As a result of increased interest in unconventional oil and gas petroleum systems worldwide, the use of scanning electron microscopy (SEM) has an important role for characterizing microstructure of shale source rocks and reservoirs (Slatt and O’Brien, 2011; Chalmers et al., 2012; Curtis et al., 2012a, 2012b; Camp et al., 2013; Cardott et al., 2015; Lu et al., 2015; Hackley et al., 2017a). The high resolutions (<10 nm) achieved with modern field emission scanning electron microscopes (FE-SEM), coupled with ion milling sample preparation (e.g., broad-ion-beam, focused-ion-beam), have enabled scientists to identify and characterize nanoscale porosity of dispersed organic matter (OM) (Loucks et al., 2009; Loucks et al., 2012; Milliken and Curtis, 2016). Characterization of this feature in shale petroleum systems via SEM is critical as the development of nanoporosity during organic catagenesis can contribute to hydrocarbon migration and storage (Löhr et al., 2015; Han et al., 2017).

Organic diagenesis and formation of kerogen from original biotic matter begins in the water column and continues in sediment surface layers where microbial activity is greatest (Meyers, 1994; Taylor et al., 1998). Catagenetic transformation of this kerogen to petroleum occurs in source rocks during deeper burial at thermal stresses of about 70°C to >150°C (158°F to >302°F) (Pepper and Corvi, 1995; Pepper, 2017) and this is the arena where petrographers using SEM have made great strides in microstructural characterization over the last decade. The instrument discussed in this report is an FE-SEM, typically available to petrographers, equipped with both secondary electron (SE) and backscattered electron (BSE) detection systems. More specialized SEM systems can be equipped with a multitude of detectors, such as energy dispersive spectroscopy (EDS), wavelength dispersive spectroscopy (WDS), electron backscatter diffraction (EBSD), micro-computed tomography (micro-CT), micro-X-ray fluorescence (micro-XRF) and more recently, a Raman laser system integral with SEM (e.g., Timmermans et al., 2016). However, one issue with SEM that has hindered organic porosity research is its inability to provide enough supporting evidence to adequately identify dispersed OM. In particular, SEM cannot reliably differentiate primary kerogen from the catagenetic products of its conversion to secondary solid petroleum (i.e., solid bitumen), nor can it distinguish kerogen types using SE and BSE analysis alone (Hackley and Cardott, 2016; Hackley, 2017). Traditional organic petrology uses optical microscopy to identify OM based on form/shape, reflectance, relief, and fluorescence. By contrast, SEM collects information on surface relief through the collection of SE and on atomic number contrast using a BSE detector. Therefore, the form and shape of OM and its geologic context are the only clues an SEM analyst has for identification (Stanton and Finkelman, 1979). This limitation has so far prevented development of a clear picture describing the thermal regime where organic nanoporosity develops and the dominant type of OM it occurs in. For example, some workers have suggested that organic nanopores form from thermal cracking or shrinkage of primary kerogen (Jarvie et al., 2007; Loucks et al., 2009; Modica and Lapierre, 2012; Camp et al., 2013; Han et al., 2017), whereas others documented formation of organic nanoporosity in secondary solid bitumen (Bernard et al., 2012a, 2012b). Bernard et al. (2012b) suggested that organic nanoporosity only developed at higher maturities, whereas other researchers found no relation to thermal maturity (Fishman et al., 2012; Milliken et al., 2013), or observed organic nanoporosity in immature amorphous kerogen (Milliken et al., 2014). More recent work may suggest that a consensus is developing around the idea that organic porosity primarily forms in secondary catagenetic solid bitumen (Camp, 2015; Cardott et al., 2015; Milliken and Olson, 2017; Zhao et al., 2017) at oil window and higher maturities (Mastalerz et al., 2013; Chen and Xiao, 2014; Romero-Sarmiento et al., 2014; Pommer and Milliken, 2015; Chen and Jiang, 2016; Klaver et al., 2016; Ko et al., 2016; Yang et al., 2016; Liu et al., 2017), and the low abundance of organic pores in high-maturity shale dominated by terrestrial OM (Zhang et al., 2017) is consistent with the development of organic nanoporosity primarily in solid bitumen. These contradictory results among SEM studies of organic nanoporosity illustrate a need for improved approaches to the identification and characterization of OM in shale microstructural research.

