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Deep shale gas in the Ordovician-Silurian Wufeng–Longmaxi formations of
the Sichuan Basin, SW China: Insights from reservoir characteristics,
preservation conditions and development strategies
Haikuan Nie
a
,
b
,
*
, Zhijun Jin
b
,
c
, Pei Li
b
, Barry Jay Katz
d
, Wei Dang
e
, Quanyou Liu
c
,
Jianghui Ding
f
, Shu Jiang
g
, Donghui Li
b
a
State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Beijing 102206, China
b
Sinopec Petroleum Exploration and Production Research Institute, Beijing 102206, China
c
Institute of Energy, Peking University, Beijing 100871, China
d
Chevron CTC, 1500 Louisiana Street, Houston, TX 77002, USA
e
School of Earth Sciences and Engineering, Xi’an Shiyou University, Xi’an 710065, China
f
CNPC Engineering Technology R & D Company Limited, No. 5 Huanghe Road, Changping District, Beijing 102206, China
g
School of Earth Resources, China University of Geosciences, Wuhan 430074, China
ARTICLE INFO
Keywords:
Deep shale gas
Reservoir characteristics
Preserve conditions
Development potential
Sichuan Basin
ABSTRACT
Shale gas at a burial depth greater than 3500 m is an important potential strategic target for exploration and
development in China. Due to the complex geological and engineering settings, our understanding of the
enrichment and retention mechanisms of deep shale gas is limited, and large-scale commercial development has
not yet been realized. In this study, deep shale gas in the Upper Ordovician Wufeng Formation and Lower
Silurian Longmaxi Formation of the Sichuan Basin is systematically studied in terms of the spatial distribution of
black shale, reservoir types and properties, preservation conditions, and gas content as well as exploration and
development practices. The deep siliceous shale of the Dicellograptus complexus-Cystograptus vesiculosus biozone
exhibits high quartz content, which is conducive to the formation and preservation of effective reservoirs, thus it
is often recognized as the optimal interval for deep shale gas development. Compared with the shallower res-
ervoirs, microfractures in deep shale gas reservoirs are not developed. Also, overburden pressure and high
temperature bring about a 40 %–50 % reduction in porosity and an 80 %–90 % decrease in permeability. High
formation temperatures, large in-situ stress and high-stress difference between the horizontal stress and vertical
stress in the deep shale gas reservoirs lead to elevated shale plasticity, making it difcult to form and extend
fracture. Moreover, due to the high fracture closure pressure, proppant tend to easily break in addition to the
reduction of effective hydraulic fractures and fracture conductivity, which explains why it is difcult to effec-
tively fracture deep shale and to achieve high and stable gas production. It is recommended to establish a volume
fracturing plan (such as a long horizontal well with an increasing number of stages and perforations) for certain
deep shale gas reservoirs. Creating and optimizing reasonable production systems with excellent pressure
management procedures are also crucial to maximize deep shale gas production and ultimately realizing the
commercial development of deep shale gas.
1. Introduction
The success of the shale gas revolution in the United States (Bowker,
2007) has driven and promoted shale gas exploration and development
in China (Zhang et al., 2004). By comparing and selecting the geological
conditions of different organic-rich shale strata, shale gas exploration
has gradually focused on the Upper Ordovician Wufeng Formation and
Lower Silurian Longmaxi Formation (Wufeng-Longmaxi formations) in
the Upper Yangtze Platform, South China (Zhang et al., 2008; Nie et al.,
2009; Zou et al., 2010). In 2009, China’s rst shale gas survey well
* Corresponding author at: Petroleum Exploration and Production Research Institute, China Petroleum and Chemical Corporation (SINOPEC), No. 197 Baisha
Road, Changping District, Beijing 102206, China.
E-mail address: niehk.syky@sinopec.com (H. Nie).
Contents lists available at ScienceDirect
Journal of Asian Earth Sciences
journal homepage: www.elsevier.com/locate/jseaes
https://doi.org/10.1016/j.jseaes.2022.105521
Received 11 July 2022; Received in revised form 2 December 2022; Accepted 16 December 2022
(Yuye-1) was drilled (Zhang et al., 2010). In 2010, the rst shale gas
exploration well (Wei-201) was implemented (Dong et al., 2012). In
2012, a high-yield commercial gas ow of 20.3 ×10
4
m
3
/d was ob-
tained from the well JY1 in the Fuling area, marking the onset of shale
gas production in China (Guo and Zhang, 2014). By the end of 2020,
several shale gas elds (e.g., Fuling, Weiyuan, Wei-Rong, Yongchuan,
Changning, Wulong, Pengshui, and Zhaotong) in the Sichuan Basin and
its periphery had been discovered, and especially, three national shale
gas demonstration areas (Fuling, Weiyuan-Changning, and Zhaotong)
were established (Guo et al., 2017; Liang et al., 2020; Ma et al., 2020b;
Nie et al., 2020b; Wang et al., 2020) (Fig. 1). The cumulative proven
shale gas resources are 2.7 ×10
12
m
3
for China thus far, with shale gas
production of 228 ×10
8
m
3
in 2021. The above-mentioned shale gas
elds are shallower in burial depth (less than 3500 m), except for Wei-
Rong and Yongchuan deep shale gas elds (greater than 3500 m). There
are different depth cutoffs for dening the deep shale. For example, the
United States and Brazil generally believe that the deep oil/gas cutoff is
4500 m, while Russia and TOTAL respectively believe that it should be
4000 m and 5000 m. According to the China Geological and Mineral
Industry Standard: Regulation of shale gas resources/reserves estima-
tion (DZ/T0254-2014), China denes shale reservoirs with a burial
depth of more than 3500 m as deep shales (He et al., 2020a), due to the
signicant chanages in geomechanical properties and reservoir charac-
teristics with the increasing burial depth.
China has embarked on an intensive appraisal and exploration of
deep shale gas with some progress to date (Cao et al., 2020; Ma et al.,
2020a). Several recent deep shale gas wells (e.g., WY1, YY1 and DYA) in
the Sichuan Basin have obtained a high initial gas production, demon-
strating promising exploration prospects. Compared with the shallower
reservoirs, these deep reservoirs are characterized by: (1) burial depth
greater than 3500 m (He et al., 2020a; Ma et al., 2020b); (2) over-
pressure, with pressure coefcients between 1.5 and 2.0 (Nie et al.,
2021a); (3) porosity dominated by organic matter pores (Ma et al.,
2020b); (4) high gas content (commonly more than 6.0 m
3
/t) (Nie et al.,
2021a); (5) the low stimulated reservoir volume (SRV) (Ma et al.,
2020a), and (6) high initial production (frequently more than 20.0 ×10
4
m
3
/d), rapid production decline (generally 50 %-70 % in decline rate in
the rst year), and low cumulative shale gas production from a single
well (generally lower than 100 ×10
8
m
3
in estimated ultimate recovery
(EUR), and only 50 %-80 % of the shallower shale) (Yang et al., 2019).
There has been little commercial development of these deep shale gas
wells to date, due to the low cumulative gas production after hydraulic
fracturing and rapid production decline, as well as high costs of drilling
and completion.
Deep shale gas enrichment and high production performance are
controlled by many factors (He et al., 2020a), such as the thickness of
organic-rich shale, pore types and porosity, gas content, and rock
frackability. The great burial depth, low permeability, high formation
temperature and pressure, and high in-situ stress makes it difcult to
obtain effective fracture networks through hydraulic fracturing for deep
shale reservoir (Jiang et al., 2017b; He et al., 2019). Therefore, it is
impossible to succeed in deep shale gas exploration and development
simply by applying the experience from shallower shales.
Based on the research status and exploration practices of deep shale
Fig. 1. Regional setting and variation of burial depths of the base Wufeng Formation in the Sichuan Basin and its periphery. Sites of wells and main shale gas elds
are also shown on the map (after He et al., 2021). Note: I denotes Gulin slope, II denotes Shizhu synclinorium, III denotes Lichuan synclinorium, and IV denotes
Shizhu synclinorium.
H. Nie et al.
Fig. 2. Chronostratigraphic and lithostratigraphic columns for the Sichuan Basin (after Liu et al., 2018b).
H. Nie et al.
gas in the Sichuan Basin and its periphery, the objectives of this study
are to (1) discuss the distribution, geochemical and reservoir charac-
teristics and gas content of deep organic-rich shales; (2) analyze the
preservation condition and controlling factors of deep shale gas
enrichment; (3) investigate the relationship between high production
and hydraulic fracturing and development practice in deep shale gas;
and (4) put forward the suggestions for deep shale gas geological eval-
uation and commercial development. All these results will provide the
basis for research and evaluation of deep shale gas, and further promote
the exploration breakthrough and commercial development of deep
shale gas in China and other regions of the world.
2. Geological setting
2.1. Tectonics
The Sichuan Basin is an intracratonic basin developed on the Upper
Yangtze Craton, which contains rocks of Archean, Paleozoic, Mesozoic
and Cenozoic ages (Liu et al., 2018a) (Fig. 1). As a result of the Cale-
donian orogeny, Devonian sediments are absent and most of the
Carboniferous was eroded, with only a thin sequence of sediments (C
1
)
remaining (Jin et al., 2018). Paleozoic-Cenozoic strata are about
6000–12000 m thick, and residual Silurian strata range from 0 to 1200
m thick. Black shale is mainly developed in the Lower Cambrian, Upper
Ordovician-Lower Silurian, Lower Permian, Upper Permian, Lower
Triassic, and Lower Jurassic (Fig. 2). Shale gas has been produced from
the Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations
and has been discovered in Lower Cambrian and Lower Jurassic strata
(Sun et al., 2021).
