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.

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.

Thermal maturity is the primary factor that determines whether a source rock will produce oil, gas, or condensate. Two new methods for estimating the thermal maturity of source rocks from log data have been developed. First, the delta log R equation has been re-arranged to solve for level of maturity and correlated to vitrinite reflectance. Second, a method to determine kerogen density from log and core data is presented. Examples from the Barnett and Woodford Shales of North America show how changes in kerogen density and delta log R relate to source rock maturity and predict whether the formations will produce oil, gas, or condensate.

This paper presents a methodology for characterizing the mineralogy and geomechanical properties of the Haynesville Shale. The results from two case study wells demonstrate how a perforating strategy based on mineralogy and geomechanical properties derived in part from mineralogy can improve hydraulic fracture stimulation performance. A full suite of openhole logs (acoustic, NMR, density-neutron, and mineralogy) provides the means for estimating both geomechanical properties and reservoir quality. An accurate measurement of total organic carbon with minimum core calibration is obtained from new wireline pulsed-neutron logging technology. Utilizing primarily openhole logging data, a micromechanical model simulates axial and radial deformations of a core sample under triaxial stress. It provides the static rock mechanical properties and strengths at different confining conditions for every depth interval. A new input to the micromechanical model is the mineralogy characterization derived from a wireline pulsed neutron tool. The static rock mechanical properties and TOC derived from these methods provide the key to understanding the fracturing potential of a zone in the Haynesville Shale. Two log examples show how optimized perforation placement based on these approaches can positively impact production. Tracer logs indicating vertical fracture containment and production data provide a validation of the approach. A post-mortem analysis of these well completions suggests that using the results of these models for fracture and completion design results in better production than wells completed differently in similar formations. The described approach brings together mineralogy, TOC, and mechanical rock properties for a complete evaluation of Haynesville Shale reservoirs with a view toward optimizing completion costs. Introduction The inherent risk associated with resource plays such as shale gas plays is mitigated by a high well success rate and high initial production. A shale gas well that does not produce at economical rates, therefore, is a major setback for operators. Both geological and well logging data are utilized to determine which zones are most likely to fracture and which are the most productive (Jacobi et al., 2008). The petrophysical, mechanical, and mineral characteristics of the play can vary significantly (Economides et al., 2008). The Haynesville Shale is one such play where careful planning and execution can be the difference between a productive economic well and a poorly completed well. Vertical wells are drilled in the Haynesville Shale to initially evaluate the play, test completions, and plan hydraulic fracturing strategies. The choice of perforation depth intervals is often based on limited geological knowledge because it is a relatively new field and there is uncertainty about the lithologies comprising the strata. A lack of knowledge about the complexity of the formation across the basin contributes to this uncertainty. Conventional log responses are at times difficult to interpret. There are effects due to relatively high clay content and organic matter in the rock matrix not usually present in other conventional reservoirs where conventional responses are less challenged. These effects make gas-rich sweet spots difficult to identify unless new technologies are incorporated for reference. The goal of formation evaluation in gas shales is to identify preferable zones for gas productivity from both a petrophysical and engineering standpoint.

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The assessment of reservoir productivity and subsurface hydrocarbon can be significantly enhanced through an understanding of formation mineralogy and organic carbon. Such information allows petrophysicists to resolve ambiguities in their predictions of reservoir hydrocarbon potential. While core samples are a prime source for exact formation mineralogy, excellent results can also be derived in a timely and cost-efficient manner from in-situ log chemistry measurements of the rock. A direct measurement of the formation's elemental concentrations is achieved using a gamma ray scintillation sensor in combination with a 14-MeV pulsed-neutron generator. The most important element measured is carbon, as it may provide a direct indication of reservoir hydrocarbons. This paper presents a method for determining the amount of organic carbon in subsurface formations using a pulsed-neutron mineralogy tool and a natural gamma ray spectroscopy tool. The natural, inelastic, and capture gamma ray energy spectra from these instruments are used to extract the chemistry of the subsurface formation being investigated. The elemental concentrations measured include Al, C, Ca, Fe, Gd, K, Mg, S, Si, Th, Ti, and U. Carbon is very difficult to measure without the inelastic spectrum generated from a pulsed-neutron source. An interpretation process, based upon the geochemistry of petroleum-bearing formations, is employed to derive the lithology and mineralogy which leads to the interpretation of the carbon measurement. The oil saturation can be computed in conventional reservoirs, assuming that the amount of carbon in excess of that required for the inorganic matrix mineralogy is part of the pore fluid as hydrocarbon. The direct carbon measurement is also important in laminated shaly sands or in low-salinity reservoirs, where oil saturation determination from indirect measurements, such as resistivity, is not compatible with the environment. In other formations the carbon can be determined to be a component of the rock matrix as kerogen or coal, both of which are uniquely identified with this logging system. Kerogen becomes extremely important in the evaluation of shale gas formations. Field examples are presented to illustrate the effectiveness of the carbon measurement. Introduction Subsurface organic carbon, i.e., carbon that does not belong to any of the carbonate minerals, indicates the presence of oil, natural gas, coal, or kerogen. Although the amount of carbon is one of the most important quantities in formation evaluation, openhole tools often provide only indirect measurements of hydrocarbons. Traditional electrical tools, for example, measure oil saturation indirectly based upon a comparison of the resistivity of saline and non-saline formation fluids. This approach works best when the salinity of the formation water is high to moderate; if connate water salinity is low, resistivity methods cannot differentiate water from hydrocarbon.

Formation fluids are displaced by drilling mud filtrate as a result of pressure overbalance during drilling. This process changes the petrophysical properties of the near-wellbore zone and creates an invasion zone that has a complex radial profile characterized by the partially decreased porosity, permeability, and altered saturations. Further, at the completion stage the well is cased, cemented, and then perforated to re-establish connection between wellbore and reservoir. During perforation, a shaped charge produces a jet of dense material traveling at very high velocity which penetrates casing, cement, and formation. The resulting tunnel is a rugose tapered cylinder roughly characterized by its diameter and total depth of penetration.One of the main goals of perforated completion is to ensure fluid flow from the productive reservoir interval to the wellbore. Equally important is the ability of the jet to penetrate beyond the zone of formation damage caused by drilling, connecting the wellbore to the virgin reservoir and alleviating the effect of formation damage on production. The ability to predict the invasion depth and the depth of penetration of downhole perforators is therefore critical for pre-job completion modeling.This work presents the results of numerical modeling predictions of both drilling mud filtrate invasion during drilling and jet penetration in rock during perforation. The invasion model is further applied to the well data interpretation, and a good agreement with log resistivity profile is shown. In addition, we review and discuss various empirical methods currently used in the industry to predict penetration depth. Despite a variety of available methods and published experimental data, penetration depth results are often inconsistent with each other and are of questionable use in predicting actual downhole penetration.We highlight the importance of combining accurate invasion and penetration models for the successful pre-job completion planning. The results should be used further with the well-inflow model to maximize well productivity and minimize the effect of formation damage.

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