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Pre-feasibility study of CCS in western Nebraska
International Journal of Greenhouse Gas Control 84 (2019) 1–12
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Pre-feasibility study of CCS in western Nebraska ⁎
T
Neil Wildgust , Kerryanne M. Leroux, Barry W. Botnen, Daniel J. Daly, Melanie D. Jensen, Nicholas S. Kalenze, Matthew E. Burton-Kelly, Chantsalmaa Dalkhaa, Thomas E. Doll, Charles D. Gorecki University of North Dakota Energy & Environmental Research Center, 15 North 23rd Street, Stop 9018, Grand Forks, ND, 58202-9018, United States
A R T I C LE I N FO
A B S T R A C T
Keywords: Pre-feasibility CCS Nebraska Capture costs Dedicated storage CarbonSAFE
The Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercialscale carbon dioxide (CO2) geologic storage complex in western Nebraska, integrated with potential CO2 capture at the coal-fired Gerald Gentleman Station (GGS). This pre-feasibility project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE (Carbon Storage Assurance Facility Enterprise) Program, where projects are required to demonstrate the potential to capture and store at least 50 million tonnes (Mt) of CO2 over a minimum 25-year operational period. Using publicly available data, this study has shown that western Nebraska has potential to host a commercialscale carbon capture and storage (CCS) project. However, three key challenges would need to be overcome. Firstly, the business case for deploying CCS projects is uncertain; recently announced federal tax credits and sales for enhanced oil recovery might not cover full project costs. Secondly, the potential dedicated storage site defined in this study is at a low level of readiness to support a CCS project. Thirdly, public outreach would be a vital element in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.
1. Introduction In collaboration with the Nebraska Public Power District (NPPD), the Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercial-scale carbon dioxide (CO2) geologic storage complex in western Nebraska, integrated with potential CO2 capture at Gerald Gentleman Station (GGS). GGS is the largest coalfired electricity-generating station in Nebraska, emitting 8.5 million tonnes (Mt) of CO2 annually and is located near the town of Sutherland. This pre-feasibility (“Phase 1″) project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE (Carbon Storage Assurance Facility Enterprise) initiative, where projects are required to demonstrate the potential to capture and store at least 50 Mt of CO2 over a minimum 25-year operational period. The study comprised a white paper assessment, undertaken using only publicly available information. The EERC and NPPD established a coordination team to identify challenges to a potential Nebraska carbon capture and storage (CCS) project, drawn from local stakeholder organizations including
regulatory agencies and industry. The pre-feasibility assessment comprised the following technical themes, all using published information sources:
• Regional and stakeholder analysis, including identification of sen• •
sitive environmental areas, potential resource conflicts, and strategies for public outreach. Scenario assessment, addressing economic and regulatory factors. Subbasinal analysis, addressing the potential for a dedicated subsurface storage complex with the potential to store the required 50 Mt of CO2.
2. Regional and stakeholder analysis A review of geographic and socioeconomic characteristics focused on GGS to identify significant surface features that could affect implementation of a CCS project, including evaluation of prospective impacts that a carbon storage effort may have on the local population and natural environment. GGS is located in Lincoln County in western
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Corresponding author. E-mail addresses: [email protected] (N. Wildgust), [email protected] (K.M. Leroux), [email protected] (B.W. Botnen), [email protected] (D.J. Daly), [email protected] (M.D. Jensen), [email protected] (N.S. Kalenze), [email protected] (M.E. Burton-Kelly), [email protected] (C. Dalkhaa), [email protected] (T.E. Doll), [email protected] (C.D. Gorecki). https://doi.org/10.1016/j.ijggc.2019.03.002 Received 3 October 2018; Received in revised form 15 February 2019; Accepted 1 March 2019 Available online 12 March 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.
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Fig. 1. State of Nebraska showing the location of GGS (black dot in Lincoln County) and the five-county study area as well as the region of detailed geologic evaluation (orange rectangle).
over 95% of daily groundwater withdrawals (Maupin et al., 2014). Groundwater also contributes about 80% of the publicly supplied drinking water for the entire state of Nebraska (Johnson et al., 2011), and the reliance on the Ogallala Aquifer has greatly impacted water levels. The North and South Platte Rivers, just north of GGS, are the major waterways flowing through the study area. These two rivers join to form the Platte River just east of the city of North Platte in Lincoln County (Fig. 2). The five-county study area is a rural, sparsely populated region primarily covered in grasslands and cropland, with corn plantings covering about 21% of the land (Fig. 2). For the general public, the sensitive land cover types consist of wetlands and open water areas, as these types are environmentally important to wildlife and for human use. Cropland and pasture constitute less sensitive land uses, as any potential CCS-related impacts would be limited to the individual landowners where injection and monitoring might occur. There are few state or federally protected lands (refuges, wetlands, etc.) or culturally protected areas within this region. The study area contains multiple state and federal wildlife management areas, wildlife refuges, and other protected environmental habitats, particularly along the North and South Platte Rivers (Fig. 3). Relatively few of these areas are located in the southwestern direction from GGS. Any potential CCS project activities would thus take measures to avoid these wildlife habitats and account for the conservation of any threatened or endangered species that may require special management or protection.
Nebraska, just south of the Platte River system. Information from the regional analysis, used in collaboration with geologic model and simulation efforts (discussed further in the Subbasinal Analysis section), contributed to defining the project study region, a five-county area (Lincoln, Keith, Perkins, Chase, and Hayes) to the south and west of GGS (Fig. 1). The EERC and NPPD established a coordination team to address identified challenges to a potential Nebraska CCS project, including the Nebraska Energy Office, Nebraska Oil & Gas Conservation Commission, Nebraska Department of Environmental Quality, University of Nebraska-Lincoln, Omaha Public Power District, Southwest Public Power District, Lincoln Electric System, ION Engineering, and Berexco LLC. The coordination team met twice in Lincoln and via several Webinars, providing feedback and guidance throughout the pre-feasibility study.
2.1. Protected and environmentally sensitive areas Planning of a CCS project requires an evaluation of the region for environmentally sensitive or protected areas. These areas may be legally protected, such as underground sources of drinking water (USDWs) and state or federal refuge systems or they may be of importance to local stakeholders such as agricultural lands. Geographic information system (GIS) data were collected to determine specific locations of potential concern or areas to avoid should a CCS project be implemented. The GIS data were collected from a variety of sources such as the U.S. Department of Agriculture’s Natural Resources Conservation Service and the state of Nebraska and incorporated into a geodatabase. The ability to layer results from surface and subsurface evaluations was crucial in determining viable sites for potential injection of CO2 generated from GGS. Land use within the study is dominated by agricultural activities and has shallow (< 300 feet), well-protected USDWs. The primary use of groundwater in the study area is for irrigation, which accounts for
2.2. Current and future resource development The five-county study area was also reviewed to determine the potential impact to any current or future mineral or other resource development should a CCS project come to fruition. Although there has been past exploration for hydrocarbons in the study area, most existing exploration and production wells are no longer in operation and have been plugged and abandoned. 2
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Fig. 2. Land cover for the five-county regional analysis (source: U.S. Department of Agriculture Natural Resources Conservation Service, 2016).
Population centers in this rural area of the state are the towns of North Platte (population 24,000), Ogallala (4600), Imperial (1900), Sutherland (1400), and Grant (1300). Together, these communities account for about 65% of the combined populations of these five counties. Agricultural activity represents nearly a quarter of the state’s workforce, generating 25% of the state’s labor income, and accounts for over 40% of the state’s economic output (Thompson et al., 2012). This information and outputs from a “Yale Survey on Climate Change” (Table 1) were then used to develop a community outreach plan that focuses on delivering technically accurate information in a proactive and transparent manner, addressing any concerns identified. The five-county study area is consistently more sceptical of global warming and associated issues than the state of Nebraska or the United States on average. The site-specific plan provides a regional overview focused on roles, approach and guidelines, outreach considerations, project narrative, audiences, strategies, tool kit components, time line, tracking and assessment, and resources. The plan also directs outreach activities to educate and inform the public, public opinion leaders, and decision makers as well as evaluate current and evolving public perception of CCS for the duration of a potential CCS project if implemented. The plan, therefore, incorporates social characterization with engagement strategies and tracking: 1. Social Characterization – detailed baseline of attitudes and concerns pertinent to implementation of the proposed project for the community, opinion leaders, and key groups. 2. Engagement Strategies:
Renewable energy development, primarily wind energy such as the proposed wind project in Keith County (Kansas Energy Information Network, 2018), could potentially occur in the area. It is conceivable that wind energy infrastructure could affect the location of CCS surface installations or vice versa. Most wind energy development, however, occurs in northern and eastern Nebraska. Any future CCS activity would likely be able to avoid these oil/gas or wind energy development areas, thus limiting impacts on resource development. Although no CO2 pipelines exist in the vicinity of GGS, a significant number of petroleum and natural gas pipelines cross the landscape (Fig. 4). If pipeline construction were part of a future CCS project in this region, siting the CO2 pipeline in existing pipeline corridors should be considered to minimize impacts to landowners.
2.3. Community impact To be successful, a CCS project needs to be compatible with the existing social setting of an area as well as with the physical character of the geology and the landscape. This involves efforts to understand, anticipate, and address public perceptions as well as address the issues relevant to a particular community or region. Contact with the general public was not undertaken during this pre-feasibility effort. However, the investigation laid a foundation for constructive public engagement regarding CCS in the region through three actions: 1) proactive engagement with key industry, government, and academic stakeholders; 2) a community impact analysis based on published information on issues and regional social character; and 3) the preparation of a community outreach plan which serves as a source document intended to facilitate future CCS public engagement in the region. As mentioned previously, the five-county study area is largely rural, with a population of nearly 52,000 people (U.S. Census Bureau, 2015).
• Formation of an outreach advisory board. • Regional and local engagement – meetings and other communication to inform Nebraska officials and regional opinion leaders.
3
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Fig. 3. Protected areas in study area.
• Community open house – community meetings hosted by the project team outlining major project milestones. • Landowner engagement – contacts, home visits, and meetings • • • •
partners and key stakeholders. 3. CCS scenario assessment
geared specifically to engage with the many landowners in the project area. Web site – development and maintenance of a project public information Web site featuring basic project explanation and meeting notices as well as fact sheets, video clips, project updates, project partners, and contact information. Tool kit – development of a background document, fact sheets, and frequently asked questions from which project personnel and partners can draw to prepare content for print and electronic media. Community display – dissemination of project posters and informational material in select public locations such as the public library and community government offices. Educator outreach – periodic educational sessions for students and teachers in local schools.
