Assessing Key Drivers Impacting the Cost to Deploy Integrated CO2 Capture, Utilization, Transportation, and Storage (CCUS)

Transcription

1 Assessing Key Drivers Impacting the Cost to Deploy Integrated CO2 Capture, Utilization, Transportation, and Storage (CCUS) Derek Vikara a,1, Chung Yan Shih b, Allison Guinan b, ShangMin Lin c, Anna Wendt a, Timothy Grant d, and Peter Balash d a KeyLogic Systems, Inc., National Energy Technology Laboratory, 626 Cochrans Mill Road, Pittsburgh, PA , United States b Leidos, National Energy Technology Laboratory, 626 Cochrans Mill Road, Pittsburgh, PA , United States c Deloitte, National Energy Technology Laboratory, 626 Cochrans Mill Road, Pittsburgh, PA , United States d United States Department of Energy, National Energy Technology Laboratory, 626 Cochrans Mill Road, Pittsburgh, PA , United States Abstract Carbon capture, utilization, and storage (CCUS) is considered by many to be essential to global efforts in reducing CO2 emissions from anthropogenic sources [1, 2, 3]. The International Energy Agency s (IEA) 2017 Energy Technology Perspectives indicates that CCUS (noted as just CCS) is vital in both their 2 C Scenario (2DS) and Beyond 2 C Scenario (B2DS) to decrease CO2 emissions [4]. However, deploying CCUS at the volume projected by the IEA would require more CCUS infrastructure and technology deployment than what currently exists today [4]. Furthermore, organizations like the Intergovernmental Panel on Climate Change, the IEA Greenhouse Gas R&D Programme, and the United States (U.S.) Environmental Protection Agency (EPA), among others, have all strongly endorsed CCUS technologies as part of the solution to reducing anthropogenic CO2 emissions [5]. While several small- and large-scale CCUS projects have deployed throughout the world that have demonstrated that significant CO2 emissions reductions are capable, broader CCUS deployment still faces challenges pertaining to cost effectiveness, regulations, and financing [6, 7]. In the United States specifically, widespread deployment of CCUS may depend on a combination of stable economic incentives and continued research and development (R&D) advancements to make the technology economical [8]. Assessing how to meet stringent federal and state-driven regulations and taking advantage of emerging financial incentives (like the modified 45Q tax credit and updated corporate tax structures) is a challenge that current and future CCUS site operations face [8, 9]. Attaining realistic costs for implementing CCUS requires further understanding of the specific cost drivers associated with each link of the CCUS value chain (i.e., capture, transport, and storage). The U.S. Department of Energy s (DOE) National Energy Technology Laboratory (NETL) has analyzed several of the more prominent challenges inhibiting broader CCUS deployment using NETLdeveloped resources that estimate critical cost drivers associated with CCUS (specifically cost drivers related to CO2 capture, CO2 transport, and CO2 storage). This paper features the results of these analyses, which provide perspective surrounding the economics associated with overcoming CCUS deployment challenges and assess the cost drivers that impact the entire CCUS value chain. In turn, these analyses provide approaches for assessing critical deployment challenges for CCUS 1 Corresponding author. Phone: , address: derek.vikara@netl.doe.gov. 1

2 and help in identifying areas where future CCUS R&D may focus to be most impactful in ultimately improving eventual pilot and commercial-scale deployment of the technology. 1.0 Introduction CCUS is considered by many to be essential to global efforts in reducing CO2 emissions from anthropogenic sources [2, 3]. According to the Intergovernmental Panel on Climate Change, CO2 capture coupled with geologic storage of CO2 represents the best and most likely short-to-medium term option for removing significant amounts of CO2 from anthropogenically-derived CO2 sources prior to release to the atmosphere [3]. For instance, energy market scenarios like IEA s 2DS or Sustainable Development Scenario, along with the studies done by Ioakimidis et al., Institute of Physical Energetics, and Weilong et al. highlight the prominence of CCUS in broader energy economy forecasts [4, 10, 11, 12, 13]. More specifically, IEA s 2DS projection shows that CCUS is critical in the world-wide energy mix, accounting for 16 percent of total CO2 emission reductions when compared to the study s Reference Technology Scenario [14]. With the growing energy market and need for affordable, secure, resilient, and reliable sources of clean energy both domestically and internationally, CCUS is one of many emerging strategies for managing or reducing the anthropogenic emissions of CO2 into the atmosphere and, in turn, the concentration of atmospheric CO2 from various sources including fossil fuel-fired power plants [15, 16]. CCUS essentially involves a sequence of events, which collectively define the CCUS value chain that includes (1) the separation and capture of CO2 from industrial and power-generation sources, purifying the CO2 stream, and compressing it for transport; (2) transporting the CO2 to a geologic storage site or enhanced oil recovery (EOR) project via pipeline (or possibly via ship in offshore storage settings) for storage in a geologic storage reservoir; and (3) injecting (or beneficially reusing or utilizing) the delivered CO2 into a suitable onshore or offshore geologic storage or EOR reservoir where the CO2 can be isolated from the atmosphere [5]. Figure 1 demonstrates the CCUS concept for an onshore setting. CCUS comprises a suite of technologies that can be used to manage CO2 emissions from various industry types, including power (i.e., fossil and biofuel-based power production) and industrial manufacturing (i.e., cement plants, ethanol plants, fertilizer plants, and chemical refining) [3]. 2

3 Figure 1. Conceptual diagram of captured CO2 from a power plant being stored in diverse types of storage formations specific to an onshore setting (from Ohio Department of Natural Resources website [17]). The United States has approximately 6,050 stationary sources of anthropogenic CO2 that emit over 2,800 million metric tons (tonnes) of CO2 per year (Mt/yr). Most of those CO2 emissions are from sources associated with electricity production (roughly 70 percent) [5]. Saline-bearing formations, depleted oil and gas reservoirs, and unmineable coal seams are all considered promising formations from which to develop reservoirs for storage of captured CO2 (Figure 1) each with their own unique benefits and associated challenges. These types of storage formations within which storage reservoirs can be developed are found in numerous basins throughout the United States and have the resource potential to sequester CO2 emissions from large and small point sources into the distant future [18]. Saline-bearing formations, in particular, present the greatest resource potential to store anthropogenic CO2 because of their vast areal extent across the sedimentary basins of the United States. Their potential storage capacities are significant unproven resources that are widely distributed and possibly co-located with many stationary sources of CO2 (Figure 2). 3

