The economic recovery of gas from shale reservoirs requires optimal multistage hydraulic stimulation in horizontal wells. Important parameters to consider in shale-gas evaluation include gas-filled porosity and total organic content. Mechanical rock properties, including a calculated brittleness index, along with mineralogy, are also required to target and design individual horizontal fracture stages in the best zones. This type of formation evaluation in horizontal wells requires careful correlation and calibration to petrophysical measurements obtained in either vertical pilot holes or direct offset wells. This paper presents a comprehensive approach to the evaluation of an unconventional resource play drilled in the Haynesville Shale in east Texas. Using openhole and logging-while-drilling (LWD) logs, conventional core analysis, and a chemostratigraphy analysis of drill cuttings, a shale analysis linking mineralogy, free gas, effective porosity, a shale brittleness index, and a clay linked transverse anisotropy is verified on separate vertical and horizontal control wells. Beyond that, pulsed neutron spectroscopy logs were run to develop a cased-hole evaluation solution from N-N (neural network) modeling that could replicate openhole wireline or LWD logs, and chemostratigraphy mineralogy results. Subsequently, two horizontal wells were logged with LWD tools and afterward, through casing, using the pulsed neutron log and neural network calibration. Fracture stages for the logged horizontal wells were then evaluated vs. the log data. Generally, lower normalized treating pressures per fracture stage are noted where lower clay volumes exhibit less transverse anisotropy and a higher calculated shale brittleness index. Radioactive tracer and production log data also confirm lower amounts of gas production from zones that are apparently fractured, but are more ductile and clay-rich.

The Haynesville Shale is an unconventional gas reservoir located in east Texas and northwest Louisiana. High gas prices and the success of other shale gas plays have led operators to invest highly in this unconventional reservoir. It has great potential for development by applying all the new technology that is available in the oil and gas industry today.Petrophysical evaluation of reservoirs has long been used for exploration and reserve estimates. New logging tools and analysis techniques have been developed to provide more precise data about target zones and bounding layers that are important when considering hydraulic fracturing for unconventional reservoirs.A processed log interpretation calibrated for the Haynesville Shale is computed using a typical triple-combo suite of logs. Other log data, such as borehole imaging, magnetic resonance, dipole sonic, and spectral gamma ray, will improve and verify the interpretation. Core analysis provides accessory data on mineralogy, total organic carbon (TOC), and rock mechanical properties to calibrate this processed log computation and improve the accuracy of the total shale interpretation.Identification of the following reservoir characteristics provides the starting point for completion-and hydraulic-fracture stimulation design:• Identification of free-gas zones • Identification of rock types and mineralogy • Total organic content • Quantification of effective shale porosity • Estimates of shale permeability • Mechanical stress measurement for hydraulic-fracturing design • Identification, classification, and orientation of marginal-class, open-conductive, and drilling-induced fractures A number of Haynesville Shale examples are presented to highlight all interpretation techniques and variations in the shale itself within its proven productive area. This interpretation can be critical for the hydraulic-fracture design approach for the Haynesville Shale.

The dominant methods of geosteering and horizontal formation evaluation in most organic source rock reservoirs has been limited to the use of logging-while-drilling (LWD) gamma ray and conventional mud logging. This limitation is primarily attributable to cost constraints and the historical preference for geometric fracture-stage placement. This process has resulted in varied performance between closely spaced wells thought to be drilled in similar stratigraphic positions and like rock. Very little new vertical well data is typically acquired in the development phases of most of these plays to document any changing physical rock properties that may contribute to the variable performance between wells. The perceived cost of additional pilot wells or additional horizontal LWD, open hole, or cased-hole measurements restricts most operational teams to a situation in which best practices may be recognized but are rarely implemented. To address this issue, this paper proposes and presents a cost effective cuttings analysis workflow, using a new combination of available technologies that is calibrated to vertical and horizontal petrophysical and mechanical properties. An automated fracture-stage and cluster placement method using this analysis workflow is applied to validate well treatment and post-fracture performance. In recent years, several tools have been developed to analyze drill cuttings from oil and gas wells. The most commonly used tools include X-ray fluorescence (XRF), X-ray diffraction (XRD), scanning electron microscopy (SEM) combined with energy dispersive X-ray spectroscopy (EDX), bulk density, and pyrolysis. Although each of these tools can be used to develop a limited determination of the in-situ rock character, the combination of three of these tools (XRF, SEM/EDX, and pyrolysis) can provide a more comprehensive picture of formation properties. The combination of XRF analysis with the SEM/EDX analysis is the key to the cuttings workflow. The exact location within the borehole can be determined and a robust mineralogy developed that is independent of normative mineralogy (typical XRF) or operator-interpretive mineralogy (XRD). Additional outputs include relative brittleness index, bulk density, lithology, fractional and textural relationships, total organic carbon (TOC) proxy, and a new porosity index. Trace and major elemental ratios are also available for precise stratigraphic placement. The addition of cuttings pyrolysis enables hydrocarbon typing, producible hydrocarbons, TOC, and total inorganic carbon (TIC) within each sample to be established. In this paper, outputs from the XRF-SEM/EDX-pyrolysis analysis of two vertically cored wells are benchmarked against complete vertical log suites for the modeling of petrophysical and mechanical properties. Subsequent horizontal cuttings properties for the two area examples, Marcellus and Eagle Ford Shales respectively, are presented and analyzed with the vertical modeling applied. In addition, the Eagle Ford horizontal cuttings analysis results are compared and contrasted with a through-casing pulsed neutron log (PNL) for potential upscaling of the sample frequency for continuous physical properties evaluation, including effective porosity. The exact stratigraphic placement from only a cuttings analysis is also demonstrated. Finally, the calibrated Eagle Ford and Marcellus horizontal cuttings analyses are used as inputs for an optimized fracture-stage and perforation cluster placement design for each of the wells. For validation, individual fracture-stage pumping performance is compared to the predicted formation properties from the Eagle Ford cuttings analysis example.

The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). The TOC can be used in conjunction with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) in conjunction with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, hydrocarbon content, and mineral analysis can be assessed. This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as, total porosity and mineralogy. The data is compared to the actual core data from three Eagle Ford wells, and it will be shown how the proposed approach will eliminate some coring operations. Finally, it will be shown how these interpretation results can be rolled up to make decisions on where to drill the lateral.

Optimizing the methodology for stimulating a shale play in early development is always a goal of the operators involved. With the Haynesville shale reservoir now well into its development, with several wells having produced 12 months or more of public production, play-wide trends can help determine which completion methodologies create the best-producing wells. The uniqueness in pressure, temperature, and lithology that characterizes the Haynesville shale creates the expectation that proven techniques of other unconventional shale reservoirs may not necessarily produce the same result in the Haynesville shale. Considering trends developed from cross-referencing completion strategies in laterals with public production, Haynesville well production appears to be heavily dependent on geographic location and total number of hydraulic fracturing treatments performed. Also impacting production are proppant placement strategies affecting conductivity (both concentration and overall volume) as well as the limited-entry clustering technique used paired with the treatment injection rate. To optimize short-term cumulative production as well as production sustainability, Haynesville well-completion strategy must focus on increasing the number of effectively stimulated fractures along the lateral as well as placing a proppant pack that will provide sustained conductivity in the adverse conditions of the Haynesville shale.