1. Classification and thermal maturity of shale. Unconventional
shale gas generation: Example of the Barnett Shale, Texas.
By Ed Cunningham
Geo 202
Section 1
May15, 2015
2. 1
Abstract
Petroleum Geologist are the detectives that must piece together a depositional basin’s
thermal maturity by identification of relict structures such as faults and fracture zones along with
mineralogy that may have an effect on hydrocarbon manufacture. Laws governing organic de-
composition and thermal kinetics associated with gas are important in determination of an or-
ganic rich, shale beds’ maximum burial depth and associated thermal maturity. Examination of
the Barnett Shale gas play in Texas has developed new methods and classifications concerning
the highly variable compositions of shale formations accounting for 50% of the sedimentary rock
record.
This paper describes the structural and mineralogical compositions of the world class
Barnett Shale gas play. Advancements in thin section creation with greater magnification has al-
lowed researchers to establish new classification schemes based upon technologies that measure
accurately to nano pore size capabilities. Technological improvements distinguishing mineral
from organic carbon (Kerogen). It is at this sub microscopic dimension that decomposing carbon;
primarily marine organisms such as plankton trapped long ago within fine grained mud; released
methane gas during burial.
Someday petroleum scientists will create a shale matrix data base mapping shale for-
mations’ thickness, organic richness, thermal maturity, gas content, and reservoir quality - Li-
thology. Just as soil scientists catalogue soil types and their ability to inhibit growth. The matrix
data base map will detail the features and locations of potential economically drilled Shale gas.
3. 2
Introduction
Since the early 1900’s, the focus of hydrocarbon exploration as an energy resource was
on conventional liquid petroleum and gas source rocks that encase the Barnett Shale with lime-
stone formations deposited within a Paleozoic carbonate mud bank. Deposition as the result of
Absaroka, an epeiric sea during the Mississippian period 320 Ma. Shale or mudstone considered
to be a trap or seal rock that is impermeable. The ideal source rocks have always been Shale.
Reservoir rocks possessed the sandstone and limestone for ideal storage of hydrocarbons and wa-
ter. Dolomite compositions, a better, reservoir rock, allowing more gas to flow due to higher po-
rosity and permeability. Researchers believe the Barnett Shale reached thermal maturity during
the Permian period (Bowker, 2007).
In the past decade their as been renewed interest in shale gas exploration due to lower
cost technologies such as horizontal drilling and hydraulic fracturing. The collective desire to re-
duce the carbon footprint has directed more resources to replace oil hydrocarbons with methane
gas for our energy needs. Currently, more attention has been placed on unconventional shale gas
not only because of improvements in technology, but development of better analysis and predic-
tive modeling down to nano scale observations of the complex composition of heterogeneous
shale deposits. The ability to visualize and analyze Nano- sized space. Minute differences in po-
rosity can be calculated as functions of adsorption, absorption and diffusion of methane gas.
Both organic matter (adsorption); as well as; the varying degrees of matrix (absorption and diffu-
sion processes involved) exist due to depositional basin structural variance. The measurement of
smaller pore spaces has helped in the development of our understanding of interconnectivity and
4. 3
its effect on capillary pressure. Pore space interconnectivity provides insight into gas creation,
migration, and storage. Essentially, hydraulic fracturing transforms the seal/cap rock into the
source rock when certain conditions are met and maintained within the thermogenic oil/gas win-
dow. The methods used to identify conventional petroleum sandstone sources must be adjusted
for the heterogeneous compositions of unconventional shale gas.
This paper’s primary objective is to describe the Barnett Shale’s depositional environ-
ment that researchers hypothesize had taken place to form its structural features; as well as; high-
light some of the advances that have allowed scientists within the petroleum industry to analyze
the heterogeneous structure of fine grained shale deposits.
Figure 1. Thermal Maturity Pollastro et al., 2007
5. 4
The Barnett Shale gas reservoir is considered to be over pressurized. Explanations for this
are being tested and debated. A main problem puzzling scientists is not all basins are subsiding
thus the difficulty in determining the mechanism for compaction and compression. No subsid-
ence, no required heat flow. The activation energy necessary for the Kerogen cracking process
correlated with hydrocarbon production ceases. Some researchers(Lancaster et al.,1993) believe
it’s in place gas occurred thermogenically while others suggest relict hydrothermal fluids of
brine produced along the Ouachita fault front as a source mechanism for over pressuriza-
tion(Montgomery et al.,2005,Bowker, Jarvie, Pollastro et al., 2007).
