Numerical simulation and interpretation of borehole fluid-production measurements



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Downhole production measurements are periodically acquired in hydrocarbon reservoirs to monitor and diagnose fluid movement in the borehole and the near-borehole region. However, because of the complexity involved with physical modeling and numerical implementation of borehole and formation multiphase flow behavior, inference of near-borehole petrophysical properties from production measurements is limited to simplified single-phase reservoir models. This dissertation develops a new transient coupled borehole-formation fluid flow algorithm to numerically simulate two-phase production logs (PL) acquired across heterogeneous rock formations penetrated by vertical and deviated boreholes. Subsequently, the coupled flow algorithm is used to estimate relevant dynamic petrophysical properties from borehole production measurements. The developed reservoir-borehole fluid flow model is based on an isothermal, one-dimensional (borehole axis) version of two-fluid formulation that simulates simultaneous flow of two fluid phases in oil-water, oil-gas, and gas-water flowing systems. Linkage of borehole and formation fluid flow models is carried out by introducing additional source terms into borehole mass conservation equations. Transient simulation of two-phase production measurements indicates the presence of borehole cross-flow when performing a shut-in test across differentially-depleted multilayer reservoirs. In a two-layer synthetic reservoir model penetrated by a vertical borehole, only two hours of through-the-borehole cross-communication of differentially-depleted layers gives rise to more than 14% increase in volume-averaged oil-phase relative permeability of the low-pressure layer. Simulated borehole fluid properties in the presence of cross-flow are used to estimate formation average pressure from two-phase selective-inflow-performance analysis. A new inversion-based interpretation algorithm is developed to estimate near-borehole absolute permeability and fluid-phase saturation from two-phase production logs. The inversion algorithm integrates production logs acquired in time-lapse mode to construct a near-borehole reservoir model that describes depth variations of skin factor over the elapsed time. Feasibility studies using synthetic reservoir models show that the estimated petrophysical properties are adversely influenced by the large volume of investigation associated with PL measurements. Moreover, undetectable fluid production across low-permeability layers decreases the sensitivity of production logs to layer incremental flow rate, thus increasing estimation uncertainty. Despite these limitations, the estimated fluid saturation and permeability across high-permeability layers are within 25% and 20% of the corresponding actual values, respectively. Oil-water and oil-gas flowing systems are additionally studied to quantify the added value of remedial workover operations (e.g., water and gas shut-off). Simulation of a gas shut-off performed in a gas-oil field example recommends a minimum bottom-hole pressure to prevent high gas production caused by (i) gas coning effects, and (ii) released gas from oil solution. Maintaining bottom-hole pressure above that limit gives rise to more than 60% reduction of downhole gas production.