4 Figure 2. CO2 sources (with types depicted by colored circles) and their proximity to saline storage reservoirs (green outlines) within the U.S. lower 48 states, Alaska, and Hawaii. The size of the CO2 sources illustrates annual CO2 emissions (Mt) with ranges depicted by gray circles (data from the National Carbon Sequestration Database and Geographic Information System [NATCARB] [19]). From work conducted by NETL and the Regional Carbon Sequestration Partnerships (RCSP), the potential CO2 storage resource estimates for saline-bearing formations in the United States (and across their study area in parts of Canada) range from 2,379 to 21,633 billion tonnes [5]. 2 Should half of this resource potential be proven, the potential for CO2 storage would represent approximately 400 to 3,750 years worth of CO2 CCUS activity based on the volume emitted from stationary sources in the United States [5]. The technology components that make up the CCUS value chain are at various stages of commercial readiness, and only a few fully integrated projects that capture and store large volumes of CO2 are underway worldwide [16]. However, the small- and large-scale CCUS projects that have been completed or are currently in operation [20, 21, 22] throughout the world have demonstrated that significant CO2 emissions reductions are possible. In 2018, NETL had identified over 300 existing, planned, or recently-completed CCUS-related projects (ranging from pilot testing to commercial-scale) across the globe [20]. The Global CCS Institute indicates that 37 CCS 2 CO2 storage resource assessments are calculated from low (P10) and high (P90) efficiency factors based on the methodology presented by Goodman et al., 2011 [61]. 4

5 projects across the globe are large-scale (> 300,000 tonnes CO2 capture per year) 18 of which are currently in operation, while the others are under construction or in development [23]. CCUS has been and continues to be successfully demonstrated throughout the world. As R&D activities continue to advance CCUS toward commercialization, demonstration projects that implement and validate safe and effective CO2 injection and storage technologies become critically important. Examples of successful CCUS projects include the Sleipner Project (Norway offshore), the Illinois Industrial Carbon Capture and Storage (ICCS) Project (United States onshore), and Petra Nova Carbon Capture Project (United States onshore), as well as several field demonstration projects implemented through the U.S. DOE RCSP Initiative (United States and Canada onshore) [18, 20]. The offshore Sleipner Project, a natural gas production operation where CO2 is separated from the natural gas stream, was the world s first commercial CCUS project for storing CO2 in a deep saline reservoir. A total of approximately 16.2 Mt of CO2 has been injected from its inception in 1996 to June 2016, with the purity of CO2 at around 99 percent. The estimated total volume of CO2 anticipated to be injected at the Sleipner Project is around 17.5 Mt by 2020 [24]. The ICCS Project captures CO2 from an ethanol production facility and stores it in a deep saline-bearing reservoir in an onshore setting. The ICCS Project expands the operations of the Illinois Basin Decatur Project toward commercial scale and is the first project to operate with a U.S. EPA s Underground Injection Control (UIC) Class VI injection well permit [25, 26]. The estimated total volume of CO2 anticipated to be injected at the ICCS Project is 5 Mt over three years [25]; since April 2017, approximately 310,000 tonnes of CO2 has been injected and stored [26]. The Petra Nova Project s goal is to advance fully-integrated CCUS technologies from the demonstration stage to commercial viability [27]. The Petra Nova project is designed to capture, utilize, and store 1.4 Mt of CO2 annually for CO2 enhanced oil recovery (EOR), making it the largest postcombustion CO2 capture project installed on an existing coal-fueled power plant (i.e., W.A. Parish plant) [28]. This project captures CO2 from a slipstream of flue gas from W.A. Parish plant s Unit 8. The CO2 captured is sent via pipeline to the West Ranch Oil Field on the Texas Gulf Coast. As of October 2017, the project has captured more than 1 million tons (~907,000 tonnes) of CO2 and increased oil production at the West Ranch Oil Field from an initial rate of 300 barrels per day to approximately 4,000 barrels per day [29]. Significant CCUS project research is conducted under the RCSP Initiative. Both small- and largescale CO2 storage field projects across the United States (and Canada) have been completed or are currently underway that focus on identifying and characterizing specific CCUS opportunities, as well as developing and testing relevant technology needed to track and verify the presence and stability of the CO2 plume in its reservoir. The RCSPs comprise seven public/private partnerships and span 43 U.S. states and four Canadian provinces [16, 18, 30]. These projects deployed in different formations evaluating different depositional environments in both saline and oil and gas reservoirs; several are integrating anthropogenic CO2 capture and subsequent storage from CO2 sources such as power plants, ethanol generation, and natural gas (NG) processing. Over 14 Mt of CO2 has been safety injected and stored or injected across 27 different projects [2, 22]. While several small- and large-scale CCUS projects utilizing storage in saline-bearing formations have deployed throughout the world and have demonstrated that considerable CO2 emissions reductions are capable, broader CCUS deployment has not yet occurred and still faces many unique challenges [6, 7, 31]. For one example, deploying integrated CCUS at large-scale is still considered 5

