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ABSTRACT

Organic matter (OM) in petroleum source rocks is a mixture of organic macerals that follow their own specific evolutionary pathways during thermal maturation. Understanding the transformation of each maceral into oil and gas with increasing thermal maturity is critical for both source rock evaluation and unconventional shale oil/gas reservoir characterization. In this study, organic petrology was used to document the reflectance, abundance, color, and fluorescence properties of primary organic macerals and solid bitumen (SB) in 14 Upper Devonian New Albany Shale samples (kerogen type II sequence) from early mature (vitrinite reflectance [VRo] of 0.55%) to post-mature (VRo 1.42%). Micro-Fourier transform infrared (micro-FTIR) spectroscopy analyses were conducted on these samples to derive information on the evolution of the chemical structure of organic macerals and SB with increasing thermal maturity.

Primary OM (amorphous organic matter, alginite, vitrinite, and inertinite) and secondary organic matter (SB) were identified in early mature samples. Amorphous organic matter (AOM) was the dominant organic component in early mature samples and was observed up to the maturity equivalent to VRo 0.79% but could not be identified at VRo 0.80%. An organic network composed of AOM and SB was observed from VRo 0.55 to 0.79%, which, together with the decrease in AOM content being accompanied by an increase in SB content, suggests that with the onset of petroleum generation, SB gradually replaced the original AOM. Alginite, represented by Tasmanites cysts, started to transform to pre-oil bitumen at a maturity corresponding to VRo 0.80%. It shows weak orange-yellow fluorescence at this maturity, a change from strong greenish-yellow fluorescence in early mature samples. Alginite could not be identified at VRo 0.89%, and generated bitumen remained in place or migrated over short distances. Petrographic observations and micro-FTIR study of alginite indicate that substantial hydrocarbon generation from alginite does not start until alginite is completely transformed to pre-oil bitumen. In contrast to AOM and alginite, vitrinite and inertinite derived from terrestrial woody materials occur as dispersed particles and do not change significantly during thermal maturation.

A linear relationship between vitrinite and SB reflectance exists for the studied samples. The reflectance of vitrinite is higher than that of SB until VRo 0.99%, and at higher maturities, SB reflectance exceeds vitrinite reflectance. The inclusion of pre-oil SB converted from alginite in reflectance measurements could result in a lower average SB reflectance and, therefore, caution should be applied when using SB reflectance as an indicator of thermal maturity.

INTRODUCTION

Organic matter quantity, type, and thermal maturity are key parameters in source rock evaluation and unconventional shale oil/gas reservoir characterization (Tissot and Welte, 1984; Peters and Cassa, 1994; Jarvie, 2012a, b). Sedimentary OM can be transformed into oil and gas during thermal maturation, and residual porous organic carbon can retain oil and gas (McAuliffe, 1979; Pepper, 1991; Pepper and Corvi, 1995; Jarvie et al., 2007; Han et al., 2015). Organic pores are an important constituent of the pore system in thermally mature organic-rich shales (Loucks et al., 2009; Wang and Reed, 2009; Passey et al., 2010; Schieber, 2010; Slatt and O’Brien, 2011). The gas content of shale reservoirs is largely controlled by total organic carbon (TOC) content in organic-rich shale gas systems (Ross and Bustin, 2009; Wang and Reed, 2009; Strąpoć et al., 2010; Hao et al., 2013; Fan et al., 2014). Besides providing space for storage, OM pore systems in source rocks can also work as pathways for oil and gas migration (McAuliffe, 1979; Stainforth and Reinders, 1990; Collell et al., 2015). Documenting OM transformation during thermal maturation and associated organic pores development is important for shale oil/gas prospecting and tight shale reservoir characterization.

Organic matter in petroleum source rocks can be classified into four principal types of kerogens (kerogen type I, II, III, and IV) based on atomic H/C (hydrogen to carbon) vs. O/C (oxygen to carbon) ratios or hydrogen index vs. oxygen index derived from Rock-Eval pyrolysis (Tissot et al., 1974; Peters and Cassa, 1994). Kerogen types can to some degree be correlated to organic macerals in thermally immature source rocks and coals (Tissot et al., 1974; Peters and Cassa, 1994). Alginite (oil-prone maceral) derived from algal bodies (e.g., Botryococcus, Tasmanites, and Leiosphaeridia) has very high hydrocarbon generation potential and generally represents type I kerogen (Tissot et al., 1974; Peters and Cassa, 1994). Amorphous organic matter (oil-prone maceral, also classified as bituminite or amorphinite; Kus et al., 2017) derived from physiochemical or microbial degradation of phytoplankton has medium to high hydrocarbon generation potential and can be either type I or II kerogen (Peters and Cassa, 1994). Vitrinite (gas-prone maceral) derived from terrestrial higher plants has low to medium (if hydrogen-rich) hydrocarbon generation potential and is chemically defined as type III kerogen (Tissot et al., 1974; Peters and Cassa, 1994). Inertinite derived from oxidized or burned terrestrial woody materials has no hydrocarbon generation potential and typically corresponds to type IV kerogen (Peters and Cassa, 1994). Theoretically, each thermally immature source rock or coal contains a mixture of organic macerals and shows variations in the proportions of macerals within a formation, which could be controlled by depositional environments and diagenetic alterations (Tyson, 1995; Schieber, 2001; Stasiuk and Fowler, 2004).

Different types of kerogens or organic macerals follow specific evolutionary pathways during thermal maturation (Tissot et al., 1974; Mastalerz and Bustin, 1993; Peters and Cassa, 1994; Waples and Marzi, 1998; Jarvie and Lundell, 2001). The temperature that is required to generate petroleum from kerogens increases in the following order: II-S < II < I < III (Horsfield and Rullkötter, 1994; Jarvie and Lundell, 2001; Petersen, 2006; Schimmelmann et al., 2006), but the transformation rate of type I kerogen is faster than that of type II and III kerogens when it reaches the required temperature, that is, the distribution of activation energy of type I kerogen is concentrated within a small range (Peters et al., 2006). The mixing of organic macerals in varying proportions in thermally immature and early mature source rocks within a formation can, therefore, cause uncertainty when evaluating source rocks using Rock-Eval pyrolysis.

Oil and gas generated from oil-prone kerogens are partially retained in organic-rich source rocks (McAuliffe, 1979; Pepper, 1991; Pepper and Corvi, 1995; Jarvie et al., 2007; Han et al., 2015). For example, Jarvie et al. (2007) studied the thermal evolution of OM in the Mississippian Barnett Shale and suggested that about 40% of organic carbon in generated hydrocarbons was retained in the Barnett Shale. Oil and gas converted from kerogen in source rocks can migrate through the inorganic as well as organic pore networks (McAuliffe, 1979; Stainforth and Reinders, 1990; Pepper and Corvi, 1995; Collell et al., 2015).

Scanning electron microscope (SEM) observations of argon ion-milled surfaces enabled the examination of nanometer-scale OM-hosted pores in shales (e.g., Loucks et al., 2009; Schieber, 2010, 2013; Sondergeld et al., 2010; Slatt and O’Brien, 2011; Loucks et al., 2012; Milliken et al., 2013; Schieber et al., 2016). SEM imaging, however, cannot readily differentiate between types of OM (Camp, 2016b; Hackley and Cardott, 2016). Correlative microscopy (light and electron microscopy) enables the examination of organic pores in specific OM particles (Camp, 2016b; Hackley et al., 2017a; Liu et al., 2017), which cannot be accomplished using SEM alone. For example, Liu et al. (2017) studied organic pores in the New Albany Shale using combined SEM and reflected light petrography and concluded that primary organic pores were inertinite hosted and secondary organic pores were SB hosted.

