An Integrated Approach for the Characterization of Shales and Other

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An integrated approach for the characterization of shales and other unconventional resource materials Shahram Farhadi Nia, Devang Dasani, Theodore T. Tsotsis, and Kristian Jessen Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.5b04761 • Publication Date (Web): 03 Mar 2016 Downloaded from http://pubs.acs.org on March 4, 2016

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Industrial & Engineering Chemistry Research

An integrated approach for the characterization of shales and other unconventional resource materials

Journal: Manuscript ID: Manuscript Type: Date Submitted by the Author:

Industrial & Engineering Chemistry Research ie-2015-04761e Article 15-Dec-2015

Complete List of Authors: Nia, Shahram; Univ. of Southern California, ChemEng and MS Dasani, Devang; Univ. of Southern California, ChemEng and MS Tsotsis, Theodore; University of Southern California, Department of Chemical Engineering Jessen, Kristian; Univ. of Southern California, ChemEng and MS

Table of Contents (TOC) Graphic:

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An Integrated Approach for the Characterization of Shales and Other Unconventional Resource Materials Shahram Farhadi Nia, Devang Dasani, Theodore T. Tsotsis, and Kristian Jessen* Mork Family Department of Chemical Engineering and Materials Science, University of Southern California, Los Angeles, CA 90089-1211, USA

ABSTRACT Production of oil and gas from unconventional source rocks (shales) has increased significantly in recent years, reflecting a shift in the focus of the oil and gas industry from conventional to unconventional oil/gas resources. An improved insight into the pore structure characteristics of these important porous materials will enable a better understanding and further optimization of the production behavior from such vast hydrocarbon resources. In particular, characterization of porosity and permeability of shales is the key to accurately estimating the initial oil and gas in place and fluid flow through these rocks. However, evaluating the pore structure of shales presents technical challenges due to the presence of a range of pores, from the nanometer to the micrometer size. Characterization of the entire range of pore sizes requires an all-inclusive study

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Corresponding author, e-mail address: [email protected] 2


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employing a variety of techniques. Such an integrated approach is followed in this work to understand the pore structure of Monterey shale samples as obtained from various characterization techniques: (i) Mercury porosimetry, (ii) Nitrogen adsorption experiments, (iii) High-Resolution X-ray Computed Tomography (HRXCT), and (iv) Focused Ion Beam – Scanning Electron Microscopy (FIB-SEM). These techniques are coupled with gas permeability measurements of the Monterey shale samples as well as spontaneous water-air imbibition experiments. Calculated permeability values (via Lattice Boltzmann flow simulations) based on the pore characterization data are in good agreement with the gas permeability measurements. Finally, the interpretation of the observed fluid flow dynamics during a spontaneous water-air imbibition experiment, based on input from various characterization techniques, demonstrates the value of characterizing shale samples at a full range of pore scales.

KEYWORDS Unconventional resources; Monterey formation; Characterization; Image analysis; Fluid flow; Imbibition.

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1. INTRODUCTION Production of oil and gas from unconventional source rocks (shales) has increased significantly over the past decade due to a shift in the focus of the industry from conventional towards unconventional oil/gas resources. As an example, expansion of shale-oil operations is largely responsible for the increase in the total domestic crude oil production, from 5.66 million barrels per day (bpd) in 2011 to 8.46 million bpd in 2014. As noted in a report from the Energy Information Administration1, there are presently 33.2 billion barrels of technically recoverable crude oil in tight (i.e., unconventional) formations in the USA, the recovery of which will require the drilling of ~220,000 new wells1. The Monterey formation, consisting of highly heterogeneous and laminated rocks, represents a large fraction of these oil reserves (by some accounts up to 40%). An improved understanding, therefore, of the hierarchical and highly heterogeneous pore structure of shale rocks, in general, and of the Monterey shales (the focus of this paper), in particular, will enable us to better understand and further optimize the production behavior from these vast unconventional oil resources. The main distinguishing feature of shale-oil rocks, when compared to their more conventional counterparts, is their small (sub-micron) pore sizes. This is important, since the size distribution and connectivity of pores in a rock determines its overall fluid flow behavior, for example, its single-phase and multi-phase permeabilities. In addition, the small pore sizes makes most of the standard core analyses and tests difficult to apply for shale systems. For example, measurements of liquid permeability, and especially of two-phase relative permeability, are tedious for these low-permeability systems. Also, the mercury injection capillary pressure (MICP) technique, which is routinely applied to measure the pore-size distribution (PSD) of conventional rock samples, is more difficult to employ for shales, since for mercury to invade 4


