Relevant bibliographies by topics / Geologic storage

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  1. Journal articles
  2. Dissertations / Theses
  3. Books
  4. Book chapters
  5. Conference papers
  6. Reports

Academic literature on the topic 'Geologic storage'

Author: Grafiati
Published: 4 June 2021
Last updated: 1 February 2022

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Journal articles on the topic "Geologic storage"

1

Orr, F. M. "Onshore Geologic Storage of CO2." Science 325, no. 5948 (2009): 1656–58. http://dx.doi.org/10.1126/science.1175677.

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Loáiciga, Hugo A. "CO2Capture and Geologic Storage: The Possibilities." Groundwater 51, no. 6 (2013): 816–21. http://dx.doi.org/10.1111/gwat.12041.

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Fairley, Jerry P. "Geologic Water Storage in Precolumbian Peru." Latin American Antiquity 14, no. 2 (2003): 193–206. http://dx.doi.org/10.2307/3557595.

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AbstractAgriculture 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 Tipón) and discuss the potential for identification of similar systems developed by other ancient Latin American cultures.
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Vilarrasa, Víctor, Jesus Carrera, Sebastià Olivella, Jonny Rutqvist, and Lyesse Laloui. "Induced seismicity in geologic carbon storage." Solid Earth 10, no. 3 (2019): 871–92. http://dx.doi.org/10.5194/se-10-871-2019.

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Abstract. Geologic carbon storage, as well as other geo-energy applications, such as geothermal energy, seasonal natural gas storage and subsurface energy storage imply fluid injection and/or extraction that causes changes in rock stress field and may induce (micro)seismicity. If felt, seismicity has a negative effect on public perception and may jeopardize wellbore stability and damage infrastructure. Thus, induced earthquakes should be minimized to successfully deploy geo-energies. However, numerous processes may trigger induced seismicity, which contribute to making it complex and translates into a limited forecast ability of current predictive models. We review the triggering mechanisms of induced seismicity. Specifically, we analyze (1) the impact of pore pressure evolution and the effect that properties of the injected fluid have on fracture and/or fault stability; (2) non-isothermal effects caused by the fact that the injected fluid usually reaches the injection formation at a lower temperature than that of the rock, inducing rock contraction, thermal stress reduction and stress redistribution around the cooled region; (3) local stress changes induced when low-permeability faults cross the injection formation, which may reduce their stability and eventually cause fault reactivation; (4) stress transfer caused by seismic or aseismic slip; and (5) geochemical effects, which may be especially relevant in carbonate-containing formations. We also review characterization techniques developed by the authors to reduce the uncertainty in rock properties and subsurface heterogeneity both for the screening of injection sites and for the operation of projects. Based on the review, we propose a methodology based on proper site characterization, monitoring and pressure management to minimize induced seismicity.
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Oldenburg, Curtis M. "Transport in Geologic CO2 Storage Systems." Transport in Porous Media 82, no. 1 (2010): 1–2. http://dx.doi.org/10.1007/s11242-009-9526-7.

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Vilarrasa, Victor, and Jonny Rutqvist. "Thermal effects on geologic carbon storage." Earth-Science Reviews 165 (February 2017): 245–56. http://dx.doi.org/10.1016/j.earscirev.2016.12.011.

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Romanak, Katherine, Russell S. Harmon, and Yousif Kharaka. "Geochemical Aspects of Geologic Carbon Storage." Applied Geochemistry 30 (March 2013): 1–3. http://dx.doi.org/10.1016/j.apgeochem.2013.02.003.

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Orr, Franklin M. "Storage of Carbon Dioxide in Geologic Formations." Journal of Petroleum Technology 56, no. 09 (2004): 90–97. http://dx.doi.org/10.2118/88842-jpt.

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Hill, Bruce, Susan Hovorka, and Steve Melzer. "Geologic Carbon Storage Through Enhanced Oil Recovery." Energy Procedia 37 (2013): 6808–30. http://dx.doi.org/10.1016/j.egypro.2013.06.614.

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Molina, Oscar, Victor Vilarrasa, and Mehdi Zeidouni. "Geologic Carbon Storage for Shale Gas Recovery." Energy Procedia 114 (July 2017): 5748–60. http://dx.doi.org/10.1016/j.egypro.2017.03.1713.

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Dissertations / Theses on the topic "Geologic storage"

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Okwen, Roland Tenjoh. "Enhanced CO2 Storage in Confined Geologic Formations." Scholar Commons, 2009. http://scholarcommons.usf.edu/etd/3683.

