he feasibility of sequestering supercritical CO2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside an aluminum coreholder that is then evacuated. Second, with or without connate water, the carbonate core is saturated with methane. Third, supercritical CO2 is injected into the core with 300 psi overburden pressure. From the volume and composition of the produced gas measured by a wet test meter and a gas chromatograph, the recovery of methane at CO2 breakthrough is determined. The core is scanned three times during an experimental run to determine core porosity and fluid saturation profile: at start of the run, at CO2 breakthrough, and at the end of the run. Runs were made with various temperatures, 20°C (68°F) to 80°C (176°F), while the cell pressure is varied, from 500 psig (3.55 MPa) to 3000 psig (20.79 MPa) for each temperature. An analytical study of the experimental results has been also conducted to determine the dispersion coefficient of CO2 using the convection-dispersion equation. The dispersion coefficient of CO2 in methane is found to be relatively low, 0.01-0.3 cm2/min.. Based on experimental and analytical results, a 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO2 under typical field conditions. The depleted gas reservoir is repressurized by CO2 injection from 500 psi to its initial pressure 3,045 psi. Simulation results for 400 bbl/d CO2 injection may be summarized as follows. First, a large amount of CO2 is sequestered: (i) about 1.2 million tons in 29 years (0 % initial water saturation) to 0.78 million tons in 19 years (35 % initial water saturation) for 40-acre pattern, (ii) about 4.8 million tons in 112 years (0 % initial water saturation) to 3.1 million tons in 73 years (35 % initial water saturation) for 80-acre pattern. Second, a significant amount of natural gas is also produced: (i) about 1.2 BSCF or 74 % remaining GIP (0 % initial water saturation) to 0.78 BSCF or 66 % remaining GIP (35 % initial water saturation) for 40-acre pattern, (ii) about 4.5 BSCF or 64 % remaining GIP (0 % initial water saturation) to 2.97 BSCF or 62 % remaining GIP (35 % initial water saturation) for 80-acre pattern. This produced gas revenue could help defray the cost of CO2 sequestration. In short, CO2 sequestration in depleted gas reservoirs appears to be a win-win technology.

he feasibility of sequestering supercritical CO2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside an aluminum coreholder that is then evacuated. Second, with or without connate water, the carbonate core is saturated with methane. Third, supercritical CO2 is injected into the core with 300 psi overburden pressure. From the volume and composition of the produced gas measured by a wet test meter and a gas chromatograph, the recovery of methane at CO2 breakthrough is determined. The core is scanned three times during an experimental run to determine core porosity and fluid saturation profile: at start of the run, at CO2 breakthrough, and at the end of the run. Runs were made with various temperatures, 20°C (68°F) to 80°C (176°F), while the cell pressure is varied, from 500 psig (3.55 MPa) to 3000 psig (20.79 MPa) for each temperature. An analytical study of the experimental results has been also conducted to determine the dispersion coefficient of CO2 using the convection-dispersion equation. The dispersion coefficient of CO2 in methane is found to be relatively low, 0.01-0.3 cm2/min.. Based on experimental and analytical results, a 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO2 under typical field conditions. The depleted gas reservoir is repressurized by CO2 injection from 500 psi to its initial pressure 3,045 psi. Simulation results for 400 bbl/d CO2 injection may be summarized as follows. First, a large amount of CO2 is sequestered: (i) about 1.2 million tons in 29 years (0 % initial water saturation) to 0.78 million tons in 19 years (35 % initial water saturation) for 40-acre pattern, (ii) about 4.8 million tons in 112 years (0 % initial water saturation) to 3.1 million tons in 73 years (35 % initial water saturation) for 80-acre pattern. Second, a significant amount of natural gas is also produced: (i) about 1.2 BSCF or 74 % remaining GIP (0 % initial water saturation) to 0.78 BSCF or 66 % remaining GIP (35 % initial water saturation) for 40-acre pattern, (ii) about 4.5 BSCF or 64 % remaining GIP (0 % initial water saturation) to 2.97 BSCF or 62 % remaining GIP (35 % initial water saturation) for 80-acre pattern. This produced gas revenue could help defray the cost of CO2 sequestration. In short, CO2 sequestration in depleted gas reservoirs appears to be a win-win technology.

For a natural gas importing country, &ldquo / take or pay&rdquo / approach creates problems since the demand for natural gas varies during the year and the excess amount of natural gas should be stored. In this study, an underground gas storage project is evaluated in a depleted gas Field M. After gathering all necessary reservoir, fluid, production and pressure data, the data were adapted to computer language, which was used in a commercial simulator software (IMEX) that is the CMG&rsquo / s (Computer Modelling Group) new generation adoptive simulator, to reach the history matching. The history matching which consists of the 4 year of production of the gas reservoir is the first step of this study. The simulation program was able to accomplish a good history match with the given parameters of the reservoir. Using the history match as a base, five different scenarios were created and forecast the injection and withdrawal performance of the reservoir. These scenarios includes 5 newly drilled horizontal wells which were used in combinations with the existing wells. With a predetermined injection rate of 13 MMcf/D was set for all the wells and among the 5 scenarios, 5 horizontal &ndash / 6 vertical injectors &amp / 5 horizontal - 6 vertical producers is the most successful in handling the gas inventory and the time it takes for a gas injection and production period. After the determination of the well configuration, the optimum injection rate for the entire field was obtained and found to be 130 MMcf/D by running different injection rates for all wells and then for only horizontal wells different injection rates were applied with a constant injection rate of 130 MMcf/d for vertical wells. Then it has been found that it is better to apply the 5th scenario which includes 5 horizontal &ndash / 6 vertical injectors &amp / 5 horizontal - 6 vertical producers having an injection rate of 130 MMcf/d for horizontal and vertical wells. Since within the 5th scenario, changing the injection rate to 1.3 Bcf/d and 13 Bcf/d, did not effect and change the average reservoir pressure significantly, it is best to carry out the project with the optimum injection rate which is 130 MMcf/d. The total gas produced untill 2012 is 394 BCF and the gas injected is 340 BCF where the maximum average reservoir pressure was recovered and set into a new value of 1881 psi by injection and cushion gas pressure as 1371 psi by withdrawal. If 5th scenario is compared with the others, there is an increase in injection and production performance about 90%.

Carbon dioxide is one of the greenhouse gases which have strong impacts on the environment and its amount in the atmosphere is far beyond to be ignored. Carbon dioxide levels are projected to be reduced by sequestering it directly to the underground. High amounts of carbon dioxide can be safely stored in underground media for very long time periods. Storage in depleted gas reservoirs provides an option for sequestering carbon dioxide. In 2002, production of Kuzey Marmara gas reservoir has been stopped due to gas storage plans. Carbon dioxide sequestration in Kuzey Marmara field has been considered in this study as an alternative to the gas storage projects. Reservoir porosity and permeability maps were prepared with the help of Surfer software demo version. These maps were merged with the available Kuzey Marmara production information to create an input file for CMG-GEM simulator and a three dimensional model of the reservoir was created. History match of the field model was made according to the 1998-2002 production data to verify the similarity between the model and actual reservoir. Kuzey Marmara field is regarded as a candidate for future gas storage projects. The reservoir still contains producible natural gas. Four different scenarios were prepared by considering this fact with variations in the regional field properties and implemented into previously built simulation model. These scenarios primarily focus on sequestering carbon dioxide while producing as much as natural gas possible. After analyzing the results from the scenarios it is realized that / CO2 injection can be applied to increase natural gas recovery of Kuzey Marmara field but sequestering high rate CO2 emissions is found out to be inappropriate.