Browsing by Subject "CO2 injection"
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Item Advances in calculation of minimum miscibility pressure(2011-05) Ahmadi Rahmataba, Kaveh; Johns, Russell T.; Bryant, Steven L.; DiCarlo, David; Dindoruk, Birol; Sepehrnoori, KamyMinimum miscibility pressure (MMP) is a key parameter in the design of gas flooding. There are experimental and computational methods to determine MMP. Computational methods are fast and convenient alternatives to otherwise slow and expensive experimental procedures. This research focuses on the computational aspects of MMP estimation. It investigates the shortcomings of the current computational models and offers ways to improve the robustness of MMP estimation. First, we develop a new mixing cell method of estimating MMP that, unlike previous "mixing cell" methods, uses a variable number of cells and is independent of gas-oil ratio, volume of the cells, excess oil volumes, and the amount of gas injected. The new method relies entirely on robust P-T flash calculations using any cubic equation-of-state (EOS). We show that mixing cell MMPs are comparable with those of other analytical and experimental methods, and that our mixing cell method finds all the key tie lines predicted by MOC; however, the method proved to be more robust and reliable than current analytical methods. Second, we identify a number of problems with analytical methods of MMP estimation, and demonstrate them using real oil characterization examples. We show that the current MOC results, which assume that shocks exist from one key tie line to the next may not be reliable and may lead to large errors in MMP estimation. In such cases, the key tie lines determined using the MOC method do not control miscibility, likely as a result of the onset of L₁-L₂-V behavior. We explain the problem with a simplified pseudo-ternary model and offer a procedure for determining when an error exists and for improving the results. Finally, we present a simple mathematical model for predicting the MMP of contaminated gas. Injection-gas compositions often vary during the life of a gasflood because of reinjection and mixing of fluids in situ. Determining the MMP by slim-tube or other methods for each possible variation in the gas-mixture composition is impractical. Our method gives an easy and accurate way to determine impure CO₂ MMPs for variable field solvent compositions on the basis of just a few MMPs. Alternatively, the approach could be used to estimate the enrichment level required to lower the MMP to a desired pressure.Item Experimental and Simulation Studies to Evaluate the Improvement of Oil Recovery by Different Modes of CO2 Injection in Carbonate Reservoirs(2011-02-22) Aleidan, Ahmed Abdulaziz S.Experimental and numerical simulation studies were conducted to investigate the improvement of light oil recovery in carbonate cores during CO2 injection. The main steps in the study are as follows. First, the minimum miscibility pressure of 31?API west Texas oil and CO2 was measured using the slimtube (miscibility) apparatus. Second, miscible CO2 coreflood experiments were carried out on different modes of injection such as CGI, WF, WAG, and SWAG. Each injection mode was conducted on unfractured and fractured cores. Fractured cores included two types of fracture systems creating two shape models on the core. Also, runs were made with different salinity levels for the injected water, 0 ppm, 60,000 ppm, and 200,000 ppm. Finally, based on the experimental results, a 2-D numerical simulation model was constructed and validated. The simulation model was then extended to conduct sensitivity studies on different parameters such as permeability variations in the core, WAG ratio and slug size, and SWAG ratio. The results of this study indicate that injecting water with CO2 either simultaneously or in alternating cycles increases the oil recovery by at least 10 percent and reduces the CO2 requirements by 50 percent. The salinity of the injected water has shown a detrimental effect on oil recovery only during WAG and SWAG injections. Lowering injected water salinity, which increases the CO2 solubility in water, increases oil recovery by up to 18 percent. Unfractured cores resulted in higher recovery than all fractured ones. CGI in fractured cores resulted in very poor recovery but WAG and SWAG injections improved the oil recovery by at least 25 percent over CGI. This is because of the better conformance provided by the injected water, which decreased CO2 cycling through the fracture. CO2 injection in layered permeability arrangements showed significant decrease in oil recovery (up to 40 percent) compared to the homogenous case. For all injection modes during the layered permeability arrangements, the best oil recovery was obtained when the flow barrier is in the middle of the core. When the permeability was arranged in sequence, each injection mode showed different preference to the permeability arrangements. The WAG ratio study in the homogenous case showed that a 1:2 ratio had the highest oil recovery, but the optimum ratio was 1:1 based on the amount of injected CO2. In contrast, layered permeability arrangements showed different WAG ratio preference depending on the location of the flow barrier.Item A simulation study of injected CO₂ migration in the faulted reservoir(2007-05) Chang, Kyung