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Cent. Eur. J. Geosci. • 3(4) • 2011 • 435-448
DOI: 10.2478/s13533-011-0042-2
Central European Journal of
Geosciences
Important Geological Properties of Unconventional
Resource Shales
Review Article
Roger M. Slatt
∗
Institute of Reservoir Characterization and Conoco-Phillips School of Geology and Geophysics,
University of Oklahoma, Norman, USA
Received 30 September 2011; accepted 18 November 2011
Abstract:
The revelation of vast global quantities of potentially productive gas and oil-prone shales has led to advancements
in understanding important geological properties which impact reservoir performance. Based upon research on a
variety of shales, several geological properties have been recognized as being common and important to hydro-
carbon production. (1) transport/depositional processes include hemipelagic ’rain’, hyperpycnal flows, turbidity
current flows, tempestites , wave-reworking, and contour currents in both shallow and deep water settings. (2)
Common shale minerals include clays, quartz, calcite, dolomite, apatite, and pyrite; organic constituents include
spores (Tasmanites), plant remains, biogenic quartz and calcite, and arenaceous foraminifera. (3) Porosity and
permeability are characteristically low with pore sizes ranging down to the nanoscale. Main pore types include
intergranular (including pores within clay floccules), porous organic matter, porous fecal pellets, and microfrac-
tures. (4) Important geochemical characteristics include organic richness (>3%), maturity (>1.1%Ro for shale
gas and 0.6-0.9% for shale oil) and type (I-IV), in addition to certain biomarkers which are indicators of bottom
water oxicity during deposition. Remaining hydrocarbon potential [RHP = (S1 + S2)/TOC] also reflects temporal
environmental changes. ’Isotopic reversals’ can be used to detect best producing areas in shale-gas plays. (5)
Lithofacies stacking patterns and sequence stratigraphy are the result of eustatic depositional history. A general
sequence stratigraphic model is presented here that highlights this commonality. (6) Geomechanical properties
are key to drilling, fracturing and production of hydrocarbons. Brittle-ductile couplets at several scales occur in
shale sequences. (7) Geophysical properties, when calibrated to rock properties, provide a means of regionally to
locally mapping the aforementioned properties. (8) Economic and societal considerations in the exploration and
development of resource shales are garnering attention. Many potentially economic shale-gas and shale-oil plays
are being identified globally. Risks and uncertainties associated with gas- and oil-rich shales include the lack of
long-term production histories, environmental concerns related to hydraulic fracturing, uncertainty in calculating
hydrocarbons-in- place, and fluctuations in supply, demand, and price.
Keywords:
shale • oil- and gas-productive • depositonal processes • shale geochemistry • shale sequence stratigraphy •
shale porosity and permeability • shale composition • shale geomechanics • resource shale economics • shale
seismic properties
©
Versita Sp. z o.o.
∗
E-mail: rslatt@ou.edu
435
Important Geological Properties of Unconventional Resource Shales
1.
Introduction
Gas- and oil-bearing shales are organically-rich, fine-
grained sedimentary rocks capable of producing commer-
cially important quantities of hydrocarbons upon artificial
fracturing. These shales typically serve as the source,
reservoir and seal of the hydrocarbons produced from
them [1]. The recent revelation of vast global quantities of
these potentially gas- and oil-productive shales has paved
the way for rapid advancements in understanding their ge-
ological properties, some of which impact – and may even
govern – reservoir performance. Because of shale’s differ-
ent, and sometimes unique physio-chemical, stratigraphic,
and production properties compared with ‘conventional’
sandstones and carbonates, the adjective ‘unconventional’
has been amply applied to their characterization. Al-
though some characteristics – such as pore networks and
geomechanical properties – are indeed different, and new
technologies are being developed to measure these dif-
ferences, other characteristics – such as depositional pro-
cesses/fabric and stratigraphic characteristics – are sim-
ilar, and conventional methodologies can be applied to
better understand shales in order to meet exploration and
production goals. The current global shale play has been
driven largely by technological advances, most notably 3D
seismic, horizontal drilling, and artificial fracturing.
