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Journal of Natural Gas Science and Engineering 57 (2018) 21–30
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Journal of Natural Gas Science and Engineering
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Experimental study of changes in fractures and permeability during nitrogen
injection and sealing of low-rank coal
Junqiang Kanga,b, Xuehai Fua,b,∗, Shun Lianga,b, Furong Zhoua,b, Yushou Lib,c
Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process, Ministry of Education, China University of Mining and Technology, Xuzhou, Jiangsu,
221008, China
School of Resources and Geoscience, China University of Mining and Technology, Xuzhou, Jiangsu, 221008, China
State Key Laboratory for Geomechanics & Deep Underground Engineering, China University of Mining and Technology, Xuzhou, Jiangsu, 221008, China
Low-rank coal
To investigate the influence of nitrogen injection and sealing (N2eIeS) on the fracture and permeability of coal
reservoirs, two low-rank coal samples from the Fukang (FK) and Wudong (WD) mining areas in the southern
margin of the Junggar Basin, China, were collected and used for N2eIeS experiments. A Chandler Model 6100
Formation Response Tester (FRT) from the Chandler Company was used for N2eIeS experiments with sealing
times of 6, 18 and 36 h and a sealing pressure of 584 psi for the samples, and the real-time permeability changes
were monitored during the N2eIeS process. An NDP-605 NanoDarcy Permeameter was used to test the permeability with different effective stresses before and after N2eIeS, and the difference in pore distribution before
and after N2eIeS was determined by low-field nuclear magnetic resonance (NMR) for the samples. X-ray CT
(μCT) was used to observe the changes in the distribution of fractures before and after N2eIeS. The results
showed that the permeability of FK increased by 43.75%, 91.67% and 162.99% and that of WD increased by
13.96%, 49.92% and 73.68% after 6, 18 and 36 h of sealing time, respectively. For each N2eIeS period, the
permeability increased with increasing sealing time, while the change rate gradually decreased, as demonstrated
by a curve similar to the “Langmuir isotherm adsorption” curve. The stress sensitivity of permeability increased
after N2eIeS, and the decrease in permeability with increasing effective stress was greater than that of nonN2eIeS-treated samples. Low-field NMR showed that the amplitude of 100% water saturation had no obviously
changes after N2eIeS, which means that no new fracture formed after that. Meanwhile, X-ray CT images also
showed that no new fracture formed after N2eIeS, but the connectivity is enhanced. Further analysis showed
that N2eIeS dispersed fracture fillers and opened up the fractures of the coal reservoir, resulting in an enhancement in permeability, but also increased the degree of fracture closure, which caused an increase in the
stress sensitivity of the permeability.
1. Introduction
The permeability of coal reservoirs in China is generally low (typically lower than 1 mD), and gas injection is an effective way to improve
permeability (Zhu et al., 2003; Sayyafzadeh et al., 2015). Because of the
large amount of adsorption swelling caused by CO2 injection in coal
reservoirs, the reservoir permeability is reduced, and injection is difficult to maintain (Harpalani and Schraufnagel, 1990; Zarębska and
Ceglarska, 2008; Zhou et al., 2013). Therefore, CO2 injection is mostly
used in coal reservoirs with higher permeability. The first CO2 injection
test was conducted in the Fruitland formation, Allison Unit, San Juan
Basin, USA, with an initial permeability of the coal reservoir ranging
between 100 and 130 mD (Reeves and Oudinot, 2005). While N2 injection is more suitable for coal reservoirs with very low permeability
(Reeves and Oudinot, 2004). The adsorption amount of N2 is only approximately one-fourth that of CO2, and N2 scarcely reacts with coal
reservoirs and formation fluids (Shi et al., 2014); thus, the adsorption
swelling degree of coal reservoirs under N2 injection is smaller than that
under CO2 injection and is reversible (Bustin et al., 2008; Perera et al.,
2015; Zhang et al., 2015a,b). N2 injection for stimulating productivity
was first developed for the hydrous low-rank coal reservoir of the
Cretaceous Horseshoe Canyon Formation in Alberta, Canada (Hoch,
2005). The American ARI company carried out N2 injection for 34 lowrank coalbed methane (CBM) wells in the Fruitland formation, San Juan
Corresponding author. Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process, Ministry of Education, China University of Mining and Technology, Xuzhou,
Jiangsu, 221008, China.
E-mail address: (X. Fu).
Received 26 March 2018; Received in revised form 14 June 2018; Accepted 27 June 2018
Available online 30 June 2018
1875-5100/ © 2018 Elsevier B.V. All rights reserved.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
Fig. 1. Sampling sites and sample forms.