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Many geoscientists endorse Carbon Capture and Storage (CCS) as a potential strategy for mitigating emissions of greenhouse gases. Deep saline aquifers have been reported to have larger CO 2 storage capacity than other formation types because of their availability worldwide and less competitive usage. This work proposes an analytical model for screening potential CO 2 storage sites and investigates injection strategies that can be employed to enhance CO 2 storage. The analytical model provides of estimates CO 2 storage efficiency, formation pressure profiles, and CO 2 –brine interface location. The results from the analytical model were compared to those from a sophisticated and reliable numerical model (TOUGH 2 ). The models showed excellent agreement when input conditions applied in both were similar. Results from sensitivity studies indicate that the agreement between the analytical model and TOUGH2 strongly depends on irreducible brine saturation, gravity and on the relationship between relative permeability and brine saturation. A series of numerical experiments have been conducted to study the pros and cons of different injection strategies for CO 2 storage in confined saline aquifers. Vertical, horizontal, and joint vertical and horizontal injection wells were considered. Simulations results show that horizontal wells could be utilized to improve CO 2 storage capacity and efficiency in confined aquifers under pressure-limited conditions with relative permeability ratios greater than or equal to 0:01. In addition, joint wells are more efficient than single vertical wells and less efficient than single horizontal wells for CO 2 storage in anisotropic aquifers.
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Szulczewski, Michael Lawrence. "The subsurface fluid mechanics of geologic carbon dioxide storage." Thesis, Massachusetts Institute of Technology, 2013. http://hdl.handle.net/1721.1/82834.

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Thesis (Ph. D.)--Massachusetts Institute of Technology, Department of Civil and Environmental Engineering, 2013.<br>Cataloged from PDF version of thesis.<br>Includes bibliographical references (pages 157-168).<br>In carbon capture and storage (CCS), CO₂ is captured at power plants and then injected into deep geologic reservoirs for long-term storage. While CCS may be critical for the continued use of fossil fuels in a carbon-constrained world, the subsurface behavior of CO₂ remains poorly understood, which has contributed to the absence of government policy to implement CCS. In this Thesis, we use simulations, experiments, and theory to clarify the fluid mechanics of CO₂ storage, with the goal of informing two practical questions. The first question is, how much CO₂ can be stored in the United States? This question is important to clarify the role of CCS among the portfolio of other climate-change mitigation options, such as renewable energy and reduced energy consumption. To address this question, we develop models of CO₂ injection and the post-injection migration, and apply them to several reservoirs in the US. We use the models to calculate the total amount of CO₂ that can be stored in these reservoirs without hydraulically fracturing the caprock or allowing the CO₂ to migrate to a major leakage pathway. We find that the US has sufficient storage capacity to stabilize emissions at the current rates for at least 100 years. The second question is, what are the long-term dissolution rates of CO₂ into the ambient groundwater? This question is important because dissolution mitigates the risk of CO₂ leakage to shallower formations or the surface. We address this question for storage in structural and stratigraphic traps, which are promising locations in a reservoir for injection and will likely be the first sites of large-scale CCS deployment. We describe several mechanisms of CO₂ dissolution in these traps and develop models to predict the dissolution rates. We apply the models to relevant subsurface conditions and find that dissolution rates vary widely depending on the reservoir properties, but that thick reservoirs with high permeabilities could potentially dissolve hundreds of megatons of CO₂ in tens of years.<br>by Michael Lawrence Szulczewski.<br>Ph.D.
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Steele-MacInnis, Matthew. "Thermodynamics of geologic fluids." Diss., Virginia Tech, 2013. http://hdl.handle.net/10919/22026.