Here we use correlative light and electron microscopy (CLEM) to create images of OM from several shale formations of North America. Images of OM from the same field of view (500× magnification) under white light, blue light, SE, and BSE conditions were created by transfer of the sample between microscope instruments, allowing comparisons of OM appearance under the separate imaging modalities. The objectives of the study were to show the benefits of a correlative microscopy approach to OM identification and characterization of organic catagenesis and microstructural development in shale reservoirs. The results illustrate the potential for misidentification of OM through sole reliance on SEM for shale microstructural characterization.

We used samples of varying thermal maturities from immature to overmature (Green River Mahogany Zone, Bakken Formation, Eagle Ford Group, Barnett Shale, Haynesville Formation, Ohio Shale [Lower Huron Member], Marcellus Formation, and Woodford Shale; Table 1). Samples were mounted into pellets using a thermoplastic resin and mechanically polished following ASTM D2797 (ASTM, 2015a). Samples were selected on the basis of previous studies that had provided organic petrology characterization and supporting information such as programmed pyrolysis and X-ray diffraction mineralogy data (Hackley et al., 2015; Hackley and Cardott, 2016). Using a Leica DM4000 microscope with an automated stage and LED illumination, the mosaic function of the DISKUS-FOSSIL software by Hilgers Technisches Buero was employed to capture maps of the entire sample pellet surface (100× magnification), as well as smaller scale regional maps (500×) to aid in navigation when transferring samples between optical and electron microscopes. Under the optical microscope (500×, oil immersion), fields of view that exhibited multiple OM types were captured using three conditions: (1) a grayscale image showing reflectance (%R_o) measured via ASTM D7708 (ASTM, 2015b) of OM types under white light conditions, (2) a color image under white light conditions, and (3) a color image under blue light fluorescence (organic fluorescence is extinguished at peak oil and higher thermal maturity conditions). Following optical microscopy, immersion oil was removed from the pellet surface with a cotton swab and remaining oil residues were removed with ethanol. After carbon coating, the same field of view was captured using a Hitachi SU-5000 FE-SEM at 500× (5 kV, spot intensity 10, working distance 5 mm) under SE and BSE conditions. Mean grayscale (mgs) values were measured to compare and contrast OM types from BSE images using ImageJ (version 1.50i) software (Schneider et al., 2012). Previous workers have used similar approaches to distinguish and identify OM types based on grayscale values to estimate OM and OM-hosted porosity (Song and Carr, 2016). Other applications have included using grayscale values from reflectivity of optical coherence tomography images (Garrido et al., 2014) or ultrasound sonograms (Harris-Love et al., 2016). As a result of changes in SEM brightness/contrast between samples, direct comparisons of measured grayscale values cannot be made (i.e., X grayscale value equals Y maceral type) and can only be used to compare relative changes within the same image. One of the samples imaged and discussed herein (Ohio Shale, Lower Huron Member) was broad-beam ion-milled prior to SEM analysis using an E. A. Fischione 1060 dual-beam SEM Mill at 6 kV, 2° incident angle, 175° rotation at 3 rpm, 50% focus for 30 min.

The organic maceral names employed herein primarily follow the nomenclature of the International Committee for Coal and Organic Petrology (ICCP). In short, the kerogen terms vitrinite (ICCP, 1998) and inertinite (ICCP, 2001) correspond to dominantly aromatic maceral groups derivative from terrigenous woody vegetation, whereas liptinite group macerals (Pickel et al., 2017) are derived from the relatively hydrogen-rich aliphatic component of terrigenous plants (exines and cuticles). The liptinite group also includes terms for oil-prone algal- and bacterial-derived kerogens. A classification for dispersed OM as it occurs in shale is available from Hackley and Cardott (2016) and includes both kerogen and its secondary conversion product (solid bitumen) formed during diagenesis and catagenesis. Herein, we identify pre- and post-oil solid bitumens as per the definitions of Curiale (1986) and Cardott et al. (2015), where pre-oil solid bitumen is recognized as an early (immature stage) diagenetic product from thermal conversion of oil-prone kerogen and post-oil solid bitumen is considered as forming from alteration of once liquid oil.