This paper is a summary of important shale properties
and both the advancing and traditional knowledge that
has been gained as a direct result of shale’s economic
importance. It is based mainly upon research conducted
in the University of Oklahoma’s Institute of Reservoir
Characterization on a variety of shales, including Bar-
nett (Texas, USA, Caney (Oklahoma, USA), Eagle Ford
(Texas, USA), Fayetteville (Arkansas, USA), Haynesville
(Texas/Louisiana, USA), Horn River (British Colombia,
Canada), LaLuna (Colombia), Longmaxei (China), Marcel-
lus (Appalachian Basin, eastern USA), Monterey (Califor-
nia, USA), and Woodford (Oklahoma, USA) shales.
Figure 1.
Sedimentary features of Barnett Shale.
A.
Scanned
core showing parallel- and graded-laminations.
B.
Thin
section photomicrograph of a graded, spiculite mudstone
from lamination shown in A.
C.
Laminations within cored
interval. Gray = massive mudstone; Orange = rhyth-
mic silty claystone; Red = ripple/low angle laminated
mudstone; Blue = graded mustone; Black = claystone;
Green=spiculitic mudstone [7].
D.
Basal micro-scour sur-
face (yellow arrows) in mudstone.
E.
Scanned thin sec-
tion photograph showing low-angle cross lamination (yel-
low arrows). Published with the permission of Society of
Exploration Geophysicists, who’s permission is required
for further publication use.
2.
Shale Depositional Processes
Recent studies of sedimentary features of shales have
refuted the long-held generalization that shales are the
product of deposition in quiet water environments as
‘hemipelagic rain.’ Many shales exhibit mm/cm-scale
cross- and parallel-laminations, scour surfaces, particle
alignment parallel to bedding planes, and burrows [2–
7]
(Figure
1).
Some shales reveal a systematic fining-
upward or coarsening-upward, followed by fining-upward
grain-size pattern [8] while others display a system-
atic stacking pattern of lithofacies that indicate tempo-
ral changes in water depths, energy levels, and/or de-
gree of bottom-water oxygenation [9,
10].
From these and
other studies, a list of potential transport, deposition, and
reworking processes include (in addition to hemipelagic
rain): (1) hyperpycnal flows [5,
8, 11, 12],
(2) turbid-
ity current flows, (3) tempestites (storm deposits) and
wave-reworked deposits [6]; and (4) contourites (bottom-
hugging slope, oceanic currents) [2]. In order for clay-
sized particles to move along the sea floor by tractive
processes, as evidenced by the sedimentary structures,
they must behave in a hydraulically similar manner to
coarser grains. In fine-grained sediments, this hydraulic
equivalence is achieved through formation of ‘floccules’
or clumps of electrostatically-charged clay particles (Fig-
ure
2)
[4,
13].
Laboratory-produced mud ripples formed
from floccules [14] have provided a mechanism for trans-
porting large volumes of mud to the ocean floor by hy-
perpycnal (originating from rivers) and/or turbidity cur-
rent (originating in the marine environment) tractive flows,
rather than by hemipelagic settling [6,
12].
Tempestites
and contour currents are more apt to redistribute muds
previously deposited in the marine environment by trac-
tive processes rather than transporting them directly into
a basin.
Along with the concept of hemipelagic rain in quiet waters
is the corollary that environments of deposition must be
436
R. M. Slatt
Figure 2.
A.
Cartoon showing flocculated clay particles in the form
of ‘domains’ [4].
B.
Freeze-dried, flocculated Georgia clay
in salt water.
C.
Floccules in Pleistocene varved clay,
Great Salt Lake, Utah.
D.
Floccules in Barnett Shale.
E.
Floccules in Woodford Shale.
F.
Floccules in Eagle Ford
Shale. Scales are shown on each figure. Published with
the permission of Society of Exploration Geophysicists,
who’s permission is required for further publication use.
Figure 3.
‘deep;’ this is supported by the fact that many shales are
enriched in organic matter, indicating an anoxic environ-
ment of deposition [15]. However, anoxic waters can occur
at shallow water depths, and extensive mud deposition can
occur in shallow-marine mud banks [16].
