Revaporization of Condensate with Methane Flood

Abstract

Abstract Coreflood experiments were performed to investigate the effectiveness of methane flood in revaporization of condensate phase from cores. Condensate was accumulated dynamically in cores by reducing the flowing pressure below the dewpoint of the flowing gas mixture used. Two-phase flow was continued until steady state was reached where condensate reached its residual saturation. Methane was flooded through the core to assess the revaporization process. Methane flooding revaporizes condensate from the core and restores the gas permeability to its initial value, but it is a slow process. Experimental results showed that revaporization of heavy components by methane is very slow process and may require several 10s or 100s of pore volumes to achieve. The revaporization of condensate is controlled by the partitioning of the hydrocarbon components into the flowing gas phase when the pressure is below the minimum miscibility pressure (MMP). Increasing methane pressure and flow rate expedites the revaporization of condensate. The revaporization of the heavy components in the condensate phase was slightly affected by non-equilibrium behavior at the high flow rates. The return permeability ratio increases with methane volume injected and is relatively insensitive to flow rate, indicating that non-equilibrium effects are of secondary importance. The experimental studies showed promising results for field application. Introduction Gas cycling has been used to maintain reservoir pressure above the dewpoint pressure. There are two schemes of gas cycling: full pressure or partial pressure maintenance.1 In full pressure maintenance, gas is cycled continuously while condensate (or oil) is withdrawn from the reservoir. In partial pressure maintenance, gas is injected into the reservoir but depletion is allowed to occur. Both methods of gas cycling require gas cycling plants that increase the initial capital costs. Injection of dry gas (N2, CO2, or CH4) into a retrograde gas-condensate reservoir vaporizes condensate and increases its dewpoint pressure. Contact of injected dry gas with gas-condensate leads to enrichment of the dry gas due to mass transfer. Injection of dry gas was found experimentally to vaporize both intermediate and some heavy hydrocarbons.2 It was found that full pressure maintenance yielded a higher condensate recovery than partial pressure maintenance.3 Boersma and Hagoort4 compared displacement characteristics of nitrogen and methane injection into volatile-oil reservoirs based on phase behavior analysis, compositional reservoir simulation, and slim-tube experiments. They used a synthetic three-component gas mixture (60 mole% methane, 20 mole% n-butane, and 20 mole% n-tetradecane). Their results showed that methane revaporized the liquid phase more efficiently than nitrogen. A significant liquid saturation was left behind in the nitrogen-invaded zone during nitrogen flooding. The liquid recovery for both methane and nitrogen flooding increases with increasing pressure. They also reported that the recovery of methane floods increased at higher Peclet numbers (decreasing dispersion level). Nitrogen has been applied in gas injection due to its economic feasibility.5,6 Sänger and Hagoort7 investigated the efficiency of nitrogen to evaporate gas-condensate compared to methane using a slim tube. They found that methane re-evaporated the condensate and resulted in complete recovery of all condensate. The recovery of nitrogen injection reached 94%, but it decreased when the pressure is lowered below the dewpoint pressure. The recovery of condensate was found to be more sensitive to dispersion during nitrogen injection than that during methane flooding. They recommended using nitrogen for gas injection based on availability and cost. Condensate blockage in the near-wellbore region caused a severe reduction in well productivity. The effectiveness of lean gas, N2 and CO2 injection in recovering the well productivity was evaluated.8 Results indicated the importance of optimum volume and pressure for successful use of injection techniques in gas condensate reservoirs.