6 too cost intensive [32, 33]. Successful projects to date have overcome this hurdle by either receiving government financial support separate from typical commercial models (i.e., the Illinois Basin Decatur Project [34], the ICCS Project [35], and projects part of the RCSP Initiative) or identifying a role for CCUS as part of a broader commercial business case (i.e., the Statoil Sleipner Project which stores CO2 separated from NG production to avoid additional Norwegian taxes for emitting the CO2 [36]). Another challenge lies in generating reliable estimates of costs associated with future commercial-scale CCUS operations. Most known costs from literature associated with CO2 storage in saline-bearing formations are largely based on research projects at the pilot-scale (i.e., first-of-a-kind ). Many CCUS R&D field projects engage in monitoring and modeling activities above what regulations require at a minimum and would be expected commercially. Additionally, CCUS R&D field projects may test new and emerging technologies (instead of only state-of-the-art/ off-the-shelf tools and techniques) to assess their usefulness in CCUS applications [37]. Therefore, costs associated with field demonstration projects are not necessarily translatable for estimating the costs of future commercial CCUS projects. Additionally, substantial legal, regulatory, and policy-based uncertainty pertaining to CCUS still exists that adds ambiguity and risk for potential investors and companies that might consider CCUS as part of a business case moving forward [38]. Examples include lack of emission reduction policies and the long timeframes associated with CO2 project permitting. Without stable legal, regulatory, and policy regimes that provide clear requirements and liability conditions, it will continue to be a challenge to facilitate the integration of the various facilities (including CO2 sources, pipelines, and storage fields) required for a wide deployment of CCUS technology [6]. Therefore, the objective of this paper is to provide a preliminary economic assessment surrounding a few of the more prominent challenges of widespread CCUS deployment. Through this type of assessment, the paper will be able to provide context around major key cost drivers, as well as afford insight toward developing innovative solutions aimed at overcoming hurdles that prohibit widespread CCUS deployment moving forward. 2.0 Noted Challenges to Widespread CCUS Deployment Widespread deployment of CCUS technology will depend on its technical feasibility, as well as the presence of relevant policies and regulations supporting large-scale/long-term financial investments [39], identification and effective characterization of potential storage sites, and continued support for early R&D efforts, which can reduce cost, risk, and uncertainty in CCUS operations [6]. Furthermore, these approaches must be applicable across different industries (i.e., power generation, industrial facilities, refineries, cement plants) given that stationary CO2 source types are highly variable and have their own unique business cases. The ability to enable effective integration of diverse source types with CO2 transport and storage options across the CCUS value chain is important for widespread, commercial-scale CCUS. The following subsections provide analyses to gain insight and perspective on the key cost drivers related to a few of the pertinent CCUS deployment challenges described in the paragraphs above. The complexity associated with balancing regulatory requirements, emerging policies, and newly introduced tax codes in the United States presents a dynamic challenge for CCUS project decisions. However, these analyses provide a quantitative outlook into the economics of CCUS where technical requirements intersect current policies and regulations. To truly understand the full economic potential of CCUS deployment, it is critical to evaluate not only each segment of the value chain, but also the value chain integrated as a whole [1]. NETL has developed models and other resources that enable cost and economic evaluation of each component of the CCUS 6

7 value chain or CCUS as an integrated whole [1]. These models (with supporting open-source literature) are flexible and enable evaluation across a broad spectrum of CCUS scenarios, or focus on particular cost drivers of capture, transport, or storage. These resources were utilized to provide the basis for most of the analyses in the following sections, mostly by performing CCUS-related modeling of distinct cases through scenario analysis. Specifically, the resources utilized included: NETL Baseline Studies for Fossil Energy Plants/Industrial CO2 Sources Report (i.e., Baseline Studies/Industrial Sources Report) NETL has developed a series of Baseline Studies that establish estimates for the cost and performance of combustion- and gasification-based power plants and options for co-generating synthetic NG and fuels, all with or without CO2 capture, for several ranks of coal. These studies provide an estimate of the costs to capture a tonne of CO2 (2011$) based on specific source type and associated operational parameters. There is also a study that evaluates CO2 capture from industrial sources [40, 41]. Financial assumptions used to estimate CO2 capture cost vary depending on the source type evaluated [41, 42, 43]. 3, 4 FE/NETL CO2 Transport Cost Model (i.e., CO2 Transport Cost Model) Microsoft Excel -based cost model for CO2 pipeline transport [44]. This model includes the capital costs of purchasing and installing the pipeline, a control system, a surge tank, and booster pumps and the operation and maintenance costs for the pipeline system (2011$). It has a financial module that calculates debt, equity, depreciation, and taxes for the transport project. The CO2 Transport Cost Model also has an engineering module to calculate the required diameter of the pipeline and the number of booster pumps needed based on the mass of CO2 to be transported. Data input needed is the mass of CO2 to be transported, distance of transport, and the change in elevation over that pipeline distance. Modeled financial assumptions as part of this study are the same as those utilized in NETL s Quality Guidelines for Energy System Studies: Cost Estimation Methodology for NETL Assessments of Power Plant Performance for a low-risk investor-owned utility [45]. 5 FE/NETL CO2 Saline Storage Cost Model (i.e., CO2 Storage Cost Model) Microsoft Excel -based cost model that calculates the first-year break-even price (2011$) to store a tonne of CO2 in a deep saline-bearing reservoir [46, 47]. This model incorporates the labor, equipment, and technology costs as well as the financial instruments needed to meet regulatory requirements set out in EPA s UIC Class VI regulations [48]. This model also has the equipment and technology needed for compliance with Subpart RR of the Greenhouse Gas Reporting Rule [49]. The financial assumptions utilized in the model are 3 Modeled financial assumptions for the electric power plants (high-risk profile for investor-owned utility) include a return on equity of 12 percent, capital charge factor of 12.4 percent, five-year capital expenditure period, 30-year payback period, debt cost of 5.5 percent, and 45/55 debt/equity ratio. 4 Modeled financial assumptions for the low CO2 purity sources include a return on equity of 20 percent, capital charge factor of 17.6 percent, three-year capital expenditure period, 30-year payback period, debt cost of 8 percent, and 50/50 debt/equity ratio. For the high CO2 purity sources, modeled financial assumptions include a return on equity of 20 percent, capital charge factor of 15.2 percent, one-year capital expenditure period, 30-year payback period, debt cost of 8 percent, and 50/50 debt/equity ratio. 5 Default economic assumptions include a return on equity of 12 percent, debt cost of 4.5 percent, 50/50 debt/equity ratio, 38 percent federal and state tax rate, 3 percent escalation rate, and project contingency factor of 15 percent. 7

