Experimental investigation of propagation mechanisms and fracture morphology for coalbed methane reservoirs
Experimental investigation of propagation mechanisms and fracture morphology for coalbed methane reservoirs
Chi Ai 0
Xiao-Xuan Li 0
Jun Zhang 0
Dan Jia 0
Wen-Jing Tan 0
0 College of Geoscience and Technology, China University of Petroleum (East China) , Qingdao 266580, Shandong , China
Fracture propagation mechanisms in coalbed methane (CBM) reservoirs are very complex due to the development of the internal cleat system. In this paper, the characteristics of initiation and propagation of hydraulic fractures in coal specimens at different angles between the face cleat and the maximum horizontal principal stress were investigated with hydraulic fracturing tests. The results indicate that the interactions between the hydraulic fractures and the cleat system have a major effect on fracture networks. ''Step-like'' fractures were formed in most experiments due to the existence of discontinuous butt cleats. The hydraulic fractures were more likely to divert or propagate along the butt cleat with an increase in the angles and a decrease in the horizontal principal stress difference. An increase in the injection rate and a decrease in the fracturing fluid viscosity were more conducive to fracture networks. In addition, the influence on fracture propagation of the residual coal fines in the wellbore was also studied. The existence of coal fines was an obstacle in fracturing, and no effective connection can be formed between fractures. The experimental investigation revealed the fracture propagation mechanisms and can provide guidance for hydraulic fracturing design of CBM reservoirs. Edited by Yan-Hua Sun
Coalbed methane reservoir; Butt cleat; Propagation mechanisms; Fracture morphology; Step-like fractures
(Ma et al. 2014, 2017a; Taleghani
et al. 2016; Wang et al. 2018; Zhang 2014)
, is a very
important technology and has been successfully applied to
the industrialized development of coalbed methane (CBM)
to improve low coalbed permeability
(Alexis et al. 2015;
Qin et al. 2018; Wu et al. 2018)
. Different from
singlejointed rock, such as shale, the cleat system developed in
coal can generate complex and diverse fractures. There is a
lack of an effective method for visualization of fractures in
underground coal seams, and numerical simulation of coal
College of Petroleum Engineering, Northeast Petroleum
University, Daqing 163318, Heilongjiang, China
seam fracturing based on ideal hypotheses can hardly
reflect the true regime of fracture propagation. However,
fracturing experiments in laboratory can simulate the
initiation and propagation process in CBM reservoirs under
real stress conditions, which can reveal complex fracture
propagation mechanisms for CBM reservoirs.
The mechanisms of fracture extension and the
description of fracture morphology in CBM reservoirs have
always been topical but difficult areas of research
et al. 2013; Wang et al. 2017; Wright et al. 1995; Zhang
et al. 2016; Zhao et al. 2016; Zou et al. 2017)
. The uniquely
developed internal cleat system (Abass et al. 1990) makes a
great difference in hydraulic fracture propagation
mechanisms between CBM reservoirs and other conventional oil
and gas reservoirs. Hydraulic fractures may propagate
along weak structural planes (bedding planes, cleats or
secondary joints, etc.), making the extension extremely
complex and even forming complex fracture extension
areas or complex fracturing zones.
Hou et al. (2013)
out a series of hydraulic fracturing experiments into
mechanical parameters and established hydraulic fracture
initiation criteria for a horizontal well in a coal seam.
et al. (2016)
investigated the effects of notch angle, notch
length and injection rate on directional hydraulic fracturing
initiation and propagation. Ma et al. (2017b) revealed the
mechanism of hydraulic fracture growth in a conglomerate
reservoir based on a series of laboratory tests.
Lin et al.
demonstrated the effect of anisotropy of shale on
hydraulic fracture propagation and found that the bedding
plane angle has a significant influence on fracturing results.
Huang et al. (2017)
observed the initiation of natural
fractures and propagation direction in coal seams under
different in situ stresses.
In order to accurately monitor fracture initiation location
and actual propagation path, acoustic emission has also
been applied to hydraulic fracturing experiments.
et al. (2013)
studied the acoustic emission monitoring
results of Lyons sandstone samples under different applied
Lu et al. (2016)
three-dimensional model to assess initiation location in coal. The
initiation was monitored by an acoustic emission system,
and the results were consistent with the model calculation.
