National Library of Energy BETA

Sample records for geologic co2 storage

  1. On Leakage from Geologic Storage Reservoirs of CO2

    SciTech Connect (OSTI)

    Pruess, Karsten

    2006-02-14

    Large amounts of CO2 would need to be injected underground to achieve a significant reduction of atmospheric emissions. The large areal extent expected for CO2 plumes makes it likely that caprock imperfections will be encountered, such as fault zones or fractures, which may allow some CO2 to escape from the primary storage reservoir. Leakage of CO2 could also occur along wellbores. Concerns with escape of CO2 from a primary geologic storage reservoir include (1) acidification of groundwater resources, (2) asphyxiation hazard when leaking CO2 is discharged at the land surface, (3) increase in atmospheric concentrations of CO2, and (4) damage from a high-energy, eruptive discharge (if such discharge is physically possible). In order to gain public acceptance for geologic storage as a viable technology for reducing atmospheric emissions of CO2, it is necessary to address these issues and demonstrate that CO2 can be injected and stored safely in geologic formations.

  2. DOE Manual Studies 11 Major CO2 Geologic Storage Formations

    Broader source: Energy.gov [DOE]

    A comprehensive study of 11 geologic formations suitable for permanent underground carbon dioxide (CO2) storage is contained in a new manual issued by the U.S. Department of Energy.

  3. International Symposium on Site Characterization for CO2Geological Storage

    SciTech Connect (OSTI)

    Tsang, Chin-Fu

    2006-02-23

    Several technological options have been proposed to stabilize atmospheric concentrations of CO{sub 2}. One proposed remedy is to separate and capture CO{sub 2} from fossil-fuel power plants and other stationary industrial sources and to inject the CO{sub 2} into deep subsurface formations for long-term storage and sequestration. Characterization of geologic formations for sequestration of large quantities of CO{sub 2} needs to be carefully considered to ensure that sites are suitable for long-term storage and that there will be no adverse impacts to human health or the environment. The Intergovernmental Panel on Climate Change (IPCC) Special Report on Carbon Dioxide Capture and Storage (Final Draft, October 2005) states that ''Site characterization, selection and performance prediction are crucial for successful geological storage. Before selecting a site, the geological setting must be characterized to determine if the overlying cap rock will provide an effective seal, if there is a sufficiently voluminous and permeable storage formation, and whether any abandoned or active wells will compromise the integrity of the seal. Moreover, the availability of good site characterization data is critical for the reliability of models''. This International Symposium on Site Characterization for CO{sub 2} Geological Storage (CO2SC) addresses the particular issue of site characterization and site selection related to the geologic storage of carbon dioxide. Presentations and discussions cover the various aspects associated with characterization and selection of potential CO{sub 2} storage sites, with emphasis on advances in process understanding, development of measurement methods, identification of key site features and parameters, site characterization strategies, and case studies.

  4. Novel Concepts Research in Geologic Storage of CO2

    SciTech Connect (OSTI)

    Neeraj Gupta

    2006-09-30

    As part of the Department of Energy's (DOE) initiative on developing new technologies for the storage of carbon dioxide (CO{sub 2}) in geologic reservoirs, Battelle has been investigating the feasibility of CO{sub 2} sequestration in the deep saline reservoirs of the Ohio River Valley region. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, Ohio Coal Development Office (OCDO) of the Ohio Air Quality Development Authority, Schlumberger, and Battelle. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations. The current technical progress report summarizes activities completed for the July-September 2006 period of the project. As discussed in the following report, the main accomplishments were reservoir modeling for the Copper Ridge ''B-zone'' and design and feasibility support tasks. Work continued on the development of injection well design options, engineering assessment of CO2 capture systems, permitting, and assessment of monitoring technologies as they apply to the project site. In addition, an integrated risk analysis of the proposed system was completed. Finally, slipstream capture construction issues were evaluated with AEP to move the project toward an integrated carbon capture and storage system at the Mountaineer site. Overall, the current design feasibility phase project is proceeding according to plans.

  5. DOE Selects Projects to Monitor and Evaluate Geologic CO2 Storage |

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Department of Energy Selects Projects to Monitor and Evaluate Geologic CO2 Storage DOE Selects Projects to Monitor and Evaluate Geologic CO2 Storage August 24, 2009 - 1:00pm Addthis Washington, D.C. -- The U.S. Department of Energy (DOE) today announced the selection of 19 projects to enhance the capability to simulate, track, and evaluate the potential risks of carbon dioxide (CO2) storage in geologic formations. The projects' total value is approximately $35.8 million over four years, with

  6. Novel Concepts Research in Geologic Storage of CO2

    SciTech Connect (OSTI)

    Neeraj Gupta

    2007-06-30

    As part of the Department of Energy's (DOE) initiative on developing new technologies for the storage of carbon dioxide (CO{sub 2}) in geologic reservoirs, Battelle has been investigating the feasibility of CO{sub 2} sequestration in the deep saline reservoirs of the Ohio River Valley region. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, Ohio Coal Development Office (OCDO) of the Ohio Air Quality Development Authority, Schlumberger, and Battelle. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations. The current technical progress report summarizes activities completed for the April-June 2007 period of the project. As discussed in the report, the main accomplishments related to preparation to move forward with a 100,000-300,000 metric tons CO{sub 2}/year capture and sequestration project at the Mountaineer site. The program includes a 10 to 30-megawatt thermal product validation at the Mountaineer Plant where up to 300,000 metric tons CO{sub 2}/year will be captured and sequestered in deep rock formations identified in this work. Design and feasibility support tasks such as development of injection well design options, engineering assessment of CO{sub 2} capture systems, permitting, reservoir storage simulations, and assessment of monitoring technologies as they apply to the project site were developed for the project. Plans to facilitate the next steps of the project will be the main work remaining in this portion of the project as

  7. Novel Concepts Research in Geologic Storage of CO2

    SciTech Connect (OSTI)

    Neeraj Gupta

    2007-03-31

    As part of the Department of Energy's (DOE) initiative on developing new technologies for the storage of carbon dioxide (CO{sub 2}) in geologic reservoirs, Battelle has been investigating the feasibility of CO{sub 2} sequestration in the deep saline reservoirs of the Ohio River Valley region. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, Ohio Coal Development Office (OCDO) of the Ohio Air Quality Development Authority, Schlumberger, and Battelle. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations. The current technical progress report summarizes activities completed for the January-March 2007 period of the project. As discussed in the report, the main accomplishment was an announcement by AEP to move forward with a {approx}100,000 metric tons CO{sub 2}/year capture and sequestration project at the Mountaineer site. This decision was the outcome of last several years of research under the current DOE funded project involving the technology, site-specific characterization, modeling, risk assessment, etc. This news marks a significant accomplishment for DOE's research program to translate the theoretical potential for carbon sequestration into tangible measures and approaches for the region. The program includes a 30-megawatt thermal product validation at the Mountaineer Plant where up to 100,000 metric tons CO{sub 2}/year will be captured and sequestered in deep rock formations identified in this work. Plans include further steps at

  8. On CO2 Behavior in the Subsurface, Following Leakage from aGeologic Storage Reservoir

    SciTech Connect (OSTI)

    Pruess, Karsten

    2006-02-09

    The amounts of CO2 that would need to be injected intogeologic storage reservoirs to achieve a significant reduction ofatmospheric emissions are very large. A 1000 MWe coal-fired power plantemits approximately 30,000 tonnes of CO2 per day, 10 Mt per year(Hitchon, 1996). When injected underground over a typical lifetime of 30years of such a plant, the CO2 plume may occupy a large area of order 100km2 or more, and fluid pressure increase in excess of 1 bar(corresponding to 10 m water head) may extend over an area of more than2,500 km2 (Pruess, et al., 2003). The large areal extent expected for CO2plumes makes it likely that caprock imperfections will be encountered,such as fault zones or fractures, which may allow some CO2 to escape fromthe primary storage reservoir. Under most subsurface conditions oftemperature and pressure, CO2 is buoyant relative to groundwaters. If(sub-)vertical pathways are available, CO2 will tend to flow upward and,depending on geologic conditions, may eventually reach potablegroundwater aquifers or even the land surface. Leakage of CO2 could alsooccur along wellbores, including pre-existing and improperly abandonedwells, or wells drilled in connection with the CO2 storage operations.The pressure increases accompanying CO2 injection will give rise tochanges in effective stress that could cause movement along faults,increasing permeability and potential for leakage.Escape of CO2 from aprimary geologic storage reservoir and potential hazards associated withits discharge at the land surface raise a number of concerns, including(1) acidification of groundwater resources, (2) asphyxiation hazard whenleaking CO2 is discharged at the land surface, (3) increase inatmospheric concentrations of CO2, and (4) damage from a high-energy,eruptive discharge (if such discharge is physically possible). In orderto gain public acceptance for geologic storage as a viable technology forreducing atmospheric emissions of CO2, it is necessary to address theseissues

  9. Site Characterization of Promising Geologic Formations for CO2 Storage

    Office of Energy Efficiency and Renewable Energy (EERE)

    In September 2009, the U.S. Department of Energy announced the award of 11 projects with a total project value of $75.5 million* to conduct site characterization of promising geologic formations...

  10. The Rosetta Resources CO2 Storage Project - A WESTCARB GeologicPilot Test

    SciTech Connect (OSTI)

    Trautz, Robert; Benson, Sally; Myer, Larry; Oldenburg, Curtis; Seeman, Ed; Hadsell, Eric; Funderburk, Ben

    2006-01-30

    WESTCARB, one of seven U.S. Department of Energypartnerships, identified (during its Phase I study) over 600 gigatonnesof CO2 storage capacity in geologic formations located in the Westernregion. The Western region includes the WESTCARB partnership states ofAlaska, Arizona, California, Nevada, Oregon and Washington and theCanadian province of British Columbia. The WESTCARB Phase II study iscurrently under way, featuring three geologic and two terrestrial CO2pilot projects designed to test promising sequestration technologies atsites broadly representative of the region's largest potential carbonsinks. This paper focuses on two of the geologic pilot studies plannedfor Phase II -referred to-collectively as the Rosetta-Calpine CO2 StorageProject. The first pilot test will demonstrate injection of CO2 into asaline formation beneath a depleted gas reservoir. The second test willgather data for assessing CO2 enhanced gas recovery (EGR) as well asstorage in a depleted gas reservoir. The benefit of enhanced oil recovery(EOR) using injected CO2 to drive or sweep oil from the reservoir towarda production well is well known. EaR involves a similar CO2 injectionprocess, but has received far less attention. Depleted natural gasreservoirs still contain methane; therefore, CO2 injection may enhancemethane production by reservoir repressurization or pressure maintenance.CO2 injection into a saline formation, followed by injection into adepleted natural gas reservoir, is currently scheduled to start inOctober 2006.

  11. Center for Geologic Storage of CO2 (GSCO2) | U.S. DOE Office of Science

    Office of Science (SC) Website

    (SC) Center for Geologic Storage of CO2 (GSCO2) Energy Frontier Research Centers (EFRCs) EFRCs Home Centers EFRC External Websites Research Science Highlights News & Events Publications History Contact BES Home Centers Center for Geologic Storage of CO2 (GSCO2) Print Text Size: A A A FeedbackShare Page GSCO<sub>2</sub> Director Scott M. Frailey Lead Institution University of Illinois at Urbana-Champaign Year Established 2014 Mission To generate new conceptual, mathematical,

  12. Leakage of CO2 from geologic storage: Role of secondaryaccumulation at shallow depth

    SciTech Connect (OSTI)

    Pruess, K.

    2007-05-31

    Geologic storage of CO2 can be a viable technology forreducing atmospheric emissions of greenhouse gases only if it can bedemonstrated that leakage from proposed storage reservoirs and associatedhazards are small or can be mitigated. Risk assessment must evaluatepotential leakage scenarios and develop a rational, mechanisticunderstanding of CO2 behavior during leakage. Flow of CO2 may be subjectto positive feedbacks that could amplify leakage risks and hazards,placing a premium on identifying and avoiding adverse conditions andmechanisms. A scenario that is unfavorable in terms of leakage behavioris formation of a secondary CO2 accumulation at shallow depth. This paperdevelops a detailed numerical simulation model to investigate CO2discharge from a secondary accumulation, and evaluates the role ofdifferent thermodynamic and hydrogeologic conditions. Our simulationsdemonstrate self-enhancing as well as self-limiting feedbacks.Condensation of gaseous CO2, 3-phase flow of aqueous phase -- liquid CO2-- gaseous CO2, and cooling from Joule-Thomson expansion and boiling ofliquid CO2 are found to play important roles in the behavior of a CO2leakage system. We find no evidence that a subsurface accumulation of CO2at ambient temperatures could give rise to a high-energy discharge, aso-called "pneumatic eruption."

  13. Geochemical Implications of CO2 Leakage Associated with Geologic Storage: A Review

    SciTech Connect (OSTI)

    Harvey, Omar R.; Qafoku, Nikolla; Cantrell, Kirk J.; Brown, Christopher F.

    2012-07-09

    Leakage from deep storage reservoirs is a major risk factor associated with geologic sequestration of carbon dioxide (CO2). Different scientific theories exist concerning the potential implications of such leakage for near-surface environments. The authors of this report reviewed the current literature on how CO2 leakage (from storage reservoirs) would likely impact the geochemistry of near surface environments such as potable water aquifers and the vadose zone. Experimental and modeling studies highlighted the potential for both beneficial (e.g., CO2 re sequestration or contaminant immobilization) and deleterious (e.g., contaminant mobilization) consequences of CO2 intrusion in these systems. Current knowledge gaps, including the role of CO2-induced changes in redox conditions, the influence of CO2 influx rate, gas composition, organic matter content and microorganisms are discussed in terms of their potential influence on pertinent geochemical processes and the potential for beneficial or deleterious outcomes. Geochemical modeling was used to systematically highlight why closing these knowledge gaps are pivotal. A framework for studying and assessing consequences associated with each factor is also presented in Section 5.6.

  14. Early opportunities of CO2 geological storage deployment in coal chemical industry in China

    SciTech Connect (OSTI)

    Wei, Ning; Li, Xiaochun; Liu, Shengnan; Dahowski, Robert T.; Davidson, Casie L.

    2014-11-12

    Abstract: Carbon dioxide capture and geological storage (CCS) is regarded as a promising option for climate change mitigation; however, the high capture cost is the major barrier to large-scale deployment of CCS technologies. High-purity CO2 emission sources can reduce or even avoid the capture requirements and costs. Among these high-purity CO2 sources, certain coal chemical industry processes are very important, especially in China. In this paper, the basic characteristics of coal chemical industries in China is investigated and analyzed. As of 2013 there were more than 100 coal chemical plants in operation or in late planning stages. These emission sources together emit 430 million tons CO2 per year, of which about 30% are emit high-purity and pure CO2 (CO2 concentration >80% and >99% respectively).Four typical source-sink pairs are studied by a techno-economic evaluation, including site screening and selection, source-sink matching, concept design, and experienced economic evaluation. The technical-economic evaluation shows that the levelized cost of a CO2 capture and aquifer storage project in the coal chemistry industry ranges from 14 USD/t to 17 USD/t CO2. When a 15USD/t CO2 tax and 15USD/t for CO2 sold to EOR are considered, the levelized cost of CCS project are negative, which suggests a net economic benefit from some of these CCS projects. This might provide China early opportunities to deploy and scale-up CCS projects in the near future.

  15. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO2 PHASE III THE OHIO RIVER VALLEY CO2 STORAGE PROJECT

    SciTech Connect (OSTI)

    Neeraj Gupta

    2005-05-26

    As part of the Department of Energy's (DOE) initiation on developing new technologies for storage of carbon dioxide in geologic reservoir, Battelle has been awarded a project to investigate the feasibility of CO{sub 2} sequestration in the deep saline reservoirs in the Ohio River Valley region. This project is the Phase III of Battelle's work under the Novel Concepts in Greenhouse Gas Management grant. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant in particular, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations and potentially in nearby deep coal seams. The current technical progress report summarizes activities completed for the January through March 2005 period of the project. As discussed in the report, the technical activities focused on development of injection well design, preparing a Class V Underground Injection Control permit, assessment of monitoring technologies, analysis of coal samples for testing the capture system by Mitsubishi Heavy Industry, and presentation of project progress at several venues. In addition, related work has progressed on a collaborative risk assessment project with Japan research institute CREIPI and technical application for the Midwest Regional Carbon Sequestration Partnership.

  16. DOE Research Projects to Examine Promising Geologic Formations for CO2 Storage

    Broader source: Energy.gov [DOE]

    The Department of Energy today announced 11 projects valued at $75.5 million aimed at increasing scientific understanding about the potential of promising geologic formations to safely and permanently store carbon dioxide (CO2).

  17. New Strategies for Finding Abandoned Wells at Proposed Geologic Storage Sites for CO2

    SciTech Connect (OSTI)

    Hammack, R.W.; Veloski, G.A.

    2007-09-01

    Prior to the injection of CO2 into geological formations, either for enhanced oil recovery or for CO2 sequestration, it is necessary to locate wells that perforate the target formation and are within the radius of influence for planned injection wells. Locating and plugging wells is necessary because improperly plugged well bores provide the most rapid route for CO2 escape to the surface. This paper describes the implementation and evaluation of helicopter and ground-based well detection strategies at a 100+ year old oilfield in Wyoming where a CO2 flood is planned. This project was jointly funded by the U.S. Department of Energys National Energy Technology Laboratory and Fugro Airborne Surveys.

  18. DOE Targets Rural Indiana Geologic Formation for CO2 Storage Field Test

    Broader source: Energy.gov [DOE]

    A U.S. Department of Energy team of regional partners has begun injecting 8,000 tons of carbon dioxide (CO2) to evaluate the carbon storage potential and test the enhanced oil recovery (EOR) potential of the Mississippian-aged Clore Formation in Posey County, Ind.

  19. Estimating the supply and demand for deep geologic CO2 storage capacity over the course of the 21st Century: A meta-analysis of the literature

    SciTech Connect (OSTI)

    Dooley, James J.

    2013-08-05

    Whether there is sufficient geologic CO2 storage capacity to allow CCS to play a significant role in mitigating climate change has been the subject of debate since the 1990s. This paper presents a meta- analysis of a large body of recently published literature to derive updated estimates of the global deep geologic storage resource as well as the potential demand for this geologic CO2 storage resource over the course of this century. This analysis reveals that, for greenhouse gas emissions mitigation scenarios that have end-of-century atmospheric CO2 concentrations of between 350 ppmv and 725 ppmv, the average demand for deep geologic CO2 storage over the course of this century is between 410 GtCO2 and 1,670 GtCO2. The literature summarized here suggests that -- depending on the stringency of criteria applied to calculate storage capacity global geologic CO2 storage capacity could be: 35,300 GtCO2 of theoretical capacity; 13,500 GtCO2 of effective capacity; 3,900 GtCO2, of practical capacity; and 290 GtCO2 of matched capacity for the few regions where this narrow definition of capacity has been calculated. The cumulative demand for geologic CO2 storage is likely quite small compared to global estimates of the deep geologic CO2 storage capacity, and therefore, a lack of deep geologic CO2 storage capacity is unlikely to be an impediment for the commercial adoption of CCS technologies in this century.

  20. Developing a Comprehensive Risk Assessment Framework for Geological Storage CO2

    SciTech Connect (OSTI)

    Duncan, Ian

    2014-08-31

    The operational risks for CCS projects include: risks of capturing, compressing, transporting and injecting CO₂; risks of well blowouts; risk that CO₂ will leak into shallow aquifers and contaminate potable water; and risk that sequestered CO₂ will leak into the atmosphere. This report examines these risks by using information on the risks associated with analogue activities such as CO2 based enhanced oil recovery (CO2-EOR), natural gas storage and acid gas disposal. We have developed a new analysis of pipeline risk based on Bayesian statistical analysis. Bayesian theory probabilities may describe states of partial knowledge, even perhaps those related to non-repeatable events. The Bayesian approach enables both utilizing existing data and at the same time having the capability to adsorb new information thus to lower uncertainty in our understanding of complex systems. Incident rates for both natural gas and CO2 pipelines have been widely used in papers and reports on risk of CO2 pipelines as proxies for the individual risk created by such pipelines. Published risk studies of CO2 pipelines suggest that the individual risk associated with CO2 pipelines is between 10-3 and 10-4, which reflects risk levels approaching those of mountain climbing, which many would find unacceptably high. This report concludes, based on a careful analysis of natural gas pipeline failures, suggests that the individual risk of CO2 pipelines is likely in the range of 10-6 to 10-7, a risk range considered in the acceptable to negligible range in most countries. If, as is commonly thought, pipelines represent the highest risk component of CCS outside of the capture plant, then this conclusion suggests that most (if not all) previous quantitative- risk assessments of components of CCS may be orders of magnitude to high. The potential lethality of unexpected CO2 releases from pipelines or wells are arguably the highest risk aspects of CO2 enhanced oil recovery (CO2-EOR), carbon capture

  1. Estimating Plume Volume for Geologic Storage of CO2 in Saline Aquifers

    SciTech Connect (OSTI)

    Doughty, Christine

    2008-07-11

    Typically, when a new subsurface flow and transport problem is first being considered, very simple models with a minimal number of parameters are used to get a rough idea of how the system will evolve. For a hydrogeologist considering the spreading of a contaminant plume in an aquifer, the aquifer thickness, porosity, and permeability might be enough to get started. If the plume is buoyant, aquifer dip comes into play. If regional groundwater flow is significant or there are nearby wells pumping, these features need to be included. Generally, the required parameters tend to be known from pre-existing studies, are parameters that people working in the field are familiar with, and represent features that are easy to explain to potential funding agencies, regulators, stakeholders, and the public. The situation for geologic storage of carbon dioxide (CO{sub 2}) in saline aquifers is quite different. It is certainly desirable to do preliminary modeling in advance of any field work since geologic storage of CO{sub 2} is a novel concept that few people have much experience with or intuition about. But the parameters that control CO{sub 2} plume behavior are a little more daunting to assemble and explain than those for a groundwater flow problem. Even the most basic question of how much volume a given mass of injected CO{sub 2} will occupy in the subsurface is non-trivial. However, with a number of simplifying assumptions, some preliminary estimates can be made, as described below. To make efficient use of the subsurface storage volume available, CO{sub 2} density should be large, which means choosing a storage formation at depths below about 800 m, where pressure and temperature conditions are above the critical point of CO{sub 2} (P = 73.8 bars, T = 31 C). Then CO{sub 2} will exist primarily as a free-phase supercritical fluid, while some CO{sub 2} will dissolve into the aqueous phase.

  2. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO2 PHASE III

    SciTech Connect (OSTI)

    Neeraj Gupta

    2006-05-18

    As part of the Department of Energy's (DOE) initiative on developing new technologies for storage of carbon dioxide in geologic reservoirs, Battelle has been investigating the feasibility of CO{sub 2} sequestration in the deep saline reservoirs in the Ohio River Valley region. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, The Ohio Coal Development Office (OCDO) of the Ohio Air Quality Development Authority, Schlumberger, and Battelle. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant in particular, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations. The current technical progress report summarizes activities completed for the January-March 2006 period of the project. As discussed in the following report, the main accomplishments were analysis of Copper Ridge ''B-zone'' reservoir test results from the AEP No.1 well and design and feasibility support tasks. Reservoir test results indicate injection potential in the Copper Ridge ''B-zone'' may be significantly higher than anticipated for the Mountaineer site. Work continued on development of injection well design options, engineering assessment of CO{sub 2} capture systems, permitting, and assessment of monitoring technologies as they apply to the project site. In addition, organizational and scheduling issues were addressed to move the project toward an integrated carbon capture and storage system at the Mountaineer site. Overall, the current design feasibility phase project is proceeding according to plans.

  3. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO2 PHASE III

    SciTech Connect (OSTI)

    Neeraj Gupta

    2006-01-23

    As part of the Department of Energy's (DOE) initiative on developing new technologies for storage of carbon dioxide in geologic reservoirs, Battelle has been investigating the feasibility of CO{sub 2} sequestration in the deep saline reservoirs in the Ohio River Valley region. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, The Ohio Coal Development Office (OCDO) of the Ohio Air Quality Development Authority, Schlumberger, and Battelle. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant in particular, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations. The current technical progress report summarizes activities completed for the October through December 2005 period of the project. As discussed in the following report, the main field activity was reservoir testing in the Copper Ridge ''B-zone'' in the AEP No.1 well. In addition reservoir simulations were completed to assess feasibility of CO{sub 2} injection for the Mountaineer site. These reservoir testing and computer simulation results suggest that injection potential may be substantially more than anticipated for the Mountaineer site. Work also continued on development of injection well design options, engineering assessment of CO{sub 2} capture systems, permitting, and assessment of monitoring technologies as they apply to the project site. Overall, the current design feasibility phase project is proceeding according to plans.

  4. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO2 PHASE III

    SciTech Connect (OSTI)

    Neeraj Gupta

    2005-11-04

    As part of the Department of Energy's (DOE) initiative on developing new technologies for storage of carbon dioxide in geologic reservoirs, Battelle has been investigating the feasibility of CO{sub 2} sequestration in the deep saline reservoirs in the Ohio River Valley region. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, The Ohio Coal Development Office (OCDO) of the Ohio Air Quality Development Authority, and Schlumberger. The main objective of the project is to demonstrate that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. In addition, the project is designed to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant in particular, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations. The current technical progress report summarizes activities completed for the July through September 2005 period of the project. As discussed in the report, the field activities focused on preparations for reservoir testing in the Copper Ridge ''B-zone'' in the AEP No.1 well. In addition work continued on development of injection well design options, engineering assessment of CO{sub 2} capture systems, reservoir simulations, work on a Class V Underground Injection Control permit, and assessment of monitoring technologies as they apply to the project site. Overall, the current design feasibility phase project is proceeding according to plans.

  5. Using the Choquet integral for screening geological CO2 storage sites

    SciTech Connect (OSTI)

    Zhang, Y.

    2011-03-01

    For geological CO{sub 2} storage site selection, it is desirable to reduce the number of candidate sites through a screening process before detailed site characterization is performed. Screening generally involves defining a number of criteria which then need to be evaluated for each site. The importance of each criterion to the final evaluation will generally be different. Weights reflecting the relative importance of these criteria can be provided by experts. To evaluate a site, each criterion must be evaluated and scored, and then aggregated, taking into account the importance of the criteria. We propose the use of the Choquet integral for aggregating the scores. The Choquet integral considers the interactions among criteria, i.e. whether they are independent, complementary to each other, or partially repetitive. We also evaluate the Shapley index, which demonstrates how the importance of a given piece of information may change if it is considered by itself or together with other available information. An illustrative example demonstrates how the Choquet integral properly accounts for the presence of redundancy in two site-evaluation criteria, making the screening process more defensible than the standard weighted-average approach.

  6. Tagging CO2 to Enable Quantitative Inventories of Geological Carbon Storage

    SciTech Connect (OSTI)

    Lackner, Klaus; Matter, Juerg; Park, Ah-Hyung; Stute, Martin; Carson, Cantwell; Ji, Yinghuang

    2014-06-30

    In the wake of concerns about the long term integrity and containment of sub-surface CO2 sequestration reservoirs, many efforts have been made to improve the monitoring, verification, and accounting methods for geo-sequestered CO2. Our project aimed to demonstrate the feasibility of a system designed to tag CO2 with carbon isotope 14C immediately prior to sequestration to a level that is normal on the surface (one part per trillion). Because carbon found at depth is naturally free of 14C, this tag would easily differentiate pre-existing carbon from anthropogenic injected carbon and provide an excellent handle for monitoring its whereabouts in the subsurface. It also creates an excellent handle for adding up anthropogenic carbon inventories. Future inventories in effect count 14C atoms. Accordingly, we have developed a 14C tagging system suitable for use at the part-per-trillion level. This system consists of a gas-exchange apparatus to make disposable cartridges ready for controlled injection into a fast flowing stream of pressurized CO2. We built a high-pressure injection and tagging system, and a 14C detection system. The disposable cartridge and injection system have been successfully demonstrated in the lab with a high-pressure flow reactor, as well as in the field at the CarbFix CO2 sequestration site in Iceland. The laser-based 14C detection system originally conceived has been shown to possess inadequate sensitivity for ambient levels. Alternative methods for detecting 14C, such as saturated cavity absorption ringdown spectroscopy and scintillation counting, may still be suitable. KEYWORDS

  7. A Review of Hazardous Chemical Species Associated with CO2 Capturefrom Coal-Fired Power Plants and Their Potential Fate in CO2 GeologicStorage

    SciTech Connect (OSTI)

    Apps, J.A.

    2006-02-23

    Conventional coal-burning power plants are major contributors of excess CO2 to the atmospheric inventory. Because such plants are stationary, they are particularly amenable to CO2 capture and disposal by deep injection into confined geologic formations. However, the energy penalty for CO2 separation and compression is steep, and could lead to a 30-40 percent reduction in useable power output. Integrated gas combined cycle (IGCC) plants are thermodynamically more efficient, i.e.,produce less CO2 for a given power output, and are more suitable for CO2 capture. Therefore, if CO2 capture and deep subsurface disposal were to be considered seriously, the preferred approach would be to build replacement IGCC plants with integrated CO2 capture, rather than retrofit existing conventional plants. Coal contains minor quantities of sulfur and nitrogen compounds, which are of concern, as their release into the atmosphere leads to the formation of urban ozone and acid rain, the destruction of stratospheric ozone, and global warming. Coal also contains many trace elements that are potentially hazardous to human health and the environment. During CO2 separation and capture, these constituents could inadvertently contaminate the separated CO2 and be co-injected. The concentrations and speciation of the co-injected contaminants would differ markedly, depending on whether CO2 is captured during the operation of a conventional or an IGCC plant, and the specific nature of the plant design and CO2 separation technology. However, regardless of plant design or separation procedures, most of the hazardous constituents effectively partition into the solid waste residue. This would lead to an approximately two order of magnitude reduction in contaminant concentration compared with that present in the coal. Potential exceptions are Hg in conventional plants, and Hg and possibly Cd, Mo and Pb in IGCC plants. CO2 capture and injection disposal could afford an opportunity to deliberately capture

  8. The Potential for Increased Atmospheric CO2 Emissions and Accelerated Consumption of Deep Geologic CO2 Storage Resources Resulting from the Large-Scale Deployment of a CCS-Enabled Unconventional Fossil Fuels Industry in the U.S.

    SciTech Connect (OSTI)

    Dooley, James J.; Dahowski, Robert T.; Davidson, Casie L.

    2009-11-02

    Desires to enhance the energy security of the United States have spurred significant interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO2) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO2 storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO2 from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO2 capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO2 emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000-7000 MtCO2, in addition to storing potentially 900-5000 MtCO2 in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000-5000 MtCO2 emitted to the atmosphere in addition to potentially 21,000-22,000 MtCO2 stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO2 storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result

  9. sRecovery Act: Geologic Characterization of the South Georgia Rift Basin for Source Proximal CO2 Storage

    SciTech Connect (OSTI)

    Waddell, Michael

    2014-09-30

    This study focuses on evaluating the feasibility and suitability of using the Jurassic/Triassic (J/TR) sediments of the South Georgia Rift basin (SGR) for CO2 storage in southern South Carolina and southern Georgia The SGR basin in South Carolina (SC), prior to this project, was one of the least understood rift basin along the east coast of the U.S. In the SC part of the basin there was only one well (Norris Lightsey #1) the penetrated into J/TR. Because of the scarcity of data, a scaled approach used to evaluate the feasibility of storing CO2 in the SGR basin. In the SGR basin, 240 km (~149 mi) of 2-D seismic and 2.6 km2 3-D (1 mi2) seismic data was collected, process, and interpreted in SC. In southern Georgia 81.3 km (~50.5 mi) consisting of two 2-D seismic lines were acquired, process, and interpreted. Seismic analysis revealed that the SGR basin in SC has had a very complex structural history resulting the J/TR section being highly faulted. The seismic data is southern Georgia suggest SGR basin has not gone through a complex structural history as the study area in SC. The project drilled one characterization borehole (Rizer # 1) in SC. The Rizer #1 was drilled but due to geologic problems, the project team was only able to drill to 1890 meters (6200 feet) instead of the proposed final depth 2744 meters (9002 feet). The drilling goals outlined in the original scope of work were not met. The project was only able to obtain 18 meters (59 feet) of conventional core and 106 rotary sidewall cores. All the conventional core and sidewall cores were in sandstone. We were unable to core any potential igneous caprock. Petrographic analysis of the conventional core and sidewall cores determined that the average porosity of the sedimentary material was 3.4% and the average permeability was 0.065 millidarcy. Compaction and diagenetic studies of the samples determined there would not be any porosity or permeability at depth in SC. In Georgia there appears to be porosity in

  10. Research project on CO2 geological storage and groundwaterresources: Large-scale hydrological evaluation and modeling of impact ongroundwater systems

    SciTech Connect (OSTI)

    Birkholzer, Jens; Zhou, Quanlin; Rutqvist, Jonny; Jordan,Preston; Zhang,K.; Tsang, Chin-Fu

    2007-10-24

    If carbon dioxide capture and storage (CCS) technologies areimplemented on a large scale, the amounts of CO2 injected and sequesteredunderground could be extremely large. The stored CO2 then replaces largevolumes of native brine, which can cause considerable pressureperturbation and brine migration in the deep saline formations. Ifhydraulically communicating, either directly via updipping formations orthrough interlayer pathways such as faults or imperfect seals, theseperturbations may impact shallow groundwater or even surface waterresources used for domestic or commercial water supply. Possibleenvironmental concerns include changes in pressure and water table,changes in discharge and recharge zones, as well as changes in waterquality. In compartmentalized formations, issues related to large-scalepressure buildup and brine displacement may also cause storage capacityproblems, because significant pressure buildup can be produced. Toaddress these issues, a three-year research project was initiated inOctober 2006, the first part of which is summarized in this annualreport.