As an aid for SEM petrographers working in the identification and interpretation of OM in shales, the image sets collected and described in this work have been added to the U.S. Geological Survey (USGS) Organic Petrology Photomicrograph Atlas (USGS, 2011; Valentine et al., 2013) available from https://energy.usgs.gov/coal/organicpetrology/photomicrographatlas.aspx.

The Woodford Shale sample selected for this study contains very finely dispersed solid bitumen with scattered inertinite fragments (Figure 1A) similar to descriptions given by previous workers (Cardott et al., 2015; Curtis et al., 2012a). Thermal maturity is in the late condensate-wet gas window based on a solid bitumen reflectance of 1.35% SB R_o (Hackley and Cardott, 2016). The distinction between inertinite and solid bitumen is easily made with white light illumination on the optical microscope as solid bitumen has a lower mean reflectance (1.46% SB R_o) whereas mean inertinite reflectance is higher (2.91% Inert R_o) (Figure 1B). Distinctions in morphology can also be made relatively easily as solid bitumen occurs as finely dispersed void-filling forms and inertinite occurs as angular to subangular fragments with well-defined boundaries to the surrounding mineral matrix. However, under SE mode (Figure 1C) no differences can be noted other than the form of the blocky inertinite fragment. Typically, in shale and coal samples, inertinite will have higher relief than solid bitumen, but in this case, both OM types show no relief compared to the mineral matrix. Using BSE mode (Figure 1D) no observable differences can be seen between OM types with mean grayscale values (mgv) of 118.0 for solid bitumen and 117.4 for inertinite.

Organic petrographic descriptions of the immature Eocene Green River Mahogany Zone sample were reported in Hackley et al. (2015, 2017a). In general, the OM assemblage is dominated by amorphous organic matter (AOM) with sporadic occurrences of narrow and elongate solid bitumen from in situ kerogen conversion (pre-oil solid bitumen). Under white light illumination (Figure 2A), the distinction between AOM and solid bitumen is determined by the presence of a gray reflecting surface in solid bitumen compared to the dull, opaque surface of the AOM. Under blue light fluorescence (Figure 2B), AOM exhibits high-intensity yellow fluorescence whereas solid bitumen has a faint brown fluorescence. Under electron microscopy conditions (Figure 2C, D), the distinction between the OM types is extremely subtle. In BSE mode (Figure 2D), the contrast between the two can be more readily seen with the solid bitumen having a slightly higher grayscale (102.0 mgv) compared to the AOM matrix (90.4 mgv). However, without initial investigation using white light optical microscopy, the identification and extent of the solid bitumen could easily be missed.

Several SEM-based studies of the Haynesville Formation of Texas and Louisiana are available (Spain and McLin, 2013; Klaver et al., 2015) but little information has been published on its organic petrology. The high-maturity (1.68% SB R_o) Haynesville Formation sample we used contains finely dispersed void-filling solid bitumen in a mineral matrix that can be clearly differentiated using optical white light petrography (Figure 3A). Also found in this sample but not shown in the field of view contained in Figure 3 was terrestrial kerogen (i.e., vitrinite and inertinite). Using electron microscopy in both SE (Figure 3B) and BSE mode (Figure 3C), the OM is fairly easy to differentiate from the mineral matrix (i.e., low atomic weight signal). Note that the labeled solid bitumen at the top of the electron images does not exhibit an apparent void-filling character, and instead appears as a possible structured organic particle that may be misinterpreted as terrestrial kerogen. In this sample, the SE image is helpful, as vitrinite and inertinite (not shown in Figure 3) in the Haynesville Formation tended to have a higher surface relief compared to softer solid bitumen.