Figure 1 displays a high concentration of high maturity gas wells indicated with black
dots aligned along the Ouachita structural front. Regional distribution of Ro values for the Bar-
nett Shale cannot be explained by present-day burial depth (Pallastro et al., 2007).Its relict struc-
tural features are primary to its classification as both expeller and retainer of hydrocarbons. A
significant structural advantage is that this shale formation possesses less natural fractures that
would become calcite cemented due to the pressure solution process reducing gas flow.
The Ellenburger Limestone encases the Barnett Shale.
Well log cores reveal the Barnett Shale formation having high angle normal faults and
graben type features throughout the Fort Worth basin. Applying Darcy’s law and basic gravita-
tional physics; these high angle faults and bounded Limestone may create the necessary pressure
gradient to maintain gas production with minimal leakage as measured within the Barnett Shale.
The faults in the central basin running North-South related to the Ouachita structural front, a ma-
jor fault. Faults associated within the productive Newark gas field within the eastern basin are
6. 5
oriented in a North-East to South-West alignment. This basin experienced thrust-fold defor-
mation during the Ouachita Orogeny within the late Paleozoic (Walper, 1982; Thompson; 1988;
Adams, 2003; Montgomery et al. 2005,2006; Pollastro et al., 2007).
Summarizing the researchers’ findings; the Ouachita front was created during conver-
gence of the North & South American plates within the early Paleozoic Era. Later mud, lime-
stone and sand were deposited. Deposits consist of about 4000–5000 ft (1200–1500 m) of Ordo-
vician– Mississippian carbonates and shales. Dependent upon Carbon weight % and type under
increasing pressure/temperature change, due to sediment burial, the gas is created, migrates, and
then stored.
Bowker (2007) makes this observation; most shale contain a high concentration of clay
minerals; conversely, the Barnett and many of the other productive shales do not. In prospecting
for Barnett type shales, prospectors must look for rock that can be fractured. The shale that ex-
hibits a low enough concentration (generally less than 50%) of clay minerals allows it to be suc-
cessfully fracture stimulated. These types of shales were mostly deposited in restricted areas and
only during specific geologic time intervals; e.g., the Devonian–Mississippian Antrim Shale of
Michigan or the subject Barnett Shale (Bowker, 2007). Black petroliferous mudstone and the lo-
cal presence of glauconite, phosphatic material, and Pyrite indicate slow deposition under reduc-
ing conditions, particularly in the basal part of the Barnett Shale in the Fort Worth Basin (Mapel
et al., 1979; Pollastro et al., 2007). A diagram of the Barnett Shale mineralogy detailed in
Figure 2. It reveals an ideal shale gas play structure with the correct composition of quartz and
calcite. Possessing less than 50% clay making it brittle to extract gas in the most efficient man-
ner.
7. 6
Figure 2.Barnett Shale Mineralogy Diagram, Jarvie et al., 2007
A review of figure 3 details the following observations; higher Total Organic Carbon
(TOC) accompanying a low clay composition along with higher matrix porosity produces the
highest volumes of gas-in-place. Comparison between northern & southern regions of the Bar-
nett Shale Play distinguishes richer Kerogen calculations averaging VRo > 0.8% within the
northern tier with southern regions averaging VRo< 0.7% possessing a clay rich, silica poor ma-
trix (Loucks et al.; 2009). The highest TOC average porosity 5.5% measured in red within the
Newark East field figure3. Estimates include a 25% water saturation within the shale matrix. It’s
important to note that pre-lithified shale or mud; before compaction and dewatering; is water sat-
urated sediment thus providing the necessary hydrogen for methane gas manufacture. Generally,
TOC varies between 0.4%- 10.6%; averaging 4% within the Barnett Play categorizing it carbon
rich. The southern region’s temperature and pressure range considered within the low end of the
8. 7
Hydro-Carbon window.
Figure 3.
Map of higher Vitrinite Reflectance % (Red-Gas) Versus Lower VR0 (Green-Oil)
Pollastro et al., 2007
Thermally immature Barnett Shale contains mostly oil-prone type II kerogen,
algal organic matter. Initially, the formation generated oil and associated gas directly
from the kerogen (Ro < 1.1%), whereas gas produced from within the formation in the
Newark East field and surrounding areas probably formed later by secondary cracking of
oil and bitumen (Jarvie et al., 2001, 2005, 2007) at higher thermal maturity (Ro > 1.1%).
