Browsing by Subject "Compositional simulation"
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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 Compositional three-phase relative permeability and capillary pressure models using Gibbs free energy(2016-08) Sadeghi Neshat, Sajjad; Pope, G. A.; Ezekoye, Ofodike E.; Lake, LarryBoth relative permeability and capillary pressure depend on composition as well as saturation, but classical models neglect this dependence. The objective of this research was to develop coupled three-phase relative permeability and capillary pressure models for implementation in a four-phase flow compositional equation-of-state simulator. The models applied to several complex but practical reservoir simulation problems. Models independent of phase label have many advantages in terms of both numerical stability and physical consistency. Identification of hydrocarbon and aqueous phases based on their molar Gibbs Free Energy (GFE) is a key feature of the new model. Instead of using labels (gas/oil/2nd liquid/aqueous) to define permeability parameters such as end points, residual saturation and exponents, the parameters are continuously interpolated between reference values using the Gibbs free energy of each phase at each time step. Consequently, the formulation used to implement other relevant physical parameters must be consistent with the new approach. A comprehensive but simple vii algorithm was developed for this purpose. The algorithm allows for very general threephase hysteresis in both relative permeability and capillary pressure. An important part of this thesis is analyzing the results of a recent series of experiments on the effect composition on relative permeability. These new data were used to calibrate the new GFE relative permeability model and apply it in a compositional reservoir simulator. The robustness of the new GFE model was shown through complex simulations such as solvent flooding, miscible/immiscible WAG processes, well stimulation processes using solvents to remove condensate and/or water blocks in both conventional and unconventional formations and other challenging applications involving both mass transfer between phases and phase changes. The interpolation of relative permeability parameters based on GFE instead of phase labels completely solves the discontinuity problem caused by phase flipping or misidentification. Therefore, simulations run significantly faster and are physically correct. The novelty of this research is in integrating and unifying relevant physical parameters including trapping number, hysteresis and capillary pressure into one rigorous algorithm with compositional consistency and in the development and application of a practical procedure for numerical compositional reservoir simulations.Item Improvements in phase behavior modeling for compositional simulation(2015-05) Rezaveisi, Mohsen; Sepehrnoori, Kamy, 1951-; Johns, Russell T.; Pope, Gary A; Delshad, Mojdeh; Mohanty, Kishore KAccurate and reliable phase equilibrium calculations are among the most important issues in compositional reservoir simulation of enhanced oil recovery (EOR) processes especially miscible gas floods. The important challenges in equation of state (EOS)-based compositional simulators are the time-consuming nature of the phase equilibrium calculations, e.g. 30%-50% of the total computational time in the UTCOMP simulator (Chang, 1990), and accuracy as well as robustness of these calculations. Thus, increasing the computational speed and robustness of the phase equilibrium calculations is of utmost importance in IMPEC-type and fully implicit reservoir simulators. Furthermore, most current compositional reservoir simulators ignore the effect of capillary pressure in porous media on the fluid’s phase behavior. This assumption may lead to significant errors in performance prediction of tight oil and shale gas reservoirs where the small pore sizes result in very large capillary pressure values. The “tie-simplex-based (TSB) phase behavior modeling” techniques attempt to speed up phase behavior calculations by skipping stability analysis and preconditioning phase-split calculations. We implemented the compositional space adaptive tabulation (CSAT), a TSB phase behavior modeling method, in UTCOMP and compared the computational performance of CSAT when used for skipping stability analysis and generating initial estimates for flash calculations, against the standard phase behavior modeling methods in UTCOMP. The results show that the CSAT method as well as a simple heuristic technique, where stability analysis is skipped for single-phase gridblocks surrounded by single phase neighbors, can improve the total computational time by up to 30% compared to the original UTCOMP. In order to avoid the negative-flash calculations required for adaptive tie-line tabulation during the simulation, a prior set of tie-line tables can be used. We demonstrate that the tie lines from the multiple-mixing-cell (MMC) method are very close to the actual compositional simulation tie lines. Thus, the MMC tie lines were used as prior tieline tables in three tie-line-based K-value simulation methods in order to improve speed and robustness of compositional simulation. Several simulation case studies were performed to compare the computational efficiency of the three MMC-based methods, an extended CSAT method (adaptive K-value simulation) and a method based on pure heuristic techniques against the original UTCOMP formulation. The results show that the MMC-based methods and the extended CSAT method can improve the total computational time by up to 50% with acceptable accuracy for the cases studied. The MMC-based methods, the CSAT method and the heuristic methods were implemented in the natural variable formulation in the fully-implicit General Purpose Adaptive Simulator (GPAS) for speeding up the phase equilibrium calculations. The computational efficiency results for several cases that we studied show that the CSAT method and the MMC-based method improve the computational time of the phase equilibrium calculations by up to 78% in the multi-contact-miscible gas injection cases studied. Finally, we present a Gibbs free energy analysis of capillary equilibrium and demonstrate that there is a limiting maximum capillary pressure (P[subscript cmax]) where gas/oil capillary equilibrium is possible and formulate the P [subscript cmax] limit using the spinodal condition of the phase of smaller pressure in capillary equilibrium. The effect of capillary pressure on phase behavior was implemented in the UTCOMP simulator and several simulation case studies in shale gas and tight oil reservoirs were performed. The simulation results illustrate the effect of capillary pressure on production behavior in shale gas and tight oil reservoirs.