The goal of this investigation is to study the evolution of organic macerals and SB during the thermal maturation in organic-rich shales. Specific objectives are to (1) document the transformation of oil-prone macerals (AOM and alginite) to petroleum and bitumen during thermal maturation; (2) document the reflectance, abundance, color, and fluorescence properties of organic macerals (AOM, alginite, vitrinite, and inertinite) and SB at differing levels of thermal maturity; and (3) characterize the evolution of the chemical structure of organic macerals and SB during thermal maturation via micro-FTIR.

METHODS AND MATERIALS

The Upper Devonian New Albany Shale of the Illinois Basin is an organic-rich formation (TOC ranging from less than 1 to 20 wt. %; Chou et al., 1991), composed of variably carbonaceous shales with indications of bottom-current activity, multiple styles and intensities of bioturbation and subdividable into four depositional sequences (Lineback, 1968; Cluff, 1980; Beier and Hayes, 1989; Schieber and Lazar, 2004; Lazar, 2007; Lazar et al., 2015). It occurs in southern Illinois, southwestern Indiana, and western Kentucky and spans a wide range of thermal maturity from immature to post-mature corresponding to vitrinite reflectance (VRo) of 1.5% (Strąpoć et al., 2010; Mastalerz et al., 2013). Kerogen typing based on Rock-Eval pyrolysis has identified OM in the New Albany Shale as type II kerogen (Chou et al., 1991; Akar et al., 2015). Petrographically, OM in the New Albany Shale is a mixture of different macerals, including AOM, alginite, vitrinite, and inertinite as well as SB (Mastalerz et al., 2012, 2013; Wei et al., 2016; Liu et al., 2017).

Fourteen New Albany Shale samples spanning a maturity range from early mature (VRo 0.55%) to post-mature (VRo 1.42%) were collected for this study (Figure 1; Table 1). Samples from Indiana and Kentucky and sample ILL-1 from Wayne County, Illinois, are core samples, and samples from Hicks Dome, Illinois, are outcrop samples. Unweathered hard samples were collected in the field and sealed immediately with plastic bags to prevent contamination. Because OM was the main focus, only black shales having high OM content were selected for this study.

Figure 1.

Map showing the locations of sampling sites and the extent of the New Albany Shale. Adapted from Mastalerz et al. (2013).

Figure 1.

Map showing the locations of sampling sites and the extent of the New Albany Shale. Adapted from Mastalerz et al. (2013).

Table 1.

Sample location, type, total organic carbon (TOC) content, vitrinite reflectance (VRo), SB reflectance (BRo), maturity stage, alginite fluorescence, and organic petrographic composition of shale samples.

SampleLocationSample typeDepth (m)TOC (wt. %)VRo (%)BRo (%)Maturity stageAlginite fluorescenceOrganic petrographic composition (vol. %, on mineral-matter-free basis)
AOMALLPDSBIV
IND-1Daviess Co., INCore545.310.770.550.35Early matureGreenish-yellow64.919.04.63.37.40.7
IND-2Daviess Co., INCore539.812.10.570.36Early matureGreenish-yellow51.731.03.88.23.41.9
IND-3Daviess Co., INCore537.110.60.630.45Early matureGreenish-yellow58.224.83.37.55.11.2
IND-4Pike Co., INCore852.88.40.730.53Middle matureYellow29.067.91.41.00.60.2
IND-5Gibson Co., INCore1218.34.50.790.58Middle matureOrange-yellow28.220.51.248.51.10.5
KY-1Webster Co., KYCore915.96.260.800.62Middle matureOrange-yellow016.52.368.112.50.6
KY-2Crittenden Co., KYCore791.05.20.840.64Middle matureWeak orange013.10.684.71.00.6
KY-3Livingston Co., KYCore180.44.80.890.77Middle matureNo alginite00091.37.90.8
KY-4Crittenden Co., KYCore858.06.10.980.91Middle matureNo alginite00097.62.00.4
ILL-1Wayne Co., ILCore1606.95.41.011.00Middle matureNo alginite00096.82.40.8
ILL-2Hicks Dome, ILOutcrop 7.11.051.13Middle matureNo alginite00098.61.00.4
ILL-3Hicks Dome, ILOutcrop 6.61.111.25Middle matureNo alginite00094.25.00.8
ILL-4Hicks Dome, ILOutcrop 7.61.181.33Late matureNo alginite00098.21.10.7
ILL-5Hicks Dome, ILOutcrop 2.581.421.71Post-matureNo alginite00097.22.30.6
SampleLocationSample typeDepth (m)TOC (wt. %)VRo (%)BRo (%)Maturity stageAlginite fluorescenceOrganic petrographic composition (vol. %, on mineral-matter-free basis)
AOMALLPDSBIV
IND-1Daviess Co., INCore545.310.770.550.35Early matureGreenish-yellow64.919.04.63.37.40.7
IND-2Daviess Co., INCore539.812.10.570.36Early matureGreenish-yellow51.731.03.88.23.41.9
IND-3Daviess Co., INCore537.110.60.630.45Early matureGreenish-yellow58.224.83.37.55.11.2
IND-4Pike Co., INCore852.88.40.730.53Middle matureYellow29.067.91.41.00.60.2
IND-5Gibson Co., INCore1218.34.50.790.58Middle matureOrange-yellow28.220.51.248.51.10.5
KY-1Webster Co., KYCore915.96.260.800.62Middle matureOrange-yellow016.52.368.112.50.6
KY-2Crittenden Co., KYCore791.05.20.840.64Middle matureWeak orange013.10.684.71.00.6
KY-3Livingston Co., KYCore180.44.80.890.77Middle matureNo alginite00091.37.90.8
KY-4Crittenden Co., KYCore858.06.10.980.91Middle matureNo alginite00097.62.00.4
ILL-1Wayne Co., ILCore1606.95.41.011.00Middle matureNo alginite00096.82.40.8
ILL-2Hicks Dome, ILOutcrop 7.11.051.13Middle matureNo alginite00098.61.00.4
ILL-3Hicks Dome, ILOutcrop 6.61.111.25Middle matureNo alginite00094.25.00.8
ILL-4Hicks Dome, ILOutcrop 7.61.181.33Late matureNo alginite00098.21.10.7
ILL-5Hicks Dome, ILOutcrop 2.581.421.71Post-matureNo alginite00097.22.30.6

AOM = amorphous organic matter; AL = alginite; LPD = liptodetrinite; SB = solid bitumen; I = inertinite; V = vitrinite.

Vitrinite reflectance (VRo) and SB reflectance (BRo) of shale samples were measured on polished whole-rock pellets, and 50 measurements were taken per sample. Quantitative organic petrographic compositions were determined using a point-counting method, with 500 points counted only on OM. The occurrence, color, and fluorescence properties of organic macerals and SB were documented using a reflected-light microscope (Leica DFC310 FX) with oil immersion. The TOC content of samples was measured using a LECO® analyzer (SC832DR).

Micro-FTIR analysis of OM at varying levels of thermal maturity was conducted using a Nicolet 6700 spectrometer connected to a Nicolet Continuum microscope operated in reflectance mode. The objective used for micro-FTIR analysis was a 15 × IR objective. Micro-FTIR spectra were obtained at a resolution of 4 cm−1, collecting 400 scans per sample and using a gold plate as background. The wavenumber of spectra ranges from 650 to 4000 cm−1. Details about instrumentation and spectra processing have been described in Chen et al. (2012). Micro-FTIR spectra were collected only on alginite (Tasmanites cysts) and SB because of their relatively large size (>25 μm). For samples that contain more than one alginite or SB particles large enough for collecting spectra, several spectra of alginite or SB were collected and subsequently averaged into one spectrum using the OMNIC program.