  11. Research Project on CO2 Geological Storage and Groundwater Resources: Water Quality Effects Caused by CO2 Intrusion into Shallow Groundwater

    SciTech Connect (OSTI)

    Birkholzer, Jens; Apps, John; Zheng, Liange; Zhang, Yingqi; Xu, Tianfu; Tsang, Chin-Fu

    2008-10-01

    One promising approach to reduce greenhouse gas emissions is injecting CO{sub 2} into suitable geologic formations, typically depleted oil/gas reservoirs or saline formations at depth larger than 800 m. Proper site selection and management of CO{sub 2} storage projects will ensure that the risks to human health and the environment are low. However, a risk remains that CO{sub 2} could migrate from a deep storage formation, e.g. via local high-permeability pathways such as permeable faults or degraded wells, and arrive in shallow groundwater resources. The ingress of CO{sub 2} is by itself not typically a concern to the water quality of an underground source of drinking water (USDW), but it will change the geochemical conditions in the aquifer and will cause secondary effects mainly induced by changes in pH, in particular the mobilization of hazardous inorganic constituents present in the aquifer minerals. Identification and assessment of these potential effects is necessary to analyze risks associated with geologic sequestration of CO{sub 2}. This report describes a systematic evaluation of the possible water quality changes in response to CO{sub 2} intrusion into aquifers currently used as sources of potable water in the United States. Our goal was to develop a general understanding of the potential vulnerability of United States potable groundwater resources in the event of CO{sub 2} leakage. This goal was achieved in two main tasks, the first to develop a comprehensive geochemical model representing typical conditions in many freshwater aquifers (Section 3), the second to conduct a systematic reactive-transport modeling study to quantify the effect of CO{sub 2} intrusion into shallow aquifers (Section 4). Via reactive-transport modeling, the amount of hazardous constituents potentially mobilized by the ingress of CO{sub 2} was determined, the fate and migration of these constituents in the groundwater was predicted, and the likelihood that drinking water

  12. On scale and magnitude of pressure build-up induced by large-scale geologic storage of CO2

    SciTech Connect (OSTI)

    Zhou, Q.; Birkholzer, J. T.

    2011-05-01

    The scale and magnitude of pressure perturbation and brine migration induced by geologic carbon sequestration is discussed assuming a full-scale deployment scenario in which enough CO{sub 2} is captured and stored to make relevant contributions to global climate change mitigation. In this scenario, the volumetric rates and cumulative volumes of CO{sub 2} injection would be comparable to or higher than those related to existing deep-subsurface injection and extraction activities, such as oil production. Large-scale pressure build-up in response to the injection may limit the dynamic storage capacity of suitable formations, because over-pressurization may fracture the caprock, may drive CO{sub 2}/brine leakage through localized pathways, and may cause induced seismicity. On the other hand, laterally extensive sedimentary basins may be less affected by such limitations because (i) local pressure effects are moderated by pressure propagation and brine displacement into regions far away from the CO{sub 2} storage domain; and (ii) diffuse and/or localized brine migration into overlying and underlying formations allows for pressure bleed-off in the vertical direction. A quick analytical estimate of the extent of pressure build-up induced by industrial-scale CO{sub 2} storage projects is presented. Also discussed are pressure perturbation and attenuation effects simulated for two representative sedimentary basins in the USA: the laterally extensive Illinois Basin and the partially compartmentalized southern San Joaquin Basin in California. These studies show that the limiting effect of pressure build-up on dynamic storage capacity is not as significant as suggested by Ehlig-Economides and Economides, who considered closed systems without any attenuation effects.

  13. Leveraging Regional Exploration to Develop Geologic Framework for CO2 Storage in Deep Formations in Midwestern United States

    SciTech Connect (OSTI)

    Neeraj Gupta

    2009-09-30

    Obtaining subsurface data for developing a regional framework for geologic storage of CO{sub 2} can require drilling and characterization in a large number of deep wells, especially in areas with limited pre-existing data. One approach for achieving this objective, without the prohibitive costs of drilling costly standalone test wells, is to collaborate with the oil and gas drilling efforts in a piggyback approach that can provide substantial cost savings and help fill data gaps in areas that may not otherwise get characterized. This leveraging with oil/gas drilling also mitigates some of the risk involved in standalone wells. This collaborative approach has been used for characterizing in a number of locations in the midwestern USA between 2005 and 2009 with funding from U.S. Department of Energy's National Energy Technology Laboratory (DOE award: DE-FC26-05NT42434) and in-kind contributions from a number of oil and gas operators. The results are presented in this final technical report. In addition to data collected under current award, selected data from related projects such as the Midwestern Regional Carbon Sequestration Partnership (MRCSP), the Ohio River Valley CO{sub 2} storage project at and near the Mountaineer Plant, and the drilling of the Ohio Stratigraphic well in Eastern Ohio are discussed and used in the report. Data from this effort are also being incorporated into the MRCSP geologic mapping. The project activities were organized into tracking and evaluation of characterization opportunities; participation in the incremental drilling, basic and advanced logging in selected wells; and data analysis and reporting. Although a large number of opportunities were identified and evaluated, only a small subset was carried into the field stage. Typical selection factors included reaching an acceptable agreement with the operator, drilling and logging risks, and extent of pre-existing data near the candidate wells. The region of study is primarily along the

  14. Industrial CO2 Removal: CO2 Capture from Ambient Air and Geological Sequestration

    SciTech Connect (OSTI)

    Dooley, James J.

    2011-06-08

    This abstract and its accompanying presentation will provide an overview of two distinct industrial processes for removing carbon dioxide (CO2) from the atmosphere as a means of addressing anthropogenic climate change. The first of these is carbon dioxide capture and storage (CCS) coupled with large scale biomass production (hereafter referred to as bioCCS). The second is CO2 capture from ambient air via industrial systems (hereafter referred to as direct air capture (DAC)). In both systems, the captured CO2 would be injected into deep geologic formations so as to isolate it from the atmosphere. The technical literature is clear that both of these technologies are technically feasible as of today (IPCC, 2005; Keith, 2009; Lackner, 2009; Luckow et al., 2010; Ranjan and Herzog, 2011). What is uncertain is the relative cost of these industrial ambient-air CO2 removal systems when compared to other emissions mitigation measures, the ultimate timing and scale of their deployment, and the resolution of potential site specific constraints that would impact their ultimate commercial deployment.

  15. Geologic Carbon Sequestration: Mitigating Climate Change by Injecting CO2 Underground (LBNL Summer Lecture Series)

    SciTech Connect (OSTI)

    Oldenburg, Curtis M

    2009-07-21

    Summer Lecture Series 2009: Climate change provides strong motivation to reduce CO2 emissions from the burning of fossil fuels. Carbon dioxide capture and storage involves the capture, compression, and transport of CO2 to geologically favorable areas, where its injected into porous rock more than one kilometer underground for permanent storage. Oldenburg, who heads Berkeley Labs Geologic Carbon Sequestration Program, will focus on the challenges, opportunities, and research needs of this innovative technology.

  16. Geologic Carbon Sequestration: Mitigating Climate Change by Injecting CO2 Underground (LBNL Summer Lecture Series)

    ScienceCinema (OSTI)

    Oldenburg, Curtis M [LBNL Earth Sciences Division

    2011-04-28

    Summer Lecture Series 2009: Climate change provides strong motivation to reduce CO2 emissions from the burning of fossil fuels. Carbon dioxide capture and storage involves the capture, compression, and transport of CO2 to geologically favorable areas, where its injected into porous rock more than one kilometer underground for permanent storage. Oldenburg, who heads Berkeley Labs Geologic Carbon Sequestration Program, will focus on the challenges, opportunities, and research needs of this innovative technology.

  17. NETL CO2 Storage Frequently Asked Questions

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    CO2 Storage Frequently Asked Questions faq-header-big.jpg A combined portfolio of carbon management options for fossil fuel use can be implemented to manage current emission levels of greenhouse gases (GHGs) while enhancing energy security and building the technologies and knowledge base for export to other countries faced with reducing emissions. The U.S. portfolio includes Use of fuels with reduced carbon intensity: renewables, nuclear, and natural gas. Adoption of more efficient technologies

  18. DOE-Sponsored Drilling Projects Demonstrate Significant CO2 Storage at

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Three Sites | Department of Energy Drilling Projects Demonstrate Significant CO2 Storage at Three Sites DOE-Sponsored Drilling Projects Demonstrate Significant CO2 Storage at Three Sites May 3, 2012 - 1:00pm Addthis Washington, DC - Evaluation-related test drilling at geologic sites in three states that could store a combined 64 million metric tons of carbon dioxide (CO2) emissions - an important component of carbon capture, utilization and storage (CCUS) technology development - has been

  19. Modeling long-term CO2 storage, sequestration and cycling

    SciTech Connect (OSTI)

    Bacon, Diana H.

    2013-11-11

    The application of numerical and analytical models to the problem of storage, sequestration and migration of carbon dioxide in geologic formations is discussed. A review of numerical and analytical models that have been applied to CO2 sequestration are presented, as well as a description of frameworks for risk analysis. Application of models to various issues related to carbon sequestration are discussed, including trapping mechanisms, density convection mixing, impurities in the CO2 stream, changes in formation porosity and permeability, the risk of vertical leakage, and the impacts on groundwater resources if leakage does occur. A discussion of the development and application of site-specific models first addresses the estimation of model parameters and the use of natural analogues to inform the development of CO2 sequestration models, and then surveys modeling that has been done at two commercial-scale CO2 sequestration sites, Sleipner and In Salah, along with a pilot-scale injection sites used to study CO2 sequestration in saline aquifers (Frio) and an experimental site designed to test monitoring of CO2 leakage in the vadose zone (ZERT Release Facility).

  20. CO2 Saline Storage Demonstration in Colorado Sedimentary Basins...

    Office of Scientific and Technical Information (OSTI)

    CO2 storage site, the Rangely Oil Field, where CO2-EOR has been underway since the 1980s. ... as well as methane and trace gases) of conventional and unconventional oil and gas. ...

  1. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations: Data used in Geosphere Journal Article

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Thomas A. Buscheck

    2015-06-01

    This data submission is for Phase 2 of Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations, which focuses on multi-fluid (CO2 and brine) geothermal energy production and diurnal bulk energy storage in geologic settings that are suitable for geologic CO2 storage. This data submission includes all data used in the Geosphere Journal article by Buscheck et al (2016). All assumptions are discussed in that article.

  2. DOE Best Practices Manual Focuses on Site Selection for CO2 Storage |

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Department of Energy Best Practices Manual Focuses on Site Selection for CO2 Storage DOE Best Practices Manual Focuses on Site Selection for CO2 Storage January 5, 2011 - 12:00pm Addthis Washington, DC - The most promising methods for assessing potential carbon dioxide (CO2) geologic storage sites - a crucial component of Carbon Capture and Storage (CCS) technology - is the focus of the latest in a series of U.S. Department of Energy (DOE) CCS "best practices" manuals. Developed by

  3. NETL's 2015 Carbon Storage Atlas Shows Increase in U.S. CO2 Storage...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    NETL's 2015 Carbon Storage Atlas Shows Increase in U.S. CO2 Storage Potential NETL's 2015 Carbon Storage Atlas Shows Increase in U.S. CO2 Storage Potential September 28, 2015 - ...

  4. Hyperspectral Geobotanical Remote Sensing For Co2 Storage Monitoring...

    Open Energy Info (EERE)

    Hyperspectral Geobotanical Remote Sensing For Co2 Storage Monitoring Jump to: navigation, search OpenEI Reference LibraryAdd to library Book: Hyperspectral Geobotanical Remote...

  5. Underground CO2 Storage, Natural Gas Recovery Targeted by Virginia...

    Energy Savers [EERE]

    of an NETL-sponsored CO2 storage research project ... teamed with the National Energy Technology Laboratory ... A supervisory control and data acquisition (SCADA) system ...

  6. Review: Role of chemistry, mechanics, and transport on well integrity in CO2 storage environments

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Carroll, Susan; Carey, J. William; Dzombak, David; Huerta, Nicholas J.; Li, Li; Richard, Tom; Um, Wooyong; Walsh, Stuart D. C.; Zhang, Liwei

    2016-03-22

    Among the various risks associated with CO2 storage in deep geologic formations, wells are important potential pathways for fluid leaks and groundwater contamination. Injection of CO2 will perturb the storage reservoir and any wells that penetrate the CO2 or pressure footprints are potential pathways for leakage of CO2 and/or reservoir brine. Well leakage is of particular concern for regions with a long history of oil and gas exploration because they are top candidates for geologic CO2 storage sites. This review explores in detail the ability of wells to retain their integrity against leakage with careful examination of the coupled physicalmore » and chemical processes involved. Furthermore, understanding time-dependent leakage is complicated by the changes in fluid flow, solute transport, chemical reactions, and mechanical stresses over decade or longer time frames for site operations and monitoring.« less

  7. Underground CO2 Storage, Natural Gas Recovery Targeted by Virginia

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Tech/NETL Research | Department of Energy Underground CO2 Storage, Natural Gas Recovery Targeted by Virginia Tech/NETL Research Underground CO2 Storage, Natural Gas Recovery Targeted by Virginia Tech/NETL Research October 20, 2015 - 8:14am Addthis Researchers from Virginia Tech are injecting CO2 into coal seams in three locations in Buchanan County, Va., as part of an NETL-sponsored CO2 storage research project associated with enhanced gas recovery. Researchers from Virginia Tech are

  8. Evaluating a new approach to CO2 capture and storage

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Evaluating a new approach to CO2 capture and storage Evaluating a new approach to CO2 capture and storage In a perspective paper published in Greenhouse Gases: Science and Technology, researchers examined a new approach that could potentially overcome many barriers to deployment and jumpstart this process on a commercial scale. September 13, 2015 Map of the contiguous United States shows the location of facilities that produce high-value chemicals/products and the amount of carbon dioxide

  9. Global Sampling for Integrating Physics-Specific Subsystems and Quantifying Uncertainties of CO2 Geological Sequestration

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Sun, Y.; Tong, C.; Trainor-Guitten, W. J.; Lu, C.; Mansoor, K.; Carroll, S. A.

    2012-12-20

    The risk of CO2 leakage from a deep storage reservoir into a shallow aquifer through a fault is assessed and studied using physics-specific computer models. The hypothetical CO2 geological sequestration system is composed of three subsystems: a deep storage reservoir, a fault in caprock, and a shallow aquifer, which are modeled respectively by considering sub-domain-specific physics. Supercritical CO2 is injected into the reservoir subsystem with uncertain permeabilities of reservoir, caprock, and aquifer, uncertain fault location, and injection rate (as a decision variable). The simulated pressure and CO2/brine saturation are connected to the fault-leakage model as a boundary condition. CO2 andmore » brine fluxes from the fault-leakage model at the fault outlet are then imposed in the aquifer model as a source term. Moreover, uncertainties are propagated from the deep reservoir model, to the fault-leakage model, and eventually to the geochemical model in the shallow aquifer, thus contributing to risk profiles. To quantify the uncertainties and assess leakage-relevant risk, we propose a global sampling-based method to allocate sub-dimensions of uncertain parameters to sub-models. The risk profiles are defined and related to CO2 plume development for pH value and total dissolved solids (TDS) below the EPA's Maximum Contaminant Levels (MCL) for drinking water quality. A global sensitivity analysis is conducted to select the most sensitive parameters to the risk profiles. The resulting uncertainty of pH- and TDS-defined aquifer volume, which is impacted by CO2 and brine leakage, mainly results from the uncertainty of fault permeability. Subsequently, high-resolution, reduced-order models of risk profiles are developed as functions of all the decision variables and uncertain parameters in all three subsystems.« less

  10. Overview of the CO2 Geological Sequestration System

    Office of Scientific and Technical Information (OSTI)

    CO 2 is a so-called "greenhouse gas" that traps infrared radiation and may contribute to global warming. Scientists project that greenhouse gases such as CO 2 will make the arctic ...

  11. Microsoft Word - NETL-TRS-1-2013_Geologic Storage Estimates for...

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    ... assumptions and data limitations pertaining to subsurface geology. CO 2 storage-resource estimates provide important bounds for energy planning at the national and regional levels. ...

  12. Large releases from CO2 storage reservoirs: analogs, scenarios,and modeling needs

    SciTech Connect (OSTI)

    Birkholzer, Jens; Pruess, Karsten; Lewicki, Jennifer; Rutqvist,Jonny; Tsang, Chin-Fu; Karimjee, Anhar

    2005-09-01

    While the purpose of geologic storage in deep salineformations is to trap greenhouse gases underground, the potential existsfor CO2 to escape from the target reservoir, migrate upward alongpermeable pathways, and discharge at the land surface. In this paper, weevaluate the potential for such CO2 discharges based on the analysis ofnatural analogs, where large releases of gas have been observed. We areparticularly interested in circumstances that could generate sudden,possibly self-enhancing release events. The probability for such eventsmay be low, but the circumstances under which they occur and thepotential consequences need to be evaluated in order to designappropriate site-selection and risk-management strategies. Numericalmodeling of hypothetical test cases is suggested to determine criticalconditions for large CO2 releases, to evaluate whether such conditionsmaybe possible at designated storage sites, and, if applicable, toevaluate the potential impacts of such events as well as designappropriate mitigation strategies.

  13. Large releases from CO2 storage reservoirs: Analogs, scenarios,and modeling needs

    SciTech Connect (OSTI)

    Birkholzer, Jens; Pruess, Karsten; Lewicki, Jennifer; Rutqvist,Jonny; Tsang, Chin-Fu; Karimjee, Anhar

    2006-03-25

    While the purpose of geologic storage in deep salineformations is to trap greenhouse gases underground, the potential existsfor CO2 to escape from the target reservoir, migrate upward alongpermeable pathways, and discharge at the land surface. In this paper, weevaluate the potential for such CO2 discharges based on the analysis ofnatural analogs, where large releases of gas have been observed. We areparticularly interested in circumstances that could generate sudden,possibly self enhancing release events. The probability for such eventsmay be low, but the circumstances under which they occur and thepotential consequences need to be evaluated in order to designappropriate site-selection and risk-managementstrategies. Numericalmodeling of hypothetical test cases is suggested to determine criticalconditions for large CO2 releases, to evaluate whether such conditionsmay be possible at designated storage sites, and, if applicable, toevaluate the potential impacts of such events as well as designappropriate mitigation strategies.

  14. Evaluation of experimentally measured and model-calculated pH for rock-brine-CO2 systems under geologic CO2 sequestration conditions

    SciTech Connect (OSTI)

    Shao, Hongbo; Thompson, Christopher J.; Cantrell, Kirk J.

    2013-11-14

    pH is an essential parameter for understanding the geochemical reactions that occur in rock-brine-CO2 systems when CO2 is injected into deep geologic formations for long-term storage. Due to a lack of reliable experimental methods, most laboratory studies conducted under geological CO2 sequestration (GCS) conditions have relied on thermodynamic modeling to estimate pH. The accuracy of these model predictions is typically uncertain. In our previous work, we have developed a method for pH determination by in-situ spectrophotometry. In the present work, we expanded the applicable pH range for this method and measured the pH of several rock-brine-CO2 systems at GCS conditions for five rock samples collected from ongoing GCS demonstration projects. Experimental measurements were compared with pH values calculated using several geochemical modeling approaches. The effect of different thermodynamic databases on the accuracy of model prediction was evaluated. Results indicate that the accuracy of model calculations is rock-dependent. For rocks comprised of carbonate and sandstone, model results generally agreed well with experimentally measured pH; however, for basalt, significant differences were observed. These discrepancies may be due to the models’ failure to fully account for certain reaction occurring between the basalt minerals the CO2-saturated brine solutions.

  15. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    2012-01-01

    Active Management of Integrated Geothermal–CO2 Storage Reservoirs in Sedimentary Formations: An Approach to Improve Energy Recovery and Mitigate Risk: FY1 Final Report The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. Based on a range of well schemes, techno-economic analyses of the levelized cost of electricity (LCOE) are conducted to determine the economic benefits of integrating GCS with geothermal energy production. In addition to considering CO2 injection, reservoir analyses are conducted for nitrogen (N2) injection to investigate the potential benefits of incorporating N2 injection with integrated geothermal-GCS, as well as the use of N2 injection as a potential pressure-support and working-fluid option. Phase 1 includes preliminary environmental risk assessments of integrated geothermal-GCS, with the focus on managing reservoir overpressure. Phase 1 also includes an economic survey of pipeline costs, which will be applied in Phase 2 to the analysis of CO2 conveyance costs for techno-economics analyses of integrated geothermal-GCS reservoir sites. Phase 1 also includes a geospatial GIS survey of potential integrated geothermal-GCS reservoir sites, which will be used in Phase 2 to conduct sweet-spot analyses that determine where promising geothermal resources are co-located in sedimentary settings conducive to safe CO2 storage, as well as being in adequate proximity to large stationary CO2 sources.

  16. SUBTASK 2.19 – OPERATIONAL FLEXIBILITY OF CO2 TRANSPORT AND STORAGE

    SciTech Connect (OSTI)

    Jensen, Melanie; Schlasner, Steven; Sorensen, James; Hamling, John

    2014-12-31

    experts represented a range of disciplines and hailed from North America and Europe. Major findings of the study are that compression and transport of CO2 for enhanced oil recovery (EOR) purposes in the United States has shown that impurities are not likely to cause transport problems if CO2 stream composition standards are maintained and pressures are kept at 10.3 MPa or higher. Cyclic, or otherwise intermittent, CO2 supplies historically have not impacted in-field distribution pipeline networks, wellbore integrity, or reservoir conditions. The U.S. EOR industry has demonstrated that it is possible to adapt to variability and intermittency in CO2 supply through flexible operation of the pipeline and geologic storage facility. This CO2 transport and injection experience represents knowledge that can be applied in future CCS projects. A number of gaps in knowledge were identified that may benefit from future research and development, further enhancing the possibility for widespread application of CCS. This project was funded through the Energy & Environmental Research Center–U.S. Department of Energy Joint Program on Research and Development for Fossil Energy-Related Resources Cooperative Agreement No. DE-FC26-08NT43291. Nonfederal funding was provided by the IEA Greenhouse Gas R&D Programme.

  17. New Carbon Storage Atlas Shows Hundreds of Years of CO2 Storage Potential |

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Department of Energy Carbon Storage Atlas Shows Hundreds of Years of CO2 Storage Potential New Carbon Storage Atlas Shows Hundreds of Years of CO2 Storage Potential December 21, 2012 - 9:58am Addthis Atlas IV was created by the National Energy Technology Laboratory (NETL), and includes input from the more than 400 organizations in 43 states and four Canadian provinces that make up the Department’s seven Regional Carbon Sequestration Partnerships (as shown above). <a

  18. Numerical Studies of Fluid Leakage from a Geologic DisposalReservoir for CO2 Show Self-Limiting Feedback between Fluid Flow and HeatTransfer

    SciTech Connect (OSTI)

    Pruess, Karsten

    2005-03-22

    Leakage of CO2 from a hypothetical geologic storage reservoir along an idealized fault zone has been simulated, including transitions between supercritical, liquid, and gaseous CO2. We find strong non-isothermal effects due to boiling and Joule-Thomson cooling of expanding CO2. Leakage fluxes are limited by limitations in conductive heat transfer to the fault zone. The interplay between multiphase flow and heat transfer effects produces non-monotonic leakage behavior.

  19. Numerical Modeling of CO2 Sequestration in Geologic Formations -Recent Results and Open Challenges

    SciTech Connect (OSTI)

    Pruess, Karsten

    2006-03-08

    Rising atmospheric concentrations of CO2, and their role inglobal warming, have prompted efforts to reduce emissions of CO2 fromburning of fossil fuels. An attractive mitigation option underconsideration in many countries is the injection of CO2 from stationarysources, such as fossil-fueled power plants, into deep, stable geologicformations, where it would be stored and kept out of the atmosphere fortime periods of hundreds to thousands of years or more. Potentialgeologic storage reservoirs include depleted or depleting oil and gasreservoirs, unmineable coal seams, and saline formations. While oil andgas reservoirs may provide some attractive early targets for CO2 storage,estimates for geographic regions worldwide have suggested that onlysaline formations would provide sufficient storage capacity tosubstantially impact atmospheric releases. This paper will focus on CO2storage in saline formations.Injection of CO2 into a saline aquifer willgive rise to immiscible displacement of brine by the advancing CO2. Thelower viscosity of CO2 relative to aqueous fluids provides a potentialfor hydrodynamic instabilities during the displacement process. Attypical subsurface conditions of temperature and pressure, CO2 is lessdense than aqueous fluids and is subject to upward buoyancy force inenvironments where pressures are controlled by an ambient aqueous phase.Thus CO2 would tend to rise towards the top of a permeable formation andaccumulate beneath the caprock. Some CO2 will also dissolve in theaqueous phase, while the CO2-rich phase may dissolve some formationwaters, which would tend to dry out the vicinity of the injection wells.CO2 will make formation waters more acidic, and will induce chemicalrections that may precipitate and dissolve mineral phases (Xu et al.,2004). As a consequence of CO2 injection, significant pressurization offormation fluids would occur over large areas. These pressurizationeffects will change effective stresses, and may cause movement alongfaults

  20. Geologic Carbon Dioxide Storage Field Projects Supported by DOE's

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Sequestration Program | Department of Energy Geologic Carbon Dioxide Storage Field Projects Supported by DOE's Sequestration Program Geologic Carbon Dioxide Storage Field Projects Supported by DOE's Sequestration Program Background: The U.S. DOE's Sequestration Program began with a small appropriation of $1M in 1997 and has grown to be the largest most comprehensive CCS R&D program in the world. The U.S. DOE's sequestration program has supported a number of projects implementing CO2

  1. Geochemical Impacts of Leaking CO2 from Subsurface Storage Reservoirs to Unconfined and Confined Aquifers

    SciTech Connect (OSTI)

    Qafoku, Nikolla; Brown, Christopher F.; Wang, Guohui; Sullivan, E. C.; Lawter, Amanda R.; Harvey, Omar R.; Bowden, Mark

    2013-04-15

    Experimental research work has been conducted and is undergoing at Pacific Northwest National Laboratory (PNNL) to address a variety of scientific issues related with the potential leaks of the carbon dioxide (CO2) gas from deep storage reservoirs. The main objectives of this work are as follows: • Develop a systematic understanding of how CO2 leakage is likely to influence pertinent geochemical processes (e.g., dissolution/precipitation, sorption/desorption and redox reactions) in the aquifer sediments. • Identify prevailing environmental conditions that would dictate one geochemical outcome over another. • Gather useful information to support site selection, risk assessment, policy-making, and public education efforts associated with geological carbon sequestration. In this report, we present results from experiments conducted at PNNL to address research issues related to the main objectives of this effort. A series of batch and column experiments and solid phase characterization studies (quantitative x-ray diffraction and wet chemical extractions with a concentrated acid) were conducted with representative rocks and sediments from an unconfined, oxidizing carbonate aquifer, i.e., Edwards aquifer in Texas, and a confined aquifer, i.e., the High Plains aquifer in Kansas. These materials were exposed to a CO2 gas stream simulating CO2 gas leaking scenarios, and changes in aqueous phase pH and chemical composition were measured in liquid and effluent samples collected at pre-determined experimental times. Additional research to be conducted during the current fiscal year will further validate these results and will address other important remaining issues. Results from these experimental efforts will provide valuable insights for the development of site-specific, generation III reduced order models. In addition, results will initially serve as input parameters during model calibration runs and, ultimately, will be used to test model predictive capability and

  2. Center for Nanoscale Controls on Geologic CO2 (NCGC) | U.S. DOE Office of

    Office of Science (SC) Website

    Science (SC) Center for Nanoscale Controls on Geologic CO2 (NCGC) Energy Frontier Research Centers (EFRCs) EFRCs Home Centers EFRC External Websites Research Science Highlights News & Events Publications History Contact BES Home Centers Center for Nanoscale Controls on Geologic CO2 (NCGC) Print Text Size: A A A FeedbackShare Page NCGC Header Director Donald DePaolo Lead Institution Lawrence Berkeley National Laboratory Year Established 2009 Mission To enhance the performance and

  3. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    2012-01-01

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. Based on a range of well schemes, techno-economic analyses of the levelized cost of electricity (LCOE) are conducted to determine the economic benefits of integrating GCS with geothermal energy production. In addition to considering CO2 injection, reservoir analyses are conducted for nitrogen (N2) injection to investigate the potential benefits of incorporating N2 injection with integrated geothermal-GCS, as well as the use of N2 injection as a potential pressure-support and working-fluid option. Phase 1 includes preliminary environmental risk assessments of integrated geothermal-GCS, with the focus on managing reservoir overpressure. Phase 1 also includes an economic survey of pipeline costs, which will be applied in Phase 2 to the analysis of CO2 conveyance costs for techno-economics analyses of integrated geothermal-GCS reservoir sites. Phase 1 also includes a geospatial GIS survey of potential integrated geothermal-GCS reservoir sites, which will be used in Phase 2 to conduct sweet-spot analyses that determine where promising geothermal resources are co-located in sedimentary settings conducive to safe CO2 storage, as well as being in adequate proximity to large stationary CO2 sources.

  4. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. Based on a range of well schemes, techno-economic analyses of the levelized cost of electricity (LCOE) are conducted to determine the economic benefits of integrating GCS with geothermal energy production. In addition to considering CO2 injection, reservoir analyses are conducted for nitrogen (N2) injection to investigate the potential benefits of incorporating N2 injection with integrated geothermal-GCS, as well as the use of N2 injection as a potential pressure-support and working-fluid option. Phase 1 includes preliminary environmental risk assessments of integrated geothermal-GCS, with the focus on managing reservoir overpressure. Phase 1 also includes an economic survey of pipeline costs, which will be applied in Phase 2 to the analysis of CO2 conveyance costs for techno-economics analyses of integrated geothermal-GCS reservoir sites. Phase 1 also includes a geospatial GIS survey of potential integrated geothermal-GCS reservoir sites, which will be used in Phase 2 to conduct sweet-spot analyses that determine where promising geothermal resources are co-located in sedimentary settings conducive to safe CO2 storage, as well as being in adequate proximity to large stationary CO2 sources.

  5. Evaluating the impact of aquifer layer properties on geomechanical response during CO2 geological sequestration

    SciTech Connect (OSTI)

    Bao, Jie; Xu, Zhijie; Lin, Guang; Fang, Yilin

    2013-04-01

    Numerical models play an essential role in understanding the facts of carbon dioxide (CO2) geological sequestration in the life cycle of a storage reservoir. We present a series of test cases that reflect a broad and realistic range of aquifer reservoir properties to systematically evaluate and compare the impacts on the geomechanical response to CO2 injection. In this study, a coupled hydro-mechanical model was introduced to simulate the sequestration process, and a quasi-Monte Carlo sampling method was introduced to efficiently sample the value of aquifer properties and geometry parameters. Aquifer permeability was found to be of significant importance to the geomechanical response to the injection. To study the influence of uncertainty of the permeability distribution in the aquifer, an additional series of tests is presented, based on a default permeability distribution site sample with various distribution deviations generated by the Monte Carlo sampling method. The results of the test series show that different permeability distributions significantly affect the displacement and possible failure zone.

  6. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    2012-01-01

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  7. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    2000-01-01

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  8. Integrated Geothermal-CO2 Storage Reservoirs: FY1 Final Report

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  9. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  10. Integrated Geothermal-CO2 Storage Reservoirs: FY1 Final Report

    SciTech Connect (OSTI)

    Buscheck, Thomas A.

    2012-01-01

    The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  11. Initial results from seismic monitoring at the Aquistore CO2 storage site, Saskatchewan, Canada

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    White, D. J.; Roach, L. A.N.; Roberts, B.; Daley, T. M.

    2014-12-31

    The Aquistore Project, located near Estevan, Saskatchewan, is one of the first integrated commercial-scale CO2 storage projects in the world that is designed to demonstrate CO2 storage in a deep saline aquifer. Starting in 2014, CO2 captured from the nearby Boundary Dam coal-fired power plant will be transported via pipeline to the storage site and to nearby oil fields for enhanced oil recovery. At the Aquistore site, the CO2 will be injected into a brine-filled sandstone formation at ~3200 m depth using the deepest well in Saskatchewan. The suitability of the geological formations that will host the injected CO2 hasmore » been predetermined through 3D characterization using high-resolution 3D seismic images and deep well information. These data show that 1) there are no significant faults in the immediate area of the storage site, 2) the regional sealing formation is continuous in the area, and 3) the reservoir is not adversely affected by knolls on the surface of the underlying Precambrian basement. Furthermore, the Aquistore site is located within an intracratonic region characterized by extremely low levels of seismicity. This is in spite of oil-field related water injection in the nearby Weyburn-Midale field where a total of 656 million m3 of water have been injected since the 1960`s with no demonstrable related induced seismicity. A key element of the Aquistore research program is the further development of methods to monitor the security and subsurface distribution of the injected CO2. Toward this end, a permanent areal seismic monitoring array was deployed in 2012, comprising 630 vertical-component geophones installed at 20 m depth on a 2.5x2.5 km regular grid. This permanent array is designed to provide improved 3D time-lapse seismic imaging for monitoring subsurface CO2. Prior to the onset of CO2 injection, calibration 3D surveys were acquired in May and November of 2013. Comparison of the data from these surveys relative to the baseline 3D survey data

  12. Coupled Geochemical Impacts of Leaking CO2 and Contaminants from Subsurface Storage Reservoirs on Groundwater Quality

    SciTech Connect (OSTI)

    Shao, Hongbo; Qafoku, Nikolla; Lawter, Amanda R.; Bowden, Mark E.; Brown, Christopher F.

