As shale gas resources have emerged as a viable energy source, their characterization has gained significance. The organic content in these shales which are measured by their TOC ratings, influence the compressional and shear velocities as well as the density and anisotropy in these formations. Consequently, it should be possible to detect changes in TOC from the surface seismic response. Besides TOC, different shale formations have different properties in terms of maturation, gas-in-place, permeability, and brittleness. We discuss different workflows for characterizing shale formations that involve well log data as well as seismic data.
In the last decade and more, shale gas resources have emerged as a viable energy source. This became possible after the Mississippian Barnett Shale in the Fort Worth Basin was successfully developed with the application of hydraulic fracturing and horizontal drilling. Logically, geoscientists began to look for other shale basins in the US and soon the Devonian Antrim shale of the Michigan Basin, the Devonian Marcellus Shale of the Appalachian Basin, the Devonian New Albany Shale in the Illinois Basin and the Cretaceous Lewis Shale in San Juan Basin were explored and developed. Following these, the Fayetteville Shale in Arkansas, the Woodford Shale in Oklahoma, the Muskwa Shale in the Horn River Basin, and the Montney Shale, both in British Columbia, Canada, the Haynesville Shale in northwest Louisiana and east Texas, and the Eagle Ford Shale in south Texas were developed.
The development of these shales changed the traditional approach geologists had been following - that of the sequence of gas first being generated in the source rock, followed by its migration into the reservoir rock in which it is trapped. Shale-gas formations are both the source rocks and the reservoir rocks. There is no need for migration and since the permeability is near zero, it forms its own seal. The gas may be trapped as free gas in natural fractures and intergranular porosity, as gas sorbed into kerogen and clay-particle surfaces, or as gas dissolved in kerogen and bitumen (Curtis, 2002). The shale gas reservoirs are characterized by low production rates (20–500 Mcf/d) but are usually spread over large areas and are up to 450 m thick. They are organically rich with total organic carbon content (TOC) varying from 1 to 20 wt%, such that the reservoirs contain large gas reserves (2 to 20 bcf/km2). Shale gas reservoirs rely on natural fractures for porosity and permeability as the matrix porosity or permeability is low. In the absence of natural fractures, these reservoirs need stimulation by way of hydraulic fracturing.
URTeC 1611962
