The reservoir rock volumetric concentration and tortuosity description of pore space of Xa field, Niger Delta Basin

Abstract

The assessment of rock reservoir volume concentration is necessary as it accounts for the appreciable pore spaces available for hydrocarbon and other targets. Raw well d-ata from oil wells A, B and C in some parts of the Niger Delta Basin (XA Field) were used for porosity estimates in sandstone and shale formations. Using the Microsoft Excel for analysis, gamma ray log, density log with respect to depth were generated. The results of these curves were used to estimate porosity and create models for porosity-formation factor with respect to density effect. The major findings revealed the average porosity values as about 20% for well A, 17% for well B and 19% for well C. The results show that increase in density gives rise to a decrease in porosity in both lithologies. In order to establish a relationship between porosity of this Field rock reservoir, a plot of porosity with formation factor due to density influence was necessary. These curves lead to several equations with the average for linear curves as FD= —400øXA+98.8 and FD = (–2øXA+4.9) .×10–3for fractional and percentage porosities respectively. These models show that both parameters are strongly related with coefficients of 0.9723 (for both plots from well A), 0.8274 (for both plots from well B) and 0.9689 (for both plots from well C) for XA Field. These results correspond to the non-linear relation, øXA = 0.8006 FD–0.465 0.9689as the original values of the cementation exponent and the tortuosity factor are obtained, if the formation factor is considered as the subject.