Liang et al. (2017)
divided the whole hydraulic fracturing
process of coal into four stages: microcrack formation,
fracture initiation, unstable crack propagation and fracture
closure, and monitored the orientation of fractures by
Many scholars have also carried out laboratory
experiments to investigate the effect of natural fractures on
hydraulic fracture propagation.
Liang et al. (2016)
investigated the influence of in situ stress, tensile strength and
natural macro-cracks on crack formation and propagation.
Fu et al. (2016)
studied the influence of partially and
strongly cemented natural fractures on hydraulic fracture
propagation. Dehghan et al. (2015a, b) investigated the
influence of pre-existing fracture dip and strike on fracture
propagation based on research of predecessors
1986; Warpinski and Teufel 1987)
. Additionally, the
influence of injection rate and viscosity of fracturing fluid,
elastic modulus and other factors have also been widely
(Guo et al. 2014; Jiang et al. 2016; Wang et al.
2016b; Westwood et al. 2017; Zou et al. 2016)
(Liu et al. 2014; Tan et al. 2017b)
have also found that the
propagation path of fractures followed certain principles,
namely the least resistance and the most preferred
propagation path. In addition, some researchers
(Ding et al.
2018; Huang et al. 2017; Song et al. 2014; Wang et al.
2016a, 2017; Yao et al. 2018; Zhou et al. 2016; Zou et al.
also analyzed the effects of the above factors by
numerical simulation. The simulation results also proved
that approach angle, horizontal principal stress difference
and development of natural fractures are the main factors
affecting the propagation orientation. However, the
numerical simulation method cannot truly simulate the
cohesion between natural fractures, leading to a
discrepancy between simulation results and the actual propagation.
Although theoretical and experimental studies of
hydraulic fracturing of unconventional reservoirs have
been carried out, the propagation mechanisms of hydraulic
fractures in coal are very complex due to the existence of
face and butt cleats and scholars have not reached a unified
understanding of its propagation mechanisms, so hydraulic
fracture propagation morphology in coal is still not able to
be described accurately. In this paper, experiments for
cubic raw coal specimens at different angles between the
face cleat and the maximum horizontal principal stress
were carried out to analyze fracture propagation
characteristics. The effects of horizontal principle stress
difference, horizontal principle stress difference coefficient and
fluid viscosity on fracture propagation were also analyzed
qualitatively and quantitatively. Furthermore, experiments
of different injection rates at 90 and 0 were investigated
to study the effect of butt cleats on fracture complexity. In
addition, since a large amount of coal fines was generated
during drilling and was difficult to clean up, the effect of
coal fines on fracturing was innovatively considered. The
results can reveal the mechanisms of fracture propagation
and provide a theoretical basis for fracturing development
design of CBM reservoirs.
2 Experimental method
2.1 Material characteristics and specimen preparation
The coal used in this study was from the Zhangchen Mine,
Jixi Colliery, Heilongjiang Province, northeast China. The
depth of coal seams is 300–450 m, and the average
thickness is about 1.8 m. The coal is anthracite, with
calcite, kaolinite and quartz. There is a higher content of
vitrinite than exinite and inertinite. The cleats and bedding
planes are extremely developed in coal
(Abass et al. 1991)
In order to obtain reliable data on cleats and bedding plane
intervals, the distances between bedding planes, face cleats
and butt cleats were separately measured using
macroscopic measurements and SEM images (Figs. 1, 2). The
average length of the bedding plane is 186 mm, while the
interval is 35 mm. As for face cleats, their average length is
173 mm, 160 mm longer than butt cleats. The interval is
13 mm for face cleats and 21 mm for butt cleats.
According to experimental requirements, the raw coal
was cut into cubic specimens with dimensions of 300 mm.
However, due to the well-developed cleat system and low
strength of coal, it is very difficult to ensure the required
dimensions for field-sampling. Therefore, a standard
specimen was prepared by wrapping it with a material
similar to raw coal. Firstly, the raw coal was cut into coal
blocks whose sizes are slightly smaller than the standard
specimen size. Meantime, we ensured that the bedding
plane is parallel to the horizontal plane and the raw coal
was cut along different cleat orientations. In accordance
with previous experimental experience and related
principles, coal fines with particle size of 40–60 mesh, gypsum
powder and Portland cement (No. 32.5) were mixed in the
ratio of 1:1:3. The mechanical properties of similar
materials were then tested, and the results indicated that the
average compressive strength, tensile strength and elastic
modulus were 12.2, 0.63, and 5431 MPa, which were
extremely close to the specimen mechanical parameters in
the tests. Secondly, the coal blocks were placed in the
center of the mold and the evenly mixed similar materials
were poured into the mold for casting. After pouring, a
rubber hammer was used to beat the mold around to
discharge excess air bubbles. Finally, the specimens were
maintained for consolidation for more than 30 days.
