Multi-scale Formation Evaluation of Tight Gas Resources

Abstract

Abstract Tight unconventional rocks have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to accurately estimate reserves and identify properties which control production. In particular this requires mapping the porosity at multiple scales and understanding the coupled contributions of fractures, variable pore types, microporosity and mineral heterogeneity to petrophysical response and reserves assessment. This paper describes the application of a formation characterization study based on the integrated analysis of data in 2D and 3D at multiple scales on plugs from two sets of unconventional tight gas samples. Heterogeneity and geological rock typing is considered at the core scale via classical 3D imaging techniques. Mineralogy and secondary microporosity characterization is mapped at the plug scale with different modes of 3D X-ray micro-CT analysis coupled with SEM and SEM-EDS analysis. In particular the pore connectivity and production potential is probed. FIBSEM imaging can then used to reveal the porous microstructure of the key phases at the nano-scale. This information, collected at multiple scales, is integrated to provide an understanding and quantification of the pore structure and connectivity of these complex rocks. Petrophysical properties which impact the storage capacity and production characteristics are then computed for each key phase and data up-scaled to the plug scale using standard procedures. Results compare favourably with available core analysis data. The methodology illustrates the value of integrating conventional geological rock typing with plug/core scale petrophysical characterization to better understand rock properties characteristic of heterogeneous "unconventional" resources. Introduction Tight gas reservoirs exhibit storage and flow characteristics that are intimately tied to depositional and diagenetic processes. As a result, exploitation of these resources requires a comprehensive reservoir description and characterization program to identify properties which control production. 3D spatial differentiation and quantification of the various porosity types is a crucial step in understanding the producibility of tight gas samples and their response to stimulation treatments. Porosity alone is not an accurate predictor of rock quality, especially in tight gas sands with significant diagenesis (Rushing et al., 2008). Differentiation and quantification of the various porosity types, their connectivity in 3D and their contribution to overall porosity and flow, is an essential step in understanding and predicting the producibility of tight gas reservoirs. A multi-scale 3D approach to the characterization of the porosity, pore & throat size distribution, pore connectivity, permeability and petrophysical response is required to better characterize tight gas resources. This will include characterizing the heterogeneity and connectivity of the key constituents (e.g., porosity, cements, clays, minerals) at the micron to millimetre scale and imaging and analyzing the porosity, pore throats and connectivity at the nanoscale of these different constituent phases.