Download or read book Uncertainty Analysis of Carbon Sequestration in an Inclined Deep Saline Aquifer written by Guang Yang and published by . This book was released on 2012 with total page 96 pages. Available in PDF, EPUB and Kindle. Book excerpt: Geologic Carbon Sequestration (GCS) is a proposed means to reduce atmospheric carbon dioxide (CO2 ). In Wyoming, GCS is proposed for the Nugget Sandstone, an eolian sandstone exhibiting permeability heterogeneity. Using subsets of static site characterization data, this study builds a suite of increasingly complex geologic model families for the Nugget Sandstone in the Wyoming Overthrust Belt, which is an inclined deep saline aquifer. These models include: a homogeneous model (FAM1), a stationary geostatistical facies model with constant petrophyscial properties in each facies (FAM2a), a stationary geostatistical petrophysical model (FAM2b), a stationary facies model with sub-facies petrophysical variability (FAM3), and a non-stationary facies model (with sub-facies variability) conditioned to soft data (FAM4). These families, representing increasingly sophisticated conceptual models built with increasing amounts of site data, were simulated with the same CO2 injection test (50-year duration at ~1/3 Mt per year), followed by a 2000-year monitoring phase. Based on the Design of Experiment (DOE), an efficient sensitivity analysis (SA) is conducted for all model families, systematically varying uncertain input parameters, while assuming identical production scenario (i.e., well configuration, rate, BHP constraint) and boundary condition (i.e., model is part of a larger semi-infinite system where the injected gas can flow out). Results are compared among the families at different time scales to identify parameters that have first order impact on select simulation outcomes. For predicting CO2 storage ratio (SR) and brine leakage, at both time scales (i.e., end of injection and end of monitoring), more geologic factors are revealed to be important as model complexity is increased, while the importance of engineering factors is simultaneously diminished. In predicting each of the trapped and dissolved gases, when model is of greater complexity, more geologic factors are identified as important with increasing time. This effect, however, cannot be revealed by simpler models. Based on results of the SA, a response surface (RS) analysis is conducted next to generate prediction envelopes of the outcomes which are further compared among the model families. Results suggest a large uncertainty range in the SR given the uncertainties of the parameter and modeling choices. At the end of injection, SR ranges from 0.18 to 0.38; at the end of monitoring, SR ranges from 0.71 to 0.98. In predicting the SR, during the entire simulation time, uncertainty ranges of FAM2b, FAM3, and FAM4 are larger than those of FAM1 and FAM2a, since the former models incorporate more geological complexities. The uncertainty range also changes with time and with the model families. By the end of injection, prediction envelops of all families are more or less similar. Over this shorter time scale, where heterogeneities near the injection site are not significantly different among the different model representations, simpler models can capture the uncertainty in the predicted SR. During the monitoring phase, prediction envelope of each family deviates gradually from one another, reflecting the different (evolving) large scale heterogeneity experienced by each family as plume migrates and grows continuously. Compared to FAM4 (i.e., the most sophisticated model), all other families estimate higher mean SRs. The lesser the amount of site data are incorporated (i.e., lesser geological complexities), the greater the estimated mean SR. In terms of magnitude and range of the uncertainty, prediction envelop of FAM3 is the closest to that of FAM4, while FAM2b's uncertainty range is the largest and FAM1 and FAM2a's ranges are small. Finally, end-member gas plume footprint for each family is established from results of the RS designs (i.e., corresponding to SR minimum, median, and maximum). For FAM1 and FAM2a, at each time scale inspected, the end-member gas plume footprints are not as drastically different as in FAM2b, 3, and 4, since their SR uncertainty range is comparatively small. However, for families of greater geological complexity (i.e., FAM2b, FAM3, and FAM4), the differences are much more significant: gas plume of minimum SR sits around the wellbore and doesn't migrate far, while gas plume of maximum SR migrates a great distance from the wellbore. To summarize, geologic factors and associated conceptual model uncertainty can dominate the uncertainty in predicting SR, brine leakage, and plume footprint. At the study site, better characterization of geologic data such as porosity-permeability transform and facies correlation structure, can lead to significantly reduced uncertainty in predictions. Given the current uncertainty in parameters and modeling choices, CO2 plume predicted by the majority of the simulation runs is either trapped near the injection site (e.g., due to low formation permeability and its heterogeneity) or is gravity-stable under conditions of higher permeability and lower temperature gradient, suggesting a low leakage risk. The inclined Nugget Sandstone at the study site appears to be a viable candidate for safe GCS in this region.

