Utilization of fluorinated tracers to monitor CO₂ sequestration in unconventional reservoirs in central appalachia - Results from a small-scale test in Morgan County, Tennessee

Sequestering carbon dioxide (CO₂) in unconventional underground reservoirs such as unmineable coal seams and organic shale formations can potentially mitigate greenhouse gas emissions while enhancing gas recovery within these formations. Enhanced gas recovery will not only add natural gas reserves throughout central Appalachia, but also extend the life of mature fields in this area. This paper discusses an overview of a small-scale 'huff and puff' injection of CO₂ into an organic shale formation in Morgan County, Tennessee, including the injection parameters, site descriptions, and utilization of fluorinated tracers to track CO₂ plume movement within the shale reservoir. Approximately 500 tons of CO₂ was injected into a horizontal well located within the Chattanooga shale formation in Morgan County, Tennessee. Fluorinated tracers were also injected with the CO₂ to model plume movement within the underground reservoir by monitoring the arrival times and concentrations at offset wells. Sulfur hexafluoride (SF₆), along with two perfluorocarbon tracers (PFTs), perfluoromethylcyclopentane (PMCP) and perfluoromethylcyclohexane (PMCH), were used as tracers for this project. Approximately 5, 500 mL (0.574 kg) of SF₆ and 500 mL (0.85 kg) of PMCP were introduced within the first 50 tons of CO₂ injection to effectively simulate the initial plume movement through the reservoir, as well as compare the arrival times of the much smaller SF₆ versus PMCP. Later during the injection phase, 500 mL (0.89 kg) of PMCH were introduced once the total tons of injected CO₂ reached 300 tons. This allowed for a comparison between the arrival times of the similar PFTs at the offset wells at different phases of the injection. Injection of the CO₂, along with the tracers, ended in mid-March 2014. The well will remain shut-in for a period between one to three months to allow the CO₂ to effectively adsorb to the shale. After this soaking period commences, the well will be flowed back into normal production. A baseline study of the injection well, along with 13 offset wells, was conducted to analyze the gas quality as well as the concentration of naturally occurring CO₂ within the formation. Monitoring for increased tracer and CO₂ concentrations at the offset wells during the injection and soaking phase will determine communication from the injection well to the offset wells. During the flowback phase, gas quality and tracer concentrations will be monitored to account for enhanced gas recovery and desorption rates. Preliminary results from all three phases will be discussed including recent flowback results.