Abstract There are a variety of pore types in unconventional resource mudstones and shales. The currently preferred method by geologists and petrophysicists is to examine and analyze these mudstones and shales by argonion and focused ion-beam milling to produce an ultrasmooth surface, coupled with observation under the field emission scanning electron microscope (FESEM). Potential issues with Ar-ion milled/FESEM preparation and imaging include (1) the small size of sample cubes for upscaling, (2) loss of structural fabric during the milling–imaging process, (3) fewer non-inorganic pore types observed than when observed with an unpolished surface, (4) analog use of pores from one shale to another, although the pore types and composition might differ, and (5) the creation of potential artifacts related to desiccation and rock expansion because of core retrieval and sample preparation. Conventional FESEM images obtained from freshly broken surfaces reveal much more textural detail than those obtained from ion-milled (polished) surfaces. Although conventional FESEM methodology may share some of the same limitations as Ar-ion beam-milled/FESEM technology, FESEM methodology should not be overlooked because it provides a more cost-effective and potentially more accurate analysis for estimating porosity and determining pore types and their distribution in shales. Comparison of FESEM images from ion-milled and fresh, non-ion-milled surfaces reveals that organic matter and internal organoporosity are best viewed on ion-milled surfaces, but shale microfabric and non-organoporosity is best viewed under non-milled surfaces. Complete FESEM imagery for shale characterization should include both types of analyses.

Abstract Scanning electron microscopy (SEM) has become a common way to estimate porosity and organic matter (OM) content within shale resource rocks. Since quantitative SEM analysis has emerged as a means for assessing the porosity of shale, a common goal has been to image polished samples at the highest possible resolutions. Because nanopores are visible at pixel resolutions ranging from 5 to 10 nm, it is natural to consider the possibility of a pore regime below 5 nm that could contribute a significant amount to the total porosity of the system. When considering that a molecule of methane gas is on the order of 0.4 nm diameter, pores smaller than 5 nm could contribute significant storage volume and transport pathways in a reservoir. These nanopores may be a significant source of porosity within certain OM bodies, where total detectable pores using SEM (i.e., ~10 nm pore body diameter and up) have been observed to be volumetrically equivalent to the OM body volumes themselves. With the potential to examine the population of pores below ~10 nm in diameter using the helium ion microscope (HIM), it is possible to construct a rock model that is more representative of the varied pore size regimes present. The primary goal of this study was to quantify the amount of organic-associated pores below the resolution of conventional field emission scanning electron microscope (FESEM). In this study, 51 individual imaging locations from 12 organic shale samples were selected for systematic imaging using a HIM. These samples and locations were selected because of the presence of porous OM identified from previously completed SEM imaging. After methodical HIM imaging and digital segmentation, it was concluded that most samples had no significant incremental, resolvable, organic pore fraction below the detection threshold of conventional FESEM imaging. The advanced resolution of the helium ion beam provides sharper definition of pore boundaries, but the total porosity fraction of these <10 nm diameter pores within the OM in most samples was negligible. We also notice that FESEM and HIM can be considered complementary techniques, as each provides beneficial information that cannot be obtained from using only one method.

Abstract The complexity of unconventional reservoirs is manifested both in compositional variance of the matrix and the vast heterogeneity of the pore geometry. These complications confound proper understanding of transport properties and, consequently, recoverability for all stages in the production life cycle. Imaging techniques have emerged as a technical solution to aid how we decipher these complexities at the appropriate scales. In this study, we use the Woodford Shale as a representative of a commercially viable unconventional reservoir, and we apply multi-scale imaging analytics to a core sample. Our observations across four different length scales from imaging results of micro-x-ray microscopy (micro-XRM), nano-x-ray microscopy (nano-XRM), and focused ion-beam scanning electron microscopy (FIB-SEM) demonstrate both heterogeneity and anisotropy at every scale. We describe our multi-scale imaging workflow, which proved necessary to capture the multi-scale variability. In this instance of siliceous type II source rock, we find that micro-XRM was insufficient to visualize porosity, nano-XRM was sufficient for visualization of only limited porosity, whereas FIB-SEM yielded the resolved pore network. We further find that discrimination of the pore types, with the aid of image segmentation, helps define the connectivity and nature of the transport system. Collectively, the application of imaging across scales with appropriate image processing is required to adequately understand the transport-governing microstructure.

