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Abstract

It is essential to comprehend how fluid concentration in rocks affects the hydrocarbon reserve and monitor fluid concentration for a sequestration or enhanced oil recovery programme. A prediction of saturation is highly uncertain due to the prior assumption that gas distribution is uniform or patchy in a rock physics theory. We therefore use the capillary pressure equilibrium theory (CPET) to develop a reservoir model that corresponds to the physics of capillary-induced fluid invasion and avoids the uncertainty associated with the type of gas distribution in pores. Assuming that the rock frame has not significantly changed throughout the field, we develop a CPET model utilising the reservoir parameters of the clean and unconsolidated sandstone formation of the Sleipner field, North Sea, which is the first industrial-scale CO₂-injection operation ever. The fluid content of the Sleipner field is then estimated by interpreting the time-lapse seismic inversion results using the model. According to our research, CO₂ is similar to a uniform distribution at higher concentrations, whereas it is mostly a somewhat patchy type at lower concentrations, or somewhere in between patchy and uniform distribution. Maximum CO₂ saturation is predicted using the CPET as 75% of the pore space. The topmost layer's CO₂-plume footprint is expanding from zero in 2001 to 7X105 sq. m. in 2010, according to a quantitative interpretation of six time-lapse seismic data sets from 1999 to 2010. Our model predicts that 50 years after the start of injection, CO₂ from all layers below will migrate to the top layer.