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The Rock Springs Uplift: A Premier CO2 Storage Site in Wyoming
Surdam, Ronald C. (U. of Wyoming) | Dahl, S. (Los Alamos Natl. Lab) | Hurless, R. (Los Alamos Natl. Lab) | Jiao, Zunsheng (U. of Wyoming) | Ganshin, Yuri (U. of Wyoming) | Bentley, R. (Los Alamos Natl. Lab) | Garcia-Gonzalez, M. (Los Alamos Natl. Lab)
Abstract With global energy consumption increasing at about 25% per decade, it is essential for energy exporting states like Wyoming to optimize energy development during the 21st century in order to safeguard our nation's economy and energy security. Without regulation, annual global CO2 emissions will double by 2030 (Figure 1). In this case, over a very short time period, the world's largest economies will either have to abandon fossil fuels as a source of energy, or capture and geologically store CO2 emissions. In the future, the results from the Wyoming Carbon Underground Storage Project (WY-CUSP) will prove critical to the optimization of responsible energy resource development in Wyoming and other Rocky Mountain states. The coal extraction, enhanced oil recovery, coal-fired electricity generation, and coal-to-chemical industries will need either CO2 or a place to store CO2. To facilitate deployment of any new and/or improved energy delivery technologies and associated industries in Wyoming, the state must document the existence of available commercial CO2 storage capacity, along with infrastructure to transport CO2 from its source to the storage site, and finally to the end point of use.
- Materials > Metals & Mining > Coal (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Bighorn Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- (28 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract Combating climate change by mitigation of release of the anthropogenic greenhouse gases has attracted worldwide attention towards research and policy formulations. One such approach utilizes the geological sequestration of carbon dioxide into coal beds which is a value addition process, capable of enhancing the yield of coalbed methane (CBM) in producing reservoirs. CO2 is preferentially adsorbed onto the microporous structure of coal seams and it displaces the methane molecule from the adsorption sites, thereby enhancing the production of the low carbon eco-friendly fuel. In this study, a finite difference based reservoir simulator, COMET3, has been utilized for construction of underground coal bed scenario for Indian seams. Numerical modeling involves solving complex equations used to describe some physical process by iterative approximate solutions. Such simulation is worked out for underground coal of Lower Gondwana sequence in Jharkhand state in India. Detailed field work was carried out to collect samples and field data. Laboratory tested parameters and some from published data were utilized for construction of the numerical model. The best fit model was developed for estimation of the volumes of gases involved in CO2 enhanced coalbed methane recovery. It also gives a detailed analysis of distribution of gases with time and space. The results obtained from the simulation are quite encouraging and ascertain that the process of CO2 enhanced CBM recovery seems to be technically feasible for Indian scenario also. The simulation was executed for a period of 20 years to understand the space-time disposition of injected CO2 and recovery of methane from the reservoirs. It is quantified in this study that for the chosen dimensions of coal block, a total of 15.1 bcf of CO2 can be injected into the reservoir and approximately 5.0 bcf of methane can be recovered.
- North America > United States (0.95)
- Asia > India > Jharkhand (0.34)
- North America > Canada > Alberta (0.29)
- Materials > Metals & Mining > Coal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > India > Tripura > Assam-Arakan Basin (0.99)
- Asia > India > Tamil Nadu > Bay of Bengal > Cauvery Basin (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Bikaner Nagaur Basin (0.99)
- (4 more...)
ABSTRACT CO2 compression is considered as one of the challenges in CO2 capture and sequestration (CCS). In enhanced oil recovery (EOR) applications where CO2 is pressurized to supercritical pressure (e.g. 150 bar) before injection into a well, CO2 compression could reduce natural gas combined cycle power plants net power by about 4%. In this paper, several CO2 pressurization strategies, such as compression or liquefaction and pumping using an open cycle or closed cycles, were explored and evaluated. New CO2 liquefaction cycles based on single refrigerant and cascade refrigerants were developed and modeled using HYSYS software. The developed models were validated against experimental data. The considered refrigerants for CO2 liquefaction are NH3, CO2, C3H8 and R134a. One of the developed vapor compression CO2 liquefaction cycles that use NH3 as a refrigerant at an optimized liquefaction pressure resulted in 5.1% less power consumption than the conventional multi-stage compression cycle as well as 27.7% less power consumption than the open CO2 liquefaction cycle. Sensitivity analysis was carried out to explore the effect of heat exchangers pressure drop, compressors isentropic efficiency and seawater temperature on the power savings. The results show that the developed liquefaction cycle outperforms the conventional multi-stage compression cycle in almost all cases explored.
