International Journal of Coal Geology 139 (2015) 106–113
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International Journal of Coal Geology
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Post-oil solid bitumen network in theWoodford Shale, USA— A potentialprimary migration pathway
Brian J. Cardott a,⁎, Charles R. Landis b, Mark E. Curtis c
a Oklahoma Geological Survey, 100 E. Boyd St., Rm. N-131, Norman, OK 73019-0628, USAb Minerals End Inc., The Woodlands, TX 77381, USAc University of Oklahoma, Norman, OK 73019-0628, USA
An important if not predominant component of porosity inmany gas shales has been identified in organicmatter.An organic network in shales has been described in the literature as organic matter (generalized term), kerogen(primary), or bitumen (secondary). Recognition of the type and origin of an organic network in shales has rele-vance in establishing the origin and timing of porosity and fracture development. The pervasive nature of the or-ganic network adopting the shape of pores in Type II kerogen-rich Woodford Shale suggests it is the residue ofprimary oil migration. We use the term “post-oil solid bitumen” to distinguish this bitumen occurrence from“pre-oil solid bitumen” (defined as a precursor of oil). Three forms of this post-oil solid bitumen network are rec-ognized in reflected white light at 500× magnification and confirmed in backscattered scanning electron micro-scope images at N2500×magnification, namely speckled (~1–2 μm), wispy (~2–5 μm), and connected (N5 μm).The post-oil solid bitumen network demonstrates the prior occurrence of oil generation and migration withinthis hydrocarbon source rock, provides porosity for hydrocarbon storage sites, and forms hydrocarbonmigrationpathways.
The basic requirements of a shale resource system for oil and gas(source-rock reservoir of Hart et al., 2013) are appropriate organic mat-ter characteristics in the hydrocarbon source rock (e.g., organic mattertype, quantity, and thermal maturity) and brittle rock fabric (Jarvie,2012). Recognition of organic-matter (e.g., maceral) types and distribu-tion are essential to the evaluation of shales as oil and gas reservoirs.
Two basic types of organic matter present in hydrocarbon sourcerock shales are kerogen and bitumen. Organic geochemists define bitu-men as the hydrocarbon fraction extracted with organic solvents. Bythis definition, pyrobitumen and kerogen are not bitumen becausethey are insoluble in the same organic solvents (Durand, 1980; Petersand Cassa, 1994; Tissot and Welte, 1984). In contrast, organic petrolo-gists use the term bitumen without reference to solubility, using petro-graphic features to infer its origin from its passive occurrence in rocks,mainly as void fillings (i.e., faunal, dissolution, microfracture, coatingand laminar fillings; Landis and Castaño, 1994).
Bitumen and residual solid hydrocarbons are important componentswhen considering shale as a hydrocarbon source-rock reservoir. Theirexistence in shale is visual proof that the rock reached an appropriatelevel of thermal maturity to generate liquid hydrocarbons and can be
used as a proxy for other visual, chemical and mineralogical compo-nents for maturation assessments, especially in rocks whose age pre-cedes terrestrial flora.
Through the maturation process, the insoluble fraction of the originalbitumen increases, rendering less efficient attempts to remove all of theoriginally generated bitumen (Landis and Castaño, 1994). The occurrenceof this insoluble pyrobitumen fraction impacts both geochemical andpet-rological evaluations of the rock. The presence of these bitumens in a hy-drocarbon source rock can affect geochemical analyses (e.g., affecting theTmax value) and petrographic analyses (e.g., appearing as vitrinite-likeorganicmatter affecting the vitrinite reflectance analysis and visual kero-gen analysis) in isolated kerogen-concentrate pellets (Glikson et al.,1992; Hackley et al., 2013; Snowdon, 1995).