8 those for a high-risk investor-owned utility. 6 Storage break-even prices can be estimated for a reservoir in one or each of the formations posted to the model s geologic database. The geologic database in the public version of the model contains 64 formations from 34 basins. Most of these formations are further divided into sub-areas (referred to as storage reservoirs) reflecting different geologic properties (e.g., depth, porosity, thickness, and salinity). There is a total of 228 reservoirs in the public version of the CO2 Storage Cost Model, and each reservoir can be further divided into different structure settings (like anticline, dome, and regional dip). As with most industrial projects, building a viable business case for CCUS projects can be a multifaceted, time-consuming process that requires assessment of both the economics of the project, its risks, and technical feasibility to be understood prior to finalizing investment decisions [50]. Failure to effectively evaluate and comprehend the economic feasibility of technology solutions being developed to overcome challenges presented by new or emerging energy policies can be detrimental to their eventual widespread deployment [1]. However, the NETL-developed resources enable a variety of possible approaches to evaluate the economics associated with deploying CCUS. Findings should help inform CCUS-related decision making, and, in turn, promote effective CCUS R&D pursuits that can help towards overcoming existing challenges to broader CCUS deployment and improve eventual pilot and commercial-scale deployment of the technology. 2.1 Capability to Apply CCUS Across Various Industry Types If CCUS is to make a significant impact in reducing CO2 emissions from stationary CO2 sources, it would need to be applied across various industries (e.g., power and industrial) that generate large volumes of anthropogenic CO2. The challenge here is that the different industry types (for that matter, CO2 sources) associated with large-volumes of CO2 emissions each have their own unique business cases, markets, and interests [6], not to mention quality and quantity of potential effluent stream from which CO2 would need to be appropriately managed. As a result, one must consider the CO2 source s unique perspective when developing viable CCUS options [51]. For instance, costs to capture CO2 are typically driven by the type of source and the associated purity of CO2 in the effluent stream. High CO2 purity sources, like NG processing or ammonia plants, may have greater than 90 percent CO2 by volume with few other components. Low purity sources, such as steel and pulverized coal (PC) power plants (subcritical or supercritical), have lower CO2 concentrations in the effluent stream (in the range of only 12 to 15 percent [52]) with higher concentrations of other components. For low CO2 purity sources, the cost of CO2 capture is higher relative to higher CO2 purity sources. Higher purity sources, however, typically generate less CO2 for capture than the lower purity sources [1, 53]. NETL s Baseline Studies and Industrial Sources Report estimate the cost and performance of different CO2 source types with and without CO2 capture. The results of these studies are considered to comprise the most comprehensive set of public data available for state-of-the-art technologies. These documents are available on NETL s website 7 and can help provide costs for each source type. 6 Default economic assumptions include return on equity of 12 percent, debt cost of 5.5 percent, 45/55 debt/equity ratio, 38 percent federal and state tax rate, 3 percent escalation rate, process contingency factor of 20 percent, project contingency factor of 15 percent, and general and administrative factor of 20 percent. 7 Baseline Studies can be found at the Industrial Sources Report can be found at 8

9 A representative list of power-generation and industrial plants from the NETL Baseline Studies and the Industrial Sources Report, as well as their associated CO2 capture parameters, is presented in Table 1. This table summarizes key components of these studies such as the net power or product output, the CO2 separation technology, CO2 captured percent, and captured CO2 volume. While the content in this table is specific to particular plants, the data provides perspective on the different CO2 volumes and capture costs associated with different source types. For example, the NG processing plant has the lowest cost of capture due to the high concentration of CO2 in the flue stream, a positive byproduct of the plant s gas separation process. It has been suggested that broader near-term CCUS deployment may be prompted from capturing CO2 from industrial sources (like ethanol plants and NG processing facilities), which emit CO2 at a high purity and offer low costs regarding CO2 capture relative to power-generating sources; and ultimately leading to a facilitative role in advancing CCUS towards ensuing deployment across all sectors [52, 54, 55]. Cement and steel have the highest cost due to low concentrations of CO2 in the effluent stream coupled with the expense associated with the methyldiethanolamine (MDEA) separation process to capture CO2. Aside from the variation in cost of capturing CO2 from the source, there would also be expected down-stream impacts associated with other critical cost drivers within the integrated CCUS value chain depending on the CO2 throughput volume, for example the sizing requirements of pipelines and the unit costs (i.e., $/tonne) of CO2 storage. These types of intricacies emphasize the need for adaptive and stable legal, regulatory, and policy-based CCUS frameworks that can function across multiple industry types. It also emphasizes the need for a broad R&D portfolio that can lead to the development of technologies that facilitate integrated CCUS from multiple sources, each with their own specific circumstance pertaining to capturing the CO2 generated. 9

10 Bituminous Coal- Powered Plants [42, 43] CO2 Source Type Table 1. Key CO2 capture parameters associated with different power plant and industrial plant configurations. Reported Net Power or Product Output Reported Percent CO2 Captured CO2 Separation Approxima te CO2 Captured (Mt/yr) Reported Capture Cost (2011$/ton ne) Reported Cost of Electricity Excluding Transport and Storage (2011$/MWh) Subcritical PC 550 MWe 90 Shell Cansolv SCPC 550 MWe IGCC Shell Global Solutions IGCC Chicago Bridge & Iron Company 497 MWe MWe 90 Selexol 2 nd Stage Natural Gas-Powered Plant [42] NGCC 2013 F-Class combustion turbine 559 MWe 90 Shell Cansolv Industrial Plants [41] Ethanol 50 Mgal/yr 100 Dehydration NG processing 500 MMscf/d 100 Separation is part of process Iron/steel 2.54 Mt/yr MDEA 992,500 System Cement tonnes/yr N/A Notes: For the industrial sources, the percent of CO2 captured is the percent of the stream considered for capture, not the overall plant. For the PC and integrated gasification combined cycle (IGCC) plants, the reference non-capture plant used to calculate capture costs is a supercritical PC (SCPC) plant without capture [42], while the reference plant for the natural gas combined cycle (NGCC) plant is an NG-based plant without capture. The capture costs for the industrial sources are the break-even costs of capturing CO2, which represent the CO2 selling price that is required for the base plant to recover all the costs associated with implementing CO2 separation (where applicable), purification, and compression. MWe = megawatt equivalent, Mgal/yr = million gallons per year, MMscf/d = million standard cubic feet per day, MWh = megawatt hour. 10

