2. particulate kerogen networks under SEM backscattered electron mode
and concluded that conventional light microscopy is needed to properly
identify organic matter. Recent application of backscattered scanning
electron microscopy of the Barnett Shale by Loucks et al. (2009) recog-
nized the importance of organic matter in shale as an important source
of microporosity, but only described the material as “organic matter”. As
pointed out in the present article, much of this organic matter occurs as
an organic network. Loucks et al. (2012) recognized the importance of
the 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 this
paper is to describe the occurrence, origin, and significance of the or-
ganic network found in organic-rich shales. We show that this network
may 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 many
terms: bitumen, pyrobitumen, asphalt, asphaltite, asphaltic pyrobitumen,
solid bitumen, solid hydrocarbon, migrabitumen, reservoir bitumen, dead
oil, and exudatinite (Abraham, 1960; Curiale, 1986; Hunt, 1979; Jacob,
1989, 1993; Landis and Castaño, 1994; Taylor et al., 1998). The term
solid bitumen, following Curiale (1986), will be used in this article.
A common generic classification of solid bitumen (primarily
fracture-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 vein
deposits) for amorphous, secondary macerals dispersed in rocks and
taking on the shape of voids. Curiale (1986, p. 559) developed a simple
genetic 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-liquid
oil”). It is widely recognized that (pre-oil solid) bitumen forms from
kerogen (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 as
asphaltite (soluble) and asphaltic pyrobitumen (insoluble). These
fracture-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 discussed
below, post-oil solid bitumen can also be any alteration of a once-liquid
oil into a solid, including the dispersed solid residue of oil migration.
Therefore, the genetic solid bitumen classification of Curiale (1986) will
be 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 solid
bitumen network as an amorphous kerogen in strewn slides.
Pre-oil solid bitumen and post-oil solid bitumen can appear similar to
vitrinite in reflected white light at 500× magnification. Hackley et al.
(2013) concluded that vitrinite reflectance measurements of early mature
Devonian shale may erroneously include solid bitumen lower reflectance
values. Landis and Castaño (1994) identified three types of solid bitumen
(homogenous, granular, and coked). In addition to distinguishing
vitrinite-like bitumen to exclude from the vitrinite-reflectance analysis,
homogenous solid bitumen reflectance values may be used to calculate
a vitrinite reflectance equivalent (VRE; Landis and Castaño, 1994). The
VRE value may be used as a thermal maturity indicator when vitrinite is
not present or to verify the vitrinite-reflectance value. Distinguishing
solid bitumen from vitrinite is more easily accomplished in whole-rock
particulate pellets than in kerogen-concentrate pellets.
3. Methods
Type II kerogen-rich (oil generative organic matter) marine Woodford
Shale (Late Devonian–Early Mississippian) samples from Oklahoma, USA
covering 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 Vickers
M17 Research Microscope system equipped with a Smith illuminator
(Cardott, 2012). The samples (Table 1) are from the Organic Petrography
Laboratory (OPL) of the Oklahoma Geological Survey. A coal stringer sam-
ple (OPL 1387) from a Woodford Shale core was used to determine the
thermal maturity whereas the shale sample in the same core was used
to visualize the post-oil solid bitumen network. An outcrop sample (OPL
1300) did not show signs of weathering (Lo and Cardott, 1994). The pre-
dominant form of silica in the quartz-rich Woodford Shale is biogenic sil-
ica formed from radiolarians (Cardott and Chaplin, 1993). Core, outcrop,
and well cuttings samples that were recognized in reflected white light
to contain post-oil solid bitumen forms or amorphous organic matter
groundmass were selected for examination by scanning electron micros-
copy (SEM). Core, outcrop, and larger chips from cuttings were initially
prepared by mechanical polishing. The samples were then ion milled in
a Fischione Model 1060 ion mill using Argon gas. Milling was performed
with the sample rotating under two crossing ion beams at 5 kV accelerat-
ing voltage for 3 h. The elevation of the ion beams was 2° above the sam-
ple horizontal. Ion beam milling provides a very flat surface for imaging
and preserved the microstructure of the samples with minimal artifacts.