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Fluids play a vital role in essentially all geologic environments and processes, and are the principal media of heat and mass transfer in the Earth. The properties of geologic fluids can be diverse, as fluids occur at conditions ranging from ambient temperatures and pressures at Earth's surface, to extreme temperatures and pressures in Earth's deep interior. Regardless the wide ranges of conditions at which geologic fluids occur, fluid properties are described and governed by the same fundamental thermodynamic relationships. Thus, application of thermodynamic principles and methods allows us to decipher the properties and roles of geologic fluids, to help understand geologic processes. Fluid inclusions in minerals provide one of the best available tools to study the compositions of geological fluids. Compositions of fluid inclusions can be determined from microthermometric measurements, based on the vapor-saturated liquidus conditions of model chemical systems, or by various microanalytical techniques. The vaporsaturated liquidus relations of the system H2O-NaCl-CaCl2 have been modeled to allow estimation of fluid inclusion compositions by either microthermometric or microanalytical methods. Carbon capture and storage (CCS) in deep saline formations represents one option for reducing anthropogenic CO2 emissions into Earth's atmosphere. Availability of storage volume in deep saline formations is a significant component of injection and storage planning. Investigation of the volumetric properties of CO2, brine and CO2-saturated brine reveals that storage volume requirements are minimized when CO2 dissolves into brine. These results suggest that a protocol involving brine extraction, CO2 dissolution and re-injection may optimize CCS in deep saline formations. Numerical modeling of quartz dissolution and precipitation in a sub-seafloor hydrothermal system was used to understand the role of fluid-phase immiscibility ("boiling") on quartz-fluid interactions, and to predict where in the system quartz could deposit and trap fluid inclusions. The spatial distribution of zones of quartz dissolution and precipitation is complex, owing to the many inter-related factors controlling quartz solubility. Immiscibility exerts a strong control over the occurrence of quartz precipitation in the deeper regions of fluid circulation.<br>Ph. D.
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Parthasarathy, Hariprasad. "Arsenic Dissolution from Sedimentary Formations under Geologic Carbon Dioxide Storage Conditions." Research Showcase @ CMU, 2014. http://repository.cmu.edu/dissertations/488.

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The overall goal of this Ph.D. study was to investigate the mobilization of arsenic (As) from sedimentary formations under conditions representative of geologic carbon dioxide storage (GCS) i.e., high pressure, temperature, and salinity. GCS is a promising technology for the mitigation of increasing CO2 emissions in the atmosphere. It primarily involves the capture of CO2 from point sources, followed by transport and injection into deep subsurface formations for long-term storage. Of the potential subsurface formations under consideration in the United States, saline formations, characterized by the presence of high salinity brines, are estimated to have the largest storage capacity. Potential for leakage of injected CO2, native brines, and CO2- saturated brines from these reservoirs exists and may lead to an increase in mineral dissolution from reservoir formations, and leakage pathways. Of particular interest in the risk assessment of GCS is the dissolution and mobilization of toxic metals such as arsenic (As) and lead. The primary mineral source of As in high and low permeability sedimentary formations is arsenopyrite (FeAsS (s)). While the oxidative dissolution of FeAsS (s) has been reported in the literature, the dissolution of FeAsS (s) under anoxic, high salinity conditions of GCS remains unexplored. To conduct dissolution experiments at high pressure, temperature, and salinity, a small-scale plug-flow system capable of measuring dissolution rates without mass transfer limitations was designed and constructed. The capacity of the system in measuring dissolution rates under GCS conditions was validated. The plug-flow system is capable of accurate and rapid measurement of dissolution rates for minerals with slow and moderate dissolution rates, with a maximum rate limitation of 5 x10-5 mol/m2s at a flow rate of 10 ml/min. To enable accurate determination of reaction rates, a method for preparation of uniformly sized arsenopyrite particles free of surface oxides was developed. The method involves sonication of crushed minerals with ethanol, washing with 12N HCl, and 50% ethanol, followed by drying in N2. Analysis of the arsenopyrite surface with X-ray photoelectron spectroscopy revelealed that the method was successful in removing all the oxides of As and S on the surface, while only 12% of Fe was left oxidized. Subsequently, the dissolution of arsenopyrite, galena, and pyrite in low-concentration alkali and alkaline metal chloride solutions under anoxic conditions was investigated. Further, the effect of Na-Ca-Cl brines on the release of arsenic was determined under ambient as well as GCS conditions. The result of these experiments revealed that electrolytes traditionally considered inert, such as NaCl, CaCl2, and MgCl2 are capable of effecting sulfide mineral dissolution. In particular, the dissolution of As increased with increasing cation activity, and the dissolution of sulfur decreased with an increase in chloride ion activity in solution. Dissolution experiments with 1.5M Na-Ca-Cl brines resulted in arsenic dissolution rates in the range of 10-10 to 10-11 mol/m2 s under anoxic conditions. The rate of As release was found to be dependent on the CaCl2 content of these Na-Ca-Cl brines. Upon the introduction of CO2 into the system, the dissolution rate of As decreased and was determined to be in the range of 10-11 to 10-12 mol/m2s. For comparison, the rate of As release from arsenopyrite under oxic conditions is in the range of X to Y mol/m2 s. Finally, dissolution experiments aimed at understanding the release of As from naturally occurring seal rocks of a GCS formation were conducted. A primary seal rock and two secondary seal rocks were obtained from the Cranfield oil field CO2- EOR site in Mississippi. The rock samples were characterized by micro Xray adsorption near edge structure analysis, which revealed that multiple sources of As exist in the reservoir seal rocks studied. Dissolution experiments with seal rocks and anoxic brines of 105g/L NaCl resulted in the dissolution of arsenic in concentrations of 70 to 80 ppb at steady state. Dissolution of CO2 in the brine had no discernible effect on the steady state release concentration of As.
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Singleton, Gregory R. (Gregory Randall). "Geologic Storage of carbon dioxide : risk analyses and implications for public acceptance." Thesis, Massachusetts Institute of Technology, 2007. http://hdl.handle.net/1721.1/40378.

