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Journal of Earth Science, Vol. 26, No. 2, p. 285–294, April 2015
Printed in China
DOI: 10.1007/s12583-015-0524-0
ISSN 1674-487X
Methods for Shale Gas Play Assessment: A Comparison between
Silurian Longmaxi Shale and Mississippian Barnett Shale
Songqi Pan*1, 2, Caineng Zou1, 2, Zhi Yang2, Dazhong Dong2, Yuman Wang2, Shufang Wang2,
Songtao Wu2, Jinliang Huang2, Qun Liu2, Dule Wang3, Ziyuan Wang1
1. School of Earth and Space Sciences, Peking University, Beijing 100871, China
2. Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083, China
3. Southwest Petroleum University, Chengdu 610500, China
ABSTRACT: Based on field work, organic geochemical analyses and experimental testing, a
six-property assessment method for shale gas is proposed. These six properties include organic matter
properies, lithofacies, petrophysical properties, gas content, brittleness and local stress field. Due to the
features of continuous distribution over a large area and low resource abundance in shale plays, a sweet
spot should have these following properties: (a) TOC>2%; (b) brittle minerals content (>40%) and clay
minerals (<30%); (c) Ro (>1.1%); (d) porosity (>2%) and permeability (>0.000 1 mD), and (e) effective
thickness (30–50 m). Applying these criteria in the Sichuan Basin, the Silurian Longmaxi shale consists
of four prospecting sweet spots, including blocks of Changning, Weiyuan, Zhaotong and
Fushun-Yongchuan. Although these four blocks have some similarities, different features were usually
observed. After comprehensive analyses using the six-property assessment method, the Fushun-Yongan
Block ranks the most favorable sweet spot, followed by the Weiyuan Block. For the other two blocks,
the Changning Block is better than the Zhaotong Block. By comparing with the Mississippian Barnett
shale, characteristics that are crucial for a high-yielding in the Sichuan Basin include a high content of
organic matter (TOC>2.5%), a moderate thermal maturity (Ro=0.4%–2%), a high content of brittle
minerals (quartz: 30%–45%), a high gas content (>2.5 m3t-1), and types I and II1 kerogen.
KEY WORDS: shale gas play, Silurian Longmaxi shale, Barnett shale, sweet spot, six-property
assessment.
0
INTRODUCTION
China, the world’s biggest energy consumer (Wang, 2010)
and one of the world’s largest shale gas resource holder, has set
an aggressive plan following the United States to boost its shale
gas output from near zero in 2012 to 6.5×109 m3 per year by
2015 and to (80–100)×109 m3 by 2020, or a quarter of its total
annual gas consumption (Wang et al., 2014). It has been reported recently that, in China, a total in-placed shale gas potential is 1.34×1015 m3, and the technically recoverable resource is
3.16×1014 m3, while the latter figure published in 2011 was
3.47×1014 m3 (EIA, 2013; Zhao et al., 2013). Since 2000, the
Chinese government and relevant companies have paid much
attention to the exploration and development affairs of shale
gas, and to the developing trend for shale gas in North America.
In general, the assessment of shale gas plays is a comprehensive task which depends on a combination of geological,
geochemical, geophysics and engineering studies with ad*Corresponding author: [email protected]
© China University of Geosciences and Springer-Verlag Berlin
Heidelberg 2015
Manuscript received June 18, 2014.
Manuscript accepted January 15, 2015. vanced technology. Geological analyses have been considered
to be a fundamental and important way in shale gas plays (Zou et
al., 2013a, b). Besides, it also needs persistence and risk taking.
The concept of “continuous-type petroleum accumulation” (Zou
et al., 2013a, 2012a), introduced and adopted by the US Geological Survey, was an important milestone in unconventional
petroleum geology (Schmoker, 1996), and was used in evaluating
the Barnett shale in US (Pollastro, 2007), as well as in the Sichuan Basin (Guo, 2013; Zou et al., 2012b, 2009a, b).
The Sichuan Basin has become a potential hotspot as a
shale gas play, and has been studied by many scholars in recent
years. Chen et al. (2011a) characterized the Lower Silurian
Longmaxi shale reservoir through organic geochemistry, mineralogy, petrophysics and gas adsorption; Liu et al. (2013) carried out a comparison between the Longmaxi Formation shale
and the Barnett shale, and found that the former was buried
deeper, and has higher degree of thermal maturity, lower gas
content, higher density, and more quartz of terristrial origin.