Primary oil migration in a hydrocarbon source rock begins soon afteroil generation when there is sufficient oil saturation (Jarvie, 2012).Ungerer et al. (1983, p. 135) concluded that oil migration “depends onthe development of a continuous network of oil-wet pores.” As a resultof primary oil migration and expulsion, a solid carbon residue is leftbehind in the shale. Taylor et al. (1998, p. 253) described this secondaryorganicmatter as a “‘kerogen network’ (impsonite)”, using the asphalticpyrobitumen (insoluble) vein classification of Abraham (1960). Else-where, Taylor et al. (1998, p. 84) recognized a network of solid bitumen(termed impsonite) as a “product of oil that was generated in but notexpelled from the source rocks.” A key question is whether this organicmaterial is kerogen or bitumen. Belin (1992) recognized laminated and
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particulate kerogen networks under SEM backscattered electron modeand concluded that conventional lightmicroscopy is needed to properlyidentify organic matter. Recent application of backscattered scanningelectron microscopy of the Barnett Shale by Loucks et al. (2009) recog-nized the importance of organic matter in shale as an important sourceofmicroporosity, but only described thematerial as “organicmatter”. Aspointed out in the present article, much of this organic matter occurs asan organic network. Loucks et al. (2012) recognized the importance ofthe interconnected network of organic matter pores. Milliken et al.(2013) recognized the importance of distinguishing kerogen versus bi-tumen in the occurrence of organic matter porosity. Our purpose in thispaper is to describe the occurrence, origin, and significance of the or-ganic network found in organic-rich shales. We show that this networkmay be observed not only at high magnification in backscattered scan-ning electron microscopy but also in reflected white light at 500×magnification.
2. Terminology
Part of the problem of recognizing bitumen is that it can go by manyterms: bitumen, pyrobitumen, asphalt, asphaltite, asphaltic pyrobitumen,solid bitumen, solid hydrocarbon,migrabitumen, reservoir bitumen, deadoil, and exudatinite (Abraham, 1960; Curiale, 1986; Hunt, 1979; Jacob,1989, 1993; Landis and Castaño, 1994; Taylor et al., 1998). The termsolid bitumen, following Curiale (1986), will be used in this article.
A common generic classification of solid bitumen (primarilyfracture-filling vein deposits of altered, once-liquid oil: asphaltite ver-sus asphaltic pyrobitumen) was given by Abraham (1960). Jacob(1989) modified this classification to include petrographic parameters(e.g., bitumen reflectance, fluorescence, solubility in immersion oil)and introduced the term migrabitumen (primarily used for veindeposits) for amorphous, secondary macerals dispersed in rocks andtaking on the shape of voids. Curiale (1986, p. 559) developed a simplegenetic classification of solid bitumen: pre-oil solid bitumen (defined as“early-generation (immature) products of rich source rocks”) and post-oil solid bitumen (defined as “products of the alteration of a once-liquidoil”). It is widely recognized that (pre-oil solid) bitumen forms fromkerogen (Barker, 1979, p. 41; Bernard et al., 2012a; Tissot and Welte,1984, p.176). Based on hydrous-pyrolysis experiments, Lewan (1983)demonstrated that pre-oil solid bitumen is the intermediate product be-tween kerogen and oil.
The terms solid bitumen and migrabitumen were first used for non-disseminated organic matter occurring as vein deposits known asasphaltite (soluble) and asphaltic pyrobitumen (insoluble). Thesefracture-fillings occur as a once-liquid oil altered to a solid from near-surface, low-temperature alteration of crude oil by limited biodegrada-tion, water-washing, and devolatilization (Curiale, 1983). As discussedbelow, post-oil solid bitumen can also be any alteration of a once-liquid
Table 1Woodford Shale samples used in this study arranged by increasing vitrinite reflectance.
OPL numbera Sample type County Geologic province D
a Oklahoma Geological Survey Organic Petrography Laboratory sample number.b NAD 83.c Random vitrinite reflectance in non-polarized light with fixed stage.
oil into a solid, including the dispersed solid residue of oil migration.Therefore, the genetic solid bitumen classification of Curiale (1986) willbe used here to distinguish bitumen as a precursor of oil (pre-oil solid bi-tumen) from bitumen formed as an alteration of a once-liquid oil (post-oil solid bitumen). Thompson-Rizer (1987) described this post-oil solidbitumen network as an amorphous kerogen in strewn slides.
