Optimum Field Development Plan Using High Simulator Resolution to Increase Recovery Factor by 35% in Mature Gas Asset in South-Est of Algeria

Abstract Sonatrach in Algeria needs to meet its natural gas production targets to honor foreign sales contracts and domestic demand. As depletion drive gas fields, their reservoir pressure declines with an associated reduction in gas production. This phenomenon is more pronounced when aquifer water breaks through resulting in well-head pressures drop. This paper demonstrates how we developed several workflows serving construction of robust high-resolution simulation model to optimize gas recovery of mature field. The applied workflows started by reviewing seismic interpretation where different scenarios for velocity model were evaluated. Then followed by revising the petrophysics reservoir evaluations and developing a general deterministic for reservoir rock typing (RRT) and fluid contact identification. A pseudo-saturation modeling workflow was settled when SCAL data are missing. Control of channels bodies distribution in the model was achieved by applying a workflow that integrates all available geological data with interpreted dynamic data. Last workflow combining the defined RRT with generated maps of GIIP density, flow-capacity (KH) and actual reservoir pressure helped to identify the sweet spot locations for infill drilling option. A robust 3D geological and compositional dynamic model that allows accurate computation of LPG and condensates recoveries was constructed for a complex clastic reservoir in South-East of Algeria. No upscaling was applied on the static model to preserve its geological sense and getting high-resolution multi-million cell model. It replicates perfectly the reservoir pressure behavior and the 20 years of production history, allowing optimization of the field development plan. Among the multiple development scenarios that were investigated using the high-resolution simulator to reduce the run time, combination of infill drilling and mainly gas compression widely adopted by the petroleum industry and considered as a reliable method for improving reserves base was found to be the optimum development plan for the studied mature gas condensate field. Compression at wellhead from 75 to 20 bars extends well and field life resulting in tapping additional reserves of natural gas, LPG and condensates, which may be left behind in case surface compression facilities are not put in place in a timely and phased manner. By 2050, the final recovery factor (RF) of gas and condensates can be increased by 35% and 15% respectively compared to the existing development. The application of such integrated workflows in a structured, consistent and proactive approaches with the use of high-resolution simulator tool leads to have multiple scenarios/evaluations in a very short time and assure the ability to handle detailed geology and therefore reduce uncertainty in modeling outcomes. All of these will definitively improve the overall asset management in terms of maximizing production and recoverable reserves in similar complex clastic reservoirs from any part of the world.