RESULTS

Petrographic Composition of Organic Matter

Organic matter in the New Albany Shale is a mixture of organic macerals. Primary OM (AOM, alginite, vitrinite, and inertinite) and secondary OM (SB) were observed in all the early mature samples, and they evolve at different rates with increasing thermal maturity. Amorphous organic matter is the dominant OM in early mature samples, accounting for ~60% of total OM (Table 1). Alginite (represented by Tasmanites cysts) is second to AOM, accounting for ~20% of total OM (Table 1). Sample IND-4 has extremely high alginite content (67.89%), which explains the comparatively low SB content relative to samples dominated by AOM because alginite matures later than AOM in the New Albany Shale (Liu et al., 2017). Amorphous organic matter and alginite were not observed at thermal maturities higher than VRo 0.80 and 0.89%, respectively (Figure 2A, B). SB is the dominant OM at maturities above VRo 0.80%. The stage when the SB content increases significantly coincides with a strong increase in the thermal degradation of AOM and alginite to bitumen and petroleum (Figure 2C), corresponding to the peak-oil-window maturity (VRo 0.8−1.0%). Vitrinite and inertinite derived from terrestrial woody materials are present in minor amounts in all samples. The proportion of terrestrial OM is commonly less than 10% (Figure 2D). There is a slight decrease in the terrestrial OM content with increasing maturity (Figure 2D). A potential explanation for this could be that little terrestrial OM was transported to the depocenter (coinciding with the highest maturity). An alternative explanation is that some more reactive vitrinite was also thermally transformed during thermal maturation.

Figure 2.

Graphs showing the evolution of organic petrographic compositions of shale samples with increasing thermal maturity. (A) Amorphous organic matter. (B) Alginite. (C) Solid bitumen. (D) Inertinite + vitrinite.

Figure 2.

Graphs showing the evolution of organic petrographic compositions of shale samples with increasing thermal maturity. (A) Amorphous organic matter. (B) Alginite. (C) Solid bitumen. (D) Inertinite + vitrinite.

Amorphous Organic Matter

Amorphous OM in source rocks refers to structureless OM derived from degraded phytoplankton, macrophyte tissues, higher plant resins, and AOM of bacterial origin (Tyson, 1995; Pacton et al., 2011; Kus et al., 2017). In the New Albany Shale, AOM dominates OM in the early mature samples and forms an OM network within the matrix. Amorphous OM was observed up to VRo 0.79%. Beyond this maturity level, AOM has been completely converted to petroleum and SB.

Amorphous OM occurs as organic streaks parallel to the bedding plane (Figure 3A–C, E, G, H). It is dark gray, brown to black in reflected white light (oil immersion) and does not show fluorescence under blue-light irradiation in most cases (Figure 3D). In places, AOM shows weak greenish-yellow fluorescence (Figure 3F), suggesting that AOM might have originated from degraded algal bodies. Amorphous OM commonly has small mineral inclusions (Figure 3A–C, E, G, H), whereas SB has a more homogenous appearance (Figure 3C).

Figure 3.

Photomicrographs of AOM in reflected white light and oil immersion (A−C, E, G−H) and fluorescence mode (D, F). AOM = amorphous organic matter; AL = alginite; V = vitrinite; I = inertinite; SB = solid bitumen.

Figure 3.

Photomicrographs of AOM in reflected white light and oil immersion (A−C, E, G−H) and fluorescence mode (D, F). AOM = amorphous organic matter; AL = alginite; V = vitrinite; I = inertinite; SB = solid bitumen.

Alginite

Alginite is represented by Tasmanites algal bodies, a type of unicellular green algae that belong to the class Prasinophyceae (Tappan, 1980; Vigran et al., 2008; Dutta et al., 2013). Tasmanites algae are known for their abundance in the Tasmanite oil shale from Tasmania, Australia (Revill et al., 1994), and they are also very common in Devonian black shales of the United States (Schieber, 1996; Schieber et al., 2000; Schieber and Baird, 2001). Alginite derived from Tasmanites cysts has very high hydrocarbon generation potential (Dutta et al., 2013); its hydrogen index can be more than 900 mg HC/g TOC (Revill et al., 1994; Vigran et al., 2008).

Alginite appears to be brown amber colored and translucent in reflected white light and oil immersion and shows strong greenish-yellow fluorescence in early mature samples (Figure 4A–D). With increasing maturity, alginite changes to a dark amber color and its fluorescence changes from greenish-yellow to orange-yellow and then orange until VRo 0.84% is reached (Figure 4). Tasmanites cysts generally occur as compacted algal bodies (Figure 4C, E, G), some of which are filled with minerals (Figure 4A, I).

Figure 4.

Photomicrographs of alginite derived from Tasmanites cysts in reflected white light and oil immersion (A, C, E, G, I) and the same fields in fluorescence mode (B, D, F, H, J). AOM = amorphous organic matter; AL = alginite.

Figure 4.

Photomicrographs of alginite derived from Tasmanites cysts in reflected white light and oil immersion (A, C, E, G, I) and the same fields in fluorescence mode (B, D, F, H, J). AOM = amorphous organic matter; AL = alginite.

Alginite could no longer be recognized at VRo 0.89% and above, suggesting that by that point, it has been completely transformed to pre-oil bitumen and petroleum. Pre-oil bitumen (bitumen before oil generation; Curiale, 1986) converted from alginite can still show very weak orange fluorescence (Figure 5).

Figure 5.

Photomicrographs of pre-oil bitumen converted from alginite in reflected white light and oil immersion (A) and the same field in fluorescence mode (B). The pre-oil bitumen still shows weak orange fluorescence.

Figure 5.

Photomicrographs of pre-oil bitumen converted from alginite in reflected white light and oil immersion (A) and the same field in fluorescence mode (B). The pre-oil bitumen still shows weak orange fluorescence.

The transformation of alginite to pre-oil bitumen generally starts at a maturity of VRo 0.80%. However, alginite can undergo thermal transformation at lower maturities. For example, one alginite particle in sample IND-2 (VRo 0.57%) is in the process of transforming to pre-oil bitumen (Figure 6). The lower part of the alginite is darker, and the fluorescence is more brownish than the upper part of the alginite (Figure 6B). The pre-oil bitumen to the right of the alginite is probably transformed from an alginite and shows no fluorescence (Figure 6). The apparent transformation of alginite to pre-oil bitumen at differing levels of thermal maturity might be a result of different algae species.

Figure 6.

Photomicrographs of early-transformed alginite and pre-oil bitumen in reflected white light and oil immersion (A), and the same field in fluorescence mode (B) in sample IND-2 (VRo 0.57%). AL, alginite.

Figure 6.

Photomicrographs of early-transformed alginite and pre-oil bitumen in reflected white light and oil immersion (A), and the same field in fluorescence mode (B) in sample IND-2 (VRo 0.57%). AL, alginite.

Terrestrial Organic Matter

Terrestrial OM includes vitrinite and inertinite in this study, both of which are derived from vascular land plants (Stach et al., 1982). Vitrinite and inertinite occur in minor amounts in the studied samples (Table 1). The reflectance of vitrinite (VRo) is used to indicate the thermal maturity of shale samples (Teichmüller, 1971; Stach et al., 1982) and, in our samples, is lower than the associated inertinite reflectance. Both vitrinite and inertinite occur as discrete particles and do not show significant changes in morphology over the course of thermal maturation (Figure 7).

Figure 7.

Photomicrographs of vitrinite (A, C) and inertinite (B, D) in reflected white light and oil immersion. V = vitrinite; I = inertinite. Inertinite in panel B and D shows cellular pores (red arrows).

Figure 7.

Photomicrographs of vitrinite (A, C) and inertinite (B, D) in reflected white light and oil immersion. V = vitrinite; I = inertinite. Inertinite in panel B and D shows cellular pores (red arrows).