9. 8
Organic-matter Type & Thermal Maturity (CH4)
Table 1: Kerogen Types (Modified After Boyer et al., 2006)
Type I Type II Type III Type IV
Lacustrine/Marine
Algal/Planktonic matter
Rich H: Low O2
Oil generation
Not Common
0.6% < V Ro < 0.8%
Deep Marine
Reducing Environment
Primary Plankton remains
Algal & herbaceous matter
High H: Low C
V Ro > 1.1%
pyrite common
Oil/ Wet Gas generation
progressive heat &
maturation
Terrestrial Plant debris
woody/coal matter
Lower H: Higher O2 than
both types 1 & 2
Dry Gas generation
V Ro > 1.5%
Residual Organic matter
High C: No H
“Dead Carbon”
No Hydrocarbons
Not a Source Rock
V Ro < 0.6%
Immature Kerogen
Most current shale-gas reservoirs had their origin as organic-rich mud. These sediments could
have been deposited in the marine environment, in lakes, or in associated swamps along the mar-
gins of lakes or seas. The type of organic matter deposited, and preserved in the mud is depend-
ent upon depositional environment. Evidence of carbonate debris flows pictured in a Barnett core
sample figure 4.Carbon isotopes extracted from Barnett cores were correlated with surrounding
oil field cores matching them as the source for the oil generation. Organic geochemists (e.g. Tis-
sot & Welte, 1984,Montgomery et al.,2005); have used hydrogen-to-carbon and oxygen-to-car-
bon ratios to describe the various types of organic matter (kerogen) in organic-rich mudstones
that have generated much of the oil and gas that resides in conventional reservoirs worldwide.
Primary kerogen cracking occurs between temperatures of 800 and 1800C (176 and 3560F), for
10% and 90% conversion, respectively, based on kinetic data and average heating rates (Jarvie
11. 10
Figure 4. Barnett Shale Lithology Carbonate Mud Debris Flow top view.
Bottom view of rip-up clasts. Bowker, 2007
12. 11
Large scale generation of hydrocarbons mostly from the Barnett Shale source rock in the
Bend arch–Fort Worth basin resulted in the migration and accumulation of oil and gas into both
conventional and unconventional reservoirs of Paleozoic age (Pollastro,2007). Thus making the
Barnett shale petroleum resource a world class; all-in-one; source, reservoir, trap rock.
New Methods: Problems Reduced thru Technologic Advancements
Shale Matrix Permeability
The development and enhanced upgrades of technologies such as Field Emission Scanning
Electron Microscopy (FESEM), X-Ray Diffraction (XRD), and Infrared Reflectance (IR) have
contributed to improved accuracy in identification of clay, lithic mineralogy, and organic matter
fraction or TOC (Total Organic Carbon %).All signatures of methane CH4 production. Well log
data from bore wells are the traditional porosity, permeability, capillary pressure means of anal-
yses. How to measure accurately porosity and permeability is a challenge for scientists. It ap-
pears there is no standard accepted method. Analysis can be calculated either by % weight or %
volume. Using Volume% calculations equate to about twice the weight % TOC, but impacting
volume by as much as 4 times if the original organic matter converts 50% of its volume to pore
space, figure 5 (Passey et al., 2011). The inter connectivity of pore space traditional viewed mi-
croscopically; now available nanoscopically. Pore formation directly related to the Kerogen to
hydrocarbon conversion process.
13. 12
Recent advancements in higher resolution in Field Emission Scanning Electron Micros-
copy (FESEM), as well as; reduced errors that occur within thin section preparation afford Geol-
ogists better understanding of these micro processes (Slatt, 2011). Normal thin sections created
from crystalline rocks encounter problems with adhesives failing having grains drop out creating
false identification of minerals seeing the glass slide where mineral grains should have been.
Giving a false indication of an opaque mineral. Also thin sections must be made to a thickness of
30 microns in order to reduce light distortion. Below and above this threshold creates color dis-
tortion misidentifying minerals under microscope. Since shale matrix is very fine grained the dif-
ficulty creating thin sections are compounded. FESEM assists in overcoming associated light
distortion difficulties of analyzing 3 dimensional space with higher resolution adaptations in-
vented since 1970.
Complementing higher resolution FESEM is Focused Argon Ion Beam milling (FIB)
which has reduced thin section errors allowing these researchers to better define the interrelation-
ships between pore formation, Nano pore distribution, and fluid flow in mud rocks(Slatt,2011).
Identification of Kerogen types based upon vitrinite reflectance (V Ro) and their relationship to
gas generation will determine thermal maturity within the gas/oil window (Boyer, 2006). Separa-
tion of mineral and Kerogen type are important in defining matrix permeability. Higher tempera-
tures and pressures are required to produce gas versus oil (Boyer, 2006).
14. 13
Figure 5.Comparison of Current TOC Wt. % versus Original TOC Volume %
Schematic representation (Passey et al., 2011)
Analytical characterization of shale-gas rocks numerous geochemical and petro physical
techniques have been developed to characterize organic-matter-rich source rocks. Although most
techniques were developed to characterize thermally mature source rocks in the oil-generation
window, the same techniques can be applied, sometimes with modification, to the shale-gas class
of unconventional reservoirs that currently exhibit maturities much higher than the onset of over
maturity (i.e., Ro>1.1). Typical sample analytical techniques mentioned previously also include:
adsorbed gas analysis, vitrinite reflectance (Ro), detailed core description, thin section petrogra-
phy using Argon Ion Milling and (FESEM) pictured in figure 6. These results are combined with
a full suite of well logs, including high resolution and borehole imaging logs, to best characterize
these heterogeneous formations. Mineralogical varies widely in Shale-Gas Reservoirs (Passey,
2010).
