Browsing by Subject "CO2 storage"
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Item Carbon Dioxide Storage in Deltaic Saline Aquifers: Invasion Percolation and Compositional Simulation(2021) Tavassoli, Shayan; Krishnamurthy Prasanna; Beckham, Emily; Meckel, Tip A.; Sepehrnoori, KamyItem CO₂ trapping mechanisms assessment using numerical and analytical methods(2020-01-30) Hosseininoosheri, Pooneh; Lake, Larry W.; Werth, Charles J.Carbon capture and storage (CCS) is a proven technique for reducing greenhouse gas emissions and climate change. Although monitoring shows that CO₂ can be safely stored underground, CO₂ leakage is still of concern. Therefore, understanding and forecasting the CO₂ distribution over a geological time is necessary to assess the storage performance and related risks. To understand the CO₂ distribution during or/and after a CCS process, four main trapping mechanisms have been introduced: stratigraphic (structural) trapping, residual trapping, solubility trapping, and mineral trapping. The relative contribution of each mechanism in CO₂ sequestration is expected to change over time as CO₂ migrates and reacts with formation rock and fluids. Although structural trapping is the most active trapping mechanism after CO₂ injection, some of the structurally trapped CO₂ dissolves into water with the rest becoming residual over time. Both the residual and dissolved CO₂ then react with rock and trap some of the CO₂, the process of which is recognized as part of mineral trapping. The relative contribution of different trapping mechanisms depends on different parameters, such as the type of geologic sink (i.e., saline aquifers, hydrocarbon reservoirs), and the properties of the reservoir fluids contained. Additionally, in the case of CO₂-EOR/storage the importance of different trapping mechanisms may change depending on the CO₂ injection strategy (e.g., water alternating gas, WAG; continuous gas injection, CGI; water curtain injection, WCI). In this dissertation, I investigate the CO₂ trapping mechanisms in two CCS processes: CO₂-EOR/storage and CO₂ injection in dipping aquifers. First, I investigate the CO₂ trapping mechanisms during and after a CO₂-EOR process using reservoir simulation. The main purpose is to answer questions associated with the relationship between EOR operational strategies and CO₂ utilization ratios, and to understand the impact of the different CO₂ trapping mechanisms on this relationship. To answer these questions, I integrate three main elements of field assessment: physical field characterization, production and pressure history, and reservoir simulation. I use this method to model and compare two fields that represent two different reservoir settings: Cranfield (representative of the U.S. Gulf Coast sandstone reservoirs) and SACROC (representative of the Permian Basin carbonate reservoirs). CGI is the original operating strategy in Cranfield and WAG is the original operating strategy applied in the SACROC unit. Second, I investigate the impact of relative permeability on the trapping mechanisms in a CO₂-EOR process using fractional flow analysis and reservoir simulation. I use the fractional flow theory for miscible displacement to analytically and graphically analyze the distribution of CO₂ trappings. I use the Cranfield model to show the impact of relative permeability on field predictions. I discuss the relative permeability impact on four different CO₂ injection schemes: continuous gas injection (CGI), water alternating gas injection (WAG), water curtain injection (WCI), and WCI+WAG. Third, I introduce a mathematical model, derived from force balance, to predict CO₂ plume migration in dipping aquifers. This model calculates the down and up-dip extension of CO₂ plume in the absence of trapping mechanisms. The force balance shows that there is a point in the down-dip flow where buoyancy and viscous forces are equal and the plume cannot extend further. However, in the up-dip flow, where the direction of viscous and buoyancy forces are the same, the plume migrates upward for an unlimited time. I validate the mathematical model against numerical simulation results. I introduce an effective relative permeability correlation to capture the competition between water and CO₂. I adjust the permeability of the aquifer to validate the mathematical model against heterogeneous cases. The results show that the heterogeneity-induced error is small if we use the near well-bore average permeability. I also investigate the effect of local capillary trapping on the plume shape. Using numerical simulation, I apply capillary trapping and show how capillary forces prevent the buoyant CO₂ from migrating up-dip.Item Fault reactivation and CO₂ migration in carbon storage(2018-10-05) Ryu, Jenny; Balhoff, Matthew T.; Espinoza, David