1,560 research outputs found

    Storage Capacity Estimation of Commercial Scale Injection and Storage of CO2 in the Jacksonburg-Stringtown Oil Field, West Virginia

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    Geological capture, utilization and storage (CCUS) of carbon dioxide (CO2) in depleted oil and gas reservoirs is one method to reduce greenhouse gas emissions with enhanced oil recovery (EOR) and extending the life of the field. Therefore CCUS coupled with EOR is considered to be an economic approach to demonstration of commercial-scale injection and storage of anthropogenic CO2. Several critical issues should be taken into account prior to injecting large volumes of CO2, such as storage capacity, project duration and long-term containment. Reservoir characterization and 3D geological modeling are the best way to estimate the theoretical CO 2 storage capacity in mature oil fields. The Jacksonburg-Stringtown field, located in northwestern West Virginia, has produced over 22 million barrels of oil (MMBO) since 1895. The sandstone of the Late Devonian Gordon Stray is the primary reservoir.;The Upper Devonian fluvial sandstone reservoirs in Jacksonburg-Stringtown oil field, which has produced over 22 million barrels of oil since 1895, are an ideal candidate for CO2 sequestration coupled with EOR. Supercritical depth (\u3e2500 ft.), minimum miscible pressure (941 psi), favorable API gravity (46.5°) and good water flood response are indicators that facilitate CO 2-EOR operations. Moreover, Jacksonburg-Stringtown oil field is adjacent to a large concentration of CO2 sources located along the Ohio River that could potentially supply enough CO2 for sequestration and EOR without constructing new pipeline facilities.;Permeability evaluation is a critical parameter to understand the subsurface fluid flow and reservoir management for primary and enhanced hydrocarbon recovery and efficient carbon storage. In this study, a rapid, robust and cost-effective artificial neural network (ANN) model is constructed to predict permeability using the model\u27s strong ability to recognize the possible interrelationships between input and output variables. Two commonly available conventional well logs, gamma ray and bulk density, and three logs derived variables, the slope of GR, the slope of bulk density and Vsh were selected as input parameters and permeability was selected as desired output parameter to train and test an artificial neural network. The results indicate that the ANN model can be applied effectively in permeability prediction.;Porosity is another fundamental property that characterizes the storage capability of fluid and gas bearing formations in a reservoir. In this study, a support vector machine (SVM) with mixed kernels function (MKF) is utilized to construct the relationship between limited conventional well log suites and sparse core data. The input parameters for SVM model consist of core porosity values and the same log suite as ANN\u27s input parameters, and porosity is the desired output. Compared with results from the SVM model with a single kernel function, mixed kernel function based SVM model provide more accurate porosity prediction values.;Base on the well log analysis, four reservoir subunits within a marine-dominated estuarine depositional system are defined: barrier sand, central bay shale, tidal channels and fluvial channel subunits. A 3-D geological model, which is used to estimate theoretical CO2 sequestration capacity, is constructed with the integration of core data, wireline log data and geological background knowledge. Depending on the proposed 3-D geological model, the best regions for coupled CCUS-EOR are located in southern portions of the field, and the estimated CO2 theoretical storage capacity for Jacksonburg-Stringtown oil field vary between 24 to 383 million metric tons. The estimation results of CO2 sequestration and EOR potential indicate that the Jacksonburg-Stringtown oilfield has significant potential for CO2 storage and value-added EOR

    Carbon Dioxide Enhanced Oil Recovery

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    Imperial Users onl

    Design of Optimal Storage and Recovery Strategies of Carbon Dioxide using the Wytch Farm Reservoir Model

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    Imperial Users onl

    Long-Term Risks and Short-Term Regulations: Modeling the Transition from Enhanced Oil Recovery to Geologic Carbon Sequestration

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    Recent policy debates suggest that geologic carbon sequestration (GS) likely will play an important role in a carbon-constrained future. As GS evolves from the analogous technologies and practices of enhanced oil recovery (EOR) operations to a long-term, dedicated emissions mitigation option, regulations must evolve simultaneously to manage the risks associated with underground migration and surface tresspass of carbon dioxide (CO2). In this paper, we develop a basic engineering-economic model of four illustrative strategies available to a sophisticated site operator to better understand key deployment pathways in the transition from EOR to GS operations. All of these strategies focus on whether or not a sophisticated site operator would store CO2 in a geologic formation. We evaluate these strategies based on illustrative scenarios of (a) oil and CO2 prices; (b) leakage estimates; and (c) transportation, injection, and monitoring costs, as obtained from our understanding of the literature. Major results reveal that CO2 storage in depleted hydrocarbon reservoirs after oil recovery is associated with the greatest net revenues (i.e., the “most-preferred” strategy) under a range of scenarios. This finding ultimately suggests that GS regulatory design should anticipate the use of the potentially leakiest, or “worst,” sites first.carbon sequestration, enhanced oil recovery, leakage, regulatory design, risk management