Complex tectonic movements including the Caledonian (Late Sinian-
Silurian), Hercynian (Devonian-Permian), Indosinian (Triassic), Yan-
shanian (Jurassic-Late Cretaceous), and Himalayan (Paleo-Quaternary)
impacted the development of the Sichuan Basin (Zhang et al., 2013). It
experienced three evolutionary phases (Fig. 2), which were: (1) a marine
cratonic basin stage with main carbonate and ne-grained clastic rock
deposited (Late Proterozoic to Middle Triassic); (2) a continental fore-
land basin stage mainly composed of uvial and lacustrine sediments
(Late Triassic to Late Cretaceous); and (3) an uplift and tectonic defor-
mation stage that caused strong folding, deformation and denudation in
the basin, with only coarse clastic rock deposited in alluvial fans in the
southwest part of the basin (Late Cretaceous to Quaternary) (Liu et al.,
2018b).
The marine cratonic basin stage (Z
2d
-T
2
): during the Paleo- to Mes-
oproterozoic, the “Jinning-Sibao” movement led to the collision and
aggregation of the Yangtze and Cathaysia Platforms to form a unied
South China Plate with crystalline-metamorphic basement (Zhang et al.,
2013). The oldest sedimentary rocks in the basin consist of the Pre-
cambrian Doushantuo and Dengying formations, which were deposited
during a major marine transgression (Shi et al., 2018; Zhang et al.,
2019). During the Late Sinian-Early Cambrian, the regional weak tensile
action caused by the Tongwan tectonic movement led to the develop-
ment of the cratonic rift basin, followed by sedimentation in the
resulting depression during the Middle and Late Cambrian-Silurian (Liu
et al., 2018b). Black shale, siltstone and sandstone were mainly devel-
oped in the Lower Cambrian, while the Middle and Upper Cambrian and
Ordovician mainly consist of dolomite and limestone, followed by clastic
sediments in the Silurian (Zhang et al., 2019). The Caledonian and
Hercynian orogeny in the Late Silurian caused the uplift of the Sichuan
Basin and extensive erosion. The break-in sedimentation lasted until the
Early Permian, and only in the eastern Sichuan Basin does a limited part
of the Carboniferous sediment remain (Zhang et al., 2013). In most
areas, Permian rocks directly overlie the Silurian or older strata (Zhang
et al., 2019). Following the Dongwu tectonic movement, cratonic rift-
depression basin sedimentation occurred in the Late Permian through
the Early Triassic, and the transitional facies led to the deposition of
coal-bearing shale in the rift, and shallow-marine carbonates on the
platform (Liu et al., 2018b).
The continental basin stage (T
3
-K
2
): the Sichuan Basin changed from
a tension-fracturing state to compression-torsion during the early
Indosinian orogeny, starting in the Middle Triassic (Zhang et al., 2013).
With the formation of the orogenic belt including Longmenshan,
Micang-Dabashan and Xuefengshan on the periphery of the Sichuan
Basin, marine platform deposition ended, and continental clastic sedi-
ments of the Upper Triassic, Jurassic and Cretaceous were deposited up
to several kilometers thick, and the depositional center around the
Leshan-Longnvsi Paleo-uplift was distributed in a ring shape, with
migration from time to time (Zou et al., 2019).
The tectonic modication stage (K
2
-present): during the late Yan-
shanian and Himalayan orogenies (Late Cretaceous-Neogene), the
intense tectonic movement in the Sichuan Basin resulted in strong
faulting and folding in the thick marine and continental strata (Zhang
et al., 2013), which nally resulted in the present structural features and
framework of the Sichuan Basin (Liu et al., 2018b).
2.2. Burial depth
The burial depth of the Wufeng -Longmaxi formations in the Sichuan
Basin and its periphery varies greatly. Outside the Sichuan Basin, the
burial depth of the Wufeng Formation base is generally less than 3500
m, except for the central part of the Wulong and Baima synclines in
eastern Chongqing (Fig. 1). However, inside the Sichuan Basin, the
overall burial depth of the Wufeng Formation base is greater than 3500
Fig. 3. Graptolite biozone division of the Wufeng, Longmaxi and Nanjiang
formations in the Yangtze area (Chen et al. 2018). Note: “3a”, “3b” and “3c”
represent three subzones of the WF3; “I” represents the Wulipo Member, “II”
represents Guanyinqiao Member; “III” represents the Dicellograptus complanatus
zone; “JCG” represents Jiancaogou Formation. The age of the bottom boundary
of each zone was taken from Gradstein et al. (2012).
H. Nie et al.
Table 1
Parameter comparison of main deep shale gas reservoirs in China and North America.
Block/
shale gas elds
China North America
Weiyuan Yongchuan Dingshan–Dongxi Nanchuan–Dongsheng Jiangdong in
Jiaoshiba
Eagle Ford Haynesville Cana
Woodford
Burial depth (m) 2500–4000 2800–4200 4373–4417 3400–4555 3277 1200–4200 3200–4100 3200–4700
Typical deep
shale gas well
WY1, WYA–1 YY1, YYA DYA, DYSA NY1 JYB-3 – – –
Rock type Black shale
with
carbonate
and rich in
graptolite
fossils
Siliceous shale,
clay-bearing
siliceous shale
and clayey
shale
Black gray
carbonaceous shale,
gray-black mudstone
with carbon, and silty
mudstone
Black graptolite shale,
silty mudstone, silty
mudstone, and siltstone
with marlstone
Argillaceous
shale, with
higher sand
content relative
to the main area
of Jiaoshiba
– – –
Depositional
environment
Deep-water
shelf facies
Deep-water
shelf facies
Deep-water shelf
facies
Semi deep-water–Deep-
water shelf facies
Deep-water shelf
facies
– – –
Thickness
oforganic-rich
shale
(TOC >2 %) (m)
28.9–47.3 40.0–60.0 30.0–32.3 30.0–40.0 37.0–44.0 20.0–90.0 45.0 50.0
Thickness of shale
(U/Th >1.25)
(m)
4.0–6.0 6.0–8.0 >8.0 >8.0 >8.0 – – –
Thickness of shale
(WF2-LM4
graptolite
biozone)
(m)
0–10.0 16.5 7.5–8.6 12.6 20.0–25.0 – – –
Kerogen type I, II
1
I, II
1
I, II
1
I, II
1
I, II
1
– – –
TOC (%) 2.50–3.20 1.11–7.83 1.90–3.80 3.10–3.25 3.15 3.0–7.0 3.0–5.0 6.0–12.0
R
o
(%) 2.4–2.6 2.2–2.5 2.0 1.8–2.5 2.4–2.8 0.6–1.8 1.2–3.0 –
Quartz content (%) 58.3 46.0–52.8 57.1 63.1–65.7 56.0–74.4 14.0–35.0 15.0–20.0 48.0–74.0
Carbonate content
(%)
15.2–20.5 6.5–9.2 5.1–10.2 3.5–8.0 3.5–6.0 20.0–50.0 40.0–90.0 <20.0
Total clay content
(%)
26.9–35.2 27.7–42.2 35.8–43.6 18.5–45.2 16.5–41.6 – – –
Porosity (%) 4.70–7.40 2.21–10.34 4.50–6.00 3.80–4.40 3.67 43.0–7.00 8.00–12.00 5.00–8.00
Natural fractures Relatively
developed
Well-developed
in the anticline
area but less
developed in
the north area
(Imaging
logging)
Generally developed
in high-angle
fractures, especially
in the middle-
upper strata
Relatively developed Well-developed
(stratum broken)
– – –
Vein type of
natural fractures
Calcite vein Calcite/quartz
vein
Calcite/ quartz/
dolomite vein
Quartz/
calcite vein
Quartz/
calcite vein
– – –
Homogenization
temperature of
vein (℃)
170.25 181.10 177.36 189.07 – – – –
Vein-uid activity
time
– Paleocene and
Eocene
Paleocene, Eocene,
Oligocene
Middle-late stage of the
Late Cretaceous to the
Early Paleogene
– – – –
Gas reservoir
temperature (℃)
– – 133 104–140 – – – –
Formation
pressure (MPa)
70.4–77.5 74.0–77.0 65.0–77.5 55.7–77.8 56.1 – – –
Pressure
coefcient
1.8–2.0 1.7–2.1 1.7–1.9 1.1–1.3 1.4 1.4–1.8 1.9 1.6
Young’s modulus
(GPa)
21.6 19.9–31.8 32.3 32.0 29.1 – – –
Poisson’s ratio 0.23 0.19–0.23 0.20 0.19 0.22 – – –
Vertical principal
stress (MPa)
89.1 94.1–105.8 118.0 119.0 93.3
Minimum
horizontal
principal stress
(MPa)
54.0–69.6 82.3–100.8 76.1–79.3 100.0–115.0 75.8 – – –
Maximum
horizontal
principal stress
(MPa)
70.0–88.3 99.1–121.7 82.5–85.6 122.0–140.0 – – – –
Horizontal stress
difference
(MPa)
11.0–16.0 7.4–25.4 27.0 10.0–12.0 7.0–8.5 4.0 <10.0 5.7
Gas composition
(methane
content) (%)
97.8 >95.0 98.7 98.0 – – – –
(continued on next page)
H. Nie et al.
m, except for the basin margin and anticlines within the basin, such as
the edges of the northeastern, eastern and southern Sichuan Basin, the
high-steep anticline belt of eastern Sichuan Basin, and the periphery of
paleo-uplifts in the basin. The area with burial depth less than 3500 m
and greater than 3500 m is about 63000 km
2
and 128000 km
2
, and the
areas with a burial depth of 3500–4500 m and areas deeper than 4500 m
are 55000 km
2
and 73000 km
2
, respectively (Fig. 1).
