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Investigation of Methane Desorption and its Effect on the Gas Production Process from Shale: Experimental and Mathematical Study Jinjie Wang, Mingzhe Dong, Zehao Yang, Houjian Gong, and Yajun Li Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b02033 • Publication Date (Web): 30 Nov 2016 Downloaded from http://pubs.acs.org on December 5, 2016
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Energy & Fuels
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Investigation of Methane Desorption and its Effect on the Gas Production
2
Process from Shale: Experimental and Mathematical Study
3
Jinjie Wanga,c, Mingzhe Dongb,*, Zehao Yanga, Houjian Gonga, Yajun Lia a
4
College of Petroleum Engineering, China University of Petroleum (Huadong), Qingdao, China, 266580
5
b
Department of Chemical Engineering, University of Calgary, Calgary, AB, Canada, T2N 1N4
6
c
Faculty of Earth Resources, China University of Geosciences, Wuhan, Hubei, China, 430074.
7
ABSTRACT:
8
production process is more complex in shale reservoirs than in conventional reservoirs, mainly because of the
9
ultralow permeability of the matrix, complex pore structure and organic components that cause desorption.
10
Long-term gas production comes from both free gas expansion and adsorbed gas desorption. In addition to the
11
estimation of the gas content reserve in a reservoir, an accurate description of the effect of adsorbed gas on the
12
dynamic gas production process is meaningful for predicting gas production from shale. Experimental and
13
mathematical efforts have been undertaken to obtain an accurate description of the gas production process. This
14
paper investigates desorption and diffusion, which are two of the key mechanisms in shale matrix during gas
15
production. The experimental results suggest that the gas production process from shale can be divided into two
16
stages: free gas expansion from inorganic micropores in the early stage and the subsequent desorption–
17
diffusion-dominated stage in the matrix. Furthermore, the effects of production pressure (equal to the external
18
pressure), temperature and particle diameter on the dynamic gas production process were examined based on the
19
variable-volume volumetric method (VVM). Both higher external pressure and higher temperature lead to the
20
lower contribution of desorbed gas to the total gas production. Moreover, the delayed adsorption diffusion
21
model, which considers the dynamic gas desorption/adsorption, is presented to adequately represent the
22
measured dynamic experimental data. The calculated gas production curves are in good agreement with
23
experimental observations. Mathematical calculations of the production rate also suggest and confirm the
24
two-stage process of gas production. This paper enables operators to develop a primary understanding of how
25
gas desorption affects the performance of a shale gas well and provides insights into the analysis of the gas flow
26
regime and more accurate forecasting for shale gas production.
27
1. INTRODUCTION
A number of potential gas reserves are present in shale reservoirs around the world. The gas
28
Shale gas efficiently helps relieve the global resource shortage and has recently become a topic of
29
considerable interest in energy investigations.1-3 China is estimated to have the world’s largest shale gas reserves,
30
comparable to the resources of its conventional natural gas.4 In contrast to conventional reservoirs, shale is *
Corresponding author at: University of Calgary, Calgary, Alberta, T2N 1N4, Canada.
Tel: +1 403 210 7642. Fax: +1 403 284 4852. E-mail:
[email protected] (Mingzhe Dong) 1
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composed of organic and inorganic mineral content5,6, which constitutes a system of ultralow-permeability
32
matrix with kerogen and natural/artificial fractures.7,8 Although significant progress has been made in horizontal
33
wells and the hydraulic fracturing of shale gas reservoirs, gas recovery remains as low as approximately 10–30%
34
of the original gas in place.9,10 It is commonly accepted that gas developed in shale comes from two sources:
35
free gas in the matrix pores and natural fractures and adsorbed gas on the surface of pores within kerogen and
36
clay minerals in the matrix.11,12 One of the issues yet to be addressed is the lack of shale gas production prediction
37
and depiction of the production process by considering the dynamic gas adsorption/desorption process.
