A significant body of work has been done on imaging the various gas and liquid producing shales. The images show the underlying heterogeneities and complexities that characterize shales. Implications of the observations at these scales on storage, thermodynamics and flow in shales are important, and are being examined by a number of groups.
The storage is conceptualized for various types of porosity – intergranular, intragranular, within the organic matter, etc. Complex pore structures that exist, for example in a Bakken shale sample are shown in Figure 1. Different types of measurements on prolific liquids producing shales indicate porosities of greater than 10%. The presence of this porosity is not easily evident from Figure 1. One of the questions is whether there is an underlying porosity in nanostructures of the shale samples. In a recent paper, Chen et al., (2013), observed that about 90% of the approximate 5% porosity is contained in pores smaller than 100 nm. Our work with fluorescent, epoxy-impregnated thin section studies have revealed underlying nanoporosity in chalks. In this project, we will create well-calibrated nanoporous materials to help us figure out the roles of different types of porosity on permeabilities and relative permeabilities. We will compare results with measurements on natural shale samples.
In our previous work, we have shown that matrix permeability is one of the most important properties that govern recoveries of liquids from shales. Thermodynamic properties such as bubble and dew points, gas-oil ratios, etc., are also important. The low gas production in some of the liquids producing shales have been attributed to suppression of bubble or dew points in nanopores. It is thus critically important to understand the impact of the nanoporous structure on the basic properties of shales and fluids in these shales.
The GRI method of measuring permeability in shales consists of crushing the rock, exposing this to pressure and measuring pressure decay. It is not clear how this measurement corresponds to the connected liquid permeability in liquid-bearing shales. In this project, we will measure permeabilities by different methods to demonstrate and understand relationships between various permeability measurement techniques. Shales that produce liquids are under primary production. Even more important is that standard methods usually only provide absolute permeability.
Concurrent saturation and flow of oil, gas and water, governed by relative permeabilities of fluids, is essential in establishing produced gas oil ratios (GORs). Variation of GOR over time may be the most important variable impacting economics of a play. There is little relative permeability data on shales because of the difficulty in performing these measurements. EGI has developed equipment and procedures for measuring saturation pressures, and absolute and relative permeabilities. In this project, we will use well-calibrated synthetic nanoporous materials and shale samples to measure saturation pressures, porosities, permeabilities and relative permeabilities.
Nanoporous materials consisting of silica and other compounds will be made by organic/inorganic molecular and supramolecular assembly chemistry. We will collaborate with Professor Michael Bartl in the Chemistry Department at the University of Utah to create these nanoporous structures. Materials will be silica based initially, but we will consider adding other mineralogies as the experiments proceed.
We will also add different clays to create shales representative of various formations. Techniques have been developed to make nanoporous materials with predefined pore sizes, ranging from a few nanometers to tens of nanometers, and shapes. It will be possible to change the pore arrangement (ordered/disordered) and the nature of connectivity of the nanopores.
Materials will be characterized using transmission and scanning electron microscope (TEM, SEM), BET Adsorption and other analytical devices. Imaging and property measurements of real shale samples will also be performed for comparison.
A special sintering technique developed by Professor Subhash Risbud at the University of California in Davis will be used to bind the nanoporous powders and transform them into solids with predefined shapes and dimensions. Sintering at different temperatures leads to different micro- and mesoporosities while preserving the nanoporous nature of the channels created. A focused ion beam scanning electron microscope (FIB-SEM) image of the sintered, synthetic shale sample is shown in Figure 2. The underlying nanoporous network is shown in Figure 3. The nano- and mesoporosities of these types of samples can be quantified explicitly. We will build well-characterized shales representative of major shale formations such as the Eagle Ford, Bakken, Niobrara and Wolfcamp by using different mineralogies and clays, measure properties and relate properties to pore size and morphology. Imaging and property measurements of real shale samples will also be performed for comparison.
Shale samples from liquids producing formations will be used for characterization and properties measurements. We will use core samples available in our core library and samples contributed by sponsors. Measurements of important properties will be provided on up-to six samples contributed by sponsors. Sample identities and specific locations will not be disclosed unless specifically approved by the contributing company. Results and interpretations will become part of a database that will be distributed to all the sponsors.
Contextual shale characterization encompasses the identification, quantification and correlation of samples using optical microscopy, automated mineralogical mapping (QEMSCAN®), XRD, XRF, argon-ion milling, high resolution electron microscopy (SEM and FIB-SEM), and ultra-high-resolution TEM/ STEM analysis. An integrated inorganic analysis of natural shales would be performed to identify, evaluate and correlate the key geological parameters that lead to ‘flow-viable’ pore systems relative to petrological variations (mineralogy, microstructure, deformational fabrics etc.). Samples from known reservoir plays (i.e. Bakken, Niobrara) will be used to characterize and identify key parameters within mineralogically varied shales (i.e. siliceous, argillaceous and carbonate mudstones). These measurements will be performed on in-house shale samples and shale samples supplied by the sponsors.
Characterization of natural shale samples is designed to focus on the contextual interpretation of rocks from micro- to nano-scales, identifying zones of differing petrology (mineralogy, deformation, etc.) in order to accurately characterize the heterogeneity of natural shales. The use of TEM/STEM in combination with SEM imaging and inorganic analytical methods is probably essential for the precise nano-scale characterization of natural shales and the subsequent accurate correlation with artificially created nanostructured materials. The use of analytically integrated techniques from a micro- to nano-scale is designed to facilitate the detailed interpretation of composition, texture, fabric, porosity, permeability, micro-tectonics, micro-facies/depositional evolution and diagenetic history of natural shale samples, thus allowing the samples to be placed into an appropriate geological context.
Saturation pressures will be measured for pure hydrocarbon mixtures in samples, synthetic and natural. The measurements in synthetics will explicitly reveal the impact of pore size on saturation pressures.
Porosity measurements will be performed using a helium porosimeter and by using a BET device. We will correlate these measurements with the petrology measurements and petrographic porosity characterization. Permeability measurements will also be carried out by multiple methods. The GRI crushed rock method will be used on a portion of a core sample and flow measurements will be performed on cores using the high-pressure, high-temperature system shown in Figure 5. Pressure pulse method will also be used on core samples. The system has been tested and has been used to measure permeabilities of the order of 100 nD in tight rocks (Figure 6). These offsets of measurements will help provide calibration to the crushed rock measurements.
Relative permeability measurements on gas-oil and water-oil fluid pairs will be performed first using permeability measurements on variably saturated samples. Selected steady-state measurements will be performed on cores. All measurements will be conducted using the apparatus shown in Figure 5 or flooding equipment equivalent to that shown in Figure 5.
Cheng Chen, Dandan Hu, Donald Westacott, and David Loveless, Nanometer-scale characterization of microscopic pores in shale kerogen by image analysis and pore-scale modeling, Geochemistry, Geophysics and Geosystems, Article: Volume 14, Number 10 2 October 2013 doi: 10.1002/ggge.20254 ISSN: 1525-2027