Abstract Porosity and pore size distribution (PSD) are required to calculate reservoir quality and volume. Numerous inconsistencies have been reported in measurements of these properties in shales (mudrocks). We investigate these inconsistencies by evaluating the effects of fine grains, small pores, high clay content, swelling clay minerals and pores hosted in organic content. Using mudrocks from the Haynesville, Eastern European Silurian, Niobrara, and Monterey formations, we measured porosity and pore or throat size distribution using subcritical nitrogen (N 2 ) gas adsorption at 77.3 K, mercury intrusion, water immersion, and helium porosimetry based on Gas Research Institute standard methodology. We used scanning electron microscope (SEM) images to understand the pore structure at a microscopic scale. We separated the samples from each formation into groups based on their clay and total organic carbon (TOC) contents and further investigated the effects of geochemical and mineralogical variations on porosity and PSD. We find that differences in the porosity and PSD measurement techniques can be explained with thermal maturity, texture, and mineralogy, specifically clay content and type and TOC variations. We find that porosity and PSD measurement techniques can provide complementary information within each group provided the comparison is made between methods appropriate for that group. Our intent is to provide a better understanding of the inconsistencies in porosity measurements when different techniques are used.

Abstract Reservoir rocks can be highly sensitive to fluids introduced through hydraulic fracturing, water disposal, or waterflood injection. The sensitivity of reservoir rocks to fluids can lead to reduced permeability and permanent formation damage resulting in reduced productivity or injectivity. It is generally assumed that clays are the primary culprit in formation damage caused by swelling, increased clay-bound water, water shock, or denigration. In this chapter, we present results from a two-year effort to understand the fluid sensitivity of tight sandstone reservoirs in the Greater Monument Butte Unit (GMBU) in the Uinta Basin, Utah, U.S.A. Newfield Exploration (NFX) drills and completes approximately 200 wells per year in the field, which is currently under waterflood with injection rates of ~90,000 barrels per day. When we initiated this study, NFX completed wells with fresh water. Pore-scale imaging was the key to designing new core flood experiments that led to optimized completions fluids for the field. Initially, we assumed that potential fluid sensitivity was caused by mixed-layer illite-smectite (I/S). XRD (x-ray diffraction) and SEM (scanning electron microscope) images indicated that some GMBU reservoir rocks contained pore-bridging I/S. We designed initial core flood experiments combined with core nuclear magnetic resonance to identify and quantify clay reactions. The results of these initial tests indicated that the reservoirs were sensitive to lower-salinity completions fluids and a reduction in permeability was observed. We utilized a new approach involving pore-scale imaging to identify the mechanism causing permeability reduction. Comparison of SEM images of minerals in pores before and after fluid placement identified calcite dissolution and fines migration as the cause of permeability reduction. Micro-CT (micro-computed tomography) scans combined with registered EDX (energy-dispersive x-ray spectroscopy) mineralogy provided the context for the severity of the problem, especially in the better reservoir rock. The results of this work challenge a number of commonly held assumptions of rock–fluid sensitivity and have implications on how to design effective fluid sensitivity studies using core. This work involved collaboration between petrophysicists, geologists, engineers, and facilities personnel to design and implement a completions fluid that does not damage multiple reservoirs while remaining cost effective and efficient. This work demonstrates the value of focused science within the context of cost and field operational constraints.

Abstract The Middle Devonian Geneseo Formation and its lateral equivalents in the Northern Appalachian Basin are regarded as crucial secondary targets to the extensively explored Marcellus subgroup. High-resolution sedimentology, stratigraphy, and petrography have yielded differentiation of genetically related packages, comprised of distinct lithofacies with characteristic physical, biological, and chemical attributes. In addition, argon ion milling and nanoscale scanning electron microscopy of shale sections has shown that the pore structure of the Geneseo derives from pores defined by phyllosilicate frameworks, carbonate dissolution, and within organic matter. Intervals of silt-rich mudstones and muddy siltstones occur in multiple facies types and “interrupt” facies, reflecting background sedimentation. These deposits and their sedimentary features are interpreted as products of high-density fluvial discharge events. Pore morphology and distribution correlates with distinct mudstone lithofacies as a result of small-scale compositional and textural characteristics. Phyllosilicate framework pores are small triangular openings (100-1500 nm wide) and are the dominant pore type observed in hyperpycnites. Organic matter porosity is common (10-500 nm pore size) and dominates the organic-rich facies that represents “background” sedimentation with high organic content. Carbonate dissolution pores (50-500 nm wide) are observed in calcareous intervals and reflect partial dissolution of carbonate grains during catagenetic formation of carboxylic/phenolic acids.

