SUMMARY
Based on self organized growth, a self‐similar geometrical model of rock materials is established. The structural mode of the internal surface is carried over to the three‐dimensional structure of the pore space and solid phase, which can be described as a fractal network. It is characterized by the fractal dimension of surface, which can be measured by physical and stereological methods. From this, the fractal behaviour of other geometrical properties, relevant for physical processes, such as porosity, number of solid connections, tortuosity and constrictivity of the capillary system and of the solid phase can be derived.
Besides the knowledge of material constants of the homogeneous phases of a disperse system, a good understanding of its geometrical properties is necessary for describing physical processes. In order to characterize the shape of the interface between solids and pore space with respect to the irregularities in all orders of magnitude, the fractal dimension has proved to be an informative parameter. By this study the theory of fractal dimensions, in three‐dimensional space originally limited to topological curves, surfaces and volumes, is extended into physical properties like specific surface, tortuosity, porosity and formation factor with “physical” dimensions −1 or 0 as an exponent of the unit of length. The typical properties of the true fractals are transferable to some of these derived parameters. This leads to power laws describing the dependence of the particular measure on the resolution length. With special models, which seem to be of widespread validity in nature, petrophysical considerations lead to further power laws for the rest of the physical parameters, dependent on discrete length parameters such as grain radius and pore radius. By determination of the exponents of such independent power laws, a better particle characterization is possible, as the fractal dimension of the surface alone may be misleading, especially when the grain size of the particles is not uniform.
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.
U.S.A., Tight unconventional rocks have be come an increasingly common target for hydrocarbon production. Exploitation of these re sources requires a compre hensive reservoir description and cha racterization program to a ccurately 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 un conventional tight gas samples. Heterogeneity and geological rock typing i s considered at the core scale via classical 3D ima ging 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-s cale. This information, collected at multiple scales, is integrated to p rovide 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 integratin g conventional geological rock typing with plug/co re scale petrophysical characterization to b etter understand rock properties characteristic of hete rogeneous "unconventional" resources.
Low Resistivity (LR) and Low Contrast (LC) pays have been identified in many clastic and carbonate reservoirs all over the world. Typical LRLC zones in PETRONAS operated fields show resistivities of 2-4 Ohmm, which are similar to the resistivities of the adjacent shale beds and very close to the resistivities of the (fresh) formation water bearing zones(1-2 Ohmm). This study is focussed on the investigation of clastic reservoirs in the Malay, Sarawak and Sabah Basins, which are mainly shaly and silty sandstone zones, that were not obvious and not classified as "net pay" from previous conventional formation evaluation techniques. Based on an integrated petrophysical analysis of modern log data (including Nuclear Magnetic Resonance (NMR),Borehole Imaging), and Special Core Analyses (SCAL) data (including electrical, hydraulic and NMR properties), improved concepts and workflows were developed for the identification and evaluation of productive hydrocarbon bearing LRLC zones.
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