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Thesis (S.M.)--Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program; and, (S.M.)--Massachusetts Institute of Technology, Dept. of Political Science, 2007.<br>Includes bibliographical references (p. 99-103).<br>Carbon Capture and Storage (CCS) technology has the potential to enable large reductions in global greenhouse gas emissions, but one of the unanswered questions about CCS is whether it will be accepted by the public. In the past, construction of large facilities such as nuclear power plants has been prevented or delayed by public opposition, and CCS proponents would like to know whether it will provoke similar public opposition. Since the Geologic Storage (GS) component of the CCS architecture has not been widely deployed, this thesis explores the characteristics of GS and how they might affect public perception and acceptance of the larger CCS architecture. To provide insight regarding public acceptance of CCS, this thesis addresses two questions; first asking how GS is likely to be perceived by the public and what can be done to improve that perception, and second asking whether financial compensation can be used to improve public acceptance of energy facilities. To address the first question about the public perception of GS, this thesis begins with a discussion of risk concepts and how it is used differently by experts, who use a realist perspective, and the general public, who use a social constructivist perspective.<br>(cont.) After discussing how this difference in perspective leads to risk disputes, this thesis presents an overview of the risk elements of GS. It then reviews existing risk assessments of GS and qualitatively evaluates the risks of GS in terms of their likelihood, impact, and uncertainty. The discussion on risk assessment perspectives and methods is then integrated with the GS risk review to forecast whether GS is likely to be accepted by the public. By using a public perspective to compare GS to existing energy technologies, this thesis concludes that the risks of GS are likely to eventually be considered no worse than existing fossil fuel energy technologies. However, since GS is a new technology with little public awareness, additional demonstrations and field tests will be necessary to make this case to the public. To address the question of whether financial compensation can be used to improve public acceptance of energy facilities, this thesis presents analyses of data from a public opinion poll on compensation and facility siting. Survey respondents were asked whether they would accept the construction of a natural gas pipeline, nuclear power plant, or coal fired power plant near their home if they were given annual payments of $100.<br>(cont.) The compensation offers had little net effect on the public's willingness to accept the facilities, and the survey results do not support the use of compensation to improve public acceptance of energy facilities. By investigating public risk perception and GS risk assessments, this thesis concludes that 1) full-scale demonstrations of GS will be needed to convince the public that the technology is safe and 2) that financial compensation is ineffective for improving public opinion.<br>by Gregory R. Singleton.<br>S.M.
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Popova, Olga. "Development of Geostatistical Models to Estimate CO2 Storage Resource in Sedimentary Geologic Formations." Research Showcase @ CMU, 2014. http://repository.cmu.edu/dissertations/485.

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Carbon capture and sequestration (CCS) is a technology that provides a near-term solution to reduce anthropogenic CO2 emissions to the atmosphere and reduce our impact on the climate system. Assessments of carbon sequestration resources that have been made for North America using existing methodologies likely underestimate uncertainty and variability in the reservoir parameters. This thesis describes a geostatistical model developed to estimate the CO2 storage resource in sedimentary formations. The proposed stochastic model accounts for the spatial distribution of reservoir properties and is implemented to a case study of the Oriskany Formation of the Appalachian sedimentary basin. The developed model allows for estimation of the CO2 sequestration resource of a storage formation with subsequent uncertainty analysis. Since the model is flexible with respect to changing input parameters and assumptions it can be parameterized to calculate the CO2 storage resource of any porous subsurface unit. The thesis continues with evaluation of the cost of CO2 injection and storage for the Oriskany Formation utilizing storage resource estimates generated by our geostatistical model. Our results indicate that the cost of sequestering CO2 has significant spatial variation due to heterogeneity of formation properties and site geology. We identify the low-cost areas within the Oriskany footprint. In general, these areas correspond to the deepest portions of the Appalachian basin and could be considered as potential CO2 injection sites for CCS industrial scale projects. Overall, we conclude that significant improvement can be made by integrating basin geology and spatial heterogeneity of formation petrophysical properties into CCS cost assessments, and that should be a focus of future research efforts. This will allow for more accurate cost estimates for the entire CCS system and identify areas of sedimentary basins with optimal conditions for CO2 injection and storage. To mitigate the effects of climate change, the U.S. will need a widespread deployment of low-carbon electricity generating technologies including natural gas and coal with CCS. More precise CO2 storage resource and CCS cost estimates will provide better recommendations for government and industry leaders and inform their decisions on what greenhouse gas mitigation measures are the best fit for their regions.
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Roberts-Ashby, Tina. "Evaluation of Deep Geologic Units in Florida for Potential Use in Carbon Dioxide Sequestration." Scholar Commons, 2010. http://scholarcommons.usf.edu/etd/3601.