Huang et al. (2012a) revealed the shale gas generation and
potential of the Lower Cambrian Qiongzhusi Formation in the
Sichuan Basin by examining its regional distribution, geochemical and reservoir characteristics, as well as gas content of
organic-rich shale. Focused on the Longmaxi Formation in
Changxin 1 well, Chen et al. (2013) found that the development
Pan, S. Q., Zou, C. N., Yang, Z., et al., 2015. Methods for Shale Gas Play Assessment: A Comparison between Silurian Longmaxi
Shale and Mississippian Barnett Shale. Journal of Earth Science, 26(2): 285–294. doi:10.1007/s12583-015-0524-0
286
of micro-pores of marine shale gas reservoir are controlled by
lithofacies, diagenetic evolution and the types of kerogen; Li et
al. (2013) presented six key parameters, including richness of
organic matter, single layer shale thickness, burial depth of the
shale, maturity, petrophysics, and brittle mineral content, to
evaluate the Longmaxi shale reservoir; Hao et al. (2013) discussed the mechanisms of shale gas storage and the major risks
or uncertainties for shale gas exploration in China, and took the
Lower Silurian organic-rich shale as a case study to analyze its
resources potential.
Although many scholars have studied and evaluated the
Longmaxi shale in the Sichuan Basin from various ways, there
is a lack of an effective and systematic method, like such six
aspects as generating, reserving, sealing, migrating, accumulating and preserving in conventional petroleum system analysis, to make an assessment for shale gas plays. Applying a
six-property assessment as a key method (Zou et al., 2014), the
purpose of this paper is to evaluate shale plays in the Sichuan
Basin, especially shale gas sweet spots, and then discuss the
content of each property using the Longmaxi shale as a case
study, and finally, make a comparison between the Longmaxi
shale and the Barnett shale from these six aspects.
1
GEOLOGICAL FRAMEWORK
The Sichuan Basin, located in the southwestern China, is
one of the large-scale sedimentary basins, and an important
area of natural gas production in China. The Sichuan Basin
belongs to the stable part of Yangtze Platform, and experiences
two major basin-forming stages from Sinian to Mid-Triassic
Craton, and Late-Triassic to Cenozoic terrestrial foreland basin
(Huang et al., 2012b).
During the Sinian Period, marine organic-rich shale and
marine-terrestrial carbonaceous shale widely formed in southern China, northern China and Tarim area. During later reformation process, most of Sinian marine shales experienced
strong deformation or uplift except for the Sichuan Basin,
northern China and Tarim Basin, which only experienced few
structural movements and have a good preservation condition.
In the Early Silurian, the Upper Yangtze located in the
middle of three major palaeohighs: Leshan-Longnüsi, Qianbei
and Jiangnan, and connected with Qinling from the north. This
structural framework has formed a semi-closed marine basin.
The Sichuan Basin, as a part of backbulge of the Yangtze foreland basin, formed three deep-water continental shelves as
North east Sichuan, East Sichuan-West Hubei and South Sichuan, and developed a set of organic-rich black shale (Liang et
al., 2009, 2008; Guo et al., 2004; Wan and Xu, 2003; Wang et
al., 2002; Zhai, 1989). Due to the Caledonian movement, the
Longmaxi shale was uplifted and eroded resulting in a loss of
northwestern part of the Sichuan Basin. Thus, the shale is
gradually thickening to north and east around Leshan-Longnüsi
Paleohigh, reaching 400 to 600 m at most. The thickness of
Longmaxi Formation shale is 50 to 600 m except for an absence in the southeastern part of Weiyuan structural belt, while
the thickness of black shale is the same as that of Longmaxi
Formation.
Songqi Pan, Caineng Zou, Zhi Yang, Dazhong Dong, and et al.
2
METHODOLOGY
All experiments are carried out in the Laboratory of Petroleum Geology at Research Institute of Petroleum Exploration and Development in Beijing, PetroChina.
2.1
Organic Matter Properties
In this study, source rocks are mainly examined from TOC
(total organic carbon), thermal maturity (Ro) and types of kerogen, respectively followed by GB/T 19145-2003 determination
of total organic carbon in sedimentary rock, SY/T 5124-2012
method of determining the reflectance of vitrinite in sedimentary
rock, and SY/T 5125-1996 method of determining maceral group
composition of kerogen and its classification in transmitted light
and fluorescent light microscopy.
