Reservoir Rock Quality Determination Through Screening of Core Samples' Permeability for Strategic Oilfield Developments

Screening of reservoir qualities by using in-situ permeability values is a good criterion for a developmental sequence in reservoir management. Tight oil reservoirs are associated with low permeability and low production flow rates. More wells, both producing and injections, are necessary to optimize oil recoveries from tight formation. The cost of drilling and completion will require heavy capital overhead. Therefore, it is important to isolate and tight reservoirs for systematic development. This study considered and attempted to modify Hall’s equation for calculating reservoir permeability, but there were some limitations. The limitation of this model was that it applies correctly to a reservoir undergoing water injection. So an existing model of permeability calculation that had been applied to the Daqing and Changqing oil regions was eventually used to conduct studies on five core samples collected from a Niger Delta oilfield. This study performed a comprehensive analysis based on pore-throat radius distribution measurements, low-temperature nitrogen adsorption measurements, centrifugation, and nuclear magnetic resonance measurements to establish a method for calculating the bound water film thickness and, in turn, the porosity and permeability. The process was applied to five rock samples from a prolific oilfield in Niger Delta. The results indicated that, for a given reservoir, bound water film thickness varies with permeability. With decreasing permeability, bound water film thickness decreases due to the changes in the pore-throat structure and the impact of molecular forces. The permeability values recorded for the five core samples were of 0.093, 0.165, 0.068, 0.087, and 0.189 mD respectively for core samples CS_1, CS_2, CS_3, CS_4, and CS_5. The higher the value of permeability, the higher the reservoir quality.