One half foot (0.3 m) spaced, core X-ray diffraction miner-
alogy compared with mineralogy from the ECS
TM
(Elec-
tron Capture Spectroscopy) log for a 35 ft (12 m) long
cored interval of the Barnett Shale. Core description is
from [9]. Static and dynamic FMI
TM
images are on the
right side columns. Note the overall similarity in mineral-
ogy from the core- and log-based analyses, and the finer-
scale stratification (beds and laminae) shown by the image
log than by the core or mineralogy descriptions. Published
with the permission of Society of Exploration Geophysi-
cists, who’s permission is required for further publication
use.
3. Shale Composition and Fabric
(Anisotropy)
The major mineral constituents of organic-rich shales are
clay minerals, quartz (detrital), calcite, and dolomite (Fig-
ure
3),
although not all minerals may be present in any
one shale. For example, the Haynesville and Eagle Ford
Shales are enriched in calcite, whereas the Barnett and
Woodford Shales are rich in clays and quartz. Less
common sedimentary minerals include feldspar, apatite,
pyrite, and hydrothermal minerals (sphalerite, barite, etc.),
the latter of which occur in the Barnett and Horn River
Shales. These minerals are mainly clay-size (<4 µm).
Some shales, such as the Woodford, exhibit a fissility and
others, like the Montney (British Colombia, Canada), are
silty.
Organic constituents include (1) organic-walled spores
(Tasmanites); (2) plant remains (in Mesozoic and younger
shales); (3) biogenic quartz from sponge spicules, radio-
larians, and within spores; (4) biogenic calcite from coc-
cospheres, ammonites, mollusks, and fish, (5) thin-walled
gastropods and brachiopods; and (6) arenaceous, as well
as calcareous, foraminifera (Figure
4).
Both inorganic and organic constituents affect well-log
Figure 4.
A.
Ruptured and compressed
Tasmanites-cyst
organic
wall (black outline) in a clay lamination; diagenetic quartz
occurs within the cyst in the curls of the S shape. Wood-
ford Shale [7].
B. – C.
Elongate and cross sectional view
of quartz sponge spicules; interior of the spicule in C is
filled with clay. Barnett Shale.
D. – E.
Cross sectional and
elongate views of hollow coccospheres and spines. Eagle
Ford Shale.
F.
Globigerina Orbulina
(?) with some diage-
netic calcite partially filling the interior of the foraminifera.
Eagle Ford Shale.
G.
Arenaceous Foraminifera, Barnett
Shale [9]. Scales are provided for each picture. Figure
4B,
4C:
Published with the permission of American Associa-
tion of Petroleum Geologists, who’s permission is required
for further publication use.
437
Important Geological Properties of Unconventional Resource Shales
response. For example, shales enriched in organic matter
and clay minerals exhibit a relatively high gamma-ray API
log response, whereas those enriched in quartz and/or car-
bonates generally exhibit a relatively low response. Some
shales though, like the Haynesville, have both high gamma
ray and high carbonate contents.
4.
Shale Porosity and Permeability
The storage and migration of hydrocarbon molecules
through shales is complex, slow and not fully understood,
owing to the small pore size and capillary properties. It is
for this reason that almost all shales require artificial frac-
turing to obtain commercial flow rates. Peak flow rates in
horizontal wells often occur within the first month or two,
after which flow decreases rapidly and remains low, but
consistent, for several years [17,
18].
