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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 685 records · Page 38
All sourcesNASA NTRSDOE OSTI
DOE OSTI2013

Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture - Rev. 1

The objective of this study was to establish the cost and performance for a range of carbon dioxide (CO 2 ) capture levels for new supercritical (SC) pulverized coal (PC) and integrated gasification combined cycle (IGCC) power plants. The SC PC cases (Case 1 series) utilize Fluor’s Econamine FG Plus SM process for post-combustion CO 2 capture via temperature swing absorption with a 30 wt% monoethanolamine (MEA) solution as the chemical solvent. The IGCC cases (Case 2 series) employ a slurry-fed, entrained-flow General Electric Energy (GEE) gasifier and leverage UOP’s (formerly Universal Oil Products) two-stage Selexol™ process for bulk CO 2 capture and selective hydrogen sulfide (H 2 S) removal via pressure swing absorption. The Selexol™ process uses dimethyl ether of polyethylene glycol (DEPG) as a physical solvent for pre-combustion capture.

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DOE OSTI2013

Greenhouse Gas Reductions in the Power Industry Using Domestic Coal and Biomass - Volume 2: PC Plants

The objective of this study was to simulate biomass co-firing in greenfield Pulverized Coal (PC) power plants and examine the resulting performance, environmental response, and economic response. To develop a more complete understanding of the impact of co-feeding biomass, each case was examined using a limited life cycle greenhouse gas (GHG) analysis, which examines GHG emissions beyond the plant stack. Included in the limited life cycle GHG analysis were anthropogenic greenhouse gas emissions from the production, processing, transportation, and fertilization of biomass and from mining, transporting and handling coal.

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DOE OSTI2015

Comprehensive Analysis of Coal and Biomass Conversion to Jet Fuel: Oxygen Blown, Transport Reactor Integrated Gasifier (TRIG) and Fischer-Tropsch (F-T) Catalyst Configurations Modeled and Validated Scenarios

This study evaluates the technological/process, life cycle environmental, and economic perspective of 20 discreet F-T jet fuel production scenarios. The technological/process model provides a process level evaluation of the 10 alternate CBTL facility scenarios considered in this study. Aspen Plus simulation models for the CBTL facility scenarios were developed to determine the composition and flows of all of the major streams in the plants. These were used to develop conceptual level cost estimates for capital and operating costs for the major process units. NETL completed this study for the Connecticut Center for Advanced Technology (CCAT) to provide techno-economic and life cycle analysis modeling support for CBTL alternative jet fuel production, which forms key references to their report to the Defense Logistics Agency (their project sponsor/funder).

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DOE OSTI2015

Comprehensive Analysis of Coal and Biomass Conversion to Jet Fuel: Oxygen Blown, Entrained-Flow Gasifier (EFG) and Fischer-Tropsch (F-T) Catalyst Configurations Modeled and Validated Scenarios

This study evaluates the technological/process, life cycle environmental, and economic perspective of 10 discreet F-T jet fuel production scenarios. The technological/process model provides a process level evaluation of the 10 alternate CBTL facility scenarios considered in this study. Aspen Plus simulation models for the CBTL facility scenarios were developed to determine the composition and flows of all of the major streams in the plants. These were used to develop conceptual level cost estimates for capital and operating costs for the major process units. NETL completed this study for the Connecticut Center for Advanced Technology (CCAT) to provide techno-economic and life cycle analysis modeling support for CBTL alternative jet fuel production, which forms key references to their report to the Defense Logistics Agency (their project sponsor/funder).

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DOE OSTI2015

Coal and Biomass to Liquids (CBTL) Greenhouse Gas Optimization Tool Documentation

This report is the user documentation for the NETL CBTL Jet Fuel Model submitted under a separate approval routing. The documentation is intended to accompany the model. The documentation explains how to the use the model. The documentation does not contain any energy analysis findings. NETL completed this model/report as part of a study for the Connecticut Center for Advanced Technology (CCAT) to provide techno-economic and life cycle analysis modeling support for CBTL alternative jet fuel production, which forms key references to their report to the Defense Logistics Agency (their project sponsor/funder).

