A comprehensive site study carried out in an Upper Devonian shale gas reservoir at a site in southern West Virginia provided data to test a geomechanical model for stimulation of the Huron formation. Using a model in which natural fractures provide the primary conduits for production and are the major target for stimulation, and in which stimulation triggers shear slip on those pre-existing fractures, we were able to predict the shape of the reservoir volume stimulated by injection of high-quality foam and to match injection flow rates and pressures using a dual porosity dual permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. The resulting calibrated model matched both the relative contribution of the individual stages measured by production logging and the early-life well production. This suggests that similar models may in the future provide earlier and better production predictions, guidance for completion and stimulation design, and recommendations to minimize production decline and maximize well value.

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.

Exploitation of unconventional shale gas reservoirs depends on successful hydraulic fracturing and horizontal drilling. Mineralogy, organic matter content, acoustic anisotropy, and in-situ stress all play an important role for well completion design. As part of a comprehensive site study of the Upper Devonian Huron shale, borehole acoustic and mineralogy logging data, in addition to conventional logs, were acquired in a vertical well prior to hydraulic fracturing and microseismic monitoring of a series of laterals drilled from the same location. The acoustic data was processed for compressional wave, cross-dipole shear, Stoneley-derived horizontal shear, radial velocity variations, and borehole Stoneley reflectivity indicators. The cross-dipole anisotropy and the near-well radial slowness variations provided information about intrinsic anisotropy and stress sensitivity to determine the source of dipole-mode anisotropy. Significant transverse acoustic anisotropy was detected and used to obtain vertical and horizontal dynamic elastic properties. The mineralogy and petrophysical analysis were used to generate a micromechanical constitutive model to reproduce numerically the laboratory stress-strain behavior of the rock, from which quasi-static mechanical properties were determined. These were calibrated against triaxial tests on core samples from an offset well, and the vertical and horizontal static elastic rock properties were used to estimate the vertical variation of the horizontal stress. The resulting stress profile, along with accurate mineralogy and petrophysical analysis, provides important information to select the best vertical locations of lateral wells and to identify natural fracture barriers.

This paper presents the methodology to identify critically stressed fractures, CSF, in naturally fractured reservoirs. A natural fracture is considered to be critically stressed if the ratio of shear and normal stresses acting on the fracture surface exceeds the frictional strength of the reservoir rock. The main objective is to identify the critically stressed fracture trends in the reservoirs in order to design wellbore trajectories that efficiently intersect theses fracture trends. In addition, geomechanical analysis for drilling scenarios under depleting reservoir conditions addressing well-bore stability is attempted to formulate drilling and completion strategy. Critically stressed fracture identification has several important implications on fluid flow behavior through naturally fractured porous media. It has been shown that fluid flow in fractured rocks is largely controlled by critically stressed fractures; therefore, critically stressed fracture analysis may enable to systematically identify producing fractures in the reservoirs that mainly produce through natural fractures. The CSF analysis includes the mechanical property characterization of the formations and the in-situ stress tensor description acting on the reservoirs. The fracture orientations from core description & borehole image log interpretation were used for the CSF analysis because fracture dip and strike are needed for the stress calculation on fracture planes. This analysis is particularly useful where several fracture trends are identified in a reservoir, with some trends more likely to be open and productive due to horizontal stress anisotropy. The case history illustrates application of CSF Analysis in conjunction with geomechanical wellbore stability analysis in selection of optimal well trajectory and formulation of drilling and completion strategy for producing a naturally fractured carbonate reservoir. Introduction This paper presents a case study involving comprehensive geomechanical characerisation of a Fractured Najma-Sargelu (NJ-SR) reservoir in an oilfield of West Kuwait (Fig.1) with special emphasis on critically stressed fracture analysis. The work includes rock mechanical characterization, in-situ stress tensor analysis, critically-stressed fracture identification as well as well bore stability analysis for drilling scenarios under depleting reservoir conditions. The overall objective of this work is to provide results that can be practically used in the field to ensure proper well planning and drilling practices, as well as for the selection of suitable drilling and completion strategies for production. Analysis Methodology and Results Static Mechanical Properties Static mechanical properties are the fundamental inputs for in-situ stress estimation, critical drawdown pressure calculation, fracturing tendency analysis, borehole stability analysis and mud weight window designs. These properties are traditionally obtained by conducting triaxial compression test in the laboratory; however, such measurements are routinely not carried out due to expense and/or limited availability of core material. Therefore, an analytical program was used to derive static mechanical properties from well log data and formation petrophysical description. The program is based on FORMEL, a constitutive model describing the microscopic processes occurring in a rock sample during mechanical loading.1 The program provides continuous representation of the formation's mechanical properties with depth, which is the ultimate objective in geomechanical characterization. Well logging and laboratory data from five offset wells (#B, #E, #F, #G and #H-1) were utilized to determine the static rock mechanical properties of the lithological column, covering NJ-SR formations. At the depth of interest (>10,000 ft), this formation in the field may be classified as moderate to high strength, as the average UCS (unconfined compressive strength) values for these rocks were found to be in excess of 6,000 psi. The log derived rock strength was corroborated with laboratory test data on a core samples from one well (#B) in NJ-SR formations.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents the results and methodology of the openhole stability analysis under production scenarios of one horizontal wellbore drilled and two horizontal wellbores planned in Jurassic carbonate reservoirs of West Kuwait. The main objective of the analysis was to investigate the stability of these horizontal wellbores under multiple drawdown conditions and different reservoir depletion scenarios in order to select a suitable completion strategy which guarantees borehole stability during the productive life of the reservoirs.The stability study includes the mechanical property characterization of the formations and the in-situ stress tensor description of the oil field. The static mechanical properties were obtained from the log responses and petrophysical analysis of several wells around the field by using a micromechanical approach. This approach is based on a constitutive model describing the microscopic processes occurring in a rock sample during tri-axial loading. A postprocessing analytical program for borehole-wall failure prediction and in-situ stress estimation/calibration was used in the open-hole stability analysis. The open-hole stability analysis consisted of predicting the shear failure zone around the borehole wall under production scenarios. When the shear failure zone covers the full extent of the borehole wall, the risk of borehole collapse becomes imminent. Therefore, the maximum drawdown which maintains borehole stability was obtained for each horizontal wellbore as a function of reservoir pressure depletion.The open-hole stability analyses were also done with multiple compressive strength degradation scenarios in order to address the effect of grain-cement disintegration after acid stimulations. The results of these analyses were found to be useful in evaluating and deciding optimal well completion (open-hole, cased and cemented or slotted/expandable liners) for these wells.