Solid Bitumen

As defined by organic petrographers (Jacob, 1989; Mastalerz et al., 2018), SB is a secondary OM that originated from oil-prone macerals, whereas the organic geochemical definition of bitumen is the organic component that can be extracted with organic solvents (Durand, 1980). In this study, the organic petrographic definition of SB is used, meaning secondary OM, including pre-oil bitumen and post-oil bitumen (Curiale, 1986; Bernard et al., 2012; Loucks and Reed, 2014; Mastalerz et al., 2018).

Solid bitumen occupies interparticle space between mineral grains (e.g., quartz, carbonates, and clay minerals) in the studied samples (Figure 8). It does not show fluorescence at any maturity level except for pre-oil bitumen generated from alginite (Figures 5, 6). The reflectance of SB increases, and the size of SB particles generally decreases with increasing maturity (Figure 8). SB size ranges from less than 1 to greater than 50 μm in the early and mid-mature samples, whereas SB is commonly smaller than 20 μm in the late and post-mature samples (Figure 8). The “cement characteristics” of SB (Figure 8) indicates that SB was mobile within the matrix in the oil window and probably even in the gas window.

Figure 8.

Photomicrographs of SB in reflected white light and oil immersion. SB occupies interparticle space between mineral grains (e.g., quartz, carbonates, and clay minerals). SB in the early (A−B) and mid-mature (C−F) samples is approximately 50 μm in size, whereas SB in late (G) and post-mature (H) samples is typically smaller than 20 μm. SB = solid bitumen.

Figure 8.

Photomicrographs of SB in reflected white light and oil immersion. SB occupies interparticle space between mineral grains (e.g., quartz, carbonates, and clay minerals). SB in the early (A−B) and mid-mature (C−F) samples is approximately 50 μm in size, whereas SB in late (G) and post-mature (H) samples is typically smaller than 20 μm. SB = solid bitumen.

Pre-oil bitumen is defined as bitumen formed before the onset of hydrocarbon generation (Curiale, 1986). It was observed in the samples of early and middle maturity but not in the late and post-mature samples (Figure 9). Pre-oil bitumen is completely black in reflected white light and oil immersion (Figure 9).

Figure 9.

Photomicrographs of pre-oil bitumen (A−B) in reflected white light and oil immersion. The morphology and occurrence of the pre-oil bitumen in panel (B) are similar to those of the alginite in Figure 4.

Figure 9.

Photomicrographs of pre-oil bitumen (A−B) in reflected white light and oil immersion. The morphology and occurrence of the pre-oil bitumen in panel (B) are similar to those of the alginite in Figure 4.

Relationship Between Vitrinite and Solid Bitumen Reflectance

The reflectance values of vitrinite and SB of the studied samples are shown in Table 1. The linear regression relationship between measured vitrinite and SB reflectance is expressed by the following equation: VRo = 0.5992 × BRo + 0.3987, with a coefficient of determination R2 = 0.9775 (Figure 10). The measured vitrinite reflectance values are very close to those obtained with the empirical equation of Jacob (1989), but 0.12−0.52% and 0−0.44% lower than those obtained based on the empirical equations from Landis and Castaño (1995) and Schoenherr et al. (2007), respectively, with greater differences in high-maturity samples (Figure 10). The measured vitrinite reflectance is higher than SB reflectance until VRo 0.99%, from which point forward, SB reflectance exceeds vitrinite reflectance (Figure 11).

Figure 10.

Graph showing linear relationship between vitrinite (VRo) and SB reflectance (BRo) of this study and empirical equations between vitrinite and SB reflectance from Jacob (1989), Landis and Castaño (1995), and Schoenherr et al. (2007).

Figure 10.

Graph showing linear relationship between vitrinite (VRo) and SB reflectance (BRo) of this study and empirical equations between vitrinite and SB reflectance from Jacob (1989), Landis and Castaño (1995), and Schoenherr et al. (2007).

Figure 11.

Graph showing measured reflectance values of vitrinite (VRo) and SB (BRo) of the studied shale samples.

Figure 11.

Graph showing measured reflectance values of vitrinite (VRo) and SB (BRo) of the studied shale samples.

Functional Group Distribution

Micro-FTIR analysis can characterize the chemical functional groups of in situ OM particles as small as 25 μm. In this study, micro-FTIR was used to document the evolution of functional groups of alginite and SB during thermal maturation. Four infrared regions are of particular interest in this study: (i) the aromatic CHx stretching region (wavenumber: 3000–3100 cm−1); (ii) the aliphatic CHx stretching region (2800–3000 cm−1); (iii) the oxygenated groups (1650–1800 cm−1); and (iv) the aromatic C=C ring stretching region (1550–1650 cm−1) (Mastalerz and Bustin, 1993; Chen et al., 2012). Because OM particles were very small, commonly at the limit of micro-FTIR resolution, the quality of spectra and signal-noise ratio are variable. For AOM, because of its small size and admixed nature with mineral matter, it was not possible to generate good-quality FTIR spectra, and, therefore, functional groups of AOM were not discussed.

Alginite (Tasmanites cysts) shows strong signal in the aliphatic CHx region from 0.57 to 0.84 VRo, suggesting high hydrocarbon generation potential over this maturity range (Figure 12A). In contrast, SB exhibits decreasing intensities in the aliphatic CHx region and increasing intensities in the aromatic CHx region with increasing maturity (Figure 12B), suggesting the generation of aliphatic hydrocarbons from SB. The apparent low intensity in the aliphatic CHx region of sample KY-3 (Figure 12B) is an artifact caused by the scale of the Y-axis because the absorbance at 1000–1300 cm−1 is so high that the spectra at 2800–3000 cm−1 is compacted. The reason for high absorbance at 1000–1300 cm−1 could be the interference by mineral matter (likely clay minerals) surrounding SB because the spectrum was collected on only one single small piece of SB (~20 μm) at the limit of micro-FTIR instrument resolution.

Figure 12.

Graph showing micro-FTIR spectra of alginite and SB at differing levels of thermal maturity. (A) Micro-FTIR spectra of alginite (VRo 0.57−0.84%). (B) Micro-FTIR spectra of SB (VRo 0.55−1.18%). n = number of spectra used to obtain the average spectrum.

Figure 12.

Graph showing micro-FTIR spectra of alginite and SB at differing levels of thermal maturity. (A) Micro-FTIR spectra of alginite (VRo 0.57−0.84%). (B) Micro-FTIR spectra of SB (VRo 0.55−1.18%). n = number of spectra used to obtain the average spectrum.

Because of different sizes of OM particles analyzed by micro-FTIR, semi-quantitative ratios are more informative than the comparison of individual functional group bands. Semi-quantitative ratios can be derived from the FTIR spectra by integrating the peak areas of selected functional group bands, such as aromaticity (aromatic CHx/aliphatic CHx), “A” factor (aliphatic CHx/[aliphatic CHx + aromatic C=C ring], a proxy for hydrocarbon-generation potential), aliphatic chain length (CH2/CH3), and Ali/Ox ratio (aliphatic CHx/oxygenated groups) (Mastalerz and Bustin, 1993; Chen et al., 2012; Hackley et al., 2017b). The “A” factor of alginite is close to 0.96 and shows a slight decrease until VRo 0.84% when alginite starts the process of transforming to pre-oil bitumen. This very small decrease suggests that oil and gas generated from alginite are very limited before alginite finishes transformation to pre-oil bitumen. Compared to alginite, the “A” factor of SB is lower, and it decreases with increasing maturity (Figure 13A). The aromaticity of alginite is close to zero in sample IND-4 (VRo 0.73%) and shows a slight increase with increasing maturity from VRo 0.73 to 0.84% (Figure 13B). The high aromaticity of the two lowest maturity samples (IND-2 and IND-3) is difficult to explain. It might be caused by different species of Tasmanites algae (as we observed different morphologies of Tasmanites cysts) or the presence of mineral matter because FTIR spectra were collected on compacted algal bodies having a thickness of ~20 μm, which is at the limit of micro-FTIR instrument resolution. The aromaticity of SB increases progressively with increasing maturity (Figure 13B), which suggests the aromatization process of the macromolecular structure of SB. The Ali/Ox ratio of alginite increases with increasing maturity from VRo 0.57 to 0.84%, which indicates the loss of oxygenated groups during this part of the maturation process. In contrast, the Ali/Ox ratio of SB decreases with increasing maturity (Figure 13C). The CH2/CH3 ratio of alginite decreases with increasing maturity from VRo 0.57 to 0.84%, whereas the CH2/CH3 ratio of SB does not change notably with increasing maturity (Figure 13D).