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their small pores it requires a very high injection pressure (up to 60,000 psi), which may potentially cause the rock pore structure to deform and/or collapse. With the advent of unconventional rocks as important hydrocarbon resources, pore-scale imaging of rocks is also emerging as a new core analysis technique2. This technique, often referred to as digital rock physics3-5, is specifically useful for tight shale samples. For example, Curtis et al. 6 utilized Focused Ion Beam – Scanning Electron Microscopy (FIB-SEM) imaging to study the pores of shale samples, and found their sizes to be similar to those obtained from MICP and Nuclear Magnetic Resonance (NMR) measurements. They also used high resolution scanning transmission electron microscopy (STEM) to study the pores in clay minerals and in kerogen. Saidian et al.7 studied the PSD of different mud-rocks, from the Monterey, Haynesville, and Niobrara formations in the USA, as well as Eastern European Silurian formations, using N2 adsorption, MICP and NMR; they concluded that the information derived from the different characterization techniques should be combined for one to be able to reconstruct a representative pore-network of these shales. Elgmati et al.8 applied MICP and FIB-SEM on three different gasshale samples (Utica, Fayettville, and Haynesville) together with 3D pore modeling to investigate their porosity and PSD. They report MICP porosities of 10.3% and 14.6% with median pore diameters of 6.5 nm and 30 nm, respectively, for the Utica and Haynesville shale samples, and a calculated porosity (from FIB-SEM) of 28.2% with a mean pore diameter of 40 nm for the Fayettville shale sample. Their SEM imaging also revealed a kerogen porosity of 4050%. Clarkson et al.9 used N2 adsorption and MICP on core-plugs from a tight siltstone reservoir in western Canada in order to determine their PSD. They found the overlapping PSD probed by the two techniques to be in reasonable agreement. They also used simple microfracture (cube and matchstick) models, employing a slit–shaped pore geometry, in order to calculate the 5



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permeability of the samples, and compared their results with the permeability values estimated from the MICP data using the Swanson’s methodology10, and the permeabilities measured via the pulse-decay method. Hemes et al.11 used a combination of X-ray µ-CT (X-µ-CT), 2D broadion beam scanning electron microscopy (BIB-SEM) and FIB-SEM to study a Bloom clay sample from the Mol-Dessel research site (Belgium). They found the PSD to obey a power-law expression over a pore range spanning ~6 orders of magnitude. The PSD obtained from MICP was also found to obey a similar power-law expression. The images generated from the above techniques were used to create a 3D pore network (PN) representation of the clay structure via a pore network extraction (PNE) modeling method. Keller et al.12 used STEM, FIB-SEM and Xray tomography to study shale samples from the Opalinus Clay formation. The porosities calculated, as expected, depended on the image resolution (voxel size): At a resolution of 2.56 µm (X-ray tomography), they calculated a porosity of 0.60% and reported the pore space not to be connected; at a resolution of 10 nm, they calculated a porosity of 2.3% and 2.8% for two separate FIB-SEM scans, which is much lower than the 10-12%, as measured by N2 adsorption in their previous work13. Their FIB-SEM results suggest a connectivity anisotropy, with a lower connectivity in the direction perpendicular to the bedding than that within the bedding plane. In summary, in the last few years pore-scale imaging is emerging as an important characterization method for unconventional resource rocks with a number of reports appearing, primarily as part of various Conference Proceedings. However, most of the work to date has focused on carbonates and clay samples, and in few instances on gas-shale materials. In addition, as seen from the literature review above, most of the published work uses only a subset of the available experimental techniques to characterize the samples in focus. In this work, we present instead the results of a systematic effort to characterize shale-oil materials and, in particular, 6