N.Injection of carbon dioxide (CO₂) underground is considered one of the possible solutions to address the increasing concentration of greenhouse gases in the atmosphere. Long-term integrity and practical storage of CO₂ is contingent upon its seal performance and the dynamic sealing capacity of faults for CO₂ storage site. Faults are prone to reactivation with reservoir pressurization caused by CO₂ injection. The goal of this research is to create and verify a model capable of capturing fault reactivation and the resulting change of permeability. This model is then used to quantify the effects of various boundary conditions, injection scheme, and capillary entry pressure on not only the reactivation of faults but also on the potential CO₂ migration along the fault.Item Gel reaction and permeability modification for CO2 leakage remediation and flood conformance(2020-08-14) Moneke, Kenechukwu; Balhoff, Matthew T.; DiCarlo, David Anthony, 1969-Carbon Capture and Storage (CCS) program, also known as CO2 sequestration, has been proposed as a long-term process to mitigate emissions of greenhouse gases such as CO2 in the atmosphere. One of the biggest challenges associated with the CO2 sequestration process is the migration and leakage of the CO2 due to the formation of leakage pathways which weakens the integrity of the reservoir caprock. To ensure the CO2 storage effectiveness and minimize the environmental and economic risk, it is important to monitor the subsurface CO2 migration and apply a treatment method if leakage is detected. One of the potential treatment methods to mitigate the leakage challenge in the CCS program is the use of chemical sealants such as silicate gel. The concentrated potassium silicate solution (i.e. silicate gel) reacts with the dissolved CO2 species to form a silica gel barrier which prevents the captured CO2 from escaping into the atmosphere and reduces the reservoir permeability. This thesis aims to evaluate the potential of silica gel as leakage prevention and remediation measure during the CO2 sequestration process. The use of the silica gel as a permeability modifier, conformance control agent and an effective cap rock sealant was also investigated. The mother solution used in these experiments is Betol K28T diluted with deionized water (50 wt.%) which acts as the silicate gel being investigated. Bulk gelation experiments were initially performed to measure the gel time at different silicate content, acid concentrations, salinities, and temperatures. The results were then fit to an existing model for gelation time and then used as a predictive tool for the core flood experiments. Core flood experiments were then performed to investigate the reaction transport of silicate gel in porous media, compare the results obtained from gelation in porous media to the gelation results from the earlier bulk experiments and finally, investigate the capability of the gel in permeability reduction and sealing of the core. These core flood experiments were conducted in two conditions: ambient condition with an acetic acid solution as a CO2 substitute and the High-Pressure High-Temperature (1500 psi, 600C, 30,000ppm) condition with CO2 saturated brine. From the core flood experiments, it is shown that using potassium silicate reagents (Betol K28T) to form a silica gel barrier is an applicable strategy for mitigating the risk of CO2 leakage Reduction in the core permeability (up to 90%) of the Benthemier sandstone core was observed during barrier formation. However, to further validate the use of the silica gel to form a chemical barrier under CO2 storage conditions, additional modeling and experiments using micromodel chips and field-scale conditions are recommendedItem Modeling CO₂ leakage from geological storage formation and reducing the associated risk(2012-08) Tao, Qing, Ph. D.; Bryant, Steven L.; Hesse, Marc A.; Sepehrnoori, Kamy; DiCarlo, David; Prodanović, MašaLarge-scale geological storage of CO₂ is likely to bring CO₂ plumes into contact with existing wellbores and faults, which can act as pathways for leakage of stored CO₂ Modeling the flux of CO₂ along a leaky pathway requires transport properties along the pathway. We provide an approach based on the analogy between the leakage pathway in wells that exhibit sustained casing pressure (SCP) and the rate-limiting part of the leakage pathway in any wellbore that CO₂ might encounter. By using field observations of SCP to estimate transport properties of a CO₂ leakage pathway, we obtain a range of CO₂ fluxes for the cases of buoyancy-driven (post-injection) and pressure-driven (during injection) leakage. The fluxes in example wells range from background levels to three orders of magnitude higher than flux at the natural CO₂ seep in Crystal Geyser, Utah. We estimate a plausible range