3. Samples and methods
3.1. Isochronous shale strata
This study is aimed to evaluate the deep organic-rich shale from the
perspective of isochronous strata. Using graptolites, the Wufeng-
Longmaxi formations have been divided into thirteen biozones,
including Dicellograptus complanatus biozone, Dicellograptus complexus
biozone, Paraorthograptus pacicus biozone, Metabolograptus extra-
ordinarius biozone, Metabolograptus Persculptus biozone, Akidograptus
ascensus biozone, Parakidograptus acuminatus biozone, Cystograptus ves-
iculosus biozone, Coronograptus cyphus biozone, Demirastrites triangulatus
biozone, Lituigraptus convolutus biozone, Stimulograptus sedgwickii bio-
zone and Spirograptus guerichi biozone (Chen et al., 2015; Chen et al.,
2017) (Fig. 3). The abbreviated codes are WF1, WF2, WF3, and WF4 in
the Wufeng Formation, and LM1, LM2, LM3, LM4, LM5, LM6, LM7, LM8
and LM9 in the Longmaxi Formation, respectively. Of these, the LM1-
LM4 sections are equivalent to the organic-rich “hot shale” of the Mid-
dle East and North Africa (Chen et al., 2018). This study analyzed the
shale thickness of different graptolite biozones in the deep-water facies
based on the formation of isochronism and global stratigraphic corre-
lation. Graptolite identication and graptolite biozone thicknesses in the
Wufeng-Longmaxi formations were determined in more than 20 wells
(Fig. 1).
3.2. Organic geochemistry and petrophysics
In this study, total organic carbon (TOC) content was determined
using a Leco C230 carbon analyzer. Samples were weighed before the
addition of hydrochloric acid to dissolve carbonates. After rinsing and
drying, the de-carbonated samples were reweighed and combusted at
high temperatures in the Leco C230. The thermal maturity parameters
were measured for 20 samples using an MPV-SP microphotometer under
oil immersion. Due to the lack of vitrinite and high thermal maturity of
the sample, the equivalent vitrinite reectance (EqVRo%) was deter-
mined according to the reectance of bitumen and graptolite. The
detailed calculation procedures are described by Luo et al. (2018).
Shale samples were crushed into a powder with a grain size of <150
μ
m for mineralogical composition analysis, which was performed using
a Bruker D8 Discover X-ray diffractometer. For further details, see
(Gasparik et al., 2014) and (Li et al., 2021).
Porosity and permeability under high temperature (up to 120 ℃) and
high pressure (up to 70 MPa) were conducted at the State Key Labora-
tory of Oil and Gas Reservoirs Geology and Exploitation at Southwest
Petroleum University, China. Seven groups of temperature and pressure
conditions were designed in the experiment, i.e., (10 MPa, 60 ℃), (20
MPa, 70 ℃), (30 MPa, 80 ℃), (40 MPa, 90 ℃), (50 MPa, 100 ℃), (60
MPa, 110 ℃) and (70 MPa, 120 ℃), corresponding to burial depths of
about 1000 m, 1500 m, 2000 m, 2500 m, 3000 m, 3500 m and 4000 m
respectively. The helium method and pulse-decay permeability mea-
surement were used to determine the porosity and permeability. It
should be noted that the permeability is in the direction parallel to the
bedding orientation. Before the experiment, check the core sample, put
the undamaged core sample into the triaxial stress core holder, increase
the conning pressure and temperature to the set value, record the
relevant parameters measured during the experiment, and calculate the
core porosity and permeability.
The characteristics of pore types and components in shales were
observed using Field-emission scanning electron microscopy (FE-SEM).
Physical properties (porosity and permeability) were obtained on more
than 60 samples prepared by the State Key Laboratory of Shale Oil and
Gas Enrichment Mechanisms and Effective Development at the China
Petroleum & Chemical Corporation. Specically, the shale samples were
rst prepared to have a cylindrical shape with a height and diameter of
2.5 cm, and the porosity and permeability were measured using a QK-98
Helium Porosimeter and C013 GDS-90F Helium Permeability tester at
25 ◦C and 0.07 MPa.
3.3. Measurement of shale gas content
In this work, both direct and indirect methods were used to measure
shale gas content. The direct methods measure the volume of gas
released from samples and are widely employed for obtaining shale gas
content due to the reliable and precise on-site gas desorption data
(Zhang et al., 2014). The lost gas content cannot be measured directly
and was instead estimated from gas desorption data using the USBM
Table 1 (continued )
Block/
shale gas elds
China North America
Weiyuan Yongchuan Dingshan–Dongxi Nanchuan–Dongsheng Jiangdong in
Jiaoshiba
Eagle Ford Haynesville Cana
Woodford
Gas occurrence
type
<50 %
(Adsorbed
gas)
>50 %
(Adsorbed gas)
84 %
(Free gas)
<50 % (Adsorbed gas) <50 %
(Adsorbed gas)
– – –
Gas content (m
3
/t) 2.6–8.7 1.6–8.3 2.0–5.1 5.4–6.2 3.6–6.7 6.0 12.0 –
Resource
abundance (10
8
m
3
/km
2
)
5.18 5.59 5.37 – – – – –
Damage intensity
of gas reservoir
Weak Relatively
strong
Relatively strong Relatively strong Weak – – –
Formation energy Strong Strong Strong – – – – –
Production yield
(10
4
m
3
/d)
3.4–30.1 14.1 20.0–31.0 – 9.5 – – –
Production
characteristics
High pilot production but rapid decline – – –
Flowback rate
(fracturing uid)
(%)
>20 >50 >50 >40 >30 – – –
Single-well EUR
(10
8
m
3
)
0.40–1.00 0.35–0.50 0.29–0.50 0.40–0.70 0.50–0.87 – – –
Note: “–” denotes not detected. The shale thickness of the WF2-LM4 graptolite zone in Well DYA is referred to as the adjacent Well DY1. Data of Eagle Ford, Haynesville
and Cana Woodford shale were compiled from (American Association of Petroleum Geologists and Division, 2018; Gentzis, 2013, 2016).
H. Nie et al.
method (Smith and Williams, 1984; Diamond and Schatzel, 1998). Due
to the longer drilling time and large temperature difference between the
subsurface and surface during the coring and recovery of these deep
shale gas reservoirs, more gas is lost than from the shallower samples.
The calculation of lost gas from deep shale is commonly underestimated.
Li and Nie (2019) established a new method to estimate shale gas con-
tent based on gas-bearing reservoir characterization, which has been
veried by theoretical calculation and production performance of shale
gas wells. Here this method was used to estimate the gas content in deep
shales. The indirect method generally estimates the adsorbed gas con-
tent and free gas content from adsorption isotherms and well-logging
data. The total gas content of shale can be estimated by summing the
adsorbed and free gas content (Dang et al., 2018). The high-temperature
and high-pressure isotherm adsorption tests were conducted at the State
Key Laboratory of Oil and Gas Reservoirs Geology and Exploitation at
Southwest Petroleum University, with a maximum temperature of
135℃ and a maximum pressure of 70 MPa.
3.4. Production data from shale gas wells
The data relating to the deep shale gas reservoirs, hydraulic frac-
turing, development practice and production in the Wei-Rong, Ding-
shan, and Yongchuan deep shale gas elds were obtained from Sinopec
Petroleum Exploration and Production Research Institute, Sinopec
Exploration Company, Sinopec Jianghan Oileld, and Sinopec East
China Petroleum Company.
4. Results
The black shale spatial distribution, organic and inorganic compo-
sitions, porosity and permeability, shale gas content and hydraulic
fracturing and development practice of deep shale gas reservoirs are
quite different from those of shallower ones (Table 1).
4.1. Shale spatial distribution characteristics
In this study, the thickness of the shale in the WF2-WF3 and LM1-
LM4 graptolite biozones was described by obtaining the identication
results of the graptolite biozones in more than 20 wells (Figs. 4 and 5).
