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Almost 4 million metric tons of CO 2 were injected at the In Salah CO 2 storage site between 2004 and 2011. Storage integrity at the site is provided by a 950-m-thick caprock that sits above the injection interval. This caprock consists of a number of low-permeability units that work together to limit vertical fluid migration. These are grouped into main caprock units, providing the primary seal, and lower caprock units, providing an additional buffer and some secondary storage capacity. Monitoring observations at the site indirectly suggest that pressure, and probably CO 2 , have migrated upward into the lower portion of the caprock. Although there are no indications that the overall storage integrity has been compromised, these observations raise interesting questions about the geomechanical behavior of the system. Several hypotheses have been put forward to explain the measured pressure, seismic, and surface deformation behavior. These include fault leakage, flow through preexisting fractures, and the possibility that injection pressures induced hydraulic fractures. This work evaluates these hypotheses in light of the available data. We suggest that the simplest and most likely explanation for the observations is that a portion of the lower caprock was hydrofractured, although interaction with preexisting fractures may have played a significant role. There are no indications, however, that the overall storage complex has been compromised, and several independent data sets demonstrate that CO 2 is contained in the confinement zone.carbon sequestration | geomechanics

Pressure buildup caused by large-scale CO 2 injection is a key concern during a carbon sequestration project. Large overpressures can compromise seal integrity, reactivate faults, and induce seismicity. Furthermore, pressure buildup is directly related with storage capacity. In this work we study the geomechanical response to CO 2 injection at Snøhvit, to understand the potential for fault reactivation, leakage, and contamination of the producing interval through bounding faults. Furthermore, we evaluate the potential contribution of a structural component to reservoir compartmentalization. We combine simplified analytical models, based on critically stressed fracture theory and a Mohr-Coulomb failure criterion, with a rigorous sensitivity analysis. Large stress uncertainties are present and reflected in the modeling results. It was found that under the most likely stress state the faults are fairly stable and caprock hydrofracturing would be expected before fault reactivation. In most of the analyzed cases, the critical pressure perturbation needed for reactivation is above 13 MPa, which was the limiting pressure increase before reaching the fracture pressure. Faults were found to be~20% less stable when considering variations in S Hmax orientation. In those cases, fault reactivation could be expected before caprock failure if injection continued. However, if the pressure increase did reach the critical values for seal failure estimated under the worst case (and least likely) stress state, no indication of such failure can be observed in the measured pressure response. Finally, the potential role of a structural component in the compartmentalization and fluid migration is difficult to assess due to the stress state uncertainty.

A pilot carbon dioxide (CO 2 ) sequestration experiment was carried out in the Michigan Basin in which ~10,000 tonnes of supercritical CO 2 was injected into the Bass Island Dolomite (BILD) at 1050 m depth. A Passive Seismic Monitoring (PSM) network was operated before, during and after the ~17 day injection period. The seismic monitoring network consisted of two arrays of eight, three-component sensors, deployed in two monitoring wells at only a few hundred meters from the injection point. 225 microseismic events were detected by the arrays. Of these, only one event was clearly an injectioninduced microearthquake. It occurred during injection, approximately 100 m above the BILD formation. No events, down to the magnitude -3 detection limit, occurred within the BILD formation during the injection. The observed seismic waveforms associated with the other 224 events were quite unusual in that they appear to contain dominantly compressional (P) but no (or extremely weak) shear (S) waves, indicating that they are not associated with shear slip on faults. The microseismic events were unusual in two other ways. First, almost all of the events occurred prior to the start of injection into the BILD formation. Second, hypocenters of the 94 locatable events cluster around the wells where the sensor arrays were deployed, not the injection well. While the temporal evolution of these events show no 2 correlation with the BILD injection, they do correlate with CO 2 injection for enhanced oil recovery (EOR) into the 1670 m deep Coral Reef formation that had been going on for ~2.5 years prior to the pilot injection experiment into the BILD formation. We conclude that the unusual microseismic events reflect degassing processes associated with leakage up and around the monitoring wells from the EOR-related CO 2 injection into the Coral Reef formation, ~700 m below the depth of the monitoring arrays. This conclusion is also supported by the observation that as soon as injection into the Coral Reef formation resumed at the conclusion of the BILD demonstration experiment, seismic events (essentially identical to the events associated with the Coral Reef injection prior to the BILD experiment) again started to occur close to a monitoring arrays. Taken together, these observations point to vertical migration around the casings of the monitoring wellbores. Detection of these unusual microseismic events was somewhat fortuitous in that the arrays were deployed at the depth where the CO 2 undergoes a strong volume increase during transition from a supercritical state to a gas. Given the large number of pre-existing wellbores that exist in depleted oil and gas reservoirs that might be considered for CO 2 sequestration projects, passive seismic monitoring systems could be deployed at appropriate depths to systematically detect and monitor leakage along them.

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The potential for CO2 leakage through a permeable fault is a key concern for geologic CO2 sequestration (GCS) in saline formations. If CO2 migrates vertically upward through a fault from the storage reservoir to an overlying fresh‐water aquifer, phase change can occur because temperature and pressure decrease with decreasing depth. The decrease in CO2 density during phase transition causes an additional reduction in temperature. In this paper, we present a computational model for simulating the behaviour of a leaky fault connecting a saline CO2 storage reservoir and an overlying fresh‐water aquifer. We address phase transition, considering the nonlinear CO2 enthalpy and viscosity functions. The model results indicate that the CO2 leakage rate initially increases when CO2 migration is driven by both buoyancy and overpressure during the period of injection. In the post‐injection period, CO2 leakage is only driven by buoyancy and the leakage rate decreases. The influence of nonisothermal conditions is more pronounced during the first stage. The deterministic model of this faulted reservoir system is used within an uncertainty quantification (UQ) framework to rigorously quantify the sensitivity of the brine and CO2 leakage in response to the uncertain model parameters. The results demonstrate that fault permeability is the most sensitive factor affecting both CO2 and brine leakage rate. Reduced‐order models of CO2 and brine leakage are developed for the emulation of a large number of sample points, from which probability distributions are derived and can be incorporated in risk assessment of groundwater contamination resulting from CO2 and brine leakage. © 2012 Society of Chemical Industry and John Wiley & Sons, Ltd

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