Pores in Marcellus Shale: A Neutron Scattering and FIB-SEM Study (original) (raw)
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Effects of maturation on multiscale (nanometer to millimeter) porosity in the Eagle Ford Shale
Interpretation, 2015
Porosity and permeability are key variables that link the thermal-hydrologic, geomechanical, and geochemical behavior in rock systems and are thus important input parameters for transport models. Neutron scattering studies indicate that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer-sized pores with huge amounts of total surface area to large open fracture systems (multiscale porosity). However, despite considerable efforts combining conventional petrophysics, neutron scattering, and electron microscopy, the quantitative nature of this porosity in tight gas shales, especially at smaller scales and over larger rock volumes, remains largely unknown. Nor is it well understood how pore networks are affected by regional variation in rock composition and properties, thermal changes across the oil window (maturity), and, most critically, hydraulic fracturing. To improve this understanding, we have used a combination of small-and ultrasmall-angle neutron scattering (U)SANS with scanning electron microscope (SEM)/backscattered electron imaging to analyze the pore structure of clay-and carbonate-rich samples of the Eagle Ford Shale. This formation is hydrocarbon rich, straddles the oil window, and is one of the most actively drilled oil and gas targets in the United States. Several important trends in the Eagle Ford rock pore structure have been identified using our approach. The (U)SANS results reflected the connected (effective) and unconnected porosity, as well as the volume occupied by organic material. The latter could be separated using total organic carbon data and, at all maturities, constituted a significant fraction of the apparent porosity. At lower maturities, the pore structure was strongly anisotropic. However, this decreased with increasing maturity, eventually disappearing entirely for carbonate-rich samples. In clay-and carbonate-rich samples, a significant reduction in total porosity occurred at (U)SANS scales, much of it during initial increases in maturity. This apparently contradicted SEM observations that showed increases in intraorganic porosity with increasing maturity. Organic-rich shales are, however, a very complex material from the point of view of scattering studies, and a more detailed analysis is needed to better understand these observations.
International Journal of Coal Geology, 2019
Small angle neutron scattering (SANS) and ultra-small angle neutron scattering (USANS) techniques have been increasingly utilized to study tight rocks (e.g., mudrocks), due to their capabilities of detecting total pore spaces (both body and throat) across the nm-m spectrum. Mercury injection capillary pressure (MICP) is a widely employed technique in the oil and gas industry, used to obtain a variety of petrophysical properties of porous rocks. In this study, we selected six samples from the three (i.e., lower, middle, and upper) members of the Bakken Formation (Late Devonian to Early Mississippian) in the Williston Basin, North Dakota. We utilized the complementary techniques of (U)SANS and MICP to characterize and differentiate their pore systems over a broad measurable range of pore/throat sizes from 1.25 nm to 50 m. Detailed processing of (U)SANS scattering data is illustrated to show how the total porosity and pore size distribution are obtained and compared against MICP analyses. The results show that the lower/upper Bakken samples and the middle Bakken samples have distinct mineral compositions and organic matter contents, which could be important factors affecting their pore structure. Assisted with the field emission-scanning electron microscopy (FE-SEM) technique, it was found that organic matter-hosted pores contribute a significant portion of total porosity in the lower/upper Bakken shales, while the middle Bakken samples are mostly composed of mineral pores. Additionally, the porosities measured by the (U)SANS and MICP techniques are related to sample sizes employed for each approach, due to a limited pore accessibility of mudrocks; a larger sample size will possess a higher proportion of isolated pores. In general, the results for the Bakken samples in this study indicate that the combination of (U)SANS, MICP, and FE-SEM approaches gives a more complete picture of the pore structure of tight rocks.