The sedimentary center of the lower part of the Wufeng Formation was
formed in the Fuling-Wulong-Shizhu-Wuxi area of western Hubei-
eastern Chongqing and Yibin-Changning-Gongxian area of the south-
ern Sichuan Basin. The lithology mainly includes siliceous shale,
calcareous siliceous shale, and carbonaceous shale with a thickness of
2–6 m (More details involving the lithofacies classication and charac-
teristics can be seen in Jiang et al. 2013). Furthermore, the maximum
thickness of siliceous shale in western Hubei-East Chongqing and
calcareous siliceous shale in the southern Sichuan Basin exceeds 4 m
(Note that the thickness represents compacted rock). The deposition of
the Guanyinqiao Member (WF4 graptolite biozone) generally corre-
sponds to a large-scale regression event after the relatively deep-water
deposition of black shale in the lower part of the Wufeng Formation
(Fig. 4) (Chen et al., 2017). Generally, partial WF2-LM4 strata were
absent in the Ziliujing bathymetric high near the Central Sichuan Uplift
and the bathymetric high of western Hubei and Hunan, while the
widespread weathering crust can be seen in the northern part of the
Guizhou paleo-uplift, and western Hubei and Hunan area, indicating the
different degrees of strata absence. The deep-water deposits of the black
grayish shale containing Hirnantia during this period are only distrib-
uted in Fuling-Wulong-Shizhu-Wuxi in the eastern Sichuan-northeastern
Sichuan area and Changning-Gongxian in the southern Sichuan area.
The LM1-LM4 graptolite biozone is mainly distributed in the Yibin-
Changning-Gongxian area in the southern Sichuan Basin and the
Fuling-Wulong-Shizhu-Pengshui-Wuxi area in the western Hubei-
Eastern Chongqing. The depositional setting had a reducing deep-
water sedimentary environment, in which the surface water was an
Fig. 4. Wufeng Formation to the bottom of Longmaxi Formation black shale of
Wells WY1, N211, DY1, JY1, LYA and HY1 (see Fig. 1 for wells position). The
dashed line is the top boundary of LM4 for each shale gas well. The data on
graptolite biozones of well N211 was from Luo et al. (2017).
H. Nie et al.
oxygen-rich oxidizing environment and the bottom water was an
oxygen-decient strong reducing environment. The corresponding li-
thologies are calcareous siliceous shale and siliceous shale, with a
thickness of 5–25 m, and a maximum thickness in the depositional
center that exceeds 20 m. The thickness of the WF2-LM4 graptolite
biozone was closely related to the shale gas elds that have been
discovered, indicating that the deep-water deposition environment is
also a prospect area for the development of deep shale gas elds (Fig. 5).
4.2. Organic and inorganic compositions
4.2.1. Total organic carbon content and thermal maturity
The siliceous shale in the Wufeng Formation and the lower part of the
Longmaxi Formation (i.e. WF2-LM4 graptolite biozone) generally have
high present-day TOC content, ranging from 2.66 % to 5.12 % (average
3.60 %). The TOC content for calcareous siliceous shale, silty shale and
argillaceous shale is between 2.01 % and 3.34 % (average 2.51 %), 1.32
%–2.38 % (average 1.56 %) and 0.50 %–2.63 % (average 1.72 %),
respectively. There are two high-value areas for TOC content (Fig. 6).
One is the Yibin-Luzhou-Xuyong area of the southern Sichuan-northern
Guizhou with a TOC content greater than 2.0 %, and more than 4.0 % in
limited areas. Another is the Fuling-Wulong-Pengshui area of western
Hubei and eastern Chongqing with a TOC content greater than 2.0 %,
exceeding 4.0 % in the Fuling-Wulong area.
The thermal maturity of the Wufeng -Longmaxi formations has little
relationship with the current burial depth and is mainly controlled by
the maximum burial depth. The tectonic background of the Upper
Yangtze and the different plate positions resulted in the thermal of the
various tectonic zones differing slightly (He et al., 2020b). The maturity
of shale developed on paleo-uplifts and paleo-highlands is relatively
low. Specically, the EqVRo% value of shale thermal maturity in the
western Hubei-Eastern Chongqing and southern Sichuan is between 2.2
% and 2.5 %, and the EqVRo% value gradually decreases toward the
Central Guizhou Uplift where the EqVRo% value in Dingshan and
Renhuai areas is about 2.0 % (Fig. 7).
4.2.2. Mineral composition
The Wufeng -Longmaxi shale in the Sichuan Basin and its periphery
contains mainly quartz, clay minerals, carbonate, feldspar and pyrite.
The quartz content in the WF2-LM4 graptolite biozone displays east-
–west zoning, that is, with the Nanchong-Chongqing-Nanchuan line as
the boundary, the lithofacies of the Jiaoshiba, Dongxi, Wulong and
Nanchuan areas in the eastern Sichuan Basin are siliceous shale with an
average quartz content of more than 50 % and an average clay content of
less than 40 %, and carbonate content of less than 10 % (Table 1). In
contrast, the lithofacies of the southern and southwestern Sichuan Basin
are dominated by calcareous siliceous shale, and its quartz content, clay
content, and carbonate content are between 40 % and 50 %, 25 %–30 %,
and 10 %–20 %, respectively. Furthermore, the Renhuai area near the
Central Guizhou Paleo-uplift and the Weiyuan area of the Central
Fig. 5. Sedimentary facies and shale thickness of LM1-LM4 graptolite biozone of Lower Silurian Longmaxi Formation and main shale gas elds in the Sichuan Basin
and its periphery. Thicknesses of graptolite biozones were determined by graptolite identication.
H. Nie et al.
Sichuan Paleo-uplift has a quartz content of less than 40 %, carbonate
content greater than 20 %, and relatively lower clay content. The
Yongchuan and Dingshan areas, which are less affected by the paleo-
uplift, generally contain more than 40 % quartz content. As for the
argillaceous shale in the LM5-LM8 graptolite biozone, the average
quartz content is less than 35 %, the clay content is mostly between 40 %
and 55 %, and the carbonate content is less than 10 %.
4.3. Porosity and permeability
Tests at normal temperature and pressure show that the porosity of
wells WY 1 (>3500 m), DYA (~4000 m), and NY1 (~4500 m) are
roughly the same as that of Well JY1 (~2400 m), with values ranging
from 4 % to 6 % (Fig. 8). The variation in porosity and permeability of
the deep shales are different from those under either high temperature
or high pressure. When the increasing conning pressure and temper-
ature, the porosity and permeability of shale are 4.06 % and 0.0063 mD,
under the condition of 10 MPa and 60 ℃; however, the porosity and
permeability at 40 MPa and 90 ℃ reduce to 2.28 % and 0.0013 mD, and
the reduction rates are 43.8 % and 79.7 %, respectively. Furthermore, at
70 MPa and 120 ℃, the porosity and permeability are 1.86 % and
0.0006 mD, with reduced rates of 54.1 % and 90.4 %, respectively. On
the contrary, when the temperature and pressure drop to 40 MPa and 90
℃, the porosity and permeability are 1.99 % and 0.0008 mD, which are
less than the values in the process of the corresponding pressurization
and temperature increase (2.28 % in porosity and 0.0013 mD in
permeability) (Fig. 9). The experimental results show that when the
burial depth reaches 3500–4000 m, the porosity and permeability
decrease signicantly, whereas the reduction range becomes limited
when the temperature and pressure continue to increase. Compared
with the experiment at normal temperature and pressure, the reduction
of the shale porosity at high temperature and high pressure in deep shale
is larger, while the reduction of the permeability is relatively smaller.
This indicates that under actual geological conditions, the porosity in
deep shale is smaller, but the permeability is greater than those in pre-
vious conclusions. This is because high temperature changes the mineral
properties and pore structure of the shale, resulting in stronger
compaction but fewer effects on permeability along the beddings.
4.4. Shale gas content
The high-temperature and high-pressure isothermal adsorption ex-
periments show that the adsorbed gas content of deep shale is 4.5 cm
3
/g
at 80 MPa and 135℃, which is about 15 % higher than that at the
maximum pressure of 30 MPa (3.9 cm
3
/g) (Fig. 10). It shows that both
considering the high-temperature and high-pressure conditions, the
adsorption capacity of deep shale is increased. In terms of free gas, the
effect of temperature and pressure on free gas content is positive, which
can be easily inferred from the pressure–volume-temperature (PVT)
equation of state. Taking the Wufeng-Longmaxi shales in the well WY1
Fig. 6. The contour of the total organic carbon content of black shale of Upper Ordovician-Lower Silurian in the Sichuan Basin and its periphery.
H. Nie et al.
as an example, the total gas content determined by the indirect method
ranges from 10.5 to 12.6 cm
3
/g, which is much higher than the gas
content determined by the direct method ranging from 3.3 to 5.9 cm
3
/g
with the depth of 3820–3852 m (Fig. 11). The indirect method estimates
the maximum theoretical gas content, while the direct method estimates
the actual gas content. It shows that deep shale gas theoretically has a
high gas-bearing capacity, whereas the actual gas content is controlled
by preservation conditions, and the gas content is quite different. The
proportion of free gas to adsorbed gas content increases with the
increasing burial depth, suggesting that the occurrence state of deep
shale gas is mainly free gas.
4.5. Hydraulic fracturing and production
Hydraulic fracturing in the Yongchuan, Dingshan, Nanchuan and
Dongxi deep shale gas elds is more difcult than that in the Fuling,
Changing and other shallower shale gas elds. Taking the Yongchuan
shale gas eld as an example, the fracture shear and slip are difcult
because of the high overburden pressure in the tri-axial stress regime,
resulting in a small transverse sweep volume of the articial fracture.
