Deep drilling and induced seismicity experiments at several locations worldwide indicate that, in general, the brittle crust in intraplate regions is critically stressed, pore pressures are close to hydrostatic, and in situ bulk permeability is ∼10 −17 to 10 −16 m 2 . This high permeability, three or four orders of magnitude higher than that measured on core samples, appears to be maintained by critically stressed faults and greatly facilitates fluid movement through the brittle crust. We demonstrate that such high permeabilities can maintain approximately hydrostatic fluid pressures at depths comparable to the thickness of the seismogenic crust. This leads to the counterintuitive result that faulting keeps intraplate crust inherently strong by preventing pore pressures greater than hydrostatic from persisting at depth.

How faulting keeps the crust strong

We produced a high‐resolution microseismic image of a hydraulic fracture stimulation in the Carthage Cotton Valley gas field of east Texas. We improved the precision of microseismic event locations four‐fold over initial locations by manually repicking the traveltimes in a spatial sequence, allowing us to visually correlate waveforms of adjacent sources. The new locations show vertical containment within individual, targeted sands, suggesting little or no hydraulic communication between the discrete perforation intervals simultaneously treated within an 80‐m section. Treatment (i.e., fracture‐zone) lengths inferred from event locations are about 200 m greater at the shallow perforation intervals than at the deeper intervals. The highest quality locations indicate fracture‐zone widths as narrow as 6 m. Similarity of adjacent‐source waveforms, along with systematic changes of phase amplitude ratios and polarities, indicate fairly uniform source mechanisms (fracture plane orientation and sense of slip) over ...

Hydraulic stimulation of natural fractures as revealed by induced microearthquakes, Carthage Cotton Valley gas field, east Texas

SUMMARY Claerbout’s daylight imaging concept is generalized to a theory of interferometric seismic imaging (II). Interferometric seismic imaging is defined to be any algorithm that inverts correlated seismic data for the reflectivity or source distribution. As examples, we show that II can image reflectivity distributions by migrating ghost reflections in passive seismic data and generalizes the receiver-function imaging method used by seismologists. Interferometric seismic imaging can also migrate free-surface multiples in common depth point (CDP) data and image source distributions from passive seismic data. Both synthetic and field data examples are used to illustrate the different possibilities of II. The key advantage of II is that it can image source locations or reflectivity distributions from passive seismic data where the source position or wavelet is unknown. In some cases it can mitigate defocusing errors as a result of statics or an incorrect migration velocity. The main drawback with II is that severe migration artefacts can be created by partial focusing of virtual multiples.

/pdf/interferometric-daylight-seismic-imaging-28gn3cc68g.pdf

Interferometric/daylight seismic imaging

We systematically describe an approach to estimate the large-scale permeability of reservoirs using seismic emission (microseismicity) induced by fluid injection. We call this approach seismicity-based reservoir characterization (SBRC). A simple variant of the approach is based on the hypothesis that the triggering front of hydraulically-induced microseismicity propagates like a diffusive process (pore pressure relaxation) in an effective homogeneous anisotropic poroelastic fluid-saturated medium. The permeability tensor of this effective medium is the permeability tensor upscaled to the characteristic size of the seismically active heterogeneous rock volume. We show that in a homogeneous medium the surface of the seismicity triggering front has the same form as the group-velocity surface of the low-frequency anisotropic, second-type Biots wave (i.e., slow wave). Further, we generalize SBRC for 3-D mapping of the permeability tensor of heterogeneous reservoirs and aquifers. For this we apply an approach similar to the geometric optics approximation. We derive an equation describing kinematic aspects of triggering-front propagation in a way similar to the eikonal equation for seismic wavefronts. In the case of isotropic heterogeneous media, the inversion for the hydraulic properties of rocks follows from a direct application of this equation. In the case of an anisotropic heterogeneous medium, only the magnitude of a global effective permeability tensor can be mapped in a 3-D spatial domain. We demonstrate the method on several field examples and also test the eikonal equation-based inversion.

Characterization of fluid transport properties of reservoirs using induced microseismicity

Analysis of induced seismicity in geothermal reservoirs – An overview

Summary

We propose an approach for estimating the permeability tensor using seismic emission induced by borehole hydraulic tests or by a fluid injection of an arbitrary nature. This approach provides a single estimation of the permeability tensor for the complete heterogeneous rock volume where the seismic emission was recorded. The approach is an extension of the method proposed by Shapiro et al. (1997) for the isotropic case. It is based on the hypothesis that the triggering front of the hydraulic-induced microseismicity propagates like a low-frequency second-type compressional Biot wave (corresponding to the process of pore-pressure relaxation) in an effective homogeneous anisotropic poroelastic fluid-saturated medium. The permeability tensor of this effective medium is the permeability tensor of the heterogeneous rock volume upscaled to the characteristic size of the seismically active region. We demonstrate the method using the microseismic data collected during the Hot Dry Rock Soultz-sous-Forets experiment (Dyer et al. 1994). These data show that the corresponding rock volume is characterized by a significant permeability anisotropy caused by oriented crack systems. The maximal principal component of the permeability tensor has a subvertical orientation. It is about seven times larger than the minimal subhorizontal principal component.

Large-scale in situ permeability tensor of rocks from induced microseismicity

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Large-scale in situ permeability tensor of rocks from induced microseismicity