Oil recovery from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of these rocks and the lack of sufficient spontaneous capillary imbibition driving force to push oil out from the matrix to the fracture network. Chemical processes such as surfactant/alkali-induced wettability alteration and interfacial tension (IFT) reduction have shown great potential to reduce the residual oil saturation in matrix blocks, leading to significant incremental oil recovery (IOR). However, the IOR response time is the most crucial decision factor in field projects. The magnitude and time efficiency of recovery depend on the degree of wettability alteration and IFT reduction, the nature and density of fracture network, and the dimensions of matrix blocks.
The available data from laboratory scale include 1) phase behavior and rheological data, 2) results of secondary and tertiary coreflood experiments for P, SP, and ASP floods under reservoir conditions, static imbibitions experiments, i.e. chemical retentions, pressure drop, and oil recovery. Therefore the proposed models need to be first validated against well controlled lab and pilot scale experiments to have reliable predictions of the full field implementations.
The measured oil recoveries were history-matched using either heterogeneous permeability distribution or explicit fracture models. The simulation models were then used to predict the recovery response times for larger cores. The controlled and systematic laboratory measurements for several core sizes helped in developing dimensionless scaling groups to aid in understanding the time dependence and upscaling of laboratory results to field-scale applications. The key objective in this project is to propose a predictive scaling group which includes all the physics related to chemical EOR processes (interfacial tension reduction and wettability change) and can predict recovery for larger scale complex field cases.