Christopher M. Prince

Evaluation of strategies for segmentation of blue-dyed pores in thin sections of reservoir rocks

Abstract Petrographic image analysis concerns segmentation and analysis of a rock fabric in the format of a 30 μ thick “thin section.” A major objective of such analysis is to segment pores (voids) from the rock material inasmuch as pore size and geometry control fluid flow. Conventionally, prior to sectioning, the rock is impregnated with blue dyed epoxy. Since few, if any naturally occurring components of reservoir rocks are blue, a segmentation process based upon color is appropriate. Segmentation in this case must accomplish both the correct identification of a pore and the precise definition of its edge. Most of the conventional segmentation techniques, which employ thresholding on histograms, failed in this because of problems associated with high light intensities required for petrographic microscopy and because of gradational boundaries caused by shelving effects. Successful segmentation was accomplished by modeling the digital filters on the human perception of the color of pore pixels. It has been shown that both of the filters developed clearly distinguish pore from nonpore and locate edges with high precision. However, a histogram of hue is still employed to identify the nature of pore boundaries (vertical, shelving, etc.).

Analysis of spatial order in sandstones. I. Basic principles

The spatial arrangement of sedimentary rock components is a fundamental property of sedimentary rocks. If we assume that the size, shape, and composition of sedimentary rock components (mineral grains, pores) carry useful petrologic information, there is no reason to assume that their spatial arrangement does not. Spatial arrangement has been discussed in terms of “texture” and “fabric,” but it has had little objective measurement or classification. This deficiency is primarily due to the difficulties associated with the quantification of spatial phenomena. However, using digital-imaging techniques it is possible to generate petrographic images from thin-sections and quantify the spatial arrangement of selected rock components using a two-dimensional (2D) Fourier transform. A Fourier transform creates a spectral representation of the image similar to an x-ray diffraction pattern. This paper presents the fundamental framework of 2D Fourier analysis in petrology. This type of analysis provides a means to quantify and analyze the spatial arrangement of rock components in an objective, mathematical framework. 2D Fourier power spectra can be used to characterize the type and degree of spatial order in an image, both in terms of the classical concepts of long-range and short-range order and in terms of spatial patterns characteristic of sedimentary rock. The clearly defined mathematical relationship between an image and its Fourier power spectrum provide the opportunity to define the 2D structure of an image in the same manner that x-ray diffraction patterns are used to map 3D structure in minerals. In addition, a 2D Fourier power spectrum is easily transformed into a radial power spectrum. Radial power spectra can be used to characterize the density of objects in an image. They also provide a valid means to compare and contrast images in a multivariate framework, regardless of the type of order. One of the most desirable properties of a Fourier transform is its reversibility. Using selected components of the power spectrum, the inverse transform can be used to build synthetic images, which highlight those petrologic components that most affect the power spectrum. The inverse transform provides the means to translate the results of analysis into meaningful petrologic characteristics.

DECODE and DFOUR: 2-D Fourier processing of petrographic images

Abstract Two-dimensional Fourier analysis provides a method to quantify the spatial arrangement of rock constituents in thin section. DECODE and DFOUR are the first in a series of Pascal programs designed to implement this technique on a low-cost PC/AT-based system. DECODE is used to preprocess binary images, allowing the user to subsample any part of a binary image. Selected (“Pore”) pixels are given a value of +1. Unselected (“Not pore”) pixels are given a value of −1. The output, stored on disk, is a 128 × 128 real-valued subsample, adjusted to have an arithmetic mean of zero. DFOUR applies a 2-D Fourier transform to the subsample. The output consists of a printed/plotted power spectrum, a disk file containing the 2-D transform results, and a disk file containing a radial power spectrum of the transform. The stored results form the basis of further analysis.