The organic petrology of the Bakken Formation has been studied by light microscopy for many years (Stasiuk, 1993, 1994; Stasiuk and Fowler, 2004), whereas more recent studies have applied SEM (Fishman et al., 2015; Zargari et al., 2015) or both SEM and light microscopy (Liu et al., 2018). Figure 4 (from Hackley et al., 2017a) illustrates the difficulty of discriminating multiple OM types in a single field of immature (0.32% SB R_o; Hackley and Lewan, 2018) Bakken Formation shale via SEM. The field contains (1) amorphous OM with moderate intensity yellow fluorescence; (2) solid bitumen with mean reflectance of 0.32% SB R_o and low-intensity red-brown fluorescence; and (3) two separate non-fluorescent inertinite fragments, both with reflectance >1.0% inert R_o. Under white light illumination (Figure 4A), all four are visible and can be separately identified; the mineral matrix contains void-filling, pre-oil solid bitumen and AOM throughout with the two inertinite fragments prominent. Blue light fluorescence (Figure 4B) further distinguishes solid bitumen from the AOM, as the AOM has brighter yellow fluorescence emission whereas the solid bitumen has low-intensity red-brown fluorescence. The BSE image (Figure 4D) shows that all of the OM has comparable or slightly negative relief compared to the mineral matrix with the exception of the high reflectance inertinite fragment (right), which has slight positive relief. No contrast or boundaries between solid bitumen, AOM, and the lower reflecting inertinite (left) can be observed with SE (Figure 4C). In BSE, the only contrast between macerals is a slightly lighter grayscale for the highest reflecting inertinite (76.5 mgv) adjacent to darker solid bitumen (68.4 mgv), but the other macerals are indistinguishable from one another (AOM, 69.8 mgv; lower reflectance inertinite, 71.5 mgv).

Classical organic petrology studies of the Marcellus Formation (Obermajer et al., 1996, 1997) have been updated by more recent SEM investigations (Milliken et al., 2013; Schieber, 2013; Gu et al., 2015). The image set in Figure 5 shows high-maturity Marcellus Formation shale with two populations of solid bitumen: (1) a lower reflecting (1.69% SB R_o), void-filling solid bitumen dispersed in the shale matrix and (2) a higher reflecting (2.22% SB R_o), isolated, void-filling type that is present in larger sized accumulations (Figure 5). The populations are difficult to distinguish under white light illumination (Figure 5A) but can be deciphered after collecting sufficient reflectance measurements (Figure 5B). It is possible that larger sized accumulations may show higher reflectance because their size allows a better polish. However, other interpretations include the following: (1) higher reflectance material is a post-oil solid bitumen generated from thermal alteration of once liquid oil, whereas the lower reflectance population is from kerogen converted in situ (remnant pre-oil solid bitumen); (2) variations in solid bitumen chemical composition are due to deasphalting because of preferential mineral adsorptions (differences in the mineral microenvironment) or gas migration (e.g., Shalaby et al., 2012); or (3) different water saturation levels at different locations in the tight shale reservoir during thermal maturation influenced the formation of different hydrocarbon products, ultimately resulting in different composition solid bitumens (e.g., Lewan, 1997). Under SE conditions (Figure 5C) all OM appears to have the same relief as the surrounding mineral matrix. In both SE and BSE (Figure 5D), there is no grayscale contrast between the two populations of solid bitumen, with 101.79 mgv for the lower reflectance population and 103.21 mgv for the higher reflectance population. Also note that the samples used in this study were embedded in a thermoplastic binder and that OM (i.e., labeled solid bitumen high R_o) on the edge of the rock fragment cannot be discriminated from the binder compound (102.39 mgv) using SE or BSE mode.