(1) TOC: About 10 g sample was smashed into 0.2 mm
particle diameter, and after depleting inorganic carbon from
sample by diluted hydrochloric acid, we put the sample in muffle furnace fully burned in oxygen-flow to convert organic
carbon into carbon dioxide, and then total organic carbon can
be measured by infrared detector.
(2) Ro: Thermal maturity analysis of organic shale is carried
out by reflected light microscopy on polished blocks of either
solid lumps of shale or of grain mounts. The later have been prepared from shale samples crushed to less than 1mm and set in an
epoxitype resin to give a polished surface area of approximately
4 cm2. Semi-automatic point count methods are applied by advancing the sample by equal steps on the microscope stage and
recording the material at a suitable reference point in the
graticule fitted to the ocular. In order to enhance contrast, oil
immersion objectives are generally employed to prevent stray
reflections, and illuminated with monochromatic light (546 nm,
in the green region of the visible spectrum). Points are no less
than 300. Vitrinite reflectance values (Ro) can be generally applied in assessing thermal maturity in types II and III kerogen,
but cannot be used for Type I kerogen because vitrinite is absent.
However, liptinite fluoresce under blue/UV light and the fluorescence is characterized by its intensity and wavelength, which can
be used as a maturity indicator (Killops and Killops, 2009).
Therefore, the two sets of measurements (i.e. vitrinite reflectance
and fluorescence measurements) are complementary.
(3) Types of kerogen: Traditionally, three general types of
kerogen are distinguished, types I, II and III by determining maceral group composition of kerogen in transmitted light and fluorescent light microscopy. After recognizing these four maceral
groups i.e. liptinite group, exinite group, vitrinite group and inertinite group, a type-index (TI) has been introduced to make a
classification for types of kerogen (Chen et al., 2007)
TI=(liptinite%×100+exinite%×50–vitrinite%×75–inertinite%×100)/100
According to TI, kerogen can be divided into these following
groups: Type I, Type II1, Type II2, and Type III (Table 1).
2.2
Lithofacies
Shale thin sections are prepared by SY/T 5913-2004 rock
thin section preparation, and nomenclature and description are
carried out based on SY/T 5368-2000 thin section examination
of rock.
Methods for Shale Gas Play Assessment: A Comparison between Silurian Longmaxi Shale and Mississippian Barnett Shale
Table 1
Types
Type I
Type II1
Type II2
Type III
The classification of kerogen
(Chen et al., 2007)
TI
>80
40–80
0–40
<0
2.3
Petrophysical Properties
Pores are studied based on SY/T 5162-1997 analytical
method of rock sample by scanning electron microscope, including types, size, texture and cement. The porosity and permeability are determined by CMS automatic rock analyzer and
helium pores detector followed national standard SY/T
6385-1999 the porosity and permeability measurement of core
in net confining stress using boyle’s law, and darcy’s law for
unstable flow.
2.4
Gas Content
The gas content is the standard volume of gas per unit
weight of rock. The use of this standard volume per weight
convention rather than a standard volume of gas per volume of
rock resulted because shale gas content measurements originally refer to coalbed methane gas content estimating (Gas
Research Institute of USA, 1996). According to GB/T
19559-2004 method of determining coalbed methane content,
shale gas content comprises these three parts, measuring desorbed gas content, estimating lost gas content and estimating
in-situ gas content.
(1) If desorption tests are performed properly, either pressure or conventional core samples can yield accurate estimates
of the gas content. Regardless of the type of the test used, samples must be desorbed at reservoir temperature.
(2) The direct method, based on the solution of a partial
differential equation describing constant temperature diffusion
from a sphere originally at constant, uniform concentration, is
the most widely used method for estimating lost gas volume
(Saulsberry et al., 1996).
(3) The residual gas most commonly refers to the gas that
remains in the shale once conventional desorption tests have
been terminated, and can be determined by measuring the gas
released from the core sample after crushing to a minus twenty
mesh particle size in a sealed ball mill.
2.5
Brittleness
We value the brittleness as an important criterion for
evaluating the shale because it determines the shale’s fraccability and exploiting potential. Due to the shale’s ultra-low permeability, almost all shale gas production is based on the use of
hydraulic fracturing techniques, so that the fraccability is crucial for shale gas development. Consequently, we employed
three parameters to evaluate the characteristics of shale brittleness as the content of brittle minerals, the Young’s modulus,
and the Poisson’s ratio.
X-ray diffraction (XRD) can be used to distinguish clay
and non-clay minerals, especially quartz, calcite, dolomite, etc..
