The demand for energy and new oil reservoirs around the world has increased rapidly while oil recovery from depleted reservoirs has become more difficult. Oil production from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of matrix rocks. Chemical enhanced oil recovery (EOR) processes such as surfactant-induced wettability alteration and interfacial tension reduction are required to decrease the residual oil saturation in matrix blocks, leading to incremental oil recovery. However, improvement in recovery will depend on the degree of wettability alteration and interfacial tension (IFT) reduction, which in turn are functions of matrix permeability, fracture intensity, temperature, pressure, and fluid properties. The oil recovery from fractured carbonate reservoirs is frequently considered to be dominated by the spontaneous imbibition mechanism which is a combination of viscous, capillary, and gravity forces. The primary purpose of this study is to model wettability alteration in the lab scale for both coreflood and imbibition cell tests using the chemical flooding reservoir simulator. The experimental recovery data for fractured carbonate rocks with different petrophysical properties were history-matched with UTCHEM, The University of Texas in-house compositional chemical flooding simulator, using a highly heterogeneous permeability distribution. Extensive simulation work demonstrates the validity and ranges of applicability of upscaled procedures, and also indicates the importance of viscous and capillary forces in larger fields. The results of this work will be useful for designing field-scale chemical EOR processes. / text

The primary objectives of this research were to understand the potential for gravity-stable surfactant floods for enhanced oil recovery without the need for mobility control agents and to optimize the performance of such floods. Surfactants are added to injected water to mobilize the residual oil and increase the oil production. Surfactants reduce the interfacial tension (IFT) between oil and water. This reduction in IFT reduces the capillary pressure and thus the residual oil saturation, which then results in an increase in the water relative permeability. The mobility of the surfactant solution is then greater than the mobility of the oil bank it is displacing. This unfavorable mobility ratio can lead to hydrodynamic instabilities (fingering). The presence of these instabilities results in low reservoir sweep efficiency. Fingering can be prevented by increasing the viscosity of the surfactant solution or by using gravity to stabilize the displacement below a critical velocity. The former can be accomplished by using mobility control agents such as polymer or foam. The latter is called gravity-stable surfactant flooding, which is the subject of this study. Gravity-stable surfactant flooding is an attractive alternative to surfactant polymer flooding under certain favorable reservoir conditions. However, a gravity-stable flood requires a low velocity less than the critical velocity. Classical stability theory predicts the critical velocity needed to stabilize a miscible flood by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension and found to over-estimate the critical velocity compared to both laboratory displacement experiments and fine-grid simulations. Predictions using classical stability theory for miscible floods were not accurate because this theory did not take into account the specific physics of surfactant flooding. Stability criteria for gravity-stable surfactant flooding were developed and validated by comparison with both experiments and fine-grid numerical simulations. The effects of vertical permeability, oil viscosity and heterogeneity were investigated. Reasonable values of critical velocity require a high vertical permeability without any continuous barriers to vertical flow in the reservoir. This capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. Numerical simulations were also used to show how gravity-stable surfactant flooding can be optimized to increase critical velocity, which shortens the project life and improves the economics of the process. The critical velocity for a stable surfactant flood is a function of the microemulsion viscosity and it turns out there is an optimum value that can be used to significantly increase the velocity and maintain stability. For example, the salinity gradient can be optimized to gradually decrease the microemulsion viscosity. Another alternative is to inject a polymer drive following the surfactant solution, but using polymer complicates the process and adds to its cost without significant benefit in most gravity-stable surfactant floods. A systematic approach was introduced to make decisions on using polymer in applications based on stability criteria and cost. Also, the effect of an aquifer on gravity-stable surfactant floods was investigated as part of a field-scale study and strategies were developed to minimize its effect on the process. This study has provided new insights into the design of an optimized gravity-stable surfactant flood. The results of the numerical simulations show the potential for high oil recovery from gravity-stable surfactant floods using horizontal wells. Application of gravity-stable surfactant floods reduces the cost and complexity of the process. The widespread use of horizontal wells has greatly increased the attractiveness and potential for conducting surfactant floods in a gravity-stable mode. This research has provided the necessary criteria and tools needed to determine when gravity-stable surfactant flooding is an attractive alternative to conventional surfactant-polymer flooding. / text