The specimen was placed on a vertical drilling machine
after maintenance, and a 150-mm-deep hole was drilled in
the center by a carbide bit with an outer diameter of 11 mm
to simulate an actual borehole. Some of the boreholes were
thoroughly cleaned up and dried, while two remained
unwashed. The length, outer and inner diameters of the
simulated wellbore are 160, 10 and 8 mm, respectively
(Fig. 3), and a sealing ring for fracturing was installed as
shown in Fig. 4.
2.2 Experimental apparatus
Figure 5 presents a true tri-axial hydraulic fracturing test
system, which consists of (I) a true tri-axial model block,
(II) a hydraulic fracturing pump pressure servo control
system and (III) a data collection system. Part I consists of
a specimen placement chamber, a cubic block to pressurize
the specimen, and a hydraulic pump to drive the block. The
true tri-axial loading device can simulate the true in situ
stress in three directions and provide a maximum confining
pressure of 150 MPa for rocks of 300 mm 9 300 mm 9
300 mm. Part II includes a control box and a high-pressure
injection pump. Two modes, constant injection pressure or
constant injection rate, can be selected in the experiment,
with a maximum pumping pressure of 40 MPa.
2.3 Experimental methods and procedures
The purpose of this experiment is to investigate fracture
propagation mechanisms and to determine the effect of
cleat system on fracture morphology for CBM reservoirs.
To investigate the effects of different angles between the
face cleat and the maximum horizontal principal stress,
in situ stress, injection rate and fluid viscosity on fracture
propagation, orthogonal experimentation was designed in
this study. The specimens were prepared along different
cleat orientations. The angles between the face cleat and
the maximum horizontal principal stress are 0 , 30 , 60
and 90 . For each experiment, fracturing fluid was injected
with non-penetrating white dye additive to highlight the
propagation path. The additive has no influence on
rheological properties of the fracturing fluid. The cases are
selected as shown in Table 1.
The specific process of the experiment was as follows:
Place the prepared specimen in the chamber, and a
thin Teflon sheet covered on both sides with
Vaseline was inserted between the confining
pressure loading platen and the specimen to prevent
(de Pater and Beugelsdijk 2005)
the confining pressure loading system to complete
the three-dimensional stress loading.
Start the hydraulic servo pump pressure system to
inject the fracturing fluid into the simulated
wellbore. The data were collected in real time with a
Once the injection pressure decreased gradually to a
stable value and the fracturing fluid reached the
boundary of the specimen, the fracturing pumping
was stopped. The true tri-axial system was unloaded
to zero smoothly, and the experiment was finished.
The specimen was removed and split subsequently.
The white dye clearly showed the actual propagation
path of hydraulic fractures.
3 Experimental results and discussion
3.1 Analysis of the pumping pressure curves
Figure 6 presents pumping pressure curves under different
cleat orientations. There was no obvious differentiation
stage in the fracturing process of coal, which was different
from that in shale
(Tan et al. 2017c)
. The fluctuation
process was relatively more obvious and intense in accordance
with the developed cleat system. The existence of the butt
cleat makes the coal generate a large number of hydraulic
fractures connected with coal during fracturing, resulting in
frequent opening and closing of cleats, which shows
apparent fluctuation on the pumping pressure curves. Ma
et al. (2017b) noted that the pumping pressure decreased
sharply to a level less than the minimum horizontal
principle stress after it reached the breakdown pressure in
conglomerate specimens, indicating that the fluid flowed
into the fracture and produced a certain resistance after the
fracture opened. The pumping pressure did not reach the
minimum horizontal principle stress in the entire fracturing
process of coal, which may be related to its developed cleat
system. Although a large amount of fluid was injected, it is
difficult to build up a high pumping pressure. In addition,
the pumping pressure in the process of propagation was
always lower than the breakdown pressure, which indicated
that the stress always concentrated near the wellbore or
within a certain range.
