Effective Geochemical and Geomechanical Characterization of Shale Gas Reservoirs from the Wellbore Environment: Caney and the Woodford Shale

Abstract

The successful recovery of hydrocarbons from gas shales requires a fundamental understanding of the reservoir's rock-matrix properties. Information about the variable lithologies, mineralogies, and kerogen content is vital to locate favorable intervals for gas production. Knowledge of the in-situ stresses and porosity of these intervals is essential for developing hydraulic fracturing strategies to recover the gas in place. Often these properties are established from the analysis of cores extracted from the wellbore, a time-consuming practice which causes costly delays in well completions and prolonged rig time. We demonstrate that these reservoir rock properties can be measured and predicted in-situ from the wellbore environment by a formation evaluation method that employs a combination of measurements made by downhole geochemical, acoustic, and nuclear magnetic resonance sondes. Using this combination of tool measurements we determine lithology, mineralogy, and kerogen content. The mineralogy, porosity, acoustic velocities, bulk density, pore pressure, and overburden stress are then used to compute the unconfined compressive strength, Poisson's ratio, and horizontal stress for each interval. These results can then be used to develop hydraulic fracture strategies. The effectiveness of this approach is shown through characterization of the rock properties of the Caney and the Woodford Shale from three different wells. The ability to quantify the kerogen content from these formations is emphasized as there is currently no other direct quantification of carbon from openhole wireline logging available. This approach for characterization of shale gas reservoirs is also further supported through comparisons of core data that display the mineralogy, chemistry, kerogen content, and geomechanical properties from the wellbore section. Introduction The Woodford and Caney formations comprise a successive series of fissile, carbonaceous, siliceous black shales that are unconventional, economic gas plays in the Arkoma Basin of eastern Oklahoma (Amsden, 1967; Cardot, 1989, Brinkerhoff, 2007, Schad, 2007). Producing commercial gas from these fine grained lithologies requires the stimulation of a large volume of rock using hydraulic fracture techniques. The projected azimuth, propagation, and containment of the induced fractures created using this method are sometimes difficult to predict. Fracture growth is impeded when stimulation stages do not successfully target siliceous lithofacies with lower fracture gradient. These can often induce extensive intersecting fractures or contain dormant mineralized fractures that upon reactivation may increase production. Instead, some stages are inadvertently applied to argillaceous zones that attenuate fracture development due to embedment. Other stages may be directed toward carbonate facies that have high breakdown pressures. Treatment pressures simply are unable to exceed the fracture gradient of the rock. Stimulations may also propagate along fault planes intersecting other formations within the basin leaving much of the reservoir rock unfractured (Vulgamore et al., 2007). Because of these problems, there can be uncertainty about whether there has been fracture containment within the zone of interest or whether optimal zones that promote gas recovery have indeed been fully accessed. For example, induced fractures into the Woodford can pose questions of whether these have been contained within the target area or have grown upward into the overlying Caney or downward into the underlying Hunton limestone. The differences in geochemical, petrophysical and geomechanical properties of the lithofacies found in both the Caney and Woodford can be used to improve hydraulic fracture strategies. Using a combination of logging tool measurements, we determine the kerogen content, porosity, mineralogy, and the principal stresses of the various lithofacies from the wellbore environment for three wells. Results will show how the integration of these into a petrophysical model provides reservoir characterization properties comparable to those gained from core analysis, which has the potential to save money and expedite well completions.

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