Integrated field development studies were performed to increase oil recovery from the Marrat reservoir in the Umm Gudair field, a large, low permeability, complex, naturally fractured and highly faulted carbonate reservoir. The studies involved rebuilding the static model, creating and history matching a new dynamic model and using it to examine redevelopment scenarios. These included well interventions and workovers under primary depletion, secondary waterflood and, following a screening exercise, low salinity flooding (LSF). A new structural interpretation of 3D seismic data provided a revised static geological model and yielded insight into the number, geometry and origin of the many faults intersecting the reservoir. Rock types defined from core analysis were distributed in the static geological model using trends from Bayesian lithofacies classification based on pre-stack inversion of seismic data. Porosity and permeability were modelled by rock type. Saturation-height functions for each rock type were developed from mercury injection capillary pressure (MICP) data; and the reservoir free water level was varied so that these functions honoured the log-based water saturation interpretation. The dynamic model input description was based on available and interpreted data for the assumed oil wet reservoir. The history matching was aided by sophisticated application of decline curve analysis (DCA) and used an Opportunity Index approach to optimise well placement. The history matching led to a simplified and effective solution for characterising the locally naturally fractured reservoir nature. The effect of high permeabilities associated with increased fracture density was accommodated by introducing facies-based and distance from fault-related permeability modifiers, while maintaining geological rigour. The dynamic model was used to examine a range of field redevelopment scenarios. This showed that LSF could enhance field recovery and achieve a three-fold increase in estimated ultimate recovery, in conjunction with other improved reservoir management strategies. The results provided support for specialised laboratory and dynamic modelling investigations as a precursor to LSF pilot trials. A low cost source of LSF injectant was identified which could contribute to lowering the overall carbon footprint.

Um Gudair Minagish Oolite reservoir (UGMO), in Kuwait, is a high temperature mature carbonate field. It is also naturally water-flooded by a strong bottom active aquifer. Specifics challenges for Polymer (P) or Surfactant-Polymer (SP) chemical enhanced oil recovery (cEOR) are faced in high temperature carbonated reservoirs such as UGMO's field. P and SP process selection prior multiwell evaluation is addressed by a well-crafted laboratory approach. This involves extensive laboratory work including coreflood experiments to select the most effective processes in terms of oil recovery and cost-effectiveness. Softened sea water through nanofiltration two passes was considered as the most appropriate water source to be used in a SP cEOR process. Polymer was selected based on classical workflow relying on bulk measurements such as solubility, stability and viscosity, and on coreflooding experiments to characterize polymer injectivity and in-depth propagation. The selected polymer was also tested for compatibility with surfactant. SP formulation was designed and evaluated following a dedicated workflow in order to achieve low interfacial tension (IFT), high solubility, oil recovery and promising economics in reservoir conditions. The most favorable SP formulation regarding economics, surface facility modifications, operating costs and performances were evaluated through coreflood tests. The best SP formulation was selected based on chemicals in-depth propagation in reservoir core, incremental oil recovery and surfactant adsorption. The process was then optimized through additional corefloods to reduce chemicals dosage while keeping high oil recovery performances. Finally, the robustness towards both, rock and field variation conditions, was tested and confirmed. P and SP process were designed and proved to be both promising for UGMO's field. SP while using more chemicals than P process leads to a far better oil recovery as final oil saturation is decreased from 42% (P process) to 11% (SP process). As surfactant adsorption is a key parameter for both SP process efficiency and cost efficiency, several surfactant adsorption mitigation strategies were tested. Injection of a non-ionic surfactant after the main surfactant flood proved to efficiently manage surfactant adsorption despite of the very challenging conditions, allowing to reach very low adsorption level of 60 μg/g. Reservoir simulations showed afterwards that both P or SP process designed were economical at commercial pilot scale. Applied laboratory study on high temperature carbonate UGMO oil reservoir in Kuwait provides useful insights that can be used on other chemical EOR projects in such challenging conditions. This allows to select the most appropriate P or SP process and injection strategy while having reduced surfactant adsorption to very low levels in highly challenging conditions and enhanced profitability.