Basin, USA, which caused a fivefold increase in the total productivity,
and the recovery factor increased by 10–20% (Reeves and Oudinot,
2004). The production of a single well in the Ishikari coalfield has been
increased fourfold by N2 injection (Shi et al., 2008). N2 injection was
also carried out on high-rank coal reservoirs in the Yangquan, Luan and
Jincheng mining areas in the Qinshui Basin, China, but the effect on
productivity was not obvious (Ye et al., 2007; Nin et al., 2012; Li et al.,
A large number of experiments and numerical simulations of N2
injection for improvement of gas production have been carried out (Zhu
et al., 2002, 2003; Jessen et al., 2008; Shi et al., 2008; Mazumder and
Wolf, 2008; Zarebska and Ceglarska, 2008; Harpalani and Mitra, 2010;
Kiyama et al., 2011; Zhou et al., 2013; Wang et al., 2015). The experimental results of Zhou's injection of N2 into a saturated CH4 coal
reservoir showed that N2 injection can accelerate methane output by up
to 71% (Zhou et al., 2013). A numerical simulation by Wang showed
that N2 injection can effectively promote CH4 production. For highpermeability reservoirs, the N2 content required to produce gas, but for
low-permeability reservoirs, it is lower (Wang et al., 2015). Most studies have focused on N2 injection, resulting in partial methane pressure
reduction and methane desorption, thus increased CBM productivity
(Zhu et al., 2002, 2003). However, few studies have reported the pattern of variation of reservoir permeability caused by N2 injection, and
the reasons for those variations in permeability have rarely been discussed. In an engineering practice analysis, Ye et al. (2007) showed that
enhanced CBM recovery by N2 injection is caused by partial methane
pressure and permeability enhancement. It is not a good explanation for
the mechanism of N2 injection to increase productivity by only partial
methane pressure reduction and methane desorption. When high
pressure gas enters the reservoir, it not only has the effect of promoting
desorption of methane to the reservoir, but also the impact force
brought by high pressure gas will also destroy the fracture structure of
reservoir, and affect the permeability of reservoir. Hou et al. (2016)
research by inject air into coal reservoir shows that the compressive
strength and Poisson's ratio decrease by 16% and 8% after injection,
and by mathematical calculation, the permeability increases by 70%.
The results of Wang et al. (2015) shows that the total pore volume
markedly increases during N2 injection with increases in transition
pores, mesopores and macropores of 8.0%, 50.0% and 138.3%, respectively. Luo (2014) conducted laboratory experiments to shows that
the permeability of high-rank coal reservoirs is improved after N2 injection.
Previous studies have shown that N2 injection can improve reservoir
permeability, but it is not clear about the dynamic change of permeability and mechanism of increasing permeability during the process,
and there is a lack of research on permeability change under different
effective stress. Therefore, this paper selected two low-rank coal
samples using a Chandler Model 6100 Formation Response Tester (FRT)
to simulate the process of N2 injection and then sealed the inlet and
outlet of samples under the N2 atmosphere to simulate the closed environment of the underground coal reservoir after N2 injection. The
variation in permeability during N2eIeS was monitored in real-time
with FRT, the pattern of variation of permeability sensitivity under
different effective stresses were tested by an NDP-605 NanoDarcy
Permeameter, and pore distribution was tested by low-field NMR in
each N2eIeS period. The changes in the distribution of fractures and
minerals before and after N2eIeS were observed by X-ray CT. The results were summarized, and the characteristics and the mechanism of
permeability change were explored to further explain the reasons for
the productivity enhancement after N2eIeS.
2. Experiments and methods
2.1. Sample preparation
Two low-rank coal samples from the Fukang (FK) and Wudong (WD)
mining areas, southern margin of Junggar basin, China, were sampled
for this experiment (Fig. 1). Proximate analysis and macerals were
tested according to GB/T 212–2008 and GB/T 15588-2013 standards,
respectively. The volatile matter (Vdaf) and moisture content (Mad) of
the two samples were similar, but the differences of macerals between
these two coals obviously showed that the FK coal was higher in vitrinite content, while the WD coal was higher in content of inertinite
and minerals (Table 1). Uniaxial mechanical parameters were tested in
accordance with DZ/T 0276.19–2015 (DZ/T 0276.19–2015). The uniaxial compressive strength and residual strength of WD were greater
than those of FK, while the Young's modulus and Poisson's ratio were
lower (Table 2).
The coal samples were drilled into a cylinder with a diameter of
25 mm and height of 50 mm (the error was less than 1 mm) along the
direction paralleled to the bedding plane (Fig. 1). The coal pillar bottom
and top surface was polished by laser cutting machine to reduce the
error of the permeability testing experiments. After processing, the coal
samples were sealed in polythene bags and stored at low temperature,
approximately 4 °C, to prevent oxidation and moisture loss.