    An overview of current status of carbon dioxide capture and storage technologies

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    AbstractGlobal warming and climate change concerns have triggered global efforts to reduce the concentration of atmospheric carbon dioxide (CO2). Carbon dioxide capture and storage (CCS) is considered a crucial strategy for meeting CO2 emission reduction targets. In this paper, various aspects of CCS are reviewed and discussed including the state of the art technologies for CO2 capture, separation, transport, storage, leakage, monitoring, and life cycle analysis. The selection of specific CO2 capture technology heavily depends on the type of CO2 generating plant and fuel used. Among those CO2 separation processes, absorption is the most mature and commonly adopted due to its higher efficiency and lower cost. Pipeline is considered to be the most viable solution for large volume of CO2 transport. Among those geological formations for CO2 storage, enhanced oil recovery is mature and has been practiced for many years but its economical viability for anthropogenic sources needs to be demonstrated. There are growing interests in CO2 storage in saline aquifers due to their enormous potential storage capacity and several projects are in the pipeline for demonstration of its viability. There are multiple hurdles to CCS deployment including the absence of a clear business case for CCS investment and the absence of robust economic incentives to support the additional high capital and operating costs of the whole CCS process

    Assessing risk to fresh water resources from long term CO2 injection- laboratory and field studies

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    In developing a site for geologic sequestration, one must assess potential consequences of failure to adequately contain injected carbon dioxide (CO2). Upward migration of CO2 or displacement of saline water because of increased pressure might impact protected water resources 100s to 1000s of meters above a sequestration interval. Questions posed are: (1) Can changes in chemistry of fresh water aquifers provide evidence of CO2 leakage from deep injection/sequestration reservoirs containing brine and or hydrocarbons? (2) What parameters can we use to assess potential impacts to water quality? (3) If CO2 leakage to freshwater aquifers occurs, will groundwater quality be degraded and if so, over what time period? Modeling and reaction experiments plus known occurrences of naturally CO2-charged potable water show that the common chemical reaction products from dissolution of CO2 into freshwater include rapid buffering of acidity by dissolution of calcite and slower equilibrium by reaction with clays and feldspars. Results from a series of laboratory batch reactions of CO2 with diverse aquifer rocks show geochemical response within hours to days after introduction of CO2. Results included decreased pH and increased concentrations of cations in CO2 experimental runs relative to control runs using argon (Ar). Some cation (Ba, Ca, Fe, Mg, Mn, and Sr) concentrations increased over and an order of magnitude during CO2 runs. Results are aquifer dependant in that experimental vessels containing different aquifer rocks showed different magnitudes of increase in cation concentrations. Field studies designed to improve understanding of risk to fresh water are underway in the vicinity of (1) SACROC oilfield in Scurry County, Texas, USA where CO2 has been injected for enhanced oil recovery (EOR) since 1972 and (2) the Cranfield unit in Adams County, Mississippi, USA where CO2 EOR is currently underway. Both field studies are funded by the U.S. Department of Energy (DOE) regional carbon sequestration partnership programs and industrial sponsors. Preliminary results of groundwater monitoring are currently available for the SACROC field study where researchers investigated 68 water wells and one spring during five field excursions between June 2006 and July 2008. Results to date show no trend of preferential degradation below drinking water standards in areas of CO2 injection (inside SACROC) as compared to areas outside of the SACROC oil field.Bureau of Economic Geolog

    Investigation of CO₂ sequestration options for Alaskan North Slope with emphasis on enhanced oil recovery

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    Thesis (M.S.) University of Alaska Fairbanks, 2006Carbon dioxide (CO₂), the main component of greenhouse gases, is released into the atmosphere primarily by combustion of fossil fuels like coal and oil. Due to a conspicuous lack of any CO₂ sequestration studies for Alaskan North Slope (ANS), the study of CO₂ sequestration options will open new avenues for CO₂ disposal options, such as viscous oil reservoirs and coal seams, on the ANS. This study focuses on the investigation of CO₂ storage options by screening ANS oil pools amenable to enhanced oil recovery, evaluating phase behavior of viscous oil and CO₂ mixture, and simulating enhanced oil recovery by CO₂ flooding, and migration of CO₂ in saline aquifer. Phase behavior studies revealed that CO₂ gas was partially miscible with West Sak, at the pressure closer to the reservoir pressure. Compositional simulation of CO₂ flooding for a five-spot West Sak reservoir pattern showed an increase in percent recovery with an increase in pore volume injected, but at the expense of an early breakthrough. Sensitivity analysis of CO₂ flooding project was found to be strongly dependent on the variables such as oil price and discount rate. Investigation of supercritical CO₂ injection in saline formation didn't increase temperature in the permafrost region
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