with other extraction methods and sources. The boundary for EOR crude extraction must be expanded upstream to account for the source of the CO2 to allow for a fair comparison of different crudes (this is represented by boundary set 2 in Figure 1). For this cradle-togate analysis, CO2 from a natural dome was selected, because it simplifies the system (no upstream coproducts to manage) and represents the current method of sourcing CO2. The corresponding parameter values for these scenarios are included in SI Tables SI-1, -2, -3, -5, and -6. Figure SI-19 shows a comparison of crude produced via EOR to other sources of crude oil consumed in the U.S. Crude extraction via EOR with Ryan-Holmes gas processing is more GHG-intensive than the majority of crudes imported by the U.S. Advanced EOR has lower extraction emissions than conventional EOR (91 vs 160 kg CO2e/bbl), because more crude is recovered per unit of CO2 injected; however, both are considerably higher than the U.S. consumption mix (39 kg CO2e/bbl). Conventional EOR has the highest cradle-to-gate emissions of any crude evaluated (higher than Canadian Oil Sands and Venezuelan Bitumen). As crude extraction moves from primary (artificial lift) to secondary (reservoir pressure maintenance) and, finally, to tertiary methods (chemical or thermal means to initiate flow), the amount of energy required per barrel recovered increases, thereby increasing the associated GHG emissions. The majority of crudes imported by the U.S. are produced via primary or secondary methods, whereas EOR is a tertiary form of crude recovery. Note that the crudes imported by the U.S. are of disparate quality. This means that the expected product slate and refining life cycle contributions would be different for each crude. The comparison of extraction emissions alone does not encompass the true life cycle GHG emissions differences between the
results are 76.8 kg CO2e/barrel, approximately 40% less than for current operations. As shown in Figure 2, the emissions associated with electricity for CO2 injection compressor, crude oil artificial lift pump, and gas processing compose the majority of gate-to-gate GHG emissions at over 90%. Other significant contributors include venting and flaring activities during oil, gas, and water separation, and natural gas combustion. The uncertainty in the total gate-to-gate GHG emissions is driven by four main factors as shown by the inset to Figure 2: crude recovery per tonne of CO2 sequestered, required formation injection pressure, makeup of electricity grid, and leakage from the formation. As shown, the crude recovery ratio is the most significant parameter when considering the gate-to-gate emissions for EOR. The four different gas processing options at the EOR facility affect the energy requirements, combustion emissions, and volumes of saleable hydrocarbons at the EOR facility. SI Figure SI-18 shows that the expected gate-to-gate GHG emissions from EOR crude range from 91.1 to 164.5 kg CO2e per barrel of crude (for current recovery) and 59.2 to 99.5 kg CO2e per barrel of crude (for advanced operations), depending on the type of gas processing technology being used; this represents an 70 to 80% difference between the low and high technologies. Detailed results and sensitivity figures for each gas processing scenario are available in the SI. The increased recovery of NGLs and corresponding high purity of the recycle CO2 comes at the expense of additional processing energy, which is demonstrated by the increased GHG emissions associated with Ryan-Holmes and membrane gas processing compared to the refrigeration and fractionation options. Membrane and Ryan-Holmes processing are modeled to recover approximately 75−85% of the NGLs produced, while refrigeration and fractionation only recover approximately 30%. When considered in the cradle-tograve model, the differences among gas processing technologies are overshadowed by processes upstream and downstream from the EOR facility. 7497
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different crudes. Expanding the boundary to include crude transport, refining, finished fuels transport, and combustion tends to reduce the life cycle GHG differences between the crude types since combustion accounts for nearly 80% of those emissions; however, crude quality differences are important to the remaining 20%.20 Cradle-to-Grave Results. Boundary Set 3 displayed in Figure 1, shows the processes included for a system where CO2 is captured at a fossil power plant and transported to an EOR site for injection. The downstream boundaries of this analysis have been shifted to include crude transport, refining, finished fuel transport, and combustion. The introduction of the anthropogenic CO2 source results in the addition of a coproduct (electricity). Coproduct management is now required for the system with a desired fuel functional unit. As previously discussed, this analysis expands the boundaries of the system to include displacement of conventional power production. Figure 3 compares three sources of CO2 for EOR (natural dome, advanced coal power [SCPC], and advanced natural gas power [NGCC]) for two different crude recovery ratios with the baseline results for conventional petroleum in the U.S.20 on the basis of 1 