2.2. Test methods and experimental instruments
2.2.1. N2eIeS experiment
N2eIeS experiments were carried out in Fracturing acidification
Laboratory of Langfang Branch of PetroChina Exploration and
Development Research Institute using a Chandler Model 6100 FRT
produced by the American Chandler Corporation, which was used to
evaluate the effects of different fluids like gas, water and drilling fluid
Table 1
The test results of proximate analysis and macerals of WD and FK sample.
Rmax- Maximum vitrinite reflectance; Mad- Moisture, air-dried basis; Ad- Ash, dried basis; Ve Vitrinite; Ie Inertinite; L-exinite; TRD- True relative density; ARDApparent relative density.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
Table 2
The mechanical parameters of WD and FK sample.
Table 3
Experimental parameters for N2eIeS.
pressure (psi)
N2 pressure
sealing time
R- Uniaxial compressive strength; Rc- Residual strength; E- Young's modulus;
Ve Poisson's ratio; G- Shear modulus.
end of each-IeS test, gas permeability was tested under different confining pressures and NMR/μCT was conducted to measure the influence
of N2eIeS on permeability stress sensitivity and fracture structure,
on reservoir permeability (Frattarelli et al., 2014). The entire testing
process was automatically controlled by a computer (Fig. 2).
Before the N2eIeS experiments, equipment degassing treatment
and an air tightness test were performed. The equipment was degassed
by injecting N2 into the instrument for 2 h and vacuum treatment to
ensure the complete removal of air and other fluids in the equipment.
The tightness test was performed to monitor the pressure in the instrument by turning off the instrument inlet and outlet valve.
Subsequently, the sample was placed in the core holder of the instrument and was wrapped by a rubber ring in the holder to ensure that the
sample was uniformly stressed under the confining pressure and that
the gas did not pass through the surface of the sample wall. The size of
the sample was entered on the computer, and then the confining
pressure was slowly loaded to 500 psi. The reason for the gradual increase of pressure to the target value was to prevent the sample from
being forced instantaneously, which would break the sample. Then, the
N2 pressure was gradually increased to 580 psi by slowly opening the
N2 valve and increasing the confining pressure to 1015 psi. In the
process of gradually increasing the pressure, the confining pressure was
consistently kept greater than the gas pressure by 300–400 psi.
When N2 had completely penetrated through the sample and formed
a steady flow at the outlet, the permeability of the sample was observed
until the permeability value was stable for 1 h, and the stable value was
taken as the initial permeability (calculated by the Darcy's law formula)
under the pressure point. After measuring the initial permeability, the
core holder inlet and outlet valve were closed immediately while the
confining pressure and the N2 pressure in the sample remained constant, which called that the “N2 sealing”. N2 in the sample could not
flow due to the closure of the core holder, resulting in the inability to
calculate the sample permeability. Therefore, in order to monitor the
change of sample permeability in real time and minimize the impact of
the valve switch on the experiment, the core holder inlet and outlet
valve were opened every 2 h to measure the sample permeability.
Because N2 had completely passed through the sample, approximately
10 min was required to re-measure the permeability each time. The test
time selection requirement is to eliminate the impact on the test process
as much as possible while obtaining enough data points. After the
completion of the planned N2 sealing time, the experimental data were
preserved, and the sample was removed slowly.
In this paper, N2eIeS experiments were carried out in six groups,
and the specific experimental parameters are shown in Table 3. At the
2.2.2. N2 permeability tests under different confining pressures
The permeability before and after N2eIeS under different effective
stress was measured using an NDP-605 NanoDarcy Permeameter by the
non-steady state method. One of the advantages of the non-steady state
method is that the test time is relatively short (Jones, 1972; Freeman
and Bush, 1983), which can effectively reduce the influence of the
experimental process on the N2eIeS results.
The experimental condition was that the pore pressure (Vp) was 500
psi, with an error less than 10 psi, and the confining pressure (Cp) was
from 1000 to 3500 psi (six pressure points with each pressure interval
of 500 psi), with an error less than 20 psi (Table 4). After placing the
sample in the core holder, all the confining pressure values and the N2
pressure according to Table 4 were entered into the computer at once.
In the non-steady state method for measuring the permeability, the
permeability will continue to decrease until stable under the action of
the pulse, and the value at the stable point is the permeability under the
pressure point (Jones, 1972; Freeman and Bush, 1983). For the computer, the criterion for the stability of the permeability is the ratio of the
difference between the permeability and the average permeability
within 1 min and the average permeability is less than 1%, it is considered that the permeability has not changed at this time. So the
permeability test of the first pressure point was carried out until the
permeability change fluctuation was less than 1%/min, which meant
that the permeability value was under the pressure point. When the first
pressure point test was completed, the confining pressure was automatically increased according to the setting of the next pressure point.