Hierarchical integration of porosity in shales
Scientific reports, 2018
Pore characterization in shales is challenging owing to the wide range of pore sizes and types present. Haynesville-Bossier shale (USA) was sampled as a typical clay-bearing siliceous, organic-rich, gas-mature shale and characterized over pore diameters ranging 2 nm to 3000 nm. Three advanced imaging techniques were utilized correlatively, including the application of Xe plasma focused ion beam scanning electron microscopy (plasma FIB or PFIB), complemented by the Ga FIB method which is now frequently used to characterise porosity and organic/inorganic phases, together with transmission electron microscope tomography of the nano-scale pores (voxel size 0.6 nm; resolution 1-2 nm). The three pore-size scales each contribute differently to the pore network. Those <10 nm (greatest number), 10 nm to 100 nm (best-connected hence controls transport properties), and >100 nm (greatest total volume hence determines fluid storativity). Four distinct pore types were found: intra-organic, ...
ACS Omega, 2022
Pore types and pore structure parameters are the important factors affecting the storage capacity of a shale oil reservoir. Pore morphology and mineralogical composition of shales have diverse effects on the upgrading of various phases of shale oil. To interpret the formation and distribution of different pore types and their structure parameters in the lacustrine calcareous shale, a combination of polarizing microscopy, X-ray diffraction, total organic carbon (TOC), field-emission scanning electron microscopy, and low-pressure nitrogen adsorption experiments were conducted on the Es3x shale of the Eocene Shahejie Formation in the Zhanhua Depression. The interpretations regarding pore types, pore structure parameters, and pore size distribution indicate that the pore morphology and pore size distribution in the lacustrine shale are very complicated and demonstrate strong heterogenic behavior. Inorganic pores (interparticle pores, intraparticle pores, intercrystalline pores, dissolution pores, and microfractures) are the most commonly distributed pore types in the studied shale. However, organic matter pores are poorly developed due to the lower thermal maturity of the Es3x shale. The Brunauer−Emmett−Teller specific surface and pore volume range from 0.026 to 1.282 m 2 /g (average 0.697 m 2 /g) and 0.003 to 0.008 cm 3 /g (average 0.005 cm 3 /g), respectively. The shape of the pores varies from slit-like to narrow slit. Different minerals develop different types of pores with various sizes extending from micropores (<2 nm), mesopores (2−50 nm), to macropores (>50 nm). The relationship between mineral components and pore parameters indicates that the carbonate minerals act as the main contributors to the formation and distribution of different pore types in the studied shale. Pore volume and the pore specific surface area did not show a good relationship with mineral composition and TOC due to disordered pores, but pore size shows a good relationship with mineral composition and TOC of the Es3x shale. The whole pore system description showed that the mesopores and macropores are abundantly distributed and are the main contributors to the pore system in the Es3x shale. A comprehensive understanding of the formation mechanism and structural features of various sized pores in a variety of different minerals can provide a good tool for the exploration and development of shale oil reservoirs.
Submicron-Pore Characterization of Shale Gas Plays
2011
Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40−50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet). 2 SPE 144050 Key to successful characterization of fluid flow behavior in shale gas plays is an understanding of the petrophysics of shale rocks and their submicron pore structures. A few studies have attempted to construct submicron pore structures. Liviu et al. (2007) conducted an intensive study of submicron pore imaging using SEM-FIB for chalk rocks. Sondergeld et al. (2010) used the same method to characterize the submicron structures of a few shale gas plays. However, no attempt has yet been made to systematically characterize the petrophysical properties of shale gas plays with any means other than submicron pore imaging. This work used high pressure mercury porosimetry analysis, or MICP (up to 60,000 psi) to determine pore throat distribution and pore volume. It used a dual-beam system (SEM/FIB) to reconstruct three-dimensional structural pore models of shale gas samples. Energy-dispersive spectroscopy (EDS) confirmed the existence of organic matter (kerogen) and defined the elemental composition of the examined shale gas samples. A modest clay mineralogy study was conducted by using X-ray diffractometer. Contact angle measurements evaluated surface wetting properties. Mercury Porosimetry (MICP) Mercury (Hg) is a toxic material that has been used in rock laboratories as an indirect measure of rock capillarity and porosimetry. These experiments are considered destructive, expensive, and time consuming. Nevertheless, mercury porosimetry has been widely accepted as a mean to characterize porous solids with respect to their pore volume (porosity) and pore size distribution over a wide range of pore sizes. Mercury is nonwetting phase and it can only access interconnected pores. The volume of mercury that can enter pore spaces is limited by the maximum pressure attained during analysis. MICP has produced representative and reproducible results for conventional reservoir rocks. However, for shale gas rocks, the scenario is almost impossible to reproduce due to the shale tightness. Only two of 12 attempts have been successful, although high injection pressures up to 60,000 psi were applied. This pressure level is still greater by a factor of 5 than that determined by curve of water drainage displaced by air.
