Browsing by Subject "Gas injection"
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Item Advanced equation of state modeling for compositional simulation of gas floods(2013-12) Mohebbinia, Saeedeh; Sepehrnoori, Kamy, 1951-; Johns, Russell T.Multiple hydrocarbon phases are observed during miscible gas floods. The possible phases that result from a gas flood include a vapor phase, an oleic phase, a solvent-rich phase, a solid phase, and an aqueous phase. The solid phase primarily consists of aggregated asphaltene particles. Asphaltenes can block pore throats or change the formation wettability, and thereby reduce the hydrocarbon mobility. The dissolution of injected gas into the aqueous phase can also affect the gas flooding recovery because it reduces the amount of gas available to contact oil. This is more important in CO₂ flooding as the solubility of CO₂ in brine is much higher than hydrocarbons. In this research, we developed efficient and fast multi-phase equilibrium calculation algorithms to model phase behavior of asphaltenes and the aqueous phase in the compositional simulation of gas floods. The PC-SAFT equation of state is implemented in the UTCOMP simulator to model asphaltene precipitation. The additional computational time of PC-SAFT is substantially decreased by improving the root finding algorithm and calculating the derivatives analytically. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate dynamics of precipitated asphaltenes. Asphaltene deposition is shown to occur with pressure depletion around the production well and/or with gas injection in the reservoir domain that is swept by injected gas. It is observed that the profile of the damaged area by asphaltene deposition depends on the reservoir fluid. A general strategy is proposed to model the phase behavior of CO₂/hydrocarbon/water systems where four equilibrium phases exist. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of CO₂/hydrocarbon mixtures. The results show changes in the phase splits and saturation pressures by adding water to these CO₂/hydrocarbon systems. We used a reduced flash approach to reduce the additional computational time of the four-phase flash calculations,. The results show a significant speed-up in flash calculations using the reduced method. The computational advantage of the reduced method increases rapidly with the number of phases and components. We also decreased the computational time of the equilibrium calculations in UTCOMP by changing the sequential steps in the flash calculation where it checks the previous time-step results as the initial guess for the current time-step. The improved algorithm can skip a large number of flash calculation and stability analyses without loss of accuracy.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 Gibbs free energy minimization for flow in porous media(2014-05) Venkatraman, Ashwin; Lake, Larry W.; Johns, Russell T.CO₂ injection in oil reservoirs provides the dual benefit of increasing oil recovery as well as sequestration. Compositional simulations using phase behavior calculations are used to model miscibility and estimate oil recovery. The injected CO₂, however, is known to react with brine. The precipitation and dissolution reactions, especially with carbonate rocks, can have undesirable consequences. The geochemical reactions can also change the mole numbers of components and impact the phase behavior of hydrocarbons. A Gibbs free energy framework that integrates phase equilibrium computations and geochemical reactions is presented in this dissertation. This framework uses the Gibbs free energy function to unify different phase descriptions - Equation of State (EOS) for hydrocarbon components and activity coefficient model for aqueous phase components. A Gibbs free energy minimization model was developed to obtain the equilibrium composition for a system with not just phase equilibrium (no reactions) but also phase and chemical equilibrium (with reactions). This model is adaptable to different reservoirs and can be incorporated in compositional simulators. The Gibbs free energy model is used for two batch calculation applications. In the first application, solubility models are developed for acid gases (CO₂ /H2 S) in water as well as brine at high pressures (0.1 - 80 MPa) and high temperatures (298-393 K). The solubility models are useful for formulating acid gas injection schemes to ensure continuous production from contaminated gas fields as well as for CO₂ sequestration. In the second application, the Gibbs free energy approach is used to predict the phase behavior of hydrocarbon mixtures - CO₂ -nC₁₄ H₃₀ and CH₄ -CO₂. The Gibbs free energy model is also used to predict the impact of geochemical reactions on the phase behavior of these two hydrocarbon mixtures. The Gibbs free energy model is integrated with flow using operator splitting to model an application of cation exchange reactions between aqueous phase and the solid surface. A 1-D numerical model to predict effluent concentration for a system with three cations using the Gibbs free energy minimization approach was observed to be faster than an equivalent stoichiometric approach. Analytical solutions were also developed for this system using the hyperbolic theory of conservation laws and are compared with experimental results available at laboratory and field scales.Item Mobility control of chemical EOR fluids using foam in highly fractured reservoirs(2011-05) Gonzaléz Llama, Oscar; Nguyen, Quoc P.; Pope, Gary A.; Mohanty, KishoreHighly fractured and vuggy oil reservoirs represent a challenge for enhanced oil recovery (EOR) methods. The fractured networks provide flow paths several orders of magnitude greater than the rock matrix. Common enhanced oil recovery methods, including gases or low viscosity liquids, are used to channel through the high permeability fracture networks causing poor sweep efficiency and early breakthrough. The purpose of this research is to determine the feasibility of using foam in highly fractured reservoirs to produce oil-rich zones. Multiple surfactant formulations specifically tailored for a distinct oil type were analyzed by aqueous stability and foam stability tests. Several core floods were performed and targeted effects such as foam quality, injection rate, injection type, permeability, gas saturation, wettability, capillary pressure, diffusion, foam squeezing, oil flow, microemulsion flow and gravity segregation. Ultimately, foam was successfully propagated under various core geometries, initial conditions and injections methods. Consequently, fluids were able to divert to unswept matrix and improve the ultimate oil recovery.Item Reservoir simulation and optimization of CO₂ huff-and-puff operations in the Bakken Shale(2014-08) Sanchez Rivera, Daniel; Balhoff, Matthew T.; Mohanty, Kishore KumarA numerical reservoir model was created to optimize CO₂ Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery treatment in which a well alternates between injection, soaking, and production. Injecting CO₂ into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator was used to study the various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical CO₂ injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO₂ to migrate deep into the formation and mix with the reservoir fluids. The discretization of the computational domain has a large impact on the simulation results, with coarser gridding corresponding to larger projected recoveries. Doubling the number of hydraulic fractures per stage results in considerably greater CO₂ injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO₂ Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO₂ and produced hydrocarbon gases was proven to be technically and economically viable, which could significantly improve profit margins of Huff-and-Puff operations. A substantial portion of this project involved studying alternative numerical methods for modeling hydraulically-fractured reservoir models. A domain decomposition technique known as mortar coupling was used to model the reservoir system as two individually-solved subdomains: fracture and matrix. A mortar-based numerical reservoir simulator was developed and its results compared to a tradition full-domain finite difference model for the Cinco-Ley et al. (1978) finite-conductivity vertical fracture problem. Despite some numerical issues, mortar coupling closely matched Cinco-Ley et al.'s (1978) solution and has potential applications in complex problems where decoupling the fracture-matrix system might be advantageous.