Improved Production and Sand (Cold) Production in Conventional and Heavy Oil Reservoirs-A Field Case and Simulation

Abstract

Abstract A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are evaluated, the effect of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake (Lloydminister, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, and (2) by higher mobility of the fluid due to the movement of the sand particles. A relative permeability reduction after a certain period of production may result in a pressure gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall slurry production. Our results suggest that a sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, which can generate a high-mobility zone with a negative skirt near the formation. Such an improvement reduces the near well pressure gradient so that the sanding condition is weakened, and permits a easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement and capillary pressure are the key factors to affect the cumulative sand production, a crucial factor to determine the success of a cold production operation and improved well completion.