About 1–2 g sample is crushed into 1 mm, and based on SY/T
287
5163-2010 analysis method for clay minerals and ordinary
non-clay minerals in sedimentary rocks by the X-ray diffraction,
the contents of quartz, calcite, dolomite and clay, i.e., Vqa, Vca,
Vdo and Vcl, can be tested.
Young’s modulus belongs to a group of coefficients called
elastic moduli, and is a measure of the stiffness of the shale, i.e..
the shale’s resistance again being compressed by a uniaxial
stress. Poisson’s ratio is another elastic parameter, and is also a
measure of lateral expansion relative to longitudinal contraction.
For preparation of test samples, the ISRM (international society
for rock mechanics) standards require that specimens intended
for standard rock mechanical tests are right, circular cylinders
with a length (L) to diameter (D) ratio between 2 and 3 (Kovari
et al., 1983; Brown, 1981). For cylindrical coordinates, r, θ and
z, if Δσ’r represents effective cylinder inner radial stress, Δσ’θ
represents effective tangential stress, and pc represents the confining pressure, the triaxial phase can be concluded as
Δσ’r=Δσ’θ=pc=0. Young’s modulus is then given by the slope of
the axial stress-strain curve in the triaxial phase, i.e.,
Efr=Δσ’z/Δεz, which Efr represents drained Young’s modulus,
while Possion’s ratio is given by the ratio between the slopes of
both the radial and the axial stress-strain curves in the triaxial
phase, i.e., υfr=-Δεr/Δεz, which υfr represents drained poisson’s
ratio. Δσ’z means the alteration of the effective normal stress in
z-direction; Δεz means the alteration of the normal strain in
z-direction; Δεr means the alteration of the normal strain in
r-direction (Fjar et al., 2008).
2.6
Local Stress Field
The local stress field is given by the three principal
stresses, i.e., the vertical stress σv, the major horizontal principal stress σH and the minor horizontal principal stress σh, and
three parameters, r, θ and z, giving the orientation of the principal stresses. These data are all from well logs and well tests.
All the results are based on the common assumption of a vertical-horizontal stress field, i.e., one principal stress is vertical
and the two others are horizontal. We’ve employed a stresses
difference (SD): σH–σh in this study to represent a local stress
field.
Additionally, the pressure coefficient is introduced to describe the relative pressures throughout a flow field in fluid
dynamics, and can be represented by Pf. The Pf means the pore
pressure, and Ps refers to hydrostatic pressure. If the value of
pressure coefficient is more than 1, that means the pore pressure is higher than the normal, and the zone is referred to as
overpressured.
3 RESULTS AND DISCUSSION
3.1 The Longmaxi Shale in the Sichuan Basin, South
China
The Longmaxi shale consists of four prospecting blocks,
i.e., Changning, Weiyuan, Zhaotong and Fushun-Yongchuan, in
the Sichuan Basin. Although they are locating in the same
Sichuan Basin, each of them has its own unique features, and
varies significantly with each other.
According to Zou et al. (2014), in the Changning Block,
the shale spreads as a gentle anticline in around 1 300 km2 with
3.09×1011 m3 recoverable resources, and its current burial depth
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Songqi Pan, Caineng Zou, Zhi Yang, Dazhong Dong, and et al.
Figure 1. Sketch map of the Sichuan Basin showing regional tectonics and isopachs of the Silurian Longmaxi shale (modified
from Huang et al., 2012b).
is 2 000 to 3 000 m. In Weiyuan, the shale, extending as a gentle
anticline, covers almost 1 200 km2 with 3.6×1011 m3 potential
resources, and buried from 1 300 to 3 700 m. The Zhaotong and
Fushun-Yongchuan blocks, however, locate in slight syncline
areas, and extend approximately 1 500 and 3 500 km2, respectively. Since the vast extension of the Fushun-Yongchuan Block,
its recoverable shale gas is much more than that of Zhaotong
Block (1.1×1011 m3) as 0.99×1012 m3. Besides, the
Fushun-Yongchuan Block (3 200 to 4 500 m) buried deeper
than the Zhaotong (900 to 2 200 m).
Another important criterion in evaluating the continuous
unconventional shale gas is the gas abundance. Since this shale
is characterized by distributing continuously over a large area
(Zou et al., 2013a), we’ve presented the gas abundance of these
four target blocks as follows: the Changning area (2.38×108
m3km-2), the Weiyuan area (3.00×108 m3km-2), the Zhaotong
area (0.73×108 m3km-2) and the Fushun-Yongchuan (2.83×108
m3km-2). In spite of these general features of the four blocks,
their six-property also varies vastly.