When the face cleat was parallel to the maximum
horizontal principle stress (Fig. 6a), a large amount of
fracturing fluid was injected into the simulated wellbore. The
pumping pressure increased gradually and dropped
suddenly when the breakdown pressure was reached, that is,
the peak of the pumping pressure curve. A strong energy
release was generated at the moment of initiation and a
main fracture was formed in the specimen. Subsequently,
#14 (with coal fines)
a is the angle between the face cleat and the maximum horizontal principle stress; Kh is the stress difference coefficient
frequent small fluctuations occurred on the curve, which is
due to the formation of some internal branch fractures
intersected with the main fracture or connected with the
cleats, forming a diversion channel for fracturing fluid
(Guo et al. 2014)
. Since there was a balance between
injection and infiltration of the fracturing fluid, the overall
pumping pressure curve maintained a relatively
When the angle between the face cleat and the
maximum horizontal principle stress is 30 (Fig. 6b), the time
point of multiple breaking can be found clearly on the
curve accompanied by the multi-stage pressure
fluctuations. It is evident that in situations where the angle was
small, the continuous injection of fracturing fluid made the
hydraulic fractures frequently encounter the opening and
closing of cleats and form relatively more branch fractures.
When the angle is 60 (Fig. 6c), it is still possible to spot
multiple breaking points and multi-stage pressure
fluctuations on the curve. Compared with the case of 30 , the
curve fluctuated more sharply, and the opening and closing
of the cleats were more frequent, resulting in more
When the face cleat was perpendicular to the maximum
horizontal principle stress (Fig. 6d), no obvious breakdown
point was found on the curve. The frequent movement of
cleats caused more frequent fluctuations and higher
fluctuating range. After the cleat opened, the fracturing fluid
flowed along the cleat opening direction, which made no
significant increase on the curve.
3.2 Effects of cleat orientation on fracture morphology
Figure 7 presents different fracture morphologies at
different angles between the face cleat and the maximum
horizontal principle stress. In Fig. 7a, the whole specimen
initiated and propagated along the direction of the face
cleat, forming a main fracture coupled with some branch
fractures around the wellbore. The fracture morphology
was not complicated when the face cleat is parallel to the
maximum horizontal principle stress.
In Fig. 7b, the main fracture propagated along the
direction of the maximum horizontal principle stress and a
large number of nonlinear branch fractures were formed
along the cleat direction. It can be seen that the hydraulic
fractures were arrested by butt cleats in the propagation
process, making the propagation path relatively
Figure 7c presents the case where the angle between the
face cleat and the maximum horizontal principle stress is
60 , and the main fracture propagated along the direction
of the maximum horizontal principle stress to the boundary
of the specimen. Due to the discontinuous butt cleat,
‘‘steplike’’ fractures were formed on both sides of the fracture
during the extension of the main fracture, rather than
forming an approximately linear fracture like sandstone or
shale. Simultaneously, a fracturing zone was formed near
the wellbore, with a gradually decreasing width from the
borehole to the boundary. The coal near the wellbore
fractured into dense cracks.
As shown in Fig. 7d, the pumping pressure was not
enough to overcome the normal stress generated in the
direction of the butt cleat. Therefore, the main fracture
traversed the face cleat and extended along the butt cleat. It
was more likely to form branch fractures near the wellbore
than specimen #1.
(Warpinski and Teufel 1987; Zhou
et al. 2008)
suggested that the approaching angle between
hydraulic fractures and natural fractures determines the
propagation direction of fractures to a great extent. The
complexity of the fracture morphology in coal seams is
significantly influenced by cleats (Fan et al. 2014). As can
be seen from the above fracture morphologies (Fig. 7e), the
fracture is more complicated and the fracture network
forms more easily near the wellbore when the face cleat
orientation and the maximum horizontal principle stress is
not parallel or orthogonal. Under such conditions, the
greater the a is, the more likely the fractures are to
propagate along the opening butt cleat and the easier it is to
form ‘‘step-like’’ fractures. With the continuous increase
and accumulation of new fractures, the new and old
fractures finally make the entire specimen fractured.
