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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...

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a b s t r a c tIn 2004, injection of carbon dioxide (CO 2 ) to be stored at depth began at the In Salah Carbon Capture and Storage (CCS) site and a pilot microseismic monitoring array was installed in 2009. The In Salah project presents an unusual dataset since it is the first major non-Enhanced Oil Recovery (EOR) CCS project to be monitored for microseismicity. This paper outlines an extensive seismological study using a range of techniques, relying mainly on data from a single three-component geophone. Important information is derived from the data, such as event locations, event magnitudes and fracture characteristics, that could be used in real-time to regulate the geomechanical response of a site to CO 2 injection. The event rate closely follows the CO 2 injection rate, with a total of 9506 seismic events detected. The locations for a carefully selected subset of events are estimated to occur at or below the injection interval, thereby ruling out fault or fracture activation caused by CO 2 migration at shallow depths. A very small number of events (11) with less well-constrained locations may have occurred above the injection interval. However, there is no microseismic evidence that these events are correlated with CO 2 injection and we suggest they are caused by stress transfer rather than CO 2 migration into the caprock. The observed maximum moment magnitude, M w = 1.7, is consistent with estimated fracture dimensions at the injection depth. Fracture orientation estimated using shear-wave splitting analysis is approximately NW-SE, in agreement with fracture orientations inferred from logging data. During periods of high injection rates the degree of anisotropy increases slightly and then falls back to original values when injection rates fall. This implies the CO 2 is opening pre-existing fractures which then close as pressure decreases.This an important proof-of-concept study that proves the value of microseismic monitoring of CCS projects, even with a limited array. We thus recommend that microseismic monitoring arrays are installed prior to CO 2 injection at future CCS sites to enhance our understanding by making baseline and comparative studies possible. This would also provide real-time monitoring of the geomechanical response to injection, allowing operators to modify injection parameters and to help ensure the safe operation of a project.

A B S T R A C TWe present an assessment of how microseismic moment magnitude, M W , estimates vary with the method and parameters used to calculate seismic moment. This is an important topic for operators and regulators who require good magnitude estimates when monitoring induced seismicity. It is therefore imperative that these parties know and understand what errors exist in given magnitude values, something that is poorly reported. This study concentrates on spectral analysis techniques and compares M W computed in the time and frequency domains. Using recordings of M W > −1.5 events at Cotton Valley, east Texas, the maximum discrepancy between M W estimated using the different methods is 0.6 units, a significant variation. By adjusting parameters in the M W calculation we find that the radiation pattern correction term can have the most significant effect on M W , generally up to 0.8 units. Following this investigation we make a series of recommendations for estimating microseismic M W using spectral methods. Noise should be estimated and removed from recordings and an attenuation correction should be applied. The spectral level can be measured by spectral fitting or taken from the low frequency level. Significant factors in obtaining reliable microseismic M W estimates include using at least four receivers recording at ≥1000 Hz and making radiation pattern corrections based on focal mechanism solutions, not average values.Key words: Microseismic monitoring, seismic moment, moment magnitude, spectral methods. I N T R O D U C T I O NSeismic moment, M 0 , and moment magnitude, M W , are important parameters in monitoring induced seismicity because the dimensions of activated fractures and an estimate of the seismic energy release can subsequently be derived. For hydraulic fracturing or geothermal exploration projects this allows operators to assess the extent of the stimulated rock volume and the efficiency of injection activities (Maxwell et al. 2006;Shapiro et al. 2011). Ideally operators would like to observe many E-mail: anna.stork@bristol.ac.uk This is an open access article under the terms of the Creative Commons Attribution License, which permits use, distribution and reproduction in any medium, provided the original work is properly cited. small events (M W < 0), indicating increased fracture density around the injection point, and no larger events (M W > 0) because this could indicate that pre-existing faults are being activated, which may lead to a dissipation of injection fluid and increased seismic hazard. To assess seismic hazard an estimate of the expected magnitude of induced earthquakes can be determined by assuming the Gutenberg-Richter law for frequency-magnitude distribution (e.g., Shapiro et al. 2011;Dinske and Shapiro, 2013). This model is given bywhere N is the number of earthquakes with magnitude greater than M and a and b are constants to describe the equation of a straight line when plotted semi-logarithmically. The