Pre-oil solid bitumen and post-oil solid bitumen can appear similar tovitrinite in reflected white light at 500× magnification. Hackley et al.(2013) concluded that vitrinite reflectancemeasurements of earlymatureDevonian shale may erroneously include solid bitumen lower reflectancevalues. Landis and Castaño (1994) identified three types of solid bitumen(homogenous, granular, and coked). In addition to distinguishingvitrinite-like bitumen to exclude from the vitrinite-reflectance analysis,homogenous solid bitumen reflectance values may be used to calculatea vitrinite reflectance equivalent (VRE; Landis and Castaño, 1994). TheVRE value may be used as a thermal maturity indicator when vitrinite isnot present or to verify the vitrinite-reflectance value. Distinguishingsolid bitumen from vitrinite is more easily accomplished in whole-rockparticulate pellets than in kerogen-concentrate pellets.
3. Methods
Type II kerogen-rich (oil generative organicmatter)marineWoodfordShale (Late Devonian–Early Mississippian) samples from Oklahoma, USAcovering a wide range of thermal maturities (0.50–6.36% vitrinite reflec-tance, VRo; random reflectance measured in non-polarized light follow-ing ASTM, 2011) have been examined in reflected white light (200×and 500×; whole-rock particulate pellets; oil immersion) using a VickersM17 Research Microscope system equipped with a Smith illuminator(Cardott, 2012). The samples (Table 1) are from the Organic PetrographyLaboratory (OPL) of the OklahomaGeological Survey. A coal stringer sam-ple (OPL 1387) from a Woodford Shale core was used to determine thethermal maturity whereas the shale sample in the same core was usedto visualize the post-oil solid bitumen network. An outcrop sample (OPL1300) did not show signs of weathering (Lo and Cardott, 1994). The pre-dominant form of silica in the quartz-richWoodford Shale is biogenic sil-ica formed from radiolarians (Cardott and Chaplin, 1993). Core, outcrop,and well cuttings samples that were recognized in reflected white lightto contain post-oil solid bitumen forms or amorphous organic mattergroundmass were selected for examination by scanning electron micros-copy (SEM). Core, outcrop, and larger chips from cuttings were initiallyprepared by mechanical polishing. The samples were then ion milled ina Fischione Model 1060 ion mill using Argon gas. Milling was performedwith the sample rotating under two crossing ion beams at 5 kV accelerat-ing voltage for 3 h. The elevation of the ion beamswas 2° above the sam-ple horizontal. Ion beam milling provides a very flat surface for imagingand preserved the microstructure of the samples with minimal artifacts.Previous work has shown that even with higher energy focused ion
epth (m) Latitudeb Longitudeb VRo (%)c n VRo range (%)
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beam milling, no significant alteration of the organic matter microstruc-ture is observed as a result of the ion milling (Curtis et al., 2010). In addi-tion, pores have been observed in organic matter that has not undergoneion milling suggesting that pores exist naturally in the organic matter ofsome samples. Samples were imaged in a FEI Helios Dual Beam FIB/SEMusing backscattered electrons (BSE) for atomic number contrast. Theaccelerating voltage was 1 kV and the beam current was 0.40 nA.
4. Discussion
4.1. Occurrence of post-oil solid bitumen network
Pre-oil solid bitumens are common in immature to mature (oil win-dow) hydrocarbon source rocks. They are recognized in reflected whitelight in whole-rock pellets by their texture (e.g., homogenous, granular,and coked), semi-translucent character with internal reflections fromimbedded pyrite, and by the pyrite that occurs on their edges (Fig. 1;ASTM, 2011).