Abstract This study shows examples of how fundamental relationships between pore shape, porosity, permeability, and acoustic response differ in carbonate mudrocks with micro- to picoporosity (<62 μm diameter) compared to conventional carbonates with primarily macroporosity (256-4 mm diameter). Quantitative data show that some positive correlations exist between porosity and permeability, similar to those observed in conventional carbonates. However, several expected relationships between properties, such as pore shape and laboratory-measured porosity and permeability, are not readily apparent and appear to be complicated by the internal pore architecture coupled with diagenetic alterations and a multiscale fracture network. Additionally, there is a significant shift in measured sonic velocity relative to values calculated from empirically derived equations that are applicable to conventional carbonates. Deviations from expected quantitative data trends can be partially explained through qualitative observations of the pore types and internal pore geometries. Visual observations show how diagenesis can increase the complexity of the internal pore network by nonsystematically subdividing the pores. When correlated to facies, the internal pore geometry partially clarifies deviations to expected relationships between quantitative pore architecture measurements, porosity, and permeability. Although there is an added level of complexity in the pore architecture of carbonate mudrocks, this study shows there are fundamental relationships that exist between the pore architecture, pore shape, porosity, permeability, acoustic response, facies, and sequence stratigraphic framework with variable levels of predictability that, when used as an integrated data set, can be used to enhance the predictability of key petrophysical properties within these types of reservoir systems.

Abstract This Memoir covers recent advances in the acquisition and application of high-resolution image data to unconventional reservoirs. The value of integrating multiple techniques is a common theme. Chapters address imaging methods, recognition of artifacts, and case studies that explore nanopore systems within particular depositional settings. The importance of mineralogy, organic matter content, and fabric to reservoir quality issues such as wettability, porosity, and formation damage are addressed. This volume will prove useful to anyone interested in the methods for observing and quantifying the pore systems that control hydrocarbon storage and flow in unconventional reservoirs. Unconventional reservoirs studied include Bakken, Barnett, Bossier, Eagle Ford, Geneseo, Green River, Horn River, Marcellus, Mississippi Lime, Monterey, Niobrara, Wolfcamp, and Woodford formations.

Abstract Minerals can precipitate in samples after coring and after preparation for scanning electron microscope (SEM) imaging. Re-deposition of solids from ion milling also produces artifacts that can be observed in images. Both mineral precipitates and re-deposited solid mixtures can be obvious artifacts, but they can also be subtle and challenging to interpret as features that are not present in the subsurface. The most common mineral precipitates are hydrous calcium sulfate (gypsum or bassanite) and halite. Iron sulfate minerals are also commonly observed. These types of artifacts are illustrated, with examples from ion-milled, mechanically polished, and freshly broken surfaces of various sedimentary rocks. Recognition of these artifacts is important because they can reduce porosity and pore size in SEM images and can affect measurements of rock composition and interpretations of pore fluid chemistry.

Abstract Using conventional core samples from the Upper Devonian–Mississippian Bakken Formation, Williston Basin, North Dakota, U.S.A., and the Upper Cretaceous Niobrara Formation, Denver Basin, Colorado, U.S.A., as examples, the pore systems and the associated organic matter habit common in these source rocks and associated unconventional tight oil reservoirs are characterized. A workflow that distinguishes primary organic matter (kerogen) and secondary organic matter (bitumen and oil) based on their morphology, paragenesis, and general thermal history as interpreted from high-resolution scanning electron microscopy-based technologies is described in this chapter. In the description of this workflow, the quantitative image processing challenges of discriminating and quantifying pores and organic matter types are reviewed.

Abstract Five shale samples preserved from the oil window of four unconventional reservoirs were solvent-extracted using toluene and methanol for high-resolution, secondary-electron imaging with field emission scanning electron microscopy (SEM) of the textures of organic matter (OM) present at or near induced fracture surfaces. The samples represent calcareous, siliceous, and mixed mineralogy mudrocks. Based on their nanoscopic textures, nine categories of OM could be distinguished: (1) nonporous particles, (2) low-porosity masses (sometimes [3] with mineral crystallites), (4) spherule aggregates, (5) intermediate-porosity granular masses, and (6) high-porosity foamy frameworks between mineral grains, together with (7) thick, (8) thin, or (9) very thin coats on mineral surfaces. The frequency of occurrence of these OM categories was qualitatively assessed from all images and compared to those from siliceous gas-window maturity Barnett Shale. The various morphologies are interpreted to comprise types of kerogen, bitumen, and asphaltenic residues, and transformations between them due to maturation and migration are proposed. After the first stage of cleaning and imaging, the samples were re-cleaned with stronger solvents for re-imaging at the same locations. Chloroform/methanol azeotrope only mobilized the very thin coats on clays, which presumably comprise asphaltenic nanoparticles deposited from crude oil as later-stage wettability alteration in the reservoir. Tetrahydrofuran effected only a slight swelling of mature bitumen, while pyridine (at higher temperature) apparently induced further bitumen production from kerogen and partially dissolved some preexisting bitumen but did not dissolve most of the OM present.