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (3 more...)
Abstract The U.S. Department of Energy's (DOE) Fossil Energy Program has adopted a comprehensive, multi-pronged approach to the research and development (R&D) of advanced carbon dioxide (CO2) capture technologies for coal-based power plants. Under this program, the National Energy Technology Laboratory (NETL) is conducting research to develop the next generation of advanced capture concepts for coal-based power plants. Research projects are carried out using various funding mechanisms - including partnerships, cooperative agreements, and financial assistance grants - with corporations, small businesses, universities, nonprofit organizations, and other national laboratories and government agencies. Current efforts cover not only improvements to state-of-the-art, first generation technologies, but also the development of second and third generation advanced CO2 capture technologies. In addition, DOE/NETL is conducting technical-economic analyses to establish the baseline cost and performance for current CO2 capture technologies and determine the feasibility of advanced capture and compression technologies. The overall goal of the DOE/NETL CO2 capture R&D program is to develop advanced technologies that achieve at least 90 percent CO2 capture with a corresponding cost and energy penalty reduction of 50 percent compared to current state-of-the art technologies applied to pulverized coal combustion and integrated gasification combined cycle (IGCC) power plants. Critical R&D targets include the completion of laboratory- and small pilot-scale testing of a broad spectrum of CO2 capture approaches, including advanced solvents, sorbents, membranes, oxy-combustion, and chemical looping combustion by 2016; completion of large pilot-scale testing by 2020; and full-scale demonstrations of the most promising technologies beginning by 2020. It is anticipated that successful progression from laboratory-through full-scale demonstration will result in several of these advanced technologies being available for commercial deployment by 2030. The purpose of this paper is to provide an update on the R&D efforts of advanced post-combustion CO2 capture technologies for coal-based power systems being conducted by DOE/NETL. INTRODUCTION The primary mission of DOE's Office of Fossil Energy (FE) is to "ensure the availability of near-zero atmospheric emissions, abundant, affordable, domestic energy to fuel economic prosperity, strengthen energy security, and enhance environmental quality." Furthermore, FE's Clean Coal Research Program (CCRP) - administered by the Office of Clean Coal and implemented by NETL - has a mission to "create technology and technology-based policy options for public benefit by enhancing U.S. economic, environmental, and energy security." This mission is achieved by developing technologies to enhance the clean use of domestic fossil fuels and to reduce emissions from fossil-fueled electricity generation plants to achieve near-zero atmospheric emissions power production. CCRP is designed to remove environmental concerns related to coal use by developing a portfolio of innovative technologies, including those for carbon capture, utilization, and storage (CCUS). DOE/NETL recently introduced the term "utilization" to the more commonly used phrase of "carbon capture and storage (CCS)" to reflect the growing importance of developing beneficial uses for captured CO2. At this time, the most significant utilization for CO2 is in enhanced oil recovery (EOR) operations. Conducted in partnership with the private sector, the program's R&D efforts are focused on maximizing the efficiency and environmental performance of advanced coal technologies while minimizing development and deployment costs.
- Materials > Metals & Mining > Coal (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
Permeability of Coal and Coal-Biomass Mixtures as Feedstocks To Reduce Net Carbon Emissions
Belvalkar, Rohan A. (Pennsylvania State U) | Chandra, Divya | Sprouse, Kenneth (Pratt & Whitney Rocketdyne) | VanEssendelft, Dirk (National Energy Technolgy Lab) | Marone, Chris (EMS Energy Institute and G3 Center, Penn State University, University Park, PA) | Elsworth, Derek (Pennsylvania State U.)