In addition to amorphous blobs of pre-oil solid bitumen andfracture-filling post-oil solid bitumen, small pieces of organic matterfilling voids are recognized under reflected white light at 500× magni-fication. Others have recognized this network, although not using theterminology we use here. Mahlstedt and Horsfield (2012) referred topost-oil solid bitumen as a carbon-rich pyrobitumen (“pore-occludingpetroleum”) that can undergo secondary cracking to gas and conden-sate at N1.1% VRo. Landis and Castaño (1994) described residual solidhydrocarbons occurring as intergranular pore fillings (b10 μm). Thevoid-filling occurrence of this material suggests that it is the solid resi-due of primary oil migration (e.g., post-oil solid bitumen). The termpost-oil solid bitumen, as we use it here, has no inference for solubility.Three post-oil solid bitumen forms are recognized in reflected whitelight at 500× in whole rock particulate pellets: speckled (~1–2 μm;Fig. 2a); wispy (~2–5 μm; Fig. 2b); and connected (N5 μm; Fig. 2c).The sizes are relative and should not be considered specific.
Speckled andwispy aremostly isolated occurrences in the rock rath-er than as a connected network. The speckled post-oil solid bitumennetwork, where it occurs, is near the magnification limit of the lightmi-croscope (~1–2 μm) and is usedmostly as a presence or absence indica-tor of oil generation and migration. Speckled post-oil solid bitumenmust be carefully distinguished from clay minerals. Speckled andwispy types are not exclusive— that is, they do not occur in shale as ei-ther one or the other. Grains that contain the wispy post-oil solid bitu-men network also will contain areas of speckled post-oil solidbitumen network (Fig. 3). Speckled and wispy forms are easy to seebut difficult to photograph in reflected white light (500×) because offocus issues and interference from pyrite. The post-oil solid bitumenshapes and sizes that form a network are confirmed and best viewed
in BSE images. BSE imaging is sensitive to the atomic number of thesample material. This results in the low atomic number organic matter(mostly carbon) appearing dark gray whereas higher atomic numberminerals such as quartz, carbonates, and pyrite exhibit progressivelyhigher grayscale values (Figs. 4–5). Belin (1994) noted that eventhough organic matter types cannot be identified in BSE images, rela-tionships of organic matter and minerals are revealed with fine resolu-tion. Although they did not use the solid bitumen terminology describedhere, Bernard et al. (2012b, p. 7) recognized the speckled and wispypost-oil solid bitumen network by using scanning transmission X-raymicroscopy and transmission electron microscopy of the BarnettShale. Similar towhatwe see in theWoodford Shale, their work indicat-ed that “Organic matter appears as micron sized angular organic grainsirregularly distributed within the mineral matrix or as organic massesfilling intergranular porosity and exhibiting smoothly curved concavesurfaces.”
4.2. Origin of post-oil solid bitumen network
Primary oil migration occurs within the hydrocarbon source rock(Cordell, 1972). McAuliffe (1979) proposed that primary oil migrationoccurs in a 3D kerogen network. However, the occurrence of secondary,amorphous dispersed organic matter filling voids suggests that thisorganic matter was once a liquid, and thus not kerogen. The pervasivenature and relationship with fracture filling bitumen indicate that it ispost-oil solid bitumen. The mechanisms of primary oil migrationthrough a kerogen network proposed by McAuliffe (1979) hold truefor a post-oil solid bitumen network. Much of the generated oil doesnot migrate out of the rock. Meyer (2012, p. 72) indicated that “forevery barrel of crude oil in conventional reservoirs … there are 8 bblof potentially producible oil equivalents remaining in the source rock”and “Speculative estimates of just how much generated oil remains inshale source rocks range between 45% and 95% depending on the geol-ogy of the formation and the quality of the estimate.” Some of the shale-hosted oil will result in a carbon residue (possibly the same as residualoil of Fan et al., 2012). Hunt (1996, p. 597–598, see references within onp. 598) recognized a “refractory bitumen” or “pyrobitumen residue”retained in the source rock.
