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Abstract

Faced with increasing field maturity and production decline from conventional gas reservoirs, oil companies are shifting their focus and pursuing new alternatives; one of them being the development of shale and gas plays. To be economically viable, these low-permeability formations require fracture stimulation. Interval selection within shale reservoirs for hydraulic fracturing or horizontal laterals are based on several variables: sufficient organic matter or total organic carbon (TOC) and favorable hydraulic fracturing stimulation. The presence and extent of the natural fracture system can also influence the performance of a shale reservoir; therefore, natural fractures should be characterized within the shale formation not only from wireline or LWD borehole images logs but also from cross-dipole deep shear wave imaging which can illuminate fractures up to 60 ft away that do not intersect the well. To assess these aspects, a mineralogical, structural, and geomechanical characterization of the shale formation should be conducted. The mineralogical characterization and TOC quantifications mainly rely on a pulsed neutron spectroscopy and nuclear magnetic resonance (NMR) logs. The processing of capture and inelastic gamma ray spectra obtained from the pulsed neutron tool quantifies the formation’s basic elemental composition, including silicon, calcium, aluminum, iron, sulfur, magnesium, and carbon. Geomechanical characterization is based on acoustic and density log responses. Variation in the reservoir mineralogy and TOC content affect the rock mechanics properties. Stress vs. strain curves can be derived from a micro-mechanical model of the rock which enable correlations between dynamic (obtained from acoustic logs) and static elastic properties (obtained from triaxial compression testing on core samples). Additionally, the azimuthal and transverse shear wave anisotropies are processed from cross-dipole acoustic logs to characterize the vertical and horizontal rock stiffness. This anisotropic characterization of the rock enables the evaluation of the fracture gradient and stress contrast between the target formation and the overlying and underlying formations. The paper focuses on the interaction between mineralogy, organic content and geomechanical analyses in shale gas reservoir evaluation.

Introduction

Exploitation of unconventional shale gas reservoirs depends on successful horizontal drilling and multi-stage hydraulic fracturing results. Characterizing rock mineralogy, organic matter content, the natural fracture network characteristics and the in-situ stress profile play an important role in well stimulation and completion design. Comprehensive formation evaluation data sets which include acquisition of conventional or rotary core samples are typically acquired in vertical pilot wells. The integrated shale gas evaluation suite includes mineralogy and lithology characterization logs (natural gamma ray spectral log in combination with the pulsed neutron gamma ray spectroscopy log), nuclear magnetic resonance (NMR) logging, borehole imaging logs (wireline acquisition in vertical pilot and LWD in the horizontal lateral boreholes), cross-dipole acoustic logs in addition to the conventional density-neutron and resistivity logs are also acquired.

Using the variable mineral compositions obtained from the pulsed neutron spectroscopy instrument, various lithofacies are determined for each shale reservoir. These lithofacies can then be studied in conjunction with the mechanical properties of the rock, which vary along with variations in the mineralogy. It has been observed that more brittle failure occurs in siliceous shale intervals than in clay-rich shale intervals when they are compressed in laboratory triaxial loading tests. (Franquet et al. 2010). This observation has been noted in both the Barnett shale (Jarvie et al. 2005) and in the Haynesville shale where vertical wells that were completed (perforated) and stimulated (hydraulic fractured) in intervals with abundant silica-rich shale produced better results than wells completed in more clay-rich shale intervals, (LeCompte et al. 2009).