Previous work has shown that even with higher energy focused ion
Table 1
Woodford Shale samples used in this study arranged by increasing vitrinite reflectance.
OPL numbera
Sample type County Geologic province Depth (m) Latitudeb
Longitudeb
VRo (%)c
n VRo range (%)
1300 Grab Murray Arbuckle Mountains Surface 34.444411 −97.130651 0.53 31 0.45–0.67
1333 Core Pottawatomie Cherokee Platform 1395 34.99476 −97.05175 0.59 50 0.50–0.70
601 Core Marshall Ardmore Basin 926 34.05082 −96.64148 0.62 24 0.48–0.77
1371 Cuttings Coal Arkoma Basin 1939 34.64914 −96.39634 0.76 30 0.66–0.88
1366 Cuttings Coal Arkoma Basin 1900 34.650283 −96.356129 0.85 35 0.76–1.01
1372 Cuttings Coal Arkoma Basin 2125 34.67924 −96.36197 0.89 27 0.74–1.07
1398 Core Washington Cherokee Platform 512 36.43725 −95.92348 0.90 29 0.82–1.02
1397 Cuttings Johnston Ardmore Basin 2525 34.173551 −96.792293 0.98 26 0.85–1.10
1076 Core Okfuskee Cherokee Platform 1126 35.33143 −96.08535 1.23 48 1.10–1.47
1402 Cuttings Carter Ardmore Basin 3812 34.287887 −97.072195 1.31 24 1.19–1.45
1387 Core of coal stringer Canadian Anadarko Basin 3809 35.66829 −98.301331 1.62 50 1.51–1.74
1373 Cuttings Coal Arkoma Basin 2556 34.562946 −96.230753 1.67 23 1.38–1.99
a
Oklahoma Geological Survey Organic Petrography Laboratory sample number.
b
NAD 83.
c
Random vitrinite reflectance in non-polarized light with fixed stage.
107B.J. Cardott et al. / International Journal of Coal Geology 139 (2015) 106–113
3. 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 undergone
ion milling suggesting that pores exist naturally in the organic matter of
some samples. Samples were imaged in a FEI Helios Dual Beam FIB/SEM
using backscattered electrons (BSE) for atomic number contrast. The
accelerating 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 white
light in whole-rock pellets by their texture (e.g., homogenous, granular,
and coked), semi-translucent character with internal reflections from
imbedded pyrite, and by the pyrite that occurs on their edges (Fig. 1;
ASTM, 2011).
In addition to amorphous blobs of pre-oil solid bitumen and
fracture-filling post-oil solid bitumen, small pieces of organic matter
filling voids are recognized under reflected white light at 500× magni-
fication. Others have recognized this network, although not using the
terminology we use here. Mahlstedt and Horsfield (2012) referred to
post-oil solid bitumen as a carbon-rich pyrobitumen (“pore-occluding
petroleum”) that can undergo secondary cracking to gas and conden-
sate at N1.1% VRo. Landis and Castaño (1994) described residual solid
hydrocarbons occurring as intergranular pore fillings (b10 μm). The
void-filling occurrence of this material suggests that it is the solid resi-
due of primary oil migration (e.g., post-oil solid bitumen). The term
post-oil solid bitumen, as we use it here, has no inference for solubility.