4.3. Lowest thermal maturity with post-oil solid bitumen network
The most common organic-matter type in low thermal maturityType II kerogen-rich shales and boghead coals is amorphous organicmatter (AOM) (Mastalerz et al., 2012; Thompson-Rizer, 1993). This pri-marymaceral, AOM, is derived from degraded, unidentifiable precursororganisms (Pacton et al., 2011). AOM is equivalent to the termbituminite (ASTM, 2011). Lewan (1987) reported that amorphous
center of photomicrograph) showing internal reflections frompyrite (reflectedwhite light,ture in pre-oil solid bitumen (reflected white light, 500×; whole-rock particulate pellet;1986) and Landis and Castaño (1994).
Fig. 3. Speckled (~1–2 μm) and wispy (~2–5 μm) post-oil solid bitumen network in thesame grain (reflected white light, 500×; Woodford Shale; OPL 1387; 1.62% VRo).
Fig. 4. Speckled (~1–2 μm;white arrow) and wispy (~2–5 μm; black arrow) post-oil solidbitumen network in backscattered SEM (5000×;Woodford Shale; OPL 1397e; 0.98% VRo).
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Type II kerogen comprised N80 vol% of isolated kerogen fromWoodfordShale samples in Oklahoma. There are several classifications of AOM.Thompson and Dembicki (1986) recognized four types of AOM relatedto hydrocarbon-generating potential (Types A–D). Taylor et al. (1998,p. 250) also recognized four types of unstructured organic matter(bituminite). Senftle et al. (1993) indicated that fluorescing AOM(fluoramorphinite) can be distinguished from nonfluorescing AOM(hebamorphinite) up to 1.1% VRo in an estimate of oil and gas potential.Only the fluorescing type of AOM (fluoramorphinite and types A andD) is considered a source of pre-oil solid bitumen and oil. AOM is bestrecognized using strewn slides in transmitted white light and reflectedfluorescent light at 500× magnification. The distribution of AOM in
shale forms an organic network (Figs. 6, 7). The AOM network couldbe misidentified as the post-oil solid bitumen network.
Post-oil solid bitumen ultimately forms from oil generated in the oilwindow. The lowest thermal maturity containing a post-oil solidbitumen network is uncertain because it may be confused with AOM(a primarymaceral). The post-oil solid bitumen network could have de-veloped preferentially along theAOMnetwork. Lewan (1987) describedprimary oil migration occurring along a continuous bitumen networkformed from kerogen and impregnating AOM. He described the devel-opment of an opaquepyrobitumen groundmass (e.g., post-oil solid bitu-men network) carbonized from bitumen and retained oil.
The lowest thermal maturity where the post-oil solid bitumen net-work is observed in the Woodford Shale is 0.76% VRo near the middleof the oil window (Fig. 8). Below this thermal maturity, the organic net-work could be AOM.
4.4. Significance of post-oil solid bitumen network
The presence of post-oil solid bitumen demonstrates that oil wasgenerated in or migrated through the rock even though the rock is cur-rently at a higher thermal maturity than the oil window (Thompson-Rizer, 1987). Recent applications of BSE images have not only revealedthe occurrence of a network of organicmatter, but also thedevelopment
Fig. 7.Amorphous organicmatter (AOM)matrix in backscattered SEM (7500×;WoodfordShale; OPL 601; 0.62% VRo).
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of secondary nanoporosity (i.e., pores several nanometers in size;Loucks et al., 2009; Ruppert et al., 2013; Fig. 9b).
