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dc.contributor.advisorBryant, Steven L.en
dc.creatorGupta, Abhishek Kumaren
dc.date.accessioned2011-07-12T16:03:41Zen
dc.date.available2011-07-12T16:03:41Zen
dc.date.issued2011-05en
dc.date.submittedMay 2011en
dc.identifier.urihttp://hdl.handle.net/2152/ETD-UT-2011-05-3386en
dc.descriptiontexten
dc.description.abstractGeological sequestration of CO₂ in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The effectiveness of any CO₂ sequestration operation depends on pore volume and the sequestration efficiency of the reservoir. Sequestration efficiency is defined here as the maximum storage with minimum risk of leakage to the overlying formations or to the surface. This can be characterized using three risk parameters i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO₂ present at any time. The selection among prospective saline reservoirs can be expedited by developing some semi-analytical correlations for these risk parameters which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO₂ sequestration. To develop such correlations, a database has been created from a large number of compositional reservoir simulations for different elementary reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip, perforation interval and constant pressure far boundary condition. This database is used to formulate different correlations that relate the sequestration efficiency to reservoir properties and operating conditions. The various elementary reservoir parameters are grouped together to generate different variants of gravity number used in the correlations. We update a previously reported correlation for time to hit the top seal and develop new correlations for other two parameters using the newly created database. A correlation for percentage of trapped CO₂ is also developed using a previously created similar database. We find that normalizing all risk parameters with their respective characteristic values yields reasonable correlations with different variants of gravity number. All correlations confirm the physics behind plume movement in a reservoir. The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs. CO₂ injection in saline reservoirs on the scale of tens of millions of tonnes may result in fracturing, fault activation and leakage of brine along conductive pathways. Critical contour of overpressure (CoP) is a convenient proxy to determine the risk associated with pressure buildup at different location and time in the reservoir. The location of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence and conductivity of faults). The CoP location also depends on relative permeability, and we extend the three-region injection model to derive analytical expressions for a specific CoP as a function of time. We consider two boundary conditions at the aquifer drainage radius, constant pressure or an infinite aquifer. The model provides a quick tool for estimating pressure profiles. Such tools are valuable for screening and ranking sequestration targets. Relative permeability curves measured on samples from seven potential storage formations are used to illustrate the effect on the CoPs. In the case of a constant pressure boundary and constant rate injection scenario, the CoP for small overpressures is time-invariant and independent of relative permeability. Depending on the relative values of overall mobilities of two-phase region and of brine region, the risk due to a critical CoP which lies in the two-phase region can either increase or decrease with time. In contrast, the risk due to a CoP in the drying region always decreases with time. The assumption of constant pressure boundaries is optimistic in the sense that CoPs extend the least distance from the injection well. We extend the analytical model to infinite-acting aquifers to get a more widely applicable estimate of risk. An analytical expression for pressure profile is developed by adapting water influx models from traditional reservoir engineering to the "three-region" saturation distribution. For infinite-acting boundary condition, the CoP trends depend on same factors as in the constant pressure case, and also depend upon the rate of change of aquifer boundary pressure with time. Commercial reservoir simulators are used to verify the analytical model for the constant pressure boundary condition. The CoP trends from the analytical solution and simulation results show a good match. To achieve safe and secure CO₂ storage in underground reservoirs several state and national government agencies are working to develop regulatory frameworks to estimate various risks associated with CO₂ injection in saline aquifers. Certification Framework (CF), developed by Oldenburg et al (2007) is a similar kind of regulatory approach to certify the safety and effectiveness of geologic carbon sequestration sites. CF is a simple risk assessment approach for evaluating CO₂ and brine leakage risk associated only with subsurface processes and excludes compression, transportation, and injection-well leakage risk. Certification framework is applied to several reservoirs in different geologic settings. These include In Salah CO₂ storage project Krechba, Algeria, Aquistore CO₂ storage project Saskatchewan, Canada and WESTCARB CO₂ storage project, Solano County, California. Compositional reservoir simulations in CMG-GEM are performed for CO₂ injection in each storage reservoir to predict pressure build up risk and CO₂ leakage risk. CO₂ leakage risk is also estimated using the catalog of pre-computed reservoir simulation results. Post combustion CO₂ capture is required to restrict the continuous increase of carbon content in the atmosphere. Coal fired electricity generating stations are the dominant players contributing to the continuous emissions of CO₂ into the atmosphere. U.S. government has planned to install post combustion CO₂ capture facility in many coal fired power plants including W.A. Parish electricity generating station in south Texas. Installing a CO₂ capture facility in a coal fired power plant increases the capital cost of installation and operating cost to regenerate the turbine solvent (steam or natural gas) to maintain the stripper power requirement. If a coal-fired power plant with CO₂ capture is situated over a viable source for geothermal heat, it may be desirable to use this heat source in the stripper. Geothermal brine can be used to replace steam or natural gas which in turn reduces the operating cost of the CO₂ capture facility. High temperature brine can be produced from the underground geothermal brine reservoir and can be injected back to the reservoir after the heat from the hot brine is extracted. This will maintain the reservoir pressure and provide a long-term supply of hot brine to the stripper. Simulations were performed to supply CO₂ capture facility equivalent to 60 MWe electric unit to capture 90% of the incoming CO₂ in WA Parish electricity generating station. A reservoir simulation study in CMG-GEM is performed to evaluate the feasibility to recycle the required geothermal brine for 30 years time. This pilot study is scaled up to 15 times of the original capacity to generate 900 MWe stripping system to capture CO₂ at surface.en
dc.format.mimetypeapplication/pdfen
dc.language.isoengen
dc.subjectCO₂ sequestrationen
dc.subjectCO₂ injectionen
dc.subjectCO₂ trappingen
dc.subjectLeakage risken
dc.subjectOverpressureen
dc.subjectCertification frameworken
dc.subjectGeothermal modelingen
dc.subjectGeothermal energyen
dc.subjectDeep saline aquifersen
dc.subjectPlume dynamicsen
dc.subjectClimatic changeen
dc.subjectCarbon captureen
dc.titleUnderstanding the plume dynamics and risk associated with CO₂ injection in deep saline aquifersen
dc.date.updated2011-07-12T16:04:10Zen
dc.identifier.slug2152/ETD-UT-2011-05-3386en
dc.contributor.committeeMemberRochelle, Gary T.en
dc.description.departmentPetroleum and Geosystems Engineeringen
dc.type.genrethesisen
thesis.degree.departmentPetroleum and Geosystems Engineeringen
thesis.degree.disciplinePetroleum Engineeringen
thesis.degree.grantorUniversity of Texas at Austinen
thesis.degree.levelMastersen
thesis.degree.nameMaster of Science in Engineeringen


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