Obtaining accurate and reproducible shale matrix-
porosity and -permeability measurements by standard
techniques is difficult and debateable. Recent studies uti-
lizing Field Emission Scanning Electron Microscopy (FE-
SEM) coupled with incremental, argon(Ar)-ion milling of
shale surfaces has revealed significant ‘organo-porosity’
within kerogen (Figure
5)
[15,
19]
This porosity is gen-
erated during the organic-maturation process that accom-
panies burial and hydrocarbon generation [1]. Organo-
porosity is by no means the only porosity within shales,
nor is Ar-ion milling the only way to image pores in
shales. [13] have identified the following pore types using
FESEM and standard SEM techniques [4]
porous floc-
cules
which appear similar to laboratory-induced floccules
(Figures
2A
– F), (2)
porous fecal pellets,
with as much as
15% micro-porosity, (3)
fossil fragments
such as
Tasminites
spores (Figure
4A),
sponge spicules whose original, hol-
low central chambers may be partially or completely pre-
served after burial (Figures
1B, 4B, 4C),
coccospheres and
their spines, who’s chambers are also hollow and often
open (Figures
4D, 4E),
and foraminifera with open cham-
bers (Figure
4F)
(4) mineral grains such as pyrite fram-
boids (Figure
5B);
(5)
microchannels
within shale matrix
which probably are either micro-burrows and/or bounding
surfaces of scours or micro-sedimentary structures (Fig-
ures
1D, 1E);
and (6) fractures which occur at micron and
larger scales (Figure
5D)
[13]. Some of these pore types
– such as floccules which are common in many shales
(Figure
2)
[4,
13]
– are probably at least as important as
organo-porosity in storing and providing migration path-
ways for hydrocarbon molecules. In-place and migrating
oil droplets before and after hydrous pyrolysis treatment
have been documented for the Woodford Shale, Horn River
Shale, Eagle Ford Shale and Monterey Formation (Fig-
ure
6)
[20].
Figure 5.
A. – B.
FESEM images of Ar-ion milled surface of Silurian
Longmaxei Shale, China, showing pores within interpar-
ticle organic matter.
C.
FESEM image of Ar-ion milled
surface of Longmaxei Shale showing the internal pyrite
crystals within two pyrite framboids. Organic matter with
nanopores occurs between crystals.
D.
FESEM image of
mineral surfaces of Woodford Shale. Note the parallelism
of fractures that developed when tensile stress was ap-
plied to rock. Figures A.-C. from [47]. Published with the
permission of American Association of Petroleum Geolo-
gists, whose permission is required for further publication
use.
Figure 6.
A-B.
SEM images of oil droplets produced from the Wood-
ford Shale during hydrous pyrolysis experiments where
samples were heated to 350
◦
C for three to four days. Re-
published with permission of the Gulf Coast Association
of Geological Societies (GCAGS), who’s permission is re-
quired for further publication use
A.
Oil droplet emerging
from pore in matrix after three days.
B.
Oil droplet in mi-
crofracture after four days.
C.
Oil droplets squeezing out
of two places in a shale and into a diatom frustule after hy-
drous pyrolysis. Monterey Formation [20].
D.
Coalesced
oil droplets within diatom spines after hydrous pyrolysis,
Monterey Formation.
E.
Oil within coccolith chamber af-
ter hydrous pyrolysis, Eagle Ford Shale.
F.
Oil droplet in
shale matrix (not generated by hydrous pyrolysis) by white
arrow, Horn River Shale. All surfaces were broken per-
pendicular to bedding. Figure 6A: Published with the per-
mission of American Association of Petroleum Geologists,
whose permission is required for further publication use.
438
R. M. Slatt
5.
Geochemistry
Conventional geochemical characterization of resource
shales includes assessment of the rock’s organic richness
(i.e., total organic carbon – TOC), quality (e.g. visual kero-
gen analysis, hydrogen index – HI), and maturity (e.g.,
Tmax, vitrinite reflectance, etc.) to estimate quantity and
type of generated hydrocarbons. From ROCK-EVAL anal-
ysis, prolific gas-shale systems are usually characterized
by high organic richness (usually
>
3% TOC) and HI val-
ues
>350
mg HC/gm of rock. TOC values generally follow
the same trend as gamma-ray log response, with higher
TOC rocks exhibiting a higher API gamma-ray count. Of
the various common visual kerogen types (Types I-IV),
many of the shales contain Type II kerogen (oil prone)
or Type II/III (oil/gas prone) kerogen. Organic maturity as
measured by vitrinite reflectance (Ro) is usually 0.6-0.9%
Ro for shale oil and
>1.1%
Ro for shale gas. Thickness of
organic-rich strata is quite variable, but generally
>
200 ft
(65 m); thicker rocks have reduced expulsion efficiencies
so that more hydrocarbons are retained during initial gen-
eration, thus preserving TOC for deeper and later burial
maturation and generation.