Three post-oil solid bitumen forms are recognized in reflected white
light 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 and wispy are mostly isolated occurrences in the rock rath-
er than as a connected network. The speckled post-oil solid bitumen
network, where it occurs, is near the magnification limit of the light mi-
croscope (~1–2 μm) and is used mostly as a presence or absence indica-
tor of oil generation and migration. Speckled post-oil solid bitumen
must be carefully distinguished from clay minerals. Speckled and
wispy 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 solid
bitumen network (Fig. 3). Speckled and wispy forms are easy to see
but difficult to photograph in reflected white light (500×) because of
focus issues and interference from pyrite. The post-oil solid bitumen
shapes and sizes that form a network are confirmed and best viewed
in BSE images. BSE imaging is sensitive to the atomic number of the
sample material. This results in the low atomic number organic matter
(mostly carbon) appearing dark gray whereas higher atomic number
minerals such as quartz, carbonates, and pyrite exhibit progressively
higher grayscale values (Figs. 4–5). Belin (1994) noted that even
though 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 described
here, Bernard et al. (2012b, p. 7) recognized the speckled and wispy
post-oil solid bitumen network by using scanning transmission X-ray
microscopy and transmission electron microscopy of the Barnett
Shale. Similar to what we see in the Woodford Shale, their work indicat-
ed that “Organic matter appears as micron sized angular organic grains
irregularly distributed within the mineral matrix or as organic masses
filling intergranular porosity and exhibiting smoothly curved concave
surfaces.”
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 migration
occurs in a 3D kerogen network. However, the occurrence of secondary,
amorphous dispersed organic matter filling voids suggests that this
organic matter was once a liquid, and thus not kerogen. The pervasive
nature and relationship with fracture filling bitumen indicate that it is
post-oil solid bitumen. The mechanisms of primary oil migration
through a kerogen network proposed by McAuliffe (1979) hold true
for a post-oil solid bitumen network. Much of the generated oil does
not migrate out of the rock. Meyer (2012, p. 72) indicated that “for
every barrel of crude oil in conventional reservoirs … there are 8 bbl
of potentially producible oil equivalents remaining in the source rock”
and “Speculative estimates of just how much generated oil remains in
shale 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 residual
oil of Fan et al., 2012). Hunt (1996, p. 597–598, see references within on
p. 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 maturity
Type II kerogen-rich shales and boghead coals is amorphous organic
matter (AOM) (Mastalerz et al., 2012; Thompson-Rizer, 1993). This pri-
mary maceral, AOM, is derived from degraded, unidentifiable precursor
organisms (Pacton et al., 2011). AOM is equivalent to the term
bituminite (ASTM, 2011). Lewan (1987) reported that amorphous
Fig. 1. (A) Homogenous texture in semi-translucent pre-oil solid bitumen (dark gray material in center of photomicrograph) showing internal reflections from pyrite (reflected white light,
500×; whole-rock particulate pellet; Woodford Shale; OPL 1333; 0.59% VRo). (B) Granular texture in pre-oil solid bitumen (reflected white light, 500×; whole-rock particulate pellet;
Woodford Shale; OPL 1076; 1.23% VRo). Solid bitumen classification is modified from Curiale (1986) and Landis and Castaño (1994).
108 B.J. Cardott et al. / International Journal of Coal Geology 139 (2015) 106–113
4. Type II kerogen comprised N80 vol% of isolated kerogen from Woodford
Shale samples in Oklahoma. There are several classifications of AOM.
Thompson and Dembicki (1986) recognized four types of AOM related
to 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 and
D) is considered a source of pre-oil solid bitumen and oil. AOM is best
recognized using strewn slides in transmitted white light and reflected
fluorescent light at 500× magnification. The distribution of AOM in
shale forms an organic network (Figs. 6, 7). The AOM network could
be misidentified as the post-oil solid bitumen network.
Post-oil solid bitumen ultimately forms from oil generated in the oil
window. The lowest thermal maturity containing a post-oil solid
bitumen network is uncertain because it may be confused with AOM
(a primary maceral). The post-oil solid bitumen network could have de-
veloped preferentially along the AOM network. Lewan (1987) described
primary oil migration occurring along a continuous bitumen network
formed from kerogen and impregnating AOM. He described the devel-
opment of an opaque pyrobitumen 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 middle
of 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 was
generated 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 revealed
the occurrence of a network of organic matter, but also the development
Fig. 2. (A) Speckled (~1-2 μm) post-oil solid bitumen network (white arrow; reflected
white light, 500×; Woodford Shale; OPL 1402; 1.31% VRo). (B) Wispy (~2–5 μm) post-
oil solid bitumen network (white arrow; reflected white light, 500×; Woodford Shale;
OPL 1372; 0.89% VRo). (C) Connected (N 5 μm) post-oil solid bitumen network (white
arrow; reflected white light, 500×; Woodford Shale; OPL 1366; 0.85% VRo). P = pyrite.