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2016

Life Cycle Analysis of Coal Exports from the Powder River Basin

The purpose of this study was to compare environmental implications of exporting United States (U.S.) coal resources to Asian markets with respect to alternative global sources of steam coal. This study seeks to evaluate and understand potential environmental consequences of exporting PRB coal compared to global alternative sources of coal. This study was informed by a 10-person industry based Technical Steering Committee to improve the quality of the analysis. The key question addressed by the study: Is there a definitive difference between the life cycle GHG profiles between sourcing coal from the U.S. (PRB), Australia, or Indonesia for Japan, South Korea, or Taiwan? Given the uncertainty in the model parameter values, there is not a definitive difference between the life cycle GHG profiles between sourcing coal from the U.S. (PRB), Australia, or Indonesia for Japan, South Korea, or Taiwan.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2019

Integrated Commercial Carbon Capture and Storage (CCS) Prefeasibility Study at Rock Springs Uplift, Wyoming (Final Report)

To establish the potential of safe, long-term commercial-scale carbon capture & storage (CCS) in southwestern Wyoming, the University of Wyoming formed a CCS coordination team (CCT) to complete a Phase I CarbonSAFE pre-feasibility study adjacent to the region’s largest coal-fired power plant, the Jim Bridger Plant (JBP). The study’s primary objective was to evaluate the potential of storing 50+ million metric tons of anthropogenic carbon dioxide (CO 2 ) in stacked reservoirs over a period of 25 years. In addition, this integrated study evaluated related aspects of carbon capture utilization & storage (CCUS) at the study site, including: (1) the CO 2 character of post-combustion flue gas from JBP and the technical capacity for retrofitting proven commercial-scale CO 2 capture technology relative to CO 2 source character and technological constraints; (2) utilization of the existing CO 2 pipeline network in the immediate vicinity of JBP for enhanced oil recovery (CO 2 -EOR) and utilizing that network as part of a regional hub for CO 2 storage from other anthropogenic sources; (3) assessment of the challenges and benefits of meeting all of CarbonSAFE programmatic Phase I goals relative to Wyoming’s carbon management regulatory framework; and (4) assessment of the community and environmental factors that may impact CCS at JBP. With respect to storage, we analyzed the potential of stacked Mesozoic reservoirs at the study site, focusing on the Entrada and Nugget sandstones. The reservoir response to injection simulations varied greatly between formations, though they both were capable of CO 2 storage. The Entrada Sandstone is relative thin (~40’) and heterogeneous; storage using one injection and production well was limited to 1.2 Mt over 25 years at the study site. The Nugget Sandstone is much thicker (> 400’) and generally homogeneous; storage using one injection and production well approached 15.0 Mt over 25 years; this scenario suggests that the storage potential in the Nugget Sandstone is close to the estimated P90 calculation of 9.6 Mt/mi 2 as models indicate a storage potential of 8.3 Mt/mi 2 at saturation. Both reservoirs’ storage capacity benefited greatly from coupling an injection well with an offset production well; total storage capacity increased and reservoir pressure stayed below critical thresholds. This indicates that implementing a pressure management strategy at the study site would optimize storage and decrease risk. Seals associated with the targeted reservoirs were shown to be capable of retaining the potential storage volumes, and the site benefits from multiple seal redundancies (i.e. > 7,000’ of seal formations). Furthermore, assessment of different reservoir variables (e.g., fluid composition, pressure, etc.) indicates all reservoirs at the study site are isolated. Storage assessments from Mesozoic reservoirs were coupled with simulations from the site’s Paleozoic reservoirs (the Weber Sandstone and Madison Limestone), which were the focus of previous study. The fully integrated stacked reservoir pre-feasibility studies suggest that the Nugget and Madison formations alone could safely store 50 million metric tons of CO 2 within the study site. Furthermore, both formations are true saline reservoirs near JBP, making them ideal target reservoirs for CO 2 sequestration. Analysis of Wyoming’s laws and regulations confirm that the State has a favorable policy environment for CCS/CCUS. The project’s economic models estimated that the following revenues collectively are sufficient to finance the project over its lifespan if CO 2 utilization is coupled with CCS via the following strategies: (1) sales of CO 2 for EOR (approximately $69 million/year); (2) use of CO 2 tax credits such as amended §45Q and §48A (approximately $484 million total); and (3) sales of low-carbon electricity and marketable carbon offset/credits into carbon-constrained markets (approximately $11-$17 million/year) to West Coast consumers. These revenue estimates are broadly consistent with other studies that concluded arbitrage in JBP retail electricity sales between California and Wyoming could help to support the cost of deploying CCS at JBP. The models also indicate that maintaining a successful business case for long-term CCS -- wherein associated capture, transportation and operational costs are fully addressed at JBP -- is reliant on numerous external factors that complicate predictions. This study suggests that this site meets the CarbonSAFE program’s requirements of being able to feasibly store 50+ million metric tons of CO 2 over 25 years within the site’s stacked reservoirs, especially if coupled with pressure management strategies. This study suggests that the Nugget Sandstone and the Madison Limestone are two of the best reservoirs in the State with respect to overall storage capacity. In addition, the site’s proximity to existing CO 2 transportation networks, CO 2 -EOR opportunities, ability to sell to markets that value low-carbon electricity, Wyoming’s existing carbon regulatory framework, and a public that is well-educated with respect to energy markets and issues collectively increase the potential for implementing commercial-scale CCS adjacent to the JBP. With respect to the available technical and non-technical site data, and the reservoir quality at the study site, we suggest that this site is capable of moving directly into Phase III of the CarbonSAFE program.