Abstract We describe measurements of permeability on coal-biomass mixtures, which are a potential feedstock to gasifiers to reduce net carbon emissions. Permeability is measured under anticipated dry feed stress conditions to determine the potential for fugitive gas emission from the gasifier into the feed hopper. Cylindrical samples of coal-biomass blends are housed within a triaxial apparatus capable of applying mean and deviatoric stresses and of concurrently measuring gas permeability. We measure the evolution of strain, porosity and permeability under mean stresses of 3.5, 7 and 14 MPa. Permeability is measured by pulse transmission testing using N2and He as the saturant and assuming the validity of Darcy's law. Porosity is measured by pressure pulse with He as saturant and assuming an ideal gas. Experiments are conducted on a range of coals and biomass blends at mixtures of 100 percent coal through 100 percent biomass. Measured permeabilities are in the range 10โ13 to 10โ16 m2 with the 100 percent biomass blends showing lower permeabilities than the coal biomass and 100 percent coal blends. Permeabilities change in loading and unloading and exhibit hysteresis. We fit the data to connect permeability with porosity using relations for porous media where permeability changes proportionally to the cube of the change in porosity. This model performs adequately since there is little size reduction in the granular mass due to the applied isotropic loading. INTRODUCTION Global development has put a significant demand on the need for affordable clean energy. Energy consumption in both the developed and the developing world is increasing with accelerating growth for developing countries. Electricity is produced primarily from non-renewable sources such as fossil fuels and nuclear power but also from renewable sources that include hydropower, wind, geothermal, solar and biomass. The United States is among one the largest consumers of electricity. The proportions of the different sources of power generation are shown in Figure1 with more than 65% of the power generated coming from fossil fuels (1). Coal remains a significant part of the energy portfolio in the U.S. as is also the case in the rest of the world. The United States has major proven coal reserves to satisfy increased energy demand along with renewables and nuclear power (2). These reserves are of high quality with most of the coal used for power generation (3).
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.89)
- Materials > Metals & Mining > Coal (1.00)
- Energy > Renewable (1.00)
- Energy > Power Industry > Utilities (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
The Plains CO2 Reduction (PCOR) Partnership: Progressing Geologic Storage Through Applied Research
Steadman, Edward N. (U. of North Dakota) | Harju, John A. (Gas Technology Institute (GTI)) | Gorecki, Charles David (Energy & Environmental Research Center) | Anagnost, Katherine K. (U. of North Dakota)
Abstract The Energy & Environmental Research Center (EERC) is focused on solving the world's energy and environmental challenges. Through its Center for Climate Change & Carbon Capture and Storage, the EERC is engaged in research activities in direct support of carbon management. One significant carbon management effort led by the EERC is the Plains CO2 Reduction (PCOR) Partnership. The PCOR Partnership is one of seven regional partnerships established by the U.S. Department of Energy National Energy Technology Laboratory to assess and develop carbon storage opportunities. The PCOR Partnership, comprising state agencies; coal, oil and gas, and other private companies; electric utilities; universities; and nonprofit organizations, covers an area of over 1.4 million square miles in the central interior of North America and includes all or part of nine states and four Canadian provinces. The PCOR Partnership region has stable geologic basins that are ideal storage targets for carbon capture and storage (CCS). These basins have been well-characterized because of commercial oil and gas activities and have very significant CO2 storage capacities. The region's energy industry is evaluating carbon management options including CCS. Many of the region's oil fields could develop carbon dioxide (CO2)-based enhanced oil recovery (EOR) projects if CO2 were more readily available. CO2-based tertiary EOR projects offer a means of developing the expertise and infrastructure required to make geologic CCS a commercial reality. The PCOR Partnership is teaming with industrial partners to conduct two commercial-scale (greater than 1 million tons a year) CCS demonstrations in its region. One of the large-scale tests will demonstrate CO2 storage in a saline formation, while the other will be a combined CCS and EOR demonstration. The sources of CO2 in both demonstrations are natural gas-processing facilities. The commercial-scale demonstration tests are designed to establish the technical and economic efficacy of CCS in the