Fractured viscous oil resources hold great potential for continued oil production growth globally. However, many of these resources are not accessible with current commercial technologies using steam injection which limits operations to high temperatures. Several steam-solvent processes have been proposed to decrease steam usage, but they still require operating temperatures too high for many projects. There is a need for a low temperature injection strategy alternative for viscous oil production. This dissertation discusses scoping experimental work for a low temperature solvent injection strategy targeting fractured systems. The strategy combines three production mechanisms – gas-oil gravity drainage, liquid extraction, and film gravity drainage. During the initial heating period when the injected solvent is in the liquid phase, liquid extraction occurs. When the solvent is in the vapor phase, solvent-enhanced film gravity drainage occurs. A preliminary simulation of the experiments was developed to study the impact of parameter uncertainty on the model performance. Additional work on reducing uncertainty for key parameters controlling the two solvent production mechanisms will be necessary. In a natural fracture network, the solvent would not be injected uniformly throughout the reservoir. Preferential injection into the higher conductivity fracture areas would result in early breakthrough leaving unswept areas of high oil saturation. Conformance control would be necessary to divert subsequent solvent injection into the unswept zones. A variety of techniques, including polymer and silica gel treatments, have been designed to block flow through the swept zones, but all involve initiating gelation prior to injection. This dissertation also looks at a strategy that uses the salinity gradient between the injected silica nanoparticle dispersion and the in-situ formation water to trigger gelation. First, the equilibrium phase behavior of silica dispersions as a function of sodium chloride and nanoparticle concentration and temperature was determined. The dispersions exhibited three phases – a clear, stable dispersion; gel; and a viscous, unstable dispersion. The gelation time was found to decrease exponentially as a function of silica concentration, salinity, and temperature. During core flood tests under matrix and fracture injection, the in-situ formed gels were shown to provide sufficient conductivity reduction even at low nanoparticle concentration. / text

Chemical treatments using solvents and surfactants can be used to increase the productivity of gas-condensate wells with condensate banks. CMG’s compositional simulator GEM was used to simulate such treatments to gain a better understanding of design questions such as how much treatment solution to inject and to predict the benefits of such treatments. GEM was used to simulate treatments in vertical wells with and without hydraulic fractures and also horizontal wells. However, like other commercial compositional simulators, the flash calculations used to predict the phase behavior is limited to two phases whereas a three-phase flash is needed to accurately model the complex phase behavior that occurs during and after the injection of treatment solutions. UTCOMP is a compositional simulator with three-phase flash routine and attempts were made to use it to simulate such well treatments. However, this is a very difficult problem to simulate and all previous attempts failed because of numerical problems caused by inconsistent phase labeling (so called phase flipping) and the discontinuities this causes in the relative permeability values. In this research, a new relative permeability model based on molar Gibbs free energy was developed, implemented in a compositional simulator and applied to several difficult three-phase flash problems. A new way of modeling the residual saturations was needed to ensure a continuous variation of the residual saturations from the three-phase region to the two-phase region or back and was included in the new model. The new relative permeability model was implemented in the compositional reservoir simulator UTCOMP. This new relative permeability model makes it is unnecessary to identify and track the phases. This method automatically avoids the previous phase flipping problems and thus is physically accurate as well as computationally faster due to the improved numerical performance. The new code was tested by running several difficult simulation problems including a CO2 flood with three-hydrocarbon phases and a water phase. A new framework for doing flash calculations was also developed and implemented in UTCOMP to account for the multiple roots of the cubic equation-of-state to ensure a global minimum in the Gibbs free energy by doing an exhaustive search for the minimum value for one, two and three phases. The purpose was to determine if the standard method using a Gibbs stability test followed by a flash calculation was in fact resulting in the true minimum in the Gibbs free energy. Test problems were run and the results of the standard algorithm and the exhaustive search algorithm compared. The updated UTCOMP simulator was used to understand the flow back of solvents injected in gas condensate wells as part of chemical treatments. The flow back of the solvents, a short-term process, affects how well the treatment works and has been an important design and performance question for years that could not be simulated correctly until now due to the limitations of both commercial simulators and UTCOMP. Different solvents and chase gases were simulated to gain insight into how to improve the design of the chemical treatments under different conditions. / text

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