Technically, CO2 injection into geological formations is quite similar to the oil field production operations. One of the main differences in the two is that the latter leads to continuous pressure decline (depletion) or pressure maintenance (by injection), while as the former (CO2 injection) normally causes reservoir pressure build-up, maybe beyond the level earlier experienced by the geological structure. Basically, this has potential to cause fault reactivation and leakage out of the target formation. Ideally, comprehending the flow barriers in a saline aquifer evaluated for geological storage of carbon dioxide is the key point for decision making and designing injection operations. This may be achieved via combining time-lapse seismic and pressure monitoring.
It has been established that the pressure data obtained in real-time during well testing and main phase of injection with installation of Permanent Downhole Gauges (PDG) may be utilized to characterize and monitor reservoir boundary conditions. Here, Pressure Transient Analysis (PTA) can be employed as interpretation tool. Regardless, several vital questions still linger unanswered mainly relating to leakage detection and the maximum allowable volume that can be injected- among others. Therefore, further research is necessitated. On this account, researchers from the NORCE – Norwegian Research Centre: Dr. Anton Shchipanov, Mr. Lars Kollbotn and Dr. Roman Berenblyum proposed to study the case of faults acting as flow barriers including scenarios of sealing and leaking faults using the history of CO2 injection into the Tubåen formation of the Snøhvit field as testing data set. Their work is currently published in the research journal, International Journal of Greenhouse Gas Control.
In their approach, the researchers first addressed the general questions on applicability of PTA for CO2 injection, related to capabilities and limitations of single-phase flow models. Next, the team suggested and tested approximate approaches to improve the capabilities of such models to deal with CO2 injection cases (brine replica). Finally, an integrated workflow for characterizing and monitoring flow barriers in geological storage projects was proposed.
The authors confirmed the value of real-time well pressure surveillance with PDG installed in injection wells. The team also reported that estimating changes in already observed boundaries for a longer history may be affected by new boundaries ought to be seen; which impacts to overall pressure build-up. Altogether, they reported that a real-time update of CO2 injection forecast is needed for long-term injection where pressure diffused to distant areas of the reservoir meeting new flow barriers or active boundaries.
In summary, the study by NORCE scientists demonstrated a basis for integrated technology for characterizing and further monitoring of reservoir boundaries and flow barriers using permanent pressure measurements in injection wells. The objective of the study was to understand how Pressure Transient Analysis could be successfully applied in CO2 storage projects, where CO2 plume has an impact on pressure transient response. Overall, in a statement to Advances in Engineering, Dr. Anton Shchipanov explained that the proposed technology offered an early detection of leakage based on active injection well monitoring, thereby making it one of the best candidates for real-time monitoring and early warning of leakage initiation.
A.A. Shchipanov, L. Kollbotn, R. Berenblyum. Characterization and monitoring of reservoir flow barriers from pressure transient analysis for CO2 injection in saline aquifers. International Journal of Greenhouse Gas Control, volume 91 (2019) 102842.