Formation and occurrence of organic matter-hosted porosity in shales
International Journal of Coal Geology, 2018
Porosity within organic matter (OM) is considered to be the main site for gas storage (via fluid phase saturation of the pores and sorption on the pore walls) and thus its presence or absence is very critical for in-place gas assessment for organic-rich rocks. Numerous workers have suggested that OM-hosted porosity increases with thermal maturity mainly related to the process of bituminized organic matter cracking to gas. Comprehensive reviews of published literature enable us to conclude that organic porosity dominantly develops within bituminized organic matter (i.e., that portion that is petrographically identified, mainly based on its morphology, as solid bitumen (Mastalerz et al., 2018)) and primary (i.e, structured or amorphous) organic matter (kerogen) is mostly deficient in porosity. We show that in the same shale sample, structured kerogen shows no porosity whereas solid bitumen contains abundant porosity. It has been previously reported that sample preparation for SEM by ion milling may alter the organic matter. In this study, some adverse effects of ion milling have been observed by comparing SEM-visible pores of the same sample prepared by mechanical grind polish (MGP) and ion milling (IM) methods. Since solid bitumen is more labile, and probably more prone to chemical/physical alterations, we recommend that SEM observations of ion milled samples to be conducted with more attentiveness.
Probing the 3D molecular and mineralogical heterogeneity in oil reservoir rocks at the pore scale
Scientific Reports
Innovative solutions have been designed to meet the global demand for energy and environmental sustainability, such as enhanced hydrocarbon recovery and geo-sequestration of CO 2. These processes involve the movement of immiscible fluids through permeable rocks, which is affected by the interfacial properties of rocks at the pore scale. Overcoming major challenges in these processes relies on a deeper understanding about the fundamental factors that control the rock wettability. In particular, the efficiency of oil recovery strategies depends largely on the 3D wetting pattern of reservoir rocks, which is in turn affected by the adsorption and deposition of 'contaminant' molecules on the pores' surface. Here, we combined high-resolution neutron tomography (NT) and synchrotron X-ray tomography (XRT) to probe the previously unobserved 3D distribution of molecular and mineralogical heterogeneity of oil reservoir rocks at the pore scale. Retrieving the distribution of neutron attenuation coefficients by Monte Carlo simulations, 3D molecular chemical mappings with micrometer dimensions could be provided. This approach allows us to identify co-localization of mineral phases with chemically distinct hydrogen-containing molecules, providing a solid foundation for the understanding of the interfacial phenomena involved in multiphase fluid flow in permeable media.