Organic petrology studies in the Eagle Ford Group include early work by Robison (1997), whereas more recent SEM studies have focused on porosity characterization (Anovitz et al., 2015; Pommer and Milliken, 2015; Ko et al., 2017). The image set from an overmature Eagle Ford Group sample is another example showing two populations of solid bitumen (Figure 6). Under white light conditions (Figure 6A), the interpreted migrated post-oil solid bitumen (2.54% SB R_o) is found to be in large linear bodies compared to the fine-grained matrix-dispersed or foraminifera-filling lower reflecting solid bitumen (1.97% SB R_o), interpreted as a pre-oil solid bitumen formed from local, in situ kerogen conversion. That is, we interpret the larger linear bodies of solid bitumen as remnants of migrated oil and the matrix-dispersed and foraminifera-chamber filling OM as relicts from pre-oil solid bitumen generated from local in situ kerogen conversion followed by short-distance migration as a viscous fluid flowing under overburden pressure into adjacent open foraminifera chambers. As described above for the Marcellus, alternate interpretations for origin of multiple solid bitumen populations also exist. Under SE and BSE conditions (Figure 6B, C), no distinction can be made between the two types of solid bitumen, with lower R_o solid bitumen having 93.53 mgv and higher R_o solid bitumen having 93.3 mgv. Also of note are small inertinite fragments surrounded by the higher reflecting post-oil solid bitumen. The slight positive relief of the inertinite fragments in the migrated solid bitumen under SE mode can be observed (Figure 6B), but in BSE mode no morphologic differences are apparent.

Landmark work in the Barnett Shale by Loucks et al. (2009) launched the study of organic porosity through SEM evaluation of ion-milled surfaces and subsequent studies have built on this frontier work (Bernard et al., 2012b; Romero-Sarmiento et al., 2014). Our Barnett Shale image set (Figure 7) further illustrates the difficulty of distinguishing vitrinite from solid bitumen using electron microscopy. Under optical white light conditions (Figure 7A), the vitrinite fragment has a slightly higher reflectance (1.82% vitrinite R_o) than the solid bitumen (1.74% SB R_o, measurement not shown in Figure 7B), which overlaps with the upper limit of the range of measured solid bitumen reflectance values for this sample (1.2–1.9% SB R_o; mean value of 1.57% SB R_o, Table 1). Solid bitumen was observed as having a thin wispy void-filling form (i.e., filling in and along mineral grain boundaries), whereas the vitrinite fragment has a well-defined and sharp delineation from the surrounding mineral matrix. For example, the lower portion of the vitrinite fragment ends in an angular termination without being defined by a surrounding mineral grain. The vitrinite fragment also has an even to slight positive relief compared to solid bitumen, which may account for why it is not as well-polished (i.e., scratches are visible on the vitrinite surface). No differences between solid bitumen (112.10 mgv) and vitrinite (111.46 mgv) can be made using electron microscopy (Figure 7C, D), except for possibly noting the form differences between the two OM fragments. However, conclusive identification of the two OM types would be difficult without the supporting reflectance data.

The OM of the Ohio Shale, Lower Huron Member is dominated by solid bitumen with lesser amounts of inertinite and telalginite such as Tasmanites (Hackley et al., 2017b). The immature Lower Huron sample we imaged shows three different types of OM in one field of view (Figure 8). Under white light optical illumination (Figure 8A), the inertinite macerals appear as subangular to subrounded isolated fragments with slight positive relief and high reflectance. Solid bitumen has a low gray reflecting surface filling around mineral grains. Alginite in Figure 8A is a thin, wisplike kerogen with low reflectance and no contrast to the mineral matrix. Under blue light fluorescence (Figure 8B), telalginite is clearly recognizable with bright yellow fluorescence whereas solid bitumen has low-intensity dull orange-brown fluorescence colors. With electron microscopy (Figure 8C, D), no clear distinguishing features can be used to identify or separate any of the maceral types except for possibly the distinctive morphology of the Tasmanites fragments. Even the inertinite macerals are difficult to distinguish as they do not show any arc- or bogenlike structures, and because of ion milling, they have lost the positive relief typically found in mechanically polished samples. An evaluation of mgs values showed that on average the inertinites had the highest mgs (mean 116.9 mgs), followed by solid bitumen (mean 111.1 mgs) and telalginite (mean 108.7 mgs), but the ranges in grayscale values (gv) significantly overlap (inert: 90–147 gv; solid bitumen: 88.5–132.3 gv; and telalginite: 86.9–130.4 gv).