of fault properties from field data in the Mahogany Field using a shale gouge ratio correlation. The estimated worst-case CO₂ flux is slightly above background range. The flux along fault could be attenuated to zero by permeable layers that intersect the fault. The attenuation is temporary if layers are sealed at other end. Counterintuitively, greater elevation in pressure at the base of the fault can result in less CO₂ leakage at the top of the fault, because the capillary entry pressure is exceeded for more permeable layers. Since non-negligible leakage rates are possible along wellbores, it is important to be able to diagnose whether leakage is occurring. Concurrent pressure and temperature measurements are especially valuable because they independently constrain the effective permeability of a leakage path along wellbore. We describe a simple set of coupled analytical models that enable diagnosis of above-zone monitoring data. Application to data from a monitoring well during two years of steady CO₂ injection shows that the observed pressure elevation requires a model with an extremely large leakage rate, while the temperature model shows that this rate would be large enough to raise the temperature in the monitoring zone significantly, which is not observed. The observation well is unlikely to be leaking. Extraction of brine from the aquifer offers advantage over standard storage procedure by greatly mitigating pressure elevation during CO₂ injection. A proper management of the injection process helps reduce the risk of leakage associated with wellbores and faults. We provide strategies that optimize the injection of CO₂ which involve extraction of brine in two scenarios, namely injecting dissolved CO₂ and supercritical CO₂. For surface dissolution case we are concerned with bubble point contour, while for supercritical CO₂ injection we are concerned with breakthrough of CO₂ at extractors. In a surface dissolution project, the CO₂ concentration front shape when it reaches the saturation pressure contour defines the maximum areal extent of CO₂-saturated brine and hence the aquifer utilization efficiency. We illustrate the reduction of utilization efficiency due to heterogeneity of the aquifer. We develop an optimal control strategy of the injection/extraction rates to maximize the utilization efficiency. We further propose an optimal well pattern orientation strategy. Results show that the approach nearly compensates the reduction of utilization efficiency due to heterogeneity. In a supercritical CO₂ injection that involves brine extraction, the problem of avoiding breakthrough of CO₂ at extraction wells can be addressed by optimizing flow rates at each extractor and injector to delay breakthrough as long as possible. We use the Capacitance-Resistive Model (CRM) to conduct the optimization. CRM runs rapidly and requires no prior geologic model. Fitting the model to data recorded during early stages of CO₂ injection characterizes the connectivities between injection and brine-extraction wells. The fitted model parameters are used to optimize subsequent CO₂ injection in the formation. Field illustration shows a significant improvement in CO₂ storage efficiency.Item Storage of Carbon Dioxide in Saline Aquifers: Physicochemical Processes, Key Constraints, and Scale-Up Potential(2021) Ringrose, Philip S.; Furre, Anne-Kari; Gilfillan, Stuart M.V.; Krevor, Samuel; Landrø, Martin; Leslie, Rory; Meckel, Tip A.; Nazarian, Bamshad; Zahid, AdeelCO2 storage in saline aquifers offers a realistic means of achieving globally significant reductions in greenhouse gas emissions at the scale of billions of tonnes per year. We review insights into the processes involved using well-documented industrial-scale projects, supported by a range of laboratory analyses, field studies, and flow simulations. The main topics we address are (a) the significant physicochemical processes, (b) the factors limiting CO2 storage capacity, and (c) the requirements for global scale-up.Although CO2 capture and storage (CCS) technology can be considered mature and proven, it requires significant and rapid scale-up to meet the objectives of the Paris Climate Agreement. The projected growth in the number of CO2 injection wells required is significantly lower than the historic petroleum industry drill rates, indicating that decarbonization via CCS is a highly credible and affordable ambition for modern human society. Several technology developments are needed to reduce deployment costs and to stimulate widespread adoption of this technology, and these should focus on demonstration of long-term retention and safety of CO2 storage and development of smart ways of handling injection wells and pressure, cost-effective monitoring solutions, and deployment of CCS hubs with associated infrastructure.