Lower permian carbonate deposits reservoir properties of western part of Hlynsko-Solohivska area of Dnieper-Donets Depression gas-oil-bearing district

The paper concerns the researches of the Lower Permian carbonate deposits reservoir properties of western part of Hlynsko-Solohivska area of gas-oil-bearing district of Dnieper-Donets depression. Such reservoir parameters as the open porosity factor, permeability coefficients and residual water saturation factor have been used to assess the promising rocks for the possible hydrocarbon reservoirs. Void structure of rocks with capillarimetric method and the correlation of rock density with their porosity were also studied. The porosity study was carried out in atmospheric and reservoir conditions. The bulk density of dry rock samples varies from 2212 kg/m3 to 2593 kg/m3 (mean 2413 kg/m3), water saturated rocks – from 2442 to 2642 kg/m3 (mean 2549 kg/m3), kerosene saturated rocks – from 2400 to 2622 kg/m3 (mean 2541 kg/m3); an apparent specific matrix density – from 2718 to 2828 kg/m3 (mean 2783 kg/m3). The open porosity coefficient of study rocks, saturated with the synthetic brine, varies from 0.045 to 0.181 (mean 0.127), if samples are saturated with kerosene then it varies from 0.049 to 0.184 (mean 0.128) and when N2 is used - from 0.063 to 0.217 (mean 0.149). The effective porosity has following values: 0.004-0.125 (0.036), and the residual water saturation factor - 0.4-0.97 (0.79). Analysis of reservoir conditions modeling revealed that porosity coefficient varies from 0.040 to 0.169 (mean 0.118). Due to the closure of microcracks under rock loading reduced to reservoir conditions the porosity decreases in comparison with atmospheric conditions, which causes a relative decrease in the porosity coefficient from 1.5 % to 11 % (mean 9.0 %). Capillar void of study rocks describes the prevalence of subcapillar pores (40-97 %, mean 79 %) while the overcapillars pores have range 1-22 % (mean 7 %) and the capillar pores - 2-38 % (mean 14 %). The permeability coefficient varies from 0.038 fm2 to 1.992 fm2 (mean 0.323 fm2). As result of petropysical researches the rocks have been classified with above mentioned reservoir parameters. The correlation analysis has allowed to establish a series of empirical relationships between the reservoir parameters (density, porosity coefficient, permeability coefficient and residual water saturation factor).