Understanding the controls on the elastic properties of reservoir rocks is crucial for exploration and successful production from hydrocarbon reservoirs. We studied the static and dynamic elastic properties of shale gas reservoir rocks from Barnett, Haynesville, Eagle Ford, and Fort St. John shales through laboratory experiments. The elastic properties of these rocks vary significantly between reservoirs (and within a reservoir) due to the wide variety of material composition and microstructures exhibited by these organicrich shales. The static (Young's modulus) and dynamic (P-and S-wave moduli) elastic parameters generally decrease monotonically with the clay plus kerogen content. The variation of the elastic moduli can be explained in terms of the Voigt and Reuss limits predicted by end-member components. However, the elastic properties of the shales are strongly anisotropic and the degree of anisotropy was found to correlate with the amount of clay and organic content as well as the shale fabric. We also found that the first-loading static modulus was, on average, approximately 20% lower than the unloading/reloading static modulus. Because the unloading/reloading static modulus compares quite well to the dynamic modulus in the rocks studied, comparing static and dynamic moduli can vary considerably depending on which static modulus is used.

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Determining the seismic fracture energy during an earthquake and understanding the associated creation and development of a fault zone requires a combination of both seismological and geological field data. The actual thickness of the zone that slips during the rupture of a large earthquake is not known and is a key seismological parameter in understanding energy dissipation, rupture processes and seismic efficiency. The 1999 magnitude-7.7 earthquake in Chi-Chi, Taiwan, produced large slip (8 to 10 metres) at or near the surface, which is accessible to borehole drilling and provides a rare opportunity to sample a fault that had large slip in a recent earthquake. Here we present the retrieved cores from the Taiwan Chelungpu-fault Drilling Project and identify the main slip zone associated with the Chi-Chi earthquake. The surface fracture energy estimated from grain sizes in the gouge zone of the fault sample was directly compared to the seismic fracture energy determined from near-field seismic data. From the comparison, the contribution of gouge surface energy to the earthquake breakdown work is quantified to be 6 per cent.

The long‐term temporal and spatial changes in statistical, source, and stress characteristics of one cluster of induced seismicity recorded at The Geysers geothermal field (U.S.) are analyzed in relation to the field operations, fluid migration, and constraints on the maximum likely magnitude. Two injection wells, Prati‐9 and Prati‐29, located in the northwestern part of the field and their associated seismicity composed of 1776 events recorded throughout a 7 year period were analyzed. The seismicity catalog was relocated, and the source characteristics including focal mechanisms and static source parameters were refined using first‐motion polarity, spectral fitting, and mesh spectral ratio analysis techniques. The source characteristics together with statistical parameters (b value) and cluster dynamics were used to investigate and understand the details of fluid migration scheme in the vicinity of injection wells. The observed temporal, spatial, and source characteristics were clearly attributed to fluid injection and fluid migration toward greater depths, involving increasing pore pressure in the reservoir. The seasonal changes of injection rates were found to directly impact the shape and spatial extent of the seismic cloud. A tendency of larger seismic events to occur closer to injection wells and a correlation between the spatial extent of the seismic cloud and source sizes of the largest events was observed suggesting geometrical constraints on the maximum likely magnitude and its correlation to the average injection rate and volume of fluids present in the reservoir.

We studied the elastic moduli, ductile creep behavior, and brittle strength of shale-gas reservoir rocks from Barnett, Haynesville, Eagle Ford, and Fort St. John shale in a series of triaxial laboratory experiments. We found a strong correlation between the shale compositions, in particular, the volume of clay plus kerogen and intact rock strength, frictional strength, and viscoplastic creep. Viscoplastic creep strain was approximately linear with the applied differential stress. The reduction in sample volume during creep suggested that the creep was accommodated by slight pore compaction. In a manner similar to instantaneous strain, there was more viscoplastic creep in samples deformed perpendicular to the bedding than parallel to the bedding. The tendency to creep also correlated well with the static Young's modulus. We explained this apparent correlation between creep behavior and elastic modulus by appealing to the stress partitioning that occurs between the soft components of the shales (clay and kerogen) and the stiff components (quartz, feldspar, pyrite, and carbonates). Through a simple 1D analysis, we found that a unique relation between the creep compliance and elastic modulus, independent of composition and orientation, can be established by considering the individual creep behavior of the soft and stiff components that arises from the stress partitioning within the rock. This appears to provide a mechanical explanation for why long-term ductile deformational properties can appear to correlate with short-term elastic properties in shale-gas reservoir rocks.

The spatiotemporal, kinematic, and source characteristics of induced seismicity occurring at different fluid injection rates are investigated to determine the predominant physical mechanisms responsible for induced seismicity at the northwestern part of The Geysers geothermal field, California. We analyze a relocated hypocenter catalog from a seismicity cluster where significant variations of the stress tensor orientation were previously observed to correlate with injection rates. We find that these stress tensor orientation changes may be related to increased pore pressure and the corresponding changes in poroelastic stresses at reservoir depth. Seismic events during peak injections tend to occur at greater distances from the injection well, preferentially trending parallel to the maximum horizontal stress direction. In contrast, at lower injection rates the seismicity tends to align in a different direction which suggests the presence of a local fault. During peak injection intervals, the relative contribution of strike-slip faulting mechanisms increases. Furthermore, increases in fluid injection rates also coincide with a decrease in b values. Our observations suggest that regardless of the injection stage, most of the induced seismicity results from thermal fracturing of the reservoir rock. However, during peak injection intervals, the increase in pore pressure may likewise be responsible for the induced seismicity. By estimating the thermal and hydraulic diffusivities of the reservoir, we confirm that the characteristic diffusion length for pore pressure is much greater than the corresponding length scale for temperature and also more consistent with the spatial extent of seismicity observed during different injection rates.

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