The effect of sandstone microfabric upon relative permeability end points

Abstract The nuances of relative permeability curves are commonly considered to be the product of variations in pore structure and wettability. Extrapolation of the results of a few flow tests into an entire reservoir for simulation purposes assumes that wettability does not change much over most of the reservoir and that the porous microstructure is relatively random and homogeneous. However, there is an increasing body of research indicating that the distribution of porosity is never random or homogeneous. Sandstone fabrics are a mixture of close-packed domains and packing flaws. This characteristic structure imparts a characteristic structure to the pore network that, in turn, defines fluid flow behavior (both single- and multiphase). Packing flaws are zones of oversized pores and pore throats with great spatial continuity. In lithified sandstones, virtually all of the single-phase flow occurs within packing flaws. The close-packed zones have much smaller pores and pore throats, and along with microporosity, tend to retain irreducible water. Results from a variety of quartz-rich sandstone reservoirs indicate that the domainal structure of porosity exerts a major influence upon S or and S wi values observed in unsteady-state tests. The sample set is limited to quartz-rich reservoir sands with an induced water-wet condition. However, the results demonstrate the linkage between pore fabric and relative permeability end points, and may ultimately permit one to extrapolate those properties as a function of depositional fabric.

Sandstone Reservoir Assessment and Production is Fundamentally Affected by Properties of a Characteristic Porous Microfabric

All sandstones have a characteristic porous micro-fabric consisting of packing flaws and close packed domains. The packing flaws are arrayed as circuits with great areal continuity composed of oversized pores linked by oversized pore throats. The porosity involved in the packing flaws can be detected and classified by two image analytical procedures and this quantitative data can be correlated with a wide range of fluid properties (permeability, Sor, Swi, etc.). Packing flaws are preferentially preserved during compaction and chemical diagenesis. Wetting phases are preferentially segregated in the close packed domains, are relatively immobile and, in most sandstones, the porosity fraction represented by close-packed porosity is correlated with Swi. However, grain size also affects the value of Swi. In general, a coarse grained conglomerate will contain close packed domains whose throats only weakly imbibe water whereas the contrary occurs in an equivalently sorted medium or fine grained quartz-rich sandstone. For a quartz rich sandstones however, Swi is proportional to the amount of porosity in close packed domains. Mobile non wetting phases are restricted to loose packed circuits. A subset of circuits with the aspect ratio closest to unity carries the non wetting phase at highest water saturations--the remainder of the loose packed circuits account for most of the Sor. Image analytical procedures can therefore objectively define reservoir rock types and evaluate the porous microfabrics of these rock types in terms of a more relevant reservoir description and tying rock type to wireline log response. The existence of the small scale heterogeneity consisting of packing flaws and close-packed domains may explain in some part the difficulty in scaling up permeability (a sample support problem) and may require a reevaluation of the basis of relative permeability procedures.

Areal and lateral changes in a major trailing margin turbidite—The Black Shell Turbidite

The Black Shell Turbidite on the Hatteras Abyssal Plain covers at least 50,000 km2, with a volume over 100 km3. It was initiated by failure on the upper continental slope and was channeled southeast through Hatteras Canyon to the plain. Provenance related shape studies indicate that on the plain the current separated into a sandy Phase which flowed S-SE and a lutitic phase, which traveled E-SE and then veered to the south. A change in the direction of slope caused the sandy phase to be deflected to the SE, where it merged with the lutitic phase on the eastern margin of the plain.

RADON and DIRPOWER: projection software for 2-D Fourier power spectra

Abstract Two-dimensional (2-D) Fourier analysis provides a method for spatial analysis of rock fabrics in thin section. RADON and DIRPOWER are analytical aids designed to create projections of 2-D real-valued functions, including 2-D Fourier power spectra. RADON is used to create parallel projections, projecting the power spectrum towards a line oriented at any angle relative to the spectrum. It provides an “edge-on” view of the power spectrum. DIRPOWER is used to create a Mean Directional Power Spectrum (MDPS), a circular projection used to assess the direction and degree of orientation within rock fabrics.