In unconventional reservoirs, stress models that account for anisotropy yield a stress profile which better represents in-situ conditions than the profile suggested by an isotropic stress model. Completion designs based on an accurate petrophysical model and stress profile which quantifies containment, influences perforating and staging strategies. This can help improve stimulation coverage from discreet shale intervals and lead to more economic completion decisions. This paper shows a comparison of stress magnitude estimated with a traditional linear poroelastic model from sonic data, with stress magnitude estimated from a model which accounts for transverse isotropy. A case study from the Baxter Shale play will show static and dynamic elastic moduli measured from core and acoustical logging, which vary significantly when measured in both the vertical and horizontal directions. The resultant stress profile estimated with a stress equation which accounts for this anisotropy better characterizes subtle stress changes that are significant for staging and perforating design in unconventional gas plays such as the Baxter Shale. Introduction As the demand for energy increases and conventional resources decrease, there is a growing need to develop and understand unconventional resources. Unconventional shale gas plays have become a key exploration target for the petroleum industry. Since intrinsic permeability and primary porosity values are lower than conventional reservoirs, producing hydrocarbons from tight shale reservoirs depends on successful hydraulic fracturing. With the demand of completion services and increased treatment volumes required to effectively stimulate these reservoirs, current completion costs are often 40% or more of the total well costs. By identifying and quantifying stress anisotropy, completion design in plays with thick perspective reservoir intervals can be improved. When incorporated with an accurate petrophysical model and integrated with rigorous post-completion analysis, accurate in-situ stress models can be used to help focus completion capital on discreet intervals within the overall reservoir package. With continuous refinement, the ultimate product is a more economic overall completion design that focuses on improving production within high-impact intervals while managing costs allocated to less perspective layers. It is well understood that shales have an anisotropic microstructure. Therefore, in thick shale plays, it is essential to use a stress model that considers this anisotropy. Estimating in-situ stress assuming isotropy has been the standard in the industry for more than 30 years; not because isotropy was a good assumption, but because anisotropic logging measurements were unavailable. Isotropic stress models applied to anisotropic formations generally predict inaccurate stress magnitudes (Thiercelin and Plumb 1994). Today, anisotropic measurements from acoustical logging are available (Pistre et al. 2005; Walsh et al. 2006). A calibrated anisotropic stress model provides a stress profile which better defines zone containment and often changes the perforating and staging strategy from that suggested by an isotropic model.

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We develop a methodology to model and interpret borehole dipole sonic anisotropy related to the effect of geologic fractures, using a forward-modeling approach. We use a classical excesscompliance fracture model that relies on the orientation of the individual fractures, the elastic properties of the host rock, and the normal and tangential fracture-compliance parameters. Orientations of individual fractures are extracted from borehole-image log analysis. The model is validated using borehole-resistivity image and sonic logs in a gas-sand reservoir over a 160-ft ͑50 m͒ vertical interval of a well. Significant amounts of sonic anisotropy are observed at three zones, with a fast-shear azimuth ͑FSA͒ exhibiting 60°of variation and slowness difference between 2% and 16%. Numerous quasivertical fractures with varying dip azimuths are identified on the image log at the locations of strong sonic anisotropy. The maximum horizontal-stress direction, given by breakouts and drilling-induced fractures, is shown not to be aligned with the strike of natural fractures. We show that using just two adjustable fracture-compliance parameters, one fornatural fractures and one for drilling-induced fractures, is an excellent first-order approximation to explain the fracture-induced anisotropy response over a depth interval of 130 ft. Given the presence of gas and the absence of clay filling within the fractures, we assumed equal normal and tangential compliances. The two inverted normal compliances are Z N Ј f NAT = 1.7ϫ 10 −12 Pa −1 and Z N Ј f DI = 0.8ϫ 10 −12 Pa −1 . Predicted FSA matches measured FSA over 130 ft ͑40 m͒ of the 160-ft ͑50 m͒ studied interval. Predicted slowness anisotropy matches the overall variation and measured values of anisotropy for two of the three strong anisotropy zones. Analysis of the symmetries of the modeled anisotropic response shows that the medium is mostly a horizontal transverse isotropic medium, with small azimuthal variation of the symmetry axis. Analysis of each independent fracture type shows that the anisotropy is mainly driven by open or partially healed fractures, but also consistent with stress-related, drilling-induced fractures. Therefore, the measured sonic anisotropy is caused by the combination of stress and fracture effects where the predominance of one mechanism over the other is depth-dependent. This method provides a consistent approach to data interpretation by integrating borehole image and sonic logs that probe the formation at different depths of investigation around the borehole.