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DOE OSTI2019

Abstract for CRADA between the National Energy Technology Laboratory, Ohio State University, Lawrence Berkeley National Laboratory, and Sandia National Laboratories (AGMT-0804)

This CRADA will enable cooperation between Ohio State University (OSU) and a collective led by the National Energy Technology Laboratory (NETL), with the goal of facilitating the accelerated commercialization of OSU’s iron-based chemical looping process through advanced modeling and state-of-the-art optimization techniques. OSU will provide data for model development and validation, while NETL and collaborators through the Institute for the Design of Advanced Energy Systems (IDAES) will develop advanced high-fidelity optimization-based system models. The project will use data collected primarily from OSU’s bench scale and sub pilot scale facilities and will be supplemented by data collected from the open literature. Models representative of chemical looping combustion or gasification using either coal or natural gas as fuel are considered in scope. Specific tasks will include 1) development of physical property sub-models, 2) development of steady-state and dynamic 1 st principles models of the novel gas solid contactor technologies being developed by OSU, and 3) superstructure and parametric optimization of a full chemical looping process by leveraging the large-scale optimization capabilities being developed by IDAES. This collaboration will provide a greater fundamental understanding of the OSU chemical looping process, will help to improve the overall process economics, and will thus enable a greater probability of commercial success. It will provide IDAES with the opportunity to validate, demonstrate, and further develop its toolset through a real-world practical demonstration.

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DOE OSTI2012

Modeling the Uncertainty of Fischer-Tropsch Jet Fuel Life Cycle Inventories with Monte Carlo Simulation [Slides]

This presentation discusses the use of Monte Carlo simulation to model the uncertainty in a life cycle inventory of the Gasification Systems of coal and biomass. While the inventory is dominated by carbon dioxide emissions from the Adv. Combustion Systems of the fuel, small changes to the feedstocks that are used to make the fuel can make the difference in complying with the Energy Independence and Security Act of 2007.

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DOE OSTI2020

Novel Membrane and Electrodeposition-Based Separation and Recovery of Rare Earth Elements from Coal Combustion Residues (Final Report)

This project developed a hydrometallurgical-based technology to extract and concentrate rare earth elements (REEs) from a representative group of coal combustion residuals (CCRs) from major coal sources in the United States. The approach for REE recovery comprises two general components: (1) Leaching of REEs from CCRs and (2) Separation of REEs from other major ions in the CCR leachate. The leaching step entails acid leaching with nitric or hydrochloric acid, and in some cases, pretreatment of CCRs with alkaline roasting prior to acid leaching. The follow-up REE recovery steps involve a series of membrane-based methods to separate and concentrate rare earth ions from other major ions in acid leachates of CCRs. These methods include liquid emulsion membranes, supported liquid membranes and electrodeposition with carbon nanotube electrochemical filters. The advantage of these separation approaches (relative to conventional approaches such as solvent extraction) is a reduction in the usage of solvents and other costly chemicals and a reduction of hazardous waste products that are challenges in conventional REE separation methods. In the testing of our process, we selected a representative set of CCR samples from our collection and performed a suite of characterization measurements (total REE content and major mineralogy). The major results of this work demonstrated that heated acid leaching could efficiently extract REEs from PRB-based coal fly ashes while the Appalachian and Illinois Basin CCRs required alkaline roasting with NaOH prior to acid leaching at room temperature. The supported liquid membrane (SLM) configuration and electrochemical deposition (ED) system yielded the most promising methods of REE recovery from the acid leachates of fly ash. Our most concentrated product to date comprised 1 wt.% (dry basis) REEs produced from an Appalachian-based fly ash leached and purified by SLM. The SLM separation process was more selective for heavy REEs over the light REEs. When SLM was combined with ED, preliminary results demonstrated that a final product of >2 wt.% REEs was possible.