15. 14
Figure 6.Slatt & O'Brien, 2011
Modifying the Klinkenberg method allowed researchers to measure pore diameters within
the range 1µm > pore diameters > 10-3 µm. Shale matrix permeability measured in milli
(mD)& nano Darcys (nD).Conventional Darcy flow rate was calculated proportional to water
pressure gradient. The modified method is altered to measure gas flow rates proportional to
capillary pressure gradient considerably smaller in magnitude. The FESEM technology compli-
mented with Argon-Ion milled surfaced thin sections produces high resolution images capable of
measuring a permeability range 10-3 m D >K>10-3 nD (Slatt & Obrien,2011). Some geoscientists
believe greater than 50% of the Barnett Shale gas-in-place is stored in its matrix porosity
(Bowker, 2003, 2007).
16. 15
Nanoscopic Pore Space Analysis
Figure 7: High Resolution Petrographic Thin sections revealing Nano sized Pores within shale
matrix, Loucks et al., 2009
The processes of Kerogen cracking and subsequent gas production occurs within nano sized
(10-9) space. Therefore, scientists must develop high resolution petrography in order to better
locate commercial levels of methane gas. Difficulties of calculating and measuring free versus
absorbed gas overcome due to technologies seen in figure 7 displaying field views ranging from
17. 16
500 nm down to 20 nm. Note the columnar joints seen within nano pores pictured Figure 7B
(scale view 100nm across).
Figure 8.Loucks et al., 2012
The modified pore size classification diagram, figure8, further details the complexity and scale
of shale formations. Note that the molecular sizes for methane (0.38nm) and water (0.28nm) fall
within the smallest pore size class < 1 nm or Picopore. The gas process starts at the smallest di-
18. 17
mension. The ability for gas to flow or remain in place (storage) will depend upon the intercon-
nectivity measured at the nano, micro, meso, and macropore dimensions. All pore sizes corre-
lated to natural fracturing, as well as, the hydraulic fractured stimulation process.
Free & Adsorbed Gas
The difficulties associated with accurately measuring porosity and permeability are com-
pounded further by counter balancing factors. Shale formations may have calculated low ab-
sorbed gas, but a mitigating factor such as bed thickness can counter act the poor quality low ab-
sorption rate (Curtis, 2002).Assisting scientists with these difficult calculations are current meth-
ods that analyze mud and gamma radiation logs; detecting precipitation of uranium within a re-
ducing environment along with chromatographic gas sensors backed up by formation cuttings
dried & sieved. Difficulties exist separating the gas species. New methods account for total gas-
in-place (GIP) defined as the free gas volume taken up by adsorbed gas attached to organic mat-
ter. Older methodology considered void space measured by porosity and absorbed mass meas-
ured by experimentation only (Ambrose et al., 2010). Total gas-in-place =Pore space & fractures
gas = Interstitial gas + adsorbed gas. Another complication to the process is the three ways in
which gas is stored.
1) Free gas stored in natural fractures
2) Sorbed gas stored in the shale matrix onto Kerogen & Clay surfaces
3) Gas dissolved in Kerogen/Bitumen
19. 18
Figure 9. Ambrose et al., 2010
Conclusions
Although the Barnett Shale Play’s capacity to supply large economic volumes of gas con-
tinues for the past 10 years. Questions about its thermal history remain. The evidence is strong for
hydrothermal brine as the heat source for continued gas generation versus the biogenic gas hy-
pothesis.
Researchers look to the creation of a Shale Matrix Data base describing % Total Organic Carbon
(TOC) with percentages of clay, limestone, and quartz, as well as, pyrite catalogued. The mineral-
ogy shale matrix data base would map and identify signature compositions, such as, < 50% clay
composition useful in locating similar restricted basins for hydrocarbon resource extraction. In
addition, Kerogen type and degree of fractures along with shale bed thickness would be listed.
Another contribution to the data base would be the Pore space classification detailing interconnec-
tivity of gas migration and storage. The Shale Matrix data base could provide better predictive
20. 19
modeling indicating regions of high porosity and permeability. The unintended consequence of
which may help to establish improvements in water resource acquisition and protection. The Bar-
nett Shale gas formation is the standard by which all future unconventional gas plays will be ex-
amined.
21. 20
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