MJ of combusted gasoline. The corresponding parameter values for these scenarios are included in SI Tables SI-1 through SI-6. The anthropogenic EOR cases are lower than the corresponding natural dome EOR cases, because the anthropogenic cases include a displacement credit for the electricity produced by the power plants. The uncertainty bars are primarily a function of the source of the electricity that is being displaced. Improvements in the efficiency of EOR crude production reduces the life cycle GHGs for EOR when the CO2 is sourced from a natural dome, but increases the emissions when anthropogenic CO2 is used for EOR. This relationship is shown clearly by looking at the slopes of the lines in SI Figure SI-20. With a higher crude recovery ratio, less injected CO2 is required per unit of crude produced; therefore, less CO2 is required per unit of fuel combusted. For the natural dome cases, the understanding is straightforward−when less CO2 per unit of crude is required (the crude recovery ratio is higher) the GHG emissions are reduced because less CO2 is produced from the natural dome, less CO2 is compressed and transported via pipeline, and less CO2 injected at the EOR site. The same is true for the anthropogenic CO2 cases, except the power displacement decreases as less CO2 is required from the power plant. This behavior is exaggerated for the NGCC cases, because the NGCC power plant produces much less CO2 per unit of produced electricity. Thus, for a fixed CO2 demand from an EOR site, the NGCC power plant will produce more electricity than an SCPC power plant. The NGCC plant produces 2.42 kWh per kg of captured CO2 while the SCPC plant produces 0.93 kWh per kg of captured CO2. The amount of power generated for a given mass of captured CO2 relates directly to the slopes of the corresponding lines in SI Figure SI20. This difference is manifested in the size of the displacement credit for the two different anthropogenic CO2 sources. Figure 3 also shows that only the anthropogenic EOR cases (i.e., SCPC- and NGCC-EOR) are below the NETL petroleum baseline. This is not specific to EOR, rather the fact that carbon-intensive electricity is being displaced with captured electricity, and the fuel produced from that system receives a credit for this displacement.
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IMPLICATIONS
As a tertiary form of crude recovery, EOR is GHG-intensive. However, when coupled with captured fossil power, the produced fuel is an improvement over conventionally produced crude, because of displacement effects. The functional unit gets the benefit of adding a low-carbon postcombustion capture fossil fuel power plant. When considering only the gate-to-gate environmental performance of a CO2-EOR facility, the recovery ratio of crude oil per unit of sequestered CO2 accounts for the greatest amount of uncertainty. However, when a life cycle perspective is applied, the variability in CO2-EOR operating conditions are overshadowed by other life cycle stages, especially the combustion of finished fuel. For example, using current recovery rates and CO2 extracted from natural domes or captured from power plants, the combustion of produced gasoline accounts for at least 66% of the GHG emissions from the system. This does not mean that the detailed gate-to-gate process model of EOR is not important. Rather, the details behind that model provide confidence in interpreting the results in the context of broader system applications. When CO2 is used as a feedstock for EOR, the accounting methods for assigning environmental burdens significantly affect analysis conclusions for scenarios that capture CO2 from power plants. The complicating factor is the assignment of environmental burdens to captured CO2 when it comes from an integrated system that also produces electricity. If the life cycle boundaries include the displacement of electricity produced by other power plants, the expected GHG results have a wide uncertainty range, because the displaced power may have high or low GHG intensity. This illustrates the importance of the coproduct management assumptions for large-scale, linked energy systems. EOR operators currently purchase CO2 for use in EOR. As with any other purchased input, it is in the operator’s economic interest to optimize the use of CO2, meaning that their goal is to produce as much crude as feasible per unit of CO2 purchased and injected. Under this scheme, as illustrated by the two natural dome cases in Figure 3, increasing the EOR efficiency actually reduces the GHG emissions on a functional unit basis. The opposite is true if the source of that purchased CO2 is a fossil power plant. Increasing the EOR efficiency increases the GHG emissions for the functional unit, because of the reduction in displacement credit for electricity. When captured anthropogenic CO2 from fossil fuel power plants is linked to EOR, the incentives for the entities involved may be very different, resulting in an interesting challenge for policymakers who are attempting to regulate carbon emissions for these interconnected systems. For example, policymakers will have to decide which entity receives credit for the sequestered carbon, the power plant or the EOR operator.40 However, the economic incentives would change for EOR operators in the presence of a price on carbon. In that scenario, EOR operators could be paid to take CO2 and, therefore, may want to maximize the amount of CO2 that ends up sequestered in the EOR formation. This would effectively reduce the crude recovery ratio, which, as shown by this analysis, would reduce the GHG emissions for fuels produced from EOR operations that source CO2 from anthropogenic sources. Depending on the price of crude relative to the value of sequestering CO2, EOR operators may turn into sequestration operators. 7498