Technical and financial incentives and/or challenges were identified that would face a potential CCS project in western Nebraska. Technical and infrastructure requirements related to CO2 capture, dehydration, compression, transport, injection, and monitoring were investigated. In terms of financial challenges, Nebraska is the only state in the United States served entirely by publicly controlled, nonprofit electric utilities, which are required by law to provide power to the largely rural population at the lowest possible cost. This creates a unique challenge when implementing technologies that require a large financial investment. Emitting 3.24 Mt of CO2 in 2016, GGS Unit 2 (GGS2) alone is large enough to provide sufficient CO2 to meet the CarbonSAFE requirement of storing 50 Mt over a 25-yr time period. A search for other large CO2 point sources within 75 miles of GGS was undertaken to identify additional CO2-sourcing opportunities. Using the U.S. Environmental Protection Agency’s (EPA’s) FLIGHT (Facility Level Information on GreenHouse gases Tool) database, only two additional sources were identified, neither of which is large enough to meaningfully contribute to the 50 Mt of CO2. Therefore, CCS scenarios for western Nebraska focused solely on GGS2.
3. Tracking – documentation of all outreach products, activities, communication, and interactions to measure project engagement. Feedback from project team members and interested stakeholders will help refine outreach activities to improve future outreach efforts as the project moves forward. The outreach plan developed during this project could be modified and adapted for use in future CCS projects in the region. Any future outreach efforts would be conducted through collaboration with the existing CCS coordination team and build upon pre-feasibility activities. In keeping with DOE best practices (U.S. Department of Energy National Energy Technology Laboratory, 2017), outreach task activities would be coordinated with the project development plan and the leadership team and liaise with other outreach efforts through a project outreach advisory group featuring outreach specialists from project
3.1. CCS infrastructure Technologies and infrastructure were identified that would be capable of capturing, dehydrating, compressing, and transporting a potential CO2 stream produced by GGS2. Although several capture technologies were investigated, such as membranes and absorption (both physical and chemical), chemical absorption using amines was 4
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Fig. 4. Pipeline routes in the study area.
The CO2 stream leaving an amine solvent capture system would consist primarily of CO2 and water. The water concentration must be reduced sufficiently to eliminate free water prior to pipeline transport of the CO2, thereby avoiding corrosion issues. Dehydration of a large CO2 stream is typically accomplished using a glycol scrubber such as triethylene glycol (TEG). Following dehydration, the CO2 stream would be compressed to its supercritical state (at least 88 °F and 1180 psi) for transport. Keeping the CO2 supercritical ensures transport in a single phase. For large mass flow rates and discharge pressures up to about 2900 psi, an integrally geared centrifugal compressor is usually
determined to be the most commercially viable technology for capturing CO2 from a power plant, as currently in use at both the Boundary Dam Unit 3 and Petra Nova plants. As a result, amine solvents were further investigated for viability in a potential GGS CCS scenario. Application of an amine solvent capture system at GGS2 would require that a wet flue gas desulfurization (FGD) unit be installed to remove SOx from the flue gas so as to limit the formation of heat-stable salts. The unit’s low-NOx burner and overfire air would likely prevent the formation of NOx in quantities that require additional flue gas treatment. Table 1 Yale Survey.
Beliefs
Risk Perception
Policy Support
Behaviors
Believe global warming is happening. Believe global warming is caused mostly by human activities. Trust climate scientists about global warming. Worried about global warming. Believe global warming is already harming people in the United States. Global warming will harm me personally. Global warming will harm people in the United States. Global warming will harm people in developing countries. Global warming will harm future generations. Global warming will harm plants and animals a great deal. Support fund research into renewable energy sources. Support the regulation of CO2 as a pollutant. Support strict CO2 limits on existing coal-fired power plants. Support the requirement of utilities to produce 20% electricity from renewable sources. Never discuss global warming.
5
Five Counties
Nebraska
USA
56% 42% 61% 47% 37% 32% 50% 54% 62% 59% 77% 66% 46% 56% 74%
64% 48% 66% 51% 44% 33% 51% 57% 65% 63% 81% 71% 63% 62% 70%
69% 52% 70% 56% 50% 38% 56% 61% 69% 68% 80% 74% 68% 65% 64%
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employed. A pipeline is the most economical way to transport large quantities of CO2, and the technology is well known, having been used to transport CO2 in the United States for more than 40 years. A typical CO2 pipeline is made of carbon steel. For a potential scenario of CO2 transported from GGS2, it was assumed based on the potential injection site from the subbasinal analysis (discussed in the next major section) that the pipeline would be about 121 km (75 mi) long, 46 cm (18 in.) in diameter, and buried. Geologic model and simulation efforts estimated that an average of four wells would be needed for a dedicated storage CCS scenario in the study area. The infrastructure required for injection into a saline formation consists primarily of the CO2 supply system (i.e., the pipeline and any infield transport lines that might be needed), the injection wells and their associated instruments, and a SCADA (supervisory control and data acquisition) system to monitor and control injection and storage operations. Assumptions included that geological core and formation fluid samples would be collected to determine mineralogy, porosity, permeability, and geochemical reactivity to CO2 at the injection site. Cement bond and variable-density logs would provide cement bond quality information to ensure the protection of drinking water and reduce the risk of CO2 migration to the shallow subsurface or the surface. Reservoir surveillance to observe and quantify the CO2 plume movement and injection profile, such as borehole-to-surface electromagnetic analysis (determines the salinity contrast between the injected CO2 and native formation fluid) and downhole pressure and temperature gauges, were also included in the assessment of required infrastructure.
Fig. 5. Estimated capture costs for GGS2 using a natural gas-fired auxiliary boiler to provide steam.
reported as dollars per tonne of CO2 captured. Combined construction and operation elements included pipelines, wells, permitting, and monitoring based on advice from Schlumberger Carbon Services. Given the uncertainties and approximations inherent in this pre-feasibility study and the similarity of modeling results for parasitic load and auxiliary boiler options, we can conclude that a best-case scenario for CCS deployment at GGS would incur total costs of approximately $70 per tonne of captured and stored CO2. Avoided costs per tonne, which may be significantly higher, were not calculated.
3.3. Financial incentives and revenue assessment
3.2. CCS investment
As mentioned previously, Nebraska is served entirely by publicly controlled, nonprofit electric utilities required by law to provide power at the lowest possible cost, creating a unique challenge with regard to implementing high-investment technologies. Therefore, possible revenue from potential CO2 production at GGS2 was investigated. Tax credits available through the Bipartisan Budget Act of 2018 under the Enhancement of Carbon Dioxide Sequestration Credit (formerly known and hereafter referred to as Section 45Q) were evaluated as an opportunity for CO2 suppliers to potentially capitalize on a supplemental market. Utilizing Section 45Q tax credits as a marketing tool would depend greatly on agreed-upon negotiating terms between the CO2 supplier (e.g., NPPD), the CO2 purchaser, or other stakeholders/partners in the CCUS value chain. Although NPPD, as a public entity, does not qualify directly for Section 45Q, a pathway to market could exist where operator(s) or other partners/stakeholders in the CCUS value chain for dedicated storage or enhanced oil recovery (EOR) would be willing to purchase CO2 from GGS2 and store in a saline formation or at an oil field(s) associated with EOR operations. In this case, the operator (s) or other partners/stakeholders in the CCUS value chain would be responsible for claiming the tax credits as well as adhering to any CO2monitoring requirements in the subsurface. The Section 45Q tax credit amounts are established by linear interpolation from $12.83 to $35 per tonne for EOR and from $22.66 to $50 per tonne for dedicated storage each calendar year after 2016 and before 2027 (Congress.gov, 2018). After 2026, the tax credits increase according to inflation as, presumably, would the cost of CCS. Compared to the minimum estimated cost of approximately $70/tonne for a CCS project, tax credits alone are not a sufficient resource for CCS investment, particularly for a dedicated storage scenario. Further revenue assessment focused on potential EOR markets. At the current estimated price of CO2 of $25 to $35/tonne, the combined value of the Section 45Q tax credit and the direct sale price of the CO2 could range from $60 to $70/tonne. At a $70/tonne value, the estimated CCS cost may be offset; however, further investigation is recommended as many details are still unclear as to how the credit can be claimed and by whom.
System requirements for the application of CO2 capture at GGS2 using amine solvents were obtained using the DOE National Energy Technology Laboratory (NETL)-funded Carnegie-Mellon University Integrated Environmental Control Model (IECM), a modeling program that systematically analyzes the cost and performance of emission control equipment at coal-fired power plants. Twelve retrofit capture scenarios were modeled for GGS2: all combinations of 65%, 80%, and 90% capture with and without an auxiliary boiler for the two commercial amine solvent technologies that are available in IECM, namely, Cansolv and Fluor’s Econamine FG + . A 65% capture scenario is the minimum capture level needed at GGS2 to average 2 Mt per year CO2 capture output (i.e., to meet the CarbonSAFE Program minimum 50-Mt CCS requirement over a 25-yr period), while a capture level of 90% is considered to be “full capture.” An intermediate level of 80% was also explored to determine if a capture cost minimum existed. IECM was used to estimate capture costs per tonne of a nearly pure CO2 stream from GGS2, including both capital and operating expenses. As GGS2 does not have a wet FGD unit, the cost of reducing SOx concentrations was also included. The power for these extra facilities may be supplied by a parasitic load at the plant or by employing an auxiliary boiler. Note that the purpose of the modeling at this pre-feasibility stage was to obtain reasonable estimates of the cost of carbon capture at GGS. The technology choice between auxiliary boiler versus parasitic load would depend on various factors, including the degree to which GGS operates at design capacity, and is thus beyond the scope of this prefeasibility study. Note also that we have not calculated avoided costs per tonne of captured CO2, which would need to allow for CO2 emissions from an auxiliary boiler. Fig. 5 compares capture costs against varying percentages of CO2 capture for both Econamine FG + and Cansolv amine systems, including costs associated with an auxiliary boiler. Although the cost differential between the two amine types is significant, both show minimum cost at around 82% capture rates. Note also that the figure does not show avoided capture costs, which would need to allow for CO2 emissions from the auxiliary boiler. Table 2 presents best-case scenario costs for the full CCS chain, 6
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Table 2 Optimal CCS Project Cost for GGS.a Component
Capture + Parasitic Load Costs, $/tonne
Capture + Auxiliary Boiler Costs, $/tonne
FG+ 80% Capture Pipelineb Four Class VI Injection Wellsc One Stratigraphic Test Wellc One Monitor Wellc 12.25-mi2 3-D Seismic Surveyc Permittingd Total
68 1.3 0.32 0.06 0.10 0.01 0.24 70
65 1.3 0.32 0.06 0.10 0.01 0.24 67
a b c d
All values reported to two significant figures. DOE NETL CO2 Model: Assumes 18-inch, 75-mile pipeline with injection at 1300 psi over 30 years in 2014 U.S. dollars. Calculated from Schlumberger estimate. Assumes permitting costs for four Class VI injection wells.
