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Abstract
Sequestration of CO2 in depleted gas condensate reservoir has several advantages including enhanced hydrocarbon liquid recovery. Depleted gas condensate reservoirs have 13 times higher capacity than saline aquifers for CO2 storage. The injection of CO2 vaporizes the liquid that has been trapped in gas condensate reservoirs during the depletion process. This results in an increase in the pore space for storage purposes as well as enhanced economics due to additional liquid recovery. The improvements in liquid recovery will depend on purity of CO2. A compositional reservoir simulator was utilized in this study to investigate the impact of reservoir characteristics including permeability, porosity, heterogeneity, pressure, and temperature on CO2 distribution and interaction with hydrocarbons in the gas/condensate reservoirs. The results have utilized to study CO2 storage and improved liquid recovery.

Introduction
The carbon dioxide, CO2, emission has been on a steady increase since the industrial era. CO2 is the by-products of combusting fossil fuels. Fossil fuels supply over 85 percent of the world's energy and will remain an important part of energy supply into the 21st century. The large volume of carbon dioxide emitted annually has lead to concerns over global warming and the ensuing climatic changes. There is a need to balance the ever increasing demand for fossil fuels with the growing concerns over global climate change linked to CO2 emissions. To stabilize and ultimately reduce concentrations of CO2, it has been recommended that to isolate CO2 from the emissions stream, compressed, and transported it to an injection site where it is stored underground permanently. One option for geological sequestration CO2 is to store in depleted reservoirs due to their capacity and relatively mature technology. Based on the attractiveness of enhanced oil and gas recovery in depleted reservoirs, geologic sequestration of CO2 is a viable option for storage of CO2 and for additional revenue from hydrocarbon recovery.

Gas condensate reservoirs are characterized by retrograde liquid formation and entrapment in the reservoir during the depletion process. Generally, the low liquid saturation in the reservoir makes the liquid non-recoverable. To prevent loss of retrograde liquid, gas cycling may be employed to displace rich gas phase, strip the liquids followed by recompression for gas injection in the reservoir to maintain the pressure above or near dew point pressure. Alternatively, a depleted gas condensate reservoir after depletion can be re-pressurized by gas injection to re-vaporize the retrograde liquid. Neither of these approaches is usually economically feasible due to high cost of natural gas and compression requirements. Therefore, most depleted gas-condensate reservoirs contain retrograde liquid at the conclusion of the primary production.

It is possible to use other gases such Nitrogen,N2 ,or CO2 to re-vaporize the trapped retrograde liquid by re-pressurization or pressure maintenance. CO2 has not been used for this purpose in the past due to transportation expenses and the lack of availability. However, there have been a number of attempts to use N2 for this purpose in gas condensate reservoirs. The purpose of this study is to evaluate the impact of the carbon dioxide injection on liquid recovery in gas condensate reservoirs. Various factors were also investigated including petrophysical parameters, injection rate, and heterogeneity to better understanding on how carbon dioxide interacts, affects and impact liquid recovery and ultimately CO2 sequestration in gas condensate reservoirs.