Nanoporosity in organics has been described in the literature as de-veloping at N0.6% to ~0.9% VRo primarily in post-oil solid bitumen.Curtis et al. (2012a) reported that the development of secondarynanoporosity is related to both thermal maturity (beginning about0.9% VRo; Fig. 10) and organic-matter type (e.g., post-oil solid bitumen).In contrast, Reed et al. (2012) reported nanopore development in or-ganic matter beginning at about 0.8% VRo. Loucks et al. (2012) andZhang et al. (2012) reported nanopore development in organic matterN0.60% VRo. Romero-Sarmiento et al. (2013) attributed nanoporositydevelopment to the maturation of kerogen in the Barnett Shale begin-ning at about 0.7% VRo. Bernard et al. (2012a) reported nanoporouspyrobitumen (e.g., post-oil solid bitumen) in a Posidonia Shale sampleat 1.45% VRo, but no organic nanoporosity in samples at 0.5% and0.85% VRo. Milliken et al. (2012) demonstrated that secondary porositydevelops primarily in intergranular organic matter (e.g., post-oil solidbitumen) instead of within particulate organic matter (e.g., kerogen)and that porosity increaseswith increasing total organic carbon content.Hao et al. (2013, p. 1342) concluded that “gas sorption in organic-richshales is mainly associated with micropores” (b2 nm).
In addition to the biogenic-silica-rich Woodford Shale, a post-oilsolid bitumen network has also been observed in other shales, includingthe Barnett, Haynesville, and Horn River shales (Curtis et al., 2012a).Although not using the post-oil solid bitumen network terminology
Fig. 6.Amorphous organicmatter (AOM; also referred to as bituminite) groundmass (darkgray material) inWoodford Shale marine boghead coal in backscattered SEM (800×; OPL1300e; 0.53% VRo).
used here, others have observed the network in other formations.Bernard et al. (2012a) recognized aliphatic-rich bitumens (e.g., pre-oilsolid bitumen) and aromatic-rich pyrobitumens (e.g., post-oil solidbitumen) in an overmature (1.45% VRo) sample of the PosidoniaShale. Bernard et al. (2012b) recognized pre-oil solid bitumen (derivedfrom thermally degraded kerogen) and post-oil solid bitumen(nanoporous pyrobitumen resulting from the secondary thermal crack-ing of retained oil) in the Barnett Shale.Milliken et al. (2012) recognizedsecondary porosity in “organic particulate debris and solid bitumen”using field-emission scanning electron microscope images of Ar ion-milled surfaces of the Barnett Shale (Mississippian). The predominantpore-filling organic matter, interpreted as solid bitumen, was recog-nized as originating as a liquid hydrocarbon. Hackley (2012) recognizedan interconnected (post-oil) solid bitumen network in whole-rock par-ticulate pellets of argillaceous lime wackestones and mudstones of theLower Cretaceous Pearsall Formation. Uffmann et al. (2012) describeda (post-oil) solid bitumen network in whole-rock pellets of high ther-mal maturity Mississippian and Pennsylvanian black shales fromGermany and Belgium. Fishman et al. (2012) did not recognize bitumenor pyrobitumen in the Kimmeridge Clay Formation and concluded thatpetroleum storage potential was attributed to inorganic pores. In con-trast, Fishman et al. (2013) recognized nanoporosity in high maturity(~1.2% VRo) migrated bitumen from Eagle Ford Shale core samplesequivalent to the post-oil solid bitumen terminology used here.Kosakowski and Krajewski (2014, their Fig. 11E) recognized a post-oilsolid bitumen network in carbonates in Poland.
Organic pores are not only sites of methane storage by adsorption tothe pore walls (Hackley, 2012; Zhang et al., 2012), but also provide mi-gration pathways for production of natural gas. 3-D reconstructions ofFocused Ion Beam/SEM tomography samples illustrate the distributionand connection of nanopores in the post-oil solid bitumen network(Curtis et al., 2012b, their Fig. 8). Microfractures that connect to thepost-oil solid bitumen network can be seen in BSE images (Fig. 9a) dem-onstrating the preferred fracture pattern following zones of weaknessthrough the bitumen. Themicrofractures (formed either naturally or in-duced by hydrofracturing) contribute to the rock permeability. Zagorskiet al. (2013, p. 172) recognized that “The observed intraorganic porositydisplays a high degree of connectivity and is responsible for a significantportion of the Marcellus Shale's productivity and gas in place.”