Fig. 3. Speckled (~1–2 μm) and wispy (~2–5 μm) post-oil solid bitumen network in the
same 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 solid
bitumen network in backscattered SEM (5000×; Woodford Shale; OPL 1397e; 0.98% VRo).
109B.J. Cardott et al. / International Journal of Coal Geology 139 (2015) 106–113
5. 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 secondary
nanoporosity is related to both thermal maturity (beginning about
0.9% 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) and
Zhang et al. (2012) reported nanopore development in organic matter
N0.60% VRo. Romero-Sarmiento et al. (2013) attributed nanoporosity
development to the maturation of kerogen in the Barnett Shale begin-
ning at about 0.7% VRo. Bernard et al. (2012a) reported nanoporous
pyrobitumen (e.g., post-oil solid bitumen) in a Posidonia Shale sample
at 1.45% VRo, but no organic nanoporosity in samples at 0.5% and
0.85% VRo. Milliken et al. (2012) demonstrated that secondary porosity
develops primarily in intergranular organic matter (e.g., post-oil solid
bitumen) instead of within particulate organic matter (e.g., kerogen)
and that porosity increases with increasing total organic carbon content.
Hao et al. (2013, p. 1342) concluded that “gas sorption in organic-rich
shales is mainly associated with micropores” (b2 nm).
In addition to the biogenic-silica-rich Woodford Shale, a post-oil
solid bitumen network has also been observed in other shales, including
the Barnett, Haynesville, and Horn River shales (Curtis et al., 2012a).
Although not using the post-oil solid bitumen network terminology
used here, others have observed the network in other formations.
Bernard et al. (2012a) recognized aliphatic-rich bitumens (e.g., pre-oil
solid bitumen) and aromatic-rich pyrobitumens (e.g., post-oil solid
bitumen) in an overmature (1.45% VRo) sample of the Posidonia
Shale. Bernard et al. (2012b) recognized pre-oil solid bitumen (derived
from 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) recognized
secondary 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 predominant
pore-filling organic matter, interpreted as solid bitumen, was recog-
nized as originating as a liquid hydrocarbon. Hackley (2012) recognized
an interconnected (post-oil) solid bitumen network in whole-rock par-
ticulate pellets of argillaceous lime wackestones and mudstones of the
Lower Cretaceous Pearsall Formation. Uffmann et al. (2012) described
a (post-oil) solid bitumen network in whole-rock pellets of high ther-
mal maturity Mississippian and Pennsylvanian black shales from
Germany and Belgium. Fishman et al. (2012) did not recognize bitumen
or pyrobitumen in the Kimmeridge Clay Formation and concluded that
petroleum 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 samples
equivalent to the post-oil solid bitumen terminology used here.
Kosakowski and Krajewski (2014, their Fig. 11E) recognized a post-oil
solid bitumen network in carbonates in Poland.
Organic pores are not only sites of methane storage by adsorption to
the pore walls (Hackley, 2012; Zhang et al., 2012), but also provide mi-
gration pathways for production of natural gas. 3-D reconstructions of
Focused Ion Beam/SEM tomography samples illustrate the distribution
and connection of nanopores in the post-oil solid bitumen network
(Curtis et al., 2012b, their Fig. 8). Microfractures that connect to the
post-oil solid bitumen network can be seen in BSE images (Fig. 9a) dem-
onstrating the preferred fracture pattern following zones of weakness
through the bitumen. The microfractures (formed either naturally or in-
duced by hydrofracturing) contribute to the rock permeability. Zagorski
et al. (2013, p. 172) recognized that “The observed intraorganic porosity
displays a high degree of connectivity and is responsible for a significant
portion of the Marcellus Shale's productivity and gas in place.”
