Publications

This is the second half of the B-Field Reservoir Characterization and Simulation study. It focuses on some unique simulation modeling to characterize the B-field excess permeability including single porosity and permeability models and dual porosity, dual permeability (DPDP) models. The extensive formation evaluation program for the large carbonate oil field shows that production will be impacted by geologic features such as karst and fractures which generally render excess permeability in addition to the matrix properties. Karst and fractures can be very effective to enhance productivity but they can also provide detrimental connection between the producing oil zone and the overlying gas and underlying water zones. Characterizing this type of DPDP system is a huge challenge for reservoir simulators.This paper will discuss the results of a modeling study in characterizing the excess permeability, quantifying its impact on production, and representing its effect in simulation models. In this study, the karst features was modeled with an analogue-based dendritic pattern and the size and permeability of karst region was calibrated with production data. To model excess permeability pertaining to fractures, a DFN (discrete fracture network) geologic model was built, upon which a DP (dual-porosity) simulation model was constructed. A series of DP sensitivity cases was designed and simulated to evaluate the range of production impact from fractures.Although DP model is considered the most rigorous modeling technique available for fractures, the challenges are that it normally requires long simulation time and more importantly it needs significant amount of data for model verification and calibration. From the results of formation evaluation, reservoir characterization and production conventional single porosity model (containing matrix properties only) with modifications that mimic fracture connections can reproduce the same results as a more complicated DPDP model and is appropriate for the B-field. Two modifications adopted in this study were pseudo wells and permeability enhancement in the fracture-prone area. Pseudo wells, shutting in at surface but permitting cross-flow in designated reservoir intervals, were implemented to capture premature gas / water breakthrough phenomena that often observed in naturally fractured reservoirs. The permeability enhancement was intended to represent the fractures positive impact on production by accelerating fluid movement through tighter reservoir. The results of DP model were used as a bench mark to determine the extent of permeability enhancement.