Previous efforts to identify OM in shale by SEM focused on processing of SEM photomicrographs to distinguish OM types as depositional (kerogen) or migrated (solid bitumen, pyrobitumen) using the form/shape of the OM, pore size/textures/shape, and the examination of adjacent mineral cementation to determine origin (Loucks and Reed, 2014; Yang et al., 2016). Canter et al. (2016) used a similar approach wherein primary (kerogen) or secondary (solid bitumen) origin of shale OM was assigned based on morphology. Camp (2017) suggested limiting SEM identification of OM to three main categories: (1) structured, (2) amorphous, and (3) void-filling, where the term “void-filling” is restricted for clear cases of OM filling cavities, microfractures, and mineral-cement lined pores. However, authigenic euhedral mineral terminations (typically used to infer void-filling textures) can protrude into both AOM (original sedimentary kerogen) and solid bitumen (Hackley et al., 2017a). That is, the formation of authigenic cementing minerals such as dolomite occurs contemporaneous with kerogen modification, creating euhedral crystal terminations that embay amorphous primary sedimentary OM. This observation could suggest that replacement or removal of nonmobile sedimentary kerogen occurs during organic catagenesis and diagenetic mineral growth, and that void-filling textures observed by SEM do not necessarily imply migration of a mobile secondary OM phase into open void spaces. Therefore, these initial efforts to provide guidelines for SEM identification of shale OM (Loucks and Reed, 2014; Canter et al., 2016; Yang et al., 2016; Camp, 2017), while important steps forward do not provide a foolproof method for accurate identification. Through a correlative approach, as described in this chapter, the use of optical and SEM methods at 500× allows researchers the ability to identify OM and understand the OM compositional character of a shale sample before evaluating the nanoscale properties.

An SEM study by Cardott and Curtis (2017) examined coal samples using low accelerating voltages (1–2 kV), resulting in low grayscale contrast (BSE) between macerals (individual organic entities), making identification difficult. Higher accelerating voltages (10 kV) yielded higher contrast between maceral groups (the kerogens vitrinite, inertinite, and liptinite; see definitions below), with some ability to distinguish maceral subgroups (telovitrinite vs. detrovitrinite) or even individual macerals (sporinite vs. cutinite). Cardott and Curtis (2017) also found that identification based solely on grayscale contrast between inertinite macerals (semifusinite, fusinite, macrinite) was difficult unless the maceral had bogen (cellular) structure (fusinite vs. semifusinite), and this also extended to the identification of inertinite vs. vitrinite in shale samples, where little to no grayscale contrast between vitrinite and inertinite was observed. Although this work is also a significant step forward, the results primarily are applicable to organic-rich coal matrices (organic carbon typically >80 vol. %), whereas OM in shale typically is <10 vol. % and generally occurs dispersed as fine fragments ~5 to 10 μm in size.

Liu et al. (2017) used traditional optical microscopy accompanied by high-magnification SEM of the same fields (CLEM) to characterize the development of organic porosity with increasing thermal maturity in different types of OM. This helped identify development of secondary nm-scale organic pores in solid bitumen and alginite during thermal maturation into the oil window, and the increasing abundance of these organic pores at higher gas window thermal maturity, thus illustrating the potential for careful CLEM work to elucidate the processes of organic porosity development. Studies such as this, where the same fields are examined with both light and electron microscopy, are necessary for further advances.

Hackley et al. (2017a) utilized an integrated correlative light and electron microscopy (iCLEM) approach to conclusively identify OM in shale wherein low magnification (500×) fluorescence microscopy was followed sequentially in the same instrument by high resolution (>10,000×) evaluation with SEM. Although this approach worked for OM identification in low-maturity shale, it has not yet been applied to peak oil window and higher maturity samples where organic porosity typically is well-developed (Ko et al., 2016). Moreover, the instrumentation for iCLEM is not widely available, and analysis of higher maturity samples will require expensive sample preparation as thin foils (e.g., Bernard et al., 2012b). Nevertheless, the potential for iCLEM to sequentially identify OM at low resolution and then provide nanoporosity characterization at ultrahigh resolution suggests that it could become an important future tool for shale microstructure evaluation.