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DOE OSTI2012

Role of Alternative Energy Sources: Pulverized Coal and Biomass Co-firing Technology Assessment [Slides]

This analysis evaluates the role of coal and biomass co-firing power in the future energy portfolio of the U.S. Coal and biomass co-firing power is evaluated with respect to resource base, growth potential, environmental profile, costs, barriers, risks, and expert opinions. Co-firing is seen as a way of reducing the greenhouse gas emissions of existing coal-fired power plants, but the incorporation of biomass into an existing coal-fired system increases the complexity of feedstock acquisition. Further, the acquisition of biomass has unique GHG burdens that offset, in part, the GHG reductions from the displacement of coal with biomass. Due to the higher feedstock prices of biomass, the co-firing of biomass at a 10 percent share of feedstock energy can increase the cost of electricity by as much as 31 percent. Other risks include regulatory uncertainty; without policies that encourage the use of renewable feedstocks, there is no incentive for producers to invest in co-fired systems.

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DOE OSTI2019

Characterizing and Interpreting the In Situ Strain Tensor During CO 2 Injection

Injecting fluid into a well creates an evolving strain tensor field in the rocks enveloping the well. Understanding the strain field has the potential to improve the effectiveness of CO 2 storage, but the strain tensor had never been measured during injection. The objective of this project was to evaluate how the strain tensor can be measured and interpreted to improve the assessment of geomechanical properties and advance an understanding of geomechanical processes that may present risks to CO 2 storage. The project consisted of three primary tasks related to 1) developing instruments for measuring the strain tensor with high precision; 2) developing methods for analyzing strain signals; and 3) demonstrating the approach at a CO 2 storage analog site.

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DOE OSTI2019

Making Coal Relevant for Small Scale Applications: Modular Gasification for Syngas/Engine CHP Applications in Challenging Environments