Figure 13.

Graphs showing the relationship between FTIR-derived ratios and vitrinite reflectance (VRo). (A) “A” factor. (B) Aromaticity. (C) Ali/Ox ratio. (D) Aliphatic chain length (CH2/CH3).

Figure 13.

Graphs showing the relationship between FTIR-derived ratios and vitrinite reflectance (VRo). (A) “A” factor. (B) Aromaticity. (C) Ali/Ox ratio. (D) Aliphatic chain length (CH2/CH3).

DISCUSSION

Evolution of Organic Macerals During Thermal Maturation

The evolution of sedimentary OM starts upon sediment burial and continues through diagenesis. In the course of diagenesis, OM experiences microbial degradation and chemical alteration; this is followed further by thermal evolution in the catagenetic stage, during which the decomposition of OM is controlled by temperature and pressure (Tissot and Welte, 1984; Horsfield and Rullkötter, 1994; Tyson, 1995). It is well documented that primary organic macerals (AOM, alginite, vitrinite, and inertinite) follow different evolutionary pathways during thermal maturation (Tissot et al., 1974; Mastalerz and Bustin, 1993; Peters and Cassa, 1994; Waples and Marzi, 1998; Jarvie and Lundell, 2001).

In OM-rich shales, the evolution of AOM and alginite is of special importance because they transform to oil and gas during thermal maturation, and their transformation ratio determines to a large degree the producibility of conventional and unconventional petroleum systems (Tissot and Welte, 1984; Jarvie, 2012a, b). Amorphous OM is the dominant OM in marine shales (Kus et al., 2017). In our suite of samples, AOM dominated OM in the three samples of lowest maturity (VRo 0.55–0.63%), and the transformation of AOM was not very advanced until the shale reached a maturity equivalent to VRo 0.73% (Table 1). Once VRo 0.80% was reached, AOM was no longer identifiable with a reflected-light microscope. Kus et al. (2017) suggested that established optical properties for AOM (bituminite) only apply to low-maturity samples (VRo ≤ 0.7%). Interestingly, between VRo 0.73 and 0.80%, there is a significant increase in SB content, strongly suggesting that SB is the direct product of AOM degradation. A significant portion of this SB likely takes up the space previously occupied by AOM, as suggested by the petrographically observed transition from AOM to SB (Figure 14). Liu et al. (2017) also reported transition from AOM to SB in the early mature New Albany Shale.

Figure 14.

Photomicrograph of AOM transforming to SB. This organic streak is a mixture of AOM and SB; SB is brighter and has a cleaner surface than AOM. AOM = amorphous organic matter; SB = solid bitumen.

Figure 14.

Photomicrograph of AOM transforming to SB. This organic streak is a mixture of AOM and SB; SB is brighter and has a cleaner surface than AOM. AOM = amorphous organic matter; SB = solid bitumen.

Prior studies have used micro-FTIR, x-ray photoelectron spectroscopy, and nuclear magnetic resonance to document that the macromolecular structure of the Tasmanites microfossil is dominated by relatively long, unbranched alkyl chains with minor oxygenated functional groups and little or no aromatic carbon (Lin and Ritz, 1993; Mastalerz et al., 2012; Dutta et al., 2013; Hackley et al., 2017b). The chemical structure of alginite evolved along its maturation pathway, as indicated by changes in fluorescent color (Figure 4) and in the ratios of functional groups (Figure 13). The changes in functional groups are clearly reflected by a decrease in the oxygenated functional groups relative to aliphatic bands (Figure 13C) and a decrease in the CH2/CH3 ratio with increasing maturity (Figure 13D). Loss of oxygenated functional groups in sporopollenin (the outer wall of spores and pollen) and Tasmanites microfossils during thermal maturation was reported by previous studies (Yule et al., 2000; Hackley et al., 2017b). A decrease in the CH2/CH3 ratio, suggesting shortening of aliphatic chains (Lin and Ritz, 1993; Chen et al., 2012), was reported for OM in both the New Albany Shale and Ohio Shale (Lis et al., 2005; Hackley et al., 2017b). The “A” factor of alginite is relatively consistent until VRo 0.84%, suggesting that substantial hydrocarbon generation from alginite does not start until alginite is completely transformed to pre-oil bitumen. These observations indicate a significant change in the chemical structure of alginite before alginite can convert to hydrocarbons. The transformation of alginite to pre-oil bitumen took place in situ, as clearly documented by the occurrence of pre-oil bitumen that inherited the shape of Tasmanites algal bodies (Figure 9B). Alginite (represented by Tasmanites cysts) disappears at a thermal maturity of VRo 0.89%, suggesting that at that point, it was completely transformed to SB and petroleum (Figure 15). Ryder et al. (2013) reported the disappearance of Tasmanites cysts in the Devonian shales of the Appalachian Basin at VRo and BRo greater than or equal to 0.9%.

Figure 15.

Diagram illustrating the thermal evolution of primary organic macerals and SB related to hydrocarbon generation. The dashed line that separates oil window and condensate and wet gas window means the maturity may vary around VRo 1.15%, depending on the nature of OM. The thickness of bars represents the relative content of organic macerals. Compiled and modified after Jarvie et al. (2005); Schimmelmann et al. (2006) and references therein; Mastalerz et al. (2013, 2018). AOM = amorphous organic matter; SB = solid bitumen.

Figure 15.

Diagram illustrating the thermal evolution of primary organic macerals and SB related to hydrocarbon generation. The dashed line that separates oil window and condensate and wet gas window means the maturity may vary around VRo 1.15%, depending on the nature of OM. The thickness of bars represents the relative content of organic macerals. Compiled and modified after Jarvie et al. (2005); Schimmelmann et al. (2006) and references therein; Mastalerz et al. (2013, 2018). AOM = amorphous organic matter; SB = solid bitumen.

Unlike AOM and alginite, vitrinite (type III kerogen) and inertinite (type IV kerogen) occur as discrete particles in the studied samples and do not change significantly in morphology during thermal maturation. Vitrinite, being derived from terrestrial materials, is more aromatic than liptinite macerals to begin with (Tissot et al., 1974; Lin and Ritz, 1993; Peters and Cassa, 1994) and, as such, does not have high hydrocarbon generation potential. In addition, vitrinite particles experienced long-distance transport before they reached the place of deposition and likely were oxidized to some degree during transport. Wei et al. (2016) studied the chemical structures of vitrinite and inertinite in the New Albany Shale using micro-FTIR and suggested that consumption of aliphatic functional groups in vitrinite and inertinite could have taken place during transport to the place of deposition. Because inertinite is derived from oxidized or burned terrestrial woody materials (Hackley and Cardott, 2016), it has essentially no hydrocarbon generation potential.