As well as the qualitative analysis above, a quantitative
analysis of the fracture network is also necessary. Fracture
number (FN) and area ratio (AR) are selected as two main
parameters to quantitatively evaluate the effect of cleat
orientation on fracture morphology. Due to the
well-developed internal cleat system in coal, it is difficult to
distinguish face cleat, butt cleat and hydraulic fractures by CT
scanning; thus, the number of fractures with fracturing fluid
was carefully observed macroscopically and the
relationship between fracture number and cleat orientation has
been given. As shown in Fig. 8, the fracture number is the
highest when the angle is 60 compared with the other
three angles. Furthermore, the area ratio of a split specimen
is selected as a sign of fracture complexity. The area ratio
is defined as the ratio of fracturing fluid infiltration area to
the actual coal cross-sectional area. The higher the area
ratio means the more complex the fracture morphology.
The value of area ratio is greater when the angle is 30 and
60 , and the fracture morphology is the most complex
under the case of 60 , forming ‘‘step-like’’ fractures.
3.3 Effects of in situ stress
3.3.1 Effects of horizontal principle stress difference
Since all experiments were conducted under normal fault
stress conditions (rv [ rH [ rh), the effect of the
horizontal principle stress difference on fracture propagation
was investigated in this section. Two groups of
experiments were designed: 2 MPa (specimen #5) and
4 MPa (specimen #1). It can be seen that the main fracture
was formed in specimen #5 (Fig. 9a), accompanied by
extension and diversion along the butt cleat, and the entire
morphology was a little more complex compared with a
single main fracture in specimen #1 (Fig. 7a). The higher
the horizontal principle stress difference, the simpler the
fracture morphology, which is in line with the propagation
principle that a high stress difference controls the fracture
(Zou et al. 2016)
. When the stress difference
decreased, the fracturing fluid easily flowed into cleats with
Fracture complexity increases
lower cementing strength and the fractures tended to divert
along the weak cleat, giving rise to more complex
fractures. As Tan et al. (2017b) and
Mayerhofer et al. (2008)
showed in their research, in situ stress plays a major role in
controlling the propagation of hydraulic fractures. To get a
better fracturing effect, an appropriate stress difference
should be ensured during the fracking process. At the same
time, in order to make the hydraulic fractures extend
farther, traverse more cleats and obtain more complex
fractures, the stress difference cannot be set too low.
3.3.2 Effects of the horizontal principle stress difference
The horizontal principle stress difference coefficient is
defined as Kh, of which the formula is Kh ¼ ðrH rhÞ=rh.
The greater the value of Kh, the more evident the horizontal
principle stress difference. By comparing specimens #5, #6
and #7, it is evident that two parallel main fractures
connected with butt cleats were formed along the face cleat in
specimen #6 (Fig. 9b), whose entire morphology is the
most complicated of the three at 2 MPa. The main fracture
was formed both in specimens #1 and #8, while the
morphology of specimen #8 was more complex (Fig. 9d). As
for specimens #1 and #7, although they shared the same
value of Kh, the morphology of specimen #7 was more
complicated in virtue of its smaller stress difference
Based on the experimental results, it can be indicated
that Kh can control the main fracture propagation direction
for specimens under the same horizontal principle stress
difference (Fig. 9e). The greater the value, the more
obvious the tendency to propagate along the maximum
horizontal principle stress
(Dehghan et al. 2015b)
Kh is beyond 0.25, the main fracture is more likely to form
along the maximum horizontal principle stress in this
study, which is in line with the results of Guo’s (2014)
Through quantitative analysis of Kh (Fig. 10), it is
obvious that the fracture number decreases with an increase
in Kh at the same horizontal principle stress difference of 2
and 4 MPa, which is consistent with the trend of area ratio.
The fracture morphology is the most complex at a Kh of
0.25, with the greatest fracture number and area ratio. It is
also evident that the value of both fracture number and area
ratio of specimen at 2 MPa is greater than at 4 MPa,
indicating a higher fracture complexity.
3.4 Effects of injection rate
Injection rate is one of the key technical parameters
controlling fracture morphology
(Tan et al. 2017a; Wang et al.
. Figure 11 presents different fracture morphologies
at different injection rates. There was a single main fracture
along the butt cleat in specimen #9 when the injection rate
is 0.5 mL/min (Fig. 11a). It is found that most fracturing
fluid flowed along cleats or bedding planes when splitting
the specimen. The hydraulic fractures cannot be effectively
interconnected with cleats and bedding planes, leading the
fracturing fluid to penetrate into weak planes, which is in
accordance with the findings of Beugelsdijk et al. (2000).
