Exploration and drilling for natural gas in North America has moved radically away from conventional reservoirs to focus on unconventional reservoirs such as tight gas sands and shales. These reservoirs have low porosity and near-zero permeability with gas stored in natural fractures and within the matrix porosity. Economic gas production requires hydraulic fracture stimulation to open connections to existing natural fractures or matrix porosity, and successful stimulation depends on the formation's geomechanical brittleness being capable of supporting extensive induced fractures. However, despite adequate stimulation, significant variations exist between wells in expected ultimate recovery (EUR) due to the heterogeneity of these resource plays. Consequently, predicting natural fractures or fracture-prone “sweet spots” is essential to optimize development of such plays.

The variation in well performance observed between various shale gas plays, and indeed within individual basins and on individual pads, has gone some way to dispelling myths regarding the perceived homogeneity of “shale gas” targets. With increased quantities of data and more determined analysis, we show that understanding the micro- and mesoscale heterogeneity can be advanced through interdisciplinary studies that incorporate traditional and advanced geophysical data and methods with geological understanding and engineering measurements. This understanding is critical in optimizing well placement, the spacing and length of horizontal wells, and hydraulic fracturing effort to maximize recovery. Specifically, we illustrate that in the Muskwa Formation and the Otter Park, Klua, and Evie members of the Horn River Formation, reservoir quality can be predicted using lambda-rho and mu-rho data extracted from AVO inversion studies. From log data, we show that the most prospective reservoir intervals are characterized by decreasing lambda, increasing mu and/or a lambda:mu ratio less than one.

The ability to high-grade gas shales is essential to optimizing completions and maximizing stimulated rock volume (SRV) in the capital-intensive development of the Horn River resource play in northeast British Columbia (NEBC). To assist in optimizing stimulation efforts, seismic data are used to estimate and map four parameters that influence hydraulic fracture effectiveness: rock properties, in-situ stress, natural fractures, and reservoir geometry.

Unconventional resource plays require that geophysicists redefine the value seismic brings for economic development of these assets. A large part of developing resource plays comes from optimizing engineering practices. Understanding that seismic data contains information regarding resource potential, rock properties, in-situ stress, reservoir pressure and fracture intensity/orientation allows for educated and optimized large scale development plans. The heuristic interpretation templates provided herein outline a method to interpret seismic data for estimated ultimate recovery (EUR) and the important physical properties for hydraulic fracturing all of which provide insight for optimizing completion efforts.

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