Geology-Based Porosity-Permeability Correlations in Carbonate Rock Types

Abstract

In carbonate reservoirs, permeability prediction is often difficult due to the influence of various geological variables that control fluid flow. Many attempts have been made to calculate permeability from porosity by using theoretical and empirical equations. The suggested permeability models have been questionable in carbonates due to inherent heterogeneity and complex pore systems. The main objective of this paper is to resolve the porosity-permeability relationships and evaluate existing models for predicting permeability in different carbonate rock types. Over 1000 core plugs were studied from 7 different carbonate reservoirs across the Middle East region; mainly cretaceous reservoirs. The plugs were carefully selected to represent main property variations in the cored intervals. The data set available included laboratory-measured helium porosity, gas permeability, thin-section photomicrographs and high-pressure mercury injection. Plug-scale X-ray CT imaging was acquired to ensure the samples were free of induced fractures and other anomalies that can affect the permeability measurement. Rock textures were analyzed in the thin-section photomicrographs and were classified based on their content as grainy, muddy and mixed. Special attention was given to the diagenesis effects mainly compaction, cementation and dissolution. The texture information was plotted in the porosity-permeability domain, and was found to produce three distinct porosity-permeability relationships. Each texture gave unique poro-perm trend, where the extent of the trend was controlled by diagenesis. Rock types were defined on each trend by detailed texture analysis and capillary pressure. Three different permeability equations (Kozney, Winland, Lucia) were evaluated to study their effectiveness in complex carbonate reservoirs. A new permeability equation was proposed to enhance the prediction results of the experimental data. Rock types were successfully classified based on porosity, permeability, capillarity and textural facies. Conclusive porosity-permeability relationships were obtained from textural rock properties and diagenesis, which were linked to rock types using capillary pressure. The texture-diagenesis based rock types provided more insight into the effects of geology on fluid flow and saturation. Available models may not fully describe permeability in heterogeneous rocks but they can improve our understanding of fluid flow characteristics and predict permeability in un-cored wells.

Integration of Well Logging and Seismic Data for the Prognosis of Reservoir Properties of Carbonates

“…Due to the complex nature of the pore system and the variety of pore space types, carbonate rocks present a challenge in terms of their characterization. Carbonate rocks exhibit diverse pore types that form as a result of both primary porosity during sedimentation and secondary porosity generated by diagenetic processes [1][2][3]. Primary porosity in clastic rocks and certain carbonates (such as ooids) depends on grain size, packing, shape, sorting, and intergranular matrix quantity and cementation.…”

“…Primary porosity in clastic rocks and certain carbonates (such as ooids) depends on grain size, packing, shape, sorting, and intergranular matrix quantity and cementation. In carbonate rocks, fluid flow occurs within the rock structure (primary porosity), where permeability is characterized by low values (ranging from 0.1 to 1 mD [1,2]), and within fractures (secondary porosity) [4][5][6][7]. The complexity of pore systems influences permeability variability at constant porosity, which can be significantly high, reaching up to three to five orders of magnitude [1].…”

“…In carbonate rocks, fluid flow occurs within the rock structure (primary porosity), where permeability is characterized by low values (ranging from 0.1 to 1 mD [1,2]), and within fractures (secondary porosity) [4][5][6][7]. The complexity of pore systems influences permeability variability at constant porosity, which can be significantly high, reaching up to three to five orders of magnitude [1]. An important aspect in characterizing carbonate rocks is the analysis of the relationship between porosity and permeability, as well as the petrophysical characteristics of the fracture systems [2].…”

“…A connected pore system ensures fluid flow into the wellbores; thus, to limit the risk of new areas for effective exploitation, the pore-fracture system must be supported by sophisticated analysis. However, in carbonate reservoirs, predicting permeability from porosity alone is often difficult due to complex pore systems, which are due to poor porosity-permeability relationships [1]. On the other hand, permeability in fractured reservoirs can be estimated based on the 'cubic law', providing a simple relationship between the hydraulic aperture of a fracture and its permeability [2,4].…”

Laboratory Testing of Novel Polyfraction Nanoemulsion for EOR Processes in Carbonate Formations

“…By design, the nanoemulsion was developed to support the displacement of crude oil from high temperature carbonate deposits. Oil reservoir carbonate rocks are characterized by double porosity and often mixed wettability [29][30][31]. In this case, the most important physical phenomena affecting the efficiency of the technology being prepared should be considered.…”