Applied to gas shales, Blood (2011, p. 56) recognized that “Organic
particles are the sites of adsorbed gas, and amorphous organic matter
and bitumen represent the dominant sites of porosity development
within the Marcellus.” As recognized by Belin (1992) for a kerogen
Fig. 5. Connected (N 5 μm) post-oil solid bitumen network (white arrow) in backscattered
SEM (2540×; Woodford Shale; OPL 1402; 1.31% VRo).
Fig. 6. Amorphous organic matter (AOM; also referred to as bituminite) groundmass (dark
gray material) in Woodford Shale marine boghead coal in backscattered SEM (800×; OPL
1300e; 0.53% VRo).
Fig. 7. Amorphous organic matter (AOM) matrix in backscattered SEM (7500×; Woodford
Shale; OPL 601; 0.62% VRo).
110 B.J. Cardott et al. / International Journal of Coal Geology 139 (2015) 106–113
6. network, the post-oil solid bitumen network may be discontinuous
(e.g., speckled and wispy) or continuous (e.g., connected) based on
total organic carbon content and available porosity. Lewan (1987) ob-
served that the (post-oil solid) bitumen network occurs in amorphous
Type 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 the
expulsion of generated oil.” The pervasive post-oil solid bitumen resi-
due left behind during primary oil migration provides nanoporosity
sites for hydrocarbon storage and microfracture permeability and path-
ways for hydrocarbon production.
5. Summary and conclusions
Primary oil migration in shales leaves behind a solid carbon residue in
available 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
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 the
proposed concept of post-oil solid bitumen networks more broadly.
The network is recognized in our Type II kerogen-rich Woodford Shale
samples in reflected white light at 500× magnification as speckled
(~1–2 μm), wispy (~2–5 μm), and connected (N5 μm) forms. (The sizes
are relative and should not be considered specific.) Speckled and wispy
forms are mostly isolated occurrences in the rock rather than as a con-
nected network. The speckled post-oil solid bitumen network is near
the magnification limit of the light microscope (~1–2 μm) and is used
mostly as a presence or absence indicator of oil generation and primary
oil migration. The small size should not be confused with clay minerals.
Speckled and wispy networks often both occur in the same rock. The
post-oil solid bitumen shapes and sizes that form a network are con-
firmed and best viewed in backscattered scanning electron microscope
images.
The post-oil solid bitumen networks in the Woodford Shale demon-
strate: (1) that the rock has generated oil; (2) that oil has migrated
through the rock; (3) that secondary nanoporosity, developing
Fig. 8. Lowest thermal maturity (0.76% VRo) Woodford Shale sample that contains post-oil solid bitumen network (connected; N 5 μm) in (A) reflected white light (500×) with pre-oil solid
bitumen homogenous form, and (B) backscattered SEM (dark gray; 15,000×; OPL 1371). The organic matter does not contain nanopores.
Fig. 9. (A) Microfracture development (possibly caused by sample handling) along post-oil solid bitumen network from Woodford Shale cuttings sample of highest thermal maturity
(1.67% VRo) condensate well in backscattered SEM (5000×; OPL 1373) demonstrates preferred zones of weakness within bitumen for fracture formation; (B) Nanoporosity in wispy
(~2–5 μm) post-oil solid bitumen network (dark gray) in backscattered SEM (20,000×; OPL 1373).
111B.J. Cardott et al. / International Journal of Coal Geology 139 (2015) 106–113
7. beginning at ~0.9% VRo, provides storage sites for hydrocarbons;
(4) that these sites are zones of weakness for the formation of
microfractures; and (5) that they also form migration pathways for
hydrocarbons.
Acknowledgments
The authors gratefully acknowledge reviews by Joseph A. Curiale and
an anonymous reviewer that improved the manuscript.
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