region, and injections are planned to begin between 2012 and 2014 for both projects. INTRODUCTION The Plains CO2 Reduction (PCOR) Partnership is one of seven regional partnerships operating under the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) Regional Carbon Sequestration Partnership (RCSP) Initiative. The PCOR Partnership is led by the Energy & Environmental Research Center (EERC) at the University of North Dakota in Grand Forks, North Dakota, and includes stakeholders from the public and private sector. The PCOR Partnership was established in the fall of 2003. Phase I focused on characterizing CO2 storage opportunities in the region. In the fall of 2005, the PCOR Partnership launched its 4-year Phase II program, which focused on carbon storage field validation projects that were designed to develop the regional technical expertise and experience needed to facilitate future large-scale CCS efforts in the region's subsurface and in terrestrial settings. In the fall of 2007, the PCOR Partnership initiated its 10-year Phase III program, which is focused on implementing two commercial-scale geologic carbon storage demonstration projects in the region. The project sites are located 1) in the Bell Creek oil field in Powder River County in southeastern Montana and 2) near Spectra Energy's Fort Nelson gas-processing facility, situated near Fort Nelson, British Columbia, Canada (Figure 1).
- North America > United States > North Dakota (0.76)
- North America > Canada > British Columbia > Northern Rockies Regional Municipality > Fort Nelson (0.46)
- North America > United States > Montana > Powder River County (0.25)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- North America > United States > Montana > Bell Creek Field (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Muskwa Field > Muskwa Formation (0.98)
- North America > United States > Wyoming > Wind River Basin > NPR-3 > Muddy Formation (0.97)
Characteristic Analyses of Gasification and Combustion of Different Coal Samples in CO2-Enriched and Recycled Flue Gases Atmosphere by Rapid Heating: Effects of O2 Concentration and H2O{capital Beta}
Li, Zhigang (Kyushu University) | Zhang, Xiaoming (Liaoning Technical University) | Sasaki, Kyuro (Kyushu U.) | Sugai, Yuichi (Kyushu U.) | Wang, Jiren (Liaoning Technical University)
Abstract Combustion and gasification of pulverized coal have been investigated experimentally for the conditions under high temperature gradient and CO2-rich atmospheres with 5% and 10% O2. Crushed coal samples were heated rapidly by a CO2 gas laser beam to give a high temperature gradient of order 100 ยฐC!s-1 in order to simulate radiation heat transfer conditions expected in coal gasification furnaces. The rapid heating is able to minimize effects of coal oxidation and combustion compared with previous studies with a TG-DTA that requires much longer time to heat up with oxidation effect. Moreover, coal-water mixture samples with different water/coal mass ratio were used in order to investigate roles of water vapor on the combustion and gasification. The experimental results indicated that coal weight reduction ratio or coal conversion ratio to gases follows the Arrhenius equation with increasing coal temperature; in addition, coal weight reduction ratio of the sample was increased around 5% with adding H2O in CO2-rich atmosphere. Furthermore, generations of CO gas and Hydrocarbons gases (HCs) were mainly dependent on coal temperature and O2 concentration, however, those are also affected by chemical reactions including H2O. Especially, reactions generating CO and HCs gases were stimulated at temperature over 1000 ยฐC in the CO2-rich atmosphere with 5% O2. 1. Introduction According to the IEA statistics (2007) [1], CO2 emission from fossil energy consumption in China was accounted for about 19% of global CO2 emission, of which coal-fired power plants occupied about 30% of total CO2 emission in China. Conventional coal fired boilers use air for combustion in which N2 gas is 79% in volume ratio, and it dilutes the CO2 gas concentration in the flue gas. CO2 capture cost from flue gases using amine stripping is expected to be relatively high [2]. Consequently, a new zeroemission coal gasification with CO2 and Oxygen combustion technology has been studied for new coal fired power plants [3,4], such as Integrated Gasification Combined Cycle (IGCC), including CO2 Capture and Storage (CCS). In this type of plants, recycled flue gas is used to control flame temperature and make up the volume of the missing N2 gas to ensure there is enough gas to generate energy in a gas turbine and heat in a steam boiler. As a consequence, a flue gas consisting mainly CO2 and water steam are generated, thus CO2 can be easily separated by condensation [5]. In addition, pulverized coal fired power plants could be the best candidates to install CO2 capture system, of which oxy-fuel or CO2/O2 combustion technology is one of promising methods to evade problems of CO2 separation [6].