3.1.1
Organic matter properties
In order to evaluate these properties effectively, we mainly
focus on the following aspects: types of kerogen, thickness,
total organic content (TOC) and Ro. Generally, the kerogen of
these four blocks is all types I and II1, indicating a liquid- and
gas-prone.
In the Changning, the thickness of shale is around 40 to 60
m, the TOC varies from 1.9% to 7.3% with a mean of 4.0%,
and its Ro ranges from 2.3% to 2.8% (a mean of 2.5%) indicating an over-maturity stage. In the Weiyuan, the thickness of
shale is 26 to 50 m, and except for the TOC (an average of
2.7% ranging from 1.9% to 6.4%) being less than that of the
Changning, its organic maturity is similar to that of the
Changning at 2.7%. In the Zhaotong, the thickness of shale is
ranging from 30 to 40 m, and the shale is characterized by its
average TOC of 3.2% (ranging from 1.6% to 4.9%) as well as
its Ro is from 2.1% to 3.0%. In the Fushun-Yongchuan, the
shale is thicker than other blocks as 60 to 120 m, and TOC is
ranging from 1.6% to 3.8% with a mean of 3.8%, while the Ro
is 2.5% to 3.0%.
3.1.2
Lithofacies
The term of “shale” as a name is misleading since the
lithofacies of the Longmaxi Formation is not just comprised of
shale but mudstone, like most of the “Barnett shale” is a mudstone rather than shale (Loucks and Ruppel, 2007). But here,
we adopt the term of “shale” to represent both “shale” and
“mudstone” in lithologic description and in the general discussion of the play type.
The lithofacies of Longmaxi Formation in these four
blocks does not vary significantly. In the Changning Block,
the strata are mainly composed of siliceous and
calcareous-siliceous shale with a little clayey siliceous shale.
The formation in the Weiyuan Block is the same as that in the
Changning Block except for bearing more clayey siliceous
shale. Besides, the lithofacies both in the Zhaotong and
Fushun-Yongchuan blocks is the same, which can be depicted
with siliceous shale and calcareous-siliceous shale with a little
clayey siliceous shale (Figs. 2a–2d).
3.1.3 Petrophysical properties
The petrophysical properties of shale are very different
from ordinary petroleum reservoirs which refer to sandstone
strata with relatively high porosity and permeability compared
to that of shale. The estimated pore-size distributions from the
volumes show that smaller pores with radii approximately 3 to
6 nm dominate in number but do not necessarily dominate in
total pore-volume contribution (Curtis et al., 2012; Loucks et
al., 2009), and are characterized by its complex texture and vast
inner surface areas. Thus, porosity and permeability are the
Methods for Shale Gas Play Assessment: A Comparison between Silurian Longmaxi Shale and Mississippian Barnett Shale
major controlling factors for gas-bearing and gas-developing in
shale (Zou et al., 2011). Compared to conventional petroleum
which stored in micrometer pores, shale gas is a kind of
nano-petroleum which needs a unique evaluating method to
work out its accumulating rules (Figs. 2e, 2f). Marine
organic-rich shale has developed nanopores broadly in China,
which contains intergranular, intragranular, and organic matter
pores (Zou, 2013; Zou et al., 2012c).
The porosity and permeability of the Longmaxi shales
vary slightly in different areas. In the Changning area, we
found that the porosity varies from 3.4% to 8.2%, with an
289
average of 5.4%, whereas the permeability is 2.2×10-4 to
1.9×10-3 mD with its mean of 2.9×10-4 mD. The results in the
Weiyuan indicate that the porosity in shale is 3.9% to 6.7%
with a median of 5.3%, and the permeability is ranging from
1.5×10-5 to 9.0×10-5 mD, which the average value is 4.2×
10-5 mD. In the Zhaotong area, the porosity has a median of
5.0% and ranges in value from as low as 2.6% to lower than
7.9%, as well as the permeability is featured by the range of
4.3×10-3 to 4.2×10-2 mD with an average value of 1.9×10-2 mD.