When the injection rate increased to 1.5 mL/min
(Fig. 11c), the fracturing fluid penetrated into the cleat
system, making the weak cleats open. The hydraulic
fractures extended and diverted along butt cleats, accompanied
with the formation of branch fractures. The overall
morphology was a little more complex. The morphology was
the most complicated in specimen #11 when the injection
rate increased to 15 mL/min. The fractures initiated from
the direction of maximum horizontal principle stress and
diverted along the butt cleat during the propagation
process, resulting in many branch fractures. On the one hand, a
higher injection rate can lead to higher breakdown
pressure, which is determined by injection pressure, the stress
caused by fracturing fluid loss and the tensile strength of
coal. Due to the unique characteristics of coal,
well-developed cleats around the wellbore will lead to fracturing
fluid loss during the injection process. With an increase in
the injection rate, the increasing rate of net pressure will
increase as well as the stress caused by loss and the
injection pressure, leading to an increase in the breakdown
Morgan et al. (2017)
AlTammar et al. (2018)
have confirmed this conclusion through experiments. At
the same time, the simulation results obtained by
Jung et al.
through PFC2D are also consistent with the
conclusion. On the other hand, it can ensure that the main
fracture extended along the maximum horizontal principle
stress and branch fractures propagated along both sides of
it, which is consistent with the simulation results of Zhou’s
(2016). The hydraulic fractures were well connected with
the cleat system, increasing the fracture complexity.
However, only one main fracture was formed in specimen
#12 when the face cleat was parallel to the maximum
horizontal principle stress at an injection rate of 15 mL/min
(Fig. 11b). It may be because the injection rate was so high
that the hydraulic fracture extended rapidly to the boundary
of the specimen, resulting in a rapid energy release. As a
consequence, there was no good interaction between
hydraulic fractures and the cleat system and the complexity
of the fractures was not high.
Figure 12 shows that an appropriate increase in injection
rate is conducive to the formation of complex fractures. An
excessive injection rate will have little effect, or may even
be counterproductive when the face cleat is along the
maximum horizontal principle stress. Besides, the fracture
Fracture number (σH -σh = 2 MPa)
Fracture number (σH -σh = 4 MPa)
Area ratio (σH -σh = 2 MPa)
Area ratio (σH -σh = 4 MPa)
number and area ratio are greater when the angle is 90
than 0 under the same injection rate.
As can be seen from the experimental results, an
appropriate injection rate can make the natural cleat system
open, while an excessive injection rate will cause hydraulic
fractures to extend only in one direction. The interactions
between fractures and the cleat system will then be
reduced, inhibiting the formation of complex fractures.
Within an appropriate range, the higher the injection rate
is, the more complicated the fractures are. The existence of
butt cleats makes the fracture propagation more complex.
With an increase in injection rate, the fractures are more
complex when a is 90 compared with 0 . Since the in situ
stress state, the characteristics of the natural cleat system
and the bedding plane cannot be changed artificially, the
injection rate is the key to get better fracturing effects. A
high injection rate can open the natural cleats and create
new hydraulic fractures, forming fracture networks.
Therefore, the selection of a higher injection rate based on
the cleat orientation is of vital importance.
3.5 Effects of fracturing fluid viscosity
Two groups of experiments were conducted to discuss the
effect of viscosity in this section: 25.4 mPa s (specimen
#1) and 1.5 mPa s (specimen #13). Each group had the
same injection rate (1.5 mL/min) and horizontal principle
stress difference (4 MPa). The main fracture extended
along the direction of maximum horizontal principle stress
in each group (Fig. 13b). A single main fracture was more
likely to form in specimen #1, whereas more branch
fractures were generated near the wellbore in specimen #13. It
Cleats Butt cleat Face cleat Main fracture
Fig. 13 Fracture morphology under different fluid viscosities.
a 1.5 mPa s, b 2-D fracture propagation with the increase in the
fluid viscosity at the horizontal principle stress difference of 4 MPa
may be because fluid with lower viscosity infiltrates more
easily into cleats, generating more complex fractures.
Water-frac fluid has been used to generate complex
fractures in most stimulations.