Colorado. The eastern extent of the storage resource models was dictated by the shallowest part of each reservoir greater than 3000 ft in depth. Because of the low data availability in the study area for the current pre-feasibility study, these storage resource assessments were conducted at the play level according to the Society of Petroleum Engineers (SPE, 2016) draft CO2 storage resources management system (SRMS). This SRMS classifies storage resources according to project maturity, where an increasing amount of data increases the chance of eventual commercialization and screens out those resources that do not meet technical, economic, or regulatory standards. Two Cloverly Formation models were used: one at a regional scale and the second a smaller area clipped out for numerical simulation. A modified DOE method of calculating CO2 storage potential in saline formations was used for each model (Peck et al., 2014) (Tables 3 and 4). Three probability distributions of formation properties (optimistic [P90], average [P50], and conservative [P10]) were considered. Most of the potential storage resource in the Cloverly regional model lies in the southwestern part of the study area and the thickest part of the formation (Fig. 6; Table 3). Facies distribution within the geologic model is a highly simplified fluvial system of fluvial sandstones interbedded with shales and represents a scenario with limited hydraulic connectivity among sandstone bodies. Digitized gamma ray logs from 52 wells were upscaled into the model grid and used to condition the facies distribution for this prefeasibility study. Sandstone channel widths from Antia et al., 2011were used to constrain the size of sandstone bodies.
3.4. Regulatory challenges The state of Nebraska has not officially contemplated or promulgated statutes regarding CCS at this time. No regulatory environment currently exists for pore space ownership, financial assurance, closure, or long-term liability. In addition, no state regulatory agency has been selected for primacy, rule making, and oversight should statutes related to CCS be introduced. EPA administers the Underground Injection Control (UIC) Program that consists of a variety of measures to ensure that all USDWs are protected. As a result, existing federal regulations currently guide any CCS efforts and long-term liability in Nebraska. Should the regulatory environment change and/or if an academic, public, private, or commercial entity proposes a CCS project, regulatory certainty would likely be a multiyear process for development of legislative statutes and rule making from state agencies. 4. Subbasinal analysis 4.1. Reservoir and seal characteristics The Lower Cretaceous Cloverly Formation (fluvial depositional environment) was characterized at a pre-feasibility level to assess its efficacy as a CO2 saline storage reservoir. This formation is continuous within the Nebraska–Colorado study area shown in Fig. 6, thickens and deepens to the southwest into the Denver–Julesburg Basin, and thins and shallows to the east. Porosity ranges from 4 to 33 percent and permeability from 0.01 to 1700 millidarcies based on core data from the Nebraska Oil and Gas Conservation Commission. Net-to-gross ratio approximates 0.5 across the extent of the Dakota Group (e.g., Covault et al., 2012; Volk, 1969). Where applicable and where data were available, the extent of the potential reservoir was limited to areas where the top of the reservoir is greater than 3000 ft deep, the formation water has a salinity greater than 10,000 ppm, and a continuous sealing formation (the overlying Skull Creek Shale) is present. Underlying sealing strata include the Cretaceous Fuson Shale, Jurassic Morrison Formation, and multiple Upper Permian evaporate deposits. Structural data were retrieved from publicly available state databases; because stratigraphic data collection in Nebraska is geographically clustered according to oil and gas production, structural uncertainty is larger across the middle of the study area where fewer wells are. Likewise, petrophysical properties used to populate geologic models were extrapolated from a limited number of digital well logs and core measurements, increasing the amount of uncertainty.
4.3. Dynamic simulation of CO2 storage in the Cloverly Sandstone Dynamic flow simulation was conducted to assess the prefeasibility of storing 50 Mt of CO2 over 25 years in the Cloverly Formation. An area in Perkins and Chase Counties, Nebraska, was chosen because this location is within the state boundaries, relatively close to GGS, and would not require pipeline development over major rivers. Given the high degree of uncertainty in the geologic heterogeneity of the sandstone, three P90, P50, and P10 probability distributions of formation properties were considered for numerical simulations (Table 5). Specific goals of the simulation study were to assess:
• Potential locations and number of injection wells required to inject 50 Mt of CO over 25 years in the Cloverly Formation. • Wellhead pressure (WHP) ranges for injection wells and the asso2
• •
4.2. Prospective storage resource assessment A regional prospective storage resource assessment was performed for the area of the Nebraska panhandle and the northeastern corner of 7
ciated parameter impact on WHP via a sensitivity analysis, including an optimum WHP to inform infrastructure design. Area of review (AOR) determined by the extent of CO2 and pressure plumes during and after injection. Postinjection CO2 plume migration and pressure stabilization.
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Fig. 6. Nebraska Cloverly Formation CO2 prospective storage resource assessment (P50 estimate), summed vertically. Northeast–southwest-trending variation in storage represents interbedded sandstones and shales with accompanying porosity distributions.
4.4. Simulation model development
Table 3 Cloverly Formation Prospective Storage Resource Estimates for Western Nebraska and Northeastern Colorado Using Esaline Values from Peck et al., 2014. Esaline, %** Cloverly Formation Model* Regional Simulation
Computer Modelling Group Ltd.’s (CMG’s) GEM simulator and CMOST sensitivity analysis tool were used to simulate CO2 injection into the Cloverly, perform a sensitivity study on WHP, and examine a postinjection scenario. The simulation fluid model includes two components, CO2 and brine, properties and relationships between which were taken from Harvey’s correlation for Henry’s Law constants (Harvey, 1996), correlations from Rowe and Chow (1970) and Kestin et al., 1981, and a CO2–brine relative permeability table from Bennion and Bachu (2005 and 2007). The primary constraint for injection was a maximum daily total injection of 5500 tonnes of CO2 based on the capture target of the facility (2 Mt of CO2 annually). A maximum bottomhole pressure (BHP) of 2100 psi was used as a secondary constraint to ensure injection remained at least 10% below the fracture pressure of the formation (using a 0.7-psi/ft fracture pressure gradient which we
Potential Storage Estimate, Mt
P10
P50
P90
P10
P50
P90
7.4 7.4
14 14
24 24
20,800 586
39,300 1110
67,400 1900
* Storage potential was calculated for two variations of the Cloverly Formation model based on two model sizes (regional and the geographically limited simulation model). ** Esaline is the efficiency factor applied to the total porosity to produce storage potential estimates (discussed below); known factors included net area, thickness, and porosity.
Table 4 Model Parameters Used for Volumetric Storage Estimates. Cloverly Formation Model
Area, mi2
Cell Size, ft
Reservoir Porosity, %
Reservoir Temperature, °C
Pressure Gradient, psi/ft
Regional Simulation*
30,600 839
1000 × 1000 1000 × 1000
18.6 18.6
45.7 45.7
0.6 0.6
* The Cloverly simulation model was clipped out of the Cloverly regional model, resulting in a smaller area but the same property distributions within that area. 8
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Table 5 Arithmetic Mean Values for Porosity and Permeability of Sand and Shale in the Three Models. Model Property
P90
Facies Sandstone Shale*
Porosity, % 25.0 12.1
P50 Permeability, mD 425 0.00001
P10
Porosity, % 18.6 9.72
Permeability, mD 211 0.00001
Porosity, % 16.0 7.95
Permeability, mD 161 0.00001
* Shale permeability was set to a value close but not equal to zero for computational efficiency.
For the P90 and P50 models, injection tubing size had the greatest impact on WHP (larger tubing for injection can significantly reduce the required WHP), as the injection rates considered per well are higher in both models. The other more influential parameters are wellhead injection temperature and tubing relative roughness following the tubing size in both models. Borehole temperature had no effect on WHP. Higher injection pressure is required to compress CO2 at a higher injection temperature because CO2 is less dense at a higher temperature. Smaller tubing roughness is related to lower injection pressure because of the lower pressure loss (friction) in the tubing during injection. As for the P10 model, where a considerably lower injection rate per well is applied because of the lower injectivity of the model, the wellhead temperature has the greatest effect on WHP, rather than the size of the injection tubing. Based on the information obtained from the sensitivity analysis, a larger tubing size of 4.5 in. (the required wellhead injection pressure would be lower at 1300 psia) was suggested because maintaining injection at a lower pressure is more economical for the infrastructure design (gas compression system).
consider to be relatively conservative). 4.5. Identification of potential location for CO2 injection The results from the numerical simulation efforts indicated that two, four, and 14 injection wells are required for the respective P90, P50, and P10 models to store 50 Mt of CO2 (annually 2 Mt or daily, on average, 5500 tonnes of CO2). The number of injection wells required for 50 Mt of CO2 storage intrinsically increases with poorer formation properties as gas injectivity per well decreases from P90 wells to P10 wells (Fig. 7). Injection wells were placed in the clean, larger, and thicker sand bodies in the model. Extra effort was made to reduce the distance between the injection wells to have a smaller surface footprint of CO2 injection and place them in a more uniform spacing. However, because of the extensive presence of shales in the model and the pressure interference from the very high injected volume of CO2, the effort was challenging to achieve. The well spacing between two injection wells in the P90 model is about 2.5 miles. The well spacing (between two adjacent wells) for the P50 and P10 models is approximately 6–13.5 and 3.5–8 miles, respectively.
4.7. AOR determination 4.6. Sensitivity analysis on WHP The extents of CO2 plume (lateral distribution of CO2 saturation) and pressure plume (pressure buildup in the formation) were evaluated at the end of 25 years of potential injection into the Cloverly Sandstone to determine the size of AOR that will be necessary for planning a MVA (monitoring, verification, and accounting) program for CO2 storage. Approved MVA plans are typically required for permitting, especially for dedicated CO2 storage (i.e., EPA UIC Class VI). The predicted CO2 plume extent was quantified in gas per unit area in total, which is a product of CO2 saturation, porosity, and thickness,
Following the base simulation work of determining the number of wells required and their potential locations for CO2 injection, a sensitivity analysis was conducted using CMG CMOST to determine the relative effects of parameters greatly impacting WHP, ranges of predicted or simulated WHP values, and an optimum wellhead injection pressure to inform infrastructure design and corresponding economic analysis. The parameters included the wellhead temperature, bottomhole temperature, tubing size, and tubing relative roughness.
Fig. 7. Simulated CO2 plumes (in plan view) for the P90, P50, and P10 models (from left to right) at the end of a potential 25-year CO2 injection operation. Note: the injection wells are labeled “DK” (Dakota), as the Cloverly Formation is in the lower Dakota Group. 9
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Fig. 8. Simulated pressure plumes (in plan view) for the P90, P50, and P10 models (from left to right) at the end of a potential 25-year CO2 injection operation. Note: the lower limit in the pressure scale is bounded by the pressure threshold value of 138 psi for determining the AOR.