This Front-End Engineering Design (FEED) study is funded by the US Department of Energy (DOE), and managed by the National Energy Technology Laboratory (NETL) through a Cooperative Agreement awarded to the University of Alaska Fairbanks (UAF) to perform a technical and cost study for the design and installation of a Hamilton-Maurer International (HMI) gasifier for generating a clean syngas for firing in reciprocating engines. An existing diesel engine generator (DEG) and a commercially available spark ignition engine are used to generate electricity with the low-Btu syngas. Other than the HMI gasifier, only commercially available technologies were assumed for this study. An important objective of this design study was to estimate capital and operating costs of small modular coal and coal/biomass fired generating units to provide wind regulation services. Although this study is based on retrofitting an existing coal fired power plant with the HMI gasifier, sufficient data was developed to characterize greenfield units. The original concept was to provide clean syngas and tars/oils from the gasification process to the existing Colt-Pielstick PC2.6B diesel engine generator (9.6 MWe) installed at the UAF Atkinson Power Plant. The intent was to convert the diesel engine to operate in a dual fuel mode, firing both syngas and tars/oils. As the project progressed, Fairbanks Morse Engine (FME), current licensee for the Colt-Pielstick engine line, was not able to develop a modification package for the engine to allow for syngas firing. Although this type of modification is available for firing natural gas, the capability does not extend to syngas. Western Energy Systems, distributor for Innio Jenbacher, was able to offer the Jenbacher Model JMS620 engine. After review of available options, the project team selected a design configuration using two Jenbacher engines rated at 1965 kWe each to fire the syngas, with the oils/tars directed to the Colt Pielstick diesel to be blended with ultra-low sulfur diesel oil (ULSD). The Jenbacher engines are expected to operate at continuous base load, with some load-following ability, while the existing diesel engine will operate in grid support service, with loads varying from a nominal 25% to 100%. An annual capacity factor for the diesel engine is projected to be between 50% and 60%. The overall gasifier and gas clean-up system is sized to produce enough syngas to adequately fuel three Jenbacher Engines for a nominal power output of 5.9 MWe, but this study assumes that only two Jenbacher engines will be installed due to space constraints in the Atkinson Power Plant, and because of expected air emission permit limitations. There is still potential that the excess syngas capacity equivalent to about 2 MWe could be used as supplemental fuel for the DEG. The exhaust from the Jenbacher engines is passed through heat recovery units to generate low pressure steam, thereby providing a significant portion of the steam required for operating the gasifier. The overall performance of the HMI gasifier/engine configuration is summarized as follows: 1) Overall electric efficiency, Jenbacher and diesel engines, based on gasifier fuel production (syngas and pyrolysis liquids) is 35.2% LHV, 2) Overall cogenerating efficiency (electricity plus steam), based on gasifier fuel production (syngas and pyrolysis liquids) is 54.8% LHV, 3) Overall electric efficiency, Jenbacher and diesel engines, based on coal input, is 29.6% LHV, and 4) Overall cogenerating efficiency, electricity plus steam, based on coal input is 46.0%. This project is estimated to have a Bare Erected Cost (BEC) of $\$$ 33.4 million and a Total Plant Cost (TPC) of $\$$ 45.7 million. Based on the original scope, sending both the clean syngas and the oils and tars to the existing diesel engine, the BEC and TPC values would have been $\$$ 23.3 million and $\$$ 32.1 million, respectively. A variable Cost of Electricity (COE) is calculated to reflect only those costs that will be incurred by incremental operation of the system for the HMI gasifier/Jenbacher engine combination. Operation of the diesel engine is determined separately. The variable COE values are: Case 1: 100% Usibelli Coal: (a) HMI gasifier/Jenbacher Engines -- 8.3 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh, and Case 2: 80% Usibelli Coal + 20% wood chips (proportion based on Btu input, LHV basis): (a) HMI Gasifier/Jenbacher -- 13.7 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh. The incremental cost of operating the gasifier/Jenbacher system increases with co-firing of wood chips due to the high cost of this material, over five times as costly as Usibelli coal delivered to the Atkinson Power building. The diesel cost is constant as the oils and tars are priced at the same value as the ULSD for the purposes of fueling the diesel engine. Section 8 of this report provides details of the O&M costs. The overall power system is configured to be modular and scalable to provide a wide range of generating capacity using the same components. This allows for reduction in cost, risk, schedule time to engineer and construct, and provides some degree of repeatability for air permitting.

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DOE OSTI2017

Hydrogen Energy California (Final Scientific and Technical Report)

Hydrogen Energy California ("HECA") is an Integrated Gasification Combined-Cycle (IGCC) “polygeneration” project. The Project gasifies a 75 percent coal and 25 percent petroleum coke (petcoke) fuel blend to produce synthesis gas (syngas). Syngas produced via gasification is purified to hydrogen-rich fuel, which is used to generate low-carbon baseload electricity in a Combined Cycle Power Block, low-carbon nitrogen-based products in an integrated manufacturing Complex, and carbon dioxide (CO 2 ) for use in enhanced oil recovery (EOR). The power and products produced by HECA have a lower carbon footprint compared to power and products produced from more traditional fossil fuel facilities. This low-carbon footprint is achieved by capturing more than 90 percent of the CO 2 in the production of the hydrogen fuel and transporting it for use in EOR, which results in simultaneous sequestration (storage) of the CO 2 in a secure geologic formation in the adjacent Elk Hills Oil Field (EHOF), a hydrocarbon producing area. Highlights of HECA as conceived during the execution of FEED are as follows: The Project is designed to operate on a fuel blend consisting of 75 percent western subbituminous coal and 25 percent California petcoke based on thermal input to the gasifier on a higher heating value (HHV) basis; The feedstocks are gasified to produce syngas that is further processed and cleaned to produce hydrogen-rich fuel; More than 90 percent of the carbon in the raw syngas is captured in a high-purity CO 2 stream during steady-state operation; High purity CO 2 is compressed and transported by pipeline to the EHOF for injection into deep underground hydrocarbon reservoirs for CO 2 EOR; The Combined Cycle Power Block produces over 420 megawatts (MW) of gross power, which yields during periods of maximum power production over 270 MW of low-carbon baseload electricity to the grid; An integrated Manufacturing Complex produces approximately 1 million tons per year of low-carbon nitrogen-based products, including urea, urea ammonium nitrate (UAN), and anhydrous ammonia, to be used in agricultural, transportation, and industrial applications.

