Tariq M. AlGhamdi

Numerical analysis of nuclear magnetic resonance relaxation–diffusion responses of sedimentary rock

The nuclear magnetic resonance (NMR) relaxation–diffusion response of porous reservoir rock is frequently used, e.g. in oil field applications, to extract characteristic length scales of pore space or information about saturating fluids. External gradients are typically applied to encode for diffusion. In reservoir rocks, field inhomogeneities due to internal gradients can even at low fields be strong enough to interfere with this encoding. Furthermore, the encoding for diffusion coefficients of fluids takes a finite amount of time, during which diffusing fluid molecules can experience restricted diffusion. Both effects can combine to make the interpretation of the diffusion dimension of a relaxation–diffusion measurement difficult. We use x-ray-CT images of porous rock samples to define the solid and fluid phases of reservoir rock and simulate the full experimental pulse sequence, taking into account the static applied field, external gradients and internal gradients as a function of susceptibility of each component, and surface and bulk relaxation properties of fluids and fluid–fluid and fluid–solid interfaces. We carry out simulations of NMR relaxation–diffusion measurements, while explicitly tracking the time-dependent diffusion coefficient in each fluid as well as associated local gradients. This allows us to quantify the influence of restricted diffusion and internal gradients for common choices of experimental parameters.

Shale Gas Characterization and Property Determination by Digital Rock Physics

Unconventional shale reservoirs diff er largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale comprises a wide variety of rocks that are composed of extremely fi ne-grained particles with very small porosity values on the order of a few porosity units and very low permeability values in the nanodarcy (nD) range. Shale formations are very complex at the core scale: they exhibit large vertical variations in lithology and total organic carbon (TOC) at a scale so small that it renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale level, where pores having diff erent porosity types are detected within the kerogen volume. Th ese complexities have led to further research and the development of an advanced application of high resolution X-ray computed tomography (XCT) scanning on full-diameter core sections to characterize shale mineralogy, porosity and rock facies so that accurate evaluation of the sweet spot locations can be made for further detailed petrophysical and petrographic studies. In this work, argillaceous shale gas cores were imaged using high resolution dual-energy XCT scanning. Th is imaging technique produces continuous whole core scans at 0.5 mm spacing and derives accurate bulk density (BD) and eff ective atomic number (Zeff ) logs along the core intervals, logs that are crucial in determining lithology, porosity and rock facies. Additionally, integrated X-ray diff raction (XRD) data and energy dispersive spectroscopy (EDS) analysis results were acquired to confi rm the mineral framework composition of the core. Smaller core plugs and subsamples representing the main variations in the core then were extracted for much higher resolution XCT scanning and scanning electron microscopy (SEM) analysis. Porosity, mainly found in organic matter, was determined from 2D and 3D SEM images by the image segmentation process. Horizontal fl uid fl ow was only possible through the organic matter and the simulations of 3D focused ion beam (FIB)SEM volumes by solving the Stokes equation using the Lattice Boltzmann method (LBM). A clear trend was observed between porosity and permeability, correlating with identifi ed facies in the core. Silica-rich facies gave higher porosity-permeability relationship characteristics compared to the clay-rich facies. Th is is mainly caused by the pressure compaction eff ect on the soft clay-rich samples. High percentages of organic matter were not found to be a good indication for high porosity or permeability in the clay-rich shale samples, while the depositional facies was found to have a great eff ect on the pore types, rock fabric and reservoir properties. Th e results and interpretations in this study provide further insights and enhance our understanding of the heterogeneity of the organic-rich shale reservoir rock. Introduction Hydrocarbon recovery factors from unconventional organic-rich shale have always been at the lower end of historic fi gures from conventional reservoirs1. Th e reason for this is the ultra-low permeability of the rock, which requires massive hydraulic fracturing to enhance connectivity, and therefore, permeability for the fl ow. Digital Rock Physics 14

Evaluation and Application of Digital Rock Physics (DRP) for Special Core Analysis in Carbonate Formations

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.