Download or read book Uncertainty Analysis of Capacity Estimates and Leakage Potential for Geologic Storage of Carbon Dioxide in Saline Aquifers written by Yamama Raza and published by . This book was released on 2009 with total page 62 pages. Available in PDF, EPUB and Kindle. Book excerpt: (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.

Download or read book A Simulation Study of Carbon Sequestration in Deep Saline Aquifers written by Ajitabh Kumar and published by . This book was released on 2004 with total page 193 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Directory of Geoscience Departments 2015 written by Carolyn Wilson and published by American Geosciences Inst. This book was released on 2015-02-27 with total page 2140 pages. Available in PDF, EPUB and Kindle. Book excerpt: The Directory of Geoscience Departments 50th Edition is the most comprehensive directory and source of information about geosciences departments and researchers available. It is an invaluable resource for individuals working in the geosciences or must identify or work with specialists on the issues of Earth, Environmental, and related sciences and engineering fields. The Directory of Geoscience Departments 50th Edition provides a state/country-sorted listing of nearly 2300 geoscience departments, research departments, institutes, and their faculty and staff. Information on contact information for departments and individuals is provided, as well as details on department enrollments, faculty specialties, and the date and source of faculty and staff's highest degree. New in the 50th edition: Listing of all US and Canadian geoscience theses and dissertations accepted in 2012 that have been reported to GeoRef Information Services, as well as a listing of faculty by their research specialty.

Download or read book Sensitivity Analysis of Carbon Dioxide Storage in Saline Aquifers in the Presence of a Gas Cap written by Silvia Veronica Solano and published by . This book was released on 2010 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Deep brine-bearing formations contain a significant CO2 storage potential as they are usually permeable sandstones at depths in which pressure and temperature conditions assure supercritical state for the injected CO2. When injecting CO2 in a hydrocarbon-rich area, presence of a gas cap significantly impacts the CO2 plume behavior. This study focuses on the assessment of the CO2 plume properties in formations typical of the Gulf Coast area, under the presence of a gas cap and its consequences for long-term storage. The study is prompted by the presence of a large depleted gas cap at Cranfield, Mississippi where CO2 is being injected for long-term storage. Presence of the gas cap, even depleted, near the injection site provides an exceptional opportunity to investigate an area made of higher compressibility fluids and its impact on reservoir and operational parameters, particularly CO2 plume behavior. Enhanced gas recovery is not planned within this area. Considerable volumes of native brine are displaced when large amounts of CO2 are injected, and when this displacement occurs in a closed system, the amount of stored CO2 will depend solely on the additional pore space available owing to compressibility of the pore structure and fluids. As a result, presence of a gas cap is expected to impact plume characteristics, as well as operational conditions, because of its larger compressibility. A multi-parameter sensitivity analysis, based on a generic reservoir model, was performed to appreciate relevant factors to CO2 migration under the influence of the nearby gas cap. It was achieved using the compositional reservoir simulator CMG-GEM and allied modules. Main parameters taken into account for the sensitivity analysis included variation in gas cap properties such as: volume, gas composition and gas residual saturation. Additionally, other parameters have been included in this study such as reservoir dip, injector-gas-cap distance, injection pressure, plume asymmetry and horizontal centroid location. The CO2 plume extends farther as the gas cap volume increases and the distance to the gas cap decreases. Gas residual saturation conditions in the gas cap region are not expected to affect the maximum lateral plume extent as much as the existent volume of gas. The effect of gas cap composition in CO2 migration is dominated by pressure changes within the formation which subsequently affects the gas cap compressibility and in consequence the plume maximum lateral extent. For example, contamination of a methane-rich gas cap by injected CO2 has a strong effect on the plume maximum lateral extent due to compressibility changes. This, in turn, affects regulatory Area of Review, project technical risks, and economics. In another part of the study, a dimensional analysis was performed to identify and assess dominant forces relevant to CO2 plume distribution in the presence of a gas cap. Dimensionless groups were used to express the relationship between centroid location and the ratio of gravity and viscous forces given by the gravity number. Appropriate assessment of gas cap impact on CO2 plume distribution and on aquifer pressure build-up is fundamental for developing an accurate economic outlook as well as for taking into account regulatory constraints (including a monitoring plan addressing leakage risk and possible aquifer contamination).

