Improved water saturation estimation in shaly sandstone through variable cementation factor

Estimation of water saturation, Sw, in shaly sandstone is an intricate process. The surface conduction of clay minerals adds up to the electrolyte conduction in the pore spaces, thus generating high formation conductivity that overshadows the hydrocarbon effect. In each resistivity-based water saturation model, the key parameter is formation factor, F, which is typically derived from Archie’s Law. Referring to a log–log plot between formation factor and porosity, cementation factor reflects the slope of the straight line abiding Archie’s Law. In the case of shaly sandstone, derivation based on Archie’s Law in combination with Waxman–Smits equation leads to higher cementation factor, m*. In the shaly parts of the reservoir, high m* is counterbalanced by clay conductivity. Nonetheless, high m* used in clean parts increases Sw estimation. In this study, the variable cementation factor equation is introduced into the standard correlation of Sw versus Resistivity Index, RI, to develop a water saturation model with shaly sandstone parameters. Data retrieved from two fields that yielded mean arctangent absolute percentage error (MAAPE) were analysed to determine the difference between calculated and measured data within the 0.01–0.15 range for variable cementation factor method. The conventional method yielded maximum MAAPE at 0.46.

Research on the Construction of a Petrophysical Model of a Heterogeneous Reservoir in the Hydrate Test Area in the Shenhu Area of the South China Sea (SCS)

The occurrence characteristics of hydrates in the Shenhu area reflect a typical inhomogeneity in terms of spatial distribution. It is difficult to accurately describe the petrophysical properties of a reservoir using a petrophysical model considering a single cementation factor parameter. According to the analysis of a mathematical model and the estimation results of V p and V s , the unique structure of foraminiferal sediment particles provides opportunities for forming a diversified hydrate occurrence in the foraminiferal area. In areas where hydrates are thin and interbedded, hydrate reservoirs are generally three-phase media, with obvious thermoelastic properties. Therefore, the parameters of the three characteristic models of the pore-filling model, particle cementation model, and thermodynamic elastic model are all included in the correction model. The weights of the influence factors are then changed to realize an accurate description of the petrophysical characteristics of the correction model in different drilling areas and at different formation depths, reducing the limitations of using a single petrophysical model to describe the petrophysical characteristics of heterogeneous regions under the influence of multiple factors.

Cementation exponent estimate in carbonate reservoirs: A new method

There are two approaches for measuring hydrocarbon saturation: well log interpretation and usually developed formulas. Archie’s equation is one of the most fundamental equations used for water saturation calculation. Archie’s equation includes three factors: cementation factor, tortuosity and saturation exponent. Archie determines these factors based on lab results in sandstone and provides fixed value for them. Carbonate reservoirs have a variety of textures, shapes and distribution of pores; therefore, the mentioned factors, especially cementation are not considered constant. In this study, the relationship between cementation factor and density log was examined because cementation factor is defined as a parameter that has a close relationship with density. By calculating the matrix density and accordance factor between the matrix density and cementation factor from core’s analysis, a log will be generated that can estimate the variation of cementation factor around the borehole. This method is useable for calculating the cementation factor in carbonate rocks. Keywords: Cementation factor, carbonate reservoir, density, new method, exponents.

Plausibility of Hydrocarbon Potential Analytics of Archie’s Model by Cementation Factor Pliability in Shaly Sand Reservoir

Comprehensive comparative analyses of 18 shaly sandstone zones in four wells of an Oil Field in the Niger Delta were carried using only the Archie Model with the appropriate cementation factor from a range of 1.3 to 2.0 This was done to comprehensively analyze and statistically validate the need for the applicability of m = 1.3. Detailed statistical analysis of water saturation results of lower and upper 95% confidence intervals for the standard deviations gave the least range of 0.00415 to 0.00724 (m=1.3), 0.00660 to 0.1151 (m=1.65) and maximum of 0.00996 to 0.01747 (m=2.0). This was however validated by the bias results of the standard deviation with -0.00025 for m=1.3, -0.00040 for m=1.65 and -0.00060 for m=2. Hydrocarbon saturation results of lower and upper 95% confidence intervals for the standard also gave the least values of 0.00427 to 0.00740 (m=1.3), 0.00680 to 0.01171 (m=1.65) and 0.01031 to 0.01773 (m=2.0). The bias results of the standard deviation gave the least for m=1.3 as -0.0002, -0.00032 for m=1.65 and -0.00048 for m=2.0. Hydrocarbon movability index results of lower and upper 95% confidence intervals for standard deviation gave the least range for m=1.3 of 0.00521 to 0.00934, 0.00793 to 0.01415 for m=1.65 and 0.01155 to 0.02049 for m=2.0. The bias results of the standard deviation gave also the least for m=1.3 as -0.00031, -0.00047 for m=1.65 and -0.00068 for m=2. The study reveals that the Archie Model predictions was improved with cementation factor of 1.3 and has favourable petrophysical parameters indicating higher hydrocarbon potential than the Simandoux  and when m=1.65 and 2.0. This model is a valuable tool in a shaly sand environment after thorough validation using the pickett plot.