Won; Bryant, Steven L.; Pope, G.A.The injection and underground storage of carbon dioxide, CO₂, can reduce anthropogenic (human-generated) emissions of greenhouse gases into the atmosphere. Accordingly, the CO₂ sequestration into a deep saline aquifer is a subject of intensive study with current reservoir simulators incorporating dissolution, dispersion of CO₂ in water, and chemical reactions of CO₂ with existing phases and host rock. However, there is little information in the literature on the numerical analysis of the structural aspect of CO₂ sequestration. The purpose of this simulation study is to understand the effects of geomechanical structures, especially faults, on the behavior of injected CO₂ The GEM (Generalized Equation-of-State Model) Compositional Reservoir Simulator is used to observe how fault-related structure impacts behavior of injected CO₂ in the saline formation. Three main tasks are categorized as follows: 1) Comparison of the analytical approach for fluid distribution, based on Buckley-Leverett theory, with the simulation results; 2) Simulation study which illustrates the impact of fault properties on the behavior of carbon dioxide phase in a CO₂ and a H₂O (brine) saturated reservoir; 3) Simulation study which shows the effect of leakage through the fault (due to geologic imperfections) during the CO₂ migration These fault-scale interactions can play an important role in determining CO₂ and storage depending on whether the faults act as barriers, conduits or combined barrier-conduits. The simulator outputs reveal that each property of the fault as a barrier and also a conduit can restrict the migration of CO₂ through the reservoir as a consequence of compartmentalization (barrier) and bypassing (conduit). This study concludes that the properties of a fault and the interactions between the fault and the reservoir matrix can play a critical role in quantifying the behavior of CO₂ after injection ends. A fault within the target formation can have a positive or negative effect on the capture of the buoyancy-driven CO₂ with residual trapping mechanism depending on its geometry and/or petrophysical property. Accordingly, when it comes to the injection and storage of CO₂, an accurate prediction of the fault conductivity and petrophysical properties of the reservoir would be required to optimize the rate of injection and the storage capacity of the reservoir for the permanent capture of CO2.Item Sustainable Carbon Sequestration: Increasing CO2-Storage Efficiency through a CO2-Brine Displacement Approach(2012-10-19) Akinnikawe, OyewandeCO2 sequestration is one of the proposed methods for reducing anthropogenic CO2 emissions to the atmosphere and therefore mitigating global climate change. Few studies on storing CO2 in an aquifer have been conducted on a regional scale. This study offers a conceptual approach to increasing the storage efficiency of CO2 injection in saline formations and investigates what an actual CO2 storage project might entail using field data for the Woodbine aquifer in East Texas. The study considers three aquifer management strategies for injecting CO2 emissions from nearby coal-fired power plants into the Woodbine aquifer. The aquifer management strategies studied are bulk CO2 injection, and two CO2-brine displacement strategies. A conceptual model performed with homogeneous and average reservoir properties reveals that bulk injection of CO2 pressurizes the aquifer, has a storage efficiency of 0.46% and can only last for 20 years without risk of fracturing the CO2 injection wells. The CO2-brine displacement strategy can continue injecting CO2 for as many as 240 years until CO2 begins to break through in the production wells. This offers 12 times greater CO2 storage efficiency than the bulk injection strategy. A full field simulation with a geological model based on existing aquifer data validates the storage capacity claims made by the conceptual model. A key feature in the geological model is the Mexia-Talco fault system that serves as a likely boundary between the saline aquifer region suitable for CO2 storage and an updip fresh water region. Simulation results show that CO2 does not leak into the fresh water region of the iv aquifer after 1000 years of monitoring if the faults have zero transmissibility, but a negligible volume of brine eventually gets through the mostly sealing fault system as pressure across the faults slowly equilibrates during the monitoring period. However, for fault transmissibilities of 0.1 and 1, both brine and CO2 leak into the fresh water aquifer in increasing amounts for both bulk injection and CO2-brine displacement strategies. In addition, brine production wells draw some fresh water into the saline aquifer if the Mexia-Talco fault system is not sealing. A CO2 storage project in the Woodbine aquifer would impact as many as 15 counties with high-pressure CO2 pipelines stretching as long as 875 km from the CO2 source to the injection site. The required percentage of power plant energy capacity was 7.43% for bulk injection, 7.9% for the external brine disposal case, and 10.2% for the internal saturated brine injection case. The estimated total cost was $0.00132?$0.00146/kWh for the bulk injection, $0.00191?$0.00211/kWh for the external brine disposal case, and $0.0019?$0.00209/kWh for the internal saturated brine injection case.