    2015-07-07

    The leakage of CO2 and the concomitant saline solutions from deep storage reservoirs to overlying groundwater aquifers is considered one of the major potential risks associated with geologic CO2 sequestration (GCS). Batch and column experiments were conducted to determine the fate of trace metals in groundwater in the scenarios of CO2 and metal contaminated brine leakage. The sediments used in this work were collected from an unconsolidated sand and gravel aquifer in Kansas, and contained 0-4 wt% carbonates. Cd and As were spiked into the reaction system to represent potential contaminants from the reservoir brine that could intrude into groundwater aquifers with leaking CO2 at initial concentrations of 114 and 40 ppb, respectively. Through this research we demonstrated that Cd and As were adsorbed on the sediments, in spite of the lowered pH due to CO2 dissolution in the groundwater. Cd concentrations were well below its MCL in both batch and column studies, even for sediment samples without detectable carbonate to buffer the pH. Arsenic concentrations in the effluent were also significantly lower than influent concentration, suggesting that the sediments tested have the capacity to mitigate the coupled adverse effects of CO2 leakage and brine intrusion. However, the mitigation capacity of sediment is a function of its geochemical properties [e.g., the calcite content; the presence of adsorbed As(III); and the presence of P in the natural sediment]. The competitive adsorption between phosphate and arsenate may result in higher concentrations of As in the aqueous phase.

  13. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    2012-01-01

    Active Management of Integrated Geothermal–CO2 Storage Reservoirs in Sedimentary Formations: An Approach to Improve Energy Recovery and Mitigate Risk : FY1 Final Report The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  14. Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Buscheck, Thomas A.

    2000-01-01

    Active Management of Integrated Geothermal–CO2 Storage Reservoirs in Sedimentary Formations: An Approach to Improve Energy Recovery and Mitigate Risk: FY1 Final Report The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. This submittal contains input and output files of the reservoir model analyses. A reservoir-model "index-html" file was sent in a previous submittal to organize the reservoir-model input and output files according to sections of the FY1 Final Report to which they pertain. The recipient should save the file: Reservoir-models-inputs-outputs-index.html in the same directory that the files: Section2.1.*.tar.gz files are saved in.

  15. Review: Role of chemistry, mechanics, and transport on well integrity in CO2 storage environments

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Carroll, Susan A.; Carey, William J.; Dzombak, David; Huerta, Nicolas J.; Li, Li; Richard, Tom; Um, Wooyong; Walsh, Stuart D. C.; Zhang, Liwei

    2016-03-22

    Among the various risks associated with CO2 storage in deep geologic formations, wells are important potential pathways for fluid leaks and groundwater contamination. Injection of CO2 will perturb the storage reservoir and any wells that penetrate the CO2 or pressure footprints are potential pathways for leakage of CO2 and/or reservoir brine. Well leakage is of particular concern for regions with a long history of oil and gas exploration because they are top candidates for geologic CO2storage sites. This review explores in detail the ability of wells to retain their integrity against leakage with careful examination of the coupled physical andmore » chemical processes involved. Understanding time-dependent leakage is complicated by the changes in fluid flow, solute transport, chemical reactions, and mechanical stresses over decade or longer time frames for site operations and monitoring. Almost all studies of the potential for well leakage have been laboratory based, as there are limited data on field-scale leakage. When leakage occurs by diffusion only, laboratory experiments show that while CO2 and CO2-saturated brine react with cement and casing, the rate of degradation is transport-limited and alteration of cement and casing properties is low. When a leakage path is already present due to cement shrinkage or fracturing, gaps along interfaces (e.g. casing/cement or cement/rock), or casing failures, chemical and mechanical alteration have the potential to decrease or increase leakage risks. Laboratory experiments and numerical simulations have shown that mineral precipitation or closure of strain-induced fractures can seal a leak pathway over time or conversely open pathways depending on flow-rate, chemistry, and the stress state. Experiments with steel/cement and cement/rock interfaces have indicated that protective mechanisms such as metal passivation, chemical alteration, mechanical deformation, and pore clogging can also help mitigate leakage. The specific

  16. FY 2014 Research Projects on CO2 Storage in Enhanced Oil Recovery |

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Department of Energy Research Projects on CO2 Storage in Enhanced Oil Recovery FY 2014 Research Projects on CO2 Storage in Enhanced Oil Recovery In FY 2014, the U.S. Department of Energy selected five projects focused on advancing the state of knowledge and developing and validating technologies that would allow for more effective storage of carbon dioxide (CO2) in enhanced oil recovery (EOR) operations while also promoting additional oil recovery. Valued at more than $14 million, these

  17. Carbon Storage Partner Completes First Year of CO2 Injection Operations in

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Illinois | Department of Energy Carbon Storage Partner Completes First Year of CO2 Injection Operations in Illinois Carbon Storage Partner Completes First Year of CO2 Injection Operations in Illinois November 19, 2012 - 12:00pm Addthis Washington, DC - A project important to demonstrating the commercial viability of carbon capture, utilization and storage (CCUS) technology has completed the first year of injecting carbon dioxide (CO2) from an industrial plant at a large-scale test site in

  18. A Feasibility Study of Non-Seismic Geophysical Methods forMonitoring Geologic CO2 Sequestration

    SciTech Connect (OSTI)

    Gasperikova, Erika; Hoversten, G. Michael

    2006-07-01

    Because of their wide application within the petroleumindustry it is natural to consider geophysical techniques for monitoringof CO2 movement within hydrocarbon reservoirs, whether the CO2 isintroduced for enhanced oil/gas recovery or for geologic sequestration.Among the available approaches to monitoring, seismic methods are by farthe most highly developed and applied. Due to cost considerations, lessexpensive techniques have recently been considered. In this article, therelative merits of gravity and electromagnetic (EM) methods as monitoringtools for geological CO2 sequestration are examined for two syntheticmodeling scenarios. The first scenario represents combined CO2 enhancedoil recovery (EOR) and sequestration in a producing oil field, theSchrader Bluff field on the north slope of Alaska, USA. The secondscenario is a simplified model of a brine formation at a depth of 1,900m.

  19. Geochemical Impacts of Leaking CO2 from Subsurface Storage Reservoirs to an Unconfined Oxidizing Carbonate Aquifer

    SciTech Connect (OSTI)

    Wang, Guohui; Qafoku, Nikolla; Lawter, Amanda R.; Bowden, Mark E.; Harvey, Omar; Sullivan, E. C.; Brown, Christopher F.

    2015-07-15

    A series of batch and column experiments combined with solid phase characterization studies (i.e., quantitative x-ray diffraction and wet chemical extractions) were conducted to address a variety of scientific issues and evaluate the impacts of the potential leakage of carbon dioxide (CO2) from deep subsurface storage reservoirs. The main objective was to gain an understanding of how CO2 gas influences: 1) the aqueous phase pH; and 2) mobilization of major, minor, and trace elements from minerals present in an aquifer overlying potential CO2 sequestration subsurface repositories. Rocks and slightly weathered rocks representative of an unconfined, oxidizing carbonate aquifer within the continental US, i.e., the Edwards aquifer in Texas, were used in these studies. These materials were exposed to a CO2 gas stream or were leached with a CO2-saturated influent solution to simulate different CO2 gas leakage scenarios, and changes in aqueous phase pH and chemical composition were measured in the liquid samples collected at pre-determined experimental times (batch experiments) or continuously (column experiments). The results from the strong acid extraction tests confirmed that in addition to the usual elements present in most soils, rocks, and sediments, the Edward aquifer samples contain As, Cd, Pb, Cu, and occasionally Zn, which may potentially be mobilized from the solid to the aqueous phase during or after exposure to CO2. The results from the batch and column experiments confirmed the release of major chemical elements into the contacting aqueous phase (such as Ca, Mg, Ba, Sr, Si, Na, and K); the mobilization and possible rapid immobilization of minor elements (such as Fe, Al, and Mn), which are able to form highly reactive secondary phases; and sporadic mobilization of only low concentrations of trace elements (such as As, Cd, Pb, Cu, Zn, Mo, etc.). The results from this experimental research effort will help in developing a systematic understanding of how CO2

  20. Using Pressure and Volumetric Approaches to Estimate CO2 Storage Capacity in Deep Saline Aquifers

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Thibeau, Sylvain; Bachu, Stefan; Birkholzer, Jens; Holloway, Sam; Neele, Filip; Zhou, Quanlin

    2014-12-31

    Various approaches are used to evaluate the capacity of saline aquifers to store CO2, resulting in a wide range of capacity estimates for a given aquifer. The two approaches most used are the volumetric “open aquifer” and “closed aquifer” approaches. We present four full-scale aquifer cases, where CO2 storage capacity is evaluated both volumetrically (with “open” and/or “closed” approaches) and through flow modeling. These examples show that the “open aquifer” CO2 storage capacity estimation can strongly exceed the cumulative CO2 injection from the flow model, whereas the “closed aquifer” estimates are a closer approximation to the flow-model derived capacity. Anmore » analogy to oil recovery mechanisms is presented, where the primary oil recovery mechanism is compared to CO2 aquifer storage without producing formation water; and the secondary oil recovery mechanism (water flooding) is compared to CO2 aquifer storage performed simultaneously with extraction of water for pressure maintenance. This analogy supports the finding that the “closed aquifer” approach produces a better estimate of CO2 storage without water extraction, and highlights the need for any CO2 storage estimate to specify whether it is intended to represent CO2 storage capacity with or without water extraction.« less

  1. Evaluating a new approach to CO2 capture and storage

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Implementing CO2 capture in coal-fired power plants could result in almost a doubling of electricity prices for consumers. The researchers examined near-term market-viable ...

  2. CO2 Capture and Storage Project, Education and Training Center...

    Broader source: Energy.gov (indexed) [DOE]

    It's the process of capturing and storing or re-using carbon dioxide (CO2) from coal-fired ... from Archer Daniels Midland's ethanol plant in Decatur, transported via a mile-long ...

  3. Rigorous Screening Technology for Identifying Suitable CO2 Storage Sites II

    SciTech Connect (OSTI)

    George J. Koperna Jr.; Vello A. Kuuskraa; David E. Riestenberg; Aiysha Sultana; Tyler Van Leeuwen

    2009-06-01

    This report serves as the final technical report and users manual for the 'Rigorous Screening Technology for Identifying Suitable CO2 Storage Sites II SBIR project. Advanced Resources International has developed a screening tool by which users can technically screen, assess the storage capacity and quantify the costs of CO2 storage in four types of CO2 storage reservoirs. These include CO2-enhanced oil recovery reservoirs, depleted oil and gas fields (non-enhanced oil recovery candidates), deep coal seems that are amenable to CO2-enhanced methane recovery, and saline reservoirs. The screening function assessed whether the reservoir could likely serve as a safe, long-term CO2 storage reservoir. The storage capacity assessment uses rigorous reservoir simulation models to determine the timing, ultimate storage capacity, and potential for enhanced hydrocarbon recovery. Finally, the economic assessment function determines both the field-level and pipeline (transportation) costs for CO2 sequestration in a given reservoir. The screening tool has been peer reviewed at an Electrical Power Research Institute (EPRI) technical meeting in March 2009. A number of useful observations and recommendations emerged from the Workshop on the costs of CO2 transport and storage that could be readily incorporated into a commercial version of the Screening Tool in a Phase III SBIR.

  4. First U.S. Large-Scale CO2 Storage Project Advances

    Broader source: Energy.gov [DOE]

    Drilling nears completion for the first large-scale carbon dioxide injection well in the United States for CO2 sequestration. This project will be used to demonstrate that CO2 emitted from industrial sources - such as coal-fired power plants - can be stored in deep geologic formations to mitigate large quantities of greenhouse gas emissions.

  5. CO2 CAPTURE PROJECT - AN INTEGRATED, COLLABORATIVE TECHNOLOGY DEVELOPMENT PROJECT FOR NEXT GENERATION CO2 SEPARATION, CAPTURE AND GEOLOGIC SEQUESTRATION

    SciTech Connect (OSTI)

    Dr. Helen Kerr

    2003-08-01

    The CO{sub 2} Capture Project (CCP) is a joint industry project, funded by eight energy companies (BP, ChevronTexaco, EnCana, Eni, Norsk Hydro, Shell, Statoil, and Suncor) and three government agencies (1) European Union (DG Res & DG Tren), (2) Norway (Klimatek) and (3) the U.S.A. (Department of Energy). The project objective is to develop new technologies, which could reduce the cost of CO{sub 2} capture and geologic storage by 50% for retrofit to existing plants and 75% for new-build plants. Technologies are to be developed to ''proof of concept'' stage by the end of 2003. The project budget is approximately $24 million over 3 years and the work program is divided into eight major activity areas: (1) Baseline Design and Cost Estimation--defined the uncontrolled emissions from each facility and estimate the cost of abatement in $/tonne CO{sub 2}. (2) Capture Technology, Post Combustion: technologies, which can remove CO{sub 2} from exhaust gases after combustion. (3) Capture Technology, Oxyfuel: where oxygen is separated from the air and then burned with hydrocarbons to produce an exhaust with high CO{sub 2} for storage. (4) Capture Technology, Pre -Combustion: in which, natural gas and petroleum coke are converted to hydrogen and CO{sub 2} in a reformer/gasifier. (5) Common Economic Model/Technology Screening: analysis and evaluation of each technology applied to the scenarios to provide meaningful and consistent comparison. (6) New Technology Cost Estimation: on a consistent basis with the baseline above, to demonstrate cost reductions. (7) Geologic Storage, Monitoring and Verification (SMV): providing assurance that CO{sub 2} can be safely stored in geologic formations over the long term. (8) Non-Technical: project management, communication of results and a review of current policies and incentives governing CO{sub 2} capture and storage. Technology development work dominated the past six months of the project. Numerous studies are making substantial progress

  6. co2-saline-storage | netl.doe.gov

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    for 2-D seismic, 3-D seismic, vertical seismic profiling, crosswell seismic and microseismic technologies. Which Reservoir for Low Cost Capture, Transportation, and Storage? -...

  7. ECONOMIC EVALUATION OF CO2 STORAGE AND SINK ENHANCEMENT OPTIONS

    SciTech Connect (OSTI)

    Bert Bock; Richard Rhudy; Howard Herzog; Michael Klett; John Davison; Danial G. De La Torre Ugarte; Dale Simbeck

    2003-02-01

    This project developed life-cycle costs for the major technologies and practices under development for CO{sub 2} storage and sink enhancement. The technologies evaluated included options for storing captured CO{sub 2} in active oil reservoirs, depleted oil and gas reservoirs, deep aquifers, coal beds, and oceans, as well as the enhancement of carbon sequestration in forests and croplands. The capture costs for a nominal 500 MW{sub e} integrated gasification combined cycle plant from an earlier study were combined with the storage costs from this study to allow comparison among capture and storage approaches as well as sink enhancements.

  8. DOE-Funded Project Testing Laser CO2 Monitoring at Carbon Storage Site

    Broader source: Energy.gov [DOE]

    A project that uses lasers to monitor carbon dioxide (CO2) is being analyzed as part of the U.S. Department of Energy’s (DOE) drive to improve greenhouse gas-monitoring abilities at CO2 storage sites. The project is managed by the DOE Office of Fossil Energy’s National Energy Technology Laboratory (NETL).

  9. Department of Energy, Shell Canada to Collaborate on CO2 Storage Project

    Broader source: Energy.gov [DOE]

    The Department of Energy (DOE) and Shell Canada announced today they intend to collaborate in field tests to validate advanced monitoring, verification, and accounting (MVA) technologies for underground storage of carbon dioxide (CO2).

  10. Interplay between microorganisms and geochemistry in geological carbon storage

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Altman, Susan J.; Kirk, Matthew Fletcher; Santillan, Eugenio-Felipe U.; Bennett, Philip C.

    2016-02-28

    Researchers at the Center for Frontiers of Subsurface Energy Security (CFSES) have conducted laboratory and modeling studies to better understand the interplay between microorganisms and geochemistry for geological carbon storage (GCS). We provide evidence of microorganisms adapting to high pressure CO2 conditions and identify factors that may influence survival of cells to CO2 stress. Factors that influenced the ability of cells to survive exposure to high-pressure CO2 in our experiments include mineralogy, the permeability of cell walls and/or membranes, intracellular buffering capacity, and whether cells live planktonically or within biofilm. Column experiments show that, following exposure to acidic water, biomassmore » can remain intact in porous media and continue to alter hydraulic conductivity. Our research also shows that geochemical changes triggered by CO2 injection can alter energy available to populations of subsurface anaerobes and that microbial feedbacks on this effect can influence carbon storage. Our research documents the impact of CO2 on microorganisms and in turn, how subsurface microorganisms can influence GCS. Furthermore, we conclude that microbial presence and activities can have important implications for carbon storage and that microorganisms should not be overlooked in further GCS research.« less

  11. CO2 Capture and Storage Project, Education and Training Center Launched in

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Decatur, Illinois | Department of Energy CO2 Capture and Storage Project, Education and Training Center Launched in Decatur, Illinois CO2 Capture and Storage Project, Education and Training Center Launched in Decatur, Illinois September 20, 2012 - 10:28am Addthis The new National Sequestration Education Center (NSEC) is a 15,000 square-foot sustainably designed center that will contain classrooms and training and laboratory facilities. | Photo courtesy of Richland Community College. The new

  12. Regional Partner Announces Plans for Carbon Storage Project Using CO2

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Captured from Coal-Fired Power Plant | Department of Energy Regional Partner Announces Plans for Carbon Storage Project Using CO2 Captured from Coal-Fired Power Plant Regional Partner Announces Plans for Carbon Storage Project Using CO2 Captured from Coal-Fired Power Plant July 20, 2009 - 1:00pm Addthis Washington, DC - Southern Company and the Southeast Regional Carbon Sequestration Partnership (SECARB), one of seven members of the U.S. Department of Energy (DOE) Regional Carbon

  13. Modelling the deployment of CO2 storage in U.S. gas-bearing shales

    SciTech Connect (OSTI)

    Davidson, Casie L.; Dahowski, Robert T.; Dooley, James J.; McGrail, B. Peter

    2014-10-23

    The proliferation of commercial development in U.S. gas-bearing shales helped to drive a twelve-fold increase in domestic gas production between 2000 and 2010, and the nation’s gas production rates continue to grow. While shales have long been regarded as a desirable caprock for CCS operations because of their low permeability and porosity, there is increasing interest in the feasibility of injecting CO2 into shales to enhance methane recovery and augment CO2 storage. Laboratory work published in recent years observes that shales with adsorbed methane appear to exhibit a stronger affinity for CO2 adsorption, offering the potential to drive additional CH4 recovery beyond primary production and perhaps the potential to store a larger volume of CO2 than the volume of methane displaced. Recent research by the authors on the revenues associated with CO2-enhanced gas recovery (CO2-EGR) in gas-bearing shales estimates that, based on a range of EGR response rates, the average revenue per ton of CO2 for projects managed over both EGR and subsequent storage-only phases could range from $0.50 to $18/tCO2. While perhaps not as profitable as EOR, for regions where lower-cost storage options may be limited, shales could represent another “early opportunity” storage option if proven feasible for reliable EGR and CO2 storage. Significant storage potential exists in gas shales, with theoretical CO2 storage resources estimated at approximately 30-50 GtCO2. However, an analysis of the comprehensive cost competitiveness of these various options is necessary to understand the degree to which they might meaningfully impact U.S. CCS deployment or costs. This preliminary analysis shows that the degree to which EGR-based CO2 storage could play a role in commercial-scale deployment is heavily dependent upon the offsetting revenues associated with incremental recovery; modeling the low revenue case resulted in only five shale-based projects, while under the high revenue case, shales

  14. TECHNOLOGY IN AN INTEGRATED ASSESSMENT MODEL: THE POTENTIAL REGIONAL DEPLOYMENT OF CARBON CAPTURE AND STORAGE IN THE CONTEXT OF GLOBAL CO2 STABILIZATION

    SciTech Connect (OSTI)

    Edmonds, James A.; Dooley, James J.; Kim, Son H.; Friedman, S. Julio; Wise, Marshall A.

    2007-11-19

    Technology is a critically important determinant of the cost of meeting any environmental objective. In this paper we examine the role of a particular technology, carbon dioxide capture and storage (CCS), in the stabilization of the concentration of atmospheric carbon dioxide (CO2). While CCS is not presently deployed at scale, it has the potential to deploy extensively during the course of the 21st century if concentrations of atmospheric CO2 are to be stabilized. The existing research literature has focused largely on the cost of capturing CO2, with the implicit assumption that storage options would be relatively cheap, plentiful and located in close proximity to future CO2 point sources. However, CO2 capture and storage will take place at the local and regional scale and will compete with other mitigation options that also exhibit local or regional differences. This paper provides an initial examination of the implications of regionally disaggregated demand for and supply of CO2 storage reservoirs within the context of a globally disaggregated, long-term analysis of both the geology and economics of CCS. This analysis suggests that some regions will see their ability to deploy CCS systems constrained by a lack of quality target reservoirs relative to the demand for storage placed upon these candidate geologic storage reservoirs by large stationary CO2 point sources within the region. Other regions appear to have sufficient storage capacity to easily carry them into the 22nd century. We examined the regional and global economic implications of the distribution of these sources and sinks in meeting various potential limits to atmospheric CO2 concentrations. This analysis confirms that CCS is an important potential response to climate change throughout the 21st century and a technology that can play a key role in controlling the cost of addressing climate change.

  15. Panel 2, Geologic Storage of Hydrogen

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000. SAND2014-3954P Geologic Storage of Hydrogen Anna S. Lord Geologist Geotechnology & Engineering Department & Peter H. Kobos Principal Staff Economist, Ph.D. Earth Systems Department 2 Geologic Storage Why underground storage?

  16. In Situ Spectrophotometric Determination of pH under Geologic CO2 Sequestration Conditions: Method Development and Application

    SciTech Connect (OSTI)

    Shao, Hongbo; Thompson, Christopher J.; Qafoku, Odeta; Cantrell, Kirk J.

    2013-02-25

    Injecting massive amounts of CO2 into deep geologic formations will cause a range of coupled thermal, hydrodynamic, mechanical, and chemical changes. A significant perturbation in water-saturated formations is the pH drop in the reservoir fluids due to CO2 dissolution. Knowing the pH under geological CO2 sequestration conditions is important for a better understanding of the short- and long-term risks associated with geological CO2 sequestration and will help in the design of sustainable sequestration projects. Most previous studies on CO2-rock-brine interactions have utilized thermodynamic modeling to estimate the pH. In this work, a spectrophotometric method was developed to determine the in-situ pH in CO2-H2O-NaCl systems in the presence and absence of reservoir rock by observing the spectra of a pH indicator, bromophenol blue, with a UV-visible spectrophotometer. Effects of temperature, pressure, and ionic strength on the pH measurement were evaluated. Measured pH values in CO2-H2O-NaCl systems were compared with several thermodynamic models. Results indicate that bromophenol blue can be used to accurately determine the pH of brine in contact with supercritical CO2 under geologic CO2 sequestration conditions.

  17. A preliminary sub-basin scale evaluation framework of site suitability for onshore aquifer-based CO2 storage in China

    SciTech Connect (OSTI)

    Wei, Ning; Li, Xiaochun; Wang, Ying; Dahowski, Robert T.; Davidson, Casie L.; Bromhal, Grant

    2013-01-30

    Development of a reliable, broadly applicable framework for the identification and suitability evaluation of potential CO2 storage sites is essential before large scale deployment of carbon dioxide capture and geological storage (CCS) can commence. In this study, a sub-basin scale evaluation framework was developed to assess the suitability of potential onshore deep saline aquifers for CO2 storage in China. The methodology, developed in consultation with experts from the academia and the petroleum industry in China, is based on a multi-criteria analysis (MCA) framework that considers four objectives: (1) storage optimization, in terms of storage capacity and injectivity; (2) risk minimization and storage security; (3) environmental restrictions regarding surface and subsurface use; and (4) economic considerations. The framework is designed to provide insights into both the suitability of potential aquifer storage sites as well as the priority for early deployment of CCS with existing CO2 sources. Preliminary application of the framework, conducted using GIS-based evaluation tools revealed that 18% of onshore aquifer sites with a combined CO2 storage capacity of 746 gigatons are considered to exhibit very high suitability, and 11% of onshore aquifer sites with a total capacity of 290 gigatons exhibit very high priority opportunities for implementation. These onshore aquifer sites may provide promising opportunities for early large-scale CCS deployment and contribute to CO2 mitigation in China for many decades.

  18. Energy Department Selects Projects to Demonstrate Feasibility of Producing Usable Water from CO2 Storage Sites

    Broader source: Energy.gov [DOE]

    Today, the Department of Energy (DOE) announced the selection of two projects that will test emerging enhanced water recovery (EWR) technologies for their potential to produce useable water from carbon dioxide (CO2) storage sites. The two projects were competitively selected from the five Brine Extraction Storage Test (BEST) projects awarded in September 2015.

  19. First-Generation Risk Profiles Help Predict CO2 Storage Site Obstacles |

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Department of Energy First-Generation Risk Profiles Help Predict CO2 Storage Site Obstacles First-Generation Risk Profiles Help Predict CO2 Storage Site Obstacles September 18, 2012 - 1:00pm Addthis Washington, DC - In support of large-scale carbon capture, utilization and storage (CCUS) projects, a collaboration of five U.S. Department of Energy (DOE) national laboratories has completed first-generation risk profiles that, for the first time, offer a means to predict the probability of

  20. Leakage and Sepage of CO2 from Geologic Carbon SequestrationSites: CO2 Migration into Surface Water

    SciTech Connect (OSTI)

    Oldenburg, Curt M.; Lewicki, Jennifer L.

    2005-06-17

    Geologic carbon sequestration is the capture of anthropogenic carbon dioxide (CO{sub 2}) and its storage in deep geologic formations. One of the concerns of geologic carbon sequestration is that injected CO{sub 2} may leak out of the intended storage formation, migrate to the near-surface environment, and seep out of the ground or into surface water. In this research, we investigate the process of CO{sub 2} leakage and seepage into saturated sediments and overlying surface water bodies such as rivers, lakes, wetlands, and continental shelf marine environments. Natural CO{sub 2} and CH{sub 4} fluxes are well studied and provide insight into the expected transport mechanisms and fate of seepage fluxes of similar magnitude. Also, natural CO{sub 2} and CH{sub 4} fluxes are pervasive in surface water environments at levels that may mask low-level carbon sequestration leakage and seepage. Extreme examples are the well known volcanic lakes in Cameroon where lake water supersaturated with respect to CO{sub 2} overturned and degassed with lethal effects. Standard bubble formation and hydrostatics are applicable to CO{sub 2} bubbles in surface water. Bubble-rise velocity in surface water is a function of bubble size and reaches a maximum of approximately 30 cm s{sup -1} at a bubble radius of 0.7 mm. Bubble rise in saturated porous media below surface water is affected by surface tension and buoyancy forces, along with the solid matrix pore structure. For medium and fine grain sizes, surface tension forces dominate and gas transport tends to occur as channel flow rather than bubble flow. For coarse porous media such as gravels and coarse sand, buoyancy dominates and the maximum bubble rise velocity is predicted to be approximately 18 cm s{sup -1}. Liquid CO{sub 2} bubbles rise slower in water than gaseous CO{sub 2} bubbles due to the smaller density contrast. A comparison of ebullition (i.e., bubble formation) and resulting bubble flow versus dispersive gas transport for CO

  1. A quantitative comparison of the cost of employing EOR-coupled CSS supplemented with secondary DSF storage for two large CO2 point sources

    SciTech Connect (OSTI)

    Davidson, Casie L.; Dahowski, Robert T.; Dooley, James J.

    2011-04-18

    This paper explores the impact of the temporally dynamic demand for CO2 for enhanced hydrocarbon recovery with CO2 storage. Previous evaluations of economy-wide CO2 capture and geologic storage (CCS) deployment have typically applied a simplifying assumption that 100% of the potential storage capacity for a given formation is available on the first day of the analysis, and that the injection rate impacts only the number of wells required to inject a given volume of fluid per year, making it a cost driver rather than a technical one. However, as discussed by Dahowski and Bachu [1], storing CO2 in a field undergoing CO2 flooding for enhanced oil recovery (EOR) is subject to a set of constraints to which storage in DSFs is not, and these constraints combined with variable demand for CO2 may strongly influence the ability of an EOR field to serve as a baseload storage formation for commercial scale CCS projects undertaken as a means of addressing climate change mitigation targets. This analysis assumes that CCS is being undertaken in order to reduce CO2 emissions from the industrial sources evaluated and that there is enough of a disincentive associated with venting CO2 to the atmosphere that any CO2 not used within the EOR field will be stored in a suitable nearby deep saline formation (DSF). The authors have applied a CO2 demand profile to two cases chosen to illustrate the differences in cost impacts of employing EOR-based CCS as a part of a given source’s CCS portfolio. The first scenario is a less-than-ideal case in which a single EOR field is used for storage and all CO2 not demanded by the EOR project is stored in a DSF; the second scenario is designed to optimize costs by minimizing storage in the DSF and maximizing lower-cost EOR-based storage. Both scenarios are evaluated for two facilities emitting 3 and 6 MtCO2/y, corresponding to a natural gas processing facility and an IGCC electric power plant, respectively. Annual and lifetime average CO2 transport

  2. Regional Opportunities for Carbon Dioxide Capture and Storage in China: A Comprehensive CO2 Storage Cost Curve and Analysis of the Potential for Large Scale Carbon Dioxide Capture and Storage in the People’s Republic of China

    SciTech Connect (OSTI)

    Dahowski, Robert T.; Li, Xiaochun; Davidson, Casie L.; Wei, Ning; Dooley, James J.

    2009-12-01

    This study presents data and analysis on the potential for carbon dioxide capture and storage (CCS) technologies to deploy within China, including a survey of the CO2 source fleet and potential geologic storage capacity. The results presented here indicate that there is significant potential for CCS technologies to deploy in China at a level sufficient to deliver deep, sustained and cost-effective emissions reductions for China over the course of this century.

  3. CO2 utilization and storage in shale gas reservoirs: Experimental results and economic impacts

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Schaef, Herbert T.; Davidson, Casie L.; Owen, Antionette Toni; Miller, Quin R. S.; Loring, John S.; Thompson, Christopher J.; Bacon, Diana H.; Glezakou, Vassiliki Alexandra; McGrail, B. Peter

    2014-12-31

    Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO2 emissions involves coupling CO2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO2) andmore » associated economic consequences. Where enhanced condensation of CO2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO2. Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO2 intercalation. Thus, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO2 gas systems, where CH4 concentrations prevail, indicate preferential CO2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO2-EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO2 exchange rates to obtain peak natural gas production.« less

  4. CO2 Utilization | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    CO2 Utilization CO2 Utilization Carbon dioxide (CO2) use and reuse efforts focus on the conversion of CO2 to useable products and fuels that will reduce CO2 emissions in areas where geologic storage may not be an optimal solution. These include: Enhanced Oil/Gas Recovery - Injecting CO2 into depleting oil or gas bearing fields to maximize the amount of CO2 that could be stored as well as maximize hydrocarbon production. View the latest projects selected in FY 2014. CO2 as Feedstock - Use CO2 as

  5. Rock Physics of Geologic Carbon Sequestration/Storage (Technical...

    Office of Scientific and Technical Information (OSTI)

    Technical Report: Rock Physics of Geologic Carbon SequestrationStorage Citation Details In-Document Search Title: Rock Physics of Geologic Carbon SequestrationStorage This report ...

  6. NETL’s 2015 Carbon Storage Atlas Shows Increase in U.S. CO2 Storage Potential

    Broader source: Energy.gov [DOE]

    The U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) today released the fifth edition of the Carbon Storage Atlas (Atlas V), which shows prospective carbon dioxide (CO2) storage resources of at least 2,600 billion metric tons – an increase over the findings of the 2012 Atlas.

  7. A Field Study on Simulation of CO 2 Injection and ECBM Production and Prediction of CO 2 Storage Capacity in Unmineable Coal Seam

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    He, Qin; Mohaghegh, Shahab D.; Gholami, Vida

    2013-01-01

    CO 2 sequestration into a coal seam project was studied and a numerical model was developed in this paper to simulate the primary and secondary coal bed methane production (CBM/ECBM) and carbon dioxide (CO 2 ) injection. The key geological and reservoir parameters, which are germane to driving enhanced coal bed methane (ECBM) and CO 2 sequestration processes, including cleat permeability, cleat porosity, CH 4 adsorption time, CO 2 adsorption time, CH 4 Langmuir isotherm, CO 2 Langmuir isotherm, and Palmer and Mansoori parameters, have been analyzed within a reasonable range. The model simulation results showed good matches formore » both CBM/ECBM production and CO 2 injection compared with the field data. The history-matched model was used to estimate the total CO 2 sequestration capacity in the field. The model forecast showed that the total CO 2 injection capacity in the coal seam could be 22,817 tons, which is in agreement with the initial estimations based on the Langmuir isotherm experiment. Total CO 2 injected in the first three years was 2,600 tons, which according to the model has increased methane recovery (due to ECBM) by 6,700 scf/d.« less

  8. Alabama Project Testing Potential for Combining CO2 Storage with Enhanced Methane Recovery

    Broader source: Energy.gov [DOE]

    Field testing the potential for combining geologic carbon dioxide storage with enhanced methane recovery is underway at a site in Alabama by a U.S. Department of Energy team of regional partners.