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract This paper reviews and compares the prevailing methods, metrics and assumptions that underlie current cost estimates for CO2 capture and storage (CCS) technologies applied to fossil fuel power plants. This assessment reveals a number of significant differences and inconsistencies across different studies, not only in key technical, economic and financial assumptions related to the cost of a CCS project, but also in the methods and elements of cost that are included in a particular analysis. Such differences often are not readily apparent in the cost results that are reported publicly. As a consequence, there is likely to be some degree of confusion, misunderstanding, and mis-representation of CCS cost information, especially among audiences not familiar with the details of CCS costing methods. Given the current state of CCS technology, more careful attention to the analysis and reporting of cost uncertainties and variability also is especially important. A path forward is suggested to improve the consistency and transparency of CCS cost estimates. Introduction and Objectives Carbon capture and storage (CCS) is a potentially critical technology for mitigating global climate change, but its current cost is a major barrier to applications at power plants and other large industrial sources of CO2. Efforts are underway to develop new lower-cost technologies, especially for CO2 captureโthe costliest component of a CCS system [1]. Given its importance, information on CCS costs is sought by a broad range of actors and organizations for investment decisions, technology assessments, R&D activities, policy analysis, and energy and environmental policy-making (including legislation and regulations involving CCS). Yet, as this paper will show, there are significant differences and inconsistencies in the way that CCS costs are currently calculated and reported by various authors and organizations involved in CCS technology development, analysis and use. The major objective of this paper, therefore, is to highlight key methodological issues related to CCS cost estimates, including project scope, terminology, calculation procedures, and the cost elements included or excluded in CCS cost estimates. The paper also discusses the various measures of CCS cost that are commonly sought and reported by organizations worldwide, and identifies some of the critical (and sometimes controversial) assumptions in such estimates. Also discussed are how (or whether) CCS costing methods treat issues such as the level of technological maturity, the type and vintage of facility treated (e.g., new vs. retrofitted power plant), and technological change over time (learning). Issues related to bias, uncertainty and variability in assumptions and underlying data also are discussed and suggestions for a path forward are presented. Cost Measures and Metrics A variety of measures are used in the literature to report the overall cost of CO2 capture and storage systems and other CO2 reduction measures [2]. The most common include the:Cost of CO2 avoided Cost of CO2 captured Cost of CO2 reduced (or abated) Increased cost of electricity
- North America > United States (1.00)
- Europe (1.00)
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
Abstract Large volumes of CO2 will have to be stored in the subsurface for carbon capture and geological sequestration to have a significant impact on the reduction of carbon emissions. Injection of large volumes of CO2 into deep saline formations can lead to significant pressure increases within that formation. The increased pressure can be a limiting factor for injection rates; it can also drive vertical brine migration through leakage pathways (e.g., abandoned wells) that could contaminate sources of drinking water. Production of brine from the injection formation can reduce the pressure increase while also limiting the spatial extent of the pressure increase. The impact of brine extraction is investigated using a hypothetical injection domain conditioned by parameters from the Illinois Basin. The domain contains one injection well and encompasses several aquifers connected through diffusive brine leakage. A vertically-integrated approach is used to model the injection formation and overlying aquifers. A set of production scenarios illustrates the impact of brine production on injection rates and vertical brine movement. The scenarios include production with surface disposal and production with reinjection into overlying formations (with and without desalinization). The results show that brine production can reduce the pressure buildup in the injection formation, leading to an increase in injectivity and a concomitant reduction in fresh water contamination risk by reducing the area of potential