Finally, in the Fushun-Yongchuan area, the value of porosity is
from 3.0% to 7.0% with an average of 4.2%, and the
Figure 2. Photomicrographs of the Longmaxi shale. (a) SEM photo showing authigenic calcite in the Longmaxi shale; (b)
SEM photo showing cubic pyrite; (c) thin section of siliceous-silty shale in Changning Block, quartz is dominant in this sample, whereas the amount of carbonate is minor, the white particles show quartz which is the dominant mineral in this section,
Longmxi Formation: Ning 201, 2 505.19–2 505.22 m; (d) thin section of siliceous-silty shale in Weiyuan Block, Longmaxi
Formation: Wei 201, 1 379.40 m; (e) SEM photo showing the rounded pores in organic matters, black organic-rich shale of
Longmaxi Formation: Wei 201 (after Zou, 2010); (f) SEM photo showing some nano-pores spreading in illite and pyrite.
Black organic-rich shale of Longmaxi Formation: Changxin 1 (after Zou et al., 2010).
290
Songqi Pan, Caineng Zou, Zhi Yang, Dazhong Dong, and et al.
permeability has a mean value of 2.3×10-4 mD and ranges from
1.9×10-4 to 2.7×10-4 mD.
3.1.4 Gas content
Gas content is a crucial parameter for indicating the content of free, adsorbed, and dissolved gas, and determining
whether the target area is exploitable and economical. Currently,
the minimum shale gas content for commercial development in
North America is approximate 1.1 m3t-1, and the highest value
is 9.91 m3t-1 (Zou, 2013). Generally, the organic matter and
clay minerals control the maximum volume of adsorbed gas,
while some free gas is mainly relevant with matrix pores.
For gas content, we have three values for all the blocks
except the Fushun-Yongchuan Block. For the Changning, gas
content in shale varies from 1.7 to 6.5 m3t-1, with an average of
4.1 m3t-1. For the Weiyuan, gas content has an average value of
2.92 m3t-1 and ranges from 2.74 to 5.01 m3t-1. For the
Zhaotong, the value of gas content is ranging from 0.6 to 5.8
m3t-1 with an average of 2.3 m3t-1.
3.1.5
Brittleness
The four blocks enjoy their own features respectively, and
each of them has a significant outlook for the brittleness. In the
Changning Block, the shale is mainly comprised by quartz
grains (26% to 68% with an average of 41%) and clay minerals
(10% to 53% with an average of 31%), as well as other minerals like feldspar, calcite and dolomite, which the former one
accounts for average 5% and the latter two account for almost
21%. In the Weiyuan area, the shale has an average quartz content of 33% ranging from 17% to 58%, a lower feldspar content
of 7% (from 3% to 18%), a clay minerals content of 34% (from
15% to 49%), as well as an allied content of calcite and dolomite ranging from 4% to 65% with an average of 22%.
In the Zhaotong area, the average contents of quartz,
feldspar, and clay are 40% (from 24% to 54%), 4.5% (from 4%
to 5%), and 32% (from 23% to 42%), respectively, and the
allied content of calcite and dolomite is 22% (from 0 to 44%).
Moreover, the values of Young’s modulus and Poisson’s ratio
for these four blocks are also different with each other. The
values of the two parameters for the Changning area range
from 0.86×104 to 4.10×104 MPa, and 0.10 to 0.25, respectively,
while the values for the Weiyuan area are slightly different:
they are ranging from 1.30×104 to 1.36×104 MPa, and 0.18 to
0.19, respectively. Compared with that for the Zhaotong area
(from 1.80×104 to 3.40×104 MPa, and 0.17 to 0.24, respectively), the values of Young’s modulus and Poisson’s ratio for
the Fushun-Yongchuan area are ranging from 2.40×104 to
3.70×104 MPa, and from 0.20 to 0.27.
3.1.6 Local stress field
Today, nearly all shale gas is produced by horizontal wells,
and the drilling direction is perpendicular to the direction of
maximum horizontal principal stress. In additional, the hydraulic fracturing process may generate a complex fracture network,
while local stress field may contribute to the development of
network in shale which can provide enough space for shale gas
migrating. Therefore, the development of artificial hydrofrac-
tures is determined by both the present-day maximum horizontal stress, which controls the direction of hydraulic fracture
propagation, and the geometry of the natural fracture system,
and is crucial for effective hydraulic fracture treatment design
(Gale et al., 2007). Therefore, we employed two quantitative
parameters as the pressure coefficient and the SD, and a descriptive extent of natural fractures to examine the characteristics of ground stress for the shale.
The four blocks have their own characteristics of stress field,
and they vary vastly from each other. The Changning area is
characterized by its well-developed natural fractures, and the
pressure coefficient and the SD range from 1.35 to 2.03 and 21.4
to 22.3 MPa. The Weiyuan area, characterized by fair developed
natural fractures, experiences its pressure coefficient ranging
from 0.92 to 1.77, and the SD ranging from 16.6 to 18.3 MPa.