38
Knowledge of the transport properties of the shale matrix is important for accurately predicting gas
39
production. Although permeability of the fracture is an important parameter for gas flow in a shale reservoir, the
40
pore size and pore distribution in the shale have a significant impact on the gas production process.13-15 Shale
41
contains a large number of nanometer- to micrometer-sized pores.16-19 The small size of the pores in kerogen
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makes the specific surface area for shale large; hence, gas production processes that depend on surface area, such
43
as diffusion and desorption, become important. Compared with conventional gas reservoirs, shale gas reservoirs
44
may produce a considerable amount of gas from desorption and will exhibit a stable production period.20 Gas
45
desorption may be a major gas production mechanism and can be an important factor for ultimate gas recovery.
46
In addition, the presence of kerogen in shale increases its porosity and lowers the permeability of the reservoir.
47
The kerogen pores are primarily nanoporous, and the permeability ranges from tens to hundreds of nD.21-23
48
Because kerogen behaves as an additional rock component with the capability of storing and providing
49
hydrocarbons during gas development, identifying the relative proportions of free gas and desorbed gas is
50
important when assessing the shale gas-in-place and designing the production strategies effectively.24 However,
51
only limited attention has been paid to desorption and its effect on the description of dynamic methane
52
production at isothermal and constant well pressure. Neglecting the gas desorption effect might lead to
53
underestimation of gas production potential and misunderstanding in the dynamic production history prediction,
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particularly in shale formations with higher total organic content (TOC).
55
Some attempts to develop experiment and mathematical models have been under taken on the production
56
process in shale.25-27 Research groups worldwide have addressed shale-related problems using different
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approaches, and the outputs of experimental results are steadily increasing.28-30 Some studies have indicated that
58
15% to 85% of the total gas in shale may exist as adsorbed phase in organic matter.30 Therefore, a significant
59
property impacting shale gas production is the desorption of gas in shale. The adsorption/desorption isotherm,
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which is the most widely used method, demonstrates the capacity of the reservoir rock to hold adsorbed gas with
61
respect to pressure at constant temperature.5,24 The pressure around the sample changes gradually during the 2
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measurement of the adsorption/desorption isotherm until equilibrium. The release of adsorbed gas is pressure
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dependent, so production pressure can affect the contribution of adsorbed gas to gas production. However, the
64
pressure vibration during each isothermal test can also significantly impact the dynamic gas transport. Therefore,
65
further research on the adsorption and its effect on the gas production process should be undertaken. Others
66
have attempted to record the pressure decay history to analyze the unsteady production process of shale gas or
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approximate ‘constant pressure’ during gas transportation in shale.31,32 Measurements tracing the bottom
68
pressure of a well in Changqing Oil Field in China indicated that no discernable pressure drop occurred for as
69
long as two years. It is reasonable to assume that the external pressure of a matrix should be constant, and study
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of the gas production process under constant external pressure should be conducted. However, the current
71
literature does not provide insights into the dynamic gas production process, which exhibits the real production
72
process with constant production pressure, nor does it discuss the accurate division of the gas transport stages.
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This gap in the literature is mainly due to the lack of sufficient control of the production or external pressure
74
during the test. Here, external pressure denotes the pressure around the shale particle. Other factors related to the
75
production capacity of shale include the specific surface area, pressure, temperature, pore diameter, and sorption
76
affinity.33,34
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Some gas transport models have been proposed that consider both free gas and adsorbed gas
78
transportation.35-39 Three types of mechanisms could play a role in gas transportation in shale: Darcy flow,
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diffusion (Fickian diffusion, Knudsen diffusion and surface diffusion) and desorption.40 Currently, shale gas is
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produced mainly through primary recovery by reservoir depressurization. In the primary decrease of reservoir
81
pressure, methane desorbs from the internal kerogen surfaces, concentrates in the natural or manmade fractures,
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migrates toward the wellbore, and then flows up to the ground surface through the wellbore annulus. The flow
83
through the cleat is pressure-driven and may be modeled using Darcy’s law, whereas flow through the matrix is
84
assumed to be concentration-driven and is modeled using Fick’s law. Carlson and Mercer35employed Langmuir
85
isotherm theory to consider the effect of desorption behavior of shale gas and described the effect of diffusion
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by Fick's law. Javadpour et al.11 systematically introduced the Knudsen mechanism into gas diffusion in shale
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with a small pore diameter. Javapour41 further proposed a diffusion model for shale gas containing viscous
88
diffusion and Knudsen diffusion. These two diffusion mechanisms were coupled in the form of linear
89
summation. The viscous diffusion in the model was corrected by the slip effect. Ozkan et al.42 presented a
90
dual-porosity multiple-fractured horizontal well model for shale gas reservoirs. Civan21 coupled the mechanisms
91
of viscous diffusion and Knudsen diffusion through a function of the Knudsen number in the form of a product.
