Monitoring of induced seismicity is gaining importance in a broad range of industrial operations from hydrocarbon reservoirs to mining to geothermal fields. Such passive seismic monitoring mainly aims at identifying fractures, which is of special interest for safety and productivity reasons. By analysing shear‐wave splitting it is possible to determine the anisotropy of the rock, which may be caused by sedimentary layering and/or aligned fractures, which in turn offers insight into the state of stress in the reservoir. We present a workflow strategy for automatic and effective processing of passive microseismic data sets, which are ever increasing in size. The automation provides an objective quality control of the shear‐wave splitting measurements and is based on characteristic differences between the two independent eigenvalue and cross‐correlation splitting techniques. These differences are summarized in a quality index for each measurement, allowing identification of an appropriate quality threshold. Measurements above this threshold are considered to be of good quality and are used in further interpretation. We suggest an automated inversion scheme using rock physics theory to test for best correlation of the data with various combinations of fracture density, its strike and the background anisotropy. This fully automatic workflow is then tested on a synthetic and a real microseismic data set.

Earthquakes induced by subsurface fluid injection pose a significant issue across a range of industries. Debate continues as to the most effective methods to mitigate the resulting seismic hazard. Observations of induced seismicity indicate that the rate of seismicity scales with the injection volume and that events follow the Gutenberg–Richter distribution. These two inferences permit us to populate statistical models of the seismicity and extrapolate them to make forecasts of the expected event magnitudes as injection continues. Here, we describe a shale gas site where this approach was used in real time to make operational decisions during hydraulic fracturing operations.Microseismic observations revealed the intersection between hydraulic fracturing and a pre‐existing fault or fracture network that became seismically active. Although “red light” events, requiring a pause to the injection program, occurred on several occasions, the observed event magnitudes fell within expected levels based on the extrapolated statistical models, and the levels of seismicity remained within acceptable limits as defined by the regulator. To date, induced seismicity has typically been regulated using retroactive traffic light schemes. This study shows that the use of high‐quality microseismic observations to populate statistical models that forecast expected event magnitudes can provide a more effective approach.

No abstract

Geological storage of CO 2 that has been captured at large, point source emitters represents a key potential method for reduction of anthropogenic greenhouse gas emissions. However, this technology will only be viable if it can be guaranteed that injected CO 2 will remain trapped in the subsurface for thousands of years or more. A significant issue for storage security is the geomechanical response of the reservoir. Concerns have been raised that geomechanical deformation induced by CO 2 injection will create or reactivate fracture networks in the sealing caprocks, providing a pathway for CO 2 leakage. In this paper, we examine three large-scale sites where CO 2 is injected at rates of ∼1 megatonne/y or more: Sleipner, Weyburn, and In Salah. We compare and contrast the observed geomechanical behavior of each site, with particular focus on the risks to storage security posed by geomechanical deformation. At Sleipner, the large, high-permeability storage aquifer has experienced little pore pressure increase over 15 y of injection, implying little possibility of geomechanical deformation. At Weyburn, 45 y of oil production has depleted pore pressures before increases associated with CO 2 injection. The long history of the field has led to complicated, sometimes nonintuitive geomechanical deformation. At In Salah, injection into the water leg of a gas reservoir has increased pore pressures, leading to uplift and substantial microseismic activity. The differences in the geomechanical responses of these sites emphasize the need for systematic geomechanical appraisal before injection in any potential storage site.carbon sequestration | geomechanics | InSAR | microseismic monitoring C arbon capture and storage (CCS)-where CO 2 is captured at large point source emitters (such as coal-fired power stations) and stored in suitable geological repositories-has been touted as a technology with the potential to achieve dramatic reductions in anthropogenic greenhouse gas emissions (1, 2). However, its success is dependent on the ability of reservoirs to retain CO 2 over long timescales (a minimum of several thousand years). If CCS is to make a significant impact on global emissions, more than 3.5 billion tons of CO 2 per year must be stored (3), which at reservoir conditions will have a volume of ∼30 billion barrels (4).Secure storage of such large volumes of CO 2 requires more than just the availability of the appropriate volumes of pore space. CO 2 is buoyant in comparison with the saline brines that fill the majority of putative storage sites. Therefore, injected CO 2 will rise through porous rocks and return to the surface, unless trapped by impermeable sealing layers (such as shales and evaporites). Preliminary estimates have tended to indicate that, from a volumetric perspective at least, sufficient storage capacity exists for many decades of CO 2 emissions in deep-lying saline aquifers that have suitable sealing capability (5).It is equally important that the integrity of the seal is not compromised by injection activitie...