The same to the Weiyuan area, the descriptive extent of natural
fractures in the Zhaotong area is fair developed, but its values of
the pressure coefficient (1.00) and the SD (from 7.5 to 9.0 MPa)
are different from that of the Weiyuan area. Finally, in the
Fushun-Yongchuan Block, we found that its natural fractures are
well-developed, and the pressure coefficient is from 2.00 to 2.25
without any experimental value of the SD.
3.2
Marine Shale in the Fort Worth Basin, United States
According to EIA, the number of wells drilled nationwide
in the US that produces both oil and natural gas from shale
formations increased from 37% in 2007 to 56% in 2012, and
steep legacy production decline rates are being offset by growing production from new wells (EIA, 2014). Six shale plays
account for nearly all domestic natural gas production growth
over the last few years, and the Marcellus play accounts for
about 25% of natural gas production growth (Fig. 3).
The Barnett shale is an organic-rich, petroliferous black
shale of Middle–Late Mississippian age in the Fort Worth Basin, long recognized as a probable source rock for hydrocarbons throughout north-central Texas (Montgomery et al., 2005).
Compared to marine shales in China, the Barnett shale, buried
in greater depth at higher pressure, characterized by entirely
thermogenic in origin, and underwent a complex, multiphase
thermal history, is unique and acts as a model for the global
shale gas industry.
For the Barnett shale, we also employed the six-property
assessment method to evaluate the characteristics of the shale,
and then make a comparison with the Longmaxi shales. The
Barnett shale lies at depths of 1 891 to 2 591 m with recoverable resources of 12 461×108 m3 (Montgomery et al., 2005;
Curtis, 2002), extends about 13 000 km2 covering a gentle anticline and slope (Ground Water Protection Council, 2009), and
has a resource abundance of 0.96×108 m3km-2. Moreover, the
Barnett shale has its own features in six aspects as: In terms of
source rocks characteristics, the thickness of the shale varies
from 30 to 183 m through a basin-scale with a mean TOC value
of 4.5% (Curtis, 2002), and the type of kerogen for the Barnett
shale as compared with that for the Longmaxi Formation is
mainly oil-prone Type II kerogen indicating its thermal immaturity (Pollastro et al., 2007). Besides, the shale has experienced lower thermal maturity as 1.0% to 1.3% (Curtis, 2002).
Methods for Shale Gas Play Assessment: A Comparison between Silurian Longmaxi Shale and Mississippian Barnett Shale
291
Figure 3. Map showing regional extent of the Barnett shale, thickness of the Barnett shale in selected wells and generalized
regional isopachs of the Barnett shale (modified from Pollastro et al., 2007).
The lithofacies of the shale is dominated by fine-grained
(clay- to silt-size) particles including nonlaminated to laminated siliceous mudstone, laminated argillaceous lime mudstone (marl), and skeletal, argillaceous lime packstone (Loucks
and Ruppel, 2007). In terms of outcrop investigation, the Barnett shale has been described as black shale on the Llano uplift
in San Saba County, Texas (Papazis, 2005).
For the petrophysical properties, the shale has a total porosity value as low as about 4% to a greatest of 5%, and the
average permeability is generally less than 0.001 mD (Curtis,
2002). Compared to the Longmaxi Formation, the gas content
for the Barnett shale ranges from 8.5 to 9.9 m3t-1(Zou et
al., 2014), and at reservoir PVT (pressure, volume, temperature)
conditions (at 6% porosity, 70 ºC, and 26.2 MPa), a maximum
storage of 4.96 m3t-1 is possible (Jarvie et al., 2007).
The brittleness of the shale is determined by the ratio of
brittle minerals to clay contents. In this conditions, quartz,
feldspar, and an allied content of calcite and dolomite play as
brittle minerals accounting for 45%, 7%, and 8%, respectively;
whereas, clay minerals including illite and minor smectite are
27%, additionally containing other minerals like pyrite (5%),
siderite (3%), and organic matter (5%), with trace amounts of
native copper and phosphatic minerals (Bowker, 2003). Besides,
the other two parameters for evaluating the brittleness are
Young’s modulus and Poisson’s ratio, which ranges from
1.37×104 to 2.12×104 MPa and from 0.12 to 0.22, respectively
(Zou et al., 2014).