  9. Ancient Lava Flows Trap CO2 for Long-Term Storage in Big Sky Injection

    Broader source: Energy.gov [DOE]

    How can a prehistoric volcanic eruption help us reduce the amount of CO2 released into the atmosphere today? The answer is found in the basalt formations created by the lava – formations that can be used as sites for injecting carbon dioxide (CO2) captured from industrial sources in a process called carbon capture and storage. The Big Sky Carbon Sequestration Partnership recently injected 1,000 metric tons of CO2 into the Grande Ronde Basalt Formation in eastern Washington. This first-of-its kind injection is part of research meant to determine if basalt formations could provide a long-term solution for storing CO2, a potent greenhouse gas.

  10. Pore scale modeling of reactive transport involved in geologic CO2 sequestration

    SciTech Connect (OSTI)

    Kang, Qinjin; Lichtner, Peter C; Viswanathan, Hari S; Abdel-fattah, Amr I

    2009-01-01

    We apply a multi-component reactive transport lattice Boltzmann model developed in previolls studies to modeling the injection of a C02 saturated brine into various porous media structures at temperature T=25 and 80 C. The porous media are originally consisted of calcite. A chemical system consisting of Na+, Ca2+, Mg2+, H+, CO2(aq), and CI-is considered. The fluid flow, advection and diHusion of aqueous species, homogeneous reactions occurring in the bulk fluid, as weB as the dissolution of calcite and precipitation of dolomite are simulated at the pore scale. The effects of porous media structure on reactive transport are investigated. The results are compared with continuum scale modeling and the agreement and discrepancy are discussed. This work may shed some light on the fundamental physics occurring at the pore scale for reactive transport involved in geologic C02 sequestration.

  11. Benefits and Costs of Brine Extraction for Increasing Injection Efficiency In geologic CO2 Sequestration

    SciTech Connect (OSTI)

    Davidson, Casie L.; Watson, David J.; Dooley, James J.; Dahowski, Robert T.

    2014-12-31

    Pressure increases attendant with CO2 injection into the subsurface drive many of the risk factors associated with commercial-scale CCS projects, impacting project costs and liabilities in a number of ways. The area of elevated pressure defines the area that must be characterized and monitored; pressure drives fluid flow out of the storage reservoir along higher-permeability pathways that might exist through the caprock into overlying aquifers or hydrocarbon reservoirs; and pressure drives geomechanical changes that could potentially impact subsurface infrastructure or the integrity of the storage system itself. Pressure also limits injectivity, which can increase capital costs associated with installing additional wells to meet a given target injection rate. The ability to mitigate pressure increases in storage reservoirs could have significant value to a CCS project, but these benefits are offset by the costs of the pressure mitigation technique itself. Of particular interest for CO2 storage operators is the lifetime cost of implementing brine extraction at a CCS project site, and the relative value of benefits derived from the extraction process. This is expected to vary from site to site and from one implementation scenario to the next. Indeed, quantifying benefits against costs could allow operators to optimize their return on project investment by calculating the most effective scenario for pressure mitigation. This work builds on research recently submitted for publication by the authors examining the costs and benefits of brine extraction across operational scenarios to evaluate the effects of fluid extraction on injection rate to assess the cost effectiveness of several options for reducing the number of injection wells required. Modeling suggests that extracting at 90% of the volumetric equivalent of injection rate resulted in a 1.8% improvement in rate over a non-extraction base case; a four-fold increase in extraction rate results in a 7.6% increase in

  12. Benefits and Costs of Brine Extraction for Increasing Injection Efficiency In geologic CO2 Sequestration

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Davidson, Casie L.; Watson, David J.; Dooley, James J.; Dahowski, Robert T.

    2014-12-31

    Pressure increases attendant with CO2 injection into the subsurface drive many of the risk factors associated with commercial-scale CCS projects, impacting project costs and liabilities in a number of ways. The area of elevated pressure defines the area that must be characterized and monitored; pressure drives fluid flow out of the storage reservoir along higher-permeability pathways that might exist through the caprock into overlying aquifers or hydrocarbon reservoirs; and pressure drives geomechanical changes that could potentially impact subsurface infrastructure or the integrity of the storage system itself. Pressure also limits injectivity, which can increase capital costs associated with installing additionalmore » wells to meet a given target injection rate. The ability to mitigate pressure increases in storage reservoirs could have significant value to a CCS project, but these benefits are offset by the costs of the pressure mitigation technique itself. Of particular interest for CO2 storage operators is the lifetime cost of implementing brine extraction at a CCS project site, and the relative value of benefits derived from the extraction process. This is expected to vary from site to site and from one implementation scenario to the next. Indeed, quantifying benefits against costs could allow operators to optimize their return on project investment by calculating the most effective scenario for pressure mitigation. This work builds on research recently submitted for publication by the authors examining the costs and benefits of brine extraction across operational scenarios to evaluate the effects of fluid extraction on injection rate to assess the cost effectiveness of several options for reducing the number of injection wells required. Modeling suggests that extracting at 90% of the volumetric equivalent of injection rate resulted in a 1.8% improvement in rate over a non-extraction base case; a four-fold increase in extraction rate results in a 7

  13. Source/Sink Matching for U.S. Ethanol Plants and Candidate Deep Geologic Carbon Dioxide Storage Formations

    SciTech Connect (OSTI)

    Dahowski, Robert T.; Dooley, James J.

    2008-09-18

    This report presents data on the 140 existing and 74 planned ethanol production facilities and their proximity to candidate deep geologic storage formations. Half of the existing ethanol plants and 64% of the planned units sit directly atop a candidate geologic storage reservoir. While 70% of the existing and 97% of the planned units are within 100 miles of at least one candidate deep geologic storage reservoir. As a percent of the total CO2 emissions from these facilities, 92% of the exiting units CO2 and 97% of the planned units CO2 emissions are accounted for by facilities that are within 100 miles of at least one potential CO2 storage reservoir.

  14. CO2ReMoVe | Open Energy Information

    Open Energy Info (EERE)

    of industrial, research and service organizations with experience in CO2 geological storage. References: CO2ReMoVe1 This article is a stub. You can help OpenEI by expanding...

  15. Geologic Storage of Greenhouse Gases: Multiphase andNon-isothermal Effects, and Implications for Leakage Behavior

    SciTech Connect (OSTI)

    Pruess, Karsten

    2005-08-05

    Storage of greenhouse gases, primarily CO2, in geologic formations has been proposed as a means by which atmospheric emissions of such gases may be reduced (Bachu et al., 1994; Orr, 2004). Possible storage reservoirs currently under consideration include saline aquifers, depleted or depleting oil and gas fields, and unmineable coal seams (Baines and Worden, 2004). The amount of CO2 emitted from fossil-fueled power plants is very large, of the order of 30,000 tons per day (10 million tons per year) for a large 1,000 MW coal-fired plant (Hitchon,1996). In order to make a significant impact on reducing emissions, very large amounts of CO2 would have to be injected into subsurface formations, resulting in CO2 disposal plumes with an areal extent of order 100 km2 or more (Pruess et al., 2003). It appears inevitable, then, that such plumes will encounter imperfections in caprocks, such as fracture zones or faults, that would allow CO2 to leak from the primary storage reservoir. At typical subsurface conditions of temperature and pressure, CO2 is always less dense than aqueous fluids; thus buoyancy forces will tend to drive CO2 upward, towards the land surface, whenever adequate (sub-)vertical permeability is available. Upward migration of CO2 could also occur along wells, including pre-existing wells in sedimentary basins where oil and gas exploration and production may have been conducted (Celia et al., 2004), or along wells drilled as part of a CO2 storage operation. Concerns with leakage of CO2 from a geologic storage reservoir include (1) keeping the CO2 contained and out of the atmosphere, (2) avoiding CO2 entering groundwater aquifers, (3)asphyxiation hazard if CO2 is released at the land surface, and (4) the possibility of a self-enhancing runaway discharge, that may culminate in a ''pneumatic eruption'' (Giggenbach et al., 1991). The manner in which CO2 may leak from storage reservoirs must be understood in order to avoid hazards and design monitoring systems.

  16. New DOE-Sponsored Study Helps Advance Scientific Understanding of Potential CO2 Storage Impacts

    Broader source: Energy.gov [DOE]

    In another step forward toward improved scientific understanding of potential geologic carbon dioxide storage impacts, a new U.S. Department of Energy sponsored study has confirmed earlier research showing that proper site selection and monitoring is essential for helping anticipate and mitigate possible risks.

  17. Numerical investigation for the impact of CO2 geologic sequestration on regional groundwater flow

    SciTech Connect (OSTI)

    Yamamoto, H.; Zhang, K.; Karasaki, K.; Marui, A.; Uehara, H.; Nishikawa, N.

    2009-04-15

    Large-scale storage of carbon dioxide in saline aquifers may cause considerable pressure perturbation and brine migration in deep rock formations, which may have a significant influence on the regional groundwater system. With the help of parallel computing techniques, we conducted a comprehensive, large-scale numerical simulation of CO{sub 2} geologic storage that predicts not only CO{sub 2} migration, but also its impact on regional groundwater flow. As a case study, a hypothetical industrial-scale CO{sub 2} injection in Tokyo Bay, which is surrounded by the most heavily industrialized area in Japan, was considered, and the impact of CO{sub 2} injection on near-surface aquifers was investigated, assuming relatively high seal-layer permeability (higher than 10 microdarcy). A regional hydrogeological model with an area of about 60 km x 70 km around Tokyo Bay was discretized into about 10 million gridblocks. To solve the high-resolution model efficiently, we used a parallelized multiphase flow simulator TOUGH2-MP/ECO2N on a world-class high performance supercomputer in Japan, the Earth Simulator. In this simulation, CO{sub 2} was injected into a storage aquifer at about 1 km depth under Tokyo Bay from 10 wells, at a total rate of 10 million tons/year for 100 years. Through the model, we can examine regional groundwater pressure buildup and groundwater migration to the land surface. The results suggest that even if containment of CO{sub 2} plume is ensured, pressure buildup on the order of a few bars can occur in the shallow confined aquifers over extensive regions, including urban inlands.

  18. Simulation of Coupled Processes of Flow, Transport, and Storage of CO2 in Saline Aquifers

    SciTech Connect (OSTI)

    Wu, Yu-Shu; Chen, Zizhong; Kazemi, Hossein; Yin, Xiaolong; Pruess, Karsten; Oldenburg, Curt; Winterfeld, Philip; Zhang, Ronglei

    2014-09-30

    This report is the final scientific one for the award DE- FE0000988 entitled “Simulation of Coupled Processes of Flow, Transport, and Storage of CO2 in Saline Aquifers.” The work has been divided into six tasks. In task, “Development of a Three-Phase Non-Isothermal CO2 Flow Module,” we developed a fluid property module for brine-CO2 mixtures designed to handle all possible phase combinations of aqueous phase, sub-critical liquid and gaseous CO2, supercritical CO2, and solid salt. The thermodynamic and thermophysical properties of brine-CO2 mixtures (density, viscosity, and specific enthalpy of fluid phases; partitioning of mass components among the different phases) use the same correlations as an earlier fluid property module that does not distinguish between gaseous and liquid CO2-rich phases. We verified the fluid property module using two leakage scenarios, one that involves CO2 migration up a blind fault and subsequent accumulation in a secondary “parasitic” reservoir at shallower depth, and another investigating leakage of CO2 from a deep storage reservoir along a vertical fault zone. In task, “Development of a Rock Mechanical Module,” we developed a massively parallel reservoir simulator for modeling THM processes in porous media brine aquifers. We derived, from the fundamental equations describing deformation of porous elastic media, a momentum conservation equation relating mean stress, pressure, and temperature, and incorporated it alongside the mass and energy conservation equations from the TOUGH2 formulation, the starting point for the simulator. In addition, rock properties, namely permeability and porosity, are functions of effective stress and other variables that are obtained from the literature. We verified the simulator formulation and numerical implementation using analytical solutions and example problems from the literature. For the former, we matched a one-dimensional consolidation problem and a two-dimensional simulation of

  19. The role of optimality in characterizing CO2 seepage from geological carbon sequestration sites

    SciTech Connect (OSTI)

    Cortis, Andrea; Oldenburg, Curtis M.; Benson, Sally M.

    2008-09-15

    Storage of large amounts of carbon dioxide (CO{sub 2}) in deep geological formations for greenhouse gas mitigation is gaining momentum and moving from its conceptual and testing stages towards widespread application. In this work we explore various optimization strategies for characterizing surface leakage (seepage) using near-surface measurement approaches such as accumulation chambers and eddy covariance towers. Seepage characterization objectives and limitations need to be defined carefully from the outset especially in light of large natural background variations that can mask seepage. The cost and sensitivity of seepage detection are related to four critical length scales pertaining to the size of the: (1) region that needs to be monitored; (2) footprint of the measurement approach, and (3) main seepage zone; and (4) region in which concentrations or fluxes are influenced by seepage. Seepage characterization objectives may include one or all of the tasks of detecting, locating, and quantifying seepage. Each of these tasks has its own optimal strategy. Detecting and locating seepage in a region in which there is no expected or preferred location for seepage nor existing evidence for seepage requires monitoring on a fixed grid, e.g., using eddy covariance towers. The fixed-grid approaches needed to detect seepage are expected to require large numbers of eddy covariance towers for large-scale geologic CO{sub 2} storage. Once seepage has been detected and roughly located, seepage zones and features can be optimally pinpointed through a dynamic search strategy, e.g., employing accumulation chambers and/or soil-gas sampling. Quantification of seepage rates can be done through measurements on a localized fixed grid once the seepage is pinpointed. Background measurements are essential for seepage detection in natural ecosystems. Artificial neural networks are considered as regression models useful for distinguishing natural system behavior from anomalous behavior

  20. Geological Sequestration of CO2 by Hydrous Carbonate Formation with Reclaimed Slag

    SciTech Connect (OSTI)

    Von L. Richards; Kent Peaslee; Jeffrey Smith

    2008-02-06

    The concept of this project is to develop a process that improves the kinetics of the hydrous carbonate formation reaction enabling steelmakers to directly remove CO2 from their furnace exhaust gas. It is proposed to bring the furnace exhaust stream containing CO2 in contact with reclaimed steelmaking slag in a reactor that has an environment near the unit activity of water resulting in the production of carbonates. The CO2 emissions from the plant would be reduced by the amount sequestered in the formation of carbonates. The main raw materials for the process are furnace exhaust gases and specially prepared slag.

  1. Sensitivity study of CO2 storage capacity in brine aquifers withclosed boundaries: Dependence on hydrogeologic properties

    SciTech Connect (OSTI)

    Zhou, Q.; Birkholzer, J.; Rutqvist, J.; Tsang, C-F.

    2007-02-07

    In large-scale geologic storage projects, the injected volumes of CO{sub 2} will displace huge volumes of native brine. If the designated storage formation is a closed system, e.g., a geologic unit that is compartmentalized by (almost) impermeable sealing units and/or sealing faults, the native brine cannot (easily) escape from the target reservoir. Thus the amount of supercritical CO{sub 2} that can be stored in such a system depends ultimately on how much pore space can be made available for the added fluid owing to the compressibility of the pore structure and the fluids. To evaluate storage capacity in such closed systems, we have conducted a modeling study simulating CO{sub 2} injection into idealized deep saline aquifers that have no (or limited) interaction with overlying, underlying, and/or adjacent units. Our focus is to evaluate the storage capacity of closed systems as a function of various reservoir parameters, hydraulic properties, compressibilities, depth, boundaries, etc. Accounting for multi-phase flow effects including dissolution of CO{sub 2} in numerical simulations, the goal is to develop simple analytical expressions that provide estimates for storage capacity and pressure buildup in such closed systems.

  2. CO2 CAPTURE PROJECT-AN INTEGRATED, COLLABORATIVE TECHNOLOGY DEVELOPMENT PROJECT FOR NEXT GENERATION CO2 SEPARATION, CAPTURE AND GEOLOGIC SEQUESTRATION

    SciTech Connect (OSTI)

    Helen Kerr

    2004-04-01

    The CO{sub 2} Capture Project (CCP) is a joint industry project, funded by eight energy companies (BP, ChevronTexaco, EnCana, Eni, Norsk Hydro, Shell, Statoil, and Suncor) and three government agencies (European Union (DG Res & DG Tren), Norway (Klimatek) and the U.S.A. (Department of Energy)). The project objective is to develop new technologies, which could reduce the cost of CO{sub 2} capture and geologic storage by 50% for retrofit to existing plants and 75% for new-build plants. Technologies are to be developed to ''proof of concept'' stage by the end of 2003. The project budget is approximately $24 million over 3 years and the work program is divided into eight major activity areas: (1) Baseline Design and Cost Estimation--defined the uncontrolled emissions from each facility and estimate the cost of abatement in $/tonne CO{sub 2}. (2) Capture Technology, Post Combustion--technologies, which can remove CO{sub 2} from exhaust gases after combustion. (3) Capture Technology, Oxyfuel--where oxygen is separated from the air and then burned with hydrocarbons to produce an exhaust with wet high concentrations of CO{sub 2} for storage. (4) Capture Technology, Pre-Combustion--in which, natural gas and petroleum coke are converted to hydrogen and CO{sub 2} in a reformer/gasifier. (5) Common Economic Model/Technology Screening--analysis and evaluation of each technology applied to the scenarios to provide meaningful and consistent comparison. (6) New Technology Cost Estimation: on a consistent basis with the baseline above, to demonstrate cost reductions. (7) Geologic Storage, Monitoring and Verification (SMV)--providing assurance that CO{sub 2} can be safely stored in geologic formations over the long term. (8) Non-Technical: project management, communication of results and a review of current policies and incentives governing CO{sub 2} capture and storage. Technology development work dominated the past six months of the project. Numerous studies have completed their

  3. CO2 Sequestration short course

    SciTech Connect (OSTI)

    DePaolo, Donald J.; Cole, David R; Navrotsky, Alexandra; Bourg, Ian C

    2014-12-08

    Given the public’s interest and concern over the impact of atmospheric greenhouse gases (GHGs) on global warming and related climate change patterns, the course is a timely discussion of the underlying geochemical and mineralogical processes associated with gas-water-mineral-interactions encountered during geological sequestration of CO2. The geochemical and mineralogical processes encountered in the subsurface during storage of CO2 will play an important role in facilitating the isolation of anthropogenic CO2 in the subsurface for thousands of years, thus moderating rapid increases in concentrations of atmospheric CO2 and mitigating global warming. Successful implementation of a variety of geological sequestration scenarios will be dependent on our ability to accurately predict, monitor and verify the behavior of CO2 in the subsurface. The course was proposed to and accepted by the Mineralogical Society of America (MSA) and The Geochemical Society (GS).

  4. Physical Constraints on Geologic CO2 Sequestration in Low-Volume Basalt Formations

    SciTech Connect (OSTI)

    Ryan M. Pollyea; Jerry P. Fairley; Robert K. Podgorney; Travis L. McLing

    2014-03-01

    Deep basalt formations within large igneous provinces have been proposed as target reservoirs for carbon capture and sequestration on the basis of favorable CO2-water-rock reaction kinetics that suggest carbonate mineralization rates on the order of 102103 d. Although these results are encouraging, there exists much uncertainty surrounding the influence of fracture-controlled reservoir heterogeneity on commercial-scale CO2 injections in basalt formations. This work investigates the physical response of a low-volume basalt reservoir to commercial-scale CO2 injections using a Monte Carlo numerical modeling experiment such that model variability is solely a function of spatially distributed reservoir heterogeneity. Fifty equally probable reservoirs are simulated using properties inferred from the deep eastern Snake River Plain aquifer in southeast Idaho, and CO2 injections are modeled within each reservoir for 20 yr at a constant mass rate of 21.6 kg s1. Results from this work suggest that (1) formation injectivity is generally favorable, although injection pressures in excess of the fracture gradient were observed in 4% of the simulations; (2) for an extensional stress regime (as exists within the eastern Snake River Plain), shear failure is theoretically possible for optimally oriented fractures if Sh is less than or equal to 0.70SV; and (3) low-volume basalt reservoirs exhibit sufficient CO2 confinement potential over a 20 yr injection program to accommodate mineral trapping rates suggested in the literature.

  5. CO2 Capture Project-An Integrated, Collaborative Technology Development Project for Next Generation CO2 Separation, Capture and Geologic Sequestration

    SciTech Connect (OSTI)

    Helen Kerr; Linda M. Curran

    2005-04-15

    The CO{sub 2} Capture Project (CCP) was a joint industry project, funded by eight energy companies (BP, ChevronTexaco, EnCana, ENI, Norsk Hydro, Shell, Statoil, and Suncor) and three government agencies (European Union [DG RES & DG TREN], the Norwegian Research Council [Klimatek Program] and the U.S. Department of Energy [NETL]). The project objective was to develop new technologies that could reduce the cost of CO{sub 2} capture and geologic storage by 50% for retrofit to existing plants and 75% for new-build plants. Technologies were to be developed to ''proof of concept'' stage by the end of 2003. Certain promising technology areas were increased in scope and the studies extended through 2004. The project budget was approximately $26.4 million over 4 years and the work program is divided into eight major activity areas: Baseline Design and Cost Estimation--defined the uncontrolled emissions from each facility and estimate the cost of abatement in $/tonne CO{sub 2}. Capture Technology, Post Combustion: technologies, which can remove CO{sub 2} from exhaust gases after combustion. Capture Technology, Oxyfuel: where oxygen is separated from the air and then burned with hydrocarbons to produce an exhaust with high CO{sub 2} for storage. Capture Technology, Pre-Combustion: in which, natural gas and petroleum cokes are converted to hydrogen and CO{sub 2} in a reformer/gasifier. Common Economic Model/Technology Screening: analysis and evaluation of each technology applied to the scenarios to provide meaningful and consistent comparison. New Technology Cost Estimation: on a consistent basis with the baseline above, to demonstrate cost reductions. Geologic Storage, Monitoring and Verification (SMV): providing assurance that CO{sub 2} can be safely stored in geologic formations over the long term. Non-Technical: project management, communication of results and a review of current policies and incentives governing CO{sub 2} capture and storage. Pre-combustion De

  6. Geologic carbon sequestration as a global strategy to mitigate CO2 emissions: Sustainability and environmental risk

    SciTech Connect (OSTI)

    Oldenburg, C.M.

    2011-04-01

    low-carbon energy is considered cheap enough to replace fossil fuels. Carbon dioxide capture and storage (CCS) is one such bridging technology (1). CCS has been the focus of an increasing amount of research over the last 15-20 years and is the subject of a comprehensive IPCC report that thoroughly covers the subject (1). CCS is currently being carried out in several countries around the world in conjunction with natural gas extraction (e.g., 2, 3) and enhanced oil recovery (17). Despite this progress, widespread deployment of CCS remains the subject of research and future plans rather than present action on the scale needed to mitigate emissions from the perspective of climate change. The reasons for delay in deploying CCS more widely are concerns about cost (18), regulatory and legal uncertainty (19), and potential environmental impacts (21). This chapter discusses the long-term (decadal) sustainability and environmental hazards associated with the geologic CO{sub 2} storage (GCS) component of large-scale CCS (e.g., 20). Discussion here barely touches on capture and transport of CO{sub 2} which will occur above ground and which are similar to existing engineering, chemical processing, and pipeline transport activities and are therefore easier to evaluate with respect to risk assessment and feasibility. The focus of this chapter is on the more uncertain part of CCS, namely geologic storage. The primary concern for sustainability of GCS is whether there is sufficient capacity in sedimentary basins worldwide to contain the large of amounts of CO{sub 2} needed to address climate change. But there is also a link between sustainability and environmental impacts. Specifically, if GCS is found to cause unacceptable impacts that are considered worse than its climate-change mitigation benefits, the approach will not be widely adopted. Hence, GCS has elements of sustainability insofar as capacity of the subsurface for CO{sub 2} is concerned, and also in terms of whether the

  7. Characterization of the Wymark CO2 Reservoir: A Natural Analog to Long-Term CO2 Storage at Weyburn

    SciTech Connect (OSTI)

    Ryerson, F; Johnson, J

    2010-11-22

    Natural accumulations of CO{sub 2} occur in the Duperow and other Devonian strata on the western flank of the Williston Basin in lithologies very similar to those into which anthropogenic CO{sub 2} is being injected as part of an EOR program in the Weyburn-Midale pool. Previous workers have established the stratgraphic and petrographic similarities between the Duperow and Midale beds (Lake and Whittaker, 2004 and 2006). As the CO{sub 2} accumulations in the Devonian strata may be as old as 50 Ma, this similarity provides confidence in the efficacy of long-term geologic sequestration of CO{sub 2} in the Midale-Weyburn pool. Here we attempt to extend this comparison with whole rock and mineral chemistry using the same sample suite used by Lake and Whittaker. We provide XRD, XRF, and electron microprobe analysis of major constituent minerals along with extensive backscattered electron and x-ray imaging to identify trace phases and silicate minerals. LPNORM analysis is used to quantify modal concentrations of minerals species. Samples from depth intervals where CO{sub 2} has been observed are compared to those where CO{sub 2} was absent, with no systematic differences in mineral composition observed. Gas accumulation can be correlated with sample porosity. In particular gas-bearing samples from the Eastend region are more porous than the overlying gas-free samples. Silicate minerals are rare in the Duperow carbonates, never exceeding 3 wt%. As such, mineral trapping is precluded in these lithologies. The geochemical data presented here will be used for comparison with a similar geochemical-mineralogical study of the Midale (Durocher et al., 2003) in a subsequent report.

  8. Probabilistic cost estimation methods for treatment of water extracted during CO2 storage and EOR

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Graham, Enid J. Sullivan; Chu, Shaoping; Pawar, Rajesh J.

    2015-08-08

    Extraction and treatment of in situ water can minimize risk for large-scale CO2 injection in saline aquifers during carbon capture, utilization, and storage (CCUS), and for enhanced oil recovery (EOR). Additionally, treatment and reuse of oil and gas produced waters for hydraulic fracturing will conserve scarce fresh-water resources. Each treatment step, including transportation and waste disposal, generates economic and engineering challenges and risks; these steps should be factored into a comprehensive assessment. We expand the water treatment model (WTM) coupled within the sequestration system model CO2-PENS and use chemistry data from seawater and proposed injection sites in Wyoming, to demonstratemore » the relative importance of different water types on costs, including little-studied effects of organic pretreatment and transportation. We compare the WTM with an engineering water treatment model, utilizing energy costs and transportation costs. Specific energy costs for treatment of Madison Formation brackish and saline base cases and for seawater compared closely between the two models, with moderate differences for scenarios incorporating energy recovery. Transportation costs corresponded for all but low flow scenarios (<5000 m3/d). Some processes that have high costs (e.g., truck transportation) do not contribute the most variance to overall costs. Other factors, including feed-water temperature and water storage costs, are more significant contributors to variance. These results imply that the WTM can provide good estimates of treatment and related process costs (AACEI equivalent level 5, concept screening, or level 4, study or feasibility), and the complex relationships between processes when extracted waters are evaluated for use during CCUS and EOR site development.« less

  9. Rock Physics of Geologic Carbon Sequestration/Storage Dvorkin...

    Office of Scientific and Technical Information (OSTI)

    Rock Physics of Geologic Carbon SequestrationStorage Dvorkin, Jack; Mavko, Gary 54 ENVIRONMENTAL SCIENCES; 58 GEOSCIENCES This report covers the results of developing the rock...

  10. Rock Physics of Geologic Carbon Sequestration/Storage (Technical Report) |

    Office of Scientific and Technical Information (OSTI)

    SciTech Connect Rock Physics of Geologic Carbon Sequestration/Storage Citation Details In-Document Search Title: Rock Physics of Geologic Carbon Sequestration/Storage This report covers the results of developing the rock physics theory of the effects of CO{sub 2} injection and storage in a host reservoir on the rock's elastic properties and the resulting seismic signatures (reflections) observed during sequestration and storage. Specific topics addressed are: (a) how the elastic properties

  11. Jumpstarting commercial-scale CO2 capture and storage with ethylene production and enhanced oil recovery in the US Gulf

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Middleton, Richard S.; Levine, Jonathan S.; Bielicki, Jeffrey M.; Viswanathan, Hari S.; Carey, J. William; Stauffer, Philip H.

    2015-04-27

    CO2 capture, utilization, and storage (CCUS) technology has yet to be widely deployed at a commercial scale despite multiple high-profile demonstration projects. We suggest that developing a large-scale, visible, and financially viable CCUS network could potentially overcome many barriers to deployment and jumpstart commercial-scale CCUS. To date, substantial effort has focused on technology development to reduce the costs of CO2 capture from coal-fired power plants. Here, we propose that near-term investment could focus on implementing CO2 capture on facilities that produce high-value chemicals/products. These facilities can absorb the expected impact of the marginal increase in the cost of production onmore » the price of their product, due to the addition of CO2 capture, more than coal-fired power plants. A financially viable demonstration of a large-scale CCUS network requires offsetting the costs of CO2 capture by using the CO2 as an input to the production of market-viable products. As a result, we demonstrate this alternative development path with the example of an integrated CCUS system where CO2 is captured from ethylene producers and used for enhanced oil recovery in the U.S. Gulf Coast region.« less

  12. Leakage Risk Assessment for a Potential CO2 Storage Project in Saskatchewan, Canada

    SciTech Connect (OSTI)

    Houseworth, J.E.; Oldenburg, C.M.; Mazzoldi, A.; Gupta, A.K.; Nicot, J.-P.; Bryant, S.L.

    2011-05-01

    A CO{sub 2} sequestration project is being considered to (1) capture CO{sub 2} emissions from the Consumers Cooperative Refineries Limited at Regina, Saskatchewan and (2) geologically sequester the captured CO{sub 2} locally in a deep saline aquifer. This project is a collaboration of several industrial and governmental organizations, including the Petroleum Technology Research Centre (PTRC), Sustainable Development Technology Canada (SDTC), SaskEnvironment Go Green Fund, SaskPower, CCRL, Schlumberger Carbon Services, and Enbridge. The project objective is to sequester 600 tonnes CO{sub 2}/day. Injection is planned to start in 2012 or 2013 for a period of 25 years for a total storage of approximately 5.5 million tonnes CO{sub 2}. This report presents an assessment of the leakage risk of the proposed project using a methodology known as the Certification Framework (CF). The CF is used for evaluating CO{sub 2} leakage risk associated with geologic carbon sequestration (GCS), as well as brine leakage risk owing to displacement and pressurization of brine by the injected CO{sub 2}. We follow the CF methodology by defining the entities (so-called Compartments) that could be impacted by CO{sub 2} leakage, the CO{sub 2} storage region, the potential for leakage along well and fault pathways, and the consequences of such leakage. An understanding of the likelihood and consequences of leakage forms the basis for understanding CO{sub 2} leakage risk, and forms the basis for recommendations of additional data collection and analysis to increase confidence in the risk assessment.

  13. A framework for environmental assessment of CO2 capture and storage systems

    SciTech Connect (OSTI)

    Sathre, R; Chester, M; Cain, J; Masanet, E

    2012-01-01

    Carbon dioxide capture and storage (CCS) is increasingly seen as a way for society to enjoy the benefits of fossil fuel energy sources while avoiding the climate disruption associated with fossil CO2 emissions. A decision to deploy CCS technology at scale should be based on robust information on its overall costs and benefits. Life-cycle assessment (LCA) is a framework for holistic assessment of the energy and environmental footprint of a system, and can provide crucial information to policy-makers, scientists, and engineers as they develop and deploy CCS systems. We identify seven key issues that should be considered to ensure that conclusions and recommendations from CCS LCA are robust: energy penalty, functional units, scale-up challenges, non-climate environmental impacts, uncertainty management, policy-making needs, and market effects. Several recent life-cycle studies have focused on detailed assessments of individual CCS technologies and applications. While such studies provide important data and information on technology performance, such case-specific data are inadequate to fully inform the decision making process. LCA should aim to describe the system-wide environmental implications of CCS deployment at scale, rather than a narrow analysis of technological performance of individual power plants. (C) 2011 Elsevier Ltd. All rights reserved.

  14. Evaluating Potential for Large Releases from CO2 StorageReservoirs: Analogs, Scenarios, and Modeling Needs

    SciTech Connect (OSTI)

    Birkholzer, Jens; Pruess, Karsten; Lewicki, Jennifer; Tsang,Chin-Fu; Karimjee, Anhar

    2005-09-19

    While the purpose of geologic storage of CO{sub 2} in deep saline formations is to trap greenhouse gases underground, the potential exists for CO{sub 2} to escape from the target reservoir, migrate upward along permeable pathways, and discharge at the land surface. Such discharge is not necessarily a serious concern, as CO{sub 2} is a naturally abundant and relatively benign gas in low concentrations. However, there is a potential risk to health, safety and environment (HSE) in the event that large localized fluxes of CO{sub 2} were to occur at the land surface, especially where CO{sub 2} could accumulate. In this paper, we develop possible scenarios for large CO{sub 2} fluxes based on the analysis of natural analogues, where large releases of gas have been observed. We are particularly interested in scenarios which could generate sudden, possibly self-enhancing, or even eruptive release events. The probability for such events may be low, but the circumstances under which they might occur and potential consequences need to be evaluated in order to design appropriate site selection and risk management strategies. Numerical modeling of hypothetical test cases is needed to determine critical conditions for such events, to evaluate whether such conditions may be possible at designated storage sites, and, if applicable, to evaluate the potential HSE impacts of such events and design appropriate mitigation strategies.

