Summary Nuclear magnetic resonance (NMR) is typically used in the petroleum industry to characterize pore size and to identify fluids in fully and partially saturated reservoir samples. Although the NMR-relaxation response can be used to estimate the permeability of the rock, it may also provide information about the fluid distribution for multiphase systems that could lead to the estimation of the effective permeability of fluids at partial saturations and the derivation of relative permeability to assess hydrocarbon recovery. By use of a random-walk method, we simulate the NMR response as a function of saturation on tomographic images of Bentheimer and Berea sandstone as well as Ferroan dolomite samples. Fluid distributions are simulated for fully water-wet conditions by use of a morphological capillary-drainage transform, allowing the calculations of the saturations directly on the images corresponding to capillary pressure. The magnetic susceptibility of minerals and fluids is used to calculate the internal magnetic fields from the material distributions of solids and fluids quantified by X-ray-diffraction (XRD) analysis. We show that the logarithmic mean of the NMR T2 distribution is a robust measure of permeability, and it results in strong correlations between NMR response and the relative permeability of both fluids. The observed relative permeability from NMR in our work is in excellent agreement with image-based relative permeability calculations by use of the lattice Boltzmann method (LBM). We compare our NMR results for the wetting phase to published experimental results on Bentheimer and Berea sandstone samples, and we observe excellent agreement. By use of NMR numerical calculations, we demonstrate that internal gradients aid the establishment of relative permeability correlations for the nonwetting phase.
Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale is a wide variety of rocks that are composed of extremely fine-grained particles with very small porosity and permeability values in the order of few porosity units and nano-darcy range, respectively. Shale formations are very complex at the core scale, and exhibit large vertical variations in lithology and Total Organic Carbon (TOC) at a small scale that renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale pore level where the pores have different porosity types that are detected within the kerogen volume. These complexities led to further research and development of advanced application of high resolution X-ray CT scanning on full diameter core sections to characterize shale mineralogy, porosity and rock facies so that accurate evaluation of the sweet spot locations could be made for further detailed petrophysical and petrographic studies. In this work, argillaceous shale gas cores were imaged using high resolution dual energy X-ray CT scanning. This imaging technique produces continuous whole core scans at 0.5mm spacing and derives accurate bulk density and effective atomic number (Zeff) logs along the core intervals which were crucial in determining lithology, porosity, and rock facies. Additionally, integrated XRD data and energy dispersive spectrum (EDS) analysis were acquired to confirm the mineral framework composition of the core. Smaller core plugs and subsamples representing the main variations in the core were extracted for much higher resolution X-ray CT scanning and Scanning Electron Microscopy (SEM) analysis. Porosity was mainly found in organic matter and was determined from 2D and 3D SEM images by image segmentation process. Horizontal fluid flow was only possible through the organic matter and the simulations of 3D FIB-SEM volumes by solving Stokes equation using Lattice Boltzmann Method (LBM). A clear trend was observed between porosity and permeability while correlating with identified facies in the core. Silica-rich facies gave higher Phie-K characteristics compared to the low clay-rich facies. This is mainly caused by pressure compaction effect in the soft clay-rich samples. High percentages of organic matter were not found to be good indication for high porosity or permeability in the clay-rich shale samples. The depositional facies was found to have great effect on the pore types, rock fabric and reservoir properties. The results and interpretations entailed in this study provide further insights and enhance our understanding of heterogeneity of the organic rich shale reservoir rock.
A pilot study to evaluate the quality and validity of special core analysis (SCA) data from Digital Rock Physics (DRP) has provided results that are comparable to laboratory measurements. The DRP technique applied in this study employs the Lattice Boltzmann Method (LBM) for computing relative permeability (Kr(Sw)) and capillary pressure (Pc(Sw)) curves from high resolution digital pore structures obtained from micro-CT image data. The DRP processes, results, and comparisons with laboratory measurements on carbonate rock samples from different Saudi Arabian carbonate reservoirs are presented.DRP conventional core analysis (DRP-CCA) computations include porosity, permeability, formation factor, and dynamic elastic properties. DRP special core analysis (DRP-SCA) computations include Kr(Sw) and Pc(Sw). The translation of DRP-CCA and DRP-SCA determinations from imaged 4 mm subsamples to the 38 mm core plug-scale was achieved by upscaling the data for the various flow units and porosity structures in each plug. The number of flow units within each plug varied between one and four. The process of assembling plug-scale DRP-CCA and DRP-SCA properties is discussed.DRP-SCA results and laboratory measurements from similar rock types in the same wells are comparable and show inherent process and inter-lab uncertainties. The dynamic range of the computed relative permeability curves is superior to the laboratory measurements. The comparisons further showed the benefit of the DRP images and computations in capturing the detailed pore structure and fabric of the rock, especially in the capillary pressure responses. The DRP-SCA computations accentuate spontaneous imbibition and the transition to forced imbibition, a region that traditional laboratory methods may not adequately capture. Computations for different wetting conditions provide relative permeability data that cover all possible rock-fluid wettability states. Similar attempts in traditional laboratory experiments would be long, tedious and expensive.This work shows that DRP can provide satisfactory and complementary data for reservoir studies. The images are readily available and can be used for sensitivity studies. The workflow allows users to conduct their own validation tests, just as we have done, to determine the applicability of the method.
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