Furthermore, fracture height is also limited resulting from the small
difference between the minimum horizontal principal stress and the
overburden pressure. Hence, the SRV is extremely small under the
current hydraulic fracturing technology (Table 2). Besides, the width of
the initial fracture of various scales is narrow and the fracture conduc-
tivity rapidly declines due to the high closure pressure in deep shale gas
reservoirs, making it difcult to maintain long-term conductivity.
Particularly, for the small-scale branched fractures, due to the lower
proppant concentration and higher closure pressure, the conductivity is
lower and the decline is quicker. For clay-rich shale, the induced stress
spreads at a limited distance and the closure gradient is in the range of
0.023–0.025 MPa/m. Moreover, the proppant broke and embedding is
serious, which affects the width of propped fractures.
Deep shale gas exploration was mainly carried out in the elds such
as the Jiangdong area of Fuling, Dingshan, Nanchuan, Luzhou, Wei-
Rong, and Yongchuan, etc. in the Sichuan Basin. Commerical gas
ows have been obtained in wells WY1, YY1, DYA and DYSA. However,
the deep shale gas development is only carried out in the Wei-Rong,
Yongchuan, and Jiangdong areas of the Fuling shale gas elds.
Compared with shale gas wells in the Fuling, Changning and other
shallower shale gas wells, the deep shale gas wells generally show high
test production (frequently more than 20.0 ×10
4
m
3
/d), but fast pro-
duction pressure drop (0.1 MPa per 10
4
m
3
) and fast decline rate (the
rst year’s decreasing rate is 90 %). The recoverable reserves of deep
shale gas wells are relatively low ranging from 0.3 ×10
8
to 0.5 ×10
8
m
3
under the current technical conditions, while the average recoverable
reserves are commonly more than 1.0 ×10
8
m
3
in the shallower
Jiaoshiba and Changning shale gas wells, probably reecting the
Fig.7. The maturity contour of black shale of Wufeng-Longmaxi formations in the Sichuan Basin and its periphery.
H. Nie et al.
complicated reservoir condition, gas-bearing properties and producing
characteristic of deep shale gas reservoir.
The Wei-Rong deep shale gas eld with proven geological reserves
exceeding 1000 ×10
8
m
3
, geographically located in Weiyuan County,
Neijiang City, Sichuan Province, South China, has a burial depth ranging
from 3550 to 3880 m. The discovery of the Wei-Rong deep shale gas eld
won the “Top Ten Geological Prospecting Achievements” of the Chinese
Geological Society in 2019, indicating that Sinopec has made a break-
through in deep shale gas exploration. Apart from the negative inuence
on the shale deposition caused by the bathymetric high in the Neijiang-
Fig. 8. Relationship between burial depth and porosity of major shale gas wells in the Sichuan Basin (Modied from He et al., 2020a).
Fig. 9. Shale porosity (left) and permeability (right) under high temperature and high-pressure conditions (well YY1, 3864.72 m in depth, Longmaxi Formation).
H. Nie et al.
Zigong area in the eastern part of the Weiyuan shale gas eld (Nie et al.,
2017; Ma and Xie, 2018), the organic-rich shale distribution is relatively
stable across the Weiyuan area. The well WYA-1 with a burial depth of
3850 m in the Wei-Rong deep shale gas eld has a test production of
26.0 ×10
4
m
3
/d, and a test pressure of 33.5 MPa. It began pilot pro-
duction on December 6, 2017, and the cumulative gas production
reached 32.9 ×10
6
m
3
with a ow back rate of 48.8 % by the end of
October 2019 (Fig. 12).
5. Discussion
5.1. Shale thickness and reservoir characteristics
5.1.1. Thickness of organic-rich shale
Many early studies involving exploration and development practices
revealed that organic-rich shale is an important factor in controlling
shale gas enrichment and production (Potter, 2018), with the deep-
water facies being favorable for shale gas enrichment (Nie et al.,
2009; Tan et al., 2015; Liang et al., 2016; Wang et al., 2020). Currently,
there are many denitions for organic-rich shale, among which shale
with a TOC of more than 2.0 % generally has better potential (Nie et al.,
2009). Some researchers believe that the high production of shale gas is
related to the shale thickness greater than 10 m and with TOC >3.0 %
(Jiang et al., 2017a; Ma et al., 2020b), while others consider that the
TOC level depends on the shale thickness of the WF2-LM4 graptolite
biozone of the deep-water facies (Jin et al., 2020; Nie et al., 2020b).
From the perspective of isochronous strata and the production charac-
teristics of shale gas wells, the authors ever pointed out that the siliceous
shale of the WF2-LM4 graptolite biozone in the Wufeng-Longmaxi for-
mations is the most favorable shale gas enrichment interval and the
target position for the horizontal wells (Nie and Jin, 2016; Jin et al.,
2018). The WF2-WF4 graptolite biozone was affected by the Guangxi
movement and global sea-level rise during deposition, resulting in the
formation of a deep-water sedimentary environment with a maximum
compacted thickness of more than 200 m and the formation of black
shale in the Upper Yangtze Platform (Chen et al., 2017, 2018).
The Wufeng Formation to the base of the Longmaxi Formation is
mainly siliceous shale in the eastern Sichuan Basin, while it is mainly
Fig. 10. The adsorbed gas content of shale under high-temperature and high-
pressure conditions (up to 80 MPa and 135 ℃, well WYA-1, Long-
maxi Formation).
Fig. 11. Shale gas content measurement in well WY1 using both direct and indirect methods.
H. Nie et al.
calcareous siliceous shale in the southern Sichuan Basin. The organic-
rich shale determines the deep shale gas reservoir type and petrophys-
ical properties, and further controls gas content and hydraulic fracturing
(Jin et al., 2016; Nie et al., 2020b). The isochronous shale thickness and
burial-depth maps based on the biostratigraphic zonations reect that
there is no correspondence between the areas with greater burial depth
(Fig. 1) and the depositional center (Fig. 5), thus it cannot be simply
concluded that the current area with greater burial depth is the depo-
sitional center of organic-rich shale. Compared with Changning-Yibin in
the southern Sichuan Basin and Fuling-Wulong in the eastern Sichuan
Basin, the water depth in the Sichuan Basin such as Weiyuan, Dingshan,
and Yongchuan, where shale is deeply buried today, was shallower, and
the organic-rich shale is thinner (Nie et al., 2017). The top and bottom of
the organic-rich shale of the WF2-LM4 graptolite biozone are all dia-
chronous strata due to the control of sea-level rise and fall, and paleo-
uplifts such as Ziliujing, Huayingshan, Dingshan, and western Hubei
and Hunan bathymetric high (Chen et al., 2018). Furthermore, they also
have the characteristics of thinning thickness or stratum absence, which
had led to a different understanding in evaluating organic-rich shale,
and these differences are essential for the reasonable evaluation of shale
gas exploration and development (Nie et al., 2020b). Some graptolite
biozones were lost or reduced on bathymetric high such as the absence
of partial WF3, WF4 and LM1-LM4 graptolite biozones in well WY1,
while the Guanyinqiao Member and partial WF4 and LM1 graptolite
biozones are absent in the Pengshui area (Figs. 4 and 5).
Specically, the thickness of the WF2-LM4 graptolite biozone is
thinner than that of the Jiaoshiba and Changning areas, which may
result in lower EUR for shale gas wells in the Weiyuan, Dingshan and
Yongchuan areas than that in Jiaoshiba and Changning shale gas elds.
Deep shale gas wells usually have the characteristics of high initial
production but low EUR (Nie et al., 2021a). Currently, the poor frac-
turing effect is believed to be the main cause (Ma et al., 2020a). The
hydraulic fracturing of deep shale gas reservoirs may not be able to
create a complex fracture network like those of the shallower shale gas
reservoirs, and the SRV is less efcient. However, analysis from frac-
turing uids and proppants indicates the potential for the development
of complicated fractures in some deep shale gas wells (He et al., 2019).
Wells such as WY1 and DYA has low EUR, not only as a result of inferior
hydraulic fracturing effect but also because of poor shale quality (i.e.
Table 2
Comparison of fracturing effect between deep shale gas wells in Yongchuan and Weiyuan shale gas elds and shallower shale gas wells in Jiaoshiba block of Fuling
shale gas eld (after He et al., 2020a).
Shale gas
eld
Well Fracture half-length
(m)
Fracture belt width
(m)
Fracture height
(m)
SRV of single-
stage
(10
4
m
3
)
Fracture complexity
index
Production pressure drop
(MPa)
Yongchuan YYA 280 68 45 173 0.24 ＜1
(30 min) YYC-
1
264 56 45 133 0.21
YY1 292 65 45 171 0.22
Weiyuan WY1 299 58 49 172 0.29 1.5
(30 min)
Jiaoshiba JY1 241 93 55 247 0.39 7 (1 min)
Fig. 12. The production performance curve of well WYA-1 in the Wei-Rong deep shale gas reservoir.
Fig. 13. The relationship between EUR and shale thickness of WF2-LM4
graptolite biozone of typical deep shale gas wells of Wufeng and Longmaxi
formations in the Sichuan Basin.
