This paper discusses the evaluation of secondary and tertiary oil recovery in a multi-layered, mature offshore oilfield. This field is highly complex vertically with 100s of stacked sandstone packages, with individual thicknesses ranging between 10 to 50 feet, and areally complex through numerous faultblocks, which exhibit varying degrees of inter-fault block communication and aquifer support; it is under primary depletion with gas lift support. Under the current development strategy field performance suggests a moderate ultimate recovery and thus application of water injection and EOR techniques becomes important in view of significant oil volumes being undrained/unswept in the reservoir.
Waterflooding, Immiscible Water Alternating Gas (iWAG), Down Dip Gas Injection (DDGI) and Low Salinity Flooding (LSF) have been evaluated as possible technologies for improving the recovery factor of the field; iWAG is the current front running EOR concept. Key considerations are the impact of reservoir heterogeneity on different displacement processes, the importance of gravity forces relative to viscous forces and the representation of the recovery process through choice of appropriate relative permeability and capillary pressure functions. Typically significantly more detail is required in models to assess waterflood and EOR processes than is captured in the models used to manage primary depletion. A particular challenge in this case is the level of complexity in terms of separate reservoirs vertically and areally, which makes the use of full field models with adequate resolution impractical.
This paper describes how these challenges have been addressed. Individual reservoirs have been characterised in terms of heterogeneity ranging from broadly coarsening upwards through to fining upwards sequences. A series of sector models with geological "types" representing the range encountered in the field have been constructed and we ensure sufficient grid resolution selection through a step-wise approach which starts with log resolution QC followed by core-to-log integration. Validity checks of the log-to-static model grid through use of Lorenz plots and comparison of their Dykstra Parson coefficients is a key step and provides assurance that the core and log observed heterogeneity is adequately captured in the model resolution. We have found that where the level of heterogeneity is not appropriately represented in the dynamic model the results may lead to selection of the wrong recovery process.
Results of our high resolution sector models is consistently assessed by comparing recovery factors as a function of both HCPV throughput and time. This allows poorly performing processes to be deselected and focussing of remaining techniques on the most favourable reservoir types. Final selection of the preferred redevelopment strategy requires an additional step in which reservoir geometry, well count, completion strategies across multiple reservoir intervals and facilities requirements are considered.