Fig. 9. The simulated postinjection CO2 plume (in plan view) after 100 years of postinjection (left) and pressure plume extent after 40 years of postinjection (right). Note: the lower limit in the pressure scale is bounded by the pressure threshold value of 138 psi for determining the AOR.
high shale content in the model did not allow pressure to dissipate uniformly, resulting in directional and larger pressure plume extents, as shown in Fig. 8. The size of the pressure plume extent for the P90 model was the smallest, covering an area of about 20 × 20 miles (west–east and north–south) at the end of the 25-year injection period. As for the P50 model, the pressure plume extent was considerably larger relative to the P90 plume, spreading out about 21 × 30 miles. The predicted pressure plume extent in the P10 model is largest, covering an area of about 22 × 32 miles. As shown in Figs. 7 and 8, the pressure plume extent was much greater than the extent of the CO2 plume; hence, the pressure plume will dictate the AOR size for CO2 injection in the Cloverly Formation. The simulated extent of the AOR in the formation for potentially storing 50 Mt of CO2 would be approximately 20 × 20 (smallest) and 22 × 32 (largest) miles. These AOR sizes would be conservative ones as a hypothetical open conduit is considered in the EPA calculation approach.
as shown in Eq. 1: CO2 per Unit Area – Total (ft) = CO2 Saturation × Porosity × Thickness (1) Fig. 7 shows the CO2 plume extents for all three models after 50 Mt of CO2 was injected over 25 years. The plume diameters approximated 3.5, 3, and 2 miles around each injection well, respectively, for the P90, P50, and P10 models. The pressure front or threshold was calculated using the EPA pressure front equation (U.S. Environmental Protection Agency, 2011). The pressure threshold, or the pressure, within the injection zone, great enough to force fluids from within the injection zone through a hypothetical open conduit into any overlying USDW, was calculated at 138 psi for the region modeled for this project. Fig. 8 shows the pressure increase and extent in each model as a result of 25 years of injection for the layer with the highest and largest (laterally) pressure extent. The simulated pressure plume was extensive in all three models because the 10
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conducted here have a relatively high degree of uncertainty, relying heavily on generalized subsurface characteristics as a result of a lack of site-specific data. Acquisition of site-specific data (including well log and core data) would provide opportunity to refine the models discussed here, enable more accurate predictive simulations, and decrease subsurface technical risks posed by geologic uncertainty. 5. Conclusions In summary, the work undertaken in this Phase 1 pre-feasibility study has shown that western Nebraska has potential to host a commercial-scale CCS project, including a dedicated storage container for 50 Mt of CO2. However, the following key challenges would need to be overcome: 1 The business case for deploying CCS projects is uncertain; recently announced federal tax credits might not compensate for the cost of CCS deployment at a coal-fired power station such as GGS. Sales of CO2 for EOR could provide additional revenue, but the combined benefits of tax credits plus EOR sales still may not cover the full costs of a CCS project at GGS, as estimated by this pre-feasibility study. 2 The potential 50-Mt CO2 dedicated storage container defined in this pre-feasibility study should be regarded as having a relatively low level of readiness to support a CCS project. Significant further work, including exploratory drilling and geophysical surveys, would be required to provide sufficient certainty to support an investment decision in a Nebraska CCS effort. 3 Public outreach would be a vital element for CCS implementation in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.
Fig. 10. The cumulative injected, dissolved, and free CO2 in the Cloverly Formation during simulation.
4.8. Postinjection simulation As part of numerical simulation efforts for this project, postinjection was also investigated using the P50 (moderate) model, after the 25-year CO2 injection halted to understand CO2 plume migration and evolution and pressure stabilization. After a period of 100 year’s postinjection, the CO2 plume diameter around each well in the P50 model had grown by 1 mile to approximately 4 miles, indicating that the CO2 is moving at a rate of approximately 50 ft per year within the formation. The remaining pressure buildup was not significant compared to the estimated pressure threshold, almost completely disappearing at the end of 100 year’s postinjection. The remaining pressure buildup (maximum value of 350 psi) at the end of 40 years of postinjection is shown in Fig. 9, compared to the pressure plume at the end of the 25-year injection period, shown in Fig. 8 (the middle image, P50 model). The pressure plume became significantly smaller beyond 40 years of postinjection. At the end of a simulated 100-year postinjection, the fate of the injected CO2 (how the injected CO2 is stored in the sandstone) was also assessed. CO2 storage is known to involve four different trapping mechanisms: hydrodynamic trapping, residual trapping, solubility trapping, and mineral trapping (Gunter et al., 1997). Injected CO2 will reside in the storage formation in the free-gas phase (through hydrodynamic and residual trapping), as dissolved in formation brine (through solubility trapping), and in immobile solid phase (through mineral trapping). The effects of mineral trapping were not included in the numerical simulations conducted in this study, as modeling mineral reactions adds to computational intensity. Fig. 10 indicates the cumulative injected CO2, dissolved CO2, and free CO2 in the Cloverly Sandstone over the injection and postinjection periods. During the postinjection period after the 25-year injection was halted, the amount of dissolved CO2 gradually increases with decreasing free CO2 migrating away from each well. The majority of the injected CO2 (approximately 90%) will be stored as free CO2 in the formation at the end of the 100-year postinjection period. Approximately 60% of the free CO2 would be mobile (hydrodynamically trapped), and 40% of the free CO2 would be immobile (residually trapped), assuming a residual CO2 saturation value of 0.2.
Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. Acknowledgments This work was funded by the US Department of Energy and Nebraska Public Power District. Technical support was provided by Schlumberger Carbon Services and CMG. References Antia, J., Fielding, C.R., Joeckel, R.M., 2011. Multiple cycles of wave-dominated estuarine deposits in low-accomodation settings, cretaceous J sandstone, northwestern Nebraska. AAPG Bull. 95 (7), 1227–1256. Bennion, D.B., Bachu, S., 2005. Relative permeability characteristics for supercritical CO2 displacing water in a variety of potential sequestration zones: SPE 95547. SPE Annual Technical Conference and Exhibition, 9–12 October, Dallas, Texas. Bennion, D.B., Bachu, S., 2007. Permeability and relative permeability measurements at reservoir conditions for CO2-water systems in ultra-low permeability confining caprocks. Soc. Pet. Eng. https://doi.org/10.2118/106995-MS. Census Bureau, U.S., 2015. American Community Survey 5-year Data Profiles. (Accessed April 2018). www.census.gov/acs/www/data/data-tables-and-tools/data-profiles/ 2015/.
4.9. Dynamic simulation discussion The simulation results achieved in this prefeasibility study show the potential of the Cloverly Sandstone to sequester 50 Mt of CO2 over 25 years; however, the resulting AOR dictated by the pressure plume would be larger than ideal for a monitoring program because of the high shale content in the sandstone. The models and simulations 11
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2014. A workflow to determine CO2 storage potential in deep saline formations. Energy Procedia 63, 5231–5238. Rowe, A., Chou, J., 1970. Pressure–volume–temperature-concentration relation of aqueous NaCl solutions. J. Chem. Eng. Data 15 (1), 61–66. Society or Petroleum Engineers, 2016. Draft CO2 Storage Resources Management System. (Accessed 2018). www.spe.org/industry/CO2-storage-resources-managementsystem.php. Thompson, E., Johnson, B., Giri, A., 2012. The 2010 Economic Impact Of The Nebraska Agricultural Production Complex: Department Of Agricultural Economics At University Of Nebraska Lincoln, Report No. 192. June 2012. . U.S. Department of Agriculture Natural Resources Conservation Service, 2016. Land Cover Dataset From NRCS Data Gateway Website. https://datagateway.nrcs.usda. gov/. U.S. Department of Energy National Energy Technology Laboratory, 2017. Public Outreach and Education for Geologic Storage Projects. 2d ed.: Best practices manual, DOE/NETL-2017/1845, June 2017 (accessed 2018). www.netl.doe.gov/File %20Library/Research/Carbon-Storage/Project-Portfolio/BPM_PublicOutreach.pdf. U.S. Environmental Protection Agency, 2011. Underground Injection Control (UIC) Program Class VI Well Area of Review Evaluation and Corrective Action Guidance for Owners and Operators. Volk, R.W., 1969. Petroleum potential of eastern Colorado, western Nebraska, southeastern Wyoming, and northeastern New Mexico. In: Cram, I.H. (Ed.), Future Petroleum Provinces of the United States—their Geology and Potential. AAPG Memoir, pp. 15.
Congress.gov, 2018. 115th Congress of the United States of America, House Bill, H.R. 1892, Section 45Q, Credit for Carbon Oxide Sequestration. BILLS-115hr1892enr.pdf (Accessed April 2018).. www.congress.gov/115/bills/hr1892/. Covault, J.A., Buursink, W.H., Craddock, M.D., Blondes, M.S., Gosai, M.A., Freeman, P.A., 2012. Geologic framework for the national assessment of carbon dioxide storage resources—Bighorn Basin, Wyoming and Montana. In: Warwick, P.D., Corum, M.D. (Eds.), Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources. USGS Open-File Report 2012-1024-A. Gunter, W.D., Wiwchar, B., Perkins, E.H., 1997. Aquifer disposal of CO2-rich greenhouse gases—extension of the time scale experiment for CO2 sequestrating reactions by geochemical modeling. Mineral. Petrol. 59, 121–140. Harvey, A., 1996. Semi-empirical correlation for Henry’s constants over large temperature ranges. Am. Inst. Chem. Eng. J. 42, 1491. Johnson, B., Thompson, C., Giri, A., Van NewKirk, S., 2011. Nebraska irrigation fact sheet. Dept. Agric. Econ (accessed June 2018). https://agecon.unl.edu/a9fcd9024da9-4c3f-9e04-c8b56a9b22c7.pdf. Kansas Energy Information Network, 2018. Existing Nebraska Wind Farms. (accessed April 2018). www.kansasenergy.org/NE_wind_projects_case.htm. Kestin, J., Khalifa, H., Correia, R., 1981. Tables of dynamic and kinematic viscosity of aqueous NaCl solutions in the temperature range 20°–150°C and the pressure range 0.1– 35 MPa. J. Phys. Chem. Ref. Data 10, 71–87. Maupin, M.A., Kenny, J.F., Hutson, S.S., Lovelace, J.K., Barber, N.L., Linsey, K.S., 2014. Estimated use of water in the United States in 2010. U.S. Geol. Surv. Circ. 1405, 56. https://doi.org/10.3133/cir1405. Peck, W.D., Glazewski, K.A., Klenner, R.C.L., Gorecki, C.D., Steadman, E.N., Harju, J.A.,
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Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Pre-feasibility study of CCS in western Nebraska ⁎
T
Neil Wildgust , Kerryanne M. Leroux, Barry W. Botnen, Daniel J. Daly, Melanie D. Jensen, Nicholas S. Kalenze, Matthew E. Burton-Kelly, Chantsalmaa Dalkhaa, Thomas E. Doll, Charles D. Gorecki University of North Dakota Energy & Environmental Research Center, 15 North 23rd Street, Stop 9018, Grand Forks, ND, 58202-9018, United States
A R T I C LE I N FO
A B S T R A C T
Keywords: Pre-feasibility CCS Nebraska Capture costs Dedicated storage CarbonSAFE
The Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercialscale carbon dioxide (CO2) geologic storage complex in western Nebraska, integrated with potential CO2 capture at the coal-fired Gerald Gentleman Station (GGS). This pre-feasibility project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE (Carbon Storage Assurance Facility Enterprise) Program, where projects are required to demonstrate the potential to capture and store at least 50 million tonnes (Mt) of CO2 over a minimum 25-year operational period. Using publicly available data, this study has shown that western Nebraska has potential to host a commercialscale carbon capture and storage (CCS) project. However, three key challenges would need to be overcome. Firstly, the business case for deploying CCS projects is uncertain; recently announced federal tax credits and sales for enhanced oil recovery might not cover full project costs. Secondly, the potential dedicated storage site defined in this study is at a low level of readiness to support a CCS project. Thirdly, public outreach would be a vital element in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.
