Probabilistic geomechanical analysis of compartmentalization at the Snøhvit CO₂ sequestration project

Abstract

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 review of developments in carbon dioxide storage

“…The Snøhvit project sources its CO2 from an LNG processing project. The CO2 is captured by a scrubbing approach [285], transported via pipeline from onshore to offshore (Figure 14), and stored in the saline Tubaen sandstone formation reservoirs at 2600 m deep with a thickness of 45 to 75 m [89]. The total storage capacity of sandstone reservoir formation is estimated around 31 to 40 Mt, and about 0.7 Mt of CO2 has been safely stored per year.…”

Characterizing the Potential for Injection‐Induced Fault Reactivation Through Subsurface Structural Mapping and Stress Field Analysis, Wellington Field, Sumner County, Kansas

“…When considering the injection of CO 2 in areas susceptible to earthquakes, the possibility of damaging seals and causing leakage into overlying strata and underground freshwater aquifers is a major concern (e.g., Benson & Cole, 2008;Chiaramonte et al, 2015;Morris et al, 2010;Streit & Hillis, 2004;Vilarrasa et al, 2014). CO 2 is less dense and more buoyant than in situ fluids and therefore rises to the base of overlying seals.…”

The Influence of Hydraulic Fracturing on Carbon Storage Performance

“…This is particularly true for reservoirs with relatively low permeabilities and consequently low injectivities. To date, high permeability reservoirs that provide favorable injection and storage conditions have been favored for use in CO 2 sequestration projects, such as the Sleipner and Snøhvit sites (Boait et al, ; Chiaramonte et al, ; Eiken et al, ; Verdon et al, ). However, significant reduction in global greenhouse gas emission requires extremely large volumes of CO 2 injection (Ehlig‐Economides & Economides, ; Pacala & Socolow, ; Zoback & Gorelick, ), and therefore, saline aquifers with a wide spectrum of permeabilities, including relatively low permeabilities, will have to be considered.…”