2.2.3. Low-field NMR test
The basic principle of low-field NMR is that the hydrogen nuclear
(1H) component of water in coal fractures and pores will produce a
transverse relaxation signal (T2) interacting with the low frequency
magnetic field, releasing an attenuation signal completely different
from the hydrogen nuclear component in the coal reservoirs (Yao and
Liu, 2012). Then, the number of hydrogen atoms in the pores and
fractures of the coal reservoirs can be determined by detecting the T2,
and the characteristics of pores and fractures in coal reservoirs can be
analyzed (Yao and Liu, 2012). The T2 relaxation spectrum is in direct
Fig. 2. The sketch map of Chandler Model 6100 FRT.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
3. Results
Table 4
Samples size and experimental conditions of permeability test.
Diameter (mm)
Confining pressure (psi)
N2 pressure
The variation of the reservoir permeability during the process of
N2eIeS plays a guiding role in CBM well construction strategies.
Meanwhile, CBM productivity reflects a drainage and depressurization
process, and there is a gradual increase in effective stress, so the sensitivity of permeability to the effective stress affects the continuity of
CBM development (Shi and Durucan, 2005). Therefore, the following
two aspects will be discussed in terms of the process of N2eIeS: the
permeability change law and the stress sensitivity of permeability. NMR
data and μCT images can provide some explanations for these changes
during N2eIeS.
proportion to the pore radius, the longer the T2 time was, the greater
the pore radius was. Low field nuclear magnetic resonance (NMR) is an
important method to detect the pore characteristics of coal reservoirs
without damaging the structure of the coal. Based on the work of Yao
and Liu (2012), three identified T2 spectrum peaks at 0.5–2.5 ms (pore
diameter < 100 nm), 20–50 ms (100 nm < pore diameter < 1000
nm), and > 100 ms (pore diameter > 1000 nm) generally correspond
to micropores/transition pores, mesopores, and macropores/micro
fractures according to decimal pore classification (Hodot, 1966), respectively.
The low-field NMR tests were carried out using a RecCore-2500
2.38 MHz NMR analyser developed by the Research Institute of
Petroleum Exploration and Development in China. Firstly, the sample
was placed in the vacuum box for saturated water treatment, with a
vacuum pressure value of 1 psi and an evacuation time of 2 h. The
sample was then immersed in water for 24 h, and the T2 distribution in
saturated water was measured. Then, the sample was placed in a centrifuge for 1 h at a speed of 8000 r/min, and then the T2 of the centrifuged of sample was measured. The following test parameters were
set: the echo time was 0.6 ms, the echo number was 2048, the waiting
time was 5 s, the number of scans was 64, and the experimental temperature was 25 °C.
3.1. Permeability change during N2eIeS
To intuitively characterize the change of permeability with sealing
time, the Permeability change rate (ΔK) was defined as:
ΔKi =
Ki − K 0
× 100 i = 1,2,3,4,6,7,8
where ΔK in the permeability increment, Ki is the permeability of a time
point i, mD; K0 is the initial permeability. The permeability of the coal
samples was obviously improved after N2eIeS compared with the initial value (Table 5, Fig. 4). After N2 sealing for 6, 18 and 36 h, the
permeability of FK increased by 43.75%, 91.67% and 162.99%, respectively (Table 5), and that of WD increased by 13.96%, 49.92%,
73.68%, which showed that the increase in permeability was greater
with the increase in sealing time (Fig. 4).
The permeability increases nonlinearly with the increase of N2sealing time (Figs. 4 and 5). In each N2eIeS round, the permeability vs
N2-sealing time curve is similar to the “Langmuir isotherm adsorption”
curve (Fig. 4). The two samples underwent continuous N2eIeS for
three time rounds, and for each time round, the permeability did not
great change after approximately half of the sealing time (Fig. 4). To
intuitively characterize the change of permeability with sealing time,
the permeability increment (dΔK) was defined as:
2.2.4. X-ray CT test
The X-ray CT (μCT) can reconstruct the internal structure of the
reservoir without damage (Yao et al., 2009; Wang et al., 2013), which
can intuitively show the distribution and change of macropores and
fractures before and after N2eIeS. The μCT scans were performed on an
Xradia 510 Versa High Solution 3D X-ray Microanalyser equipment
manufactured by Carl Zeiss Corporation of Germany and the X-ray
source is a 225 kV tungsten target. Because in the CT scan, the size of
the sample is inversely proportional to the scanning resolution, that is,
the larger the sample size, the lower the detection resolution (Yao et al.,
2009). In the current size of 25 mm × 500 mm, the scanning resolution
is 24 μm. In order to be able to observe even smaller fractures, a fine
scan of the local position in the sample is performed to obtain a finer
scan image by scanning sample internal dimensions of 10 mm × 10 mm
(Fig. 3). The resolution of the scanned sample reaches 10 μm, which can
identify the fractures. In order to be able to accurately compare the
characteristics of reservoir fractures before and after N2eIeS, we
marked the test locations and test parameters during the μCT test.
