The evaluation of carbonate reservoirs is a complex task because of the inherent heterogeneities that occur at all length scales. Rock properties may be defined differently at different scales and this introduces a challenge in capturing heterogeneity in a single rock volume. Heterogeneities at smaller length scales must be upscaled into larger scale volumes to better predict reservoir performance. The objective in this study is to define carbonate rock types at multiple scales and then upscale those rock types and associated properties to the whole core level. Representative core plugs were selected in a heterogeneous reservoir interval based on statistical distribution of litho-types in the core. The litho-types were described by porosity and mineralogy variations along the core length using advanced dual energy XCT imaging. Plug-scale rock types were defined on the basis of petrophysical data and geological facies. High-resolution micro to nano XCT images were integrated in the rock typing scheme. Those rock types were upscaled to the whole core level by linking the core litho-types to the plug data. The core litho-types (porosity and mineralogy) gave good representation of the whole core heterogeneity and were reliable for selecting representative samples. This allowed establishing the link between plugs and whole cores and hence upscaling rock type information to the whole core scale. The high-resolution digital images emphasized the different pore geometries in the samples and improved the definition of the rock types. Accurate porosity and permeability logs were derived along the core length and gave very good match with the plug data. Multi-scale porosity-permeability trends were investigated and found to have direct impact on the determination of upscaled permeability log at the whole core level. The paper presents an advanced and quick tool for representative sample selection and statistical core characterization in heterogeneous reservoirs. The identified rock types at multiple scales provided new insights into carbonate heterogeneity and gave upscaling options for rock types and petrophysical data. The upscaled rock types at the whole core level enhance the prediction of dynamic imbibition data along the reservoir column for improved reservoir performance.
A quantitative model of the spatial distribution of reservoir properties is key to understanding reservoir heterogeneity. Special Core Analysis (SCAL) data is essential input for static and dynamic modeling of heterogenous reservoirs. To provide highquality reliable data, the SCAL program should use the right samples from the core. Conventionally, integrated geological and petrophysical approaches are applied to select samples but they generally lack consistency and seldom incorporate upscaling options.This paper presents a novel methodology for core characterization and SCAL sample selection. SCAL data is used as input for spatial distribution of reservoir properties in a static reservoir model. The analysis is performed in siliciclastics and carbonate reservoirs from wells in the Bahrah Oil Field. An integrated X-ray, CT scanning, geological, and conventional core analysis approach is applied for understanding the reservoirs. We demonstrate the efficiency of dual-energy CT imaging in producing continuous whole core scans at 0.5 mm (500 micron) spacing and in deriving bulk density (BD) and effective atomic number (Zeff) logs along the core intervals. The high resolution 3D CT images improved the sedimentological descriptions of the core and the X-ray CT-derived numerical data (BD and Zeff) are used to derive porosity and mineralogy along the whole core sections. This information is then converted into lithology logs which predicted the cross-well correlation and enhanced the previously established correlation from conventional core descriptions. BD and Zeff cross plots suggested four lithotypes in the core intervals and the corresponding lithology log helped in deriving the percentage of each type: 1. Low BD (high pososity) carbonate formed around 20% of the whole cores. 2. High BD (low porosity) carbonate formed around 36% of the whole cores. 3. Low BD (high porosity) sandstone formed around 28% of the whole cores. 4. High BD (low porosity) sandstone formed around 16% of the whole cores.The data provided a unique capability for ensuring that the plugs adequately and correctly represented the lithotype variations along the core. The overall procedure helped minimize uncertainties in defining the rock types and effectively assign those rock types to the selected samples and core intervals.
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.
Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir. A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRTs) were identified on the basis of whole core and plug X-ray computed tomography (CT), nuclear magnetic resonance (NMR) T2, mercury injection capillary pressure (MICP), porosity, permeability, and thin-section analyses. Primary-drainage (PD) and imbibition water/oil relative permeability (bounding) curves were measured on all the five rock types by the steady-state (SS) technique by use of live fluids at full reservoir conditions with in-situ saturation monitoring (ISSM). Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone (TZ) by varying connate-water saturations. Hysteresis effects were observed between PD and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e., wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual-energy (DE) CT scanning and high-resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves that were explained by different pore-level fluidflow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate-water saturation. Relative permeability to oil was explained on the basis of the occupancy of the oil phase at varying connate-water saturations. The change in the water relative permeability trend was addressed on the basis of the connectivity of water at the varying connatewater saturations. These results and interpretations introduced an improved understanding of the hysteresis phenomena and fluidflow behavior in the TZ of a Cretaceous carbonate reservoir that can assist in the overall reservoir modeling and well planning. Rock Characterization The rock (micro) properties that control pore geometry determine many macroscopic properties of the porous medium. Establishing
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