1. Introduction In collaboration with the Nebraska Public Power District (NPPD), the Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercial-scale carbon dioxide (CO2) geologic storage complex in western Nebraska, integrated with potential CO2 capture at Gerald Gentleman Station (GGS). GGS is the largest coalfired electricity-generating station in Nebraska, emitting 8.5 million tonnes (Mt) of CO2 annually and is located near the town of Sutherland. This pre-feasibility (“Phase 1″) project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE (Carbon Storage Assurance Facility Enterprise) initiative, where projects are required to demonstrate the potential to capture and store at least 50 Mt of CO2 over a minimum 25-year operational period. The study comprised a white paper assessment, undertaken using only publicly available information. The EERC and NPPD established a coordination team to identify challenges to a potential Nebraska carbon capture and storage (CCS) project, drawn from local stakeholder organizations including
regulatory agencies and industry. The pre-feasibility assessment comprised the following technical themes, all using published information sources:
• Regional and stakeholder analysis, including identification of sen• •
sitive environmental areas, potential resource conflicts, and strategies for public outreach. Scenario assessment, addressing economic and regulatory factors. Subbasinal analysis, addressing the potential for a dedicated subsurface storage complex with the potential to store the required 50 Mt of CO2.
2. Regional and stakeholder analysis A review of geographic and socioeconomic characteristics focused on GGS to identify significant surface features that could affect implementation of a CCS project, including evaluation of prospective impacts that a carbon storage effort may have on the local population and natural environment. GGS is located in Lincoln County in western
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Corresponding author. E-mail addresses: [email protected] (N. Wildgust), [email protected] (K.M. Leroux), [email protected] (B.W. Botnen), [email protected] (D.J. Daly), [email protected] (M.D. Jensen), [email protected] (N.S. Kalenze), [email protected] (M.E. Burton-Kelly), [email protected] (C. Dalkhaa), [email protected] (T.E. Doll), [email protected] (C.D. Gorecki). https://doi.org/10.1016/j.ijggc.2019.03.002 Received 3 October 2018; Received in revised form 15 February 2019; Accepted 1 March 2019 Available online 12 March 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.
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Fig. 1. State of Nebraska showing the location of GGS (black dot in Lincoln County) and the five-county study area as well as the region of detailed geologic evaluation (orange rectangle).
over 95% of daily groundwater withdrawals (Maupin et al., 2014). Groundwater also contributes about 80% of the publicly supplied drinking water for the entire state of Nebraska (Johnson et al., 2011), and the reliance on the Ogallala Aquifer has greatly impacted water levels. The North and South Platte Rivers, just north of GGS, are the major waterways flowing through the study area. These two rivers join to form the Platte River just east of the city of North Platte in Lincoln County (Fig. 2). The five-county study area is a rural, sparsely populated region primarily covered in grasslands and cropland, with corn plantings covering about 21% of the land (Fig. 2). For the general public, the sensitive land cover types consist of wetlands and open water areas, as these types are environmentally important to wildlife and for human use. Cropland and pasture constitute less sensitive land uses, as any potential CCS-related impacts would be limited to the individual landowners where injection and monitoring might occur. There are few state or federally protected lands (refuges, wetlands, etc.) or culturally protected areas within this region. The study area contains multiple state and federal wildlife management areas, wildlife refuges, and other protected environmental habitats, particularly along the North and South Platte Rivers (Fig. 3). Relatively few of these areas are located in the southwestern direction from GGS. Any potential CCS project activities would thus take measures to avoid these wildlife habitats and account for the conservation of any threatened or endangered species that may require special management or protection.
Nebraska, just south of the Platte River system. Information from the regional analysis, used in collaboration with geologic model and simulation efforts (discussed further in the Subbasinal Analysis section), contributed to defining the project study region, a five-county area (Lincoln, Keith, Perkins, Chase, and Hayes) to the south and west of GGS (Fig. 1). The EERC and NPPD established a coordination team to address identified challenges to a potential Nebraska CCS project, including the Nebraska Energy Office, Nebraska Oil & Gas Conservation Commission, Nebraska Department of Environmental Quality, University of Nebraska-Lincoln, Omaha Public Power District, Southwest Public Power District, Lincoln Electric System, ION Engineering, and Berexco LLC. The coordination team met twice in Lincoln and via several Webinars, providing feedback and guidance throughout the pre-feasibility study.
2.1. Protected and environmentally sensitive areas Planning of a CCS project requires an evaluation of the region for environmentally sensitive or protected areas. These areas may be legally protected, such as underground sources of drinking water (USDWs) and state or federal refuge systems or they may be of importance to local stakeholders such as agricultural lands. Geographic information system (GIS) data were collected to determine specific locations of potential concern or areas to avoid should a CCS project be implemented. The GIS data were collected from a variety of sources such as the U.S. Department of Agriculture’s Natural Resources Conservation Service and the state of Nebraska and incorporated into a geodatabase. The ability to layer results from surface and subsurface evaluations was crucial in determining viable sites for potential injection of CO2 generated from GGS. Land use within the study is dominated by agricultural activities and has shallow (< 300 feet), well-protected USDWs. The primary use of groundwater in the study area is for irrigation, which accounts for
2.2. Current and future resource development The five-county study area was also reviewed to determine the potential impact to any current or future mineral or other resource development should a CCS project come to fruition. Although there has been past exploration for hydrocarbons in the study area, most existing exploration and production wells are no longer in operation and have been plugged and abandoned. 2
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Fig. 2. Land cover for the five-county regional analysis (source: U.S. Department of Agriculture Natural Resources Conservation Service, 2016).
Population centers in this rural area of the state are the towns of North Platte (population 24,000), Ogallala (4600), Imperial (1900), Sutherland (1400), and Grant (1300). Together, these communities account for about 65% of the combined populations of these five counties. Agricultural activity represents nearly a quarter of the state’s workforce, generating 25% of the state’s labor income, and accounts for over 40% of the state’s economic output (Thompson et al., 2012). This information and outputs from a “Yale Survey on Climate Change” (Table 1) were then used to develop a community outreach plan that focuses on delivering technically accurate information in a proactive and transparent manner, addressing any concerns identified. The five-county study area is consistently more sceptical of global warming and associated issues than the state of Nebraska or the United States on average. The site-specific plan provides a regional overview focused on roles, approach and guidelines, outreach considerations, project narrative, audiences, strategies, tool kit components, time line, tracking and assessment, and resources. The plan also directs outreach activities to educate and inform the public, public opinion leaders, and decision makers as well as evaluate current and evolving public perception of CCS for the duration of a potential CCS project if implemented. The plan, therefore, incorporates social characterization with engagement strategies and tracking: 1. Social Characterization – detailed baseline of attitudes and concerns pertinent to implementation of the proposed project for the community, opinion leaders, and key groups. 2. Engagement Strategies:
Renewable energy development, primarily wind energy such as the proposed wind project in Keith County (Kansas Energy Information Network, 2018), could potentially occur in the area. It is conceivable that wind energy infrastructure could affect the location of CCS surface installations or vice versa. Most wind energy development, however, occurs in northern and eastern Nebraska. Any future CCS activity would likely be able to avoid these oil/gas or wind energy development areas, thus limiting impacts on resource development. Although no CO2 pipelines exist in the vicinity of GGS, a significant number of petroleum and natural gas pipelines cross the landscape (Fig. 4). If pipeline construction were part of a future CCS project in this region, siting the CO2 pipeline in existing pipeline corridors should be considered to minimize impacts to landowners.
2.3. Community impact To be successful, a CCS project needs to be compatible with the existing social setting of an area as well as with the physical character of the geology and the landscape. This involves efforts to understand, anticipate, and address public perceptions as well as address the issues relevant to a particular community or region. Contact with the general public was not undertaken during this pre-feasibility effort. However, the investigation laid a foundation for constructive public engagement regarding CCS in the region through three actions: 1) proactive engagement with key industry, government, and academic stakeholders; 2) a community impact analysis based on published information on issues and regional social character; and 3) the preparation of a community outreach plan which serves as a source document intended to facilitate future CCS public engagement in the region. As mentioned previously, the five-county study area is largely rural, with a population of nearly 52,000 people (U.S. Census Bureau, 2015).
• Formation of an outreach advisory board. • Regional and local engagement – meetings and other communication to inform Nebraska officials and regional opinion leaders.
3
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Fig. 3. Protected areas in study area.
• Community open house – community meetings hosted by the project team outlining major project milestones. • Landowner engagement – contacts, home visits, and meetings • • • •
partners and key stakeholders. 3. CCS scenario assessment
geared specifically to engage with the many landowners in the project area. Web site – development and maintenance of a project public information Web site featuring basic project explanation and meeting notices as well as fact sheets, video clips, project updates, project partners, and contact information. Tool kit – development of a background document, fact sheets, and frequently asked questions from which project personnel and partners can draw to prepare content for print and electronic media. Community display – dissemination of project posters and informational material in select public locations such as the public library and community government offices. Educator outreach – periodic educational sessions for students and teachers in local schools.