11 2.2 Need for Early Identification and Effective Characterization of Suitable Candidate Storage Sites Effective and reliable long-term storage of CO2 requires the successful selection and characterization of a reservoir with suitable characteristics providing for a low cost of storage. A CO2 storage site operator must ensure, at a minimum, that the candidate storage reservoir [56]: Has the necessary capacity for storage; Has the geologic conditions necessary for the injection of CO2 into the subsurface at the desired rate; Has sufficient depth (typically greater than 2,600 feet) to store CO2 in a supercritical phase; and Has a sufficient seal to retain the CO2 and prevent contamination of overlying underground sources of drinking water. The importance of detailed understanding of the geological setting of a candidate storage site cannot be understated. The challenge here is that geological properties of any particular reservoir are greatly variable over the areal extent of that reservoir [57]. Therefore, identifying and characterizing numerous viable CO2 storage sites is critical for future CCUS deployment. Similar to the deployment of historical industrial operations and associated infrastructure build-outs (underground NG storage and CO2 EOR are strong analogs to CCUS in this context [39]), there is likely minimal potential for CO2 transport and storage infrastructure development via private investment if a combination of strong policy/economic incentives and viable geologic storage sites are not both in place. Therefore, continued investment is needed for exploration and characterization to identify suitable storage sites, as well as to gain an understanding of the costs and cost drivers associated with deploying CO2 storage at those sites [6]. NETL has contributed substantial effort in characterizing high-priority formations across various depositional settings that have potential for future commercial-scale geologic CO2 storage [58, 59]. The overall storage resource estimates and areal extent pertaining to saline storage formations listed in NETL s Carbon Storage Atlas and NATCARB provide initial insight to the magnitude and spatial distribution of potential storage resources (not necessarily sites), but do not provide the detail needed to evaluate storage costs and critical cost drivers, which are strongly influenced by the geology of candidate reservoirs [1, 51]. Geologic properties, such as reservoir depth, thickness, porosity, and permeability define the quality of a potential storage reservoir and can strongly impact the cost to store CO2. These properties vary significantly across potential storage reservoirs and have a direct impact on the capacity, injectivity, and containment properties of sites [56, 57]. For example, reservoir depth impacts the drilling and operational costs of both injection and monitoring wells as deeper wells cost more in general than shallower wells. Reservoir thickness and permeability affect injectivity which, in turn, may influence the number of injection wells needed to inject the annual volume of CO2 delivered to a storage site. Reservoir thickness and porosity, along with the storage coefficient and areal extent, determine the reservoir s overall storage capacity, which dictates the volume of CO2 a reservoir can accommodate. Storage reservoirs with larger storage capacities can typically attain unit cost savings (i.e., $/tonne basis) via economies of scale by storing larger volumes of CO2 than smaller reservoirs [51]. NETL has conducted a basin-by-basin evaluation that highlights how variations in reservoir properties 11

12 influence the cost of CO2 storage [60]. This study suggests that economically-viable CO2 storage sites are not just influenced by storage capacity, but also by reservoir quality. A challenge to generating suitable CO2 storage cost estimates, particularly over multiple candidate sites, lies in the feasibly of integrating potential project design requirements (e.g., CO2 injection volumes) with site geologic parameters (depth, reservoir thickness, porosity, and storage coefficient). The CO2 Storage Cost Model provides the capability to evaluate the impact the geologic properties of a particular storage reservoir can have on the CO2 first-year break-even price of storing CO2 in that reservoir. A modified version of the publicly available CO2 Storage Cost Model was used to generate data and provide analyses to gain perspective on major CO2 storage cost drivers that would impact the decision to implement CO2 storage at candidate storage sites. 8 The most notable change was in the model s geologic database. This modification provided additional reservoirs in California s Central Valley, the Willison Basin, and the Appalachian Basin. The modified geologic database contains 87 formations found in 36 basins across the United States (Figure 3). Most of these formations are further sub-divided into reservoirs with unique geologic properties (e.g., depth, porosity, thickness, and salinity) and geographic boundaries (state lines often serve as boundary limits). There is a total of 277 reservoirs in this database. Each reservoir can be further divided into different structure settings (like anticline, dome, and regional dip), with each structural setting having a unique value for storage efficiency. Figure 3. Reservoir centroid locations (blue dots) and areal extents (blue outlines) of the storage reservoirs within the CO2 Storage Cost Model database. Each centroid represents a potential storage reservoir site for cost modeling. 8 It is important to note that a non-public version of the CO2 Storage Cost Model was used for this analysis. However, a version of the model and its supplementary user s manual describing assumptions, modules, and cost estimation methodologies are available on NETL s website at 12