DOI: 10.1021/acs.est.5b00700 Environ. Sci. Technol. 2015, 49, 7491−7500
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(12) Khoo, H. H.; Tan, R. B. H. Life cycle investigation of CO2 recovery and sequestration. Environ. Sci. Technol. 2006, 40 (12), 4016−4024. (13) Jaramillo, P.; Griffin, W. M.; McCoy, S. T. Life cycle inventory of CO2 in an enhanced oil recovery system. Environ. Sci. Technol. 2009, 43 (21), 8027−8032. (14) Hussain, D.; Dzombak, D. A.; Jaramillo, P.; Lowry, G. V. Comparative lifecycle inventory (LCI) of greenhouse gas (GHG) emissions of enhanced oil recovery (EOR) methods using different CO2 sources. Int. J. Greenhouse Gas Control 2013, 16 (0), 129−144. (15) Oil prices drive projected enhanced oil recovery using carbon dioxide. http://www.eia.gov/todayinenergy/detail.cfm?id=17331. (16) Kuuskraa, V.; Wallace, M., CO2-EOR set for growth as new CO2 supplies emerge. Oil Gas J. 2014, 112, (4). (17) Life Cycle Analysis: Supercritical Pulverized Coal (SCPC) Power Plant, DOE/NETL-403/110609; National Energy Technology Laboratory: Pittsburgh, PA, 2010; http://www.netl.doe.gov/ File%20Library/Research/Energy%20Analysis/ Life%20Cycle%20Analysis/SCPC-LCA-Final-Report---Report---9-3010---Final---Rev-1.pdf. (18) Life Cycle Analysis: Natural Gas Combined Cycle (NGCC) Power Plant, DOE/NETL-403-110509; National Energy Technology Laboratory: Pittsburgh, PA, 2013; http://www.netl.doe.gov/ File%20Library/Research/Energy%20Analysis/ Life%20Cycle%20Analysis/NGCC-LCA-Report.zip. (19) Role of Alternative Energy Sources: Natural Gas Technology Assessment; DOE/NETL-2012/1539; National Energy Technology Laboratory: Pittsburgh, PA, 2012; http://www.netl.doe.gov/ File%20Library/Research/Energy%20Analysis/ Life%20Cycle%20Analysis/NGTechAssess.pdf. (20) Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels, DOE/NETL2009/1346; National Energy Technology Laboratory: Pittsburgh, PA, 2008; http://www.netl.doe.gov/File%20Library/Research/ Energy%20Analysis/Life%20Cycle%20Analysis/NETL-LCAPetroleum-based-Fuels-Nov-2008.pdf. (21) Gate-to-Grave Life Cycle Analysis Model of Saline Aquifer Sequestration of Carbon Dioxide, DOE/NETL-2013/1600; National Energy Technology Laboratory: Pittsburgh, PA, 2013; http://www. netl.doe.gov/File%20Library/Research/Energy%20Analysis/ Life%20Cycle%20Analysis/GtG-LCA-of-Saline-Aquifer-Sequestration. pdf. (22) Climate Change 2013 The Physical Science Basis; Intergovernmental Panel on Climate Change: Cambridge University Press, New York, 2013; http://www.climatechange2013.org/images/ uploads/WGIAR5_WGI-12Doc2b_FinalDraft_All.pdf. (23) Kinder Morgan Final Draft Environmental Assessment: Kinder Morgan Well Sites YE-5, HB-4, HE-5, and SC-10; May 16, 2002; http:// www.blm.gov/pgdata/etc/medialib/blm/co/nm/canm/CANM_ Documents.Par.30809.File.dat/kindermorganea.pdf. (24) Cost and Performance Baseline for Fossil Energy Plants Vol. 1: Bituminous Coal and Natural Gas to Electricity, DOE/NETL-2010/ 1397; National Energy Technology Laboratory: Pittsburgh, PA, 2010; http://www.netl.doe.gov/energy-analyses/pubs/BitBase_FinRep_ Rev2.pdf. (25) McCollum, D. L.; Ogden, J. M. Techno-Economic Models for Carbon Dioxide Compression, Transport, and Storage & Correlations for Estimating Carbon Dioxide Density and Viscosity; UCDITSRR 06−14; Davis, California, 2006; http://pubs.its.ucdavis.edu/ publication_detail.php?id=1047. (26) Bylin, C.; Schaffer, Z.; Goel, V.; Robinson, D.; Campos, A.; Borensztein, F. Designing the Ideal Offshore Platform Methane Mitigation Strategy; Society of Petroleum Engineers: 2010; http://www.epa.gov/ gasstar/documents/spe126964.pdf. (27) 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2: Energy, Chapter 5: Carbon Dioxide Transport, Injection, and Geological Storage; Intergovernmental Panel on Climate Change 2006; http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/ V2_5_Ch5_CCS.pdf.
ASSOCIATED CONTENT
S Supporting Information *
The Supporting Information file accompanying this paper includes a detailed discussion of the development of the modeling parameters for the gate-to-gate and cradle-to-grave models as well as model results. The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.5b00700.
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AUTHOR INFORMATION
Corresponding Author
*Phone: 412-386-7555; e-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS This analysis was prepared by the Energy Sector Planning and Analysis (ESPA) team for the United States Department of Energy (DOE), National Energy Technology Laboratory (NETL). This work was completed under DOE NETL Contract Number DE-FE0004001.
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REFERENCES
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