Download or read book Large scale Impact of CO2 Storage in Deep Saline Aquifers written by and published by . This book was released on 2008 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Large volumes of CO2 captured from carbon emitters (such as coal-fired power plants) may be stored in deep saline aquifers as a means of mitigating climate change. Storing these additional fluids may cause pressure changes and displacement of native brines, affecting subsurface volumes that can be significantly larger than the CO2 plume itself. This study aimed at determining the three-dimensional region of influence during/after injection of CO2 and evaluating the possible implications for shallow groundwater resources, with particular focus on the effects of interlayer communication through low-permeability seals. To address these issues quantitatively, we conducted numerical simulations that provide a basic understanding of the large-scale flow and pressure conditions in response to industrial-scale CO2 injection into a laterally open saline aquifer. The model domain included an idealized multilayered groundwater system, with a sequence of aquifers and aquitards (sealing units) extending from the deep saline storage formation to the uppermost freshwater aquifer. Both the local CO2-brine flow around the single injection site and the single-phase water flow (with salinity changes) in the region away from the CO2 plume were simulated. Our simulation results indicate considerable pressure buildup in the storage formation more than 100 km away from the injection zone, whereas the lateral distance migration of brine is rather small. In the vertical direction, the pressure perturbation from CO2 storage may reach shallow groundwater resources only if the deep storage formation communicates with the shallow aquifers through sealing units of relatively high permeabilities (higher than 10 x 18 m2). Vertical brine migration through a sequence of layers into shallow groundwater bodies is extremely unlikely. Overall, large-scale pressure changes appear to be of more concern to groundwater resources than changes in water quality caused by the migration of displaced saline water.

Download or read book MODELING OF CARBON DIOXIDE SEQUESTRATION IN A DEEP SALINE AQUIFER written by and published by . This book was released on 2005 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: ABSTRACT MODELING OF CARBON DIOXIDE SEQUESTRATION IN A DEEP SALINE AQUIFER BAÞBUÐ, Baþar M.S., Department of Petroleum and Natural Gas Engineering Supervisor : Prof. Dr. Fevzi Gümrah July 2005, 245 pages CO2 is one of the hazardous greenhouse gases causing significant changes in the environment. The sequestering CO2 in a suitable geological medium can be a feasible method to avoid the negative effects of CO2 emissions in the atmosphere. CO2 sequestration is the capture of, separation, and long-term storage of CO2 in underground geological environments. A case study was simulated regarding the CO2 sequestration in a deep saline aquifer. The compositional numerical model (GEM) of the CMG software was used to study the ability of the selected aquifer to accept and retain the large quantities of injected CO2 at supercritical state for long periods of time (200 years). A field-scale model with two injectors and six water producers and a single-well aquifer model cases were studied. In a single-well aquifer model, the effects of parameters such as vertical to horizontal permeability ratio, aquifer pressure, injection rate, and salinity on the sequestration process were examined and the sensitivity analyses were performed after simulating the field-scale model. The supercritical CO2, one-state fluid which exhibits both gas and liquid-like properties, and gaseous CO2 were sequestered in the forms of free CO2 bubble, dissolved CO2 in brine and precipitated CO2 with calcite mineral in a deep saline aquifer. The isothermal condition was assumed during injection and sequestration processes. The change in porosity and permeability values that might have occurred due to mineralization and CO2 adsorption on rock were not considered in this study. Vertical to horizontal permeability ratio and initial pressure conditions were the most dominating parameters affecting the CO2 saturation in each layer of the aquifer whereas CO2 injection rate influenced CO2 saturation in middle and bot.

Download or read book Geologic Carbon Sequestration written by V. Vishal and published by Springer. This book was released on 2016-05-11 with total page 336 pages. Available in PDF, EPUB and Kindle. Book excerpt: This exclusive compilation written by eminent experts from more than ten countries, outlines the processes and methods for geologic sequestration in different sinks. It discusses and highlights the details of individual storage types, including recent advances in the science and technology of carbon storage. The topic is of immense interest to geoscientists, reservoir engineers, environmentalists and researchers from the scientific and industrial communities working on the methodologies for carbon dioxide storage. Increasing concentrations of anthropogenic carbon dioxide in the atmosphere are often held responsible for the rising temperature of the globe. Geologic sequestration prevents atmospheric release of the waste greenhouse gases by storing them underground for geologically significant periods of time. The book addresses the need for an understanding of carbon reservoir characteristics and behavior. Other book volumes on carbon capture, utilization and storage (CCUS) attempt to cover the entire process of CCUS, but the topic of geologic sequestration is not discussed in detail. This book focuses on the recent trends and up-to-date information on different storage rock types, ranging from deep saline aquifers to coal to basaltic formations.

