Uncertainties Associated with Petroleum Reservoir’s Rock and Fluid Properties.
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| Title: | Uncertainties Associated with Petroleum Reservoir’s Rock and Fluid Properties. |
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| Authors: | Govindarajan, Suresh Kumar1 gskumar@iitm.ac.in |
| Source: | Petroleum & Coal. 2025, Vol. 67 Issue 1, p181-187. 7p. |
| Subject Terms: | *Compressibility (Fluids), *Properties of fluids, *Rock properties, *Contact angle, *Multiphase flow |
| Abstract: | The estimation of petroleum reservoir’s rock and fluid properties remains fundamental for an efficient characterization of multi-phase hydrocarbon flow in a saturated confined reservoir under high pressure and high temperature conditions. The main reservoir rock property includes porosity, permeability and rock compressibility. The principal fluid properties include density, viscosity and compressibility of hydrocarbon fluids. In addition to this basic properties, the introduction of relative permeability for characterizing multi-phase hydrocarbon flow becomes a complex function of wetting-phase saturation. Further, the fluid-fluid interphase property namely interfacial tension (IFT) arising from the presence of capillary pressure; and fluid-solid interphase property namely contact angle (θ) arising from reservoir wettability plays a very crucial role in dictating the resulting spatial and temporal distribution of hydrocarbon pore fluids within a petroleum reservoir as a function of time, upon hydrocarbon production. Thus, accurate estimation of these fundamental reservoir properties become very crucial towards a successful reservoir characterization. In this context, the objective of the present article is to provide an inherent uncertainties associated with the deduction of each of these reservoir rock and fluid properties towards characterizing a petroleum reservoir. The present study concludes that although very recently developed data-driven forward and reverse models remain mathematically convincing, they still remain to be not geologically trustworthy. Since, addressing reservoir heterogeneity it-self requires a high-end computing facility, the concept of uncertainty quantification of permeability becomes further computationally expensive. In addition, the uncertainties resulting from laboratory-scale experimental investigations, minimum number of core samples from field-scale investigations and the association of reservoir physics at multiple-scales make the measurement of relative permeability to remain to be highly erroneous. [ABSTRACT FROM AUTHOR] |
| Database: | Energy & Power Source |
| Abstract: | The estimation of petroleum reservoir’s rock and fluid properties remains fundamental for an efficient characterization of multi-phase hydrocarbon flow in a saturated confined reservoir under high pressure and high temperature conditions. The main reservoir rock property includes porosity, permeability and rock compressibility. The principal fluid properties include density, viscosity and compressibility of hydrocarbon fluids. In addition to this basic properties, the introduction of relative permeability for characterizing multi-phase hydrocarbon flow becomes a complex function of wetting-phase saturation. Further, the fluid-fluid interphase property namely interfacial tension (IFT) arising from the presence of capillary pressure; and fluid-solid interphase property namely contact angle (θ) arising from reservoir wettability plays a very crucial role in dictating the resulting spatial and temporal distribution of hydrocarbon pore fluids within a petroleum reservoir as a function of time, upon hydrocarbon production. Thus, accurate estimation of these fundamental reservoir properties become very crucial towards a successful reservoir characterization. In this context, the objective of the present article is to provide an inherent uncertainties associated with the deduction of each of these reservoir rock and fluid properties towards characterizing a petroleum reservoir. The present study concludes that although very recently developed data-driven forward and reverse models remain mathematically convincing, they still remain to be not geologically trustworthy. Since, addressing reservoir heterogeneity it-self requires a high-end computing facility, the concept of uncertainty quantification of permeability becomes further computationally expensive. In addition, the uncertainties resulting from laboratory-scale experimental investigations, minimum number of core samples from field-scale investigations and the association of reservoir physics at multiple-scales make the measurement of relative permeability to remain to be highly erroneous. [ABSTRACT FROM AUTHOR] |
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| ISSN: | 13353055 |
