Ethane miscibility correlations and their applications to oil shale reservoirs
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Compositional simulation studies were performed to evaluate the practicality and efficiency of using ethane as an enriching solvent in miscible displacements. More than 1,300 compositional simulation runs were used to build ethane minimum miscibility correlations. The miscibility conditions of four different reservoir fluids by mixtures of methane and ethane were determined for a range of pressures and temperatures. Correlations were built for pressures from 1,500 to 4,000 psi and temperatures from 100 to 260 °F. The correlations were modeled after Benham's et al. (1959) findings and they were obtained using reservoir pressure, temperature and the C₅+ molecular weight of the displaced fluid. The correlations were checked using data from the literature and with results obtained using other methods. The correlations are in good agreement with other data and showed a deviation of 5 to10 mole % in the predicted ethane minimum miscibility enrichment. As a second part of this study, additional compositional reservoir simulation models were used to assess the feasibility of using ethane as a solvent in shale reservoirs. The obtained correlations in the first part of this study were used to predict the minimum miscibility condition in shale reservoirs. Based on cumulative oil recovered and sweep efficiency at simulation termination, results suggest that miscible ethane injection performs better than water injection, water alternating gas, and immiscible gas injection. Sensitivity analysis was performed on shale reservoirs models with permeabilities of 0.1 md and 0.001 md. Parameters such as injector-producer spacing, fracture spacing, and injector placement were evaluated. In the 0.1 md formations, simulation results suggest that cumulative production depends strongly on spacing. Assuming a one well pair in the 6000 ft × 6000 ft area, wider injector-producer spacing and fracture spacing produces more oil compared to close spacing because of the larger swept volume. Likewise, placing injectors on top of the producer showed some improvement in the oil recovery compared to placing producer and injector next to each other. On the other hand, results show that it is very difficult to inject any fluid in formations with permeabilities in the range of 0.001 md. Close injector-producer spacing does not show any increase in recovery because the injected fluid does not reach the producer. The simulation results show that even an injector-producer spacing of more than 120 ft does not exhibit any difference in the recovery. Fracture spacing, on the other hand, shows some increase in the oil recovery because of the increase in the stimulated volume around the injector. In contrast to the 0.1 md reservoirs, results suggest that cumulative oil production is less dependent on the type of injected fluid. Water, miscible and immiscible injection show similar results. Saturation maps and injected pore volume calculations show that there is little matrix contribution and almost all production is dominated by fractures. Therefore, any sort of injection might not be considered a practical option.