An experimental study of the physical properties of black, kerogen‐rich shales, also including maturation analysis, scanning electron microscope (SEM) observations, and physical modeling, revealed fairly peculiar petrophysical parameters. Specifically, these rocks have very low porosity and density, but most importantly, both P and S ultrasonic velocities normal to bedding are extremely low, whereas they are much higher parallel to bedding, giving rise to a strong anisotropy even at high confining pressures. We found that these parameters primarily reflect kerogen content, microstructure, and maturation level of these rocks. We found also that microcracks inferred from ultrasonic velocity measurements occur only in mature shales. These microcracks are parallel to the bedding plane and further enhance strong intrinsic anisotropy, notably at low effective pressure. Our results show, that on a small scale, kerogen‐rich shales are transversely isotropic rocks and can be effectively modeled using the thin‐layer composite concept modified to account for the specific distribution of organic matter in the rock fabric.

Using ultrasonic velocity and anisotropy measurements on a variety of shales with different clay and kerogen content, clay mineralogy, and porosity at a wide range of effective pressure, we find that elastic anisotropy of shales increases substantially with compaction. The effect is attributed to both porosity reduction and smectite‐ to‐illite transformation with diagenesis. A means of kerogen content mapping using velocity versus porosity crossplot for shales is shown. Matrix anisotropy of shales dramatically increases with kerogen reaching the maximum values of about 0.4 at total organic carbon (TOC)=15–20%. A strong chemical softening effect was found in shales containing even minor amounts of swelling (smectite) clay when saturated with aqueous solution. This effect results in a significant P‐wave anisotropy reduction as compared to dry and oil‐saturated shales. Since mature black shales are normally oil wet, this effect can only have a local significance restricted to the wellbore wall. Accurate measurements of phase velocities, including velocities at a 45° direction to the bedding plane, allow us to immediately calculate elastic stiffnesses and anisotropic parameters. Intrinsic (high pressure) properties of shales display an ε > δ > 0 relation. Introduction of the bedding‐parallel microcracks in overpressured shales results in a δ decrease when fully fluid saturated and a δ increase when partially gas saturated, with a characteristic effect on the shape of the P‐wave velocity surface at small angles of incidence. Filtering the contribution of the intrinsic anisotropy of shales, it is possible to estimate the pore fluid phase, microcrack density, and aspect ratio parameters using seismic anisotropy measurements.

In this paper we utilize the mechanical properties of core samples, detailed observations of stress‐induced well bore breakouts and estimates of the magnitude of Shmin from hydraulic fracturing experiments to construct a vertical profile of the maximum horizontal principal stress SHmax to 3.5 km depth in the Cajon Pass borehole. As in essentially all other boreholes, the hydraulic fracturing stress measurements in the Cajon Pass borehole yielded appreciably more (and more reliable) data on the magnitude of the least principal horizontal stress, Shmin, than the maximum principal horizontal stress, SHmax. To utilize the breakout observations to constrain the magnitude of SHmax, a brittle failure criterion was used that is based on the effective strain energy concept. This failure criterion also allows us to account for the polyaxial stress around the borehole and to incorporate the role of pore fluid pressure on rock strength in various ways. A comparison of the SHmax profile estimated from the breakouts with estimates of SHmax obtained from the hydraulic fracturing tests indicates that they compare fairly well for the case when the effect of pore pressure on hydraulic fracture initiation is negligible. The overall stress state to a depth of 3.5 km in the well corresponds to a normal/strike‐slip faulting regime. The SHmax profile indicates several marked decreases in stress magnitude associated with major fault zones, an observation consistent with the Shmin profile obtained from hydraulic fracturing tests.

Several publications over the last 20 years have established that black organic shales are generally characterized by strong velocity anisotropy, low velocity in the bedding-normal direction, and relatively low density and porosity (e.g., Vernik and Nur, 1992; Vernik and Liu, 1997). These rock properties are of interest in seismic attribute studies, but even more so in geomechanical applications related to reservoir characterization and hydraulic fracture stimulation. Organic shales typically, but not necessarily, express strong vertical transverse isotropy (VTI), with axis of symmetry perpendicular to the bedding-parallel lamination and clay-particle-preferred orientation. High-resolution SEM imaging (Figure 1) immediately reveals all these textural features in addition to silt grains and the lenticular distribution of the solid organic matter (kerogen), which in turn is characterized by significant intraparticle porosity in mature shales. Any TI medium is described by the five independent elastic constants ([Formula: see text], [Formula: see text], [Formula: see text], [Formula: see text], and [Formula: see text]) and detailed multidirectional ultrasonic core measurements can provide the most accurate means for their adequate evaluation. Single-well sonic- and density-log data fall short of the full TI tensor description resulting in major ambiguities related to empirical correlations.

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