  15. The Ohio River Valley CO2 Storage Project AEP Mountaineer Plan, West Virginia

    SciTech Connect (OSTI)

    Neeraj Gupta

    2009-01-07

    This report includes an evaluation of deep rock formations with the objective of providing practical maps, data, and some of the issues considered for carbon dioxide (CO{sub 2}) storage projects in the Ohio River Valley. Injection and storage of CO{sub 2} into deep rock formations represents a feasible option for reducing greenhouse gas emissions from coal-burning power plants concentrated along the Ohio River Valley area. This study is sponsored by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL), American Electric Power (AEP), BP, Ohio Coal Development Office, Schlumberger, and Battelle along with its Pacific Northwest Division. An extensive program of drilling, sampling, and testing of a deep well combined with a seismic survey was used to characterize the local and regional geologic features at AEP's 1300-megawatt (MW) Mountaineer Power Plant. Site characterization information has been used as part of a systematic design feasibility assessment for a first-of-a-kind integrated capture and storage facility at an existing coal-fired power plant in the Ohio River Valley region--an area with a large concentration of power plants and other emission sources. Subsurface characterization data have been used for reservoir simulations and to support the review of the issues relating to injection, monitoring, strategy, risk assessment, and regulatory permitting. The high-sulfur coal samples from the region have been tested in a capture test facility to evaluate and optimize basic design for a small-scale capture system and eventually to prepare a detailed design for a capture, local transport, and injection facility. The Ohio River Valley CO{sub 2} Storage Project was conducted in phases with the ultimate objectives of demonstrating both the technical aspects of CO{sub 2} storage and the testing, logistical, regulatory, and outreach issues related to conducting such a project at a large point source under realistic constraints. The site

  16. Effects of Increased Upward Flux of Saline Water Caused by CO2 Storage or Other Factors

    SciTech Connect (OSTI)

    Murdoch, Lawrence; Xie, Shuang; Falta, Ronald W.; Yonkofski, Catherine MR

    2015-08-01

    likely be minor if the upward flux was smaller than a few tenths of the magnitude of recharge, according to the 2D analyses. The 3D analyses also show that upward flux could occur without a significant increase in the risk categories. The major contribution of this work is that it shows how a large increase in diffuse upward flux from a basin could cause significant problems, but a small increase in upward flux may occur without significantly affecting risks to the shallow freshwater flow system. This heightens the importance of understanding interactions between shallow and deep hydrologic systems when characterizing CO2 storage projects.

  17. Uncertainty Quantification for the Reliability of the Analytical Analysis for the Simplified Model of CO2 Geological Sequestration

    SciTech Connect (OSTI)

    Bao, Jie; Xu, Zhijie; Fang, Yilin

    2015-04-01

    A hydro-mechanical model with analytical solutions including pressure evolution and geomechanical deformation for geological CO2 injection and sequestration were introduced in our previous work. However, the reliability and accuracy of the hydro-mechanical model and the companion analytical solution are uncertain because of the assumptions and simplifications in the analytical model, though it was validated by a few example cases. This study introduce the method to efficiently measure the accuracy of the analytical model, and specify the acceptable input parameters range that can guarantee the accuracy and reliability of the analytical solution. A coupled hydro-geomechanical subsurface transport simulator STOMP was adopted as a reference to justify the reliability of the hydro-mechanical model and the analytical solution. A quasi-Monte Carlo sampling method was applied to efficiently sample the input parameter space.

  18. Estimating nocturnal ecosystem respiration from the vertical turbulent flux and change in storage of CO2

    SciTech Connect (OSTI)

    Gu, Lianhong; Van Gorsel, Eva; Leuning, Ray; Delpierre, Nicolas; Black, Andy; Chen, Baozhang; Munger, J. William; Wofsy, Steve; Aubinet, M.

    2009-11-01

    Micrometeorological measurements of nighttime ecosystem respiration can be systematically biased when stable atmospheric conditions lead to drainage flows associated with decoupling of air flow above and within plant canopies. The associated horizontal and vertical advective fluxes cannot be measured using instrumentation on the single towers typically used at micrometeorological sites. A common approach to minimize bias is to use a threshold in friction velocity, u*, to exclude periods when advection is assumed to be important, but this is problematic in situations when in-canopy flows are decoupled from the flow above. Using data from 25 flux stations in a wide variety of forest ecosystems globally, we examine the generality of a novel approach to estimating nocturnal respiration developed by van Gorsel et al. (van Gorsel, E., Leuning, R., Cleugh, H.A., Keith, H., Suni, T., 2007. Nocturnal carbon efflux: reconciliation of eddy covariance and chamber measurements using an alternative to the u*-threshold filtering technique. Tellus 59B, 397 403, Tellus, 59B, 307-403). The approach is based on the assumption that advection is small relative to the vertical turbulent flux (FC) and change in storage (FS) of CO2 in the few hours after sundown. The sum of FC and FS reach a maximum during this period which is used to derive a temperature response function for ecosystem respiration. Measured hourly soil temperatures are then used with this function to estimate respiration RRmax. The new approach yielded excellent agreement with (1) independent measurements using respiration chambers, (2) with estimates using ecosystem light-response curves of Fc + Fs extrapolated to zero light, RLRC, and (3) with a detailed process-based forest ecosystem model, Rcast. At most sites respiration rates estimated using the u*-filter, Rust, were smaller than RRmax and RLRC. Agreement of our approach with independent measurements indicates that RRmax provides an excellent estimate of nighttime

  19. CO2 Injection Begins in Illinois | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    CO2 Injection Begins in Illinois CO2 Injection Begins in Illinois November 17, 2011 - 12:00pm Addthis Washington, DC - The Midwest Geological Sequestration Consortium (MGSC), one of seven regional partnerships created by the U.S. Department of Energy (DOE) to advance carbon storage technologies nationwide, has begun injecting carbon dioxide (CO2) for their large-scale CO2 injection test in Decatur, Illinois. The test is part of the development phase of the Regional Carbon Sequestration

  20. Synthetic Catalysts for CO2 Storage: Catalytic Improvement of Solvent Capture Systems

    SciTech Connect (OSTI)

    2010-08-15

    IMPACCT Project: LLNL is designing a process to pull CO2 out of the exhaust gas of coal-fired power plants so it can be transported, stored, or utilized elsewhere. Human lungs rely on an enzyme known as carbonic anhydrase to help separate CO2 from our blood and tissue as part of the normal breathing process. LLNL is designing a synthetic catalyst with the same function as this enzyme. The catalyst can be used to quickly capture CO2 from coal exhaust, just as the natural enzyme does in our lungs. LLNL is also developing a method of encapsulating chemical solvents in permeable microspheres that will greatly increase the speed of binding of CO2. The goal of the project is an industry-ready chemical vehicle that can withstand the harsh environments found in exhaust gas and enable new, simple process designs requiring less capital investment.

  1. CO2 on the Integrity of Well Cement | netl.doe.gov

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    CO2 Utilization CO2 Utilization Carbon dioxide (CO2) use and reuse efforts focus on the conversion of CO2 to useable products and fuels that will reduce CO2 emissions in areas where geologic storage may not be an optimal solution. These include: Enhanced Oil/Gas Recovery - Injecting CO2 into depleting oil or gas bearing fields to maximize the amount of CO2 that could be stored as well as maximize hydrocarbon production. View the latest projects selected in FY 2014. CO2 as Feedstock - Use CO2 as

  2. Integrated Reflection Seismic Monitoring and Reservoir Modeling for Geologic CO2 Sequestration

    SciTech Connect (OSTI)

    John Rogers

    2011-12-31

    The US DOE/NETL CCS MVA program funded a project with Fusion Petroleum Technologies Inc. (now SIGMA) to model the proof of concept of using sparse seismic data in the monitoring of CO{sub 2} injected into saline aquifers. The goal of the project was to develop and demonstrate an active source reflection seismic imaging strategy based on deployment of spatially sparse surface seismic arrays. The primary objective was to test the feasibility of sparse seismic array systems to monitor the CO{sub 2} plume migration injected into deep saline aquifers. The USDOE/RMOTC Teapot Dome (Wyoming) 3D seismic and reservoir data targeting the Crow Mountain formation was used as a realistic proxy to evaluate the feasibility of the proposed methodology. Though the RMOTC field has been well studied, the Crow Mountain as a saline aquifer has not been studied previously as a CO{sub 2} sequestration (storage) candidate reservoir. A full reprocessing of the seismic data from field tapes that included prestack time migration (PSTM) followed by prestack depth migration (PSDM) was performed. A baseline reservoir model was generated from the new imaging results that characterized the faults and horizon surfaces of the Crow Mountain reservoir. The 3D interpretation was integrated with the petrophysical data from available wells and incorporated into a geocellular model. The reservoir structure used in the geocellular model was developed using advanced inversion technologies including Fusion's ThinMAN{trademark} broadband spectral inversion. Seal failure risk was assessed using Fusion's proprietary GEOPRESS{trademark} pore pressure and fracture pressure prediction technology. CO{sub 2} injection was simulated into the Crow Mountain with a commercial reservoir simulator. Approximately 1.2MM tons of CO{sub 2} was simulated to be injected into the Crow Mountain reservoir over 30 years and subsequently let 'soak' in the reservoir for 970 years. The relatively small plume developed from this

  3. Maximizing Storage Rate and Capacity and Insuring the Environmental Integrity of Carbon Dioxide Sequestration in Geological Reservoirs

    SciTech Connect (OSTI)

    L.A. Davis; A.L. Graham; H.W. Parker; J.R. Abbott; M.S. Ingber; A.A. Mammoli; L.A. Mondy; Quanxin Guo; Ahmed Abou-Sayed

    2005-12-07

    Maximizing Storage Rate and Capacity and Insuring the Environmental Integrity of Carbon Dioxide Sequestration in Geological Formations The U.S. and other countries may enter into an agreement that will require a significant reduction in CO2 emissions in the medium to long term. In order to achieve such goals without drastic reductions in fossil fuel usage, CO2 must be removed from the atmosphere and be stored in acceptable reservoirs. The research outlined in this proposal deals with developing a methodology to determine the suitability of a particular geologic formation for the long-term storage of CO2 and technologies for the economical transfer and storage of CO2 in these formations. A novel well-logging technique using nuclear-magnetic resonance (NMR) will be developed to characterize the geologic formation including the integrity and quality of the reservoir seal (cap rock). Well-logging using NMR does not require coring, and hence, can be performed much more quickly and efficiently. The key element in the economical transfer and storage of the CO2 is hydraulic fracturing the formation to achieve greater lateral spreads and higher throughputs of CO2. Transport, compression, and drilling represent the main costs in CO2 sequestration. The combination of well-logging and hydraulic fracturing has the potential of minimizing these costs. It is possible through hydraulic fracturing to reduce the number of injection wells by an order of magnitude. Many issues will be addressed as part of the proposed research to maximize the storage rate and capacity and insure the environmental integrity of CO2 sequestration in geological formations. First, correlations between formation properties and NMR relaxation times will be firmly established. A detailed experimental program will be conducted to determine these correlations. Second, improved hydraulic fracturing models will be developed which are suitable for CO2 sequestration as opposed to enhanced oil recovery (EOR

  4. Microsoft Word - NETL-TRS-4-2014_CO2 Storage and Enhanced Gas Recovery_20140924.docx

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Investigation of CO 2 Storage and Enhanced Gas Recovery in Depleted Shale Gas Formations Using a Dual- Porosity/Dual-Permeability, Multiphase Reservoir Simulator 25 September 2014 Office of Fossil Energy NETL-TRS-4-2014 Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or

  5. Microsoft Word - NRAP-TRS-III-002-2012_Modeling the Performance of Large Scale CO2 Storage_20121024.docx

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Modeling the Performance of Large- Scale CO 2 Storage Systems: A Comparison of Different Sensitivity Analysis Methods 24 October 2012 Office of Fossil Energy NRAP-TRS-III-002-2012 Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy,

  6. Reactive transport modeling of the enhancement of density-driven CO2 convective mixing in carbonate aquifers and its potential implication on geological carbon sequestration

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Islam, Akand; Sun, Alexander Y.; Yang, Changbing

    2016-04-20

    We study the convection and mixing of CO2 in a brine aquifer, where the spread of dissolved CO2 is enhanced because of geochemical reactions with the host formations (calcite and dolomite), in addition to the extensively studied, buoyancy-driven mixing. The nonlinear convection is investigated under the assumptions of instantaneous chemical equilibrium, and that the dissipation of carbonate rocks solely depends on flow and transport and chemical speciation depends only on the equilibrium thermodynamics of the chemical system. The extent of convection is quantified in term of the CO2 saturation volume of the storage formation. Our results suggest that the densitymore » increase of resident species causes significant enhancement in CO2 dissolution, although no significant porosity and permeability alterations are observed. Furthermore, early saturation of the reservoir can have negative impact on CO2 sequestration.« less

  7. Secretary Moniz Announces New CO2 Storage Network at Multinational Carbon Sequestration Forum

    Broader source: Energy.gov [DOE]

    Energy Secretary Ernest Moniz today announced the formation of an international initiative to facilitate collaborative testing of advanced carbon capture and storage (CCS) technologies at real-world, saline storage sites.

  8. Quantum Chemistry of CO2 Interaction with Swelling Clays | netl.doe.gov

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Chemistry of CO2 Interaction with Swelling Clays Quantum Chemistry of CO2 Interaction with Swelling Clays Ubiquitous clay minerals can play an important role in assessing the suitability of geologic formations for secure storage of carbon dioxide (CO2). The minerals may affect the reservoir storage capacity as well as the integrity of its natural seals such as caprock formations. CO2 interaction with swelling clays such as smectites is a complex process involving physisorption in micropores and

  9. Geomechanical Evaluation of Thermal Impact of Injected CO2 Temperature on a Geological Reservoir: Application to the FutureGen 2.0 Site

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Bonneville, Alain; USA, Richland Washington; Nguyen, Ba Nghiep; USA, Richland Washington; Stewart, Mark; USA, Richland Washington; Hou, Z. Jason; USA, Richland Washington; Murray, Christopher; USA, Richland Washington; et al

    2014-12-31

    The impact of temperature variations of injected CO2 on the mechanical integrity of a reservoir is a problem rarely addressed in the design of a CO2 storage site. The geomechanical simulation of the FutureGen 2.0 storage site presented here takes into account the complete modeling of heat exchange between the environment and CO2 during its transport in the pipeline and injection well before reaching the reservoir, as well as its interaction with the reservoir host rock. An ad-hoc program was developed to model CO2 transport from the power plant to the reservoir and an approach coupling PNNL STOMP-CO2 multiphase flowmore » simulator and ABAQUS® has been developed for the reservoir model which is fully three-dimensional with four horizontal wells and variable layer thickness. The Mohr-Coulomb fracture criterion has been employed, where hydraulic fracture was predicted to occur at an integration point if the fluid pressure at the point exceeded the least compressive principal stress. Evaluation of the results shows that the fracture criterion has not been verified at any node and time step for the CO2 temperature range predicted at the top of the injection zone.« less

  10. Using Pressure and Volumetric Approaches to Estimate CO2 Storage Capacity in Deep Saline Aquifers

    SciTech Connect (OSTI)

    Thibeau, Sylvain; Bachu, Stefan; Birkholzer, Jens; Holloway, Sam; Neele, Filip; Zhou, Quanlin

    2014-12-31

    Various approaches are used to evaluate the capacity of saline aquifers to store CO2, resulting in a wide range of capacity estimates for a given aquifer. The two approaches most used are the volumetric open aquifer and closed aquifer approaches. We present four full-scale aquifer cases, where CO2 storage capacity is evaluated both volumetrically (with open and/or closed approaches) and through flow modeling. These examples show that the open aquifer CO2 storage capacity estimation can strongly exceed the cumulative CO2 injection from the flow model, whereas the closed aquifer estimates are a closer approximation to the flow-model derived capacity. An analogy to oil recovery mechanisms is presented, where the primary oil recovery mechanism is compared to CO2 aquifer storage without producing formation water; and the secondary oil recovery mechanism (water flooding) is compared to CO2 aquifer storage performed simultaneously with extraction of water for pressure maintenance. This analogy supports the finding that the closed aquifer approach produces a better estimate of CO2 storage without water extraction, and highlights the need for any CO2 storage estimate to specify whether it is intended to represent CO2 storage capacity with or without water extraction.

  11. Geological Sequestration Training and Research Program in Capture and Transport: Development of the Most Economical Separation Method for CO2 Capture

    SciTech Connect (OSTI)

    Vahdat, Nader

    2013-09-30

    The project provided hands-on training and networking opportunities to undergraduate students in the area of carbon dioxide (CO2) capture and transport, through fundamental research study focused on advanced separation methods that can be applied to the capture of CO2 resulting from the combustion of fossil-fuels for power generation . The project team’s approach to achieve its objectives was to leverage existing Carbon Capture and Storage (CCS) course materials and teaching methods to create and implement an annual CCS short course for the Tuskegee University community; conduct a survey of CO2 separation and capture methods; utilize data to verify and develop computer models for CO2 capture and build CCS networks and hands-on training experiences. The objectives accomplished as a result of this project were: (1) A comprehensive survey of CO2 capture methods was conducted and mathematical models were developed to compare the potential economics of the different methods based on the total cost per year per unit of CO2 avoidance; and (2) Training was provided to introduce the latest CO2 capture technologies and deployment issues to the university community.

  12. First-Generation Risk Profiles Help Predict CO2 Storage Site...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    September 18, 2012 - 1:00pm Addthis Washington, DC - In support of large-scale carbon capture, utilization and storage (CCUS) projects, a collaboration of five U.S. Department...

  13. Effect of Oxygen Co-Injected with Carbon Dioxide on Gothic Shale Caprock-CO2-Brine Interaction during Geologic Carbon Sequestration

    SciTech Connect (OSTI)

    Jung, Hun Bok; Um, Wooyong; Cantrell, Kirk J.

    2013-09-16

    Co-injection of oxygen, a significant component in CO2 streams produced by the oxyfuel combustion process, can cause a significant alteration of the redox state in deep geologic formations during geologic carbon sequestration. The potential impact of co-injected oxygen on the interaction between synthetic CO2-brine (0.1 M NaCl) and shale caprock (Gothic shale from the Aneth Unit in Utah) and mobilization of trace metals was investigated at ~10 MPa and ~75 °C. A range of relative volume percentages of O2 to CO2 (0, 1, 4 and 8%) were used in these experiments to address the effect of oxygen on shale-CO2-brine interaction under various conditions. Major mineral phases in Gothic shale are quartz, calcite, dolomite, montmorillonite, and pyrite. During Gothic shale-CO2-brine interaction in the presence of oxygen, pyrite oxidation occurred extensively and caused enhanced dissolution of calcite and dolomite. Pyrite oxidation and calcite dissolution subsequently resulted in the precipitation of Fe(III) oxides and gypsum (CaSO4•2H2O). In the presence of oxygen, dissolved Mn and Ni were elevated because of oxidative dissolution of pyrite. The mobility of dissolved Ba was controlled by barite (BaSO4) precipitation in the presence of oxygen. Dissolved U in the experimental brines increased to ~8–14 g/L, with concentrations being slightly higher in the absence of oxygen than in the presence of oxygen. Experimental and modeling results indicate the interaction between shale caprock and oxygen co-injected with CO2 during geologic carbon sequestration can exert significant impacts on brine pH, solubility of carbonate minerals, stability of sulfide minerals, and mobility of trace metals. The major impact of oxygen is most likely to occur in the zone near CO2 injection wells where impurity gases can accumulate. Oxygen in CO2-brine migrating away from the injection well will be continually consumed through the reactions with sulfide minerals in deep geologic formations.

  14. Integrated modeling of CO2 storage and leakage scenarios including transitions between super- and sub-critical conditions, and phase change between liquid and gaseous CO2

    SciTech Connect (OSTI)

    Pruess, K.

    2011-05-15

    Storage of CO{sub 2} in saline aquifers is intended to be at supercritical pressure and temperature conditions, but CO{sub 2} leaking from a geologic storage reservoir and migrating toward the land surface (through faults, fractures, or improperly abandoned wells) would reach subcritical conditions at depths shallower than 500-750 m. At these and shallower depths, subcritical CO{sub 2} can form two-phase mixtures of liquid and gaseous CO{sub 2}, with significant latent heat effects during boiling and condensation. Additional strongly non-isothermal effects can arise from decompression of gas-like subcritical CO{sub 2}, the so-called Joule-Thomson effect. Integrated modeling of CO{sub 2} storage and leakage requires the ability to model non-isothermal flows of brine and CO{sub 2} at conditions that range from supercritical to subcritical, including three-phase flow of aqueous phase, and both liquid and gaseous CO{sub 2}. In this paper, we describe and demonstrate comprehensive simulation capabilities that can cope with all possible phase conditions in brine-CO{sub 2} systems. Our model formulation includes: (1) an accurate description of thermophysical properties of aqueous and CO{sub 2}-rich phases as functions of temperature, pressure, salinity and CO{sub 2} content, including the mutual dissolution of CO{sub 2} and H{sub 2}O; (2) transitions between super- and subcritical conditions, including phase change between liquid and gaseous CO{sub 2}; (3) one-, two-, and three-phase flow of brine-CO{sub 2} mixtures, including heat flow; (4) non-isothermal effects associated with phase change, mutual dissolution of CO{sub 2} and water, and (de-) compression effects; and (5) the effects of dissolved NaCl, and the possibility of precipitating solid halite, with associated porosity and permeability change. Applications to specific leakage scenarios demonstrate that the peculiar thermophysical properties of CO{sub 2} provide a potential for positive as well as negative

  15. Basin-Scale Hydrologic Impacts of CO2 Storage: Regulatory and Capacity Implications

    SciTech Connect (OSTI)

    Birkholzer, J.T.; Zhou, Q.

    2009-04-02

    Industrial-scale injection of CO{sub 2} into saline sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration reservoirs. In this paper, we discuss how such basin-scale hydrologic impacts can (1) affect regulation of CO{sub 2} storage projects and (2) may reduce current storage capacity estimates. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO{sub 2} storage projects in a core injection area suitable for long-term storage. Each project is assumed to inject five million tonnes of CO{sub 2} per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO{sub 2}-brine flow processes and the large-scale groundwater flow patterns in response to CO{sub 2} storage. The far-field pressure buildup predicted for this selected sequestration scenario suggests that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrologic response may be affected by interference between individual sites. Our results also support recent studies in that environmental concerns related to near-field and far-field pressure buildup may be a limiting factor on CO{sub 2} storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO{sub 2}, may have to be revised based on assessments of pressure perturbations and their potential impact on caprock integrity and groundwater resources, respectively. We finally discuss some of the challenges in making reliable predictions of large-scale hydrologic impacts related to CO{sub 2

  16. Niagara Falls Storage Site, Lewiston, New York: geologic report

    SciTech Connect (OSTI)

    Not Available

    1984-06-01

    This report is one of a series of engineering and environmental reports planned for the US Department of Energy's properties at Niagara Falls, New York. It describes the essential geologic features of the Niagara Falls Storage Site. It is not intended to be a definitive statement of the engineering methods and designs required to obtain desired performance features for any permanent waste disposal at the site. Results are presented of a geological investigation that consisted of two phases. Phase 1 occurred during July 1982 and included geologic mapping, geophysical surveys, and a limited drilling program in the vicinity of the R-10 Dike, planned for interim storage of radioactive materials. Phase 2, initiated in December 1982, included excavation of test pits, geophysical surveys, drilling, observation well installation, and field permeability testing in the South Dike Area, the Northern Disposal Area, and the K-65 Tower Area.

  17. The Ohio River Valley CO2 Storage Project AEP Mountaineer Plant, West Virginia Numerical Simulation and Risk Assessment Report

    SciTech Connect (OSTI)

    Neeraj Gupta

    2008-03-31

    A series of numerical simulations of carbon dioxide (CO{sub 2}) injection were conducted as part of a program to assess the potential for geologic sequestration in deep geologic reservoirs (the Rose Run and Copper Ridge formations), at the American Electric Power (AEP) Mountaineer Power Plant outside of New Haven, West Virginia. The simulations were executed using the H{sub 2}O-CO{sub 2}-NaCl operational mode of the Subsurface Transport Over Multiple Phases (STOMP) simulator (White and Oostrom, 2006). The objective of the Rose Run formation modeling was to predict CO{sub 2} injection rates using data from the core analysis conducted on the samples. A systematic screening procedure was applied to the Ohio River Valley CO{sub 2} storage site utilizing the Features, Elements, and Processes (FEP) database for geological storage of CO{sub 2} (Savage et al., 2004). The objective of the screening was to identify potential risk categories for the long-term geological storage of CO{sub 2} at the Mountaineer Power Plant in New Haven, West Virginia. Over 130 FEPs in seven main classes were assessed for the project based on site characterization information gathered in a geological background study, testing in a deep well drilled on the site, and general site conditions. In evaluating the database, it was apparent that many of the items were not applicable to the Mountaineer site based its geologic framework and environmental setting. Nine FEPs were identified for further consideration for the site. These FEPs generally fell into categories related to variations in subsurface geology, well completion materials, and the behavior of CO{sub 2} in the subsurface. Results from the screening were used to provide guidance on injection system design, developing a monitoring program, performing reservoir simulations, and other risk assessment efforts. Initial work indicates that the significant FEPs may be accounted for by focusing the storage program on these potential issues. The

  18. Mathematical models as tools for probing long-term safety of CO2 storage

    SciTech Connect (OSTI)

    Pruess, Karsten; Birkholzer, Jens; Zhou, Quanlin

    2009-02-01

    Subsurface reservoirs being considered for storing CO{sub 2} include saline aquifers, oil and gas reservoirs, and unmineable coal seams (Baines and Worden, 2004; IPCC, 2005). By far the greatest storage capacity is in saline aquifers (Dooley et al., 2004), and our discussion will focus primarily on CO{sub 2} storage in saline formations. Most issues for safety and security of CO{sub 2} storage arise from the fact that, at typical temperature and pressure conditions encountered in terrestrial crust, CO{sub 2} is less dense than aqueous fluids. Accordingly, CO{sub 2} will experience an upward buoyancy force in most subsurface environments, and will tend to migrate upwards whenever (sub-)vertical permeable pathways are available, such as fracture zones, faults, or improperly abandoned wells (Bachu, 2008; Pruess, 2008a, b; Tsang et al., 2008). CO{sub 2} injection will increase fluid pressures in the target formation, thereby altering effective stress distributions, and potentially triggering movement along fractures and faults that could increase their permeability and reduce the effectiveness of a caprock in containing CO{sub 2} (Rutqvist et al., 2008; Chiaramonte et al., 2008). Induced seismicity as a consequence of fluid injection is also a concern (Healy et al., 1968; Raleigh et al., 1976; Majer et al., 2007). Dissolution of CO{sub 2} in the aqueous phase generates carbonic acid, which may induce chemical corrosion (dissolution) of minerals with associated increase in formation porosity and permeability, and may also mediate sequestration of CO{sub 2} as solid carbonate (Gaus et al., 2008). Chemical dissolution of caprock minerals could promote leakage of CO{sub 2} from a storage reservoir (Gherardi et al., 2007). Chemical dissolution and geomechanical effects could reinforce one another in compromising CO{sub 2} containment. Additional issues arise from the potential of CO{sub 2} to mobilize hazardous chemical species (Kharaka et al., 2006), and from migration of

  19. Monitoring CO2 Storage at Cranfield, Mississippi with Time-Lapse Offset VSP – Using Integration and Modeling to Reduce Uncertainty

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Daley, Thomas M.; Hendrickson, Joel; Queen, John H.

    2014-12-31

    A time-lapse Offset Vertical Seismic Profile (OVSP) data set was acquired as part of a subsurface monitoring program for geologic sequestration of CO2. The storage site at Cranfield, near Natchez, Mississippi, is part of a detailed area study (DAS) site for geologic carbon sequestration operated by the U.S. Dept. of Energy’s Southeast Regional Carbon Sequestration Partnership (SECARB). The DAS site includes three boreholes, an injection well and two monitoring wells. The project team selected the DAS site to examine CO2 sequestration multiphase fluid flow and pressure at the interwell scale in a brine reservoir. The time-lapse (TL) OVSP was partmore » of an integrated monitoring program that included well logs, crosswell seismic, electrical resistance tomography and 4D surface seismic. The goals of the OVSP were to detect the CO2 induced change in seismic response, give information about the spatial distribution of CO2 near the injection well and to help tie the high-resolution borehole monitoring to the 4D surface data. The VSP data were acquired in well CFU 31-F1, which is the ~3200 m deep CO2 injection well at the DAS site. A preinjection survey was recorded in late 2009 with injection beginning in December 2009, and a post injection survey was conducted in Nov 2010 following injection of about 250 kT of CO2. The sensor array for both surveys was a 50-level, 3-component, Sercel MaxiWave system with 15 m (49 ft) spacing between levels. The source for both surveys was an accelerated weight drop, with different source trucks used for the two surveys. Consistent time-lapse processing was applied to both data sets. Time-lapse processing generated difference corridor stacks to investigate CO2 induced reflection amplitude changes from each source point. Corridor stacks were used for amplitude analysis to maximize the signal-to-noise ratio (S/N) for each shot point. Spatial variation in reflectivity (used to ‘map’ the plume) was similar in magnitude to the

  20. Modeling basin- and plume-scale processes of CO2 storage for full-scale deployment

    SciTech Connect (OSTI)

    Zhou, Q.; Birkholzer, J.T.; Mehnert, E.; Lin, Y.-F.; Zhang, K.

    2009-08-15

    Integrated modeling of basin- and plume-scale processes induced by full-scale deployment of CO{sub 2} storage was applied to the Mt. Simon Aquifer in the Illinois Basin. A three-dimensional mesh was generated with local refinement around 20 injection sites, with approximately 30 km spacing. A total annual injection rate of 100 Mt CO{sub 2} over 50 years was used. The CO{sub 2}-brine flow at the plume scale and the single-phase flow at the basin scale were simulated. Simulation results show the overall shape of a CO{sub 2} plume consisting of a typical gravity-override subplume in the bottom injection zone of high injectivity and a pyramid-shaped subplume in the overlying multilayered Mt. Simon, indicating the important role of a secondary seal with relatively low-permeability and high-entry capillary pressure. The secondary-seal effect is manifested by retarded upward CO{sub 2} migration as a result of multiple secondary seals, coupled with lateral preferential CO{sub 2} viscous fingering through high-permeability layers. The plume width varies from 9.0 to 13.5 km at 200 years, indicating the slow CO{sub 2} migration and no plume interference between storage sites. On the basin scale, pressure perturbations propagate quickly away from injection centers, interfere after less than 1 year, and eventually reach basin margins. The simulated pressure buildup of 35 bar in the injection area is not expected to affect caprock geomechanical integrity. Moderate pressure buildup is observed in Mt. Simon in northern Illinois. However, its impact on groundwater resources is less than the hydraulic drawdown induced by long-term extensive pumping from overlying freshwater aquifers.

  1. Geologic Water Storage in Pre-Columbian Peru

    SciTech Connect (OSTI)

    Fairley Jr., Jerry P.

    1997-07-14

    Agriculture in the arid and semi-arid regions that comprise much of present-day Peru, Bolivia, and Northern Chile is heavily dependent on irrigation; however, obtaining a dependable water supply in these areas is often difficult. The precolumbian peoples of Andean South America adapted to this situation by devising many strategies for transporting, storing, and retrieving water to insure consistent supply. I propose that the ''elaborated springs'' found at several Inka sites near Cuzco, Peru, are the visible expression of a simple and effective system of groundwater control and storage. I call this system ''geologic water storage'' because the water is stored in the pore spaces of sands, soils, and other near-surface geologic materials. I present two examples of sites in the Cuzco area that use this technology (Tambomachay and Tipon) and discuss the potential for identification of similar systems developed by other ancient Latin American cultures.

  2. Environmental Responses to Carbon Mitigation through Geological Storage

    SciTech Connect (OSTI)

    Cunningham, Alfred; Bromenshenk, Jerry

    2013-08-30

    In summary, this DOE EPSCoR project is contributing to the study of carbon mitigation through geological storage. Both deep and shallow subsurface research needs are being addressed through research directed at improved understanding of environmental responses associated with large scale injection of CO{sub 2} into geologic formations. The research plan has two interrelated research objectives. Objective 1: Determine the influence of CO{sub 2}-related injection of fluids on pore structure, material properties, and microbial activity in rock cores from potential geological carbon sequestration sites. Objective 2: Determine the Effects of CO{sub 2} leakage on shallow subsurface ecosystems (microbial and plant) using field experiments from an outdoor field testing facility.

  3. THE OHIO RIVER VALLEY CO2 STORAGE PROJECT - PRELIMINARY ASSESSMENT OF DEEP SALINE RESERVOIRS AND COAL SEAMS

    SciTech Connect (OSTI)

    Michael J. Mudd; Howard Johnson; Charles Christopher; T.S. Ramakrishnan, Ph.D.

