A successful drilling campaign in an unconventional shale play usually brings together disparate pieces of relevant geological, petrophysical, and geophysical information to build a realistic and accurate model of the subsurface. Including seismic inversion information in the knowledge mix promises to be a gamechanger because it can pinpoint sweet spots in the play, even with sparse well control. The sweet spots should have all of the ingredients to make wells profitable -good free gas volumes, good poro permeability, and brittleness (hence fracable). If the rock interval exceeds a threshold of brittleness, its fracability can be reliably estimated by the combination of Poisson's Ratio and Young's Modulus. These two mechanical properties are combined (Rickman et al, 2008) to indicate the rock's propensity to fail under stress (Poisson's Ratio) and to maintain a fracture (Young's Modulus). In this Barnett Shale project, a simultaneous AVO inversion was used to demonstrate the feasibility of constructing a subsurface geological and geomechanical model describing the thickness and complex architecture of the brittle/fracable formation portion. This information can, in turn, be used to determine the optimal well bore trajectory. Considering that the Barnett Shale has a significant structural component, an accurate design of the well bore trajectory is required to remain within the bounds of the most appropriate facies. The ultimate result of strategic well bore placement is the maximization of cumulative volumes of hydrocarbon production per barrel of frac fluid.Historical data show that productivity is a function of the induced fracture extent and how well the formation can maintain those fractures. Fracability, the propensity of the formation to fracture and maintain the fracture, is directly correlated with brittleness. In turn, the field results validate that the formation's susceptibility to fracturing can be reliably predicted from the brittleness as calculated using Poisson's Ratio and Young's Modulus (Pitcher and Buller, 2012).

In this study, 2D multicomponent seismic data and well logs from the Willesden Green, Alberta area are used to investigate an oil reservoir interval. The Upper Cretaceous (Turonian) Second White Speckled Shale (2WS) represents the zone of interest. PP and PS synthetic seismograms generated from well logs correlate reasonably with the surface seismic data. PP and PS inversion was applied to the vertical and radial components to yield P and S impedance. The geologic model consists of 2WS shale interspersed with sand, limestone, gas and oil, giving rise to a low Vp/Vs ratio. The oil-saturated 2WS interval shows a P-wave impedance decrease and S impedance increase. The Vp/Vs estimate shows anomalous values over the zones of interest around the producing wells: 8-13-41-6W5; 8-26-41-6W5 and 6-15-41-6W5.

The goals of this work are to better delineate sand channels, which can be hydrocarbon bearing, using multicomponent seismic data. The specific exploration targets of this survey, undertaken in the Manitou Lake heavy oilfield, Saskatchewan, Canada include the Colony and Sparky sand channels, both members of the Cretaceous Mannville Group. These intervals are currently producing oil and gas in the area. We outline a methodology to interpret 3C-3D seismic data to discriminate sand versus shale. Detailed registration of PP and PS sections followed by joint inversion aims to reduce the uncertainty of traditional channel interpretation and improve well targeting. Seismic attributes as AVO, simultaneous inversion, and LMR methods can complement the information for drilled wells and possibly identify new drilling locations.

No abstract