We provide new kinematic data from the Potwar Plateau (Pakistan) to evaluate the tectonic evolution of the region during the Neogene. The plateau is bound by two major strike-slip faults in the west and the east, accommodating its southwards translation.We have recognized two Neogene deformation phases in the plateau, based on paleostress inversion and Anisotropy of Magnetic Susceptibility (AMS) tensors. The first phase lasted until the early Pliocene and was characterized by vertical minor stress and N-S compression, implying thrust tectonics. The second deformation phase is characterized by a near-vertical intermediate principal stress and near-horizontal major and minor stresses, interpreted to be associated with strike-slip tectonics since the late Pliocene.K int vectors from 21 sites are relatively compatible with the major principal stress orientations (σ 1 ) and indicate two distinct domains. This is possibly because K min orientations are related to compaction, whereas K int orientations were always parallel to tectonic shortening and hence compression direction during both strike-slip (post-late Pliocene) and thrusting (pre-late Pliocene) phases. These phases are characterized by swapping of (σ 2 ) and (σ 3 ) orientations while (σ 1 ) maintained its orientation. The most prominent change occurs at the western part of the Potwar Plateau, where major principal stress directions (σ 1 ) and K int axes fan out south-westwards. The eastern domain is dominated by NE-SW trending folds and thrust faults, which are absent in the western domain. These structural features are interpreted to be the result of the distribution of deposits of the Neoproterozoic Salt Range Formation as a substratum below the Potwar Plateau. The Salt Range Formation is very thick and widespread in the west area and almost absent in the east. This factor led to unconstrained southwards gliding of the Potwar Plateau over the salt deposits in the west as opposed to frictional sliding and substantial internal deformation in the east.

Both for the oil & gas and geothermal industry, induced seismicity caused by field development and operation can pose a risk, in particular when the reservoir (or overburden / underburden) is intersected by faults. The mechanisms by which faults can be reactivated (potentially leading to seismicity) include pressure effects (reservoir depletion, or pressure rise over large areas as a result of injection) or thermal effects (cooling such as in geothermal operations or heating such as in steam flooding). Earlier, we proposed a simple methodology to assess seismic risk for geothermal reservoirs that can also be applied to hydrocarbon reservoirs. This methodology uses an elastoplastic finite element model of the reservoir in question. However, its application turned out to be laborious. Therefore, we developed an exact analytical solution for the stress changes induced by cooling, depletion and /or pressurization along (a) representative fault(s). This solution is a generalisation of the Goodier analytical solution for the situation of non-vertical faults. The analytical solution can be used to quickly evaluate a number of different scenarios related to temperature and /or pressure distributions in the reservoir. In the case of fault activation, maximum fault displacements (slip) can be computed by linking the results to elastic finite element calculations for similar load conditions. Using published standard correlations, the seismic magnitude can subsequently be estimated from the computed fault displacements. The analytical model was applied to different fault geometries, reservoir temperature distributions and depletions. It turns out that certain fault geometries (dip angles, offsets) are far more prone to activation than other fault geometries. An explanation of this result is provided. Furthermore, for non-critically stressed faults, the risk of activation is far less for geothermal operations than for situations where large parts of the reservoir are depleted or pressurized. This can be explained by the fact that the extent of the cooled zone in geothermal operations is generally limited, even after 30 years of operation. Consequently, cooling-induced stress changes along the fault are significantly reduced because of arching by the adjacent non-cooled areas. Finally, one geothermal field example in The Netherlands is presented where the above methodology was applied to demonstrate that there exists no seismic risk over the entire field life.

A new methodology for a "Level 2" Seismic Hazard Assessment has been developed for a geothermal project. Geomechanical models were created to understand the thermo-mechanical effects in the lifetime of a specific geothermal operation. Two types of geomechanical models are used, a 3-D Mohr-Coulomb model using both a deterministic and a probabilistic methodology, and a 2-D elastoplastic finite element model, simulating the lifetime and the associated mechanical changes caused by the geothermal operation. The simulated results show that, under maximum production conditions, there is a <1% likelihood of induced seismicity. Using published correlations, the movement along a fault is used to calculate the maximum magnitude of the unlikely seismicity, projected to be the order of 1.5 to 2 Mw. As a mitigation method, a Traffic Light System is proposed. This allows the geothermal operation to continue while staying within the expected safety margins.

Faults have extensively been studied for hydrocarbon exploration and production; however, previous studies on fault behaviour for geological carbon storage have focused on sealing capacity or reactivation potential during injection or post-injection phases. Little is known on the impact of faults for estimating storage capacity in highly faulted basins. A geological conceptual model of a representative compartment was designed to identify the key drivers of storage capacity estimates in highly faulted basins. An uncertainty quantification framework was then designed upon this model to address the impact of geological uncertainties such as fault permeability, reservoir injectivity, compartment geometry and closure on the compartment storage capacity. Pressure-limited storage capacity was estimated from numerical simulation of CO2 injection under the constraints of maximum bottom hole pressure and fault reactivation pressure. Interpretation of the simulation results highlights that (1) two injection regimes are observed: borehole- or fault-controlled, (2) storage capacity can vary more than an order of magnitude, (3) fault and reservoir permeability can be regarded as the most influential properties with respect to storage capacity, (4) compartment geometry mainly influences the injection regime controlling the storage capacity and (5) the large sensitivity of storage capacity to the type of enclosure and fault permeability indicates that pressure build-up at the fault is often the deciding factor for CO2 storage capacity.