13 The cross-plot in Figure 4 illustrates the relation between first-year break-even price across three structure types (anticline, dome, and regional dip) and the reservoir quality. Reservoir quality is defined here by porosity, storage coefficient, and thickness at the depth of each reservoir for each of the three structural settings, dome, anticline, and regional dip. The first-year break-even prices are calculated under a scenario injecting 3.2 Mt/yr over 30 years of injection for all reservoirs; six years prior to operations for site selection, characterization, permitting, and construction; and 50 years of post-injection site care (PISC). More details about this scenario can be found in the base case scenario description in NETL s Quality Guidelines for Energy System Studies Carbon Dioxide Transport and Storage Cost in NETL Studies report [60]. Figure 4 highlights how reservoir quality impacts first-year break-even prices, with higher-quality reservoirs providing lower storage costs and lower-quality reservoirs resulting in higher storage costs. Some of the reservoirs that shift to the right on the x-axis relative to other reservoirs with the same quality typically have smaller storage capacities, thus possess a greater first-year break-even price. Figure 4. Cross-plot (log-log scale) of the CO2 first-year break-even price vs. reservoir quality for all reservoirs in the CO2 Storage Cost Model with anticline, dome, and regional dip structure settings (where = porosity, E = storage efficiency factor, and h = reservoir thickness in feet) [61]. Vertical lines have been placed at the interface between percentile bins. The storage cost supply curve in Figure 5 illustrates the cumulative storage potential for all 277 reservoirs analyzed. Each point along the supply curve illustrates the first-year break-even price of CO2 stored (Y-axis) for a single storage project in a specific reservoir and structural setting. Due to the areal extent of some storage reservoirs, it is possible to have more than one storage project (cumulative mass stored along the X-axis) in a specific reservoir and structural setting at that same first-year break-even cost. Looking at cumulative storage in several reservoirs and structural settings, there are 334 gigatonnes (Gt) of storage potential in multiple reservoirs at a cost of $8/tonne or less, and up to 1,600 Gt of storage potential for $10/tonne or less (left-hand portion of Figure 5). That equates to a substantial volume of low-cost CO2 storage potential. For 13

14 perspective, 334 Gt is larger than the potential CO2 emissions that could be captured from electrical and industrial sources combined in the United States over the next century (260 Gt) based on data from the Energy Information Administration s (EIA) Annual Energy Outlook 2018 (AEO 2018) (assuming 90 percent of CO2 is captured) [62]. However, across the reservoirs evaluated as part of this study, most of the storage capacity (over 4,100 Gt; 72 percent of the total) comes at a cost greater than $10/tonne, with approximately 3,760 Gt (65 percent of the total) between $10 and $100/tonne. Keeping transportation in mind, this emphasizes the importance of identifying not only available resource capacity for CO2 storage sites, but also sites of higher-quality to keep integrated CCUS costs as low as possible. Figure 5. National CO2 storage cost supply curve. Storage costs plotted for anticline, dome, and regional dip structural settings and plotted against the cumulative captured CO2 emissions estimates from electric and industrial sources as part of EIA s AEO 2018 data [62]. A few of the more promising saline-bearing formations for CO2 storage in the United States are the Mt. Simon in the Illinois Basin, the Frio and Tuscaloosa along the Gulf Coast, and formations within the Central Valley region of California. Each of these formations holds the potential to store substantial amounts of CO2 due to the quality of their reservoirs; which are several hundreds of feet thick with average porosities ranging from 10 to >20 percent and permeabilities >100 millidarcy (md). They are also located in areas with a high density of CO2 point sources. NETL s Quality Guidelines for Energy System Studies Carbon Dioxide Transport and Storage Cost in NETL Studies emphasizes the impact of geologic parameters associated with storage reservoir quality on the overall cost to store CO2 [60]. The study estimated the storage cost variability in four different geologic basins in the United States (Illinois, East Texas, Williston, and Powder River) using region-specific results from the CO2 Storage Cost Model. The modeled parameters as part of this evaluation include trust fund growth rate, monitoring well spacing, PISC 14

15 length, and project stage durations remained identical between basins, but geologic parameters were inherently variable. The overall results of this study are presented in Table 2, and the distribution of unit costs across storage project stages is presented in Figure 6. For each basin evaluated, the cost value presented (in 2011$/tonne) is associated with the cost for the reservoir within each basin that stores up to a cumulative total of 25 Gt of CO2 under a regional dip structure within each basin. The Mt. Simon 3 reservoir in the Illinois Basin was the low-cost site at $9.71/tonne; the highest-cost site is the Madison 1in the Powder River Basin at $22.72/tonne. Specifically, the Mt. Simon 3 reservoir (Table 2) is thick, permeable, has a high porosity, and is relatively shallow compared to the other reservoirs. This combination provides for relatively lower CO2 storage unit costs. Change in reservoir quality across the four storage reservoirs of Table 2 is illustrated in the increasing permitting cost as a percent of overall costs as illustrated in Figure 6. Three injection wells are drilled for the Mt. Simon 3, Woodbine 1, and Red River 1 reservoirs, but nine wells were required for the Madison 1 reservoir. The difference here is most likely attributed to the differences in permeability across the reservoirs. More monitoring wells are drilled in the Red River 1 and Madison 1 due to increasing plume area reflected in the 3-D seismic are of Table 2. Additionally, the Red River 1 and Madison 1 reservoirs are substantially deeper than the Woodbine 1 and Mt. Simon 3 reservoirs, adding to the cost to drill and complete injection and monitoring wells. These costs carry through operations and PISC even though as a percent of overall cost, these two project stages in the Red River 1 and Madison 1 are slightly less than that for the Mt. Simon 3 and Woodbine 1. Table 2. Cost drivers for reservoirs providing storage resource potential at 25 Gt under a regional dip structure [60]. Reservoirs Mt. Simon 3 Woodbine 1 Red River 1 Madison 1 Basin Illinois East Texas Williston Powder River First-year break-even price ($/tonne) $9.71 $10.14 $15.18 $22.72 Thickness (ft) 1, Permeability (md) Porosity (%) Storage coefficient (unitless) Active injection wells Injection well depth (ft) 5,320 6,250 9,580 11,883 Monitoring wells (dual completed) Monitoring wells (above seal) Total monitoring wells Maximum 3-D seismic area (mi 2 )