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Freeman et al.43 and Yao et al.36 mixed the diffusion mechanisms through the dusty gas model (DGM). However,
3
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little attention has been given to the systematic investigation and comparison of the dynamic gas desorption
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effect on the gas production process for shale gas reservoirs. In addition, there is limited material in the
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literature on the contribution share of free gas and desorbed gas to the total gas production. Hence, a detailed
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and systematic study of dynamic gas production in shale is necessary.
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This paper presents new experimental results investigating the process of gas production in shale. The
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dynamic gas production in shale is obtained according to the dynamic record of gas diffused out of and desorbed
99
from shale. Fifty-eight tests were conducted under constant external pressure of three temperatures and five
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pressures for three shale samples with different particle diameters. Furthermore, the effect of external pressure,
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temperature and particle diameter is discussed in depth. Additionally, by combining the experimental results
102
with a corresponding mathematical model, information is obtained on the dynamic gas production process, the
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contributions of free gas and adsorbed gas to the total gas production, the apparent diffusion coefficient and the
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adsorption/desorption rate coefficient by considering the effect of kerogen. Moreover, the gas production
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process is experimentally divided into two stages, as has been confirmed mathematically by calculating the
106
critical point.
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2. BACKGROUND
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2.1 Variable-volume Volumetric Method
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The variable-volume volumetric method (VVM) was designed to study the gas production process in
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shale.27,30 The main concept of the VVM is measuring the gas volume produced from a shale sample by
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changing the system volume and keeping the external pressure of the shale particles constant. The sensitivity
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and accuracy of the approach have been verified by comparing the test results with the constant-volume
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volumetric method.
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Figure1 shows a schematic diagram of the experimental setup. The experimental procedures include the
115
following five steps: 1) Leak test: Before adding a shale sample into the sample cell, helium is injected into the
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system (including the reference cell, sample cell and pipelines) to check the leakage. The leakage will be
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guaranteed if no pressure drop is detected for 4 h. 2) Sample preparation: according to the volume of the sample
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cell, approximately 160 g of crushed shale samples is dried, weighed, sealed in the sample cell, and degassed at
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10-3 Pa for 4 h. 3) Volume determination: the volume of the reference cell plus connected pipelines and the
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volume of the sample cell plus connected pipe lines are accurately measured using the equation of state of real
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gas. 4) Gas volume recording: both the temperature and external pressure are maintained at the designed
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constant values during each test, as guaranteed by a dual temperature control system and a pump with an 4
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accuracy of ±2.6 µL. Thus, the volume change of the gas system is recorded over time, which shows the
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dynamic process of desorption–diffusion. 5) Gas saturation: after reaching the equilibrium state of each test, the
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pressure of the sample cell is reduced to and saturated at the next pressure for the following test.
126 127 128 129
Figure 1. Schematic diagram of the experimental apparatus29 Based on the recorded volume change over time, the amount of gas produced under a specific test condition can be calculated with the following equation:
∆V =
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PVz 0T0 P0 zT
(1)
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where △V denotes the volume of gas produced at standard conditions (Scm3/g); P, V, T, and z denote the
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pressure (MPa), volume (cm3), temperature (K), and compressibility factor under the experimental conditions,
133
respectively; and P0, T0, and z0 are the pressure (MPa), temperature (K), and compressibility factor under
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standard conditions, respectively.