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Concerns about elevated atmospheric carbon dioxide (CO 2 ) and the effect on global climate have created proposals for the reduction of carbon emissions from large stationary sources, such as power plants. Carbon dioxide capture and sequestration (CCS) in deep geologic units is being considered by Florida electric-utilities. Carbon dioxide-enhanced oil recovery (CO 2 -EOR) is a form of CCS that could offset some of the costs associated with geologic sequestration. Two potential reservoirs for geologic sequestration were evaluated in south-central and southern Florida: the Paleocene Cedar Keys Formation/Upper Cretaceous Lawson Formation (CKLIZ) and the Lower Cretaceous Sunniland Formation along the Sunniland Trend (Trend). The Trend is a slightly arcuate band in southwest Florida that is about 233 kilometers long and 32 kilometers wide, and contains oil plays within the Sunniland Formation at depths starting around 3,414 meters below land surface, which are confined to mound-like structures made of coarse fossil fragments, mostly rudistids. The Trend commercial oil fields of the South Florida Basin have an average porosity of 16% within the oil-producing Sunniland Formation, and collectively have an estimated storage capacity of around 26 million tons of CO 2 . The Sunniland Formation throughout the entire Trend has an average porosity of 14% and an estimated storage capacity of about 1.2 billion tons of CO 2 (BtCO2 ). The CKLIZ has an average porosity of 23% and an estimated storage capacity of approximately 79 BtCO 2 . Porous intervals within the CKLIZ and Sunniland Formation are laterally homogeneous, and low-permeability layers throughout the units provide significant vertical heterogeneity. The CKLIZ and Sunniland Formation are considered potentially suitable for CCS operations because of their geographic locations, appropriate depths, high porosities, estimated storage capacities, and potentiallyeffective seals. The Trend oil fields are suitable for CO 2 -EOR in the Sunniland Formation due to appropriate injected-CO 2 density, uniform intergranular porosity, suitable API density of formation-oil, sufficient production zones, and adequate remaining oil-in-place following secondary recovery. In addition to these in-depth investigations of the CKLIZ and Sunniland Formation, a more-cursory assessment of deep geologic units throughout the state of Florida, which includes rocks of Paleocene and Upper Cretaceous age through to rocks of Ordovician age, shows additional units in Florida that may be suitable for CO 2 -EOR and CCS operations. Furthermore, this study shows that deep geologic units throughout Florida potentially have the capacity to sequester billions of tons of CO 2 for hundreds of fossil-fuel-fired power plants. Geologic sequestration has not yet been conducted in Florida, and its implementation could prove useful to Florida utility companies, as well as to other energy-utilities in the southeastern United States.
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Azzolina, Nicholas A. "Statistical Approaches to Quantifying Uncertainty of Monitoring and Performance at Geologic CO2 Storage Sites." Research Showcase @ CMU, 2015. http://repository.cmu.edu/dissertations/567.

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Geologic carbon dioxide (CO2) storage is one approach for mitigating concentrations of CO2 in the atmosphere that are caused by stationary anthropogenic inputs. Injecting CO2 into the subsurface for long-term storage is an “engineered-natural system”. This engineered-natural system is complex, with potential interactions during CO2 injection between CO2 and other reservoir fluids and various components of the geologic system. The National Risk Assessment Partnership (NRAP) is an initiative within DOE’s Office of Fossil Energy that is improving the fundamental understanding of the complex science behind engineered-natural systems and is developing the risk assessment tools that are needed for safe, permanent geologic CO2 storage. The NRAP technical approach entails an iterative modeling process that integrates component models into a system model which may then be used to provide quantitative assessments of potential risks and to design monitoring protocols that will effectively monitor risks at a geologic CO2 storage project. A theme throughout all phases of the NRAP approach is quantifying uncertainty and variability. The focus of this dissertation is to contribute statistical methods and/or approaches for quantifying uncertainty and variability with respect to both monitoring and performance at geologic CO2 storage sites. These methods are intended for future use by NRAP or other geologic CO2 storage practitioners and may be incorporated into broader modeling approaches. However, the results and contributions from this work extend beyond geologic CO2 storage and apply to other subsurface engineered-natural systems.
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Gulliver, Djuna M. "Concentration - Dependent Effects of CO2 on Subsurface Microbial Communities Under Conditions of Geologic Carbon Storage and Leakage." Research Showcase @ CMU, 2014. http://repository.cmu.edu/dissertations/408.