S U M M A R YThe ability to detect aligned fractures using seismic anisotropy provides a valuable tool for exploiting hydrocarbon reservoirs better. Perhaps the most direct way of identifying anisotropy is by observing shear wave splitting. However, the interaction of shear waves with subsurface structure is often complicated. Although fractures in hydrocarbon reservoirs are usually subvertical, shear waves recorded on downhole receivers from microseismic events in or near the reservoir are not likely to have travelled vertically. As such, interpreting splitting measurements made on such waves is a non-trivial problem. Here we develop an approach to model the effects of subsurface structure on non-vertically propagating shear waves. Rock physics theory is used to model the effects of sedimentary fabrics as well as fractures, allowing us to use shear wave splitting measurements to invert for aligned fractures. We use synthetic examples to demonstrate how it is possible to assess in advance how well splitting measurements will image structures, and how this is highly dependent on the available range of ray coverage. Finally, we demonstrate the inversion technique on a passive seismic data set collected during hydraulic fracture stimulation. Despite an unfavourable source-receiver geometry, the strike of an aligned fracture set is accurately identified.

Recent work in hydrocarbon reservoir monitoring has focused on developing coupled geomechanical/fluid-flow simulations to allow production-related geomechanical effects, such as compaction and subsidence, to be included in reservoir models. To predict realistic time-lapse seismic signatures, generation of appropriate elastic models from geomechanical output is required. These elastic models should include not only the fluid saturation effects of intrinsic, shapeinduced, and stress-induced anisotropy, but also should incorporate nonlinear stress-dependent elasticity. To model nonlinear elasticity, we use a microstructural effective-medium approach in which elasticity is considered as a function of mineral stiffness and additional compliance is caused by the presence of low-aspect ratio displacement discontinuities. By jointly inverting observed ultrasonic P-and S-wave velocities to determine the distribution of such discontinuities, we assessed the appropriateness of modeling them as simple, planar, penny-shaped features. By using this approximation, we developed a simple analytical approach to predict how seismic velocities will vary with stress. We tested our approach by analyzing the elasticity of various sandstone samples; from a United Kingdom continental shelf ͑UKCS͒ reservoir, some of which display significant anisotropy, as well as two data sets taken from the literature.

No abstract

Earthquakes induced by subsurface industrial activities are a globally emotive issue, with a growing catalog of induced earthquake sequences. However, attempts at discriminating between natural and induced causes, particularly for anomalously shallow seismicity, can be challenging. An earthquake swarm during 2018–2019 in southeast England with a maximum magnitude of ML 3.2 received great public and media attention because of its proximity to operating oilfields. It is therefore vital and timely to provide a detailed characterization of the earthquake sequence at present, and to decide based on current evidence, whether the earthquakes were likely natural or induced. We detected 168 low‐magnitude earthquakes and computed detailed source parameters of these events. Most earthquakes occurred at a shallow depth of 2.3 km, >1  km deeper than the geological formations targeted by the oilfields, and laterally >3  km away from the drill sites. We combine the east–west‐trending cluster of the seismicity with 2D seismic reflection profiles to find the causative fault system for the earthquakes. A b‐value close to unity and strike‐slip faulting mechanisms are consistent with tectonic reactivation along a pre‐existing fault. Overall, we find no indicators in the earthquake parameters that would strongly suggest an induced source. Nor do we find any clear trends between seismicity and drilling activities based on operational logs provided by the operators. Injected volumes are near zero and monthly production amounts are many orders of magnitude smaller than other reported cases of extraction‐induced seismicity. On balance, and based on the available evidence, we find it currently unlikely that nearby industrial activities induced the seismic swarm. Most likely, the Surrey earthquakes offer a uniquely detailed insight into shallow seismicity within sedimentary basins. Nevertheless, self‐reporting of injection and production times and volumes by operators, and the lack of easily and publicly available oilfield operational data continues to be a point of concern for local residents.