Download or read book Science of Carbon Storage in Deep Saline Formations written by Pania Newell and published by Elsevier. This book was released on 2018-09-06 with total page 447 pages. Available in PDF, EPUB and Kindle. Book excerpt: Science of Carbon Storage in Deep Saline Formations: Process Coupling across Time and Spatial Scales summarizes state-of-the-art research, emphasizing how the coupling of physical and chemical processes as subsurface systems re-equilibrate during and after the injection of CO2. In addition, it addresses, in an easy-to-follow way, the lack of knowledge in understanding the coupled processes related to fluid flow, geomechanics and geochemistry over time and spatial scales. The book uniquely highlights process coupling and process interplay across time and spatial scales that are relevant to geological carbon storage. - Includes the underlying scientific research, as well as the risks associated with geological carbon storage - Covers the topic of geological carbon storage from various disciplines, addressing the multi-scale and multi-physics aspects of geological carbon storage - Organized by discipline for ease of navigation

Download or read book Optimization of Multiple Wells in Carbon Sequestration written by Swathi Gangadharan and published by . This book was released on 2014 with total page 69 pages. Available in PDF, EPUB and Kindle. Book excerpt: Injection of CO2 in saline aquifers is considered as one of the best strategies for the reduction of greenhouse gases. In order to select a potential saline aquifer storage site for carbon sequestration, many parameters are considered such as relative permeability, thickness, compressibility, porosity, salinity and well interference. These are significant because they affect the CO2 storage capacity of the reservoir. The one of the most important criteria to be considered during sequestration is the pressure profile inside the reservoir as the sequestered CO2 increases the pressure within the saline formation over time. In order to maintain the integrity of the reservoir, the reservoir pressure is always maintained below the fracture pressure. Thus, modeling of pressure profile is essential as it controls the maximum amount of CO2 which can be into the reservoir. There are various analytical and numerical models to determine the bottom-hole pressure for CO2 injection. The main objective of my thesis is to examine and identify the analytical approaches in modeling of pressure profile during CO2 injection. It includes single injection as well as multiple wells injection scenarios. The second case is much more important from practical point of view and applicability of analytical tools should be validated. Two models of injection/production are considered: (i) Single-phase (brine production from a brine reservoir) and (ii) Two phase model (CO2 injection in a brine reservoir). In both cases, we analyzed the pressure build-up and discussed the results in comparison with numerical simulations. We also present a sensitivity analysis of the reservoir parameters on CO2 sequestration. The second part of the thesis focuses on finding ways to increase the CO2 injection capacity of saline aquifers by using the technique of multiple wells injection strategy. Numerous test cases will be presented to optimize the well placement and number of wells to get the maximum sequestration. The thesis will look upon the different ways to maintain the reservoir pressure below fracture pressure such as optimization of injection wells, varying the flow-rates of injection wells and by placement of relief wells to produce brine from the reservoir.

Download or read book Carbon Dioxide Sequestration Into Deep Saline Aquifers written by Emre Özgür and published by LAP Lambert Academic Publishing. This book was released on 2010-05 with total page 128 pages. Available in PDF, EPUB and Kindle. Book excerpt: The analytical and numerical modeling of CO2 sequestration in deep saline aquifers having different properties was studied with diffusion and convection mechanisms. The complete dissolution of CO2 in the aquifer by diffusion took thousands, even millions of years. In diffusion dominated system, an aquifer with 100 m thickness saturated with CO2 after 10,000,000 years. It was much earlier in convective dominant system. In diffusion process, the dissolution of CO2 in aquifer increased with porosity increase; however, in convection dominant process dissolution of CO2 in aquifer decreased with porosity increase. The increase in permeability accelerated the dissolution of CO2 in aquifer significantly, which was due to increasing velocity. The results of convective dominant mechanism in aquifers with 1md and 10 md permeability values were so close to that of diffusion dominated system. For the aquifer having permeability higher than 10 md, the convection mechanism began to dominate gradually and it became fully convection dominated system for 50 md and higher permeability values.