impact. While reinjection of brine into an overlying aquifer solves the disposal problem, it also reduces the effectiveness of brine production by increasing the pressure. Injection of a smaller amount of more concentrated brine resulting from desalinization reduces the impact of reinjection and acts as an additional source of fresh water, but increases the cost of the injection operation. Based on the results from these numerical experiments pressure management through brine production should be considered for industrial-scale CO2 injection operations, as it increases injectivity and reduces the size of the area of potential impact. However, the brine disposal problem needs to be solved for brine production to be a useful endeavor. INTRODUCTION Carbon capture and sequestration (CCS) is one of the options currently being discussed to reduce anthropogenic carbon emissions (Pacala &Socolow, 2004; IPCC, 2005; Meadowcroft & Langhelle, 2011). If CCS is to have a significant role in the carbon reduction strategy, large volumes of carbon dioxide (CO2) will have to be sequestered for long time periods. Deep sedimentary formations are being targeted as storage sites, because of their large accessible storage volumes (USDOE, 2007). Sedimentary basins often consist of a sharply defined sequence of alternating high and low permeability formations. CO2 is injected into formations with high permeability (e.g., sandstone) and the overlying formations with low permeability (e.g., shale) act as confining cap rock.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin (0.99)
- North America > Canada (0.89)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Evaluation of Large-Scale Geologic Carbon Sequestration Potential in the Virginia Piedmont and Coastal Plain
Roth, Ben (VCCER) | Hernon, Katie (Department of Mines, Minerals, and Energy) | Lassetter, William (Department of Mines, Minerals, and Energy) | Ripepi, Nino (Virginia Center for Coal and Energy Research)
Abstract The geologic storage of carbon dioxide (CO2) is increasingly being recognized as a suitable means of sequestering this greenhouse gas. The Piedmont and Coastal Plain physiographic provinces of the eastern United States contain a large number of greenhouse gas emissions sources, such as power plants and other industrial facilities, but little work has been carried out to examine the potential of local geologic carbon storage. In order to address this issue, a preliminary investigation into the carbon sequestration potential within the Virginia Piedmont and Coastal Plain has been conducted. This paper builds on previous work directed by the Southeast Regional Carbon Sequestration Partnership (SECARB) and the Southern States Energy Board (SSEB) in conjunction with the Texas Bureau of Economic Geology (BEG), examining potential sinks for geologic storage of carbon dioxide generated by power plants in the Southeastern region of the U.S. Detailed geologic characterization has been carried out, which investigated formations with 1) suitable porosity, permeability, and favorable injectivity, 2) favorable storage capacity characteristics, 3) suitable mineralogical properties, and 4) overlying geologic seals to prevent the vertical movement of the injected CO2. These characteristics were evaluated based on publicly available subsurface geologic information, published maps and cross-sections, available core, and wireline log data. The suitability characteristics for the potential carbon sinks are based on the specific criteria established in the previous Coastal Characterization Studies for the Carolinas and Georgia. Based on the regional investigation, it was determined that the presence of Mesozoic-age sedimentary basins, namely the Taylorsville and Richmond Basins, and, offshore, the Potomac aquifer, provided the most suitable potential reservoirs for large-scale storage of CO2. In addition to the geologic characterization, a cost analysis was conducted for source-to-sink matching. This was completed in order to determine a lowest cost scenario for transport of CO2 from the producing power plant to the most suitable sequestration site. This multi-disciplinary research has been carried out by the Virginia Center for Coal and Energy Research (VCCER) at Virginia Tech and the Virginia Department of Mines, Minerals, and Energy (DMME).
- Phanerozoic > Mesozoic > Jurassic (1.00)
- Phanerozoic > Mesozoic > Triassic > Upper Triassic (0.93)
- Geology > Structural Geology > Tectonics > Plate Tectonics (1.00)
- Geology > Structural Geology > Tectonics > Extensional Tectonics (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment (1.00)
- (8 more...)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Magnetic Surveying (1.00)
- Geophysics > Gravity Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)