Enhanced Natural Gas and Condensate Recovery by Injection of Pure SCCO2, Pure CH4 and Their Mixtures: Experimental Investigation

Abstract

Abstract This paper quantitatively investigates the fractional condensate recovery and relative permeability following supercritical carbon dioxide (SCCO2) injection, methane injection and the injection of their mixtures; and compositionally-sensitive reservoir gas relative permeability following SCCO2 injection. A high pressure high temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores. All tests were made at measured miscible conditions of 5900psi, 95–160°C and constant flow velocity inside the cores of 10cm/h. Two sequences of coreflooding experiments were employed to replicate the displacement of reservoir gas by pure SCCO2 injection, and the displacement of condensate by injection of different SCCO2-methane concentrations. This work is part of an integrated enhanced gas and condensate recovery project conducted for a local reservoir in Western Australia. The results provide valuable insights into gas and condensate recovery following SCCO2 injection with various methane impurities. The results demonstrate that SCCO2 injection appears to offer less capillary instabilities and better mobility ratios resulting in a delayed breakthrough and favorable condensate sweep efficiency (79% recovery and 0.62 PV BT); as opposed to the injection of SCCO2-methane mixtures, or pure methane injection (45% recovery and 0.27 PV BT). Further, the relative permeability curves to condensate improve following SCCO2 injection due to decrease in condensate-to-gas viscosity ratio (curves cross at 58% gas saturation with SCCO2 injection compared to 24% gas saturation with methane injection). On the gas-gas side, experiments confirm that the greater the methane concentration in the reservoir gas (i.e. less CO2 contamination) the better relative permeability and sweep efficiency data become at the flooding temperatures and pressures (curves cross at 40% SCCO2 saturation when 90% methane is present in the reservoir compared to less than 5% SCCO2 saturation when only 25% methane is present in the porous medium). These data will help the operators develop operational and design strategies for their current and future EOR projects, as well as to input parameters for full-field simulation practices. Introduction Production from gas condensate reservoirs usually involves the simultaneous flow of two or more fluids when the reservoir pressure falls below the dew point. These fluids compete for the dynamical occupation of the micro-paths within the porous medium. On a laboratory scale, researchers1 have observed significant reductions of 70% to 95% in gas relative permeability in reservoir cores due to condensate build-up (often referred to as condensate banking or condensate blockage). The reduction in gas relative permeability was more pronounced during two-phase flow in the presence of water saturation due to the dual effect of condensate and water blockage. Condensate saturations in the near wellbore region can reach as high as 50–60% under pseudo steady-state flow conditions1. However, the severity of productivity index (PI) reduction is higher in low permeability cores. On a field scale, operators2 have reported that the accumulation of liquid saturation in the vicinity of a producing well can throttle the flow of gas, ultimately reduces the productivity of a well by a factor of two or more. Those figures clearly demonstrate that prediction capabilities of the dropout magnitude as well as remedial strategies are the crux of the reservoir engineering difficulties of managing gas condensate reservoirs.