Technical and financial incentives and/or challenges were identified that would face a potential CCS project in western Nebraska. Technical and infrastructure requirements related to CO2 capture, dehydration, compression, transport, injection, and monitoring were investigated. In terms of financial challenges, Nebraska is the only state in the United States served entirely by publicly controlled, nonprofit electric utilities, which are required by law to provide power to the largely rural population at the lowest possible cost. This creates a unique challenge when implementing technologies that require a large financial investment. Emitting 3.24 Mt of CO2 in 2016, GGS Unit 2 (GGS2) alone is large enough to provide sufficient CO2 to meet the CarbonSAFE requirement of storing 50 Mt over a 25-yr time period. A search for other large CO2 point sources within 75 miles of GGS was undertaken to identify additional CO2-sourcing opportunities. Using the U.S. Environmental Protection Agency’s (EPA’s) FLIGHT (Facility Level Information on GreenHouse gases Tool) database, only two additional sources were identified, neither of which is large enough to meaningfully contribute to the 50 Mt of CO2. Therefore, CCS scenarios for western Nebraska focused solely on GGS2.
3. Tracking – documentation of all outreach products, activities, communication, and interactions to measure project engagement. Feedback from project team members and interested stakeholders will help refine outreach activities to improve future outreach efforts as the project moves forward. The outreach plan developed during this project could be modified and adapted for use in future CCS projects in the region. Any future outreach efforts would be conducted through collaboration with the existing CCS coordination team and build upon pre-feasibility activities. In keeping with DOE best practices (U.S. Department of Energy National Energy Technology Laboratory, 2017), outreach task activities would be coordinated with the project development plan and the leadership team and liaise with other outreach efforts through a project outreach advisory group featuring outreach specialists from project
3.1. CCS infrastructure Technologies and infrastructure were identified that would be capable of capturing, dehydrating, compressing, and transporting a potential CO2 stream produced by GGS2. Although several capture technologies were investigated, such as membranes and absorption (both physical and chemical), chemical absorption using amines was 4
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Fig. 4. Pipeline routes in the study area.
The CO2 stream leaving an amine solvent capture system would consist primarily of CO2 and water. The water concentration must be reduced sufficiently to eliminate free water prior to pipeline transport of the CO2, thereby avoiding corrosion issues. Dehydration of a large CO2 stream is typically accomplished using a glycol scrubber such as triethylene glycol (TEG). Following dehydration, the CO2 stream would be compressed to its supercritical state (at least 88 °F and 1180 psi) for transport. Keeping the CO2 supercritical ensures transport in a single phase. For large mass flow rates and discharge pressures up to about 2900 psi, an integrally geared centrifugal compressor is usually
determined to be the most commercially viable technology for capturing CO2 from a power plant, as currently in use at both the Boundary Dam Unit 3 and Petra Nova plants. As a result, amine solvents were further investigated for viability in a potential GGS CCS scenario. Application of an amine solvent capture system at GGS2 would require that a wet flue gas desulfurization (FGD) unit be installed to remove SOx from the flue gas so as to limit the formation of heat-stable salts. The unit’s low-NOx burner and overfire air would likely prevent the formation of NOx in quantities that require additional flue gas treatment. Table 1 Yale Survey.
Beliefs
Risk Perception
Policy Support
Behaviors
Believe global warming is happening. Believe global warming is caused mostly by human activities. Trust climate scientists about global warming. Worried about global warming. Believe global warming is already harming people in the United States. Global warming will harm me personally. Global warming will harm people in the United States. Global warming will harm people in developing countries. Global warming will harm future generations. Global warming will harm plants and animals a great deal. Support fund research into renewable energy sources. Support the regulation of CO2 as a pollutant. Support strict CO2 limits on existing coal-fired power plants. Support the requirement of utilities to produce 20% electricity from renewable sources. Never discuss global warming.
5
Five Counties
Nebraska
USA
56% 42% 61% 47% 37% 32% 50% 54% 62% 59% 77% 66% 46% 56% 74%
64% 48% 66% 51% 44% 33% 51% 57% 65% 63% 81% 71% 63% 62% 70%
69% 52% 70% 56% 50% 38% 56% 61% 69% 68% 80% 74% 68% 65% 64%
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employed. A pipeline is the most economical way to transport large quantities of CO2, and the technology is well known, having been used to transport CO2 in the United States for more than 40 years. A typical CO2 pipeline is made of carbon steel. For a potential scenario of CO2 transported from GGS2, it was assumed based on the potential injection site from the subbasinal analysis (discussed in the next major section) that the pipeline would be about 121 km (75 mi) long, 46 cm (18 in.) in diameter, and buried. Geologic model and simulation efforts estimated that an average of four wells would be needed for a dedicated storage CCS scenario in the study area. The infrastructure required for injection into a saline formation consists primarily of the CO2 supply system (i.e., the pipeline and any infield transport lines that might be needed), the injection wells and their associated instruments, and a SCADA (supervisory control and data acquisition) system to monitor and control injection and storage operations. Assumptions included that geological core and formation fluid samples would be collected to determine mineralogy, porosity, permeability, and geochemical reactivity to CO2 at the injection site. Cement bond and variable-density logs would provide cement bond quality information to ensure the protection of drinking water and reduce the risk of CO2 migration to the shallow subsurface or the surface. Reservoir surveillance to observe and quantify the CO2 plume movement and injection profile, such as borehole-to-surface electromagnetic analysis (determines the salinity contrast between the injected CO2 and native formation fluid) and downhole pressure and temperature gauges, were also included in the assessment of required infrastructure.
Fig. 5. Estimated capture costs for GGS2 using a natural gas-fired auxiliary boiler to provide steam.
reported as dollars per tonne of CO2 captured. Combined construction and operation elements included pipelines, wells, permitting, and monitoring based on advice from Schlumberger Carbon Services. Given the uncertainties and approximations inherent in this pre-feasibility study and the similarity of modeling results for parasitic load and auxiliary boiler options, we can conclude that a best-case scenario for CCS deployment at GGS would incur total costs of approximately $70 per tonne of captured and stored CO2. Avoided costs per tonne, which may be significantly higher, were not calculated.
3.3. Financial incentives and revenue assessment
3.2. CCS investment
As mentioned previously, Nebraska is served entirely by publicly controlled, nonprofit electric utilities required by law to provide power at the lowest possible cost, creating a unique challenge with regard to implementing high-investment technologies. Therefore, possible revenue from potential CO2 production at GGS2 was investigated. Tax credits available through the Bipartisan Budget Act of 2018 under the Enhancement of Carbon Dioxide Sequestration Credit (formerly known and hereafter referred to as Section 45Q) were evaluated as an opportunity for CO2 suppliers to potentially capitalize on a supplemental market. Utilizing Section 45Q tax credits as a marketing tool would depend greatly on agreed-upon negotiating terms between the CO2 supplier (e.g., NPPD), the CO2 purchaser, or other stakeholders/partners in the CCUS value chain. Although NPPD, as a public entity, does not qualify directly for Section 45Q, a pathway to market could exist where operator(s) or other partners/stakeholders in the CCUS value chain for dedicated storage or enhanced oil recovery (EOR) would be willing to purchase CO2 from GGS2 and store in a saline formation or at an oil field(s) associated with EOR operations. In this case, the operator (s) or other partners/stakeholders in the CCUS value chain would be responsible for claiming the tax credits as well as adhering to any CO2monitoring requirements in the subsurface. The Section 45Q tax credit amounts are established by linear interpolation from $12.83 to $35 per tonne for EOR and from $22.66 to $50 per tonne for dedicated storage each calendar year after 2016 and before 2027 (Congress.gov, 2018). After 2026, the tax credits increase according to inflation as, presumably, would the cost of CCS. Compared to the minimum estimated cost of approximately $70/tonne for a CCS project, tax credits alone are not a sufficient resource for CCS investment, particularly for a dedicated storage scenario. Further revenue assessment focused on potential EOR markets. At the current estimated price of CO2 of $25 to $35/tonne, the combined value of the Section 45Q tax credit and the direct sale price of the CO2 could range from $60 to $70/tonne. At a $70/tonne value, the estimated CCS cost may be offset; however, further investigation is recommended as many details are still unclear as to how the credit can be claimed and by whom.
System requirements for the application of CO2 capture at GGS2 using amine solvents were obtained using the DOE National Energy Technology Laboratory (NETL)-funded Carnegie-Mellon University Integrated Environmental Control Model (IECM), a modeling program that systematically analyzes the cost and performance of emission control equipment at coal-fired power plants. Twelve retrofit capture scenarios were modeled for GGS2: all combinations of 65%, 80%, and 90% capture with and without an auxiliary boiler for the two commercial amine solvent technologies that are available in IECM, namely, Cansolv and Fluor’s Econamine FG + . A 65% capture scenario is the minimum capture level needed at GGS2 to average 2 Mt per year CO2 capture output (i.e., to meet the CarbonSAFE Program minimum 50-Mt CCS requirement over a 25-yr period), while a capture level of 90% is considered to be “full capture.” An intermediate level of 80% was also explored to determine if a capture cost minimum existed. IECM was used to estimate capture costs per tonne of a nearly pure CO2 stream from GGS2, including both capital and operating expenses. As GGS2 does not have a wet FGD unit, the cost of reducing SOx concentrations was also included. The power for these extra facilities may be supplied by a parasitic load at the plant or by employing an auxiliary boiler. Note that the purpose of the modeling at this pre-feasibility stage was to obtain reasonable estimates of the cost of carbon capture at GGS. The technology choice between auxiliary boiler versus parasitic load would depend on various factors, including the degree to which GGS operates at design capacity, and is thus beyond the scope of this prefeasibility study. Note also that we have not calculated avoided costs per tonne of captured CO2, which would need to allow for CO2 emissions from an auxiliary boiler. Fig. 5 compares capture costs against varying percentages of CO2 capture for both Econamine FG + and Cansolv amine systems, including costs associated with an auxiliary boiler. Although the cost differential between the two amine types is significant, both show minimum cost at around 82% capture rates. Note also that the figure does not show avoided capture costs, which would need to allow for CO2 emissions from the auxiliary boiler. Table 2 presents best-case scenario costs for the full CCS chain, 6
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Table 2 Optimal CCS Project Cost for GGS.a Component
Capture + Parasitic Load Costs, $/tonne
Capture + Auxiliary Boiler Costs, $/tonne
FG+ 80% Capture Pipelineb Four Class VI Injection Wellsc One Stratigraphic Test Wellc One Monitor Wellc 12.25-mi2 3-D Seismic Surveyc Permittingd Total
68 1.3 0.32 0.06 0.10 0.01 0.24 70
65 1.3 0.32 0.06 0.10 0.01 0.24 67
a b c d
All values reported to two significant figures. DOE NETL CO2 Model: Assumes 18-inch, 75-mile pipeline with injection at 1300 psi over 30 years in 2014 U.S. dollars. Calculated from Schlumberger estimate. Assumes permitting costs for four Class VI injection wells.