Download or read book An Uncertainty Analysis of Modeling Geologic Carbon Sequestration in a Naturally Fractured Reservoir at Teapot Dome Wyoming written by Ye Li and published by . This book was released on 2014 with total page 198 pages. Available in PDF, EPUB and Kindle. Book excerpt: This study presents an uncertainty analysis of Geologic Carbon Sequestration modeling in a naturally fractured reservoir at Teapot Dome, Wyoming. Structural & stratigraphic, residual, and solubility trapping mechanisms are the focus of this study, while mineral trapping is not considered. A reservoir-scale geologic model is built to model CO2 storage in the Tensleep Sandstone using a variety of site characterization data that have been collected, screened for accuracy, and analyzed. These data are from diverse sources, such as reservoir geology, geophysics, petrophysics, engineering, and analogs. Because fluid flow occurs in both matrix and fractures of the Tensleep Sandstone, both systems of heterogeneity must be incorporated into the geologic model. The matrix heterogeneity of the geologic model is developed through a hierarchical process of structural modeling, facies modeling, and petrophysical modeling. In structural modeling, the framework of the reservoir is conditioned to seismic data and well log interpretations. Based on the concept of flow units, the facies model, which is conditioned to a global vertical facies proportion curve that acts as `soft' data, is built geostatistically by the Sequential Indicator Simulation method. Then, the petrophysical properties (porosity) are modeled geostatistically within each facies through the Sequential Gaussian Simulation approach. A Discrete Fracture Network (DFN) is adopted as the method to model the distribution of open natural fractures in the reservoir. Basic inputs for the DFN model are derived from FMI logs, cores, and analogs. In addition, in combination with an artificial neural network analysis, 3D seismic attributes are used as fracture drivers to guide the modeling of fracture intensity distribution away from the boreholes. In DFN models, power laws are adopted to define the distribution of fracture intensity, length and aperture. To understand the effect of model complexity on CO2 storage predictions, a suite of increasingly simplified conceptual geologic model families are created with decreasing amount of site characterization data: a hierarchical stochastic model family conditioned to ' soft' data (FAM4), a simple stochastic facies model family (FAM3), a simple stochastic porosity model family (FAM2), and a homogeneous model family (FAM1). These families, representing alternative conceptual geologic models built with increasing reduced data, are simulated with the same CO2 injection test (20 years of injection at 1,000 Mscf/day), followed by 80 years of monitoring. Using the Design of Experiment, an efficient sensitivity analysis (SA) is conducted for all families, systematically varying uncertain input parameters, while assuming identical well configurations, injection rates, bottom-hole pressure constraints, and boundary conditions. The SA results are compared among the families to identify parameters that have the first order impact on predicting the CO2 storage ratio (SR) at two different time scales, i.e., end of injection and end of monitoring. This comparison indicates that, for this naturally fractured reservoir, the facies model is necessary to study the sensitivity characteristics of predicting the CO 2 storage behavior. The SA results identify matrix relative permeability, fracture aperture of fracture set 1, and fracture aperture of fracture set 2 as the statistically important factors. Based on the results of the SA, a response surface analysis is conducted to generate prediction envelopes of the CO2 storage ratio, which are also compared among the families at both times. Its results demonstrate that the SR variation due to the different modeling choices is relatively small. At the proposed storage site, as more than 90% of injected CO2 is probably mobile, short-term leakage risk is considered large, and it depends on the sealing ability of top formations.

