Abstract

Gas shales are economically viable hydrocarbon prospects that have proven to be successful in North America. Unlike conventional hydrocarbon prospects, gas shales serve as the source, seal, and the reservoir rock. Generating commercial production from these unique lithofacies requires stimulation through extensive hydraulic fracturing. The absence of an accurate petrophysical model for these unconventional plays makes the prediction of economic productivity and fracturing success risky.

This paper presents an integrated approach to petrophysical evaluation of shale gas reservoirs, specifically, the Barnett Shale from the Fort Worth basin is used as an example. The approach makes use of different formation evaluation data, including density, neutron, acoustic, nuclear magnetic resonance, and geochemical logging data. This combination of logging measurements is used to provide lithology, stratigraphy and mineralogy. It also differentiates source rock intervals, classifies depositional facies by their petrophysical and geomechanical properties, and quantifies total organic carbon. The analysis is also employed to locate optimal completion intervals, zones preferable for horizontal sections, and intervals of possible fracture propagation attenuation. Resistivity image analysis complements the approach with the identification of natural and drilling induced fractures. We compare results from three different wells to show the effectiveness of the method for shale gas characterization.

The methodology presented provides a means to understand the geomechanical and petrophysical properties of the Barnett Shale. This knowledge can be used to design a selective completion strategy that has the potential to reduce fracturing expenses and optimize well productivity. Though developed specifically for the Barnett Shale, the underlying ideas are applicable to other thermogenic shale gas plays in North America.

Introduction

Numerous organic-rich shale sections located in some North American basins have been proven as productive natural gas plays (Jarvie et al., 2007; Martini et al., 2003; Pollastro et al., 2003; Pollastro et al., 2007; Pollastro, 2007). They extend over large geographical areas and offer sustainable reservoirs with attractive exploration and development costs (Hill and Nelson, 2000). Economic production from these complex, kerogen-rich formations, which typically possess poorly-defined gas-water contacts, natural fractures, and very low matrix permeability, depends heavily on the completion technology implemented for recovery. The primary strategy used for stimulating production is hydraulic fracturing, the scale of which can pose a major cost and challenge to producers (Mayerhofer et al., 2006). The challenge is mainly related to the difficulties involved in monitoring and predicting the propagation of the fracturing process through the strata in order to recover potential reserves (Le Calvez et al., 2006; Mayerhofer et al., 2006; Moore and Ramakrishnan, 2006). This uncertainty can be traced to the varying geomechanical properties associated with the complex lithofacies inherent in many shale gas sections. For this reason, shale gas lithofacies and their relation to reservoir stratigraphy and productivity has recently become a focus of producers (Bowker, 2007; Hickey and Henk, 2007). As a result, the ability to define and categorize in situ the complex lithofacies associated with shale gas plays according to kerogen content, mineralogy, and geomechanical properties has the potential to aid in reducing the costs involved in hydraulic fracturing and at the same time improve hydrocarbon recovery.

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