dΔKi = ΔKi − ΔKi − 1
i = 2,3,4,6,7,8,9
where Ki is the permeability of a time point i, mD; Ki-1 is the permeability of a time point i-1, which is the last time point of time point i,
mD. The time interval between two time points is 2 h. The permeability
increment (ΔK) decreased gradually with increasing sealing time in the
two samples (Fig. 5). The data fitting by SPSS numerical analysis software showed that the permeability increment (ΔK) decreased logarithmically with sealing time, and the correlation coefficient (R2) was
greater than 0.75 (Fig. 5), which indicated that there was a significant
correlation between the permeability increment and the sealing time.
It was also shown that under the same N2 injection conditions, the
increase in the permeability of two low-rank coal samples was different.
Compared with WD sample, the initial permeability of FK samples is
relatively low, about one percent of that of WD (Table 5). After 36 h of
N2-sealing, the permeability of FK sample increased by 0.003375mD,
and that of WD increased by 0.131352mD. It can be seen that the increment in the permeability of WD sample is greater than that of FK
sample. However, compared with the initial value, the growth rate of
FK was 162.99%, and that of WD was 72.68%, which showed the
growth rate of FK samples was larger than that of WD. This means that
Table 5
Permeability test results of N2 -sealing for different times.
Sealing time (h)
Permeability (mD)
Permeability change rate
Fig. 3. The μCT scan position.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
Fig. 4. Real-time permeability change curve of WD and FK coal sample.
under the same CBM production conditions, if the nitrogen injection is
currently under the same output capacity, the gas production of CBM
well in the area like FK sample is better than that area like WD, though
the permeability increment of WD sample is larger than FK, but its
growth rate is lower.
For the 6- and 12-h sealing times, although the cumulative sealing
time was 18 h, the summed permeability increase was greater than that
of a one-time 18-h sealing time (Fig. 5). This phenomenon may be related to the change in fracture shape after unloading of the samples at
the end of each N2eIeS. Meanwhile, this result may also indicate that
the effect of increasing permeability with multiple rounds of N2eIeS is
better than that of a one-time injection under the same conditions in
actual engineering applications. Previous studies have shown that the
more the injection rounds are in the same injection time, the more
obvious the permeability increases (Hou et al., 2016).
Table 6
Equations of permeability and effective stress.
K = 0.0086e−0.00201(CP − VP )
K = 0.0605e−0.00402(CP − VP )
K = 0.0599e−0.00400(CP − VP )
K = 0.0213e−0.00203(CP − VP )
K = 0.2637e−0.00100(CP − VP )
K = 0.2914e−0.00101(CP − VP )
K = 0.3795e−0.00101(CP − VP )
K = 0.4385e−0.00111(CP − VP )
decreases exponentially with an increase in effective stress (Table 6,
Fig. 6). The relationship between permeability and effective stress is
shown in Table 6 and is consistent with the exponential decay law in
formula (2). The permeability changes obviously under effective
stresses of 500, 1000 and 1500 psi, and the permeability varies little at
the four subsequent pressure points. Comparing the permeability-effective stress curves of FK and WD, the stress sensitivity of the permeability of the FK sample was higher than that of WD, where the cf of FK
was 0.00067–0.00133 psi−1 and that of WD was 0.00033–0.00037
psi−1. Due to the smaller initial permeability (0.002258 mD) and
higher stress sensitivity of FK, the permeability of FK is close to 0 mD
when the effective stress is over 2000 psi, and the permeability-stress
curve is also steeper (Fig. 6a), while WD is the opposite (Fig. 6b). The
permeability increases more obviously at lower effective stress
(< 2000psi) after N2eIeS, while for the higher effective stress is not
(Fig. 6). The permeability of FK exhibited no change when the effective
stress was greater than or equal to 2000 psi, while showed that under
the current N2eIeS conditions, there may not be good permeability
enhancement for deep high-stress reservoirs.
From Table 6 and Fig. 6, it can be seen that the greater the permeability increase caused by N2eIeS is, the stronger the stress sensitivity of permeability is. This phenomenon is a paradoxical result for
the exploitation of CBM in that the increase of stress sensitivity leads to
3.2. Stress sensitivity of permeability
The process of CBM drainage involves an increase of the effective
stress (Chen et al., 2013). The greater the stress sensitivity of permeability, the faster the permeability drops during the process of CBM
drainage, which may lead to the shortening of the gas productivity
cycle of CBM wells.