Our image sets discussed herein illustrate the difficulties encountered in identification of shale OM using electron microscopy alone. Most source rock SEM-based work focuses on the characterization of OM-hosted porosity in thermally mature samples (Cardott et al., 2015; Milliken and Olson, 2017; Zhao et al., 2017), indicating that documenting the formation of solid bitumen during diagenesis-catagenesis is important in better understanding the early evolution of source rocks. The conversion of oil-prone kerogen and early emplacement and local migration of solid bitumen are illustrated in our low-maturity source rock sample sets (Bakken Formation, Green River Mahogany Zone, Huron Shale) and demonstrate the importance of accurate OM identification (Figures 2, 4, 8). For example, in the Bakken image set (Figure 4), with the exception of the arclike structure of the inertinite fragment (right side of the image), the OM could be easily misinterpreted as solid bitumen in SEM because most of it has neutral to negative relief and appears to be void-filling. The same could be said for the Ohio Shale image set (Figure 8), where inertinites could be misidentified as they lack bogen-structures, and only one of the labeled alginite macerals (top of image) shows a well-preserved, uncompacted shape parallel to bedding. In contrast, the Green River Mahogany Zone image set (Figure 2) does show some subtle grayscale contrast between AOM and solid bitumen under SE and BSE. This may be because the majority of the field of view is OM and the threshold conditions could be better optimized to bring out the compositional differences between the two OM types. However, without optical characterization prior to SEM, the subtle grayscale contrast could be missed. Each of these examples illustrates the potential to misidentify OM in immature to early mature shale during SEM-based nanostructural characterization. Even with optical microscopy, conclusive OM identification in immature and early mature shale typically requires the use of both white and blue light illumination sources.

The higher thermal maturity samples (Woodford Shale, Haynesville Formation, Marcellus Formation, Barnett Shale, and Eagle Ford Formation) have the same complexity in terms of distinguishing secondary OM (i.e., solid bitumen) from terrigenous OM. In these samples, the oil-prone kerogen (i.e., AOM, telalginite) has been converted into solid bitumen during organic catagenesis (Figures 1, 3, 5, 6, 7). Use of OM form and relief can aid in the identification of possible woody terrigenous OM (Loucks and Reed, 2014; Yang et al., 2016), but the use of correlative light microscopy is necessary for conclusive identification. Here, the correct identification of OM is critical when trying to understand organic nanoporosity development. For example, in both the Marcellus Formation and the Eagle Ford Formation image sets (Figures 5, 6), the bulk of the OM present is a lower reflectance solid bitumen, with lesser amounts of higher reflectance solid bitumen and inertinite. As the electron images show, there is no contrast between the two populations of solid bitumen and very little contrast between solid bitumen and inertinite. If organic nanoporosity occurs in different proportions in the two secondary OM populations, their correct identification will have a significant impact on porosity estimates and improved understanding of their formation processes. Relying solely on an SEM approach for characterization of OM in these examples ultimately will result in puzzling outcomes such as that reported by Curtis et al. (2012a), where organic nanoporosity was shown to be well-developed in an OM fragment immediately adjacent to a fragment with no porosity.

The CLEM approach described in this chapter demonstrates the difficulty of identifying OM exclusively with SEM SE and BSE image approaches. Without correlative optical microscopy of the same fields of view, mistakes from misidentification of OM using SEM will continue to hinder interpretations of OM characteristics and obscure findings from nanoscale observation of shale samples. Therefore, CLEM approaches will aid understanding of hydrocarbon generation, migration, storage and expulsion processes in shale petroleum systems. As correlative imaging techniques continue to improve and with advances in SEM technology (i.e., low-voltage microscopy, low-pressure/environmental modes, iCLEM/SECOM), electron microscopy will play a role of increasing importance in the evaluation and microstructural characterization of shale hydrocarbon reservoirs.

Reviews by Wayne Camp, Andy Pepper, Brian Cardott, and Harvey Belkin improved this chapter. This research was funded by the USGS Energy Resources Program. Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the U.S. government.