The amplitude variation with offset (AVO) responses of elastic transversely isotropic media are sensitive to contrasts in both of Thomsen’s anisotropic parameters δ and ε. The equation describing P-P reflections indicates that the smaller the contrasts in isotropic properties (compressional velocity, shear velocity, and density) and the larger the contrasts in δ and ε across an interface of reflection, the greater the effects of anisotropy on the AVO signature. Contrasts in δ are most important under small‐to‐medium angles of incidence as previously described by Banik (1987), while contrasts in ε can have a strong influence on amplitudes for the larger angles of incidence commonly encountered in exploration (20 degrees and beyond). Consequently, using Rutherford and Williams’ AVO classification of isotropic gas sands, type I gas sands overlain by a transversely isotropic (TI) shale exhibit a larger decrease in AVO than if the shale had been isotropic, and type III gas sands overlain by a transversely isotropic (TI) shale exhibit a larger increase in AVO than if the shale had been isotropic. Furthermore, it is possible for a “type III” isotropic water sand to exhibit an “unexpected) increase in AVO if the overlying shale is sufficiently anisotropic. More quantitative AVO interpretations in TI media require considerations of viscoelastic TI in addition to elastic TI and lead to complicated integrated earth models. However, when elastic and viscoelastic TI have the same axis of symmetry in a shale overlying an isotropic sand, both elastic and viscoelastic TI affect the overall AVO response in the same direction by constructively increasing/decreasing the isotropic component of the AVO response. Continued efforts in this area will lead to more realistic reservoir models and hopefully answer some of the unexplained pitfalls in AVO interpretation.

Ultrasonic compressional and shear‐wave velocities of isotropic sands are shown to be dependent on their mineralogy, their porosity, their fluid content, and their state of consolidation, under fixed temperature and pressure conditions. This leads to a distinction between two broad classes of sands: those that are well consolidated, and those that are loosely consolidated. Changes in elastic velocities reflect changes in the ratio of bulk and shear moduli to density in response to lithologic variations. We decouple the two effects by examining changes in elastic moduli with respect to changes in lithology, and we observe three main points: (1) For consolidated sandstones, the effects of mineralogy and porosity can be approximated both empirically and theoretically by a modified isostrain theory: the dry bulk and shear moduli of the rock aggregate follow a “mixing law,” being linear combinations of the respective moduli of the individual constituents. The dry elastic moduli of families of clean sands and shaley sands are linear functions of porosity, with decreasing y‐axis intercepts as their clay‐to‐sand ratio increases. (2) Loosely consolidated sands and sandy shales appear to follow a behavior closer to that of the isostress theory for suspensions: the reciprocals of the bulk and shear moduli of the rock aggregate are linear combinations of the reciprocal moduli of their individual constituents. In general, the elastic moduli of poorly lithified sands are less sensitive to changes in mineralogy and porosity than those of consolidated sandstones. (3) For high permeability sands like the loosely consolidated sands of Troll, the Biot‐Gassman theory is a good approximation to the effects of fluids on seismic velocities. With our understanding of elastic moduli, we then show that dry ratios [Formula: see text] increase with porosity and clay content.

The classical interpretation relating Amplitude Versus Offset (AVO) to Poisson’s ratio and other petrophysical properties is based on the assumptions of elasticity and isotropy. We extend this interpretation to a layered medium with anisotropic and/or viscoelastic properties, using a Fourier Pseudo‐Spectral method to solve the wave equation. Both viscoelasticity and anisotropy are key factors for the quantitative interpretation of AVO trends, because they contribute to the seismic energy partition at geological interfaces (the reflection coefficients), and because they continually induce propagation effects. We show that: 1) Reflection coefficients at an interface are strongly dependent on the elastic anisotropy of both the overlying and the underlying media. The AVO effect is further complicated by materials with viscoelastic properties. 2) Propagation effects are due to elastic anisotropic energy focusing and viscoelastic dissipation that distort the energy and phase distribution of the incident and reflected wavefronts. These two phenomena can be of the same order of magnitude as variations in reflection amplitudes with offset and can make it difficult to recover reflection coefficients along an interface from seismic data. In theory, they make the amplitude determination of a seismic event somewhat dependent on wavelet phase changes that occur continually as the wavefront propagates. In practice, they create anisotropic radiation patterns and differentially focus the seismic energy distribution along the wavefront. For these reasons, all detailed reservoir characterizations based on modeling and interpretation work should attempt to account for anisotropy and viscoelastic attenuation; this is not an easy task in the real world because of the difficulty in prescribing appropriate physical parameters.

Hess Corporation performed microseismic monitoring of hydraulic fracturing in two infill horizontal wells in the Middle Bakken Play of North Dakota during 2011. Six vertical observation wells were drilled to monitor microseismic events. Each observation well was fitted with a pressure gauge in the Middle Bakken interval, capped by a bridge plug, and instrumented with 40 geophones. The experiment was specifically designed to observe the interaction of the fracs with a pre-existing Middle Bakken horizontal well, which had been on production for about two and a half years. The producing well was shut in for the duration of the experiment and instrumented with a downhole pressure gauge.Experimental results show the hydraulic fracturing did not propagate as anticipated. Instead, the microseismic observations provided a very interesting result early during the stimulation of the first infill well. While fracturing the fourth stage of the first infill well, microseismic events appeared along the length of the nearby production well at distances up to 9,000 ft away from the open frac port. During this stage, and just prior to the appearance of the distant events, a pressure connection was established to the original well as recorded by the pressure gauge in that well. Our interpretation is that these microseismic events were distributed throughout the depleted zone surrounding the original production well. We provide evidence for the development of a cloud of depletion points through the use of pressure measurements, microseismic event speed plots, and Mohr's circle analysis.This experiment provided a unique opportunity to "see" the shape of the depleted zone and to understand its influence in developing Bakken resources. By analyzing the outline of the depleted zone outline, we can now propose a series of reasonable infill well locations at a minimum distance from the original producer. We are leveraging microseismic as a tool to optimize the spacing of development wells. Our objective is to infill drill at the minimum distance required to maximize fracture contact in-zone near the infill wells and yet avoid significant overlap into previously depleted zones. Thus, a new application for microseismic monitoring is envisioned, in which one would pressure-up a producing well in order to measure its actual area of depletion prior to planning subsequent development wells and executing field-wide strategies for hydraulic fracturing.

Hess Corporation performed an extensive data collection project in 2011 designed to investigate infill well spacing in the Williston Basin. Using combined microseismic and pressure data collected from six observation wells and the original depleted horizontal wellbore, we identified the potential for using microseismic data to monitor the extent of depletion in unconventional reservoirs. We propose broader use of this surveillance process, which we call microseismic depletion delineation. We recommend pumping pressurized fluids into, or in the vicinity of, a well that has been on production while simultaneously monitoring for microseismic events as a means to discover the optimal spacing for development wells. Our measurements revealed that depletion over a two-and-a-half year period puts the reservoir in a critically stressed state. By repressurizing the depleted wellbore to a level below the minimum horizontal stress, we promoted shear events that revealed the location of the connected, permeable fractures that delineate the depleted part of the subsurface. We considered alternative interpretations for the nonuniform depletion that we mapped along the length of this Middle Bakken well, including completion fluid diversion by faults and wellbore sloughing occluding the production string. We conclude that this procedure has application to shale plays in much the same way that 4D seismic monitoring is used as a production surveillance tool for conventional reservoirs.