Petrophysical Characteristics of Reservoir Sands in Sam-Bis Field, Greater Ughelli Depobelt, Niger Delta Basin, Nigeria

  • Raphael Oaikhena Oyanyan Department of Geology, Federal University Otuoke, P.M.B. 126 Yenagoa, Bayelsa State, Nigeria
Keywords: Niger Delta Basin, Reservoir sands, Petrophysical properties, Fluid saturation, Depositional environments


To understand the variations of petrophysical properties with paleoenvironments of deposition of reservoir sands, mathematical models were applied to a suit of wire line logs data to calculate thickness, volume of shale, porosity, permeability and fluid saturations. Twenty-one sand units were identified. The average sand thickness ranged from 2.6m in the fluvial distributary channel to 14.93m in the tidal channel. The average volume of shale ranged from 0% in some sand units of the mouth bar to 26.3% in a sand unit of the tidal channel. Effective porosity values ranged from 12.12% in a sand unit of distributary channel to 30.8% in a sand unit of mouth bar, while permeability values ranged from 96.3Md in a sand unit of distributary channel to 903.2Md in a sand unit of mouth bar. The cross-plot of porosity values against depth and permeability gave regression coefficients of 67.9 and 64.5, respectively. Therefore, there is a strong relationship between porosity and permeability, and with depth, it decreases gradually. Generally, the porosity values are fair to very good, while the permeability values are good to very good for hydrocarbon production. The order of increase in porosity with depositional environments is given as follows: fluvial distributary channel, lower/middle shoreface, point bar, tidal channel, and mouth bar. The tidal channel formed a thicker reservoir than the mouth bar, but the mouth bar formed a higher-quality reservoir due to the energy of the depositional environment. Rocks deposited in the same depositional environment have similar porosity values. Therefore, petrophysical properties are controlled by depositional processes, thickness, and depth. Only 14.3% of the identified reservoir sand units have hydrocarbon in commercial quantity with hydrocarbon saturations that ranged from 47.8 to 81.5%.


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