Unconventional reservoirs require advanced technologies such as horizontal well placement and hydraulic fracturing to be successfully exploited at economic rates. In this context, static and dynamic reservoir quality (RQ) concepts are introduced. Static RQ or standard RQ comprises a set of petrophysical parameters that describe formation tendency for development. Dynamic RQ or completion quality is defined by a set of geomechanical parameters that estimate formation tendency to be fractured. The convergence of static and dynamic RQs allows for evaluating the production potential of a field; particularly, productive sweet spots are located in those intervals in which good static and dynamic RQs are detected. We have developed a workflow to identify producible intervals in unconventional reservoirs by means of lithologic and geomechanical facies classification. Starting from core data, a clustering technique is used to create a set of lithologic facies that are then extended to the logged interval and characterized in terms of static RQ. The same approach is used to classify the logged interval with a set of geomechanical facies in which dynamic RQ is estimated. The integration of lithologic and geomechanical facies leads to sweet spot identification. Workflow application to available data from the Barnett Shale Formation allows us to classify the logged interval with four log facies (LF) and five geomechanical facies (GF) and to identify productive sweet spots in the upper and middle Lower Barnett. Eventually, LF and GF are linked to seismic facies probability volumes and Young’s modulus from elastic inversion of surface seismic. Seismic-driven geostatistical realization of LF and GF provides static and dynamic RQs volumes that are combined into volumes of productive and nonproductive facies.

Significant improvements in shale gas reservoir characterization have been recently obtained by means of detailed geochemical and mineralogical analysis on cuttings and cores directly at wellsite using the combined application of different technologies. These technologies include: X-ray diffractometry for mineralogy, X-ray fluorescence for rock chemical (elemental) composition, TOC analysis for Total Organic Carbon measurement and Pyrolysis for source rock characterization (Hydrogen Index, free oil content, Petroleum Potential & Maturity Index). The analyses, normally carried out in specialized laboratories, have been performed while drilling into a field unit. Dedicated procedures were also defined in order to improve the quality of the cuttings and to optimize the analyses timing to obtain near real time responses. The first field application has been carried out within an exploratory campaign for a shale gas drilling project. The rig site analyses provided in near real time complete geochemical/mineralogical log of the reservoir section. Wellsite analyses have been afterwards validated by laboratories analyses repeated on the same samples, confirming the reliability and accuracy of the rig site measurements. The Advanced Real-Time Cutting Analysis provided a strong support to the drilling operations (selection of the coring point, identification of sweet spot, etc.) resulting in significant time and cost savings in the well target phase and allowed for a reliable quick Formation Evaluation by using the organic matter and mineralogy data to calibrate the wireline logs response. The acquired data were also used to update the geochemical model utilized in the Petroleum System Model performed during the pre-drilling phase for a better understanding of the reservoir during the ongoing exploratory campaign.

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A workflow applied to achieve a multi-scale characterisation of a carbonate reservoir is presented. Carbonate rocks are strongly heterogeneous due either to complexity of the primary fabric or to diagenetic over-printing. The combination of these features leads to complicated pore systems, thus a proper definition of pore types using either pore size or pore throat size distributions, is important to indirectly capture diagenetic modifications and to get a link to dynamic properties. A new approach was developed in order to define a Rock Type classification (RRT) each time the approaches based on Winland's and Hydraulic Flow Unit methods do not give a reliable core facies characterisation when moving to the log scale. Moreover, the proposed workflow accounts for stratigraphy and seismic since RRT are linked to the elastic properties. In the new MICP-based Rock Typing workflow, RRT are identified by describing dominant pore types using mercury injection (MICP) curves parameterisation and routine core data (RCA). Clustering and subsequent extrapolation of MICP derived RRT to RCA samples, are the first two stages to achieve a predictable classification into the log domain. Log RRT are then defined at the log scale using curves of elastic properties, like Poisson's Ratio (PR), Frame Stiffness (fk) and Flexibility (γk) Factors. These elastic parameters (calculated with the Extended Biot Theory), can capture the effects of pore structure on the petrophysical properties and link RRT prediction at well position to seismic attributes. Since the RRT are characterised in the elastic space, the facies model – properly upscaled – represents the basis to classify elastic attributes from seismic inversion in a Bayesian framework. The seismic classification can then be used as a driver for RRT distribution in the inter-well space into the 3D model. A further benefit is the direct relationship to the original RRT porosity/permeability distributions, when modelling petrophysical properties. This new workflow was a successful solution to define homogeneous reservoir intervals in a carbonate environment characterised by the lack of a significant relationship between depositional facies and petrophysical properties.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractPermeability is one of the key petrophysical parameters in reservoir evaluation. Information about permeability is commonly derived from cores and test data, that generally cover only part of the reservoir section, but can also be derived from logs, and then extrapolated to uncored intervals and wells. Two logs provide such information: acoustic and nuclear magnetic resonance. In the Karachaganak Field, an approach based on the acoustic tool was preferred because of the textural characteristics of the vuggy carbonate reservoir. The approach relies also on the use of image logs to obtain a detailed description of reservoir rocks texture and discriminate between rocks with primary interparticle porosity or very small vugs and lithotypes with multi modal distribution of pores, enlarged and touching vugs. More than 900 meters of core have been used to validate the permeability log derived from the analysis of Stoneley waves in 25 wells from this field. A correlation between the validated log derived permeability and the textural facies from image logs, has allowed the relationship between permeability variations and the geological framework to be established. The results have been compared with dynamic data from production logging through the definition of flow units from Stoneley wave-derived permeability and porosity log data and the use of a Stratigraphic Modified Lorenz Plot to identify possible fluid entry points. Three main permeability trends have been identified:• for undolomitised or patchily dolomitised biohermal deposits.