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Geologic carbon storage (GCS) is a crucial part of a proposed mitigation strategy to reduce the anthropogenic CO2 emissions to the atmosphere. During this process, CO2 is injected as super critical carbon dioxide (SC-CO2) in confined deep subsurface storage units, such as saline aquifers and depleted oil reservoirs. The deposition of vast amounts of CO2 in subsurface geologic formations may ultimately lead to CO2 leakage into overlying freshwater aquifers. Introduction of CO2 into these subsurface environments will greatly increase the CO2 concentration and will create CO2 concentration gradients that drive changes in the microbial communities present. While it is expected that altered microbial communities will impact the biogeochemistry of the subsurface, there is no information available on how CO2 gradients will impact these communities. The overarching goal of this dissertation is to understand how CO2 exposure will impact subsurface microbial communities at temperature and pressure that are relevant to GCS and CO2 leakage scenarios. To meet this goal, unfiltered, aqueous samples from a deep saline aquifer, a depleted oil reservoir, and a fresh water aquifer were exposed to varied concentrations of CO2 at reservoir pressure and temperature. The microbial ecology of the samples was examined using molecular, DNA-based techniques. The results from these studies were also compared across the sites to determine any existing trends. Results reveal that increasing CO2 leads to decreased DNA concentrations regardless of the site, suggesting that microbial processes will be significantly hindered or absent nearest the CO2 injection/leakage plume where CO2 concentrations are highest. At CO2 exposures expected downgradient from the CO2 plume, selected microorganisms emerged as dominant in the CO2 exposed conditions. Results suggest that the altered microbial community was site specific and highly dependent on pH. The site-dependent results suggests no ability to predict the emerging dominant species for other CO2exposed environments. This body of work improves the understanding of how a subsurface microbial community may respond to conditions expected from geologic carbon storage and CO2 leakage. This is the first step for understanding how a CO2 altered microbial community may impact injectivity, permanence of stored CO2, and subsurface water quality. .
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Raza, Yamama. "Uncertainty analysis of capacity estimates and leakage potential for geologic storage of carbon dioxide in saline aquifers." Thesis, Massachusetts Institute of Technology, 2009. http://hdl.handle.net/1721.1/53063.

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Thesis (S.M. in Technology and Policy)--Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program, 2009.<br>Includes bibliographical references (p. 61-62).<br>The need to address climate change has gained political momentum, and Carbon Capture and Storage (CCS) is a technology that is seen as being feasible for the mitigation of carbon dioxide emissions. However, there is considerable uncertainty that is present in our understanding of the behavior of CO₂ that is injected into the sub-surface. In this work, uncertainty analysis is performed using Monte Carlo simulations for capacity estimates and leakage potential for a saline aquifer. Six geologic parameters are treated as uncertain: porosity, irreducible water saturation, the endpoint relative permeability of CO₂, residual gas saturation, viscosity of water, and viscosity of the brine. The results of the simulations for capacity indicate that there is a large uncertainty in capacity estimates, and that evaluating the model at using the mean values of the individual parameters does not give the same result as the mean of the distribution of capacity estimates. Sensitivity analysis shows that the two parameters that contribute the most to the uncertainty in estimates are the residual gas saturation and the endpoint relative permeability of CO₂. The results for the leakage simulation suggest that while there is a non-zero probability of leakage, the cumulative amount of CO₂ that leaks is on the order of fractions of a percent of the total injected volume, suggesting that essentially all the CO₂ is trapped. Additionally, the time when leakage begins is on the order of magnitude of thousands of years, indicating that CCS has the potential to be a safe carbon mitigation option.<br>(cont.) Any development of regulation of geologic storage and relevant policies should take uncertainty into consideration. Better understanding of the uncertainty in the science of geologic storage can influence the areas of further research, and improve the accuracy of models that are being used. Incorporating uncertainty analysis into regulatory requirements for site characterization will provide better oversight and management of injection activities. With the proper management and monitoring of sites, the establishment of proper liability regimes, accounting rules and compensation mechanisms for leakage, geologic storage can be a safe and effective carbon mitigation tool to combat climate change.<br>by Yamama Raza.<br>S.M.in Technology and Policy
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Books on the topic "Geologic storage"

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Geologic carbon dioxide storage. Nova Science Publishers, 2011.

