Fracture networks inside geologic ${\mathrm{CO}}_2$ storage reservoirs can serve as the primary fluid flow conduit, particularly in low-permeability formations. Although some experiments focus on the geophysical properties of brine- and ${\mathrm{CO}}_2$-saturated rocks during matrix flow, geophysical monitoring of fracture flow when ${\mathrm{CO}}_2$ displaces brine inside the fracture seems to be overlooked. We have conducted laboratory geophysical monitoring of fluid flow in a naturally fractured tight sandstone during brine and liquid ${\mathrm{CO}}_2$ injection. For the experiment, the low-porosity, low-permeability, naturally fractured core sample from the Triassic De Geerdalen Formation was acquired from the Longyearbyen ${\mathrm{CO}}_2$ storage pilot at Svalbard, Norway. Stress dependence, hysteresis, and the influence of fluid-rock interactions on fracture permeability were investigated. The results suggest that in addition to stress level and pore pressure, mobility and fluid type can affect fracture permeability during loading and unloading cycles. Moreover, the fluid-rock interaction may impact volumetric strain and consequently fracture permeability through swelling and dry out during water and ${\mathrm{CO}}_2$ injection, respectively. Acoustic velocity and electrical resistivity were measured continuously in the axial direction and three radial levels. Geophysical monitoring of fracture flow revealed that the axial P-wave velocity and axial electrical resistivity are more sensitive to saturation change than the axial S-wave, radial P-wave, and radial resistivity measurements when ${\mathrm{CO}}_2$ was displacing brine, and the matrix flow was negligible. The marginal decreases of acoustic velocity (maximum 1.6% for axial $V_{\mathrm{P}}$) compared with the 11% increase in axial electrical resistivity suggest that in the case of dominant fracture flow within the fractured tight reservoirs, the use of electrical resistivity methods have a clear advantage compared with seismic methods to monitor ${\mathrm{CO}}_2$ plume. The knowledge learned from such experiments can be useful for monitoring geologic ${\mathrm{CO}}_2$ storage in which the primary fluid flow conduit is the fracture network.

Fractures and faults are critical elements affecting the geomechanical integrity of CO₂ storage sites. In particular, the slip of fractures and faults may affect reservoir integrity and increase potential for breach, may be monitored via the resulting seismicity. This paper presents an experimental study on shale samples from Draupne and Rurikfjellet formations from the North Sea and Svalbard, Norway, using a laboratory test procedure simulating the slip of fractures and faults under realistic stress conditions for North Sea CO₂ storage sites. The motivation of the study is to investigate whether the slip along the fractures within these shales may cause detectable seismic events, based on a slip stability criterion. Using a direct shear apparatus, frictional properties of the fractures were measured during shearing, as a function of the shear velocity and applied stress normal to the fracture. We calculated the friction coefficient of the fractures during the different stages of the shear tests and analysed its dependency on shear velocity. Information on velocity-dependent friction coefficient and its evolution with increasing slip were then used to assess whether slip was stable (velocity-strengthening) or unstable (velocity-weakening). Results showed that friction coefficient for both Draupne and Rurikfjellet shales increased when the shear velocity was increased from 10 to 50 µm/s, indicating a velocity-strengthening behaviour. Such a behaviour implies that slip on fractures and faults within these formations may be less prone to producing detectable seismicity during a slip event. These results will have implications for the type of techniques to be used for monitoring reservoir and caprock integrity, for instance, for CO₂ storage sites.

This paper presents a probabilistic seismic hazard analysis (PSHA) for a site offshore Maheshkhali Island, Bangladesh. The tectonic setting of the area is complex, and the PSHA includes active crustal faults, megathrust and intraplate subduction faults, and a background gridded seismicity areal source zone based on historical and recorded earthquakes. In addition, we model several rupture scenarios for the closest megathrust source. The peak ground acceleration values for return periods of 475 years and 2475 years are 0.33 g and 0.63 g, respectively. These values are higher than previous studies conducted in the area, however, past studies only included areal source zones based on recorded seismicity whereas this study takes advantage of recent research to include more detailed fault data. The deaggregation plots show that the main contributors to the hazard are a magnitude 6.5–7.1 earthquake 15–20 km from the site on the Maheshkhali fault and a magnitude 8.0–8.8 earthquake 120–250 km from the site on the Ramree megathrust.

We present a generalized Geertsma solution that can consider any number of finite-thickness layers in the subsurface whose mechanical properties are different from layer to layer. In addition, each layer can be assumed either isotropic or anisotropic. The accuracy of the generalized solution is validated against a numerical reference solution. The generalized Geertsma solution is further extended by a linear superposition framework that enables a response simulation due to an arbitrarily-distributed non-uniform pressure anomaly. The linear superposition approach is tested and validated by solving a realistic synthetic model based on the In Salah CO₂ storage model and compared with a full 3D finite element solution. Finally, by means of a simple inversion exercise (based on the linear superposition approach), we learn that the stiffnesses of cap rock and reservoir are the most influencing parameter on the inversion result for a given layering geometry, suggesting that it is very important to estimate high-confidence mechanical properties of both cap rock and reservoir.

This investigation provides an in-depth experimental analysis of the prepared artificial fault gouge material on permeability characteristics as a function of the confining pressures and injection flow rate pertinent to both CO₂ storage and subsurface fluid flow that addresses an ultimate challenge in CO₂ storage. The purpose of the research is to gain a better understanding of the role of fault gouge material in structuring fluid flow patterns within geological media and improving the safety and efficiency of subsurface storage systems. In order to ensure the reproducibility of the experimental program, fault gouge material that resembled the size distribution and material type observed in the field and reported within the literature was purposefully designed and prepared. A set of core-flooding experiments were conducted to evaluate the relationships between permeability, confining pressure, and fluid flow rates. The subsequently obtained results showed that lower permeability is always the result of increasing confining pressure, highlighting the significance of fault gouge material for controlling fluid flow in fractured rock formations. These conclusions provide novel insights and can be applicable in practice when evaluating the integrity of CO₂ storage sites, which calls for knowledge of permeability behavior under high-stress conditions.