The stress sensitivity of the permeability of coal reservoirs can be
expressed by the cleat volume compressibility (Seidel et al., 1992). In
permeability tests, the pore pressure is kept unchanged and the confining pressure is increased to achieve an increase in the effective stress.
Therefore, the influence of the adsorption deformation should not be
considered. In the equation of permeability and effective stress established by Seidle et al. (1992):
K = K 0 e−3cf (CP − VP )
sealing time(h)
Where K is the permeability at the corresponding pressure points, mD;
K0 is the Klinkenberg permeability, mD; cf is the cleat volume compressibility, psi−1; CP is the confining pressure, psi; and VP is the pore
pressure, psi; CP- VP is the effective stress.
Under different N2eIeS, the permeability of the two samples
Fig. 5. Relationship between permeability increment and sealing time.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
Fig. 6. Variation of permeability with different effective stress.
saturation, the better connectivity between pores and fractures, which
can reflect the change of permeability from another aspect (Mckee and
Bumb, 1988; Zhang et al., 2015a,b).
a faster decrease in permeability during the production process, resulting in reduced overall productivity of CBM wells.
3.3. Low-field NMR test
3.4. Reconstructions for fracture spatial distribution by X-ray CT
Low-field NMR can non-destructively compare changes in reservoir
pores before and after N2eIeS (Yao et al., 2012). During CBM development, the gas in the fracture, macropores and mesopores is Darcy
flow while in transition pores and micropores by diffusion (Clarkson
and Bustin, 1999; Shi and Durucan, 2005; Pan and Connell, 2012; Staib
et al., 2015). Therefore, in order to explore the mechanism of permeability change, mesopores, macropores and fractures are targeted analysis (T2 > 20 ms).
There is no obvious regularity in the amplitude of 100% saturated
water samples after N2eIeS (Fig. 7). That is only a slight decrease in
the amplitude corresponding to the mesopores, but no significant
change in macropores and fractures, indicating that the mesopores are
compressed. Previous studies have shown that high-pressure gas injection can result in damage to reservoir pore and fractures, and increase permeability (Hou et al., 2016; Wang et al., 2015). The results in
this paper were different from previous studies. The analysis considers
that the nitrogen pressure in this paper is low and cannot reach the
effect of fracturing reservoirs (Zhang et al., 2013; Majid et al., 2015;
Zhai et al., 2016; Zhu et al., 2016), and we also can see that from the
μCT images in the next section 3.4. During the N2eIeS process, the
samples are subjected to a long period of confining pressure, and the
sample undergoes a slight irreversible compression deformation, resulting in a decrease in pore volume (Wang et al., 2015; Hou et al.,
2016). The amplitude of irreducible water saturation samples showed
different changes in characteristics (Fig. 8). After the N2eIeS at different times, the amplitude gradually decreased after irreducible water
saturation. The amplitude of irreducible water saturation reflects the
pore size distribution of the irreducible water after removing the movable water, and it can reflect the degree of connectivity of the pores
and fractures (Yao et al., 2009). Under the same of amplitude of 100%
saturated water, the smaller the amplitude of irreducible water
Using X-ray CT technology, the fracture spatial distribution of coal
can be determined (Freyer et al., 2010). Here, 1200 slices were scanned
along the axial direction to obtain consecutive grayscale images of the
samples. Less fractures and minerals developed on the FK sample with
only two approximately orthogonal fractures and no mineral filling in
the fracture (Fig. 9a). WD sample developed more fractures, and the
width is wider than that of FK (Fig. 9c), which is why the WD permeability is larger than that of FK. What is more apparent is the presence
of large amounts of minerals in the WD sample, with many of them
filled in fractures (Fig. 9c). In the same area, there was almost no
change in fracture development before and after N2eIeS, and no new
fractures formed, but some unconnected fractures have been connected
after N2eIeS (Fig. 9b, d). In the grayscale image, the fractures are
darker and the coal matrix is lighter. A part of the fracture before the
N2eIeS can be identified as a fracture by the naked eye, but some of the
fractures are light in colour and consistent with the coal matrix and
cannot be identified by the software as connected fractures during the
automatic identification of fractures. After N2eIeS, the colour of the
shallower part of the fracture begins to deepen, and is identified as a
connected fracture under the same identification parameters.