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Saini, Dayanand. Engineering Aspects of Geologic CO2 Storage. Springer International Publishing, 2017. http://dx.doi.org/10.1007/978-3-319-56074-8.

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Geological Survey (U.S.). National assessment of geologic carbon dioxide storage resources--results. U.S. Dept. of the Interior, U.S. Geological Survey, 2013.

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Lynds, Ranie M. Geologic storage assessment of carbon dioxide (CO₂) in the Laramide basins of Wyoming. Wyoming State Geological Survey, 2013.

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International, Symposium on Geologic Disposal of Spent Fuel High Level and Alpha Bearing Wastes (1992 Antwerp Belgium). Geological disposal of spent fuel and high level and alpha bearing wastes: Proceedings of an International Symposium on Geologic Disposal of Spent Fuel, High Level and Alpha Bearing Wastes. IAEA, 1993.

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International Symposium on Geologic Disposal of Spent Fuel, High Level and Alpha Bearing Wastes (1992 Antwerp, Belgium). Geological disposal of spent fuel and high level and alpha bearing wastes: Proceedings of an International Symposium on Geologic Disposal of Spent Fuel, High Level and Alpha Bearing Wastes. International Atomic Energy Agency, 1993.

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Nordbotten, Jan M., and Michael A. Celia. Geological Storage of CO2. John Wiley & Sons, Inc., 2011. http://dx.doi.org/10.1002/9781118137086.

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Surdam, Ronald C., ed. Geological CO2 Storage Characterization. Springer New York, 2013. http://dx.doi.org/10.1007/978-1-4614-5788-6.

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Pusch, Roland. Geological Storage of Highly Radioactive Waste. Springer Berlin Heidelberg, 2008. http://dx.doi.org/10.1007/978-3-540-77333-7.

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Niemi, Auli, Jacob Bear, and Jacob Bensabat, eds. Geological Storage of CO2 in Deep Saline Formations. Springer Netherlands, 2017. http://dx.doi.org/10.1007/978-94-024-0996-3.

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Book chapters on the topic "Geologic storage"

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Pashin, Jack C. "Geological Considerations for CO2 Storage in Coal." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_8.

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Ettehadtavakkol, Amin. "Storage of CO2 in depleted/producing oil reservoirs." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_10.

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Jain, Nikhil, Akash Srivastava, and T. N. Singh. "Carbon Capture, Transport and Geologic Storage: A Brief Introduction." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_1.

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Li, Qi, and Guizhen Liu. "Risk Assessment of the Geological Storage of CO2: A Review." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_13.

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Cantucci, Barbara, Mauro Buttinelli, Monia Procesi, Alessandra Sciarra, and Mario Anselmi. "Algorithms for CO2 Storage Capacity Estimation: Review and Case Study." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_2.

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Saini, Dayanand. "Selection of Favorable Storage Sites." In Engineering Aspects of Geologic CO2 Storage. Springer International Publishing, 2017. http://dx.doi.org/10.1007/978-3-319-56074-8_7.

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Hurtado, Antonio, Sonsoles Eguilior, and Fernando Recreo. "Security Assessment on Geological Storage of CO2: Application to Hontomin Site." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_15.

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Shukla Potdar, Richa, and V. Vishal. "Trapping Mechanism of CO2 Storage in Deep Saline Aquifers: Brief Review." In Geologic Carbon Sequestration. Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-27019-7_3.

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Großmann, Jochen, and Andreas Dahmke. "Chances and Risks of Geologic CO2 Storage." In Springer Series in Geomechanics and Geoengineering. Springer Berlin Heidelberg, 2013. http://dx.doi.org/10.1007/978-3-642-37849-2_3.

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Ussiri, David A. N., and Rattan Lal. "Carbon Capture and Storage in Geologic Formations." In Carbon Sequestration for Climate Change Mitigation and Adaptation. Springer International Publishing, 2017. http://dx.doi.org/10.1007/978-3-319-53845-7_13.

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Conference papers on the topic "Geologic storage"

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Myer, Larry R., David Hafemeister, B. Levi, M. Levine, and P. Schwartz. "Carbon Capture and Geologic Storage." In PHYSICS OF SUSTAINABLE ENERGY: Using Energy Efficiently and Producing It Renewably. AIP, 2008. http://dx.doi.org/10.1063/1.2993734.