H. Nie et al.
lower TOC content). The organic-rich shale in the Weiyuan and Ding-
shan deep shale gas reservoirs is relatively poor compared with that in
the Changning and Jiaoshiba shale gas elds (Figs. 4 and 5). The
thickness of the WF2-LM4 graptolite biozone, which corresponds to the
most productive shale gas elds, turns thinner in the Weiyuan and
Dingshan shale gas elds. The thickness of the WF2-LM4 graptolite
biozone is 10 m in Well DY1 and only 3 m in Well WY1, which ranges
from 20 to 25 m in the well JY1 of the Fuling shale gas eld (Nie et al.,
2021a). The EUR of the three wells is 0.40 ×10
8
m
3
, 0.50 ×10
8
m
3
, and
1.50 ×10
8
m
3
, respectively. Good correspondence has been found be-
tween the shale thickness of the WF2-LM4 graptolite biozone and the
EUR of shale gas wells, and when the thickness exceeds 10 m, the EUR
approaches to exceed 0.50 ×10
8
m
3
(Figs. 5 and 13). The previous
studies on the detailed division of shale intervals in Wufeng-Longmaxi
formations were mainly based on TOC content but did not consider
the distribution of the graptolite biozone (Jiang et al., 2017a; Ma et al.,
2020b), thus it is not enough to be applied to the optimization of
prospect areas of deep shale gas. Specically, shales deposited in the
deep water where the thickness of the WF2-LM4 graptolite biozone
exceeds 10 m are the most prospect areas for deep shale gas develop-
ment, therefore, the future study should focus on the organic-rich shale
thickness of the WF2-LM4 graptolite biozone deposited in the deep
water.
Because there are few deep shale gas wells, the current research on
deep organic-rich shale is still at a preliminary stage. Therefore, a
comprehensive analysis of typical deep shale gas wells and seismic data
is necessary, with the sedimentary facies, thickness distribution,
geochemical parameters and mineral composition of the deep-buried
Wufeng-Longmaxi formations shales needing to be systematically
studied.
5.1.2. Reservoir characteristics
The geological characteristics such as high temperature and high
pressure in the deep shale gas reservoir will cause the porosity and
permeability to be lower than that of the shallower shale gas reservoirs.
Dong (2018) found that the shale permeability shows an exponential
decline as the temperature increases, i.e., as the temperature increases
from 20 to 80 ◦C, the permeability decreases by 37.5–42.9 %. As the
overlying strata stress of the deep shale gas reservoir increases to 50
MPa, the porosity and permeability decrease by 15–20 % and 90–95 %,
respectively (He et al., 2020a). Furthermore, they suggest that the sili-
ceous shale of the Wufeng Formation to the bottom of the Longmaxi
Formation (WF2-LM4 graptolite biozone) has the highest porosity and
permeability. The high-temperature and high-pressure experiments in
this study show that, compared with shallower shale gas reservoirs, the
porosity of deep shale is reduced by about 40 to 50 %, while the
permeability decreases by as much as 80 to 90 %. Because the perme-
ability of deep shale gas reservoirs is signicantly lower than that of
shallower ones, improving the seepage capacity is the key to the effec-
tive development of deep shale gas reservoirs.
In terms of reservoir types, there are obvious differences in pore
types and lithofacies characteristics of the deep shale, which signi-
cantly affect gas content and cumulative production of shale gas (Hu
et al., 2020; Nie et al., 2020b). The siliceous shale is dominated by
various organic matter-hosted pores. In addition, the calcareous sili-
ceous shale also has abundant dissolution pores (Fig. 14), which seems
to have an uncertain effect on shale gas enrichment. However, it is
generally believed that the type and formation time of dissolution pores
Fig. 14. Differences in shale gas reservoir types between siliceous shale and calcareous siliceous shale in the Sichuan Basin. a. Siliceous shale: oating contact,
organic pores developed in the siliceous framework. Well JYA, 2585.9 m, Longmaxi Formation, LM3 graptolite biozone. b. Calcareous siliceous shale, point contact
and line contact, organic matter pores developed in the siliceous framework and dissolution pores developed in the carbonate minerals. Well WY1, 3574.4 m,
Longmaxi Formation, LM5 graptolite biozone. c. Siliceous shale, oating contact, and organic pores were well developed. Well WY1, 3587.2 m, Longmaxi Formation,
LM4 graptolite biozone. d. Siliceous shale, oating contact, and organic matter pores were well developed. Well YY1, 3868 m, Wufeng Formation, WF3 grapto-
lite biozone.
H. Nie et al.
has an important effect on the enrichment and preservation of shale gas
(Nie et al., 2019, 2020a). Dissolution pores formed later than the
maximum gas-generation period have a negative effect on shale gas
reservoirs (Nie et al., 2019), in the worst-case scenario, the development
of the pores will likely destroy the shale gas enrichment and can convert
reservoir pressure to normal pressure.
5.1.3. Hydrocarbon generation and expulsion history and gas content
The original depositional conditions of the organic-rich shale provide
the basis for shale gas development (Loucks and Ruppel, 2007). If the
original organic-rich shale is comparable between deep shale gas res-
ervoirs and shallower shale gas reservoirs, the deep shale gas enrich-
ment is mainly determined by the history of hydrocarbon generation and
expulsion, and the retention history which is controlled by the ampli-
tude of uplift, as well as the structural deformation (He et al., 2017). The
burial history controls the generation and expulsion processes of shale
and the amount of hydrocarbons generated and expelled. A model
considering the impact of maturity, pressure and temperature on the
sorption capacity of hydrocarbons for exploration targeting gas is rec-
ommended (Baur et al., 2020), which reveals that the organic matter
sorption capacity and actual hydrocarbon sorption capacity are very
weak for mature source rocks with greater burial depth. Large burial
depth (i.e. high temperature and pressure effects) and strong compac-
tion enable higher hydrocarbon expulsion efciency, resulting in fewer
hydrocarbons being retained in the shale formation (Cooles et al., 1986).
For instance, the Lower Cambrian shale in the Sichuan Basin and its
periphery has a maximum burial depth exceeding 8000 m (Zhao et al.,
2019) and the amount of gas retained in the shale is low due to the large
hydrocarbon expulsion, resulting in limited exploration and develop-
ment potential, which was also conrmed by exploration. If the
maximum burial depth is the same and less than 7000 m, and the only
difference between the deep shale and the shallower shale is the uplift
amplitude. The maximum burial depth of deep shale and shallower shale
of the Wufeng-Longmaxi formations is about 6000–7000 m (Gao et al.,
2019; Zhao et al., 2019). Due to the small uplift amplitude of deep shale,
thus deep shale of this type maybe more favorable and with greater shale
gas potential. In areas with better preservation conditions, the generated
methane was well preserved throughout its geological history, and the
total gas content of deep shale is believed to be greater than that of
shallower shale was conrmed by wells L203 and DYSA (Nie et al.,
2022).
Deep shales are subjected to higher temperatures and pressures as
they undergo large burial. The increasing temperatures and pressures
could affect the thermodynamic and kinetic properties of methane
adsorption in shale (Dang et al., 2020), and the uid compositions and
pore structures (Pitakbunkate et al., 2016; He et al., 2020a). All of these
factors could further affect the gas-bearing characteristics of shale. In
terms of adsorbed gas, increasing temperatures could decrease adsorbed
gas content, while increasing pressures could increase adsorbed gas
content. So, the coupling effect of temperature and pressure on adsorbed
gas content is very complicated (Dang et al., 2017). Overall, the deep
shale shows a great difference in gas-bearing characteristics from the
shallower shale. The proportion of free gas to adsorbed gas of deep shale
Table 3
Location of the major failed exploratory wells and faults in the Sichuan Basin,
China.
Well Structural location Distance away from deep-large fault
(km)
Gas
content
RY1 Gulin slope 0.5 None
YZ1 Shizhu synclinorium 2.7 Little
LiY1 Lichuan
synclinorium
1.5 Little
TY1 Shizhu synclinorium In the fault zone None
Note: In the Fig. 1, I denotes Gulin slope, II denotes Shizhu synclinorium, III
denotes Lichuan synclinorium, IV denotes Shizhu synclinorium.
Fig. 15. Section of Yongchuan shale gas eld in the Sichuan Basin. The location
of the section is in Fig. 1 (BB’).
H. Nie et al.
is greater than that of shallower shale.
5.2. Preservation conditions
5.2.1. Structural characteristics
There is little difference in the maximum paleo-burial depth expe-
rienced by the Wufeng-Longmaxi formations in the Sichuan Basin and its
periphery, with the difference in the current burial depth being mainly
controlled by the extent of later tectonic uplift. Compared to the shal-
lower shale gas reservoir, the deep shale gas reservoir generally expe-
riences fewer episodes of tectonic uplift and denudation, and thus
usually exhibits better preservation conditions, but the actual situation
may be more complicated. Inuenced by the plate tectonic evolution in
southern China, especially the difference in tectonic transformation
since the Yanshan movement, the preservation conditions of the deep
shale gas reservoir in the Wufeng-Longmaxi formations are very
complicated. Shale gas wells (e.g., RY1, YZ1, and TY1) near the deep-
large faults frequently show extremely low gas content (Table 3).
Shale gas wells away from those faults generally display good preser-
vation conditions, however, gas contents vary enormously owing to
their different structural locations (Guo et al., 2017; He et al., 2017).
