Determination of Reservoir Rock Types (RRT) is one of the main parameters in the process of reservoir modelling and simulation. In carbonate reservoirs, the rock typing process is challenging due to multiscale heterogeneity with varying pore types and complex microstructures. The objective in this paper is to select representative samples from a heterogeneous core (350 feet) and establish unique reservoir rock types as well as model permeability along the entire core length based on textural analysis, geological interpretations and petrophysical measurements. Representative core plugs were selected in a full-diameter heterogeneous core from a carbonate reservoir in the Middle East. The sample selection was based on statistical distribution of porosity and CT-textures in the core. The porosity and textural variations were determined along the core length at 0.5 mm resolution using advanced dual energy X-ray CT imaging. Plug-scale rock types were established based on micro-textures and pore types using thin-section photomicrographs, mercury injection analysis and poroperm measurements. The micro-texture analysis (grainy, muddy, mixed) and pore types were linked to the poroperm data. The micro-texture information was then upscaled to the entire core length using CT-textural analysis. The porosity and permeability data were fitted into unique trends that were derived from the detailed textural analysis. This process provided the link between the poroperm trends and the different textures in the core enabling permeability and rock types to be upscaled to the entire whole core intervals. Variation of reservoir rock types was studied for each poro-perm trend. The different trends were mainly controlled by the different rock micro-textures whereas the extent of the trend was due to different diagenesis processes (i.e. dissolution, cementation & compaction). This paper describes a novel approach of combining textures with porosity to model permeability and rock types at the plug scale and core level. A unique dual energy CT technique was used to ensure that all the core property variations were well represented in the plug-scale core analysis measurements.

Detailed core characterization is often overlooked in the sampling process for core analysis measurements. Random core sampling is usually performed and the selected plugs are not associated with rock types or the reservoir heterogeneity. The objective of this study is to obtain representative samples for direct simulation of petrophysical and fluid flow properties in complex rock types. A robust sampling strategy was followed in reservoir cores from two successive heterogeneous carbonate and siliciclastic formations in the Raudhatain field in Kuwait. The sample selection criteria were based on statistical distribution of litho-types in the cores to ensure optimum characterization of the main reservoir units. The litho-types were identified based on porosity and mineralogy variations along the core lengths utilizing advanced dual-energy X-ray CT scanning. High resolution micro-CT imaging and subsequent segmentation provided 3D representation of the pore space and geometric fabric of the core samples. Primary drainage and imbibition processes were simulated in numerical experiments using a pore-scale simulator by the Lattice Boltzmann Method. Capillary pressure (Pc) and relative permeability (Kr) curves together with water and oil distributions were investigated for complex geometries by the different rock types. The dual energy CT density was compared with wireline log and provided accurate calibrations to the downhole logs. The different rock types gave distinct capillary and flow properties that can be linked to the rock structure and pore type of the samples. The Lattice Boltzmann based pore-level fluid calculations provided realistic fluid distributions in the 3D rock volume, which are consistent with pore-scale physical phenomena. This characterization method by the dual energy CT eliminates sampling bias and allows for each cored litho-type to be equally represented in the plugs acquired for subsequent petrophysical and fluid flow analyses. It also provides accurate calibration tool for downhole logs. The digital analysis gave reliable SCAL data with improved understanding of the pore-level events and proved its effectiveness in providing advanced interpretations at multiple scales in relatively short timeframes.

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.

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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 estimate 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 provide a workflow to improve the use of existing models (e.g., Kozeny, Lucia, and Winland) to predict permeability in carbonate reservoirs. More than 1,000 core plugs were studied from seven different carbonate reservoirs across the Middle East: mainly Cretaceous reservoirs. The plugs were carefully selected to represent a wide range of properties within the cored intervals. The data set available included laboratory-measured helium porosity, gas permeability, thin-section photomicrographs, and high-pressure mercury injection. 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 a unique porosity-permeability 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 (Kozeny, Winland, and Lucia) were evaluated to study their effectiveness in complex carbonate reservoirs. Both Kozeny and Lucia models honored the geology of the samples and showed similar trends to the porosity-permeability relationships, whereas the Winland model gave different slopes to the experimental data. The prediction of the permeability was improved by using different model parameters per RRT within each texture. This work presents a systematic approach to construct correlations between porosity and permeability in complex carbonate reservoirs. Model parameters (i.e., FZI, RFN, and r35) were suggested within different geological rock types to estimate permeability. Based on the workflow presented in the paper, the predicted permeability was improved to less than a factor of 2 compared to the measured values. Moreover, the same workflow was applied using the data from seven different reservoirs, and the same rock typing scheme was applicable to all the reservoirs. Such work is not abundant in the literature and would serve to improve permeability prediction in heterogeneous carbonate reservoirs, which is one of the main uncertainties in modeling carbonates.