16 $30.00 Break-Even Price to Store One Tonne CO 2 (2011$/tonne) $25.00 $20.00 $15.00 $10.00 $5.00 $- $ % $ % 34.3% 34.1% $ % 32.3% 13.1% $ % 29.4% 25.4% 10.8% 11.4% 23.2% 0.1% 0.1% 24.8% 0.1% 0.04% 23.0% 23.2% Mt. Simon 3 Woodbine 1 Red River 1 Madison 1 Illinois East Texas Williston Powder River Site Screening Site Characterization Permitting Operations PISC Figure 6. CO2 break-even price to store one tonne of CO2 by project stage for reservoirs at 25 Gt for base case (regional dip structure) [60]. This NETL basin-level study highlights several of the factors that affect the cost of CO2 storage, which are strongly influenced by overall storage reservoir quality. Figure 7 shows a cost breakout of the main categories of a project storing CO2 in Frio 3A per results from the CO2 Storage Cost Model. This analysis provides a bit more granularity as to what drivers directly influence CO2 storage costs. With a regional dip structure in Frio 3A, the first-year break-even price of CO2 is $6.80/tonne under a baseline scenario. Well costs, which include costs associated with installing, testing for mechanical integrity, operating and maintenance (O&M), and plugging stratigraphic, injection, and monitoring wells, account for 24 percent of the total cost $1.61/tonne. Costs to meet financial responsibility requirements make up another 28 percent of the total cost $1.93/tonne. These two items alone account for over 50 percent of the total unit cost to store CO2 in this example. 16

17 Figure 7. Cost breakout of various components of a CO2 storage project using the Frio 3A reservoir (east Texas) under a regional dip setting as the case study. The areal extent of the CO2 plume is another critical cost driver for a project. The monitoring and testing program that is part of the Class VI permit is designed to monitor the CO2 plume. Larger plumes increase the areal extent of the monitoring program, possibly increasing the number of monitoring wells needed, and the areal extent of seismic surveys designated to track the plume. These costs associated with delineating the areal extent of the CO2 plume contribute to several of the cost categories listed in Figure 7 above. The areal extent of a CO2 plume can be calculated based on the storage reservoir s geologic properties and the total CO2 injected over the duration of a project as indicated in Equation 1 [61]. Equation 1 Where: 9 ACO2 = area of the CO2 plume (ft 2 ) GCO2 = mass of total CO2 stored (tonnes) h = thickness of the storage reservoir (ft) ρco2 = density of the stored CO2 at storage reservoir conditions (pounds per ft 3 ) Φ = porosity of the storage reservoir rock (percent) E = storage coefficient for the storage reservoir rock (unitless) 9 The units for CO2 density (ρco2) in Equation 1 must be converted to tonnes per cubic foot to attain ACO2 in square feet. The approximate conversion is 1 tonne = 2,204 pounds. 17

18 The areal extent of the CO2 plume is proportional to the mass of CO2 injected over the life of a project and inversely proportional to storage reservoir quality. The calculated area of a plume in the subsurface, as shown in Equation 1, is too deterministic and does not account for geologic uncertainty. In the CO2 Storage Cost Model, an uncertainty factor of 1.75 is applied to the results of Equation 1 to account for geologic uncertainty in the subsurface in estimating the CO2 plume area size. Figure 8 provides a graphical depiction of the CO2 plume uncertainty area concept in relation to other boundaries relevant to CO2 storage accounted for in the CO2 Storage Cost Model. Figure 8. Conceptual depiction of critical CO2 storage cost driver boundaries and definitions part of the CO2 Storage Cost Model [63]. The total CO2 plume area modeled for costs is, therefore, the area defined by Equation 1 plus the uncertainty area. Applying ±10 percent variance to the CO2 plume uncertainty area as a uniform distribution demonstrates how a change in the plume uncertainty area affects the overall costs via Monte Carlo simulation (Latin Hypercube approach) as outlined in Figure 9. The Frio 3A reservoir in the Gulf Coast region and the Rose Run 3 reservoir of the Appalachian Basin were selected as the storage reservoirs for this evaluation. Frio 3A is of higher reservoir quality than Rose Run 3. Figure 9 shows that with only a ±10 percent change in the calculated plume uncertainty area, the first-year break-even price for CO2 storage can vary by up to 14 cents (2011$/tonne of CO2) in the higher-quality Frio3A reservoir, which is only 2 percent of the overall cost. But for the lowerquality Rose Run 3, the first-year break-even price can vary by up to $2.50/tonne (5 percent of the overall cost). As illustrated in Figure 8, the area defined by the plume uncertainty boundary defines that area to be monitored during and after CO2 injection operations. Understanding the growth of the plume in the reservoir and developing the approach to estimate the size would be essential to reduce the plume uncertainty and therefore costs for CCUS projects. 18

19 Figure 9. CO2 storage unit cost in Frio3A and Rose Run 3 under a regional dip setting impacted by CO2 plume size uncertainty. 2.3 Commercial-scale Integration of the CCUS Value Chain Components (i.e., capture, transport, and storage) Deployment of an integrated CCUS network may include multiple source types and sizes (captured CO2 volumes) across different industrial spectrums in cooperation with pipeline(s) and storage reservoir(s) operators. There can be inherent challenges in aligning the interests of the multiple parties involved across the CCUS value chain. Each CCUS component needs to sort out its own financial strategy [6]. CO2 sources must account for their own unique conditions and circumstances, as well as constraints, when considering participation within an integrated CCUS system. For instance, CO2 flue stream content and purity for either EOR or saline storage, CO2 capture rate, and proximity to storage reservoirs of varying quality will influence a CO2 source s decisions on selecting optimal transport and storage options that provide overall low cost CCUS [51]. This is the dilemma for CO2 sources in that they are affixed to their unique spatial location. Their captured CO2 would likely be delivered to a storage site via pipeline (dedicated pipeline or trunkline as options), so the source must consider its proximity to suitable low-cost storage reservoirs that are located close by, as well as options in higher-quality reservoirs farther away as part of initial planning into integrated CCUS systems. CO2 transport rates/volumes and the pipeline length are two major cost drivers for the overall CO2 transportation cost. Figure 10 shows trends between these two major cost drivers and CO2 transport break-even prices evaluated using NETL s CO2 Transport Cost Model 10 for a pipeline project with 3 years of construction and 30 years of operation. The potential cost of CO2 transport over a range of mass of CO2 transported is illustrated in Figure 10. This figure shows that transportation costs increase with increasing distance of transport for each mass of CO2 plotted. But, there is an economy of scale here as the cost of transport decreases with increasing mass of CO2 transported. For example, at a pipeline length of 1,000 miles, the cost (2011$/tonne) to transport captured CO2 from an NG processing plant is about three times more than transporting captured CO2 from an SCPC power plant (based on CO2 captured volumes provided in Table 1). With a dedicated pipeline, larger CO2 sources can transport their captured CO2 at a lower unit cost than smaller 10 The CO2 Transport Cost Model and its supplementary user s manual describing assumptions, modules, and cost estimation methodologies are available on NETL s website at 19