Solid bitumen is a secondary product of the transformation of primary organic macerals (Jacob, 1989; Mastalerz et al., 2018), and understanding its formation, occurrence, and fate during thermal maturation is important in understanding petroleum generation, expulsion, and migration processes (Mastalerz et al., 2018). Bitumen forms when oil-prone kerogen undergoes thermal degradation (Lewan, 1987; Mastalerz et al., 2018). Oil-prone kerogen is first transformed to pre-oil bitumen via the degradation process, and pre-oil bitumen is then transformed to oil and post-oil bitumen during oil generation (Jarvie et al., 2007; Bernard and Horsfield, 2014; Camp, 2016a; Mastalerz et al., 2018). Lewan (1983, 1987) studied thermal maturation of OM in the Woodford Shale with hydrous pyrolysis and suggested that a continuous bitumen network developed after the degradation of amorphous kerogen and that oil was then generated from that bitumen network. The transformation of alginite and AOM to bitumen observed in this study substantiates this proposed bituminization process (Figures 6, 14). It is very likely that minor oil and gas are generated during the bituminization process (Liu et al., 2017). Bitumen converted from alginite optically appears as dark nonfluorescent material and has lower reflectance than previously generated post-oil bitumen from AOM. This difference in reflectance suggests different timing of generation of alginite-derived bitumen and AOM-derived bitumen and subsequently different timing of hydrocarbon generation. Interestingly, we did not directly observe pre-oil bitumen generated from AOM because both AOM and pre-oil bitumen are black and can be indistinguishable under a reflected-light microscope. However, based on the disappearance of AOM at VRo 0.80% and the transformation ratio (<50%) of type II kerogen at this maturity (Waples and Marzi, 1998), we believe that AOM was transformed to bitumen and that hydrocarbon generation potential of AOM is, to some extent, retained in the generated bitumen.

In the New Albany Shale, SB was documented in all samples, but it is rare (<10%) at thermal maturities below VRo 0.73% (Table 1; Figure 2). Solid bitumen becomes the dominant OM above VRo 0.80% (Figure 15). Other studies also indicated the dominance of SB in high-maturity organic-rich shales (Hackley and Cardott, 2016; Liu et al., 2017; Mastalerz et al., 2018). For example, Hackley and Cardott (2016) reported that OM in thermally mature shales (VRo~0.9−1.1%) is dominated by SB because oil-prone type I/II kerogen is converted to hydrocarbons and no longer present as kerogen. Functional group distribution in SB in the New Albany Shale documents an increase in aromaticity with increasing maturity, as a result of the decrease in aliphatic bands and an increase in aromatic functionalities (Figure 13B). There is also a decrease in its hydrocarbon generation potential as suggested by “A” factor values (Figure 13A), suggesting that hydrocarbon was generated from SB. Solid bitumen also records a decrease in the ratio of aliphatic bands to oxygenated groups with increasing maturity (Figure 13C), a result of a faster loss of the former, opposite to the trend observed in alginite. Also different from alginite is an absence of the shortening of aliphatic chains of SB with increasing maturity, as suggested by a relatively uniform CH2/CH3 ratio (Figure 13D). The CH2/CH3 ratio suggests that aliphatic chains in SB are much shorter and more branched than in alginite and, therefore, are also more difficult to break. A potential explanation for this is that the measured SB is post-oil bitumen and that hydrocarbons with long alkyl chains were generated when pre-oil bitumen was transformed to oil and post-oil bitumen. Lis et al. (2005) reported that the CH2/CH3 ratio of type II kerogen in the New Albany Shale exhibits an initial decrease with increasing maturity and then becomes relatively stable at higher maturity (VRo > 0.9%). The initial decrease is caused by the presence of AOM and alginite, and the CH2/CH3 ratio becomes relatively stable after peak-oil window maturity.

Solid Bitumen Reflectance as a Thermal Maturity Indicator

Solid-bitumen reflectance can be used as a thermal maturity indicator in organic-rich shales that do not contain enough vitrinite for reflectance measurements, especially in pre-Devonian shales where vitrinite is absent (Jacob, 1989; Landis and Castaño, 1995; Schoenherr et al., 2007; Petersen et al., 2013; Mastalerz et al., 2018). The empirical equations by Jacob (1989) and Landis and Castaño (1995) are commonly used to correlate SB reflectance to vitrinite reflectance. Schoenherr et al. (2007) derived an updated empirical equation using the data set from these two studies. In the studied samples, SB and vitrinite reflectance show a good linear relationship from VRo 0.55 to 1.42%, and SB reflectance exceeds vitrinite reflectance after a maturity of VRo 0.99%, which suggests enhanced evolution of SB (degree of polymerization) at peak-oil-window maturity (Ro 0.8−1.0%). Jacob (1989) found that SB reflectance is lower than vitrinite reflectance until VRo 1.05%, which closely matches the results of this study.

The mobility of SB at reservoir temperature and pressure conditions (Jacob, 1989), presence of secondary nanopores in SB, and presence of varying generations of SB complicate the relationship between vitrinite and SB reflectance (Landis and Castaño, 1995; Sanei et al., 2015; Liu et al., 2017). For example, Landis and Castaño (1995) identified anisotropic, granular, and homogenous SB and suggested that only the reflectance measured on homogenous SB is a reliable thermal maturity indicator. Sanei et al. (2015) studied the effect of nanoporosity on SB reflectance measurements and suggested that nanoporosity in SB could result in lower SB reflectance relative to nongranular (homogenous) SB. Liu et al. (2017) reported that SB with secondary nanopores is almost unidentifiable using an optical microscope because some incident light is absorbed by the pores in SB. Our study indicates that pre-oil SB has a lower reflectance than post-oil SB. For example, in sample KY-4 with an average SB reflectance of 0.91%, the reflectance of post-oil SB (Figure 16A) is 0.34% higher than pre-oil SB (Figure 16B). The reflectance of completely black pre-oil SB can be as low as 0.15%, which was not included in the SB reflectance measurement for any sample. Therefore, the inclusion of pre-oil SB in reflectance measurements could result in a lower average reflectance of SB, and pre-oil SB should be excluded when using SB reflectance as an indicator of thermal maturity (Figure 17).

Figure 16.

Photomicrographs of SB with reflectance values in sample KY-4 (BRo 0.91%). (A) SB used for calculating the mean SB reflectance; (B) SB excluded for calculating the mean SB reflectance. This SB is probably pre-oil SB transformed from alginite.

Figure 16.

Photomicrographs of SB with reflectance values in sample KY-4 (BRo 0.91%). (A) SB used for calculating the mean SB reflectance; (B) SB excluded for calculating the mean SB reflectance. This SB is probably pre-oil SB transformed from alginite.

Figure 17.

Histogram of reflectance of SB in sample KY-4 (BRo 0.91%). n=number of measurements.

Figure 17.

Histogram of reflectance of SB in sample KY-4 (BRo 0.91%). n=number of measurements.

Organic-Matter-Hosted Pores

The “cement characteristics” of SB in the New Albany Shale suggests that SB was once liquid in the oil window and probably in the gas window at reservoir temperature and pressure conditions (Figure 8). The infill of matrix porosity by migrated bitumen and oil can reduce the porosity of shales significantly in the oil window (Mastalerz et al., 2013). However, secondary organic pores can form when oil and gas are generated and expelled from SB in source rocks (Loucks et al., 2009; Bernard et al., 2012; Liu et al., 2017). Consequently, OM-hosted pores can be the dominant pore type in some thermally mature organic-rich shales (Loucks et al., 2012).

Prior studies demonstrated that migrated bitumen can fill void space including previously generated organic pores. For example, Reeder et al. (2016) documented the opening of organic pores after removing bitumen. Löhr et al. (2015) reported the filling of OM-hosted pores with generated bitumen in the Woodford Shale. Liu et al. (2017) documented the filling of cellular pores in inertinite by SB in the New Albany Shale. Therefore, migrated bitumen can mask the presence of OM-hosted pores in the oil window by filling original and previously formed organic pores, making secondary organic pores very rare in samples of oil-window maturity (Liu et al., 2017).