    2003-08-01

    This report describes the geologic setting for the Deep Saline Reservoirs and Coal Seams in the Ohio River Valley CO{sub 2} Storage Project area. The object of the current project is to site and design a CO{sub 2} injection facility. A location near New Haven, WV, has been selected for the project. To assess geologic storage reservoirs at the site, regional and site-specific geology were reviewed. Geologic reports, deep well logs, hydraulic tests, and geologic maps were reviewed for the area. Only one well within 25 miles of the site penetrates the deeper sedimentary rocks, so there is a large amount of uncertainty regarding the deep geology at the site. New Haven is located along the Ohio River on the border of West Virginia and Ohio. Topography in the area is flat in the river valley but rugged away from the Ohio River floodplain. The Ohio River Valley incises 50-100 ft into bedrock in the area. The area of interest lies within the Appalachian Plateau, on the western edge of the Appalachian Mountain chain. Within the Appalachian Basin, sedimentary rocks are 3,000 to 20,000 ft deep and slope toward the southeast. The rock formations consist of alternating layers of shale, limestone, dolomite, and sandstone overlying dense metamorphic continental shield rocks. The Rome Trough is the major structural feature in the area, and there may be some faults associated with the trough in the Ohio-West Virginia Hinge Zone. The area has a low earthquake hazard with few historical earthquakes. Target injection reservoirs include the basal sandstone/Lower Maryville and the Rose Run Sandstone. The basal sandstone is an informal name for sandstones that overlie metamorphic shield rock. Regional geology indicates that the unit is at a depth of approximately 9,100 ft below the surface at the project site and associated with the Maryville Formation. Overall thickness appears to be 50-100 ft. The Rose Run Sandstone is another potential reservoir. The unit is located approximately 1

  4. Comparing large scale CCS deployment potential in the USA and China: a detailed analysis based on country-specific CO2 transport & storage cost curves

    SciTech Connect (OSTI)

    Dahowski, Robert T.; Davidson, Casie L.; Dooley, James J.

    2011-04-18

    The United States and China are the two largest emitters of greenhouse gases in the world and their projected continued growth and reliance on fossil fuels, especially coal, make them strong candidates for CCS. Previous work has revealed that both nations have over 1600 large electric utility and other industrial point CO2 sources as well as very large CO2 storage resources on the order of 2,000 billion metric tons (Gt) of onshore storage capacity. In each case, the vast majority of this capacity is found in deep saline formations. In both the USA and China, candidate storage reservoirs are likely to be accessible by most sources with over 80% of these large industrial CO2 sources having a CO2 storage option within just 80 km. This suggests a strong potential for CCS deployment as a meaningful option to efforts to reduce CO2 emissions from these large, vibrant economies. However, while the USA and China possess many similarities with regards to the potential value that CCS might provide, including the range of costs at which CCS may be available to most large CO2 sources in each nation, there are a number of more subtle differences that may help us to understand the ways in which CCS deployment may differ between these two countries in order for the USA and China to work together - and in step with the rest of the world - to most efficiently reduce greenhouse gas emissions. This paper details the first ever analysis of CCS deployment costs in these two countries based on methodologically comparable CO2 source and sink inventories, economic analysis, geospatial source-sink matching and cost curve modeling. This type of analysis provides a valuable insight into the degree to which early and sustained opportunities for climate change mitigation via commercial-scale CCS are available to the two countries, and could facilitate greater collaboration in areas where those opportunities overlap.

  5. Simulation of CO2 Sequestration at Rock Spring Uplift, Wyoming: Heterogeneity and Uncertainties in Storage Capacity, Injectivity and Leakage

    SciTech Connect (OSTI)

    Deng, Hailin; Dai, Zhenxue; Jiao, Zunsheng; Stauffer, Philip H.; Surdam, Ronald C.

    2011-01-01

    Many geological, geochemical, geomechanical and hydrogeological factors control CO{sub 2} storage in subsurface. Among them heterogeneity in saline aquifer can seriously influence design of injection wells, CO{sub 2} injection rate, CO{sub 2} plume migration, storage capacity, and potential leakage and risk assessment. This study applies indicator geostatistics, transition probability and Markov chain model at the Rock Springs Uplift, Wyoming generating facies-based heterogeneous fields for porosity and permeability in target saline aquifer (Pennsylvanian Weber sandstone) and surrounding rocks (Phosphoria, Madison and cap-rock Chugwater). A multiphase flow simulator FEHM is then used to model injection of CO{sub 2} into the target saline aquifer involving field-scale heterogeneity. The results reveal that (1) CO{sub 2} injection rates in different injection wells significantly change with local permeability distributions; (2) brine production rates in different pumping wells are also significantly impacted by the spatial heterogeneity in permeability; (3) liquid pressure evolution during and after CO{sub 2} injection in saline aquifer varies greatly for different realizations of random permeability fields, and this has potential important effects on hydraulic fracturing of the reservoir rock, reactivation of pre-existing faults and the integrity of the cap-rock; (4) CO{sub 2} storage capacity estimate for Rock Springs Uplift is 6614 {+-} 256 Mt at 95% confidence interval, which is about 36% of previous estimate based on homogeneous and isotropic storage formation; (5) density profiles show that the density of injected CO{sub 2} below 3 km is close to that of the ambient brine with given geothermal gradient and brine concentration, which indicates CO{sub 2} plume can sink to the deep before reaching thermal equilibrium with brine. Finally, we present uncertainty analysis of CO{sub 2} leakage into overlying formations due to heterogeneity in both the target saline

  6. Uncertainty quantification for evaluating impacts of caprock and reservoir properties on pressure buildup and ground surface displacement during geological CO2 sequestration

    SciTech Connect (OSTI)

    Bao, Jie; Hou, Zhangshuan; Fang, Yilin; Ren, Huiying; Lin, Guang

    2013-08-12

    A series of numerical test cases reflecting broad and realistic ranges of geological formation properties was developed to systematically evaluate and compare the impacts of those properties on geomechanical responses to CO2 injection. A coupled hydro-geomechanical subsurface transport simulator, STOMP (Subsurface Transport over Multiple Phases), was adopted to simulate the CO2 migration process and geomechanical behaviors of the surrounding geological formations. A quasi-Monte Carlo sampling method was applied to efficiently sample a high-dimensional parameter space consisting of injection rate and 14 subsurface formation properties, including porosity, permeability, entry pressure, irreducible gas and aqueous saturation, Young’s modulus, and Poisson’s ratio for both reservoir and caprock. Generalized cross-validation and analysis of variance methods were used to quantitatively measure the significance of the 15 input parameters. Reservoir porosity, permeability, and injection rate were found to be among the most significant factors affecting the geomechanical responses to the CO2 injection. We used a quadrature generalized linear model to build a reduced-order model that can estimate the geomechanical response instantly instead of running computationally expensive numerical simulations. The injection pressure and ground surface displacement are often monitored for injection well safety, and are believed can partially reflect the risk of fault reactivation and seismicity. Based on the reduced order model and response surface, the input parameters can be screened for control the risk of induced seismicity. The uncertainty of the subsurface structure properties cause the numerical simulation based on a single or a few samples does not accurately estimate the geomechanical response in the actual injection site. Probability of risk can be used to evaluate and predict the risk of injection when there are great uncertainty in the subsurface properties and operation

  7. Large Releases from CO2 Storage Reservoirs: A Discussion ofNatural Analogs, FEPS, and Modeling Needs

    SciTech Connect (OSTI)

    Birkholzer, J.; Pruess, K.; Lewicki, J.L.; Rutqvist, J.; Tsang,C-F.; Karimjee, A.

    2005-11-01

    While the purpose of geologic storage in deep saline formations is to trap greenhouse gases underground, the potential exists for CO{sub 2} to escape from the target reservoir, migrate upward along permeable pathways, and discharge at the land surface. In this paper, we evaluate the potential for such CO{sub 2} discharges based on the analysis of natural analogs, where large releases of gas have been observed. We are particularly interested in circumstances that could generate sudden, possibly self-enhancing release events. The probability for such events may be low, but the circumstances under which they occur and the potential consequences need to be evaluated in order to design appropriate site-selection and risk-management strategies. Numerical modeling of hypothetical test cases is suggested to determine critical conditions for large CO{sub 2} releases, to evaluate whether such conditions may be possible at designated storage sites, and, if applicable, to evaluate the potential impacts of such events as well as design appropriate mitigation strategies.

  8. Surface CO2 leakage during the first shallow subsurface CO2release experiment

    SciTech Connect (OSTI)

    Lewicki, J.L.; Oldenburg, C.; Dobeck, L.; Spangler, L.

    2007-09-15

    A new field facility was used to study CO2 migrationprocesses and test techniques to detect and quantify potential CO2leakage from geologic storage sites. For 10 days starting 9 July 2007,and for seven days starting 5 August 2007, 0.1 and 0.3 t CO2 d-1,respectively, were released from a ~;100-m long, sub-water table (~;2.5-mdepth) horizontal well. The spatio-temporal evolution of leakage wasmapped through repeated grid measurements of soil CO2 flux (FCO2). Thesurface leakage onset, approach to steady state, and post-release declinematched model predictions closely. Modeling suggested that minimal CO2was taken up by groundwater through dissolution, and CO2 spread out ontop of the water table. FCO2 spatial patterns were related to well designand soil physical properties. Estimates of total CO2 discharge along withsoil respiration and leakage discharge highlight the influence ofbackground CO2 flux variations on detection of CO2 leakagesignals.

  9. Large-Scale Utilization of Biomass Energy and Carbon Dioxide Capture and Storage in the Transport and Electricity Sectors under Stringent CO2 Concentration Limit Scenarios

    SciTech Connect (OSTI)

    Luckow, Patrick; Wise, Marshall A.; Dooley, James J.; Kim, Son H.

    2010-08-05

    This paper examines the potential role of large scale, dedicated commercial biomass energy systems under global climate policies designed to meet atmospheric concentrations of CO2 at 400ppm and 450ppm by the end of the century. We use an integrated assessment model of energy and agriculture systems to show that, given a climate policy in which terrestrial carbon is appropriately valued equally with carbon emitted from the energy system, biomass energy has the potential to be a major component of achieving these low concentration targets. A key aspect of the research presented here is that the costs of processing and transporting biomass energy at much larger scales than current experience are explicitly incorporated into the modeling. From the scenario results, 120-160 EJ/year of biomass energy is produced globally by midcentury and 200-250 EJ/year by the end of this century. In the first half of the century, much of this biomass is from agricultural and forest residues, but after 2050 dedicated cellulosic biomass crops become the majority source, along with growing utilization of waste-to-energy. The ability to draw on a diverse set of biomass based feedstocks helps to reduce the pressure for drastic large-scale changes in land use and the attendant environmental, ecological, and economic consequences those changes would unleash. In terms of the conversion of bioenergy feedstocks into value added energy, this paper demonstrates that biomass is and will continue to be used to generate electricity as well as liquid transportation fuels. A particular focus of this paper is to show how climate policies and technology assumptions - especially the availability of carbon dioxide capture and storage (CCS) technologies - affect the decisions made about where the biomass is used in the energy system. The potential for net-negative electric sector emissions through the use of CCS with biomass feedstocks provides an attractive part of the solution for meeting stringent

  10. Two-Stage, Integrated, Geothermal-CO2 Storage Reservoirs: An Approach for Sustainable Energy Production, CO2-Sequestration Security, and Reduced Environmental Risk

    SciTech Connect (OSTI)

    Buscheck, T A; Chen, M; Sun, Y; Hao, Y; Elliot, T R

    2012-02-02

    We introduce a hybrid two-stage energy-recovery approach to sequester CO{sub 2} and produce geothermal energy at low environmental risk and low cost by integrating geothermal production with CO{sub 2} capture and sequestration (CCS) in saline, sedimentary formations. Our approach combines the benefits of the approach proposed by Buscheck et al. (2011b), which uses brine as the working fluid, with those of the approach first suggested by Brown (2000) and analyzed by Pruess (2006), using CO{sub 2} as the working fluid, and then extended to saline-formation CCS by Randolph and Saar (2011a). During stage one of our hybrid approach, formation brine, which is extracted to provide pressure relief for CO{sub 2} injection, is the working fluid for energy recovery. Produced brine is applied to a consumptive beneficial use: feedstock for fresh water production through desalination, saline cooling water, or make-up water to be injected into a neighboring reservoir operation, such as in Enhanced Geothermal Systems (EGS), where there is often a shortage of a working fluid. For stage one, it is important to find economically feasible disposition options to reduce the volume of brine requiring reinjection in the integrated geothermal-CCS reservoir (Buscheck et al. 2012a). During stage two, which begins as CO{sub 2} reaches the production wells; coproduced brine and CO{sub 2} are the working fluids. We present preliminary reservoir engineering analyses of this approach, using a simple conceptual model of a homogeneous, permeable CO{sub 2} storage formation/geothermal reservoir, bounded by relatively impermeable sealing units. We assess both the CO{sub 2} sequestration capacity and geothermal energy production potential as a function of well spacing between CO{sub 2} injectors and brine/CO{sub 2} producers for various well patterns and for a range of subsurface conditions.

  11. Department of Energy Announces 15 Projects Aimed at Secure CO2 Underground

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Storage | Department of Energy 5 Projects Aimed at Secure CO2 Underground Storage Department of Energy Announces 15 Projects Aimed at Secure CO2 Underground Storage August 11, 2010 - 12:00am Addthis Washington, D.C. - U.S. Energy Secretary Steven Chu announced today the selection of 15 projects to develop technologies aimed at safely and economically storing carbon dioxide in geologic formations. Funded with $21.3 million over three years, today's selections will complement existing DOE

  12. Application of Cutting-Edge 3D Seismic Attribute Technology to the Assessment of Geological Reservoirs for CO2 Sequestration

    SciTech Connect (OSTI)

    Christopher Liner; Jianjun Zeng; Po Geng Heather King Jintan Li; Jennifer Califf; John Seales

    2010-03-31

    The goals of this project were to develop innovative 3D seismic attribute technologies and workflows to assess the structural integrity and heterogeneity of subsurface reservoirs with potential for CO{sub 2} sequestration. Our specific objectives were to apply advanced seismic attributes to aide in quantifying reservoir properies and lateral continuity of CO{sub 2} sequestration targets. Our study area is the Dickman field in Ness County, Kansas, a type locality for the geology that will be encountered for CO{sub 2} sequestration projects from northern Oklahoma across the U.S. midcontent to Indiana and beyond. Since its discovery in 1962, the Dickman Field has produced about 1.7 million barrels of oil from porous Mississippian carbonates with a small structural closure at about 4400 ft drilling depth. Project data includes 3.3 square miles of 3D seismic data, 142 wells, with log, some core, and oil/water production data available. Only two wells penetrate the deep saline aquifer. Geological and seismic data were integrated to create a geological property model and a flow simulation grid. We systematically tested over a dozen seismic attributes, finding that curvature, SPICE, and ANT were particularly useful for mapping discontinuities in the data that likely indicated fracture trends. Our simulation results in the deep saline aquifer indicate two effective ways of reducing free CO{sub 2}: (a) injecting CO{sub 2} with brine water, and (b) horizontal well injection. A tuned combination of these methods can reduce the amount of free CO{sub 2} in the aquifer from over 50% to less than 10%.

  13. GEOLOGIC SCREENING CRITERIA FOR SEQUESTRATION OF CO2 IN COAL: QUANTIFYING POTENTIAL OF THE BLACK WARRIOR COALBED METHANE FAIRWAY, ALABAMA

    SciTech Connect (OSTI)

    Jack C. Pashin; Richard E. Carroll; Richard H. Groshong Jr.; Dorothy E. Raymond; Marcella McIntyre; J. Wayne Payton

    2004-01-01

    Sequestration of CO{sub 2} in coal has potential benefits for reducing greenhouse gas emissions from the highly industrialized Carboniferous coal basins of North America and Europe and for enhancing coalbed methane recovery. Hence, enhanced coalbed methane recovery operations provide a basis for a market-based environmental solution in which the cost of sequestration is offset by the production and sale of natural gas. The Black Warrior foreland basin of west-central Alabama contains the only mature coalbed methane production fairway in eastern North America, and data from this basin provide an excellent basis for quantifying the carbon sequestration potential of coal and for identifying the geologic screening criteria required to select sites for the demonstration and commercialization of carbon sequestration technology. Coalbed methane reservoirs in the upper Pottsville Formation of the Black Warrior basin are extremely heterogeneous, and this heterogeneity must be considered to screen areas for the application of CO{sub 2} sequestration and enhanced coalbed methane recovery technology. Major screening factors include stratigraphy, geologic structure, geothermics, hydrogeology, coal quality, sorption capacity, technology, and infrastructure. Applying the screening model to the Black Warrior basin indicates that geologic structure, water chemistry, and the distribution of coal mines and reserves are the principal determinants of where CO{sub 2} can be sequestered. By comparison, coal thickness, temperature-pressure conditions, and coal quality are the key determinants of sequestration capacity and unswept coalbed methane resources. Results of this investigation indicate that the potential for CO{sub 2} sequestration and enhanced coalbed methane recovery in the Black Warrior basin is substantial and can result in significant reduction of greenhouse gas emissions while increasing natural gas reserves. Coal-fired power plants serving the Black Warrior basin in

  14. GEOLOGIC SCREENING CRITERIA FOR SEQUESTRATION OF CO2 IN COAL: QUANTIFYING POTENTIAL OF THE BLACK WARRIOR COALBED METHANE FAIRWAY, ALABAMA

    SciTech Connect (OSTI)

    Jack C. Pashin; Richard E. Carroll; Richard H. Groshong, Jr.; Dorothy E. Raymond; Marcella McIntyre; J. Wayne Payton

    2003-01-01

    Sequestration of CO{sub 2} in coal has potential to reduce greenhouse gas emissions from coal-fired power plants while enhancing coalbed methane recovery. Data from more than 4,000 coalbed methane wells in the Black Warrior basin of Alabama provide an opportunity to quantify the carbon sequestration potential of coal and to develop a geologic screening model for the application of carbon sequestration technology. This report summarizes stratigraphy and sedimentation, structural geology, geothermics, hydrology, coal quality, gas capacity, and production characteristics of coal in the Black Warrior coalbed methane fairway and the implications of geology for carbon sequestration and enhanced coalbed methane recovery. Coal in the Black Warrior basin is distributed among several fluvial-deltaic coal zones in the Lower Pennsylvanian Pottsville Formation. Most coal zones contain one to three coal beds that are significant targets for coalbed methane production and carbon sequestration, and net coal thickness generally increases southeastward. Pottsville strata have effectively no matrix permeability to water, so virtually all flow is through natural fractures. Faults and folds influence the abundance and openness of fractures and, hence, the performance of coalbed methane wells. Water chemistry in the Pottsville Formation ranges from fresh to saline, and zones with TDS content lower than 10,000 mg/L can be classified as USDW. An aquifer exemption facilitating enhanced recovery in USDW can be obtained where TDS content is higher than 3,000 mg/L. Carbon dioxide becomes a supercritical fluid above a temperature of 88 F and a pressure of 1,074 psi. Reservoir temperature exceeds 88 F in much of the study area. Hydrostatic pressure gradients range from normal to extremely underpressured. A large area of underpressure is developed around closely spaced longwall coal mines, and areas of natural underpressure are distributed among the coalbed methane fields. The mobility and

  15. Projects Selected for Safe and Permanent Geologic Storage of Carbon Dioxide

    Broader source: Energy.gov [DOE]

    The U.S. Department of Energy announced the selection of 13 projects to develop technologies and methodologies for geologic storage of carbon dioxide.

  16. On sorption and swelling of CO2 in clays

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Busch, A.; Bertier, P.; Gensterblum, Y.; Rother, G.; Spiers, C. J.; Zhang, M.; Wentinck, H. M.

    2016-03-23

    One well-studied technology is the geological storage of carbon dioxide (CO2), and a number of demonstration projects around the world have proven its feasibility and challenges. Storage conformance and seal integrity are among the most important aspects, as they determine risk of leakage as well as limits for storage capacity and injectivity. By providing evidence for safe storage is critical for improving public acceptance. Most caprocks are composed of clays as dominant mineral type which can typically be illite, kaolinite, chlorite or smectite. A number of recent studies addressed the interaction between CO2 and these different clays and it wasmore » shown that clay minerals adsorb considerable quantities of CO2. For smectite this uptake can lead to volumetric expansion followed by the generation of swelling pressures. On the one hand CO2 adsorption traps CO2, on the other hand swelling pressures can potentially change local stress regimes and in unfavourable situations shear-type failure is assumed to occur. Moreover, for storage in a reservoir having high clay contents the CO2 uptake can add to storage capacity which is widely underestimated so far. Smectite-rich seals in direct contact with a dry CO2 plume at the interface to the reservoir might dehydrate leading to dehydration cracks. Such dehydration cracks can provide pathways for CO2 ingress and further accelerate dewatering and penetration of the seal by supercritical CO2. At the same time, swelling may also lead to the closure of fractures or the reduction of fracture apertures, thereby improving seal integrity. Finally, the goal of this communication is to theoretically evaluate and discuss these scenarios in greater detail in terms of phenomenological mechanisms, but also in terms of potential risks or benefits for carbon storage.« less

  17. Final Report on "Rising CO2 and Long-term Carbon Storage in Terrestrial Ecosystems: An Empirical Carbon Budget Validation"

    SciTech Connect (OSTI)

    J. Patrick Megonigal; Bert G. Drake

    2010-08-27

    The primary goal of this report is to report the results of Grant DE-FG02-97ER62458, which began in 1997 as Grant DOE-98-59-MP-4 funded through the TECO program. However, this project has a longer history because DOE also funded this study from its inception in 1985 through 1997. The original grant was focused on plant responses to elevated CO2 in an intact ecosystem, while the latter grant was focused on belowground responses. Here we summarize the major findings across the 25 years this study has operated, and note that the experiment will continue to run through 2020 with NSF support. The major conclusions of the study to date are: (1 Elevated CO2 stimulated plant productivity in the C3 plant community by ~30% during the 25 year study. The magnitude of the increase in productivity varied interannually and was sometime absent altogether. There is some evidence of down-regulation at the ecosystem level across the 25 year record that may be due to interactions with other factors such as sea-level rise or long-term changes in N supply; (2) Elevated CO2 stimulated C4 productivity by <10%, perhaps due to more efficient water use, but C3 plants at elevated CO2 did not displace C4 plants as predicted; (3) Increased primary production caused a general stimulation of microbial processes, but there were both increases and decreases in activity depending on the specific organisms considered. An increase in methanogenesis and methane emissions implies elevated CO2 may amplify radiative forcing in the case of wetland ecosystems; (4) Elevated CO2 stimulated soil carbon sequestration in the form of an increase in elevation. The increase in elevation is 50-100% of the increase in net ecosystem production caused by elevated CO2 (still under analysis). The increase in soil elevation suggests the elevated CO2 may have a positive outcome for the ability of coastal wetlands to persist despite accelerated sea level rise; (5) Crossing elevated CO2 with elevated N causes the elevated CO

  18. Leakage risk assessment of the In Salah CO2 storage project: Applying the Certification Framework in a dynamic context.

    SciTech Connect (OSTI)

    Oldenburg, C.M.; Jordan, P.D.; Nicot, J.-P.; Mazzoldi, A.; Gupta, A.K.; Bryant, S.L.

    2010-08-01

    The Certification Framework (CF) is a simple risk assessment approach for evaluating CO{sub 2} and brine leakage risk at geologic carbon sequestration (GCS) sites. In the In Salah CO{sub 2} storage project assessed here, five wells at Krechba produce natural gas from the Carboniferous C10.2 reservoir with 1.7-2% CO{sub 2} that is delivered to the Krechba gas processing plant, which also receives high-CO{sub 2} natural gas ({approx}10% by mole fraction) from additional deeper gas reservoirs and fields to the south. The gas processing plant strips CO{sub 2} from the natural gas that is then injected through three long horizontal wells into the water leg of the Carboniferous gas reservoir at a depth of approximately 1,800 m. This injection process has been going on successfully since 2004. The stored CO{sub 2} has been monitored over the last five years by a Joint Industry Project (JIP) - a collaboration of BP, Sonatrach, and Statoil with co-funding from US DOE and EU DG Research. Over the years the JIP has carried out extensive analyses of the Krechba system including two risk assessment efforts, one before injection started, and one carried out by URS Corporation in September 2008. The long history of injection at Krechba, and the accompanying characterization, modeling, and performance data provide a unique opportunity to test and evaluate risk assessment approaches. We apply the CF to the In Salah CO{sub 2} storage project at two different stages in the state of knowledge of the project: (1) at the pre-injection stage, using data available just prior to injection around mid-2004; and (2) after four years of injection (September 2008) to be comparable to the other risk assessments. The main risk drivers for the project are CO{sub 2} leakage into potable groundwater and into the natural gas cap. Both well leakage and fault/fracture leakage are likely under some conditions, but overall the risk is low due to ongoing mitigation and monitoring activities. Results of

  19. Methanogenic Conversion of CO2 Into CH4

    SciTech Connect (OSTI)

    Stevens, S.H., Ferry, J.G., Schoell, M.

    2012-05-06

    This SBIR project evaluated the potential to remediate geologic CO2 sequestration sites into useful methane gas fields by application of methanogenic bacteria. Such methanogens are present in a wide variety of natural environments, converting CO2 into CH4 under natural conditions. We conclude that the process is generally feasible to apply within many of the proposed CO2 storage reservoir settings. However, extensive further basic R&D still is needed to define the precise species, environments, nutrient growth accelerants, and economics of the methanogenic process. Consequently, the study team does not recommend Phase III commercial application of the technology at this early phase.

  20. In-Situ MVA of CO2 Sequestration Using Smart Field Technology

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    In-Situ MVA of CO 2 Sequestration Using Smart Field Technology Background Through its core research and development program administered by the National Energy Technology Laboratory (NETL), the U.S. Department of Energy (DOE) emphasizes monitoring, verification, and accounting (MVA), as well as computer simulation and risk assessment, of possible carbon dioxide (CO 2 ) leakage at CO 2 geologic storage sites. MVA efforts focus on the development and deployment of technologies that can provide an

  1. Geologic Carbon Dioxide Storage Field Projects Supported by DOE...

    Broader source: Energy.gov (indexed) [DOE]

    program has supported a number of projects implementing CO2 injection in the United States and other countries including, Canada, Algeria, Norway, Australia, and Germany. ...

  2. Third Carbon Sequestration Atlas Estimates Up to 5,700 Years of CO2 Storage Potential in U.S. and Portions of Canada

    Broader source: Energy.gov [DOE]

    There could be as much as 5,700 years of carbon dioxide storage potential available in geologic formations in the United States and portions of Canada, according to the latest edition of the U.S. Department of Energy’s Carbon Sequestration Atlas (Atlas III).

  3. Adapting Dry Cask Storage for Aging at a Geologic Repository

    SciTech Connect (OSTI)

    C. Sanders; D. Kimball

    2005-08-02

    A Spent Nuclear Fuel (SNF) Aging System is a crucial part of operations at the proposed Yucca Mountain repository in the United States. Incoming commercial SNF that does not meet thermal limits for emplacement will be aged on outdoor pads. U.S. Department of Energy SNF will also be managed using the Aging System. Proposed site-specific designs for the Aging System are closely based upon designs for existing dry cask storage (DCS) systems. This paper evaluates the applicability of existing DCS systems for use in the SNF Aging System at Yucca Mountain. The most important difference between existing DCS facilities and the Yucca Mountain facility is the required capacity. Existing DCS facilities typically have less than 50 casks. The current design for the aging pad at Yucca Mountain calls for a capacity of over 2,000 casks (20,000 MTHM) [1]. This unprecedented number of casks poses some unique problems. The response of DCS systems to off-normal and accident conditions needs to be re-evaluated for multiple storage casks. Dose calculations become more complicated, since doses from multiple or very long arrays of casks can dramatically increase the total boundary dose. For occupational doses, the geometry of the cask arrays and the order of loading casks must be carefully considered in order to meet ALARA goals during cask retrieval. Due to the large area of the aging pad, skyshine must also be included when calculating public and worker doses. The expected length of aging will also necessitate some design adjustments. Under 10 CFR 72.236, DCS systems are initially certified for a period of 20 years [2]. Although the Yucca Mountain facility is not intended to be a storage facility under 10 CFR 72, the operational life of the SNF Aging System is 50 years [1]. Any cask system selected for use in aging will have to be qualified to this design lifetime. These considerations are examined, and a summary is provided of the adaptations that must be made in order to use DCS

  4. Assessing the health risks of natural CO2 seeps in Italy

    SciTech Connect (OSTI)

    Roberts, J.J.; Wood, R.A.; Haszeldine, R.S.

    2011-10-04

    Industrialized societies which continue to use fossil fuel energy sources are considering adoption of Carbon Capture and Storage (CCS) technology to meet carbon emission reduction targets. Deep geological storage of CO2 onshore faces opposition regarding potential health effects of CO2 leakage from storage sites. There is no experience of commercial scale CCS with which to verify predicted risks of engineered storage failure. Studying risk from natural CO2 seeps can guide assessment of potential health risks from leaking onshore CO2 stores. Italy and Sicily are regions of intense natural CO2 degassing from surface seeps. These seeps exhibit a variety of expressions, characteristics (e.g., temperature/ flux), and location environments. Here we quantify historical fatalities from CO2 poisoning using a database of 286 natural CO2 seeps in Italy and Sicily. We find that risk of human death is strongly influenced by seep surface expression, local conditions (e.g., topography and wind speed), CO2 flux, and human behavior. Risk of accidental human death from these CO2 seeps is calculated to be 10-8 year-1 to the exposed population. This value is significantly lower than that of many socially accepted risks. Seepage from future storage sites is modeled to be less than Italian natural flux rates. With appropriate hazard management, health risks from unplanned seepage at onshore storage sites can be adequately minimized.

  5. Development of Science-Based Permitting Guidance for Geological Sequestration of CO2 in Deep Saline Aquifers Based on Modeling and Risk Assessment

    SciTech Connect (OSTI)

    Jean-Philippe Nicot; Renaud Bouroullec; Hugo Castellanos; Susan Hovorka; Srivatsan Lakshminarasimhan; Jeffrey Paine

    2006-06-30

    Underground carbon storage may become one of the solutions to address global warming. However, to have an impact, carbon storage must be done at a much larger scale than current CO{sub 2} injection operations for enhanced oil recovery. It must also include injection into saline aquifers. An important characteristic of CO{sub 2} is its strong buoyancy--storage must be guaranteed to be sufficiently permanent to satisfy the very reason that CO{sub 2} is injected. This long-term aspect (hundreds to thousands of years) is not currently captured in legislation, even if the U.S. has a relatively well-developed regulatory framework to handle carbon storage, especially in the operational short term. This report proposes a hierarchical approach to permitting in which the State/Federal Government is responsible for developing regional assessments, ranking potential sites (''General Permit'') and lessening the applicant's burden if the general area of the chosen site has been ranked more favorably. The general permit would involve determining in the regional sense structural (closed structures), stratigraphic (heterogeneity), and petrophysical (flow parameters such as residual saturation) controls on the long-term fate of geologically sequestered CO{sub 2}. The state-sponsored regional studies and the subsequent local study performed by the applicant will address the long-term risk of the particular site. It is felt that a performance-based approach rather than a prescriptive approach is the most appropriate framework in which to address public concerns. However, operational issues for each well (equivalent to the current underground injection control-UIC-program) could follow regulations currently in place. Area ranking will include an understanding of trapping modes. Capillary (due to residual saturation) and structural (due to local geological configuration) trappings are two of the four mechanisms (the other two are solubility and mineral trappings), which are the most

  6. Well blowout rates and consequences in California Oil and Gas District 4 from 1991 to 2005: Implications for geological storage of carbon dioxide

    SciTech Connect (OSTI)

    Jordan, Preston; Jordan, Preston D.; Benson, Sally M.

    2008-05-15

    Well blowout rates in oil fields undergoing thermally enhanced recovery (via steam injection) in California Oil and Gas District 4 from 1991 to 2005 were on the order of 1 per 1,000 well construction operations, 1 per 10,000 active wells per year, and 1 per 100,000 shut-in/idle and plugged/abandoned wells per year. This allows some initial inferences about leakage of CO2 via wells, which is considered perhaps the greatest leakage risk for geological storage of CO2. During the study period, 9% of the oil produced in the United States was from District 4, and 59% of this production was via thermally enhanced recovery. There was only one possible blowout from an unknown or poorly located well, despite over a century of well drilling and production activities in the district. The blowout rate declined dramatically during the study period, most likely as a result of increasing experience, improved technology, and/or changes in safety culture. If so, this decline indicates the blowout rate in CO2-storage fields can be significantly minimized both initially and with increasing experience over time. Comparable studies should be conducted in other areas. These studies would be particularly valuable in regions with CO2-enhanced oil recovery (EOR) and natural gas storage.

  7. Observational evidence confirms modelling of the long-term integrity of CO2-reservoir caprocks

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Kampman, N.; Busch, A.; Bertier, P.; Snippe, J.; Hangx, S.; Pipich, V.; Di, Z.; Rother, G.; Harrington, J. F.; Evans, J. P.; et al

    2016-07-28

    Storage of anthropogenic CO2 in geological formations relies on a caprock as the primary seal preventing buoyant super-critical CO2 escaping. Although natural CO2 reservoirs demonstrate that CO2 may be stored safely for millions of years, uncertainty remains in predicting how caprocks will react with CO2-bearing brines. The resulting uncertainty poses a significant challenge to the risk assessment of geological carbon storage. We describe mineral reaction fronts in a CO2 reservoir-caprock system exposed to CO2 over a timescale comparable with that needed for geological carbon storage. Moreover, the propagation of the reaction front is retarded by redox-sensitive mineral dissolution reactions andmore » carbonate precipitation, which reduces its penetration into the caprock to ~7 cm in ~105 years. This distance is an order-of-magnitude smaller than previous predictions. The results attest to the significance of transport-limited reactions to the long-term integrity of sealing behaviour in caprocks exposed to CO2.« less

  8. storage | netl.doe.gov

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Geologic Storage Technologies & Simulation & Risk Assessment The Carbon Storage Program's Geologic Storage and Simulation and Risk Assessment (GSRA) Technology Area supports research to develop technologies that can improve containment and injection operations, increase reservoir storage efficiency, and prevent and mitigate unwanted migration of CO2 in all types of storage formations. Research conducted in the near and long term will augment existing technologies to ensure permanent

  9. DOE Regional Partnership Successfully Demonstrates Terrestrial CO2 Storage Practices in Great Plains Region of U.S. and Canada

    Broader source: Energy.gov [DOE]

    A field test demonstrating the best approaches for terrestrial carbon dioxide storage in the heartland of North America has been successfully completed by one of the U.S. Department of Energy's seven Regional Carbon Sequestration Partnerships.