20 sources (Figure 10). This is due to the larger-diameter pipeline needed to accommodate the CO2 mass captured from the larger sources, which spreads the cost over the greater mass of CO2 transported. With larger-diameter pipelines, trunklines offer the same low unit cost to both large and small sources. For small sources, they can either select a dedicated pipeline to a storage reservoir nearby or transport to a more distant reservoir via trunkline and share the lower cost with other sources utilizing a large-diameter pipeline. Figure 10. The first-year break-even price required for a CO2 pipeline based on various lengths and different transportation volumes (in Mt/yr), which align to CO2 capture volumes for certain source types (based on NETL s Baseline Studies and Industrial Sources Report). The evaluation assumes no change in elevation between source and storage reservoir locations. An example is presented in Figure 11 below that integrates data from NETL s Baseline Studies, the CO2 Storage Cost Model, and CO2 Transport Model in a modular approach evaluating the unit cost ($/tonne of CO2) for a given CO2 source, pipeline segments, and storage options across a hypothetical CCUS value chain concept. Figure 11 shows the CCUS cost breakdown for a source in New York transporting CO2 to either the Mt. Simon 6 (MS6) reservoir in Indiana or Frio 3A (FR3A) reservoir in Texas via a dedicated pipeline system (one pipeline connecting CO2 source to storage site) or 36-inch trunkline pipeline system, which consists of pipeline segments (i.e., gathering lines, trunklines, and distribution lines) and hubs. A dedicated system, for the purpose of this evaluation, has the capacity to accommodate CO2 from only one source, while a trunkline system has the capacity to accommodate CO2 from multiple sources. There is a gathering pipeline to connect the source to the trunkline and a distribution pipeline at the end of the trunkline to provide delivery of the captured CO2 to either the Mt. Simon 6 or Frio 3A storage reservoirs. The CO2 source is assumed to be a SCPC power plant with a CO2 capture rate of 3.58 Mt/yr. A CO2 source must make certain business decisions when determining where to store its captured CO2. A source not only needs to consider the cost drivers for each portion of the CCUS value chain (e.g., capture mass of CO2, transport distance to storage site, and storage reservoir quality) but also the system as an integrated whole. From this example, the overall CCUS cost for the SCPC plant to store at Mt. Simon 6 in a regional dip structure is $81/tonne when using a dedicated pipeline to transport the CO2. The capture cost is 72 percent of the total cost, while transport makes 20

21 up 17 percent and storage 9 percent. If this source transports its captured CO2 to Frio 3A for storage, the overall CCUS cost would be $103/tonne causing capture, transport, and storage costs to be 56 percent, 37 percent, and 7 percent of the total cost, respectively. Even though Frio 3A is a high-quality reservoir, its lower storage unit cost cannot justify the higher costs to transport CO2 down to the Gulf Coast Region (an extensive distance). When using a dedicated pipeline, Mt. Simon 6 is the optimal storage site. However, if a trunkline is used, the Frio3A option becomes comparable to the Mt. Simon 6 option when a dedicated pipeline is used. A single CO2 source, large or small, can take advantage of the lower unit transport costs ($3 to $7/tonne CO2) of a trunkline since overall capital and operating costs are spread across the total capacity of the pipeline and can be shared by multiple sources. As can be seen in the Trunkline Pipeline System table in Figure 11, the overall CCUS cost for the SCPC power plant to store at Mt. Simon 6 in a regional dip structural setting is $76/tonne, only $8/tonne less than if the source chose to store in the same structural setting at Frio 3A. For the Mt. Simon 6 option using a trunkline, capture cost is 76 percent of the total cost, while both transport and storage each make up 12 percent. For the Frio 3 option under trunkline transport, capture cost is 69 percent of the total cost, transport is 23 percent, and storage is 8 percent. The cost share of each CCUS component can vary depending on the source type, the transport distance, and reservoir quality/capacity. For instance, having a low quality storage reservoir closer to the CO2 source may reduce the overall transport cost share, but the storage cost could be significantly higher as compared to storing in higher-quality reservoirs located farther away [1, 51]. 21

22 Figure 11. CCUS cost ($/tonne) breakdown for a dedicated pipeline system (top map and table) and trunkline pipeline system (bottom map and table) transporting 3.58 Mt/yr (550-MWe SCPC power plant) of CO2 from the source to storage at Mt. Simon 6 or Frio 3A based on 30 years of injection. Storage is in regional dip and dome structural settings. Should the same trunkline example be evaluated by swapping out the SCPC plant with a low CO2 volume/high CO2 purity NG processing plant (0.65 Mt/yr capture rate), the overall CCUS costs will be less than that for the SCPC plant due to its low cost of capture at $18/tonne CO2. Both sources benefit from the same unit cost of the trunkline pipeline segments. However, the smaller source will have higher gathering and distribution pipeline costs and higher storage cost. When using a trunkline system, Mt. Simon 6 is still the optimal storage site for the low purity source. When comparing the savings of using a dedicated pipeline or trunkline, the lowest cost CCUS option for the SCPC source is a trunkline to dome storage in the Mt. Simon 6 at $73/tonne CO2 22