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Results
Abstract Thermodynamic modeling of phase behavior is one of the most fundamental components in the study of enhanced oil recovery by gas injection. Robust algorithms exist for multiphase equilibrium problems with no capillary pressure as commonly used in compositional reservoir simulation. However, various convergence problems have been reported even for simple two-phase split problems in the presence of capillary pressure by using the traditional algorithm based on minimization of the Gibbs free energy. In this research, the phase-split problem with capillary pressure is formulated by using the Helmholtz free energy for a given temperature and total volume. The algorithm is based on the successive substitution (SS) for updating K values, which is coupled with the volume update by using the pressure constraint equation. The robustness of the SS algorithm is improved by using the convexity information of the Helmholtz free energy. Case studies present phase-split problems with capillary pressure by using the developed algorithm and highlight several advantages of using the Helmholtz free energy over the Gibbs free energy. The improved robustness comes mainly from the involvement of a single energy surface regardless of the number of phases. The pressure variability that occurs during the phase-split calculation with capillary pressure is inherent in the Helmholtz free energy in volume space.
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Identifying and Evaluating Surfactant Additives to Reduce Water Blocks after Hydraulic Fracturing for Low Permeability Reservoirs
Liang, Tianbo (The University of Texas at Austin) | Achour, Sofiane H. (The University of Texas at Austin) | Longoria, Rafael A. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin) | Nguyen, Quoc P. (The University of Texas at Austin)
Abstract Significant amount of fracturing fluid is lost after hydraulic fracturing, and it is believed that the loss of fluid into the matrix can hinder the hydrocarbon production. One way to reduce this damage is to use the surfactants. Robust surfactant formulations have been developed for chemical enhanced oil recovery (CEOR); similar ideas are introduced in this study to reduce water blocks in low permeability reservoirs. Here we present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production within the rock near the fracture face. Different levels of IFT reductions are tested and compared in order to explore the best condition that maximizes the permeability enhancement. The effect of in-situ microemulsion generation to mobilize the trapped water is also studied. From this work, we recognize the mechanism responsible for the permeability damage in matrix and we suggest criteria to optimize the performance of surfactant additives so as to enhance the hydrocarbon production from low permeability gas/oil reservoirs after hydraulic fracturing.
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)