Finally, for the local stress field, the pressure coefficient
and the SD varies from 0.90 to 1.01 and 3.7 to 4.7 MPa (Zou et
al., 2014). According to Gale et al. (2007), two sets of natural
fractures are present in the Fort Worth Basin as an older
north-south-trending set and a dominant, younger, westnorthwest-east-southeast-trending set. Cements in the
fractures are not generally templated onto grains in the wall
rock, and the fractures act as planes of weakness that can reactivate (Gale et al., 2007).
4
COMPARISON
Many scholars had made a comparison between the Silurian Longmaxi shale and the Mississippian Barnett shale (Liu et
al., 2013; Huang et al., 2012b; Chen et al., 2011b). Based on a
comparison in such five shales in the United States as the Ohio
shale, Antrim shale, New Albany shale, Barnett shale and
Lewis shale, the author drew a conclusion that such five characteristics are crucial for a high-yielding shale as a high abundance of organic matter (TOC>2.5%), a moderate thermal maturity (Ro: 0.4%–2%), a high content of brittle minerals (quartz:
30%–45%), a high gas content (>2.5 m3t-1), and types I and II1
kerogen. Although the shale in the Sichuan Basin is much
similar with that in Fort Worth Basin, there are some differences between these two (Fig. 4).
The Longmaxi shale is buried deeper than the Barnett
shale, and has experienced a higher thermal maturity. The deep
depth contributes to the difficulty of gas development and the
292
Songqi Pan, Caineng Zou, Zhi Yang, Dazhong Dong, and et al.
5
Figure 4. A comparison between the Sichuan Basin shale
and the Barnett shale showing differences in organic matter
properties (thickness, TOC and Ro), petrophysical property
(porosity), gas content, brittleness (Poisson’s ratio and
Young’s modulus), and local stress field (pressure coefficient and stresses difference). Some parameters are applying the average value of maximum and minimum.
CONCLUSION
This paper is about the theoretical understandings of
six-property assessment for shale plays evaluation, and reveals
its effectiveness and scientificity utilizing in the Sichuan Basin
Longmaxi shale. It also points out that, due to the features of
continuous accumulation over a large area and orderly enrichment, some favorable shale zones must be distinguished from
shale-bearing basin in order to carry out further economically
feasible exploitation, and several important features of a shale
gas sweet spot are critical when considering how to plan these
sweet spots.
Based on the six-property assessment analysis for the
Longmaxi shale in the Sichuan Basin, organic-rich shale
mainly locates at the bottom of strata with an increasing sandy
content, a gradual lightening and a decreasing TOC value upward. The Longmaxi shale was in a low maturity stage (its Ro
ranging from 0.5% to 0.7%) at the end of the early Permian, in
a hydrocarbon generating peak (its Ro ranging from 0.9% to
1.1%) at the end of Triassic, in a humid gas and condensate oil
generating stage (its Ro>1.3%) at the end of the Early Jurassic,
and in an over-maturity stage at now.
As one of the most potential plays in shale gas development in China, the Sichuan Basin has experienced multi-stages
studies, and become a key area for promoting the shale industry.
From a geological perspective, the Longmaxi shale has a similarity with the Barnett shale in many aspects except for its deep
burial and relative low porosity and permeability rate. By applying six-property assessment, this paper raises a method to
illustrate the relationships among every parameter in evaluating
a shale gas play, and provides a reference and an inspiration
when carrying out further research.
ACKNOWLEDGMENTS
We’d like to express our appreciation to two anonymous
reviewers for their comments and suggestions, and the editors
for their hard work. This study is financially supported by the
National Basic Research Program of China (No.
2014CB239000) and the China Major National Scientific and
Technological Project (No. 2011ZX05018-001).
Figure 5. Mineral composition of Longmaxi Formation
shale showing a comparison with that of shale in the United
States (after Huang et al., 2012a).
high cost of drilling and hydrofracturing, and leads to a high
thermal maturity which results in a decrease in gas content.
Moreover, the TOC of the Longmaxi shale is lower than that of
the Barnett shale, indicating that more organic substance is
crucial for gas content and storage.
Although the quartz and carbonate contents of the Longmaxi shale are similar to those for the Barnett shale (Hao and
Zou, 2013; Huang et al., 2012b) (Fig. 5), the quartz in the
Longmaxi shale mainly comes from land sources while that in
the Barnett shale is biogenesis. The quartz particles not only
determine the fraccability of shale in hydraulic fracturing, but
also can form a relative inflexible framework to increase the
anti-pressure ability of shale, and thus, help to preserve the
residual organic micropores in shale.
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