Applied to gas shales, Blood (2011, p. 56) recognized that “Organicparticles are the sites of adsorbed gas, and amorphous organic matterand bitumen represent the dominant sites of porosity developmentwithin the Marcellus.” As recognized by Belin (1992) for a kerogen
Fig. 8. Lowest thermalmaturity (0.76%VRo)Woodford Shale sample that contains post-oil solid bitumennetwork (connected; N 5 μm) in (A) reflectedwhite light (500×)with pre-oil solidbitumen homogenous form, and (B) backscattered SEM (dark gray; 15,000×; OPL 1371). The organic matter does not contain nanopores.
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network, the post-oil solid bitumen network may be discontinuous(e.g., speckled and wispy) or continuous (e.g., connected) based ontotal organic carbon content and available porosity. Lewan (1987) ob-served that the (post-oil solid) bitumen network occurs in amorphousType II kerogen-rich shales. We are in agreement with Lewan (1987,p. 128) that “Impregnation of the groundmass with [pre-oil solid] bitu-men to form a continuous network appears to be a prerequisite for theexpulsion of generated oil.” The pervasive post-oil solid bitumen resi-due left behind during primary oil migration provides nanoporositysites for hydrocarbon storage andmicrofracture permeability and path-ways for hydrocarbon production.
5. Summary and conclusions
Primary oilmigration in shales leaves behind a solid carbon residue inavailable porosity that we describe as a post-oil solid bitumen network.Development of the network is dependent on kerogen-type and total-organic-carbon content. This study reports the development of a post-oil solid bitumen in one of the most recognized conventional hydrocar-bon source rocks in North America. The Woodford Shale lithofacies are
Fig. 9. (A) Microfracture development (possibly caused by sample handling) along post-oil so(1.67% VRo) condensate well in backscattered SEM (5000×; OPL 1373) demonstrates preferr(~2–5 μm) post-oil solid bitumen network (dark gray) in backscattered SEM (20,000×; OPL 13
broadly characterized as Type II kerogen assemblages. The initial devel-opment of unconventional reservoirs focused on Paleozoic rocks but fur-ther work on a wider range of kerogen types is needed to assess theproposed concept of post-oil solid bitumen networks more broadly.The network is recognized in our Type II kerogen-rich Woodford Shalesamples in reflected white light at 500× magnification as speckled(~1–2 μm), wispy (~2–5 μm), and connected (N5 μm) forms. (The sizesare relative and should not be considered specific.) Speckled and wispyforms are mostly isolated occurrences in the rock rather than as a con-nected network. The speckled post-oil solid bitumen network is nearthe magnification limit of the light microscope (~1–2 μm) and is usedmostly as a presence or absence indicator of oil generation and primaryoil migration. The small size should not be confused with clay minerals.Speckled and wispy networks often both occur in the same rock. Thepost-oil solid bitumen shapes and sizes that form a network are con-firmed and best viewed in backscattered scanning electron microscopeimages.
The post-oil solid bitumen networks in theWoodford Shale demon-strate: (1) that the rock has generated oil; (2) that oil has migratedthrough the rock; (3) that secondary nanoporosity, developing
lid bitumen network from Woodford Shale cuttings sample of highest thermal maturityed zones of weakness within bitumen for fracture formation; (B) Nanoporosity in wispy73).
Fig. 10.Nanoporosity development at ~0.90%VRo inwispypost-oil solid bitumennetworkshown in backscattered SEM (25,000×; Woodford Shale; OPL 1398).
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beginning at ~0.9% VRo, provides storage sites for hydrocarbons;(4) that these sites are zones of weakness for the formation ofmicrofractures; and (5) that they also form migration pathways forhydrocarbons.
Acknowledgments
The authors gratefully acknowledge reviews by JosephA. Curiale andan anonymous reviewer that improved the manuscript.
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