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.

In field development programs where large variations in reservoir and completion parameters exist, the evaluation of reservoir performance to determine the optimal completion strategy can be a challenging task. This paper presents findings from a recent integrated cross-discipline analysis of a pilot program performed in the Bakken and Three Forks Formations (Williston Basin, North Dakota) to evaluate the impact of petrophysical and geomechanical properties on hydraulic fracture lengths, reservoir connectivity, well performance and well spacing.Microseismic, geological, geomechanical, completions, engineering and production data were integrated in single and multiwell modeling approaches to provide an objective method to evaluate and compare well performance. Results and conclusions from various disciplines were validated by integrating operational observations with the modeling. The application of the proposed workflow allows one to (1) understand and evaluate the effect of fracturing parameters (length/conductivity) on well performance, (2) characterize reservoir and fracture properties using hydraulic fracture pressure and production history matching techniques (3) relate fracture parameters to reservoir, geology and mechanical properties and, (4) provide a methodology to understand key drivers controlling the development strategy of an asset.

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The recent growth in horizontal well technology has resulted in existing oil and gas vertical development plays to be evaluated for horizontal well applicability. As operators attmept to evaluate the criteria for converting from vertical well plays to horizontal well plays, sound data gathering and modeling become crucial to understand how completion strategies needs to be modified for improved production, without utilizing an expensive trial and error methodology. The Powder River basin contains a variety of producing shales and sands currently being explored for vialibility (i.e. Niobrara, Frontier, etc). In this study, reservoir and fracture properties are estimated based on hydraulic fracture modeling, rate-transient analysis techniques and production history matching to calibrate log data measurements. The challenges associated with calibration and modeling measurements from petrophysical and rock mechanics models are compared with hydraulic fracture and production modeling results to understand the direction of optimization and future basin growth. Past experiences are typically the basis for design and implementation of developing a new drilling and completion program. Interpretation of the hydraulic fracture behavior is often inferred from simple diagnostics, and as production ensues the repeatability for success or failure is often attributed to modifying the hydraulic fracturing program or geological influences, which is subject to inconsistency and qualitative introspection. Within this study a single well modeling approach is utilized to understand fracture geometry, correlate this with production history matching results, and distinguish production attribution from hydraulic fracture characteristics or reservoir properties. Exercising this workflow addresses challenges affiliated with modeling fracture propagation and production matching and the gap associated with horizontal well development in existing vertical plays.

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