Controlled by the high-steep belt in the east of Huaying Mountain, the
southeastern Sichuan Basin appears as a “nger-shaped” anticline
structure (Figs. 1 and 15), which is characterized by a narrow-steep
anticline and a wide-gentle syncline. The deep shale gas enrichment in
such a setting is jointly controlled by the wide-gentle syncline and
organic-rich shale development areas (Nie et al., 2021a). In general,
shale gas wells in a wide-gentle syncline show good preservation con-
ditions and have high EUR and gas production after hydraulic
fracturing.
The preservation conditions of deep shale gas need to be systemati-
cally analyzed based on structural location, fault feature, tectonic
movement period, and uid activity. Among them, the uid activity
intensity and period (vein type and period) are closely related to the
preservation conditions of shale gas. Fluid activity can be reected by
the vein llings in the fractures, with the inclusion capture time re-
ected by vein formation times. According to the analysis of the ho-
mogenization temperature of uid inclusions in shale fracture veins and
burial history-thermal evolution history, the formation time of veins and
uid activity time can be conrmed, and the time and damage degree
when shale gas reservoirs are formed or destroyed can be determined
(Nie et al., 2020a). Several studies revealed that the deeper and earlier
the vein formation, the more favorable the preservation conditions of
the shale gas reservoir (Gao et al., 2019; Nie et al., 2020a). The greater
the vein formation (fracture formation-closure) stages and the lower the
homogenization temperature of uid inclusions, the more severe the
shale gas reservoir is destroyed. Shale gas preservation conditions in the
Jiaoshiba, Pingqiao, Nanchuan, and Dingshan shale gas elds in the
southwestern Sichuan Basin would weaken with increasing the number
of episodes of paleo-uid movement and vein formation (Nie et al.,
2020a).
The southeastern Sichuan Basin has undergone multi-stage compli-
cated tectonic movements, forming a range of “nger-shaped” anticlines
and mostly vertical fracture development in the shale (Fig. 16), which is
more destructive to shale gas preservation and shows more vein for-
mation periods than the detachment structures in the Wufeng Formation
outside the Sichuan Basin. Two periods of calcite veins and one-period
quartz vein formation can be identied in well YY1 in the Yongchuan
area, showing an extra calcite vein at 160–180 ◦C and quartz vein at
170–180 ◦C than one-period calcite vein in well JY1 in the Fuling area
(Jin et al., 2018; He et al., 2020a). This information conrmed that the
multi-stage tectonic movements lead to more complicated preservation
conditions of shale gas. In addition, the high part of the anticline is more
susceptible to tectonic movement, probably leading to increasing frac-
ture development and poor preservation conditions of shale gas. Taking
the YYA well as an example, there are many high-angle fractures in cores
Fig. 16. Vertical fractures in the shale cores of well DYSA (a & b, Longmaxi Formation, 4204.2 m) and well YYA (c, Longmaxi Formation, 3050.5 m), Sichuan Basin.
H. Nie et al.
lacking calcite or quartz lling (Fig. 16), which may be unfavorable for
shale gas preservation.
5.2.2. Pressure coefcient
The pressure coefcient is a comprehensive reection of preserva-
tion conditions. The exploration and development of shallower shale gas
reservoirs show that shale gas wells with higher pressure coefcients
commonly have higher productivity (Nie et al., 2021a). Because the
Wufeng -Longmaxi shales in the Sichuan Basin and its periphery has
generally undergone the cracking of crude oil into gas (Dai et al., 2014;
Liu et al., 2018b), the shale gas reservoir is likely to maintain high uid
overpressure when the preservation condition is good, which can pre-
serve organic matter pores (Katz and Arango, 2018), as well as the large
pore size and high adsorption capacity (Gao et al., 2020), leading to
potential commercial shale gas reservoirs (Nie et al., 2021b). Where the
preservation condition is poor, the pressure coefcient is low and the
organic matter pores are strongly deformed (Wang, 2020), and gener-
ally, a commercial shale gas reservoir usually cannot be formed (He
et al., 2020b). Therefore, the pressure coefcient of the current shale gas
reservoir is a useful and reliable proxy to evaluate preservation
conditions.
Caprocks with a strong sealing ability (e.g., gypsum) are the key to
the formation of large- and medium-sized oil and gas elds in marine
carbonate strata (Jin, 2012). Gypsum caprock plays a vital role in the
large-sized gas eld (Jin, 2012). Studies have revealed that even though
the source rocks are old, oil and gas can still be preserved as long as the
preservation conditions are high (Jin, 2012). The Middle-Lower Triassic
gypsum in the Sichuan Basin can form a pressure seal for the Wufeng-
Longmaxi shale gas (Nie and Jin, 2016; Jin et al., 2018). The explora-
tion practice proved that the Wufeng -Longmaxi shale gas reservoir in
the Sichuan Basin has better preservation conditions with pressure co-
efcients between 1.2 and 2.0 where the overlying gypsum is well
preserved, otherwise, the pressure coefcients are lower than 1.2 (Jin
et al., 2018). It is noteworthy that shale gas wells in the overpressured
zones (e.g. Fuling, Weiyuan, and Changning shale gas elds) with
pressure coefcients ranging from 1.2 to 2.0 usually have high pro-
duction after fracturings, such as the EUR of well JY1 and well N201,
both exceeded 1.00 ×10
8
m
3
. However, the pressure coefcient in the
high steep anticline in the Sichuan Basin is generally less than 1.2, and
the EUR is usually less than 0.50 ×10
8
m
3
(e.g. well YYA) (Fig. 17).
5.3. Development practice
5.3.1. Hydraulic fracturing
Deep shale gas reservoirs in the United States are characterized by
relatively low in-situ stress (generally around 70–90 MPa), small hori-
zontal stress difference, large vertical stress difference, and high brit-
tleness (Bill and Chris, 2012; Farinas and Fonseca, 2013; Lowe et al.,
2013). All these factors are benecial to hydraulic fracturing, proppant
adding, fracture initiation and extension, and forming a complex frac-
ture network. In the United States, early hydraulic fracturing was mainly
suitable for small stages and multiple clusters, intensive cutting, and
Fig. 17. Pressure coefcient of Wufeng-Longmaxi formations in the Sichuan Basin and its periphery.
H. Nie et al.
high-strength continuously adding sand, which could guarantee suf-
cient extension of the height and width of the fractures in each cluster
(Table 4) (Warpinski et al., 2009; Zhang and Yang, 2015; Zhao et al.,
2020). At present, third-generation hydraulic fracturing is characterized
by “intensive cutting, high-strength sand, and adding diverting agent to
force fracture diverting”, which has the characteristics of increasing
sanding intensity, decreasing the length of a single-stage, increasing
cluster number and decreasing cluster spacing of a single stage. In terms
of proppant, the proportion of small particle size has increased, and
high-viscosity slickwater has been actively tested. Slickwater has a
simple formula, strong sand-carrying and fracture-making ability, which
can signicantly improve production.
There are distinct differences in geological conditions and hydraulic
fracturing parameters of deep shale gas reservoirs between the U.S. and
China. China’s deep shales have a high temperature (>100 ℃), high
pressure (>90 MPa) and large vertical stress difference, as well as large
horizontal stress difference (Table 1), which will inevitably lead to a
signicant increase in shale plasticity and directly enhance the frac-
turing pressure. The higher stress difference makes fractures difcult to
divert, so it is not conducive to increasing the complexity of the fracture
network and the SRV (Cao et al., 2020). Therefore, it is difcult to in-
crease the complexity of articial fractures and SRV. There is a limited
amount of sand and sand to-liquid ratio, insufcient fracture monitoring
and interpretation accuracy, high fracture closure pressure, and the
proppant is easy to break or embed in the formation, resulting in dif-
culty in forming complex fracture networks and the fractures are easily
closed. The monitoring results of the deep shale gas wells showed that
the fracture height and width of deep shale gas reservoirs in China are
relatively small, resulting in a small SRV (Table 2), further affecting the
stable production capacity of deep shale gas wells and restricting the
commercial development of deep shale gas in China.
The brittleness index, fracture density, self-supporting ability and
ow conductivity of deep shale gas reservoirs are lower than those of
shallower ones. The calculation method of the brittleness index estab-
lished based on mineral compositions for shallower shale gas reservoirs
is difcult to apply to the needs of deep shale gas reservoirs due to their
geological differences (Jiang et al., 2017b; Hou et al., 2018). It is
necessary to establish a new method for evaluating the brittleness of
shale when the rock is plastically deformed under high temperature and
high pressure of deep shale gas reservoirs. It is noteworthy that the
fracture volume should be paid more attention to the fracturing design
of deep shale gas wells. However, there is a limited improvement in
fracturing equipment and pump pressure. It is difcult to form a similar
fracture length and fracture height under the same fracture pressure
between deep shale gas wells and shallower ones. Therefore, the
importance of the fracturing design should focus on increasing the
complexity of the near-wellbore fracture network rather than enhancing
the fracture length and fracture height. Because the high closing fracture
pressure increases the difculty of fracture opening and diverting, it is
recommended to add the diverting agent to force fracture diverting and
improve the complexity of the fracture network. Furthermore, the high-
viscosity slickwater is recommended to reduce the fracture pressure,
promote balanced fracture extension, and improve the support strength
and ow conductivity of the fracture. It can also be achieved by reducing
cluster spacing in a single-stage, using variable-rate fracturing, reducing
the proppant size, increasing the proppant strength and volume, and
optimizing the fracturing parameters. Most importantly, in the equip-
ment, try to improve upgrading equipment for hydraulic fracturing. The
fracturing equipment with a 140 MPa pressure limit is commonly used,
but the average cost of a single well increases.