Migrated SB can form a potentially interconnected OM network in high-maturity organic-rich shales (Cardott et al., 2015), and secondary organic pores can develop in the SB network (Liu et al., 2017) with subsequent thermal maturation, forming an organic pore network in unconventional shale reservoirs. Moreover, the SB network might alter the wettability of tight shales by coating the hydrophilic surface of mineral grains and facilitate the migration of oil and gas in unconventional shale reservoirs.

CONCLUSIONS

Petrographic observations of OM in the Upper Devonian New Albany Shale samples that span a thermal maturity range from early mature (VRo 0.55%) to post-mature (VRo 1.42%) document the reflectance, abundance, color, and fluorescence properties of primary organic macerals (AOM, alginite, vitrinite, and inertinite) and secondary organic matter (SB) at varying levels of maturity. Micro-FTIR measurements characterize the evolution of the chemical structure of alginite and SB. Specific conclusions are as follows:

Amorphous OM is the dominant OM in early mature samples, followed by alginite represented by Tasmanites cysts. Amorphous OM and alginite disappear at thermal maturities of VRo 0.80 and 0.89%, respectively, because they were transformed to SB and petroleum. The hydrocarbon generation potential of AOM and alginite is retained in generated SB. SB becomes the dominant OM in the studied samples above a maturity of VRo 0.80%. Vitrinite and inertinite derived from terrestrial woody materials occur as dispersed particles and do not change significantly in morphology across the entire maturity range.

Oil-prone kerogen is first transformed to pre-oil bitumen via a bituminization process in the oil window and then to oil, gas, and post-oil bitumen or pyrobitumen. Petrographic observations and micro-FTIR analysis indicate that substantial hydrocarbon generation from alginite does not start before alginite finishes transformation to pre-oil bitumen, although significant changes happen to the chemical structure of alginite, such as loss of oxygenated functional groups and shortening of aliphatic chains.

Solid bitumen reflectance can be a robust indicator of thermal maturity. Vitrinite reflectance is higher than SB reflectance until VRo 0.99%, beyond which SB reflectance exceeds vitrinite reflectance. Pre-oil SB generally has a lower reflectance than the average reflectance of SB, and, therefore, should be excluded when using SB reflectance as a thermal maturity indicator.

The “cement characteristics” of SB indicates that SB was mobile in the oil window at reservoir temperature and pressure conditions. Migrated bitumen can mask the presence of OM-hosted pores in the oil window by filling original or previously formed organic pores. Secondary organic pores in the SB network, together with the oil wettability of SB, may facilitate the migration of oil and gas in unconventional shale reservoirs.

ACKNOWLEDGMENTS

This research was supported by the sponsors of the Indiana University Shale Research Consortium, a Geological Society of America Graduate Student Research Grant, an Indiana Geological and Water Survey John B. Patton Award, and a Research Grant-in-Aid Award from Department of Earth and Atmospheric Sciences, Indiana University Bloomington. Mastalerz’s contribution is based on the work supported by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences, Chemical Sciences, Geosciences, and Biosciences Division under Award Number DE-SC0006978. Financial support for B. Liu from the China Scholarship Council is also gratefully acknowledged.

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Figures & Tables

Figure 1.

Map showing the locations of sampling sites and the extent of the New Albany Shale. Adapted from Mastalerz et al. (2013).

Figure 1.

Map showing the locations of sampling sites and the extent of the New Albany Shale. Adapted from Mastalerz et al. (2013).

Figure 2.

Graphs showing the evolution of organic petrographic compositions of shale samples with increasing thermal maturity. (A) Amorphous organic matter. (B) Alginite. (C) Solid bitumen. (D) Inertinite + vitrinite.

Figure 2.

Graphs showing the evolution of organic petrographic compositions of shale samples with increasing thermal maturity. (A) Amorphous organic matter. (B) Alginite. (C) Solid bitumen. (D) Inertinite + vitrinite.

Figure 3.

Photomicrographs of AOM in reflected white light and oil immersion (A−C, E, G−H) and fluorescence mode (D, F). AOM = amorphous organic matter; AL = alginite; V = vitrinite; I = inertinite; SB = solid bitumen.

Figure 3.

Photomicrographs of AOM in reflected white light and oil immersion (A−C, E, G−H) and fluorescence mode (D, F). AOM = amorphous organic matter; AL = alginite; V = vitrinite; I = inertinite; SB = solid bitumen.

Figure 4.

Photomicrographs of alginite derived from Tasmanites cysts in reflected white light and oil immersion (A, C, E, G, I) and the same fields in fluorescence mode (B, D, F, H, J). AOM = amorphous organic matter; AL = alginite.

Figure 4.

Photomicrographs of alginite derived from Tasmanites cysts in reflected white light and oil immersion (A, C, E, G, I) and the same fields in fluorescence mode (B, D, F, H, J). AOM = amorphous organic matter; AL = alginite.

Figure 5.

Photomicrographs of pre-oil bitumen converted from alginite in reflected white light and oil immersion (A) and the same field in fluorescence mode (B). The pre-oil bitumen still shows weak orange fluorescence.

Figure 5.

Photomicrographs of pre-oil bitumen converted from alginite in reflected white light and oil immersion (A) and the same field in fluorescence mode (B). The pre-oil bitumen still shows weak orange fluorescence.

Figure 6.

Photomicrographs of early-transformed alginite and pre-oil bitumen in reflected white light and oil immersion (A), and the same field in fluorescence mode (B) in sample IND-2 (VRo 0.57%). AL, alginite.

Figure 6.

Photomicrographs of early-transformed alginite and pre-oil bitumen in reflected white light and oil immersion (A), and the same field in fluorescence mode (B) in sample IND-2 (VRo 0.57%). AL, alginite.

Figure 7.

Photomicrographs of vitrinite (A, C) and inertinite (B, D) in reflected white light and oil immersion. V = vitrinite; I = inertinite. Inertinite in panel B and D shows cellular pores (red arrows).

Figure 7.

Photomicrographs of vitrinite (A, C) and inertinite (B, D) in reflected white light and oil immersion. V = vitrinite; I = inertinite. Inertinite in panel B and D shows cellular pores (red arrows).

Figure 8.

Photomicrographs of SB in reflected white light and oil immersion. SB occupies interparticle space between mineral grains (e.g., quartz, carbonates, and clay minerals). SB in the early (A−B) and mid-mature (C−F) samples is approximately 50 μm in size, whereas SB in late (G) and post-mature (H) samples is typically smaller than 20 μm. SB = solid bitumen.

Figure 8.

Photomicrographs of SB in reflected white light and oil immersion. SB occupies interparticle space between mineral grains (e.g., quartz, carbonates, and clay minerals). SB in the early (A−B) and mid-mature (C−F) samples is approximately 50 μm in size, whereas SB in late (G) and post-mature (H) samples is typically smaller than 20 μm. SB = solid bitumen.

Figure 9.

Photomicrographs of pre-oil bitumen (A−B) in reflected white light and oil immersion. The morphology and occurrence of the pre-oil bitumen in panel (B) are similar to those of the alginite in Figure 4.

Figure 9.

Photomicrographs of pre-oil bitumen (A−B) in reflected white light and oil immersion. The morphology and occurrence of the pre-oil bitumen in panel (B) are similar to those of the alginite in Figure 4.

Figure 10.

Graph showing linear relationship between vitrinite (VRo) and SB reflectance (BRo) of this study and empirical equations between vitrinite and SB reflectance from Jacob (1989), Landis and Castaño (1995), and Schoenherr et al. (2007).

Figure 10.