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Melick, Jesse John, Michael H. Gardner, and Michael James Uland. "Geologic Heterogeneity in Basin-Scale Geologic Carbon Storage: Examples from the Powder River Basin, NE Wyoming and SE Montana." In SPE International Conference on CO2 Capture, Storage, and Utilization. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/126443-ms.

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Hovorka, Susan. "Using EOR as Geologic Storage: Downsides and benefits." In Stanford Center for Carbon Storage Annual Meeting Stanford, CA May 2014. US DOE, 2014. http://dx.doi.org/10.2172/1749851.

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Litynski, John, Traci Rodosta, Larry Myer, Robert Kane, and Gregory Alan Washington. "What Is Next in Geologic CO2 Storage Research?" In Carbon Management Technology Conference. Carbon Management Technology Conference, 2012. http://dx.doi.org/10.7122/151471-ms.

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Frailey, Scott Michael, and Robert James Finley. "Overview of the Midwest Geologic Sequestration Consortium Pilot Projects." In SPE International Conference on CO2 Capture, Storage, and Utilization. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/139746-ms.

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Ren, Bo, Steven L. Bryant, and Larry W. Lake. "Quantifying Local Capillary Trapping Storage Capacity Using Geologic Criteria." In Carbon Management Technology Conference. Carbon Management Technology Conference, 2015. http://dx.doi.org/10.7122/439489-ms.

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Holtz, Mark H. "Geologic CO2 Storage in Oil Fields: Considerations for Successful Sites." In SPE International Conference on CO2 Capture, Storage, and Utilization. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/126198-ms.

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Kuuskraa, Vello Alex. "Cost-Effective Remediation Strategies for Storing CO2 in Geologic Formations." In SPE International Conference on CO2 Capture, Storage, and Utilization. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/126618-ms.

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Gendrin, A., D. Zen, G. Sosio, et al. "Seismic Interpretation for Carbon Dioxide Geologic Storage - Duero Basin, Spain." In 75th EAGE Conference and Exhibition incorporating SPE EUROPEC 2013. EAGE Publications BV, 2013. http://dx.doi.org/10.3997/2214-4609.20130821.

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Udo Weyer, K. "Application of Geofluids Systems Analysis to Successful Geologic CO2 Storage." In 73rd EAGE Conference and Exhibition - Workshops 2011. EAGE Publications BV, 2011. http://dx.doi.org/10.3997/2214-4609.20147129.

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Reports on the topic "Geologic storage"

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Vikara, Derek, Tyler Zymroz, Jeffrey A. Withum, et al. Underground Natural Gas Storage – Analog Studies to Geologic Storage of CO2. Office of Scientific and Technical Information (OSTI), 2019. http://dx.doi.org/10.2172/1557139.

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Dvorkin, Jack, and Gary Mavko. Rock Physics of Geologic Carbon Sequestration/Storage. Office of Scientific and Technical Information (OSTI), 2013. http://dx.doi.org/10.2172/1097614.

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Neeraj Gupta. Novel Concepts Research in Geologic Storage of CO2. Office of Scientific and Technical Information (OSTI), 2007. http://dx.doi.org/10.2172/908780.

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Neeraj Gupta. Novel Concepts Research in Geologic Storage of CO2. Office of Scientific and Technical Information (OSTI), 2007. http://dx.doi.org/10.2172/909261.

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Neeraj Gupta. Novel Concepts Research in Geologic Storage of CO2. Office of Scientific and Technical Information (OSTI), 2006. http://dx.doi.org/10.2172/898059.

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Vikara, Derek, Tyler Zymroz, Jeffrey A. Withum, et al. Underground Natural Gas Storage - Analog Studies to Geologic Storage of CO2. Office of Scientific and Technical Information (OSTI), 2019. http://dx.doi.org/10.2172/1492342.

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Guinan, Allison, and Derek Vikara. NETL’s Analog Studies to Geologic Storage of CO2 – Overview. Office of Scientific and Technical Information (OSTI), 2019. http://dx.doi.org/10.2172/1615146.

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Neeraj Gupta. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO2 PHASE III. Office of Scientific and Technical Information (OSTI), 2006. http://dx.doi.org/10.2172/882732.

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Neeraj Gupta. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO{sub 2}. Office of Scientific and Technical Information (OSTI), 2005. http://dx.doi.org/10.2172/837075.

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Neeraj Gupta. NOVEL CONCEPTS RESEARCH IN GEOLOGIC STORAGE OF CO2 PHASE III. Office of Scientific and Technical Information (OSTI), 2006. http://dx.doi.org/10.2172/876070.

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