It is well known that with continued production from wet gas reservoirs, the reservoir pressure eventually falls below the dew point pressure leading to condensation and loss of gas productivity in the reservoir. The concept of simultaneously injecting CO2 in a gas reservoir for long term storage while at the same time accelerating production of the natural gas is intriguing and promising. CO2 may also interact with carbonate matrix by changing porosity and permeability of the host rock; this is true for reservoirs that are found in the Gulf Region.
To maintain field gas production targets, operators routinely set the bottom hole pressure below the dew point pressure which results in condensate blockage. Injecting CO2 can delay the onset of condensate blockage by reducing the dew point pressure of the condensate blockage zone. The approach illustrated, utilizes CO2 to delay the onset of condensate blockage. Factors such as improved effusion were analyzed to justify the use of CO2 for wellbore condensate removal and enhanced gas recovery (EGR). Experimental verification of a new method of determining dew point pressures for wet gas fluids is presented in this work and compared to simulation results.
Core floods experiments with carbon dioxide were conducted in a core sample analogue to carbonate at reservoir conditions in order to study the interaction between CO2 and carbonate reservoir. CO2 sequestration in carbonate formation was evaluated by XRF and AFM.
Experimental and simulation results show increases in productivity index after CO2 injection. Increases in productivity index were caused by CO2 evaporating the condensate blockage. Condensate vaporization was caused by CO2 reducing the dew point pressure of the condensate. Carbonate aging in presence of CO2 shows two mechanism of CO2 trapping which are dissolution and mineralization.