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The advantages of the VVM are as follows: (i) The dynamic desorption process can be recorded through
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this method, which will simulate the actual production history of a shale gas field. (ii) The experimental
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conditions, particularly the pressure, are neither too sensitive to control nor too slow to respond for experimental
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management, and thus, the measurement is easy to operate and more reliable. (iii) The VVM method provides
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the experimental data for obtaining the desorption rate coefficient, which will be utilized to obtain the
140
contribution of free gas and desorbed gas and to further predict gas production in a gas shale field.44
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2.2 Delayed Adsorption Diffusion (DAD) Model
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Under a certain pressure and temperature, one or more gas transport mechanisms coexist in shale rocks. A
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comprehensive constitutive equation is designed to describe this gas production process to facilitate field
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application. The core issue is to characterize the share of each transport mechanism in the total transport, 5
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particularly the additional amount of gas produced due to the existence of kerogen in shale. Therefore, based on
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the knowledge of free gas flow in pores and adsorbed gas adsorption/desorption from kerogen, we define the
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apparent gas diffusion coefficient (D), adsorption rate coefficient (λ), and desorption rate coefficient (µ) in this
148
study as the physical parameters of free gas diffusion and adsorbed gas adsorption/desorption, respectively. Based
149
on this consideration, a numerical model derived and modified from Fick’s law is27
∂c f
150
∂t
= D(
∂ 2c f ∂r
2
+
2 ∂c f ∂ca )− r ∂r ∂t
(2)
151
where cf is the concentration of free gas in the pore space of the shale particle (spherical, mol/m3), D is the apparent
152
gas diffusion coefficient (m2/s), r is the distance to the center of the shale particle (m), ca is the equivalent surface
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concentration or adsorbed gas concentration (mol/m3), and t is time (s).
154 155
The dynamic gas adsorption/desorption process before equilibrium can be described with the following equations:41
∂ca = λ c f − µ ca ∂t
156
(3)
157
where λ is the adsorption rate coefficient (s-1) and µ is the desorption rate coefficient (s-1).When λ×cf is smaller
158
than µ×ca—that is, the desorbed rate is higher than the adsorbed rate—the gas stored in kerogen starts to produce.
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The relationship between λ and µ under equilibrium pressure is expressed as
160
c eq λ = R = ae q µ cf
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where cfeq is the equilibrium concentration of free gas in the pore space (mol/m3), caeq is the equilibrium
162
concentration of the adsorbed gas concentration on the surface (mol/m3), and R is the ratio of caeq and cfeq.
(4)
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Eqs. (3) and (4) reveal the interaction or the influence of the adsorbed gas on the dynamic gas production
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process. It is assumed that the gas concentration at the external boundary (cfe) remains constant during the
165
experiment. The internal boundary condition is an impermeable boundary condition. The initial concentration in
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the pore of the particle is cfi, and the initial equivalent surface concentration on the surface of the pore is cai. For the
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gas production process, the external boundary concentration (cfe) is smaller than the initial concentration (cfi) in
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the pore of the particle. r0 is the radius of the shale particle. Thus, the boundary conditions and initial conditions
169
can be expressed as follows:
170
The boundary conditions: 6
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cf
= c fe
(5)
=0
(6)
∂c f
172
173
r = r0
∂r
r=0
The initial conditions:
174
cf
175
ca
t = 0 ,0 ≤ r < r0
t = 0,0 ≤ r < r0
= c fi
(7)
= cai
(8)