It is difficult to visually characterize the development of fractures
before and after N2eIeS in two-dimensional images, and the three-dimensional reconstruction of the fracture can make up for this defect,
which can intuitively characterize the extension and connectivity of the
fractures. Through the three-dimensional reconstruction, it was found
that after the N2eIeS, the previously unconnected fractures achieved
connectivity, indicating that the blocked material was cleared (Fig. 10).
Fig. 7. Distribution of the T2 relaxation spectrum of saturated water.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
Fig. 8. Distribution of the T2 relaxation spectrum of centrifuged samples.
loose fillers in the fractures are dissipated, mainly coal matrix particles,
resulting in enhanced connectivity of the fractures (Fig. 11). The coal
matrix particles in the fractures are mainly due to the falling of the coal
matrix during the formation of fractures in the coal reservoirs, which
have weak adhesion to the fracture surfaces (Fig. 12a) (Laubach et al.,
1998; Liu et al., 2008, 2015; Dawson and Esterle, 2010; Zhao et al.,
2013). The minerals in the fracture, especially WD samples, are obviously invaded by the exogenous minerals and distributed in the form
of sheets in the fractures (Fig. 12b) (Spears and Widdowson, 1993;
Pitman et al., 2003). They have a strong bond with the fracture surface
and are not easily dissipated by high-pressure nitrogen.
N2eIeS is a process in which external gas invades the inside of coal
4. Discussion
In the current work, the permeability in real time in N2eIeS and
changes in fractures were investigated by using a series of test methods.
The experimental results showed that 1) the permeability increased to
varying degrees, with the change curve similar to the “Langmuir isotherm adsorption” curve in each N2eIeS period; 2) a greater increase in
permeability after N2eIeS led to stronger stress sensitivity of the permeability; 3) low-field NMR and μCT image showed that the reservoir
had no new fractures after N2eIeS but that unconnected fractures
achieve connectivity.
Based on the experimental results, we believe that after N2eIeS, the
Fig. 9. Comparison of fracture development before and after N2eIeS.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
Fig. 10. Comparison of fracture connectivity before and after N2eIeS.
Fig. 13. Schematic diagram of stress sensitivity analysis under different permeability changes after N2eIeS
Note: for the convenience of illustration, the fractures and fillers are modelled
as flat.
Fig. 11. Schematic diagram of fractures and pore changes before and after
Fig. 12. Distribution of coal matrix particles and minerals in fractures.
Journal of Natural Gas Science and Engineering 57 (2018) 21–30
J. Kang et al.
that N2eIeS has the function of communicating fractures and increasing reservoir permeability, and the intermittent N2eIeS effect is
better than continuous N2eIeS (Fig. 4). Shi et al. (2008) analyzed the
on-site data of the injection of CO2 into the Ishikari coalfield in Japan to
increase the production rate of coalbed methane. It was found that the
injection rate of CO2 increased by 60% after 15 days of nitrogen injection, and consider that the nitrogen injection communicated with
existing fractures (Shi et al., 2008). The experimental results provide
more direct evidence for that. This research result also provide some
additional thoughts for gas injection stimulation measures. When gas
injection stimulation measures are performed at the site, injection time
can be increased to achieve better permeability enhancement and methane desorption efficiency, and intermittent nitrogen injection can be
used. Under the repeated pressure impact, the permeability of the reservoir can be improved and the production efficiency can be increased.
reservoirs from large apertures to small apertures, and macro-fractures
and micro-fractures would be affected firstly. Fractures are the main
contributors of permeability, and have great influence on permeability
changes. Moreover, because the larger width between the fracture
surfaces produces a greater moment applied to the filler surface when
N2 is invading, it is more likely that the coal matrix particles will be
destroyed (Müller, 1969). When N2 intrudes into macropores or mesopores, it contributes less to permeability because the width, and
moment are smaller that less prone to destruction. These two factors
lead to an increase in permeability with N2eIeS characterized by a
gradual decrease of the increment, similar to the “Langmuir isotherm
adsorption curve”. The enhancement of stress sensitivity of permeability after N2eIeS can also be reasonably explained. It was assumed
that the fracture width was L and the effective width was L1 due to the
fracture was filled partially, while N2eIeS results in a portion of the
matrix particles being discharged, with the effective width becoming
L2, wherein L2 > L1. After N2eIeS, if the permeability increment ΔK1
is greater than ΔK2, then the effective width L21 is also larger than L22,
which means that the maximum fracture closure degree for the effective
width L21 was also larger than that of L22 for a fracture (Fig. 13). When
the confining pressure is increased, the fracture of the sample with
greater permeability increments is closed more tightly, and the permeability drops faster. Macroscopic reflection means that the stress
sensitivity of permeability is greater. Although N2eIeS results in better
fracture connectivity, this does not mean that all fractures are connected, only that some of the weak points were destroyed.
