Gas Storage in a Depleted Gas/Condensate Reservoir in the Appalachian Basin

Abstract

Abstract A depleted gas condensate reservoir in the Appalachian Basin has been under investigation for possible conversion to a gas storage reservoir. When depleted gas condensate reservoirs are used for gas storage, the injected gas will pressurize the reservoir and will evaporate the retrograde condensate that is remaining in the reservoir upon completion of the primary production. This will result in significant compositional alteration of the withdrawn gas from the storage. The produced gas during withdrawal cycle must be processed to remove condensible hydrocarbons prior to pipeline transportation to prevent liquid drop out by retrograde condensation in the pipeline. The composition of produced gas will depend on the degree of mixing between the injected and the residue fluids. To investigate the impact of the formation on the mixing, a compositional reservoir simulator was utilized in this study. The primary production history of the reservoir was first modeled with simulator using available data and the results of the data analysis. The phase behavior studies with Peng-Robinson equation of state (PR-EOS) provided a reliable estimate for reservoir fluid composition. Upon successfully history matching the primary production, the reservoir model was utilized to predict the composition of the withdrawn gas from the storage. Pipeline gas was injected into the reservoir and the reservoir was pressurized to its original pressure. Both vertical and horizontal wells were considered for injection to evaluate the extent of mixing among residue gas, residue condensate, and the injected gas. Subsequently, a withdrawal cycle was simulated to predict the liquid yields and gas heating contents based on the design of the surface facilities. The results of simulation study were then used to finalize the design storage field and surface facilities. The preliminary data collected after pressurizing the reservoir confirms the simulation results. Introduction A depleted gas reservoir in the Appalachian Basin has been considered for new gas storage field development. This reef reservoir is considered to be an excellent candidate because of its high permeability and compactness. The laboratory data and the field history clearly indicate that this reservoir is a gas condensate reservoir. Therefore, it was believed that retrograde liquid is present in the reservoir. The liquid (condensate), which is formed by the retrograde condensation process during primary depletion, is trapped by porous media because of its low saturation. Injection of pipeline gas into this reservoir will increase the pressure and cause the trapped condensate to evaporate and be mixed with the injected and residue gases. Subsequently during withdrawal cycle, the withdrawn gas will be a mixture of injected gas, evaporated condensate and residue gas. As a result, the withdrawn gas will contain heavy hydrocarbons and must be processed to prevent condensation in the gathering and transmission distribution systems. It should be noted that significant volume of liquid can be produced from the withdrawn gas even though the liquid yield during storage withdrawal cycle is significantly lower than the liquid yield during the primary production. This mainly due to high gas withdrawal rates during storage operation. Consequently, the proper design of the surface and processing facilities to handle the produced liquid is essential for the reliable operation of the storage field. The condensate yield during storage withdrawal cycle is the key parameters for the storage facility design and operation. The condensate yield depends on the composition of the withdrawn gas from the storage. The degree of mixing among residue gas, evaporated condensate, and the injected gas determines the withdrawn gas composition. The degree of mixing will depend on a number of factor including the well configuration, residence time, reservoir structure, and injection-withdrawal schedule. To accurately evaluate the degree of mixing a compositional numerical reservoir simulator was employed in this study.