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The physical parameters for the gas transport process are denoted as the apparent gas diffusion coefficient,
177
adsorption rate coefficient and desorption rate coefficient, which might reveal the nature of the gas–solid
178
interaction as a dynamic process. By solving the above equations, the analytical solutions for the free gas
179
concentration (cf) in the shale particle and equivalent surface concentration (ca) of adsorbed gas at position r are
180
equal to27
181
182
183
184
185
186 187
∞
( c f 0 − c fi ) e Pn t sin( m n r )
n =1
p r r sin( m n r0 ) λµ − n (1 + ) cos( m n r0 ) + 2 mn D ( pn + µ ) 2 r0
cf = cf 0 + ∑
n=1, 2, 3 ···
( ca 0 − cai ) µ e Pn t sin( mn r ) pn r r sin( mn r0 ) λµ n =1 ( − (1 + ) cos( mn r0 ) + )( pn + µ ) 2 r0 2 mn D ( pn + µ ) ∞
ca = ca 0 + ∑
(9)
(10)
The expressions of pn and mn in Eqs. (9) and (10) are as follows:
pn = −
Dn2π 2 + r02 (λ + µ) ± −4r02 Dn2π 2 µ + ( Dn2π 2 + r02 (λ + µ ))2 2r02
mn = −
pn (λ + µ + pn ) D( pn + µ )
(11)
(12)
By integrating the total concentration from the surface of a particle to its center, the amount of gas produced from the particle at an arbitrary time can be obtained as
7
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r0
V (t ) = Vm ∫ (c f 0 + ca 0 − c f − ca ) ⋅ 4π r 2φ dr =
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4π r03φ (c fi − c f 0 )(ca eq + c f eq )Vm
0
188
3c f eq
∞
8π r0φ (c fi − c f 0 ) D2e pnt kn ( pn + µ )2 (r0 kn cos(r0 kn ) − sin(r0 kn ))
n =1
pn (r0 pn (λµ + ( pn + µ )2 ) cos(r0 kn ) − 2 Dkn ( pn + µ )2 sin(r0 kn ))
−Vm ∑
(13)
189
Eq. (13) illustrates that when the time for gas transport is sufficiently long, the total produced gas volume is
190
not associated with the adsorption/desorption rate coefficient. That is, the adsorption/desorption rate coefficient is
191
the parameter that reveals the dynamic process before the adsorption/desorption and diffusion equilibrium are
192
reached. The adsorption/desorption rate coefficient and apparent diffusion coefficient for each isothermal and
193
constant external pressure condition can be obtained by fitting Eq. (13) with the experimental data based on the
194
least-squares method. In addition, the amount of free gas and desorbed gas produced can be obtained by
195
integrating Eqs. (9) and (10). Then, the production rate for free gas and desorbed gas can be calculated
196
accordingly.
197
3. EXPERIMENTAL
198
3.1 Sample Characterization
199
The shale samples studied in this paper were collected from Lower Jurassic Ziliujing Formation of Sichuan
200
Basin, which is located on the upper Yangzi block in the eastern Sichuan fold belt in China. The total carbon
201
contents for shale samples from two strata are 1.7% and 4.7%. The permeability of the sample is between 0.6 to
202
1.68 mD. They seem to be higher than the published shale permeabilities in the literature.45-47 This is mostly
203
because there are micro-fractures distributed in the shale cores. The average porosity for the sample is
204
3.76%.The shale samples were originally sieved using the shaker screen, and three of the diameters were chosen
205
for this study. We primarily use scanning electron microscopy (SEM) and N2adsorption to calculate and analyze
206
the pore structure in this study.
207
Scanning electron microscopy (SEM)
208
Shale matrix has a complex pore structure, with pore sizes ranging from nanometers to micrometers. The
209
BIB-polished cross-sections were Au-coated and imaged with an SU 8000 microscope (Hitachi, Ltd., Tokyo,
210
Japan) with a backscatter detector for phase contrast imaging. From BIB cross-sections, large areas were
211
selected to be imaged at magnifications of 5,000 and 100,000 using 10–20% of overlap to create a large
212
representative map to study the pores down to the SEM resolution.
213
N2 adsorption/desorption isotherm 8
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Knowledge of the pore size distribution is critical for understanding the mechanism of the gas desorption–
215
diffusion process. The matrix pore structure is difficult to characterize due to the wide pore size distribution, and a
216
large portion of porosity is distributed in nanopores associated with kerogen and clays.18 Fluid invasion methods
217
have historically been used to characterize shale samples but have been found to be inaccurate in showing the pore
218
size distribution. Liquid nitrogen desorption (LND) is the most widely used means of depicting the pore structure,
219
interpreted using the multi-point Brunauer–Emmett–Teller (BET) method.48 Samples are first sealed into the test
220
cell. Liquid nitrogen is then utilized as the test liquid to obtain the desorption isotherm at the designed pressure.
