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Abstract
The paper provides a case history of the application of 3D imaging and Pore Network Modeling (PNM) technology to establish a direct relationship between rock micro-structure parameters from 3D via micro-tomographic images, and the simulation of petrophysical properties of clastic tight gas reservoir rocks in Oman. Tight gas reservoirs exhibit storage and flow characteristics that are intimately tied to the depositional and diagenetic processes. In particular, cores have significant primary and secondary porosity often dominated by clays and slot like pores. Accurately mapping the pore and grain structure and mineralogy in 3D and the interconnectivity of primary and secondary porosity illustrates the role 3D imaging plays in a comprehensive reservoir characterization program.

The computed petrophysical properties (e.g. porosity, permeability, formation resistivity factor, hydraulic radii and drainage capillary pressure) are compared with routine and special core analysis results measured on conventional core samples. The use of 3D micro-tomograms at different scales and PNM provides a quick complimentary method to characterize the distribution and nature of different pore types and matrix components to characterize the static, elastic and dynamic rock properties even on rock fragments (2mm to 1cm diameter) that are not suitable for conventional core analysis techniques.

The presented case history demonstrates that the new 3D PNM technologies can also be successfully applied to the challenging tight gas reservoirs with low porosities and very low permeabilities for comprehensive reservoir characterization to optimize the development scenarios.

Introduction
In the recent years significant progress has been made in the development of high resolution 3D tomographic imaging and registration techniques to directly image rock microstructures across a continuous range of length scales (from 10nm to cm scales). This emerging new technology provides a direct characterization of multi-modal pore size distributions and allows one to predict petrophysical flow properties and the producibility of complex reservoir types. Rock properties derived from small fragments of core material have been compared with conventional laboratory measurements and shown to be in good agreement for a wide variety of clastic and carbonate rocks [Schwartz et al. (1994), Øren & Bakke (2003), Knackstedt et al. (2004), Arns et al. (2005)].