Download or read book Experimental Design Applications for Modeling and Assessing Carbon Dioxide Sequestration in Saline Aquifers written by and published by . This book was released on 2014 with total page 83 pages. Available in PDF, EPUB and Kindle. Book excerpt: This project was a computer modeling effort to couple reservoir simulation and ED/RSM using Sensitivity Analysis, Uncertainty Analysis, and Optimization Methods, to assess geologic, geochemical, geomechanical, and rock-fluid effects and factors on CO2 injectivity, capacity, and plume migration. The project objective was to develop proxy models to simplify the highly complex coupled geochemical and geomechanical models in the utilization and storage of CO2 in the subsurface. The goals were to investigate and prove the feasibility of the ED/RSM processes and engineering development, and bridge the gaps regarding the uncertainty and unknowns of the many geochemical and geomechanical interacting parameters in the development and operation of anthropogenic CO2 sequestration and storage sites. The bottleneck in this workflow is the high computational effort of reactive transport simulation models and large number of input variables to optimize with ED/RSM techniques. The project was not to develop the reactive transport, geomechanical, or ED/RSM software, but was to use what was commercially and/or publically available as a proof of concept to generate proxy or surrogate models. A detailed geologic and petrographic mineral assemblage and geologic structure of the doubly plunging anticline was defined using the USDOE RMOTC formations of interest data (e.g., Lower Sundance, Crow Mountain, Alcova Limestone, and Red Peak). The assemblage of 23 minerals was primarily developed from literature data and petrophysical (well log) analysis. The assemblage and structure was input into a commercial reactive transport simulator to predict the effects of CO2 injection and complex reactions with the reservoir rock. Significant impediments were encountered during the execution phase of the project. The only known commercial reactive transport simulator was incapable of simulating complex geochemistry modeled in this project. Significant effort and project funding was expended to determine the limitations of both the commercial simulator and the Lawrence Berkeley National Laboratory (LBNL) R & D simulator, TOUGHREACT available to the project. A simplified layer cake model approximating the volume of the RMOTC targeted reservoirs was defined with 1-3 minerals eventually modeled with limited success. Modeling reactive transport in porous media requires significant computational power. In this project, up to 24 processors were used to model a limited mineral set of 1-3 minerals. In addition, geomechanical aspects of injecting CO2 into closed, semi-open, and open systems in various well completion methods was simulated. Enhanced Oil Recovery (EOR) as a storage method was not modeled. A robust and stable simulation dataset or base case was developed and used to create a master dataset with embedded instructions for input to the ED/RSM software. Little success was achieved toward the objective of the project using the commercial simulator or the LBNL simulator versions available during the time of this project. Several hundred realizations were run with the commercial simulator and ED/RSM software, most having convergence problems and terminating prematurely. A proxy model for full field CO2 injection sequestration utilization and storage was not capable of being developed with software available for this project. Though the chemistry is reasonably known and understood, based on the amount of effort and huge computational time required, predicting CO2 sequestration storage capacity in geologic formations to within the program goals of ±30% proved unsuccessful.

Download or read book Understanding the Plume Dynamics and Risk Associated with CO2 Injection in Deep Saline Aquifers written by Abhishek Kumar Gupta and published by . This book was released on 2011 with total page 506 pages. Available in PDF, EPUB and Kindle. Book excerpt: Geological 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.

Download or read book Experimental and Numarical Investigation of Carbon Dioxide Sequestration in Deep Saline Aquifers written by and published by . This book was released on 2005 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Started as an EOR technique to produce oil, injection of carbon dioxide which is essentially a greenhouse gas is becoming more and more important. Although there are a number of mathematical modeling studies, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to characterize relevant chemical reactions associated with injection and storage of CO2 in carbonate formations. Porosity changes along the core plugs and the corresponding permeability changes are reported for varying CO2 injection rates, temperature and salt concentrations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. It was observed that either a permeability improvement or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related to distribution of pores, brine composition and as well the thermodynamic conditions. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. Calcite scaling is mainly influenced by orientation and horizontal flow resulted in larger calcite deposition compared to vertical flow. The duration of CO2 – rock contact and the amount of area contacted by CO2 seems to have a more pronounced effect compared to rate effect. The experiments were modeled using a multi-phase, non-isothermal commercial simulator where solution and deposition of calcite were considered by the means of chemical reactions. The calibrated model was then used to analyze field scale injections and to model the potential CO2 sequestration capacity of a hypothetical carbonate aquifer formation. It was observed that solubility and hydrodynamic storage of CO2 is larger compared to mineral trapping.

Download or read book The Journal of Canadian Petroleum Technology written by and published by . This book was released on 2009 with total page 464 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Storage of Carbon Dioxide in Saline Aquifers written by Philip Ringrose and published by . This book was released on 2023-08 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Carbon capture and storage is part of global efforts to reduce greenhouse gas emissions. This book reviews the science and technology underpinning CO2 storage in deep saline aquifer formations using insights from several industrial-scale projects. Factors which limit storage capacity are analyzed. Then, we discuss how to optimize monitoring methods.