Table 4
Comparison of hydraulic fracturing parameters of deep shale gas reservoirs
between the U.S. and China.
Hydraulic
fracturing
parameters
The U.S. (the Haynesville Shale
in the North Louisiana Salt
Basin, the eagle Ford Shale in
the Gulf Coast Basin and the
Cana Woodford shale in the
Western Oklahoma)
China (the Wufeng-
Longmaxi shale in the
Sichuan Basin)
Stage and clusters 3–10 clusters of a single-stage 2–6 clusters of a single-
stage
Perforation
parameters (mm)
Aperture: above 14 Aperture: 9.5, 10.5, and
12.7
Liquid mode Pretreatment-acid, linear gel,
slickwater and gel
Pretreatment-acid,
colloid uid, slickwater
and colloid uid
Fracturing uid
system
Slickwater (1–3 mPa.s), and gel Slickwater (9–12 mPa.s),
and polymer
Proppant 100, 40/70, 30/50, and 20/40-
mesh
100, 40/70 and 30/50-
mesh
Mode of sand
injection
Low sand ratio and continuous
injection
High-strength proppant
stage plug
SRV of a single-
stage (m
3
)
1500–2900 1600–3100
Proppant volume of
a single-stage
(m
3
)
70–110 50–80
Sand to liquid ratio
(%)
3.0–6.0 1.1–4.1
Displacement (m
3
/
min)
11–14 12–18
Pressure (MPa) 70–90 90–118
Note: Data were compiled from (Bill and Chris, 2012; Lowe et al., 2013; Farinas
and Fonseca, 2013; Zhao et al., 2020; Zheng et al., 2020).
Fig. 18. Production characteristics of well WYB-1 and well WYB-2 in the Wei-Rong shale gas eld. (a) Uncontrol pressure production. (b) Control pres-
sure production.
H. Nie et al.
5.3.2. Increase the length of the horizontal wells
Extending the length of horizontal wells can increase the production
of shale gas (Wang, 2020). On average, every 100 m increase in the
length can add 21 ×10
6
m
3
to the recoverable reserves of a single well in
the Wufeng-Longmaxi shale gas reservoir. The long length is an effective
way for deep shale gas to realize commercial development by reducing
the number of wells and pads, cutting the drilling cost per lateral meter,
and improving single-well production and PDP (Proved Developed
Producing (oil/gas reserves)) reserves. New wells drilled in the Duver-
nay shale at the western edge of the Alberta sub-basin in the Western
Canada Basin have increased the length by 1.66 times (Li et al., 2020). In
addition, the operator has increased the number of clusters from 3 to 4
clusters to 7 clusters, shortened the cluster spacing from 15 to 7 m, and
increased the proppant intensity from 1.69 to 3.90 t/m, as a result, the
EUR of condensate oil for a single well jumped from 2.8 ×10
4
to 6.9 ×
10
4
m
3
, and EUR of natural gas grew from 0.40 ×10
8
to 0.90 ×10
8
m
3
(Li et al., 2020), which demonstrates that single well production and
EUR can be boosted by longer length and higher hydraulic fracturing
intensity.
The development of shallower shale gas elds of the Wufeng
-Longmaxi formations shows that the horizontal length for every 100 m
increases after 1000 m, and the recoverable reserves of a single well can
increase by about 3 ×10
6
m
3
. The integration of geology with engi-
neering is necessary to get the optimal length and perforation number of
deep shale gas wells. The relationship should be evaluated between the
burial depth, organic-rich shale thickness, length of the horizontal sec-
tion and well production. Based on the comprehensive analysis of well
performance in different regions, the length of deep shale gas wells, the
number of fracturing stages and perforations and the amount of prop-
pant can be optimized. Also, treatments like chemical or mechanical
diversion can be applied.
5.3.3. Production system
For gas occurrence in deep shale gas reservoirs, free gas was domi-
nated with absorbed gas as an auxiliary (Hao et al., 2013; Tang et al.,
2016). Energy from gas expansion pushed gas up to the wellbore in the
early stage, and the daily gas production is high. When free gas is
exhausted, the production of a gas well depends on adsorbed gas
desorption. With reservoir pressure and gas production going down,
some hydraulic fractures close and the permeability decreases due to the
fast gas production rate and high-stress sensitivity. The deep shale gas
wells generally have the characteristics of high initial production, large
decline rate, and low EUR with a rst-year decline rate of about 70 %–
80 %. Pressure control can mitigate formation damage caused by factors
such as proppant embedding, crash, or blockage, thus it is an effective
way to retain the permeability of the fracture network (Fan et al., 2010).
Gas wells using a controlled pressure production system or a smaller size
choke to slow down the pressure drop witness a lower initial production
but a much higher EUR when compared with wells applying an open
ow production system. It has been proven that reasonable pressure
control can reduce the rst-year production decline rate by 50 %–80 %
(Fan et al., 2010), which allows a steady growth of production and a
signicant improvement of recovery rate by offsetting the low initial
production inuence on the net present value of gas wells.
The well WYB-1 with a vertical depth of 3974 m in the Wei-Rong
shale gas eld had a high initial production of 18.0 ×10
4
m
3
/d,
which is much higher than 6.0 ×10
4
m
3
/d in the development period.
Consequently, a sharp decline was observed after the well was put into
production with the gas production per unit pressure dropping as low as
47.00 ×10
4
m
3
/MPa (Fig. 18). By the end of February 2021, the cu-
mulative gas production was 0.21 ×10
8
m
3
and the EUR is 0.56 ×10
8
m
3
, far below the expected values (1.00 ×10
8
m
3
). Thus, it is revealed
that poor pressure management during the initial stage can result in a
signicantly lower EUR. On the contrary, well WYB-2 with a similar
burial depth on the same platform has an initial daily production of 8.00
×10
4
m
3
(Fig. 18). The well achieved a stable production time close to 1
year with gas production per unit pressure dropping up to 73.00 ×10
4
m
3
/MPa. As of February 2021, the cumulative gas production and EUR
of this well reached 0.29 ×10
8
m
3
and 0.78 ×10
8
m
3
, respectively,
which is a better result when compared with that of well WYB-1.
6. Conclusions and implications
(1) The deep shale gas from the Ordovician-Silurian Wufeng-Long-
maxi formations is promising, with exploration and development being
in a preliminary stage, facing a series of theoretical and technical
challenges. The deep shale gas reservoir resources feature as high tem-
perature, high pressure and high in-situ stress.
(2) Compared with shallower shale gas reservoirs (<3500 m), deep
shale gas reservoirs display lower porosity and permeability, fewer
microfractures and a signicant decrease in the reservoir permeability.
This explains why deep shale has been difcult to effectively fracture
and establish stable gas-production.
(3) The development should be directed toward siliceous shale in-
tervals, with priority in areas where the shale thickness of the WF2-LM4
graptolite biozone is greater than 15 m. Tailoring the length of hori-
zontal wells and hydraulic fracturing scheme (such as an optimum
number of stages, perforations and proppant amount) for the deep shale
gas reservoir and optimizing the gas production system are effective
ways to maximize the deep shale gas production and its effective
development.
(4) The effective development of deep shale gas reservoirs is quite
complicated, requiring close interdisciplinary integration. Through the
extraction of geophysical attributes and detailed analysis, target areas
and sweet spots can be determined highlighting their superior sedi-
mentary and diagenetic conditions, moderate structural uplift and
deformation, and good preservation conditions, together with favorable
reservoir features like high brittleness, high porosity and permeability,
high-pressure coefcient, high gas content. Moreover, the design of
drilling, completion and hydraulic fracturing is essential according to
the difference of deep organic-rich shale under different geological
conditions to realize large-scale commercial development of shale gas
resources. Furthermore, appropriate development programs and
consistently optimizing the shale gas production system are of signi-
cant importance to ensure the maximum amount of shale gas production
and commercial development.
CRediT authorship contribution statement
Haikuan Nie and Zhijun Jin: Conceptualization, Methodology,
Writing - original draft, Supervision. Pei Li and Wei Dang: Data cura-
tion, Experiment design and conduct, data collection. Barry Jay Katz,
Quanyou Liu and Shu Jiang: Writing-review & editing. Jianghui Ding
and Donghui Li: Visualization, Investigation.
Declaration of Competing Interest
The authors declare that they have no known competing nancial
interests or personal relationships that could have appeared to inuence
the work reported in this paper.
Data availability
Data will be made available on request.
Acknowledgments
This work was supported by the National Natural Science Foundation
of China (Grant No. 41872124 & 41202103) and Several Sinopec in-
House Projects. We thank Sinopec Petroleum Exploration and Produc-
tion Research Institute, Sinopec Exploration Company, Sinopec Jian-
ghan Oileld, and Sinopec East China Petroleum Company, for the
H. Nie et al.
valuable data and information. We also thank Sinopec management for
permission to publish this work.
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