Pressure Transient Response Analysis at the Southeast Regional Carbon Sequestration (SECARB) Anthropogenic Test Site near Citronelle, Alabama

Assessing the long term stability of CO₂ injected into subsurface saline reservoirs is a critical component to the research and development of geologic sequestration. At the Southeast Regional Carbon Sequestration Partnership (SECARB) Anthropogenic Test site at the Citronelle oil field near Citronelle, Alabama, 114,000 metric tons of CO₂ have been injected approximately 9,400 feet deep into the Paluxy Formation, a regionally extensive deep saline reservoir. Per requirements of the Class V UIC experimental injection permit, stringent monitoring of the study area has generated abundant reservoir and pressure data. In order to exit the permit, multiple lines of evidence must demonstrate the CO₂ plume has stabilized and represents no danger to the public or the environment. Ultimately, these monitoring data from this project are interpreted to predict the stability of the carbon dioxide plume, to demonstrate non-endangerment.

This study compares the theoretical pressure transience for several different CO₂ saturation levels with empirically derived pressure transient data from two study-area observations wells. The two observation wells, the D 9-8 #2 and the D 4-14 are located 840 feet and 3,500 feet respectively from the D 9-7 #2 injection well. Theoretical pressure transient times are calculated using the radius of investigation equation to solve for time as a function of reservoir saturation by applying reservoir parameters determined from log and core analyses.

Empirical pressure transient times were calculated for each injection period from the delay measured between the commencement of the CO₂ injection pump and the onset of the pressure response at the observation wells. Additional post-CO₂ injection data was gathered from small scale water pulses periodically injected into the formation to create an observable pressure transient. These transient times were compared with the saturation-based theoretical transient times to constrain potential reservoir CO₂ saturation levels, providing CO₂ saturation estimates at different times throughout injection. Theoretical CO₂ saturation estimates were compared and validated against saturations determined through independent modeling of the injection using the computational reservoir simulator GEM.

An increase in pressure transient time was observed to correlate with an increase in cumulative volume of CO₂ injected. This suggests that the introduction of a compressible fluid into a relatively incompressible system acts to increase the system’s overall compressibility, yielding longer transient times with increasing saturations of CO₂. However, after a 9 month period of non-injection, the transient time decreased for the D 9-8 #2 well. This may suggest that the CO₂ saturation in the system decreased during the shut in period, which may be explained by CO₂ dissolution into the brine, or migration away.

Overall, the driving force behind the change in pressure behavior of the reservoir appears to be linked to the changes in saturation of the CO₂ and brine system. Analysis of pressure transience behavior yields information on the CO₂ saturation of the reservoir, which can be applied along with reservoir parameters to indicate the presence of the CO₂ plume.  This tool may be used to evaluate the efficacy of geologic sequestration by using pressure transience response times as a proxy for saturation to represent the size and location of the plume, as well as determining if any dissolution into the brine has occurred.  Such predictive methods may be applied to exhibit evidence of non-endangerment, which would satisfy the requirements of exiting the UIC Class V permit.