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samples from the important Monterey formation. The Miocene Monterey is a diagenetic sequence that varies from amorphous opal-A to crystalline chert depending on the burial depth14. The samples used in this study are from the quartz porcelanite phase of the Monterey formation. Our efforts involve the use of imaging techniques (HRXCT, SEM, FIB-SEM) together with more conventional pore structure measurement methods (N2 BET, MICP, He pycnometry), as well as experiments to measure their transport properties (permeability and spontaneous waterair imbibition) and simulations (Lattice Boltzmann flow calculations) to predict such properties. The purpose of our study is two-fold: First, to provide new structural information for these important materials which enables a better understanding and further optimization of the production behavior from this vast hydrocarbon resource; and second, to demonstrate the value of the integrated use of these various measurement/analysis techniques, to characterize shale-oil samples at a full range of scales. 2. EXPERIMENTAL APPROACH As noted above, the focus of this paper is on shale-oil materials from the quartz porcelanite phase of the Monterey formation. Quartz porcelanite is a siliceous shale which is dominated by quartz, plagioclase and clay minerals. For the sample depth specific to this study, XRD analysis finds 71% of quartz and 18 % of clay with small amounts of dolomite (0.3%) and halite (0.5%). Due to the destructive nature of some of the tests performed, multiple samples from the same depth (subsamples of a larger core) were utilized throughout the study. A concise description of the various techniques employed is provided below.

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2.1. Mercury Porosimetry The MICP method is a well-established technique for the measurement of volumes associated with different pore sizes in reservoir rocks and in other porous materials15. The total pore volume of sample invaded by mercury provides a measure of its porosity, while a cross-plot of mercury saturation vs. injection pressure provides valuable information related to the PSD. During the MICP test, a rock sample is placed in a mercury container and the injection pressure of the mercury is gradually increased. At each pressure step, the mercury volume that has invaded the rock sample is then recorded. As the pressure increases, smaller and smaller pores in the sample are progressively invaded. During the MICP test, mercury is the non-wetting phase, hence, the MICP data reflect a drainage process. The mercury pressure and the corresponding invaded pore size are related through the Young-Laplace equation16 below: r = 2γcos(θ)/p ,

(1)

where r = pore radius, γ = surface tension, θ = contact angle, and p = absolute Hg injection pressure. The equation above indicates that in order to invade pores as small as a few nanometers, the injection pressure must be increased to about 60,000 psi. For the MICP analysis in this study a Micrometric AutoPore IV MICP instrument was utilized. 2.2. BET Analysis Another method that is commonly used to characterize porous materials, including shales, is the BET technique. In contrast to the MICP method, BET is a low-pressure gas adsorption technique, in which the surface area, the pore volume and the average pore size are all evaluated based on the physical adsorption and desorption of probe gas molecules, commonly N2 and CO2,

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on the sample’s pore surface17-18. In this work, N2 sorption at its liquid temperature (77 K) was carried out using a Micromeritics ASAP 2010 instrument. Several approaches, including the Barrett-Joyner-Halenda (BJH), Horvath-Kawazoe (HK), the t-plot methods, and density functional theory (DFT), are all commonly used to analyze the experimental isotherm data to determine the sample’s pore structure characteristics. In this work, the BJH method was used to calculate the PSD in the mesoporous region (2-50 nm) assuming a cylindrical pore geometry, while the HK method was used to characterize the pores in the microporous region (50 nm) is assumed to be fractures, while the mesoporous and microporous regions (pores with diameter

An Integrated Approach for the Characterization of Shales and Other

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