Previous studies show that Lambda-rho/Mu-rho cross plots from seismic data can be used to quantitatively grade unconventional plays. In this work which condenses the results of first author’s M.Sc. thesis, we examine the utility of these cross plots with actual field data acquired from the Lower Barnett play. We use seismically inverted Poisson’s ratio as a fracability discriminator and Young’s modulus as an indicator of Total Organic Carbon (TOC) richness and porosity. We classify the Lower Barnett shale in the study area into four rock groups: Brittle-Rich, Rich-Ductile, Brittle-Poor, and Ductile-Poor. We validate these results using production logs and microseismic data acquired on four wells. Production logs directly measure the rates coming from each perforation cluster while microseismic events directly measure locations where the rock breaks which is a good proxy to the stimulated rock volume, SRV. Integration of seismic data, production logs and microseismic data indicates that Brittle-Rich zones are the most suitable locations to drill wells in this particular play because they exhibit two components: significant hydrocarbon in place and sufficient strength to sustain effective fractures. On the other hand, rock zones characterized as Ductile-Poor should be avoided during drilling and fracturing since once the fracturing pressure is released, the rock will close back against the proppant resulting in ineffective completions. Brittle-poor zones adjacent to zones with high TOC (rich zones) can also be target drilling locations since the brittle/competent rock can sustain long-lasting hydraulic fracture treatments bridging the gap between the hydrocarbon rich zone and the wellbore.


One of the key developments critical to making shale wells economically productive over extended periods of time is the use of hydraulic fracture treatments. In combination with horizontal well technology, shale gas wells are now orders of magnitude more productive than wells completed in similar settings in the 1990s to the early 2000s (Agrawal et al., 2012). Shale wells are now routinely completed with a suite of hydraulic fracture treatments in several stages (Bennett et al., 2006; Bruner and Smosna, 2011). The stages are designed to contact as much of the reservoir rock as possible, thereby creating highly conductive oil and gas migration pathways between the reservoir rock and the wellbore (Daniels et al., 2007; Cipolla et al., 2008; Mayerhofer et al., 2010; Cipolla et al., 2012; Yu and Aguilera, 2012).

Additionally, as our knowledge of shales has expanded from the classical homogeneous seal rock model to that of a reservoir rock characterized by considerable lateral and vertical variability, there is an increasing need to exploit this knowledge for optimal well and fracture placement. The work presented in this paper is organized around this main theme: to identify optimal locations for infill drilling and for hydraulic fracture treatments by mapping these heterogeneities and identifying the location and distribution of significant hydrocarbon accumulations to extract shale oil and gas resources more efficiently and economically.

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