Palynofacies Analysis and Submicron Pore Modeling of Shale-Gas Plays
North American Unconventional Gas Conference and Exhibition, 2011
The present study combines palynological applications with advanced microscopic techniques to characterize the Utica, Haynesville and Fayetteville shale-gas source rocks. This unprecedented approach could offer an alternative way to measure the total organic carbon (TOC) content using the 2D subsurface Scanning Electron Microscope (SEM) images. This approach is considered to be a faster and inexpensive method compared to conventional geochemical analyses. Palynofacies analysis provided valuable information about kerogen type and its degree of thermal maturation, which are key parameters in shalegas exploration. Moreover, it qualitatively allowed the estimation of important organic geochemical parameters such as vitrinite reflectance (R o %) and numerical thermal alteration index (TAI). New high resolution microscopic solutions have successfully been exploited for source rock characterization at both micro-and nano-meter scales. In-situ Focused Ion Beam (FIB) and Scanning Electron Microscope (SEM) technologies provided new insights into rock fabrics such as porosity, permeability, tortuosity, anisotropy and kerogen content. Serial sectioning and sequential imaging using dual beam SEM/FIB instrument were implemented successfully to characterize the 2D kerogen content and 3D submicron-pore structures. Moreover, pores were found in organic matters with the size of nano level and occupy 40−50% of the kerogen body. A successful example of reconstructed 3D pore model from Fayetteville Shale is presented.
International Journal of Oil, Gas and Coal Technology, 2012
Three-dimensional pore network reconstructions of mudstone properties are made using dual focused ion beam-scanning electron microscopy (FIB-SEM). Samples of Jurassic Haynesville Formation mudstone are examined with FIB-SEM and image analysis to determine pore properties, topology, and tortuosity. Resolvable pore morphologies (>~10 nm) include large slit-like pores between clay aggregates and smaller pores in strain shadows surrounding larger clastic grains. Mercury injection capillary pressure (MICP) data suggest a dominant 1-10 nm or less size of pores barely resolvable by FIB-SEM imaging. Computational fluid dynamics modelling is used to calculate single phase permeability of the larger pore networks on the order of a few nanodarcys (which compare favourably with core-scale permeability tests). This suggests a pore hierarchy wherein permeability may be limited by connected networks of inter-aggregate pores larger than about 20 nm, while MICP results reflect smaller connected networks of pores residing in the clay matrix. [
Pore structure and tracer migration behavior of typical American and Chinese shales
Petroleum Science, 2015
With estimated shale gas resources greater than those of US and Canada combined, China has been embarking on an ambitious shale development program. However, nearly 30 years of American experience in shale hydrocarbon exploration and production indicates a low total recovery of shale gas at 12 %-30 % and tight oil at 5 %-10 %. One of the main barriers to sustainable development of shale resources, namely the pore structure (geometry and connectivity) of the nanopores for storing and transporting hydrocarbons, is rarely investigated. In this study, we collected samples from a variety of leading hydrocarbon-producing shale formations in US and China. These formations have different ages and geologic characteristics (e.g., porosity, permeability, mineralogy, total organic content, and thermal maturation). We studied their pore structure characteristics, imbibition and saturated diffusion, edge-accessible porosity, and wettability with four complementary tests: mercury intrusion porosimetry, fluid and tracer imbibition into initially dry shale, tracer diffusion into fluid-saturated shale, and high-pressure Wood's metal intrusion followed with imaging and elemental mapping. The imbibition and diffusion tests use tracer-bearing wettability fluids (API brine or n-decane) to examine the association of tracers with mineral or organic matter phases, using a sensitive and micro-scale elemental laser ablation ICP-MS mapping technique. For two molecular tracers in n-decane fluid with the estimated sizes of 1.39 nm 9 0.29 nm 9 0.18 nm for 1-iododecane and 1.27 nm 9 0.92 nm 9 0.78 nm for trichlorooxobis (triphenylphosphine) rhenium, much less penetration was observed for larger molecules of organic rhenium in shales with median pore-throat sizes of several nanometers. This indicates the probable entanglement of sub-nano-sized molecules in shales with nano-sized pore-throats. Overall findings from the above innovative approaches indicate the limited accessibility (several millimeters from sample edge) and connectivity of tortuous nanopore spaces in shales with spatial wettability, which could lead to the low overall hydrocarbon recovery because of the limited fracture-matrix connection and migration of hydrocarbon molecules from the shale matrix to the stimulated fracture network.