  10. Comparison of methods for geologic storage of carbon dioxide...

    Office of Scientific and Technical Information (OSTI)

    United States Geological Survey (Brennan et al., 2010); ... generated by multiple methods revealed that assessments ... Research Org: National Energy Technology Laboratory - ...

  11. A method for quick assessment of CO2 storage capacity in closedand semi-closed saline formations

    SciTech Connect (OSTI)

    Zhou, Q.; Birkholzer, J.; Tsang, C.F.; Rutqvist, J.

    2008-02-10

    Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO{sub 2}) injection into and storage in such 'closed' systems with impervious seals, or 'semi-closed' systems with nonideal (low-permeability) seals, is different from that in 'open' systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO{sub 2} injection may have a limiting effect on CO{sub 2} storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO{sub 2} storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO{sub 2} occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With nonideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO{sub 2} storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the 'true' values obtained using detailed numerical simulations of CO{sub 2} and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage-formation-seal systems of various geometric and hydrogeological properties.

  12. DOE Seeks Applications for Tracking Carbon Dioxide Storage in Geologic Formations

    Office of Energy Efficiency and Renewable Energy (EERE)

    The U.S. Department of Energy today issued a Funding Opportunity Announcement (FOA) to enhance the capability to simulate, track, and evaluate the potential risks of carbon dioxide storage in geologic formations.

  13. DOE Investing $11.5 Million to Advance Geologic Carbon Storage and

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Geothermal Exploration | Department of Energy DOE Investing $11.5 Million to Advance Geologic Carbon Storage and Geothermal Exploration DOE Investing $11.5 Million to Advance Geologic Carbon Storage and Geothermal Exploration July 27, 2016 - 10:15am Addthis WASHINGTON - The The U.S. Department of Energy (DOE) has announced the selection of eight new research and development projects to receive a total of $11.5 million in federal funding under DOE's Subsurface Technology and Engineering

  14. SIMULATION FRAMEWORK FOR REGIONAL GEOLOGIC CO{sub 2} STORAGE ALONG ARCHES PROVINCE OF MIDWESTERN UNITED STATES

    SciTech Connect (OSTI)

    Sminchak, Joel

    2012-09-30

    were corrected in locations where reservoir tests have been performed in Mount Simon injection wells. The geocellular model was used to develop a series of numerical simulations designed to support CO2 storage applications in the Arches Province. Variable density fluid flow simulations were initially run to evaluate model sensitivity to input parameters. Two dimensional, multiple-phase simulations were completed to evaluate issues related to arranging injection fields in the study area. A basin-scale, multiple-phase model was developed to evaluate large scale injection effects across the region. Finally, local scale simulations were also completed with more detailed depiction of the Eau Claire formation to investigate to the potential for upward migration of CO2. Overall, the technical work on the project concluded that injection large-scale injection may be achieved with proper field design, operation, siting, and monitoring. Records from Mount Simon injection wells were compiled, documenting more than 20 billion gallons of injection into the Mount Simon formation in the Arches Province over the past 40 years, equivalent to approximately 60 million metric tons CO2. The multi-state team effort was useful in delineating the geographic variability in the Mount Simon reservoir properties. Simulations better defined potential well fields, well field arrangement, CO2 pipeline distribution system, and operational parameters for large-scale injection in the Arches Province. Multiphase scoping level simulations suggest that injection fields with arrays of 9 to 50+ wells may be used to accommodate large injection volumes. Individual wells may need to be separated by 3 to 10 km. Injection fields may require spacing of 25 to 40 km to limit pressure and saturation front interference. Basin-scale multiple-phase simulations in STOMP reflect variability in the Mount Simon. While simulations suggest a total injection rate of 100 million metric tons per year (approximately to a 40

  15. DOE Regional Partnership Initiates CO2 Injection in Lignite Coal Seam |

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Department of Energy Initiates CO2 Injection in Lignite Coal Seam DOE Regional Partnership Initiates CO2 Injection in Lignite Coal Seam March 10, 2009 - 1:00pm Addthis Washington, DC -- A U.S. Department of Energy/National Energy Technology Laboratory (NETL) team of regional partners has begun injecting CO2 into a deep lignite coal seam in Burke County, North Dakota, to demonstrate the economic and environmental viability of geologic CO2 storage in the U.S. Great Plains region. Ultimately,

  16. Geological and Geotechnical Site Investigation for the Design of a CO2 Rich Flue Gas Direct Injection and Storage Facility

    SciTech Connect (OSTI)

    Metz, Paul; Bolz, Patricia

    2013-03-25

    With international efforts to limit anthropogenic carbon in the atmosphere, various CO{sub 2} sequestration methods have been studied by various facilities worldwide. Basalt rock in general has been referred to as potential host material for mineral carbonation by various authors, without much regard for compositional variations due to depositional environment, subsequent metamorphism, or hydrothermal alteration. Since mineral carbonation relies on the presence of certain magnesium, calcium, or iron silicates, it is necessary to study the texture, mineralogy, petrology, and geochemistry of specific basalts before implying potential for mineral carbonation. The development of a methodology for the characterization of basalts with respect to their susceptibility for mineral carbonation is proposed to be developed as part of this research. The methodology will be developed based on whole rock data, petrography and microprobe analyses for samples from the Caledonia Mine in Michigan, which is the site for a proposed small-scale demonstration project on mineral carbonation in basalt. Samples from the Keweenaw Peninsula will be used to determine general compositional trends using whole rock data and petrography. Basalts in the Keweenaw Peninsula have been subjected to zeolite and prehnite-pumpellyite facies metamorphism with concurrent native copper deposition. Alteration was likely due to the circulation of CO{sub 2}-rich fluids at slightly elevated temperatures and pressures, which is the process that is attempted to be duplicated by mineral carbonation.

  17. Prospective life-cycle modeling of a carbon capture and storage system using metal-organic frameworks for CO2 capture

    SciTech Connect (OSTI)

    Sathre, R; Masanet, E

    2013-01-01

    Metal-organic frameworks (MOFs) are promising new material media for carbon dioxide (CO2) capture. Their tunable adsorption patterns may allow relatively efficient separation of gases, e.g. from power plant exhaust. Here we conduct scenario-based prospective life-cycle system modeling to estimate the potentials and implications of large-scale MOF application for post-combustion carbon capture and storage (CCS), and estimate the source and magnitude of uncertainties. The methodological approach includes parametric system modeling to quantify relations between system components; scenario projections of plausible pathways for system scale-up; proxy data on analogous materials and processes; and uncertainty analysis of parameter significance. We estimate the system-wide material and energy flows and economic costs associated with projected large-scale CCS deployment. We compare the performance of a MOF-based system to currently more mature amine-based capture technology. We discuss balancing two critical factors that determine the success of CO2 capture media: thermodynamic efficiency of the capture/regeneration cycle, and life-cycle embodied energy and cost of the material and its ancillary systems.

  18. Natural and industrial analogues for leakage of CO2 from storagereservoirs: identification of features, events, and processes and lessonslearned

    SciTech Connect (OSTI)

    Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

    2006-02-28

    The injection and storage of anthropogenic CO2 in deepgeologic formations is a potentially feasible strategy to reduce CO2emissions and atmospheric concentrations. While the purpose of geologiccarbon storage is to trap CO2 underground, CO2 could migrate away fromthe storage site into the shallow subsurface and atmosphere if permeablepathways such as well bores or faults are present. Large-magnitudereleases of CO2 have occurred naturally from geologic reservoirs innumerous volcanic, geothermal, and sedimentary basin settings. Carbondioxide and natural gas have also been released from geologic CO2reservoirs and natural gas storage facilities, respectively, due toinfluences such as well defects and injection/withdrawal processes. Thesesystems serve as natural and industrial analogues for the potentialrelease of CO2 from geologic storage reservoirs and provide importantinformation about the key features, events, and processes (FEPs) that areassociated with releases, as well as the health, safety, andenvironmental consequences of releases and mitigation efforts that can beapplied. We describe a range of natural releases of CO2 and industrialreleases of CO2 and natural gas in the context of these characteristics.Based on this analysis, several key conclusions can be drawn, and lessonscan be learned for geologic carbon storage. First, CO2 can bothaccumulate beneath, and be released from, primary and secondaryreservoirs with capping units located at a wide range of depths. Bothprimary and secondary reservoir entrapments for CO2 should therefore bewell characterized at storage sites. Second, many natural releases of CO2have been correlated with a specific event that triggered the release,such as magmatic fluid intrusion or seismic activity. The potential forprocesses that could cause geomechanical damage to sealing cap rocks andtrigger the release of CO2 from a storage reservoir should be evaluated.Third, unsealed fault and fracture zones may act as fast and directconduits

  19. Brine flow up a borehole caused by pressure perturbation from CO2 storage: Static and dynamic evaluations

    SciTech Connect (OSTI)

    Birkholzer, J.T.; Nicot, J.-P.; Oldenburg, C.M.; Zhou, Q.; Kraemer, S.; Bandilla, K.W.

    2011-05-01

    Industrial-scale storage of CO{sub 2} in saline sedimentary basins will cause zones of elevated pressure, larger than the CO{sub 2} plume itself. If permeable conduits (e.g., leaking wells) exist between the injection reservoir and overlying shallow aquifers, brine could be pushed upwards along these conduits and mix with groundwater resources. This paper discusses the potential for such brine leakage to occur in temperature- and salinity-stratified systems. Using static mass-balance calculations as well as dynamic well flow simulations, we evaluate the minimum reservoir pressure that would generate continuous migration of brine up a leaking wellbore into a freshwater aquifer. Since the brine invading the well is denser than the initial fluid in the wellbore, continuous flow only occurs if the pressure perturbation in the reservoir is large enough to overcome the increased fluid column weight after full invasion of brine into the well. If the threshold pressure is exceeded, brine flow rates are dependent on various hydraulic (and other) properties, in particular the effective permeability of the wellbore and the magnitude of pressure increase. If brine flow occurs outside of the well casing, e.g., in a permeable fracture zone between the well cement and the formation, the fluid/solute transfer between the migrating fluid and the surrounding rock units can strongly retard brine flow. At the same time, the threshold pressure for continuous flow to occur decreases compared to a case with no fluid/solute transfer.

  20. The scientific case for large CO2 storage projects worldwide: Where they should go, what they should look like, and how much they should cost

    SciTech Connect (OSTI)

    Friedmann, S J

    2006-04-21

    To achieve substantial GHG reductions through carbon capture and storage (CCS) requires 100's to 1000's of large volume injection facilities distributed globally with very low rates and volumes of leakage. Several large-scale projects exist (Weyburn, Sleipner, In-Salah) and each has revealed an important aspect of the geology that was not previously known. This reaffirms the notion that key geological thresholds in the earth's crust are sensitive to the magnitude and rate of excursions, (e.g., pressure build-up, pH). Because commercial-scale CCS will reach these thresholds, a suite of large-scale projects is needed to investigate the conditions for successful deployment. These projects must cover a range of geological and geographic settings and key plays. Moreover, they must be supported by a sufficiently large science and technology program to understand the key features, events, and processes in each case to address stakeholder concerns and develop operational guidelines for large-scale deployment.

  1. A life cycle cost analysis framework for geologic storage of hydrogen : a scenario analysis.

    SciTech Connect (OSTI)

    Kobos, Peter Holmes; Lord, Anna Snider; Borns, David James

    2010-10-01

    The U.S. Department of Energy has an interest in large scale hydrogen geostorage, which would offer substantial buffer capacity to meet possible disruptions in supply. Geostorage options being considered are salt caverns, depleted oil/gas reservoirs, aquifers and potentially hard rock cavrns. DOE has an interest in assessing the geological, geomechanical and economic viability for these types of hydrogen storage options. This study has developed an ecocomic analysis methodology to address costs entailed in developing and operating an underground geologic storage facility. This year the tool was updated specifically to (1) a version that is fully arrayed such that all four types of geologic storage options can be assessed at the same time, (2) incorporate specific scenarios illustrating the model's capability, and (3) incorporate more accurate model input assumptions for the wells and storage site modules. Drawing from the knowledge gained in the underground large scale geostorage options for natural gas and petroleum in the U.S. and from the potential to store relatively large volumes of CO{sub 2} in geological formations, the hydrogen storage assessment modeling will continue to build on these strengths while maintaining modeling transparency such that other modeling efforts may draw from this project.

  2. A life cycle cost analysis framework for geologic storage of hydrogen : a user's tool.

    SciTech Connect (OSTI)

    Kobos, Peter Holmes; Lord, Anna Snider; Borns, David James; Klise, Geoffrey T.

    2011-09-01

    The U.S. Department of Energy (DOE) has an interest in large scale hydrogen geostorage, which could offer substantial buffer capacity to meet possible disruptions in supply or changing seasonal demands. The geostorage site options being considered are salt caverns, depleted oil/gas reservoirs, aquifers and hard rock caverns. The DOE has an interest in assessing the geological, geomechanical and economic viability for these types of geologic hydrogen storage options. This study has developed an economic analysis methodology and subsequent spreadsheet analysis to address costs entailed in developing and operating an underground geologic storage facility. This year the tool was updated specifically to (1) incorporate more site-specific model input assumptions for the wells and storage site modules, (2) develop a version that matches the general format of the HDSAM model developed and maintained by Argonne National Laboratory, and (3) incorporate specific demand scenarios illustrating the model's capability. Four general types of underground storage were analyzed: salt caverns, depleted oil/gas reservoirs, aquifers, and hard rock caverns/other custom sites. Due to the substantial lessons learned from the geological storage of natural gas already employed, these options present a potentially sizable storage option. Understanding and including these various geologic storage types in the analysis physical and economic framework will help identify what geologic option would be best suited for the storage of hydrogen. It is important to note, however, that existing natural gas options may not translate to a hydrogen system where substantial engineering obstacles may be encountered. There are only three locations worldwide that currently store hydrogen underground and they are all in salt caverns. Two locations are in the U.S. (Texas), and are managed by ConocoPhillips and Praxair (Leighty, 2007). The third is in Teeside, U.K., managed by Sabic Petrochemicals (Crotogino et

  3. Geological Carbon Sequestration Storage Resource Estimates for the Ordovician St. Peter Sandstone, Illinois and Michigan Basins, USA

    SciTech Connect (OSTI)

    Barnes, David; Ellett, Kevin; Leetaru, Hannes

    2014-09-30

    The Cambro-Ordovician strata of the Midwest of the United States is a primary target for potential geological storage of CO2 in deep saline formations. The objective of this project is to develop a comprehensive evaluation of the Cambro-Ordovician strata in the Illinois and Michigan Basins above the basal Mount Simon Sandstone since the Mount Simon is the subject of other investigations including a demonstration-scale injection at the Illinois Basin Decatur Project. The primary reservoir targets investigated in this study are the middle Ordovician St Peter Sandstone and the late Cambrian to early Ordovician Knox Group carbonates. The topic of this report is a regional-scale evaluation of the geologic storage resource potential of the St Peter Sandstone in both the Illinois and Michigan Basins. Multiple deterministic-based approaches were used in conjunction with the probabilistic-based storage efficiency factors published in the DOE methodology to estimate the carbon storage resource of the formation. Extensive data sets of core analyses and wireline logs were compiled to develop the necessary inputs for volumetric calculations. Results demonstrate how the range in uncertainty of storage resource estimates varies as a function of data availability and quality, and the underlying assumptions used in the different approaches. In the simplest approach, storage resource estimates were calculated from mapping the gross thickness of the formation and applying a single estimate of the effective mean porosity of the formation. Results from this approach led to storage resource estimates ranging from 3.3 to 35.1 Gt in the Michigan Basin, and 1.0 to 11.0 Gt in the Illinois Basin at the P10 and P90 probability level, respectively. The second approach involved consideration of the diagenetic history of the formation throughout the two basins and used depth-dependent functions of porosity to derive a more realistic spatially variable model of porosity rather than applying a

  4. Supercritical CO2-Brayton Cycle

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Supercritical CO2-Brayton Cycle - Sandia Energy Energy Search Icon Sandia Home Locations Contact Us Employee Locator Energy & Climate Secure & Sustainable Energy Future Stationary Power Energy Conversion Efficiency Solar Energy Wind Energy Water Power Supercritical CO2 Geothermal Natural Gas Safety, Security & Resilience of the Energy Infrastructure Energy Storage Nuclear Power & Engineering Grid Modernization Battery Testing Nuclear Energy Defense Waste Management Programs

  5. Carbon Storage R&D | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    R&D Carbon Storage R&D Carbon dioxide storage in geologic formations includes oil and gas reservoirs, unmineable coal seams, and deep saline reservoirs. These are structures that have stored crude oil, natural gas, brine and CO2 over millions of years. The primary goal of our carbon storage research is to understand the behavior of CO2 when stored in geologic formations. For example, studies are being conducted to determine the extent to which the CO2 moves within the geologic formation,

  6. Advanced Technologies for Monitoring CO2 Saturation and Pore Pressure in Geologic Formations: Linking the Chemical and Physical Effects to Elastic and Transport Properties

    SciTech Connect (OSTI)

    Mavko, G.; Vanorio, T.; Vialle, S.; Saxena, N.

    2014-03-31

    Ultrasonic P- and S-wave velocities were measured over a range of confining pressures while injecting CO2 and brine into the samples. Pore fluid pressure was also varied and monitored together with porosity during injection. Effective medium models were developed to understand the mechanisms and impact of observed changes and to provide the means for implementation of the interpretation methodologies in the field. Ultrasonic P- and S-wave velocities in carbonate rocks show as much as 20-50% decrease after injection of the reactive CO2-brine mixture; the changes were caused by permanent changes to the rock elastic frame associated with dissolution of mineral. Velocity decreases were observed under both dry and fluid-saturated conditions, and the amount of change was correlated with the initial pore fabrics. Scanning Electron Microscope images of carbonate rock microstructures were taken before and after injection of CO2-rich water. The images reveal enlargement of the pores, dissolution of micrite (micron-scale calcite crystals), and pitting of grain surfaces caused by the fluid- solid chemical reactivity. The magnitude of the changes correlates with the rock microtexture – tight, high surface area samples showed the largest changes in permeability and smallest changes in porosity and elastic stiffness compared to those in rocks with looser texture and larger intergranular pore space. Changes to the pore space also occurred from flow of fine particles with the injected fluid. Carbonates with grain-coating materials, such as residual oil, experienced very little permanent change during injection. In the tight micrite/spar cement component, dissolution is controlled by diffusion: the mass transfer of products and reactants is thus slow and the fluid is expected to be close to thermodynamical equilibrium with the calcite, leading to very little dissolution, or even precipitation. In the microporous rounded micrite and macropores, dissolution is controlled by

  7. TIME-LAPSE SEISMIC MODELING & INVERSION OF CO2 SATURATION FOR SEQUESTRATION AND ENHANCED OIL RECOVERY

    SciTech Connect (OSTI)

    Mark A. Meadows

    2006-03-31

    Injection of carbon dioxide (CO2) into subsurface aquifers for geologic storage/sequestration, and into subsurface hydrocarbon reservoirs for enhanced oil recovery, has become an important topic to the nation because of growing concerns related to global warming and energy security. In this project we developed new ways to predict and quantify the effects of CO2 on seismic data recorded over porous reservoir/aquifer rock systems. This effort involved the research and development of new technology to: (1) Quantitatively model the rock physics effects of CO2 injection in porous saline and oil/brine reservoirs (both miscible and immiscible). (2) Quantitatively model the seismic response to CO2 injection (both miscible and immiscible) from well logs (1D). (3) Perform quantitative inversions of time-lapse 4D seismic data to estimate injected CO2 distributions within subsurface reservoirs and aquifers. This work has resulted in an improved ability to remotely monitor the injected CO2 for safe storage and enhanced hydrocarbon recovery, predict the effects of CO2 on time-lapse seismic data, and estimate injected CO2 saturation distributions in subsurface aquifers/reservoirs. We applied our inversion methodology to a 3D time-lapse seismic dataset from the Sleipner CO2 sequestration project, Norwegian North Sea. We measured changes in the seismic amplitude and traveltime at the top of the Sleipner sandstone reservoir and used these time-lapse seismic attributes in the inversion. Maps of CO2 thickness and its standard deviation were generated for the topmost layer. From this information, we estimated that 7.4% of the total CO2 injected over a five-year period had reached the top of the reservoir. This inversion approach could also be applied to the remaining levels within the anomalous zone to obtain an estimate of the total CO2 injected.

  8. Elucidating geochemical response of shallow heterogeneous aquifers to CO2 leakage using high-performance computing: Implications for monitoring of CO2 sequestration

    SciTech Connect (OSTI)

    Navarre-Sitchler, Alexis K.; Maxwell, Reed M.; Siirila, Erica R.; Hammond, Glenn E.; Lichtner, Peter C.

    2013-03-01

    Predicting and quantifying impacts of potential carbon dioxide (CO2) leakage into shallow aquifers that overlie geologic CO2 storage formations is an important part of developing reliable carbon storage techniques. Leakage of CO2 through fractures, faults or faulty wellbores can reduce groundwater pH, inducing geochemical reactions that release solutes into the groundwater and pose a risk of degrading groundwater quality. In order to help quantify this risk, predictions of metal concentrations are needed during geologic storage of CO2. Here, we present regional-scale reactive transport simulations, at relatively fine-scale, of CO2 leakage into shallow aquifers run on the PFLOTRAN platform using high-performance computing. Multiple realizations of heterogeneous permeability distributions were generated using standard geostatistical methods. Increased statistical anisotropy of the permeability field resulted in more lateral and vertical spreading of the plume of impacted water, leading to increased Pb2+ (lead) concentrations and lower pH at a well down gradient of the CO2 leak. Pb2+ concentrations were higher in simulations where calcite was the source of Pb2+ compared to galena. The low solubility of galena effectively buffered the Pb2+ concentrations as galena reached saturation under reducing conditions along the flow path. In all cases, Pb2+ concentrations remained below the maximum contaminant level set by the EPA. Results from this study, compared to natural variability observed in aquifers, suggest that bicarbonate (HCO3) concentrations may be a better geochemical indicator of a CO2 leak under the conditions simulated here.

  9. SIMULATION FRAMEWORK FOR REGIONAL GEOLOGIC CO{sub 2} STORAGE ALONG ARCHES PROVINCE OF MIDWESTERN UNITED STATES

    SciTech Connect (OSTI)

    Sminchak, Joel

    2012-09-30

    were corrected in locations where reservoir tests have been performed in Mount Simon injection wells. The geocellular model was used to develop a series of numerical simulations designed to support CO{sub 2} storage applications in the Arches Province. Variable density fluid flow simulations were initially run to evaluate model sensitivity to input parameters. Two dimensional, multiple-phase simulations were completed to evaluate issues related to arranging injection fields in the study area. A basin-scale, multiple-phase model was developed to evaluate large scale injection effects across the region. Finally, local scale simulations were also completed with more detailed depiction of the Eau Claire formation to investigate to the potential for upward migration of CO{sub 2}. Overall, the technical work on the project concluded that injection large-scale injection may be achieved with proper field design, operation, siting, and monitoring. Records from Mount Simon injection wells were compiled, documenting more than 20 billion gallons of injection into the Mount Simon formation in the Arches Province over the past 40 years, equivalent to approximately 60 million metric tons CO2. The multi-state team effort was useful in delineating the geographic variability in the Mount Simon reservoir properties. Simulations better defined potential well fields, well field arrangement, CO{sub 2} pipeline distribution system, and operational parameters for large-scale injection in the Arches Province. Multiphase scoping level simulations suggest that injection fields with arrays of 9 to 50+ wells may be used to accommodate large injection volumes. Individual wells may need to be separated by 3 to 10 km. Injection fields may require spacing of 25 to 40 km to limit pressure and saturation front interference. Basin-scale multiple-phase simulations in STOMP reflect variability in the Mount Simon. While simulations suggest a total injection rate of 100 million metric tons per year

  10. Risk Assessment and Monitoring of Stored CO2 in Organic Rocks Under Non-Equilibrium Conditions

    SciTech Connect (OSTI)

    Malhotra, Vivak

    2014-06-30

    The USA is embarking upon tackling the serious environmental challenges posed to the world by greenhouse gases, especially carbon dioxide (CO2). The dimension of the problem is daunting. In fact, according to the Energy Information Agency, nearly 6 billion metric tons of CO2 were produced in the USA in 2007 with coal-burning power plants contributing about 2 billion metric tons. To mitigate the concerns associated with CO2 emission, geological sequestration holds promise. Among the potential geological storage sites, unmineable coal seams and shale formations in particular show promise because of the probability of methane recovery while sequestering the CO2. However. the success of large-scale sequestration of CO2 in coal and shale would hinge on a thorough understanding of CO2's interactions with host reservoirs. An important parameter for successful storage of CO2 reservoirs would be whether the pressurized CO2 would remain invariant in coal and shale formations under reasonable internal and/or external perturbations. Recent research has brought to the fore the potential of induced seismicity, which may result in caprock compromise. Therefore, to evaluate the potential risks involved in sequestering CO2 in Illinois bituminous coal seams and shale, we studied: (i) the mechanical behavior of Murphysboro (Illinois) and Houchin Creek (Illinois) coals, (ii) thermodynamic behavior of Illinois bituminous coal at - 100oC ≤ T ≤ 300oC, (iii) how high pressure CO2 (up to 20.7 MPa) modifies the viscosity of the host, (iv) the rate of emission of CO2 from Illinois bituminous coal and shale cores if the cores, which were pressurized with high pressure (≤ 20.7 MPa) CO2, were exposed to an atmospheric pressure, simulating the development of leakage pathways, (v) whether there are any fractions of CO2 stored in these hosts which are resistance to emission by simply exposing the cores to atmospheric pressure, and (vi) how compressive shockwaves applied to the coal and shale

  11. FT-IR study of CO2 interaction with Na-rich montmorillonite

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Krukowski, Elizabeth G.; Goodman, Angela; Rother, Gernot; Ilton, Eugene S.; Guthrie, George; Bodnar, Robert J.

    2015-05-27

    Here, carbon capture, utilization and storage (CCUS) in saline reservoirs in sedimentary formations has the potential to reduce the impact of fossil fuel combustion on climate change by reducing CO2 emissions to the atmosphere and storing the CO2 in geologic formations in perpetuity. At pressure and temperature (PT) conditions relevant to CCUS, CO2 is less dense than the pre-existing brine in the formation, and the more buoyant CO2 will migrate to the top of the formation where it will be in contact with cap rock. Interactions between clay-rich shale cap rocks and CO2 are poorly understood at PT conditions appropriatemore » for CCUS in saline formations. In this study, the interaction of CO2 with clay minerals in the cap rock overlying a saline formation has been examined using Na+ exchanged montmorillonite (Mt) (Na+-STx-1) (Na+ Mt) as an analog for clay-rich shale. Attenuated Total Reflectance-Fourier Transform Infrared Spectroscopy (ATR-FTIR) was used to discern mechanistic information for CO2 interaction with hydrated (both one- and two-water layers) and relatively dehydrated (both dehydrated layers and one-water layers) Na+-STx-1 at 35 °C and 50 C and CO2 pressure from 0 5.9 MPa. CO2-induced perturbations associated with the water layer and Na+-STx-1 vibrational modes such as AlAlOH and AlMgOH were examined. Data indicate that CO2 is preferentially incorporated into the interlayer space, with relatively dehydrated Na+-STx-1 capable of incorporating more CO2 compared to hydrated Na+-STx-1. Spectroscopic data provide no evidence of formation of carbonate minerals or the interaction of CO2 with sodium cations in the Na+-STx-1 structure.« less

  12. A Review of the CO2 Pipeline Infrastructure in the U.S.

    Broader source: Energy.gov [DOE]

    This paper provides summary descriptions of the U.S. carbon dioxide (CO2) pipeline system and future scenarios for expansion. Spanning across more than a dozen U.S. states and into Canada, a safe and regionally extensive network of pipelines has been constructed over the past four decades. These pipelines represent an essential building block for linking the capture of CO2 from electric power plants and other industrial sources with its productive use in oilfields and its safe storage in saline formations. The vast majority of the CO2 pipeline system is dedicated to CO2- Enhanced Oil Recovery (EOR), connecting natural and industrial sources of CO2 with EOR projects in oil fields. Roughly 80 percent of CO2 traveling through U.S. pipelines is from natural (geologic) sources; however, if currently planned industrial CO2 capture facilities and new pipelines are built, by 2020 the portion of CO2 from industrial sources could nearly match the portion from natural sources. A national carbon policy could significantly increase the scale of CO2 infrastructure by creating incentives for electric power plants and other industrial facilities to reduce CO2 emissions through carbon capture technologies and improving the economics for oil production through EOR. Low-carbon cases modeled for this report project that construction through 2030 could more than triple the size of current U.S. CO2 pipeline infrastructure. The development of an expanded national CO2 pipeline network capable of meeting U.S. GHG emission goals may require regulatory changes, incentives and a more concerted federal policy, involving closer cooperation among federal, state, and local governments.

  13. "Applications and future trends in polymer materials for green energy systems: from energy generation and storage, to CO2 capture and transportaion"

    SciTech Connect (OSTI)

    George Zafiris

    2010-08-24

    Presentation describes United Technologies Research Center's recent work in green energy systems, including APRA-E project content to create a synthetic analogue of the carbonic anhydrase enzyme and incorporate it into a membrane for CO2 separation from the flue gas of a coal power plant.

  14. Improved understanding of geologic CO{sub 2} storage processes requires risk-driven field experiments

    SciTech Connect (OSTI)

    Oldenburg, C.M.

    2011-06-01

    The need for risk-driven field experiments for CO{sub 2} geologic storage processes to complement ongoing pilot-scale demonstrations is discussed. These risk-driven field experiments would be aimed at understanding the circumstances under which things can go wrong with a CO{sub 2} capture and storage (CCS) project and cause it to fail, as distinguished from accomplishing this end using demonstration and industrial scale sites. Such risk-driven tests would complement risk-assessment efforts that have already been carried out by providing opportunities to validate risk models. In addition to experimenting with high-risk scenarios, these controlled field experiments could help validate monitoring approaches to improve performance assessment and guide development of mitigation strategies.

  15. Overview of geologic storage of natural gas with an emphasis on assessing the feasibility of storing hydrogen.

    SciTech Connect (OSTI)

    Lord, Anna Snider

    2009-09-01

    In many regions across the nation geologic formations are currently being used to store natural gas underground. Storage options are dictated by the regional geology and the operational need. The U.S. Department of Energy (DOE) has an interest in understanding theses various geologic storage options, the advantages and disadvantages, in the hopes of developing an underground facility for the storage of hydrogen as a low cost storage option, as part of the hydrogen delivery infrastructure. Currently, depleted gas/oil reservoirs, aquifers, and salt caverns are the three main types of underground natural gas storage in use today. The other storage options available currently and in the near future, such as abandoned coal mines, lined hard rock caverns, and refrigerated mined caverns, will become more popular as the demand for natural gas storage grows, especially in regions were depleted reservoirs, aquifers, and salt deposits are not available. The storage of hydrogen within the same type of facilities, currently used for natural gas, may add new operational challenges to the existing cavern storage industry, such as the loss of hydrogen through chemical reactions and the occurrence of hydrogen embrittlement. Currently there are only three locations worldwide, two of which are in the United States, which store hydrogen. All three sites store hydrogen within salt caverns.

  16. Two-phase convective CO2 dissolution in saline aquifers

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Martinez, Mario J.; Hesse, Marc A.

