Compositional variation in multi-component system caused by adsorption and confinement in organic nanopores leads to capillary condensation and trapping of concentric hydrocarbon liquids. The objective of this paper is to show the presence of capillary condensation in kerogen pores, and argue that pressure depletion/fluid expansion is no longer effective and EOR process is required for these pores. We quantify stripping effects of CO2 on the condensates recovery from the kerogen nanopores and discuss the fundamentals of cyclic-CO2 injection into source rocks. Investigation is carried out using a multi-component hydrocarbon mixture representing fluids produced from US shale gas plays. Nano-channels in equilibrium with bulk phase such as fractures represent kerogen nanostructures and are modeled with varying sizes. Using Monte Carlo simulation, in-situ molecular configuration inside the nano-channels is restored as the pressure of the bulk phase and proportion of CO2 in bulk phase changes in stages. This process enables to correlate the accessible information, such as the subsurface conditions, produced bulk fluid composition and injected CO2 amounts, to inaccessible information such as the in-situ thermodynamic state of the hydrocarbon fluids and CO2 in kerogen. Based on information obtained from this, the impact of CO2 injection on recovery is systematically analyzed. Since selective adsorption of CO2 to kerogen is weaker than those of the heavy molecules in the mixture while stronger than those of the light components, it is difficult for the injected CO2 to strip off many hydrocarbons in small pores. For large kerogen pores, however, the injected CO2 relatively easily extracts the hydrocarbons from the pores. This in turn drives a shift in phase equilibrium properties and prevents the capillary condensation. Consequential significant enhancement in recovery is observed. Moreover, the higher injection pressure leads to the higher recovery in the small pores providing that the introduced CO2 takes up more than 50% of the bulk space. This is in contrast to the case of large pores that the injection following pressure depletion is preferred to enhance the recovery. An efficiency of the CO2 injection is generally improved as the pressure increases in small pores but it is still less effective than that in larger pores and the increasing pressure does not bring out substantial rises in the efficiency in the large pores. 6nm and 10nm pores show residual oil saturation, which is less than 0.2 and the values remain more or less constant over the investigated pressure range whereas the value in 2nm pore varies depending on injection pressure and it increases by a factor of 1.9 as the pressure depletes from 3,500psi to 500psi. The effects of introduced CO2 on transport properties of the hydrocarbon fluids in kerogen pores and other injecting agents (N2 and CH4) on the recovery are also investigated. The present work provides an essential understanding of the role of CO2 in multi-component fluids and lays down the first principles of CO2 injection into shale gas/condensate reservoirs.
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