Compared with previous studies, the current work focused on the
influence of gas injection on reservoirs using multiple methods with
same samples and explored the changes of permeability in real time for
the first time. There is very little research on this aspect (Shi et al.,
2008; Luo, 2014; Hou et al., 2016). A lot of research has been done on
gas injection experiments and numerical simulations (Zhu et al., 2002,
2003; Jessen et al., 2008; Mazumder and Wolf, 2008; Zarebska and
Ceglarska, 2008; Harpalani and Mitra, 2010; Kiyama et al., 2011; Zhou
et al., 2013; Wang et al., 2015), but the studies, including CO2 and N2
injection, the increase in methane production rate was often attributed
to the competing adsorption (CO2) with CH4 and lower partial pressure
(N2) of CH4, and theoretical models supported this (Zhu et al., 2003;
Zhou et al., 2013; Wang et al., 2015). The analysis of the results is
mainly based on the analysis of multi-component adsorption equations,
and the theoretical simulation does not consider the reservoir fracture
and filler. Some studies use briquette to conduct research, which destroys the original structure of the reservoir (Wang et al., 2014, 2015).
Fractures are widely distributed in coal reservoirs, which are filled with
varying degrees of inorganic minerals and pulverized coal (Laubach
et al., 1998; Dawson and Esterle, 2010). The high-pressure gas formed
by the gas injection will inevitably affect the filler of the fracture, which
will affect the permeability of the reservoir that was proved by multiple
methods in the current work. Hou et al. (2016) used high-frequency
pulsed air (78% N2) to act on coal reservoirs and found that the permeability of reservoirs gradually increased with increasing time. Its
pulse pressure is 6Mpa, which is 2 MPa higher than the current work
and far below the pressure required for reservoir fracturing measures
(Ren et al., 2014; Wu et al., 2018). Different from the current work, Hou
et al. (2016) did not compare the same sample after air injection and
the pulsed air is different from the actual gas injection process. However, both work support the physical destruction of the reservoir by gas
injection with relatively low pressure that can be visually seen from
μCT images before and after N2eIeS (Fig. 9), which is often overlooked
in previous work.
For now, gas injection has been a very effective means to increase
the productivity of coalbed methane (Shi et al., 2008; Reeves and
Oudinot, 2004; Nin et al., 2012), and its strategy also mainly considers
that the competitive adsorption with CH4 and reduces the partial
pressure to achieve the increase in production, thus formulating the
corresponding gas injection stimulation measures. The results showed
5. Conclusions
In this paper, two low-rank coal samples were used for 6/12/
18 h N2eIeS experiments to investigate the effect of N2eIeS on reservoir fractures and permeability. The permeability during N2eIeS
was monitored in real time, and the characteristics of fractures before
and after N2eIeS were explored using gas permeability, low field NMR
and μCT. The following experimental results were obtained:
1) The permeability of coal reservoirs gradually increased with increasing N2 sealing time. In each N2eIeS period, the permeability
showed a “Langmuir equation” curve shape, and the effect of multiple N2eIeS rounds was better than that of a one-time injection.
The greater the increase in permeability after N2eIeS, the stronger
the stress sensitivity of the permeability, which means that the
permeability will decline rapidly as the effective stress increases.
2) low-field NMR and μCT showed that the reservoir had no new
fractures after N2eIeS but that the connectivity was enhanced and
minerals and coal matrix particles in the fracture surface had been
significantly reduced by μCT reconstruction.
3) The mechanism of permeability variation is N2eIeS leads to the
dispersion of the coal matrix in fractures, increases the connectivity
of fractures, which increases the permeability of reservoirs.
Meanwhile, the permeability stress sensitivity is obviously increased
due to the lack of the bolster in the fracture.
The authors declare no competing financial interest.
This study was supported by the development of large oil and gas
fields and CBM in major national scientific and technological projects
(2016ZX05043-004-001), the National Natural Science Foundation of
China (41772158, 41602174) and the Key Laboratory of Coalbed
Methane Resources and Reservoir Formation Process of the Ministry of
Education (China University of Mining and Technology) (No. 2018006). The author is grateful to the China Petroleum Exploration and
Development Research Institute for supplying the relevant experimental equipment.
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N2eIeS: nitrogen injection and sealing
Vdaf: volatile matter (dry ash free base)
Mad: moisture (air-dried basis)
Vp: pore pressure
Cp: confine pressure
K: permeability
ΔK: permeability change rate
Ki: permeability at a time point i
K0: klinkenberg permeability
cf: cleat volume compressibility
L: fracture width
L1: effective fracture width
L2: effective fracture width after N2eIeS
L21: effective fracture width-1 after N2eIeS
L22: effective fracture width-2 after N2eIeS
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