--> Abstract: Shale Gas Reservoir Characterization Workflows, by Chopra, Satinder; Sharma, Ritesh; Keay, James; Marfurt, Kurt; #90163 (2013)

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Shale Gas Reservoir Characterization Workflows

Chopra, Satinder; Sharma, Ritesh; Keay, James; Marfurt, Kurt

In addition to depth, characteristics such as organic richness (TOC), maturation (Ro%), thickness, gas-in-place, permeability, mineralogy, brittleness, and pore pressure need to be considered for a shale gas reservoir to become a successful shale gas play. The detection of natural fractures can also have a bearing on completion strategies and the economics of the gas recovery. While such properties can be directly measured about the wells where well log and core data are available, shale gas formation characterization requires different geophysical workflows applied to 3-D surface seismic data and are discussed here.

Changes in TOC in shale formations influence VP, VS, density and anisotropy and are exhibited in the longer offset seismic response measurements. For a given layer thickness and organic content, the P-wave reflection coefficient will generally decrease with increasing angle. This implies that if the near- and far- stack are examined for a given seismic data volume along the top of the reservoir rock, the negative amplitudes on the near-angle stack will dim on the far-angle stack, exhibiting a class IV AVO response. Any change in such a response in terms of reservoir and non-reservoir facies can be detected using seismic waveform classification based on their shapes and the assigned color.

Brittleness is a function of mineralogy and porosity which can be estimated from ECS log or core measurements. Mineralogy is then plotted against elastic parameters such as Young's modulus and Poisson's ratio computed from P-wave sonic, S-wave sonic, and density logs, forming a basin-specific template that can then be used to calibrate simultaneous prestack inversion results. Zones with high Young's modulus and low Poisson's ratio are those that would be brittle as well as have better reservoir quality (higher TOC, higher porosity). Such a workflow works well for good quality data.

While many shale formations are devoid of fractures, others are either highly fractured or exhibit highly fractured sweet spots. The Woodford shale, Eagle Ford shale as well as the Muskwa-Otter-Park-Evie shale package in the Horn River Basin, all exhibit such natural fractures which are highly correlated to areas of significant strain measured by coherence and curvature on post-stack seismic data. The relative intensity and orientation of natural fractures can be measured using azimuthal amplitude versus azimuth (AVAz) measures from wide azimuth prestack seismic data.


AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013