Shales are complex porous materials, normally consisting of percolating and interpenetrating fluid and solid phases. The solid phase is generally comprised of several mineral components and forms an intricate and anisotropic microstructure. The shape, orientation, and connection of the two phases control the anisotropic elastic properties of the composite solid. We develop a theoretical framework that allows us to predict the effective elastic properties of shales. Its usefulness is demonstrated with numerical modeling and by comparison with established ultrasonic laboratory experiments. The theory is based on a combination of anisotropic formulations of the self‐consistent (SCA) and differential effective‐medium (DEM) approximations. This combination guarantees that both the fluid and solid phases percolate at all porosities. Our modeling of the elastic properties of shales proceeds in four steps. First, we consider the case of an aligned biconnected clay‐fluid composite composed of ellipsoidal inclusions. Anisotropic elastic constants are estimated for a clay‐fluid composite as a function of the fluid‐filled porosity and the aspect ratio of the inclusions. Second, a new processing technique is developed to estimate the distribution of clay platelet orientations from digitized scanning electron microphotographs (SEM). Third, the derived clay platelet distribution is employed to estimate the effective elastic parameters of a solid comprising clay‐fluid composites oriented at different angles. Finally, silt minerals are included in the calculations as isolated spherical inclusions.

The ultrasonic anisotropic elastic properties of drained, saturated shales were measured as a function of confining pressure. Two shales were characterized in this study: a Jurassic outcrop shale retrieved under the sea in a saturated state and a Kimmeridge Clay shale cut from a North Sea borehole. Both shales were highly anisotropic, both texturally, as revealed by scanning electron microscopy analysis, and elastically, as measured ultrasonically in the laboratory. The strongest anisotropy was seen in the Kimmeridge Clay shale, where up to 38% compressional wave anisotropy (Thomsen's parameter ε) and up to 58% shear wave anisotropy (Thomsen's parameter γ) were observed. In addition, for both shales, ε and γ were found to decrease as a function of increasing confining pressure, with the pore pressure drained to atmosphere, while the anellipticity (deviation of the slowness surfaces from ellipses) was found to be positive and decreased as a function of increasing confining pressure. Accompanying these changes in elastic properties was a decrease in porosity with increasing confining pressure, from 10.5 to 8.5% for the Jurassic shale. The decrease in overall anisotropy of the shales with increasing confining pressure was found to be consistent with theoretical modeling of shale properties where the shale anisotropy and anellipticity were predicted to decrease as a function of decreasing fluid‐filled porosity.

We use the low‐frequency reflected Stoneley‐wave mode to locate permeable fractures intersecting a borehole and to estimate their effective apertures. Assuming a model in which the average aperture of the fracture is roughly constant, theoretical work relates the magnitude of the Stoneley‐wave reflectivity to an effective fracture width, We treat both the case of a horizontal fracture and the case of a fracture crossing the borehole at an angle. Laboratory experiments verify the analytic solution for the case of a horizontal fracture. Full‐waveform array sonic data were also acquired in a wellbore with a long recording time (25.5 ms) in order to capture the late Stoneley‐wave arrivals. The data processing involves computation of the Stoneley‐wave reflectivity response using the measured direct and reflected Stoneley‐wave arrivals. A least‐squares fit to the arrival time of the reflected‐wave arrivals is used to estimate the locations of permeable fractures, and the effective width of the fractures is estimated by comparing the computed Stoneley‐wave reflectivity to the theoretical response from a parallel‐plate model. Test‐well results are consistent with a borehole televiewer analysis.

The full waveforms recorded by an array of receivers in a modern borehole sonic tool contain secondary arrivals that are reflected from near‐borehole structural features. These arrivals are used to form an image of the near‐borehole structural features in a manner similar to seismic migration. Possible uses of this technique include horizontal well logging; structural dip and contour determination; fault, salt dome, pinnacle reef, and fracture zone imaging; and EOR steam‐flood monitoring. Since both the source and the receivers pass through structures that cross the borehole, the downdip structure and the updip structure can be imaged separately. The technique involves a backprojection of the recorded data into a matrix of accumulation bins representing distances radially out from the borehole and along the borehole axis. Separate matrices are formed for the updip and for the downdip raypaths. The basic technique is illustrated with synthetic data, generated to approximate the case of a sonic tool logging through a dipping bed boundary. Results are shown for a borehole experiment performed in Alaska. The data were acquired with a research sonic prototype tool and specially recorded with a long acquisition time—20 ms per trace instead of the normal 5 ms. This longer acquisition time enabled the acquisition of scattered P and S arrivals to be recorded after most of the direct signal had died out. Images are shown of near‐borehole structural features to a distance of 18 m from the borehole. The images are presented against an independently derived formation lithology analysis and a high‐resolution synthetic seismic display computed from the measured density and slowness logs.

Seismic interferometry has become a technology of growing interest for imaging borehole seismic data. We demonstrate that interferometry of internal multiples can be used to image targets above a borehole receiver array. By internal multiples, we refer to all types of waves that scatter multiple times inside the model. These include, for instance, interbed, intrasalt, and water-bottom multiples as well as conversions among them. We use an interferometry technique that is based on representation theorems for perturbed media and targets the reconstruction of specific primary reflections from multiply reflected waves. In this interferometry approach, we rely on shot-domain wavenumber separation to select the directions of waves arriving at a given receiver. Using a numerical walkaway ͑WAW͒ VSP experiment recorded by a subsalt borehole receiver array in the Sigsbee salt model, we use the interference of internal multiples to image the salt structure from below. In this numerical example, the interferometric image that uses internal multiples reconstructs the bottomand top-of-salt reflectors above the receiver array as well as the subsalt sediment structure between the array and the salt. Because of the limited source summation in this interferometry example, the interferometric images show artifact reflectors within the salt body. We apply this method to a field walkaway VSP from the Gulf of Mexico. With the field data, we demonstrate that the choice of shot-domain wavenumbers in the target-oriented interferometry procedure controls the wavenumbers in the output pseudoshot gathers. Target-oriented interferometric imaging from the 20-receiver array recovers the top-of-salt reflector that is consistent with surface seismic images. We present our results with both correlationbased and deconvolution-based interferometry.