Cipolla et al. (2009)
that stimulated reservoir volume created with slick water (a
fracturing fluid) was roughly 3.4 times that of cross-linked
gel (a fracturing fluid) and validated by gas production in
the Barnett shale. Active water and other low-viscosity
fracturing fluids have been widely used in CBM reservoirs
(Ma et al. 2014)
to keep the natural cleats open to connect
with hydraulic fractures, increasing the complexity of the
Gomaa et al. (2014)
noted that the fracturing
fluid type can strongly determine the degree of fracture
complexity. The lower the viscosity is, the more complex
the fractures are.
Figure 14 presents the pumping pressure curve of
specimen #13, from which we can see that both the
initiating and propagating pressures were lower than in
specimen #1 (Fig. 6a). Fracturing fluid with low viscosity is
more likely to infiltrate into the coal matrix, which
decreases the effective stress, promoting the generation and
propagation of fractures.
As shown in Fig. 15, the lower the fluid viscosity, the
greater the fracture number and area ratio and the greater
the possibility of forming complex fractures. It is obvious
that fracturing fluid with low viscosity can make cleats
open and facilitate interactions between hydraulic fractures
and cleats, which can enhance the stimulated volume of the
In consequence, mixed-fracturing fluid is recommended
in the fracking process. Fracturing fluid with high viscosity
is used in the initial period of fracturing to form obvious
main fractures, while fracture networks are formed at a
distance from the wellbore with low-viscosity fracturing
fluid subsequently. In this way, the interactions between
hydraulic fractures and natural fractures can be enhanced to
expand the stimulated reservoir volume. Moreover, the
hydraulic fractures and the wellbore can be effectively
connected, further improving the fracturing effects.
A large amount of coal fines was generated during drilling
process, which is difficult to clean up. The influence of coal
fines on fracture morphology and subsequent fracturing
effects were analyzed through two groups of experiments.
Both cleaned specimen #1 and uncleaned specimen #14
were set with an injection rate of 1.5 mL/min, a horizontal
stress difference of 4 MPa and a fracturing fluid viscosity
of 25.4 mPa s. From the fracture morphology, it can be
seen clearly that the main fracture was formed in specimen
#1, accompanied with branch fractures near the wellbore in
Fig. 7a. As for specimen #14, the fractures were
disorganized and no obvious main fracture is found in Fig. 16a, c.
Coal fines was not dispersed in the fracturing fluid but
gathered in front of the fractures (Fig. 16b), resulting in
abnormal fracture extension and propagation. As can be
seen by comparison, the existence of coal fines hinders the
fracturing effects and easily forms a resistant barrier on the
leading edge of the fractures, resulting in the failure to
produce effective fracture channels in coal. Fractures
cannot be interconnected effectively, and no fracture
network is generated.
In this paper, investigation of the effects of different face
cleat orientations, in situ stress, injection rate, fracturing
fluid viscosity and the existence of coal fines on fracture
extension mechanisms was undertaken on raw coal
specimens. The main conclusions are summarized as follows.
1. The most complex fractures are generated by the
interactions between fractures and cleats. A large
number of nonlinear branch fractures are formed near
the wellbore when the face cleat and the maximum
horizontal principle stress are not parallel or
orthogonal. The greater the angle between the maximum
horizontal principle stress and the face cleat, the more
likely the fractures are to propagate along the butt cleat
and the more complex the ‘‘step-like’’ factures.
The greater the maximum horizontal principle stress
difference, the greater the value of Kh, the simpler the
fracture morphology, and the more obvious the
tendency to propagate along the maximum horizontal
principle stress. It is advantageous to maintain an
appropriate stress difference to generate fracture
networks during fracking.
An increase in the injection rate is beneficial to
generate fracture networks due to the butt cleat. The
fractures are more complex with an increase in the
injection rate when a is 90 compared with 0 . Fluid
with low viscosity is more likely to infiltrate into coal
matrix, facilitating fracture generation and
The existence of coal fines inhibits fracturing. The
residual coal fines in the wellbore needs to be cleaned
up before fracturing to improve the subsequent
fracturing effects and enhance the production of CBM
Acknowledgements The study was funded by the National Science
and Technology Major Project of China (2016ZX05046004-003) and
Northeast Petroleum University Innovation Foundation for
Postgraduate (YJSCX2017-010NEPU and YJSCX2017-009NEPU).
Open Access This article is distributed under the terms of the Creative
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