Colorado. The eastern extent of the storage resource models was dictated by the shallowest part of each reservoir greater than 3000 ft in depth. Because of the low data availability in the study area for the current pre-feasibility study, these storage resource assessments were conducted at the play level according to the Society of Petroleum Engineers (SPE, 2016) draft CO2 storage resources management system (SRMS). This SRMS classifies storage resources according to project maturity, where an increasing amount of data increases the chance of eventual commercialization and screens out those resources that do not meet technical, economic, or regulatory standards. Two Cloverly Formation models were used: one at a regional scale and the second a smaller area clipped out for numerical simulation. A modified DOE method of calculating CO2 storage potential in saline formations was used for each model (Peck et al., 2014) (Tables 3 and 4). Three probability distributions of formation properties (optimistic [P90], average [P50], and conservative [P10]) were considered. Most of the potential storage resource in the Cloverly regional model lies in the southwestern part of the study area and the thickest part of the formation (Fig. 6; Table 3). Facies distribution within the geologic model is a highly simplified fluvial system of fluvial sandstones interbedded with shales and represents a scenario with limited hydraulic connectivity among sandstone bodies. Digitized gamma ray logs from 52 wells were upscaled into the model grid and used to condition the facies distribution for this prefeasibility study. Sandstone channel widths from Antia et al., 2011were used to constrain the size of sandstone bodies.
3.4. Regulatory challenges The state of Nebraska has not officially contemplated or promulgated statutes regarding CCS at this time. No regulatory environment currently exists for pore space ownership, financial assurance, closure, or long-term liability. In addition, no state regulatory agency has been selected for primacy, rule making, and oversight should statutes related to CCS be introduced. EPA administers the Underground Injection Control (UIC) Program that consists of a variety of measures to ensure that all USDWs are protected. As a result, existing federal regulations currently guide any CCS efforts and long-term liability in Nebraska. Should the regulatory environment change and/or if an academic, public, private, or commercial entity proposes a CCS project, regulatory certainty would likely be a multiyear process for development of legislative statutes and rule making from state agencies. 4. Subbasinal analysis 4.1. Reservoir and seal characteristics The Lower Cretaceous Cloverly Formation (fluvial depositional environment) was characterized at a pre-feasibility level to assess its efficacy as a CO2 saline storage reservoir. This formation is continuous within the Nebraska–Colorado study area shown in Fig. 6, thickens and deepens to the southwest into the Denver–Julesburg Basin, and thins and shallows to the east. Porosity ranges from 4 to 33 percent and permeability from 0.01 to 1700 millidarcies based on core data from the Nebraska Oil and Gas Conservation Commission. Net-to-gross ratio approximates 0.5 across the extent of the Dakota Group (e.g., Covault et al., 2012; Volk, 1969). Where applicable and where data were available, the extent of the potential reservoir was limited to areas where the top of the reservoir is greater than 3000 ft deep, the formation water has a salinity greater than 10,000 ppm, and a continuous sealing formation (the overlying Skull Creek Shale) is present. Underlying sealing strata include the Cretaceous Fuson Shale, Jurassic Morrison Formation, and multiple Upper Permian evaporate deposits. Structural data were retrieved from publicly available state databases; because stratigraphic data collection in Nebraska is geographically clustered according to oil and gas production, structural uncertainty is larger across the middle of the study area where fewer wells are. Likewise, petrophysical properties used to populate geologic models were extrapolated from a limited number of digital well logs and core measurements, increasing the amount of uncertainty.
4.3. Dynamic simulation of CO2 storage in the Cloverly Sandstone Dynamic flow simulation was conducted to assess the prefeasibility of storing 50 Mt of CO2 over 25 years in the Cloverly Formation. An area in Perkins and Chase Counties, Nebraska, was chosen because this location is within the state boundaries, relatively close to GGS, and would not require pipeline development over major rivers. Given the high degree of uncertainty in the geologic heterogeneity of the sandstone, three P90, P50, and P10 probability distributions of formation properties were considered for numerical simulations (Table 5). Specific goals of the simulation study were to assess:
• Potential locations and number of injection wells required to inject 50 Mt of CO over 25 years in the Cloverly Formation. • Wellhead pressure (WHP) ranges for injection wells and the asso2
• •
4.2. Prospective storage resource assessment A regional prospective storage resource assessment was performed for the area of the Nebraska panhandle and the northeastern corner of 7
ciated parameter impact on WHP via a sensitivity analysis, including an optimum WHP to inform infrastructure design. Area of review (AOR) determined by the extent of CO2 and pressure plumes during and after injection. Postinjection CO2 plume migration and pressure stabilization.
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Fig. 6. Nebraska Cloverly Formation CO2 prospective storage resource assessment (P50 estimate), summed vertically. Northeast–southwest-trending variation in storage represents interbedded sandstones and shales with accompanying porosity distributions.
4.4. Simulation model development
Table 3 Cloverly Formation Prospective Storage Resource Estimates for Western Nebraska and Northeastern Colorado Using Esaline Values from Peck et al., 2014. Esaline, %** Cloverly Formation Model* Regional Simulation
Computer Modelling Group Ltd.’s (CMG’s) GEM simulator and CMOST sensitivity analysis tool were used to simulate CO2 injection into the Cloverly, perform a sensitivity study on WHP, and examine a postinjection scenario. The simulation fluid model includes two components, CO2 and brine, properties and relationships between which were taken from Harvey’s correlation for Henry’s Law constants (Harvey, 1996), correlations from Rowe and Chow (1970) and Kestin et al., 1981, and a CO2–brine relative permeability table from Bennion and Bachu (2005 and 2007). The primary constraint for injection was a maximum daily total injection of 5500 tonnes of CO2 based on the capture target of the facility (2 Mt of CO2 annually). A maximum bottomhole pressure (BHP) of 2100 psi was used as a secondary constraint to ensure injection remained at least 10% below the fracture pressure of the formation (using a 0.7-psi/ft fracture pressure gradient which we
Potential Storage Estimate, Mt
P10
P50
P90
P10
P50
P90
7.4 7.4
14 14
24 24
20,800 586
39,300 1110
67,400 1900
* Storage potential was calculated for two variations of the Cloverly Formation model based on two model sizes (regional and the geographically limited simulation model). ** Esaline is the efficiency factor applied to the total porosity to produce storage potential estimates (discussed below); known factors included net area, thickness, and porosity.
Table 4 Model Parameters Used for Volumetric Storage Estimates. Cloverly Formation Model
Area, mi2
Cell Size, ft
Reservoir Porosity, %
Reservoir Temperature, °C
Pressure Gradient, psi/ft
Regional Simulation*
30,600 839
1000 × 1000 1000 × 1000
18.6 18.6
45.7 45.7
0.6 0.6
* The Cloverly simulation model was clipped out of the Cloverly regional model, resulting in a smaller area but the same property distributions within that area. 8
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Table 5 Arithmetic Mean Values for Porosity and Permeability of Sand and Shale in the Three Models. Model Property
P90
Facies Sandstone Shale*
Porosity, % 25.0 12.1
P50 Permeability, mD 425 0.00001
P10
Porosity, % 18.6 9.72
Permeability, mD 211 0.00001
Porosity, % 16.0 7.95
Permeability, mD 161 0.00001
* Shale permeability was set to a value close but not equal to zero for computational efficiency.
For the P90 and P50 models, injection tubing size had the greatest impact on WHP (larger tubing for injection can significantly reduce the required WHP), as the injection rates considered per well are higher in both models. The other more influential parameters are wellhead injection temperature and tubing relative roughness following the tubing size in both models. Borehole temperature had no effect on WHP. Higher injection pressure is required to compress CO2 at a higher injection temperature because CO2 is less dense at a higher temperature. Smaller tubing roughness is related to lower injection pressure because of the lower pressure loss (friction) in the tubing during injection. As for the P10 model, where a considerably lower injection rate per well is applied because of the lower injectivity of the model, the wellhead temperature has the greatest effect on WHP, rather than the size of the injection tubing. Based on the information obtained from the sensitivity analysis, a larger tubing size of 4.5 in. (the required wellhead injection pressure would be lower at 1300 psia) was suggested because maintaining injection at a lower pressure is more economical for the infrastructure design (gas compression system).
consider to be relatively conservative). 4.5. Identification of potential location for CO2 injection The results from the numerical simulation efforts indicated that two, four, and 14 injection wells are required for the respective P90, P50, and P10 models to store 50 Mt of CO2 (annually 2 Mt or daily, on average, 5500 tonnes of CO2). The number of injection wells required for 50 Mt of CO2 storage intrinsically increases with poorer formation properties as gas injectivity per well decreases from P90 wells to P10 wells (Fig. 7). Injection wells were placed in the clean, larger, and thicker sand bodies in the model. Extra effort was made to reduce the distance between the injection wells to have a smaller surface footprint of CO2 injection and place them in a more uniform spacing. However, because of the extensive presence of shales in the model and the pressure interference from the very high injected volume of CO2, the effort was challenging to achieve. The well spacing between two injection wells in the P90 model is about 2.5 miles. The well spacing (between two adjacent wells) for the P50 and P10 models is approximately 6–13.5 and 3.5–8 miles, respectively.
4.7. AOR determination 4.6. Sensitivity analysis on WHP The extents of CO2 plume (lateral distribution of CO2 saturation) and pressure plume (pressure buildup in the formation) were evaluated at the end of 25 years of potential injection into the Cloverly Sandstone to determine the size of AOR that will be necessary for planning a MVA (monitoring, verification, and accounting) program for CO2 storage. Approved MVA plans are typically required for permitting, especially for dedicated CO2 storage (i.e., EPA UIC Class VI). The predicted CO2 plume extent was quantified in gas per unit area in total, which is a product of CO2 saturation, porosity, and thickness,
Following the base simulation work of determining the number of wells required and their potential locations for CO2 injection, a sensitivity analysis was conducted using CMG CMOST to determine the relative effects of parameters greatly impacting WHP, ranges of predicted or simulated WHP values, and an optimum wellhead injection pressure to inform infrastructure design and corresponding economic analysis. The parameters included the wellhead temperature, bottomhole temperature, tubing size, and tubing relative roughness.
Fig. 7. Simulated CO2 plumes (in plan view) for the P90, P50, and P10 models (from left to right) at the end of a potential 25-year CO2 injection operation. Note: the injection wells are labeled “DK” (Dakota), as the Cloverly Formation is in the lower Dakota Group. 9
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Fig. 8. Simulated pressure plumes (in plan view) for the P90, P50, and P10 models (from left to right) at the end of a potential 25-year CO2 injection operation. Note: the lower limit in the pressure scale is bounded by the pressure threshold value of 138 psi for determining the AOR.