    2016-01-01

    Geologic carbon storage in deep saline aquifers is a promising technology for reducing anthropogenic emissions into the atmosphere. Dissolution of injected CO2 into resident brines is one of the primary trapping mechanisms generally considered necessary to provide long-term storage security. Given that diffusion of CO2 in brine is woefully slow, convective dissolution, driven by a small increase in brine density with CO2 saturation, is considered to be the primary mechanism of dissolution trapping. Previous studies of convective dissolution have typically only considered the convective process in the single-phase region below the capillary transition zone and have either ignored the overlyingmore » two-phase region where dissolution actually takes place or replaced it with a virtual region with reduced or enhanced constant permeability. Our objective is to improve estimates of the long-term dissolution flux of CO2 into brine by including the capillary transition zone in two-phase model simulations. In the fully two-phase model, there is a capillary transition zone above the brine-saturated region over which the brine saturation decreases with increasing elevation. Our two-phase simulations show that the dissolution flux obtained by assuming a brine-saturated, single-phase porous region with a closed upper boundary is recovered in the limit of vanishing entry pressure and capillary transition zone. For typical finite entry pressures and capillary transition zone, however, convection currents penetrate into the two-phase region. As a result, this removes the mass transfer limitation of the diffusive boundary layer and enhances the convective dissolution flux of CO2 more than 3 times above the rate assuming single-phase conditions.« less

  17. An Assessment of Geological Carbon Storage Options in the Illinois Basin: Validation Phase

    SciTech Connect (OSTI)

    Finley, Robert

    2012-12-01

    The Midwest Geological Sequestration Consortium (MGSC) assessed the options for geological carbon dioxide (CO{sub 2}) storage in the 155,400 km{sup 2} (60,000 mi{sup 2}) Illinois Basin, which underlies most of Illinois, western Indiana, and western Kentucky. The region has annual CO{sub 2} emissions of about 265 million metric tonnes (292 million tons), primarily from 122 coal-fired electric generation facilities, some of which burn almost 4.5 million tonnes (5 million tons) of coal per year (U.S. Department of Energy, 2010). Validation Phase (Phase II) field tests gathered pilot data to update the Characterization Phase (Phase I) assessment of options for capture, transportation, and storage of CO{sub 2} emissions in three geological sink types: coal seams, oil fields, and saline reservoirs. Four small-scale field tests were conducted to determine the properties of rock units that control injectivity of CO{sub 2}, assess the total storage resources, examine the security of the overlying rock units that act as seals for the reservoirs, and develop ways to control and measure the safety of injection and storage processes. The MGSC designed field test operational plans for pilot sites based on the site screening process, MVA program needs, the selection of equipment related to CO{sub 2} injection, and design of a data acquisition system. Reservoir modeling, computational simulations, and statistical methods assessed and interpreted data gathered from the field tests. Monitoring, Verification, and Accounting (MVA) programs were established to detect leakage of injected CO{sub 2} and ensure public safety. Public outreach and education remained an important part of the project; meetings and presentations informed public and private regional stakeholders of the results and findings. A miscible (liquid) CO{sub 2} flood pilot project was conducted in the Clore Formation sandstone (Mississippian System, Chesterian Series) at Mumford Hills Field in Posey County, southwestern

  18. Thermodynamic Data for Geochemical Modeling of Carbonate Reactions Associated with CO2 Sequestration – Literature Review

    SciTech Connect (OSTI)

    Krupka, Kenneth M.; Cantrell, Kirk J.; McGrail, B. Peter

    2010-09-28

    Permanent storage of anthropogenic CO2 in deep geologic formations is being considered as a means to reduce the concentration of atmospheric CO2 and thus its contribution to global climate change. To ensure safe and effective geologic sequestration, numerous studies have been completed of the extent to which the CO2 migrates within geologic formations and what physical and geochemical changes occur in these formations when CO2 is injected. Sophisticated, computerized reservoir simulations are used as part of field site and laboratory CO2 sequestration studies. These simulations use coupled multiphase flow-reactive chemical transport models and/or standalone (i.e., no coupled fluid transport) geochemical models to calculate gas solubility, aqueous complexation, reduction/oxidation (redox), and/or mineral solubility reactions related to CO2 injection and sequestration. Thermodynamic data are critical inputs to modeling geochemical processes. The adequacy of thermodynamic data for carbonate compounds has been identified as an important data requirement for the successful application of these geochemical reaction models to CO2 sequestration. A review of thermodynamic data for CO2 gas and carbonate aqueous species and minerals present in published data compilations and databases used in geochemical reaction models was therefore completed. Published studies that describe mineralogical analyses from CO2 sequestration field and natural analogue sites and laboratory studies were also reviewed to identify specific carbonate minerals that are important to CO2 sequestration reactions and therefore require thermodynamic data. The results of the literature review indicated that an extensive thermodynamic database exists for CO2 and CH4 gases, carbonate aqueous species, and carbonate minerals. Values of ∆fG298° and/or log Kr,298° are available for essentially all of these compounds. However, log Kr,T° or heat capacity values at temperatures above 298 K exist for less than

  19. Near-surface monitoring strategies for geologic carbon dioxide storage verification

    SciTech Connect (OSTI)

    Oldenburg, Curtis M.; Lewicki, Jennifer L.; Hepple, Robert P.

    2003-10-31

    Geologic carbon sequestration is the capture of anthropogenic carbon dioxide (CO{sub 2}) and its storage in deep geologic formations. Geologic CO{sub 2} storage verification will be needed to ensure that CO{sub 2} is not leaking from the intended storage formation and seeping out of the ground. Because the ultimate failure of geologic CO{sub 2} storage occurs when CO{sub 2} seeps out of the ground into the atmospheric surface layer, and because elevated concentrations of CO{sub 2} near the ground surface can cause health, safety, and environmental risks, monitoring will need to be carried out in the near-surface environment. The detection of a CO{sub 2} leakage or seepage signal (LOSS) in the near-surface environment is challenging because there are large natural variations in CO{sub 2} concentrations and fluxes arising from soil, plant, and subsurface processes. The term leakage refers to CO{sub 2} migration away from the intended storage site, while seepage is defined as CO{sub 2} passing from one medium to another, for example across the ground surface. The flow and transport of CO{sub 2} at high concentrations in the near-surface environment will be controlled by its high density, low viscosity, and high solubility in water relative to air. Numerical simulations of leakage and seepage show that CO{sub 2} concentrations can reach very high levels in the shallow subsurface even for relatively modest CO{sub 2} leakage fluxes. However, once CO{sub 2} seeps out of the ground into the atmospheric surface layer, surface winds are effective at dispersing CO{sub 2} seepage. In natural ecological systems with no CO{sub 2} LOSS, near-surface CO{sub 2} fluxes and concentrations are controlled by CO{sub 2} uptake by photosynthesis, and production by root respiration, organic carbon biodegradation in soil, deep outgassing of CO{sub 2}, and by exchange of CO{sub 2} with the atmosphere. Existing technologies available for monitoring CO{sub 2} in the near-surface environment

  20. Secure and sustainable energy infrastructure: The case of CO2...

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Technical Report: Secure and sustainable energy infrastructure: The case of CO2 capture, utilization, and storage Citation Details In-Document Search Title: Secure and sustainable ...

  1. Capture and Sequestration of CO2 at the Boise White Paper Mill

    SciTech Connect (OSTI)

    B.P. McGrail; C.J. Freeman; G.H. Beeman; E.C. Sullivan; S.K. Wurstner; C.F. Brown; R.D. Garber; D. Tobin E.J. Steffensen; S. Reddy; J.P. Gilmartin

    2010-06-16

    This report documents the efforts taken to develop a preliminary design for the first commercial-scale CO2 capture and sequestration (CCS) project associated with biomass power integrated into a pulp and paper operation. The Boise Wallula paper mill is located near the township of Wallula in Southeastern Washington State. Infrastructure at the paper mill will be upgraded such that current steam needs and a significant portion of the current mill electric power are supplied from a 100% biomass power source. A new biomass power system will be constructed with an integrated amine-based CO2 capture plant to capture approximately 550,000 tons of CO2 per year for geologic sequestration. A customized version of Fluor Corporation’s Econamine Plus™ carbon capture technology will be designed to accommodate the specific chemical composition of exhaust gases from the biomass boiler. Due to the use of biomass for fuel, employing CCS technology represents a unique opportunity to generate a net negative carbon emissions footprint, which on an equivalent emissions reduction basis is 1.8X greater than from equivalent fossil fuel sources (SPATH and MANN, 2004). Furthermore, the proposed project will offset a significant amount of current natural gas use at the mill, equating to an additional 200,000 tons of avoided CO2 emissions. Hence, the total net emissions avoided through this project equates to 1,100,000 tons of CO2 per year. Successful execution of this project will provide a clear path forward for similar kinds of emissions reduction that can be replicated at other energy-intensive industrial facilities where the geology is suitable for sequestration. This project also represents a first opportunity for commercial development of geologic storage of CO2 in deep flood basalt formations. The Boise paper mill site is host to a Phase II pilot study being carried out under DOE’s Regional Carbon Partnership Program. Lessons learned from this pilot study and other separately

  2. Systematic assessment of wellbore integrity for geologic carbon storage projects using regulatory and industry information

    SciTech Connect (OSTI)

    Moody, Mark; Sminchak, J.R.

    2015-11-01

    database of over 4 million items on well integrity parameters in the study areas, a systematic CBL evaluation tool for rating cement in boreholes, SCP field testing procedures and analysis methodology, a process for summarizing well integrity at CO2 storage fields, a statistical analysis of well integrity indicators, and an assessment of practical methods and costs necessary to repair/remediate typical wells in the region based on assessment of six test study areas. Project results may benefit both CO2 storage and improved oil recovery applications. This study of wellbore integrity is a useful precursor to support development of geologic storage in the Midwest United States because it sheds more light on the actual well conditions (rather than the perceived condition) of historic oil and gas wells in the region.

  3. Early opportunities of CO₂ geological storage deployment in coal chemical industry in China

    SciTech Connect (OSTI)

    Wei, Ning; Li, Xiaochun; Liu, Shengnan; Dahowski, R. T.; Davidson, C. L.

    2014-12-31

    Carbon dioxide capture and geological storage (CCS) is regarded as a promising option for climate change mitigation; however, the high capture cost is the major barrier to large-scale deployment of CCS technologies. High-purity CO₂ emission sources can reduce or even avoid the capture requirements and costs. Among these high-purity CO₂ sources, certain coal chemical industry processes are very important, especially in China. In this paper, the basic characteristics of coal chemical industries in China is investigated and analyzed. As of 2013 there were more than 100 coal chemical plants in operation. These emission sources together emit 430 million tons CO₂ per year, of which about 30% are emit high-purity and pure CO₂ (CO₂ concentration >80% and >98.5% respectively). Four typical source-sink pairs are chosen for techno-economic evaluation, including site screening and selection, source-sink matching, concept design, and economic evaluation. The technical-economic evaluation shows that the levelized cost of a CO₂ capture and aquifer storage project in the coal chemistry industry ranges from 14 USD/t to 17 USD/t CO₂. When a 15USD/t CO₂ tax and 20USD/t for CO₂ sold to EOR are considered, the levelized cost of CCS project are negative, which suggests a benefit from some of these CCS projects. This might provide China early opportunities to deploy and scale-up CCS projects in the near future.

  4. Early opportunities of CO₂ geological storage deployment in coal chemical industry in China

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Wei, Ning; Li, Xiaochun; Liu, Shengnan; Dahowski, R. T.; Davidson, C. L.

    2014-12-31

    Carbon dioxide capture and geological storage (CCS) is regarded as a promising option for climate change mitigation; however, the high capture cost is the major barrier to large-scale deployment of CCS technologies. High-purity CO₂ emission sources can reduce or even avoid the capture requirements and costs. Among these high-purity CO₂ sources, certain coal chemical industry processes are very important, especially in China. In this paper, the basic characteristics of coal chemical industries in China is investigated and analyzed. As of 2013 there were more than 100 coal chemical plants in operation. These emission sources together emit 430 million tons CO₂more » per year, of which about 30% are emit high-purity and pure CO₂ (CO₂ concentration >80% and >98.5% respectively). Four typical source-sink pairs are chosen for techno-economic evaluation, including site screening and selection, source-sink matching, concept design, and economic evaluation. The technical-economic evaluation shows that the levelized cost of a CO₂ capture and aquifer storage project in the coal chemistry industry ranges from 14 USD/t to 17 USD/t CO₂. When a 15USD/t CO₂ tax and 20USD/t for CO₂ sold to EOR are considered, the levelized cost of CCS project are negative, which suggests a benefit from some of these CCS projects. This might provide China early opportunities to deploy and scale-up CCS projects in the near future.« less

  5. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO{sub 2}

    SciTech Connect (OSTI)

    Neeraj Gupta

    2005-02-02

    As part of the Department of Energy's (DOE) initiative on developing new technologies for storage of carbon dioxide in geologic reservoirs, Battelle has been awarded a project to investigate the feasibility of CO{sub 2} sequestration in the deep saline reservoirs in the Ohio River Valley region. This project is the Phase III of Battelle's work under the Novel Concepts in Greenhouse Gas Management grant. In addition to the DOE, the project is being sponsored by American Electric Power (AEP), BP, The Ohio Coal Development Office (OCDO) of the Ohio Department of Development, and Schlumberger. The main objective of the project is to evaluate the geology of deep formations in the Ohio River Valley region in general and in the vicinity of AEP's Mountaineer Power Plant in particular, in order to determine their potential use for conducting a long-term test of CO{sub 2} disposal in deep saline formations and potentially in nearby deep coal seams. This work supports the overall project objective of demonstrating that CO{sub 2} sequestration in deep formations is feasible from engineering and economic perspectives, as well as being an inherently safe practice and one that will be acceptable to the public. The current technical progress report summarizes activities completed for the October through December 2004 period of the project. As discussed in the report, the technical activities focused on initial injection well design, completion of the site characterization report, assessment of monitoring technologies, shipment of coal samples for testing the capture system to Mitsubishi Heavy Industry, and presentation of project progress at several venues. In addition, proposals to DOE for continued funding of the project activities under the current contract and potentially a new contract for development of regional framework were being evaluated and processed.

  6. EIS-0473: W.A. Parish Post-Combustion CO2 Capture and Sequestration Project (PCCS), Fort Bend County, TX

    Broader source: Energy.gov [DOE]

    This EIS evaluates the environmental impacts of a proposal to provide financial assistance for a project proposed by NRG Energy, Inc (NRG). DOE selected NRG’s proposed W.A. Parish Post-Combustion CO2 Capture and Sequestration Project for a financial assistance award through a competitive process under the Clean Coal Power Initiative Program. NRG would design, construct and operate a commercial-scale carbon dioxide (CO2) capture facility at its existing W.A. Parish Generating Station in Fort Bend County, Texas; deliver the CO2 via a new pipeline to the existing West Ranch oil field in Jackson County, Texas, for use in enhanced oil recovery operations; and demonstrate monitoring techniques to verify the permanence of geologic CO2 storage.

  7. Supercritical CO2 Tech Team

    Broader source: Energy.gov [DOE]

    Supercritical CO2 is a highly technical team focused on different heat source applications of the sCO2 Brayton Cycle.

  8. Predictions of long-term behavior of a large-volume pilot test for CO2 geological storage in a saline formation in the Central Valley, California

    SciTech Connect (OSTI)

    Doughty, Christine; Myer, Larry R.; Oldenburg, Curtis M.

    2008-11-01

    The long-term behavior of a CO{sub 2} plume injected into a deep saline formation is investigated, focusing on mechanisms that lead to plume stabilization. Key measures are plume migration distance and the time evolution of CO{sub 2} phase-partitioning, which are examined by developing a numerical model of the subsurface at a proposed power plant with CO{sub 2} capture in the San Joaquin Valley, California, where a large-volume pilot test of CO{sub 2} injection will be conducted. The numerical model simulates a four-year CO{sub 2} injection period and the subsequent evolution of the CO{sub 2} plume until it stabilizes. Sensitivity studies are carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual gas saturation.

  9. Investigation of CO2 plume behavior for a large-scale pilot test of geologic carbon storage in a saline formation

    SciTech Connect (OSTI)

    Doughty, C.

    2009-04-01

    The hydrodynamic behavior of carbon dioxide (CO{sub 2}) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO{sub 2} plume stabilization. A numerical model of the subsurface at a proposed power plant with CO{sub 2} capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO{sub 2} is injected over a four-year period, and the subsequent evolution of the CO{sub 2} plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO{sub 2} between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO{sub 2} plume is effectively immobilized at 25 years. At that time, 38% of the CO{sub 2} is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical, and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint, but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual CO{sub 2} saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs between different trapping mechanisms.

  10. Microsoft Word - NETL-TRS-1-2013_Geologic Storage Estimates for Carbon Dioxide_20130312.electronic.docx

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Comparison of Publicly Available Methods for Development of Geologic Storage Estimates for Carbon Dioxide in Saline Formations 12 March 2013 Office of Fossil Energy NETL-TRS-1-2013 Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy,

  11. Measurements of 222Rn, 220Rn, and CO Emissions in Natural CO2 Fields in Wyoming: MVA Techniques for Determining Gas Transport and Caprock Integrity

    SciTech Connect (OSTI)

    Kaszuba, John; Sims, Kenneth

    2014-09-30

    An integrated field-laboratory program evaluated the use of radon and CO2 flux measurements to constrain source and timescale of CO2 fluxes in environments proximate to CO2 storage reservoirs. By understanding the type and depth of the gas source, the integrity of a CO2 storage reservoir can be assessed and monitored. The concept is based on correlations of radon and CO2 fluxes observed in volcanic systems. This fundamental research is designed to advance the science of Monitoring, Verification, and Accounting (MVA) and to address the Carbon Storage Program goal of developing and validating technologies to ensure 99 percent storage performance. Graduate and undergraduate students conducted the research under the guidance of the Principal Investigators; in doing so they were provided with training opportunities in skills required for implementing and deploying CCS technologies. Although a final method or “tool” was not developed, significant progress was made. The field program identified issues with measuring radon in environments rich in CO2. Laboratory experiments determined a correction factor to apply to radon measurements made in CO2-bearing environments. The field program also identified issues with radon and CO2-flux measurements in soil gases at a natural CO2 analog. A systematic survey of radon and CO2 flux in soil gases at the LaBarge CO2 Field in Southwest Wyoming indicates that measurements of 222Rn (radon), 220Rn (thoron), and CO2 flux may not be a robust method for monitoring the integrity of a CO2 storage reservoir. The field program was also not able to correlate radon and CO2 flux in the CO2-charged springs of the Thermopolis hydrothermal system. However, this part of the program helped to motivate the aforementioned laboratory experiments that determined correction factors for measuring radon in CO2-rich environments. A graduate student earned a Master of Science degree for this part of the field program; she is currently employed with a

  12. Evaluating Impacts of CO2 Gas Intrusion Into a Confined Sandstone aquifer: Experimental Results

    SciTech Connect (OSTI)

    Qafoku, Nikolla; Lawter, Amanda R.; Shao, Hongbo; Wang, Guohui; Brown, Christopher F.

    2014-12-31

    results from the batch experiments showed that the High Plains sediments mobilized only low concentrations of trace elements (potential contaminants), which were detected occasionally in the aqueous phase during these experiments. Importantly, these occurrences were more frequent in the calcite-free sediment. Results from these investigations provide useful information to support site selection, risk assessment, and public education efforts associated with geological CO2 storage and sequestration.

  13. Evaluating Impacts of CO2 Gas Intrusion Into a Confined Sandstone aquifer: Experimental Results

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Qafoku, Nikolla; Lawter, Amanda R.; Shao, Hongbo; Wang, Guohui; Brown, Christopher F.

    2014-12-31

    , the results from the batch experiments showed that the High Plains sediments mobilized only low concentrations of trace elements (potential contaminants), which were detected occasionally in the aqueous phase during these experiments. Importantly, these occurrences were more frequent in the calcite-free sediment. Results from these investigations provide useful information to support site selection, risk assessment, and public education efforts associated with geological CO2 storage and sequestration.« less

  14. Evaluating impacts of CO2 gas intrusion into a confined sandstone aquifer: Experimental results

    SciTech Connect (OSTI)

    Qafoku, Nikolla; Lawter, Amanda R.; Shao, Hongbo; Wang, Guohui; Brown, Christopher F.

    2014-12-31

    results from the batch experiments showed that the High Plains sediments mobilized only low concentrations of trace elements (potential contaminants), which were detected occasionally in the aqueous phase during these experiments. Importantly, these occurrences were more frequent in the calcite-free sediment. Results from these investigations provide useful information to support site selection, risk assessment, and public education efforts associated with geological CO2 storage and sequestration.

  15. Underground CO2 Storage | GE Global Research

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    William Challener, principal investigator and physicist in the Photonics Lab at GE Global Research. "The work is very challenging. We have already developed a single sensor system ...

  16. Geologic characterization and carbon storage resource estimates for the knox group, Illinois Basin, Illinois, Indiana and Kentucky

    SciTech Connect (OSTI)

    Harris, David; Ellett, Kevin; Rupp, John; Leetaru, Hannes

    2014-09-30

    Research documented in this report includes (1) refinement and standardization of regional stratigraphy across the 3-state study area in Illinois, Indiana, and Kentucky, (2) detailed core description and sedimentological interpretion of Knox cores from five wells in western Kentucky, and (3) a detailed calculation of carbon storage volumetrics for the Knox using three different methodologies. Seven regional cross sections document Knox formation distribution and thickness. Uniform stratigraphic nomenclature for all three states helps to resolve state-to-state differences that previously made it difficult to evaluate the Knox on a basin-wide scale. Correlations have also refined the interpretation of an important sandstone reservoir interval in southern Indiana and western Kentucky. This sandstone, a CO2 injection zone in the KGS 1 Blan well, is correlated with the New Richmond Sandstone of Illinois. This sandstone is over 350 ft (107 m) thick in parts of southern Indiana. It has excellent porosity and permeability at sufficient depths, and provides an additional sequestration target in the Knox. The New Richmond sandstone interval has higher predictability than vuggy and fractured carbonates, and will be easier to model and monitor CO2 movement after injection.

  17. Plains CO2 Reduction Partnership PCOR | Open Energy Information

    Open Energy Info (EERE)

    Grand Forks, North Dakota Zip: 58202-9018 Product: North Dakota-based consortium researching CO2 storage options. PCOR is busy with the ECBM in the Unminable Lignite Research...

  18. Assessing the Effect of Timing of Availability for Carbon Dioxide Storage in the Largest Oil and Gas Pools in the Alberta Basin: Description of Data and Methodology

    SciTech Connect (OSTI)

    Dahowski, Robert T.; Bachu, Stefan

    2007-03-05

    Carbon dioxide capture from large stationary sources and storage in geological media is a technologically-feasible mitigation measure for the reduction of anthropogenic emissions of CO2 to the atmosphere in response to climate change. Carbon dioxide (CO2) can be sequestered underground in oil and gas reservoirs, in deep saline aquifers, in uneconomic coal beds and in salt caverns. The Alberta Basin provides a very large capacity for CO2 storage in oil and gas reservoirs, along with significant capacity in deep saline formations and possible unmineable coal beds. Regional assessments of potential geological CO2 storage capacity have largely focused so far on estimating the total capacity that might be available within each type of reservoir. While deep saline formations are effectively able to accept CO2 immediately, the storage potential of other classes of candidate storage reservoirs, primarily oil and gas fields, is not fully available at present time. Capacity estimates to date have largely overlooked rates of depletion in these types of storage reservoirs and typically report the total estimated storage capacity that will be available upon depletion. However, CO2 storage will not (and cannot economically) begin until the recoverable oil and gas have been produced via traditional means. This report describes a reevaluation of the CO2 storage capacity and an assessment of the timing of availability of the oil and gas pools in the Alberta Basin with very large storage capacity (>5 MtCO2 each) that are being looked at as likely targets for early implementation of CO2 storage in the region. Over 36,000 non-commingled (i.e., single) oil and gas pools were examined with effective CO2 storage capacities being individually estimated. For each pool, the life expectancy was estimated based on a combination of production decline analysis constrained by the remaining recoverable reserves and an assessment of economic viability, yielding an estimated depletion date, or year

  19. Site characterization of the highest-priority geologic formations for CO2 storage in Wyoming

    SciTech Connect (OSTI)

    Surdam, Ronald C.; Bentley, Ramsey; Campbell-Stone, Erin; Dahl, Shanna; Deiss, Allory; Ganshin, Yuri; Jiao, Zunsheng; Kaszuba, John; Mallick, Subhashis; McLaughlin, Fred; Myers, James; Quillinan, Scott

    2013-12-07

    This study, funded by U.S. Department of Energy National Energy Technology Laboratory award DE-FE0002142 along with the state of Wyoming, uses outcrop and core observations, a diverse electric log suite, a VSP survey, in-bore testing (DST, injection tests, and fluid sampling), a variety of rock/fluid analyses, and a wide range of seismic attributes derived from a 3-D seismic survey to thoroughly characterize the highest-potential storage reservoirs and confining layers at the premier CO2 geological storage site in Wyoming. An accurate site characterization was essential to assessing the following critical aspects of the storage site: (1) more accurately estimate the CO2 reservoir storage capacity (Madison Limestone and Weber Sandstone at the Rock Springs Uplift (RSU)), (2) evaluate the distribution, long-term integrity, and permanence of the confining layers, (3) manage CO2 injection pressures by removing formation fluids (brine production/treatment), and (4) evaluate potential utilization of the stored CO2

  20. Establishing MICHCARB, a geological carbon sequestration research and education center for Michigan, implemented through the Michigan Geological Repository for Research and Education, part of the Department of Geosciences at Western Michigan University

    SciTech Connect (OSTI)

    Barnes, David A.; Harrison, William B.

    2014-01-28

    The Michigan Geological Repository for Research and Education (MGRRE), part of the Department of Geosciences at Western Michigan University (WMU) at Kalamazoo, Michigan, established MichCarb—a geological carbon sequestration resource center by: • Archiving and maintaining a current reference collection of carbon sequestration published literature • Developing statewide and site-specific digital research databases for Michigan’s deep geological formations relevant to CO2 storage, containment and potential for enhanced oil recovery • Producing maps and tables of physical properties as components of these databases • Compiling all information into a digital atlas • Conducting geologic and fluid flow modeling to address specific predictive uses of CO2 storage and enhanced oil recovery, including compiling data for geological and fluid flow models, formulating models, integrating data, and running the models; applying models to specific predictive uses of CO2 storage and enhanced oil recovery • Conducting technical research on CO2 sequestration and enhanced oil recovery through basic and applied research of characterizing Michigan oil and gas and saline reservoirs for CO2 storage potential volume, injectivity and containment. Based on our research, we have concluded that the Michigan Basin has excellent saline aquifer (residual entrapment) and CO2/Enhanced oil recovery related (CO2/EOR; buoyant entrapment) geological carbon sequestration potential with substantial, associated incremental oil production potential. These storage reservoirs possess at least satisfactory injectivity and reliable, permanent containment resulting from associated, thick, low permeability confining layers. Saline aquifer storage resource estimates in the two major residual entrapment, reservoir target zones (Lower Paleozoic Sandstone and Middle Paleozoic carbonate and sandstone reservoirs) are in excess of 70-80 Gmt (at an overall 10% storage efficiency factor; an approximately

  1. Microsoft Word - NRAP-TRS-III-004-2013_DevelopSurrogateModelsCO2...

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    ... S. Injection and storage of CO 2 in deep saline aquifers: analytical solution for CO 2 ... Jared Ciferno Director Office of Coal and Power R&D National Energy Technology Laboratory ...

  2. DOE Investing $11.5 Million to Advance Geologic Carbon Storage...

    Office of Environmental Management (EM)

    Storage and Geothermal Exploration July 27, 2016 - 10:15am Addthis WASHINGTON - The The U.S. Department of Energy ... Researchers will deploy a system of technologies to ...

  3. Investigating the Fundamental Scientific Issues Affecting the Long-term Geologic Storage of Carbon Dioxide

    SciTech Connect (OSTI)

    Spangler, Lee; Cunningham, Alfred; Barnhart, Elliot; Lageson, David; Nall, Anita; Dobeck, Laura; Repasky, Kevin; Shaw, Joseph; Nugent, Paul; Johnson, Jennifer; Hogan, Justin; Codd, Sarah; Bray, Joshua; Prather, Cody; McGrail, B.; Oldenburg, Curtis; Wagoner, Jeff; Pawar, Rajesh

    2014-12-19

    The Zero Emissions Research and Technology (ZERT) collaborative was formed to address basic science and engineering knowledge gaps relevant to geologic carbon sequestration. The original funding round of ZERT (ZERT I) identified and addressed many of these gaps. ZERT II has focused on specific science and technology areas identified in ZERT I that showed strong promise and needed greater effort to fully develop.

  4. Trinity CO2 LLC | Open Energy Information

    Open Energy Info (EERE)

    CO2 LLC Jump to: navigation, search Name: Trinity CO2 LLC Place: Texas Product: String representation "Trinity CO2 LLC ... smission lines." is too long. References: Trinity CO2...

  5. Department of Energy Announces 15 Projects Aimed at Secure CO2...

    Energy Savers [EERE]

    Aimed at Secure CO2 Underground Storage Department of Energy Announces 15 Projects Aimed at ... a mesoscale high-pressure rock test system, develop biomineralization seal ...

  6. Monitoring CO 2 sequestration into deep saline aquifer and associated salt intrusion using coupled multiphase flow modeling and time lapse electrical resistivity tomography

    SciTech Connect (OSTI)

    Chuan Lu; CHI Zhang; Hai Hanag; Timothy C. Johnson

    2014-04-01

    Successful geological storage and sequestration of carbon dioxide (CO2) require efficient monitoring of the migration of CO2 plume during and after large-scale injection in order to verify the containment of the injected CO2 within the target formation and to evaluate potential leakage risk. Field studies have shown that surface and cross-borehole electrical resistivity tomography (ERT) can be a useful tool in imaging and characterizing solute transport in heterogeneous subsurface. In this synthetic study, we have coupled a 3-D multiphase flow model with a parallel 3-D time-lapse ERT inversion code to explore the feasibility of using time-lapse ERT for simultaneously monitoring the migration of CO2 plume in deep saline formation and potential brine intrusion into shallow fresh water aquifer. Direct comparisons of the inverted CO2 plumes resulting from ERT with multiphase flow simulation results indicate the ERT could be used to delineate the migration of CO2 plume. Detailed comparisons on the locations, sizes and shapes of CO2 plume and intruded brine plumes suggest that ERT inversion tends to underestimate the area review of the CO2 plume, but overestimate the thickness and total volume of the CO2 plume. The total volume of intruded brine plumes is overestimated as well. However, all discrepancies remain within reasonable ranges. Our study suggests that time-lapse ERT is a useful monitoring tool in characterizing the movement of injected CO2 into deep saline aquifer and detecting potential brine intrusion under large-scale field injection conditions.

  7. Experimental study of potential wellbore cement carbonation by various phases of carbon dioxide during geologic carbon sequestration

    SciTech Connect (OSTI)

    Jung, Hun Bok; Um, Wooyong

    2013-08-16

    Hydrated Portland cement was reacted with carbon dioxide (CO2) in supercritical, gaseous, and aqueous phases to understand the potential cement alteration processes along the length of a wellbore, extending from deep CO2 storage reservoir to the shallow subsurface during geologic carbon sequestration. The 3-D X-ray microtomography (XMT) images displayed that the cement alteration was significantly more extensive by CO2-saturated synthetic groundwater than dry or wet supercritical CO2 at high P (10 MPa)-T (50C) conditions. Scanning electron microscopy with energy dispersive spectroscopy (SEM-EDS) analysis also exhibited a systematic Ca depletion and C enrichment in cement matrix exposed to CO2-saturated groundwater. Integrated XMT, XRD, and SEM-EDS analyses identified the formation of extensive carbonated zone filled with CaCO3(s), as well as the porous degradation front and the outermost silica-rich zone in cement after exposure to CO2-saturated groundwater. The cement alteration by CO2-saturated groundwater for 2-8 months overall decreased the porosity from 31% to 22% and the permeability by an order of magnitude. Cement alteration by dry or wet supercritical CO2 was slow and minor compared to CO2-saturated groundwater. A thin single carbonation zone was formed in cement after exposure to wet supercritical CO2 for 8 months or dry supercritical CO2 for 15 months. Extensive calcite coating was formed on the outside surface of a cement sample after exposure to wet gaseous CO2 for 1-3 months. The chemical-physical characterization of hydrated Portland cement after exposure to various phases of carbon dioxide indicates that the extent of cement carbonation can be significantly heterogeneous depending on CO2 phase present in the wellbore environment. Both experimental and geochemical modeling results suggest that wellbore cement exposure to supercritical, gaseous, and aqueous phases of CO2 during geologic carbon sequestration is unlikely to damage the wellbore

  8. Watch Our CO2 Drop | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Watch Our CO2 Drop Watch Our CO2 Drop

  9. PLAINS CO2 REDUCTION (PCOR) PARTNERSHIP

    SciTech Connect (OSTI)

    Edward N. Steadman; Daniel J. Daly; Lynette L. de Silva; John A. Harju; Melanie D. Jensen; Erin M. O'Leary; Wesley D. Peck; Steven A. Smith; James A. Sorensen

    2006-01-01

    During the period of October 1, 2003, through September 30, 2005, the Plains CO2 Reduction (PCOR) Partnership, identified geologic and terrestrial candidates for near-term practical and environmentally sound carbon dioxide (CO2) sequestration demonstrations in the heartland of North America. The PCOR Partnership region covered nine states and three Canadian provinces. The validation test candidates were further vetted to ensure that they represented projects with (1) commercial potential and (2) a mix that would support future projects both dependent and independent of CO2 monetization. This report uses the findings contained in the PCOR Partnership's two dozen topical reports and half-dozen fact sheets as well as the capabilities of its geographic information system-based Decision Support System to provide a concise picture of the sequestration potential for both terrestrial and geologic sequestration in the PCOR Partnership region based on assessments of sources, sinks, regulations, deployment issues, transportation, and capture and separation. The report also includes concise action plans for deployment and public education and outreach as well as a brief overview of the structure, development, and capabilities of the PCOR Partnership. The PCOR Partnership is one of seven regional partnerships under Phase I of the U.S. Department of Energy National Energy Technology Laboratory's Regional Carbon Sequestration Partnership program. The PCOR Partnership, comprising 49 public and private sector members, is led by the Energy & Environmental Research Center at the University of North Dakota. The international PCOR Partnership region includes the Canadian provinces of Alberta, Saskatchewan, and Manitoba and the states of Montana (part), Wyoming (part), North Dakota, South Dakota, Nebraska, Missouri, Iowa, Minnesota, and Wisconsin.

  10. ARM - Instrument - co2flx

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    govInstrumentsco2flx Documentation CO2FLX : Handbook ARM Data Discovery Browse Data Comments? We would love to hear from you Send us a note below or call us at 1-888-ARM-DATA....