Capillary pressure equilibrium theory mapping of 4D seismic inversion results to predict saturation in a gas-water system

Abstract

Understanding the effect of fluid concentration in rocks is crucial to characterize a hydrocarbon reservoir. Monitoring of fluid concentration specifically becomes challenging during a sequestration/enhanced oil recovery program because the objective is to understand the amount of initial fluid replaced by liquid/gas injection and identify the probability of leakage with time. The prior assumption of uniform or patchy type of distribution of gas in a rock-physics theory leads to large uncertainty in the prediction of saturation. As a result, we have used the capillary pressure equilibrium theory (CPET) for creating a reservoir model that matches the physics of capillary-induced fluid invasion and avoids the uncertainty related to the type of distribution of gas in pores. We create a CPET model using the reservoir parameters of the clean and unconsolidated sandstone formation of the Sleipner field, North Sea, which is the world’s first industrial-scale CO2-injection project, assuming that there is no significant change in the rock frame throughout the field. The model is then used to analyze the fluid content from the time-lapse seismic inversion results of the Sleipner field. CO2 at higher quantities, according to our research, is analogous to a uniform distribution, whereas CO2 at lower concentrations is mostly in between patchy and uniform distribution or slightly patchy type. We predict maximum CO2 saturation from a quantitative interpretation of six time-lapse seismic data from 1999 to 2010 using the CPET as 75% of the pore space, and the footprint of the CO2 plume in the topmost layer is spreading from zero in 2001 to 7 × 105 m2 in 2010. Our model finds that injected CO2 from all layers below will migrate to the top layer approximately 50 years after the commencement of the injection.