Risk Assessment Based on Single Porosity, Alpha Factor, Dual Porosity Simulation of a Naturally Fractured Rich Gas Condensate Reservoir

Abstract

Abstract Modeling naturally fractured reservoirs is difficult because of the need to characterize the fractures, matrix and the matrix-fracture interaction. It becomes more challenging if the naturally fractured reservoir produces wet gas, condensates and water. Three different three dimensional, compositional models--single-porosity (SP), single-porosity with alpha factor (SPWAF), and dual-porosity single permeability (DPSP) of the study area, were studied. The models were calibrated against measured pressure, historical oil production, layer contributions and gas-oil ratios. The calibrated models were then used to forecast the performance of wells in the study area. The impacts of the methodology of describing the natural fractures on fluid flow behavior and recovery mechanisms, as well as on the ultimate hydrocarbon recovery were evaluated. The results also were used to ascertain the risks of selecting the optimum methodology for the field development plan. The forecasted results show little variations in oil recovery, pressure and oil saturation distributions under identical operating strategy for the three models. This is attributed to the absence of some critical properties required to model the oil recovery mechanisms in dual porosity system. For example, imbibition capillary and relative permeability functions were not input in the dual porosity (DPSP) model. However, the DPSP model is considered more efficient than the single porosity (SP and SPWAF) models because it took less time and modifications to obtain reasonable history match of the field performance. It was also more difficult to obtain a reasonable and acceptable history match using the SP and SPWAF models compared to the DPSP model, and the reservoir properties in the single porosity models had to be modified extensively and unrealistically to obtain history match.