Graph showing linear relationship between vitrinite (VRo) and SB reflectance (BRo) of this study and empirical equations between vitrinite and SB reflectance from Jacob (1989), Landis and Castaño (1995), and Schoenherr et al. (2007).

Figure 11.

Graph showing measured reflectance values of vitrinite (VRo) and SB (BRo) of the studied shale samples.

Figure 11.

Graph showing measured reflectance values of vitrinite (VRo) and SB (BRo) of the studied shale samples.

Figure 12.

Graph showing micro-FTIR spectra of alginite and SB at differing levels of thermal maturity. (A) Micro-FTIR spectra of alginite (VRo 0.57−0.84%). (B) Micro-FTIR spectra of SB (VRo 0.55−1.18%). n = number of spectra used to obtain the average spectrum.

Figure 12.

Graph showing micro-FTIR spectra of alginite and SB at differing levels of thermal maturity. (A) Micro-FTIR spectra of alginite (VRo 0.57−0.84%). (B) Micro-FTIR spectra of SB (VRo 0.55−1.18%). n = number of spectra used to obtain the average spectrum.

Figure 13.

Graphs showing the relationship between FTIR-derived ratios and vitrinite reflectance (VRo). (A) “A” factor. (B) Aromaticity. (C) Ali/Ox ratio. (D) Aliphatic chain length (CH2/CH3).

Figure 13.

Graphs showing the relationship between FTIR-derived ratios and vitrinite reflectance (VRo). (A) “A” factor. (B) Aromaticity. (C) Ali/Ox ratio. (D) Aliphatic chain length (CH2/CH3).

Figure 14.

Photomicrograph of AOM transforming to SB. This organic streak is a mixture of AOM and SB; SB is brighter and has a cleaner surface than AOM. AOM = amorphous organic matter; SB = solid bitumen.

Figure 14.

Photomicrograph of AOM transforming to SB. This organic streak is a mixture of AOM and SB; SB is brighter and has a cleaner surface than AOM. AOM = amorphous organic matter; SB = solid bitumen.

Figure 15.

Diagram illustrating the thermal evolution of primary organic macerals and SB related to hydrocarbon generation. The dashed line that separates oil window and condensate and wet gas window means the maturity may vary around VRo 1.15%, depending on the nature of OM. The thickness of bars represents the relative content of organic macerals. Compiled and modified after Jarvie et al. (2005); Schimmelmann et al. (2006) and references therein; Mastalerz et al. (2013, 2018). AOM = amorphous organic matter; SB = solid bitumen.

Figure 15.

Diagram illustrating the thermal evolution of primary organic macerals and SB related to hydrocarbon generation. The dashed line that separates oil window and condensate and wet gas window means the maturity may vary around VRo 1.15%, depending on the nature of OM. The thickness of bars represents the relative content of organic macerals. Compiled and modified after Jarvie et al. (2005); Schimmelmann et al. (2006) and references therein; Mastalerz et al. (2013, 2018). AOM = amorphous organic matter; SB = solid bitumen.

Figure 16.

Photomicrographs of SB with reflectance values in sample KY-4 (BRo 0.91%). (A) SB used for calculating the mean SB reflectance; (B) SB excluded for calculating the mean SB reflectance. This SB is probably pre-oil SB transformed from alginite.

Figure 16.

Photomicrographs of SB with reflectance values in sample KY-4 (BRo 0.91%). (A) SB used for calculating the mean SB reflectance; (B) SB excluded for calculating the mean SB reflectance. This SB is probably pre-oil SB transformed from alginite.

Figure 17.

Histogram of reflectance of SB in sample KY-4 (BRo 0.91%). n=number of measurements.

Figure 17.

Histogram of reflectance of SB in sample KY-4 (BRo 0.91%). n=number of measurements.

Table 1.

Sample location, type, total organic carbon (TOC) content, vitrinite reflectance (VRo), SB reflectance (BRo), maturity stage, alginite fluorescence, and organic petrographic composition of shale samples.

SampleLocationSample typeDepth (m)TOC (wt. %)VRo (%)BRo (%)Maturity stageAlginite fluorescenceOrganic petrographic composition (vol. %, on mineral-matter-free basis)
AOMALLPDSBIV
IND-1Daviess Co., INCore545.310.770.550.35Early matureGreenish-yellow64.919.04.63.37.40.7
IND-2Daviess Co., INCore539.812.10.570.36Early matureGreenish-yellow51.731.03.88.23.41.9
IND-3Daviess Co., INCore537.110.60.630.45Early matureGreenish-yellow58.224.83.37.55.11.2
IND-4Pike Co., INCore852.88.40.730.53Middle matureYellow29.067.91.41.00.60.2
IND-5Gibson Co., INCore1218.34.50.790.58Middle matureOrange-yellow28.220.51.248.51.10.5
KY-1Webster Co., KYCore915.96.260.800.62Middle matureOrange-yellow016.52.368.112.50.6
KY-2Crittenden Co., KYCore791.05.20.840.64Middle matureWeak orange013.10.684.71.00.6
KY-3Livingston Co., KYCore180.44.80.890.77Middle matureNo alginite00091.37.90.8
KY-4Crittenden Co., KYCore858.06.10.980.91Middle matureNo alginite00097.62.00.4
ILL-1Wayne Co., ILCore1606.95.41.011.00Middle matureNo alginite00096.82.40.8
ILL-2Hicks Dome, ILOutcrop 7.11.051.13Middle matureNo alginite00098.61.00.4
ILL-3Hicks Dome, ILOutcrop 6.61.111.25Middle matureNo alginite00094.25.00.8
ILL-4Hicks Dome, ILOutcrop 7.61.181.33Late matureNo alginite00098.21.10.7
ILL-5Hicks Dome, ILOutcrop 2.581.421.71Post-matureNo alginite00097.22.30.6
SampleLocationSample typeDepth (m)TOC (wt. %)VRo (%)BRo (%)Maturity stageAlginite fluorescenceOrganic petrographic composition (vol. %, on mineral-matter-free basis)
AOMALLPDSBIV
IND-1Daviess Co., INCore545.310.770.550.35Early matureGreenish-yellow64.919.04.63.37.40.7
IND-2Daviess Co., INCore539.812.10.570.36Early matureGreenish-yellow51.731.03.88.23.41.9
IND-3Daviess Co., INCore537.110.60.630.45Early matureGreenish-yellow58.224.83.37.55.11.2
IND-4Pike Co., INCore852.88.40.730.53Middle matureYellow29.067.91.41.00.60.2
IND-5Gibson Co., INCore1218.34.50.790.58Middle matureOrange-yellow28.220.51.248.51.10.5
KY-1Webster Co., KYCore915.96.260.800.62Middle matureOrange-yellow016.52.368.112.50.6
KY-2Crittenden Co., KYCore791.05.20.840.64Middle matureWeak orange013.10.684.71.00.6
KY-3Livingston Co., KYCore180.44.80.890.77Middle matureNo alginite00091.37.90.8
KY-4Crittenden Co., KYCore858.06.10.980.91Middle matureNo alginite00097.62.00.4
ILL-1Wayne Co., ILCore1606.95.41.011.00Middle matureNo alginite00096.82.40.8
ILL-2Hicks Dome, ILOutcrop 7.11.051.13Middle matureNo alginite00098.61.00.4
ILL-3Hicks Dome, ILOutcrop 6.61.111.25Middle matureNo alginite00094.25.00.8
ILL-4Hicks Dome, ILOutcrop 7.61.181.33Late matureNo alginite00098.21.10.7
ILL-5Hicks Dome, ILOutcrop 2.581.421.71Post-matureNo alginite00097.22.30.6

AOM = amorphous organic matter; AL = alginite; LPD = liptodetrinite; SB = solid bitumen; I = inertinite; V = vitrinite.

Contents

GeoRef

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