Fig. 9. The simulated postinjection CO2 plume (in plan view) after 100 years of postinjection (left) and pressure plume extent after 40 years of postinjection (right). Note: the lower limit in the pressure scale is bounded by the pressure threshold value of 138 psi for determining the AOR.
high shale content in the model did not allow pressure to dissipate uniformly, resulting in directional and larger pressure plume extents, as shown in Fig. 8. The size of the pressure plume extent for the P90 model was the smallest, covering an area of about 20 × 20 miles (west–east and north–south) at the end of the 25-year injection period. As for the P50 model, the pressure plume extent was considerably larger relative to the P90 plume, spreading out about 21 × 30 miles. The predicted pressure plume extent in the P10 model is largest, covering an area of about 22 × 32 miles. As shown in Figs. 7 and 8, the pressure plume extent was much greater than the extent of the CO2 plume; hence, the pressure plume will dictate the AOR size for CO2 injection in the Cloverly Formation. The simulated extent of the AOR in the formation for potentially storing 50 Mt of CO2 would be approximately 20 × 20 (smallest) and 22 × 32 (largest) miles. These AOR sizes would be conservative ones as a hypothetical open conduit is considered in the EPA calculation approach.
as shown in Eq. 1: CO2 per Unit Area – Total (ft) = CO2 Saturation × Porosity × Thickness (1) Fig. 7 shows the CO2 plume extents for all three models after 50 Mt of CO2 was injected over 25 years. The plume diameters approximated 3.5, 3, and 2 miles around each injection well, respectively, for the P90, P50, and P10 models. The pressure front or threshold was calculated using the EPA pressure front equation (U.S. Environmental Protection Agency, 2011). The pressure threshold, or the pressure, within the injection zone, great enough to force fluids from within the injection zone through a hypothetical open conduit into any overlying USDW, was calculated at 138 psi for the region modeled for this project. Fig. 8 shows the pressure increase and extent in each model as a result of 25 years of injection for the layer with the highest and largest (laterally) pressure extent. The simulated pressure plume was extensive in all three models because the 10
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conducted here have a relatively high degree of uncertainty, relying heavily on generalized subsurface characteristics as a result of a lack of site-specific data. Acquisition of site-specific data (including well log and core data) would provide opportunity to refine the models discussed here, enable more accurate predictive simulations, and decrease subsurface technical risks posed by geologic uncertainty. 5. Conclusions In summary, the work undertaken in this Phase 1 pre-feasibility study has shown that western Nebraska has potential to host a commercial-scale CCS project, including a dedicated storage container for 50 Mt of CO2. However, the following key challenges would need to be overcome: 1 The business case for deploying CCS projects is uncertain; recently announced federal tax credits might not compensate for the cost of CCS deployment at a coal-fired power station such as GGS. Sales of CO2 for EOR could provide additional revenue, but the combined benefits of tax credits plus EOR sales still may not cover the full costs of a CCS project at GGS, as estimated by this pre-feasibility study. 2 The potential 50-Mt CO2 dedicated storage container defined in this pre-feasibility study should be regarded as having a relatively low level of readiness to support a CCS project. Significant further work, including exploratory drilling and geophysical surveys, would be required to provide sufficient certainty to support an investment decision in a Nebraska CCS effort. 3 Public outreach would be a vital element for CCS implementation in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.
Fig. 10. The cumulative injected, dissolved, and free CO2 in the Cloverly Formation during simulation.
4.8. Postinjection simulation As part of numerical simulation efforts for this project, postinjection was also investigated using the P50 (moderate) model, after the 25-year CO2 injection halted to understand CO2 plume migration and evolution and pressure stabilization. After a period of 100 year’s postinjection, the CO2 plume diameter around each well in the P50 model had grown by 1 mile to approximately 4 miles, indicating that the CO2 is moving at a rate of approximately 50 ft per year within the formation. The remaining pressure buildup was not significant compared to the estimated pressure threshold, almost completely disappearing at the end of 100 year’s postinjection. The remaining pressure buildup (maximum value of 350 psi) at the end of 40 years of postinjection is shown in Fig. 9, compared to the pressure plume at the end of the 25-year injection period, shown in Fig. 8 (the middle image, P50 model). The pressure plume became significantly smaller beyond 40 years of postinjection. At the end of a simulated 100-year postinjection, the fate of the injected CO2 (how the injected CO2 is stored in the sandstone) was also assessed. CO2 storage is known to involve four different trapping mechanisms: hydrodynamic trapping, residual trapping, solubility trapping, and mineral trapping (Gunter et al., 1997). Injected CO2 will reside in the storage formation in the free-gas phase (through hydrodynamic and residual trapping), as dissolved in formation brine (through solubility trapping), and in immobile solid phase (through mineral trapping). The effects of mineral trapping were not included in the numerical simulations conducted in this study, as modeling mineral reactions adds to computational intensity. Fig. 10 indicates the cumulative injected CO2, dissolved CO2, and free CO2 in the Cloverly Sandstone over the injection and postinjection periods. During the postinjection period after the 25-year injection was halted, the amount of dissolved CO2 gradually increases with decreasing free CO2 migrating away from each well. The majority of the injected CO2 (approximately 90%) will be stored as free CO2 in the formation at the end of the 100-year postinjection period. Approximately 60% of the free CO2 would be mobile (hydrodynamically trapped), and 40% of the free CO2 would be immobile (residually trapped), assuming a residual CO2 saturation value of 0.2.
Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. Acknowledgments This work was funded by the US Department of Energy and Nebraska Public Power District. Technical support was provided by Schlumberger Carbon Services and CMG. References Antia, J., Fielding, C.R., Joeckel, R.M., 2011. Multiple cycles of wave-dominated estuarine deposits in low-accomodation settings, cretaceous J sandstone, northwestern Nebraska. AAPG Bull. 95 (7), 1227–1256. Bennion, D.B., Bachu, S., 2005. Relative permeability characteristics for supercritical CO2 displacing water in a variety of potential sequestration zones: SPE 95547. SPE Annual Technical Conference and Exhibition, 9–12 October, Dallas, Texas. Bennion, D.B., Bachu, S., 2007. Permeability and relative permeability measurements at reservoir conditions for CO2-water systems in ultra-low permeability confining caprocks. Soc. Pet. Eng. https://doi.org/10.2118/106995-MS. Census Bureau, U.S., 2015. American Community Survey 5-year Data Profiles. (Accessed April 2018). www.census.gov/acs/www/data/data-tables-and-tools/data-profiles/ 2015/.
4.9. Dynamic simulation discussion The simulation results achieved in this prefeasibility study show the potential of the Cloverly Sandstone to sequester 50 Mt of CO2 over 25 years; however, the resulting AOR dictated by the pressure plume would be larger than ideal for a monitoring program because of the high shale content in the sandstone. The models and simulations 11
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2014. A workflow to determine CO2 storage potential in deep saline formations. Energy Procedia 63, 5231–5238. Rowe, A., Chou, J., 1970. Pressure–volume–temperature-concentration relation of aqueous NaCl solutions. J. Chem. Eng. Data 15 (1), 61–66. Society or Petroleum Engineers, 2016. Draft CO2 Storage Resources Management System. (Accessed 2018). www.spe.org/industry/CO2-storage-resources-managementsystem.php. Thompson, E., Johnson, B., Giri, A., 2012. The 2010 Economic Impact Of The Nebraska Agricultural Production Complex: Department Of Agricultural Economics At University Of Nebraska Lincoln, Report No. 192. June 2012. . U.S. Department of Agriculture Natural Resources Conservation Service, 2016. Land Cover Dataset From NRCS Data Gateway Website. https://datagateway.nrcs.usda. gov/. U.S. Department of Energy National Energy Technology Laboratory, 2017. Public Outreach and Education for Geologic Storage Projects. 2d ed.: Best practices manual, DOE/NETL-2017/1845, June 2017 (accessed 2018). www.netl.doe.gov/File %20Library/Research/Carbon-Storage/Project-Portfolio/BPM_PublicOutreach.pdf. U.S. Environmental Protection Agency, 2011. Underground Injection Control (UIC) Program Class VI Well Area of Review Evaluation and Corrective Action Guidance for Owners and Operators. Volk, R.W., 1969. Petroleum potential of eastern Colorado, western Nebraska, southeastern Wyoming, and northeastern New Mexico. In: Cram, I.H. (Ed.), Future Petroleum Provinces of the United States—their Geology and Potential. AAPG Memoir, pp. 15.
Congress.gov, 2018. 115th Congress of the United States of America, House Bill, H.R. 1892, Section 45Q, Credit for Carbon Oxide Sequestration. BILLS-115hr1892enr.pdf (Accessed April 2018).. www.congress.gov/115/bills/hr1892/. Covault, J.A., Buursink, W.H., Craddock, M.D., Blondes, M.S., Gosai, M.A., Freeman, P.A., 2012. Geologic framework for the national assessment of carbon dioxide storage resources—Bighorn Basin, Wyoming and Montana. In: Warwick, P.D., Corum, M.D. (Eds.), Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources. USGS Open-File Report 2012-1024-A. Gunter, W.D., Wiwchar, B., Perkins, E.H., 1997. Aquifer disposal of CO2-rich greenhouse gases—extension of the time scale experiment for CO2 sequestrating reactions by geochemical modeling. Mineral. Petrol. 59, 121–140. Harvey, A., 1996. Semi-empirical correlation for Henry’s constants over large temperature ranges. Am. Inst. Chem. Eng. J. 42, 1491. Johnson, B., Thompson, C., Giri, A., Van NewKirk, S., 2011. Nebraska irrigation fact sheet. Dept. Agric. Econ (accessed June 2018). https://agecon.unl.edu/a9fcd9024da9-4c3f-9e04-c8b56a9b22c7.pdf. Kansas Energy Information Network, 2018. Existing Nebraska Wind Farms. (accessed April 2018). www.kansasenergy.org/NE_wind_projects_case.htm. Kestin, J., Khalifa, H., Correia, R., 1981. Tables of dynamic and kinematic viscosity of aqueous NaCl solutions in the temperature range 20°–150°C and the pressure range 0.1– 35 MPa. J. Phys. Chem. Ref. Data 10, 71–87. Maupin, M.A., Kenny, J.F., Hutson, S.S., Lovelace, J.K., Barber, N.L., Linsey, K.S., 2014. Estimated use of water in the United States in 2010. U.S. Geol. Surv. Circ. 1405, 56. https://doi.org/10.3133/cir1405. Peck, W.D., Glazewski, K.A., Klenner, R.C.L., Gorecki, C.D., Steadman, E.N., Harju, J.A.,
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