Geochemical biomarkers are very useful indicators of oxic
or anoxic bottom water conditions of mud depositional en-
vironments.
Steranes
can be used to differentiate marine
from terrestrial organic source material. The presence
of
Gammacerene
in sediments indicates elevated salin-
ity [21].
Eukaryotic biomarkers
within the extractable por-
tion of shales are indicators of paleoenvironments. For
example, the upper, relatively more quartz-rich part of a
Woodford Shale core contains higher concentrations of
eu-
karyotic biomarkers
such as
C
29
steranes
than occurs in
the lower, more clay- and organic-rich part of the core,
implying oxygenated waters in the former and anoxic wa-
ters in the lower part (Figure
7).
As another example,
[22] suggested that variations in the pristane/phytane ra-
tio (Pr/Ph) and C
13
-C
20
regular isoprenoids measured in
Barnett Shale core extracts are associated with changes
in redox conditions as well as variations in terrigenous in-
put during deposition. Molybdenum (Mo) content has also
been considered a proxy for an anoxic environment [23].
TOC and ROCK-EVAL analyses are also used for deter-
mining parameters such as: (1) amount of extractable or-
ganic material in the source rock, generally derived from
kerogen breakdown (S1 peak on a gas chromatogram), and
(2) residual kerogen (S2 peak). The S1+S2 peaks nor-
malized to TOC content of analyzed samples provide the
parameter named
remaining hydrocarbon potential
(RHP)
by [24]. Within stratigraphic intervals that have a simi-
lar burial history and are not widely separated strati-
graphically, changes in S1 and S2 reflect changes in the
Figure 7.
Geochemical biomarker trends in the Woodford Shale
from a behind-outcrop cored well in a quarry [47].
The trends are of different biomarker ratios (AIR =
(C
13
-C
17
)/(C
18
-C
22
) 2,3,6-trimethyl substituted aryl iso-
prenoids). The upper Woodford is relatively quartz- rich
and biomarkers indicate an oxic environment of depo-
sition. The middle Woodford is clay- and organic-rich
and biomarkers indicate an anoxic environment of depo-
sition [48]. Published with the permission of American As-
sociation of Petroleum Geologists, who’s permission is re-
quired for further publication use.
amount of preserved organic matter. More of organic mat-
ter will be preserved in the sediment and the S2 peak will
be larger under anoxic conditions than under oxic condi-
tions, where less TOC is preserved and the S2 peak is
smaller. Thus, the calculated RHP value [(S1 + S2/TOC)]
will be greater for sediment deposited under anoxic con-
ditions than for sediment deposited under oxic conditions.
[24] interpreted an interval which becomes increasingly
more organic-rich (increasing RHP) from its base to its
top as representing deposition during marine transgres-
sion and an interval with a decrease in RHP from the
base, upward, as representing deposition during marine
regression. For the Barnett Shale, systematic sratigraphic
fluctuations of intervals of low RHP (approximately 1.3-
1.5) and high RHP (1.6-2.2) correspond with [9]’s relative
sea-level curve, derived from independent interpretation
of lithofacies stacking patterns (Figure
8).
Those inter-
vals with a relatively high RHP tend to be organic-rich
(Figure
8).
[25] has established a similar relationship for
the Woodford Shale.
A relatively recent geochemical parameter – termed ‘iso-
topic reversal’ – offers the potential to detect the best
producing areas in shale-gas plays [26]. In mature shales,
it has been postulated that hydrocarbons generated dur-
ing the first stages of oil and gas generation are relatively
depleted in
13
C isotope compared to the original isotopic
composition of the kerogen. The early-generated hydro-
carbons that are retained in the source rock after expulsion
are cracked to gas at later stages of maturity, contributing
12
C to the gas being generated, and giving rise to the iso-
topic reversal. This reversal has now been recognized in a
439

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