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DOE OSTI2019

Techno-Economic Analysis of an LGFCS MWe-Class SOFC System (Final Report)

The objective of this project is to perform a range of technical, cost and economic analyses of a MW-scale natural gas fired Solid Oxide Fuel Cell (SOFC) distributed power generation system design. The information generated will provide evidence of the tracking of technology and manufacturing readiness supportive of Technology Readiness Level 7 (TRL7) system testing in the 2022 timeframe that meets the Department of Energy’s (DOE) targets for cost (<$6000/kW) and durability (<0.5% power degradation/1000 hours).

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DOE OSTI2019

Scale-Up of Coal-Based Supercritical CO 2 cycle technology

The Allam Cycle is a transformational technology that enables a step change in the performance, efficiency, and cost of electricity for electrical generating units by using supercritical CO 2 (sCO 2 ) as the working fluid in the turbine for power generation. The objectives of this Phase I effort were to select a host site for a large pilot system through a process of down selection, develop a conceptual design, and conduct a pre-front-end engineering design (pre-FEED) study for a sCO 2 cycle pilot plant that uses domestic coal reserves as the primary feedstock, thereby furthering technology development of the coal-based Allam Cycle. The project was divided into four main tasks: 1) Project Management and Planning; 2) Conceptual Pilot Plant Definition and Host Site Selection; 3) Preliminary Design, Cost, and Schedule Development; and 4) Commitments and Environmental Information Volume (EIV). All project management activities occurred in Task 1. Host site selection was conducted in Task 2, while conceptual design and pre-FEED activities took place under Task 3. Task 4 enhanced the project by securing commitments for the next phase of the program and completing an initial EIV. The Great Plains Synfuels Plant (GPSP) has been selected as the host site for the large-scale pilot, and its owner, Dakota Gasification Company (DGC), is a committed partner. GPSP was compared to two other host site candidates during Phase I: the existing natural gas Allam Cycle facility in La Porte, Texas, and the Energy & Environmental Research Center’s (EERC) high-bay demonstration facility in Grand Forks, North Dakota. Costs for hosting the pilot plant were estimated for each facility, and those costs are shown in Table ES-1. Based on these estimates, the DGC site was clearly shown to be the lowest cost option and was selected as the host site for the project.

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DOE OSTI2019

Quality Guidelines for Energy System Studies: Specification for Selected Feedstocks

This section provides recommended specifications for various feed stocks that are commonly found in NETL-sponsored energy system studies. Adhering to these specifications should enhance the consistency of such studies. NETL recommends these guidelines be followed in the absence of any compelling market, project, or site-specific requirements in order to facilitate comparison of studies evaluating coal-based technologies.

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DOE OSTI2019

Integrated Commercial Carbon Capture and Storage (CCS) Prefeasibility Study at Dry Fork Station, Wyoming

The study focuses on the Basin Electric Dry Fork Power Station (DFS), the newest coal-fired power plant operating in the lower 48 states. DFS began operation in 2011 and has an operating lifetime of approximately 80 years, is a 420 MW plant, and emits roughly 3.3 million metric tonnes (Mt) of CO 2 per annum. Adjacent to DFS is the Wyoming Integrated Test Center (ITC). The ITC provides space and access to DFS flue gas for researchers to test CO 2 utilization and CO 2 capture technologies. The objective of this study is to identify saline storage opportunities proximal to DFS and the ITC in the Powder River Basin. The objectives of the prefeasibility study were as follows: (1) to establish a CCS coordination team capable of achieving a successful implementation of commercial-scale CCS for the Dry Fork Power Station; (2) to develop site-specific business and execution strategies; and (3) to identify and describe promising saline storage sites capable of storing 50 million metric tons of CO 2 .

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