221
3.2 Adsorption Isotherm Measurement
222
The selected shale samples are accurately weighed and sealed into the sample cell, maintaining the
223
temperature within ± 0.1 K. The sample cell is evacuated after the leak test is finished. Before gas adsorption,
224
the void volumes of the test cells are measured with helium gas. After another evacuation with a vacuum pump,
225
methane is injected, and the test pressure steadily increases from atmospheric pressure to the highest pressure.
226
The time for every pressure point to reach equilibrium is typically more than 12 h, after which the pressure is
227
raised to the next pressure point, until the highest designed pressure is attained.
228
3.3 Methane Production Process Measurement
229
The amount of gas diffused out of and desorbed from shale is determined by recording the change in gas
230
volume at an isothermal and constant external pressure with the VVM.30 The dynamic gas production volume
231
over time is recorded during each measurement of the VVM. The production process of shale is investigated
232
under three temperatures and five external pressures with shale samples of three diameters. The schematic
233
diagram of the apparatus is shown in Figure 1.The shale sample is first saturated at the highest saturation
234
pressure, and then, a pressure difference is created by releasing a proper amount of gas from the reference cell.
235
The external pressure of the sample is held constant by changing the volume of the test system. After each
236
measurement, the external pressure is reduced to the next external pressure until the last pressure point.
237
4. RESULTS AND DISCUSSION
238
The real-time dynamic gas production process of shale at constant external pressure and temperature
239
conditions was investigated using the VVM. All 58 experimental and calculated results are summarized in Table
240
1, including the test conditions (external pressure and temperature), incremental produced amount of gas (△Vt),
241
processing time of each test (t), apparent diffusion coefficient (D) and contribution of desorbed gas to the total
242
gas production (Cde).
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Table 1. Summary of Experimental Results for the Dynamic Gas ProductionProcess Number
External pressure (MPa)
Temperature (K)
△Vt (Scm3/g)
t (min/min)
D (10-12m2/s)
Cde (%)
Particle diameter (µm)
1
13.99
308.15
0.08
41
14.0
29.2
1420
2
10.53
308.15
0.21
80
11.5
32.4
1420
3
6.84
308.15
0.36
95
8.9
37.2
1420
4
3.62
308.15
0.56
140
6.1
40.5
1420
5
0.50
308.15
0.90
150
2.4
42.2
1420
6
13.97
313.15
0.08
25
17.1
27.7
1420
7
10.61
313.15
0.17
50
13.0
30.1
1420
8
7.10
313.15
0.35
75
11.8
34.5
1420
9
3.64
313.15
0.45
81
8.7
38.9
1420
10
0.53
313.15
0.72
116
4.8
40.7
1420
11
13.96
318.15
0.09
26
18.4
26
1420
12
10.40
318.15
0.21
45
14.8
27.8
1420
13
7.02
318.15
0.33
49
12.3
32.7
1420
14
3.53
318.15
0.51
80
9.7
37.2
1420
15
0.38
318.15
0.68
117
5.8
39
1420
16
13.74
308.15
0.07
29
14.0
29
360
17
10.35
308.15
0.22
37
11.4
32.7
360
18
7.00
308.15
0.34
43
9.0
36.8
360
19
3.14
308.15
0.58
63
6.2
39.9
360
20
0.14
308.15
0.87
137
2.5
41.3
360
21
13.54
313.15
0.05
26
17.0
27.8
360
22
10.25
313.15
0.19
50
13.1
30.4
360
23
6.81
313.15
0.33
58
11.7
35.1
360
24
3.50
313.15
0.46
65
8.8
38.6
360
25
0.16
313.15
0.78
113
4.8
40.5
360
26
13.62
318.15
0.11
14
18.5
26.1
360
27
10.53
318.15
0.18
37
14.9
27.7
360
28
6.85
318.15
0.39
32
12.2
32.8
360
29
3.36
318.15
0.52
64
9.6
37.1
360
30
0.17
318.15
0.72
75
5.9
39.2
360
31
13.69
308.15
0.08
23
14.1
28.6
130
32
10.50
308.15
0.22
35
11.3
32.4
130
33
6.87
308.15
0.35
47
9.1
36.6
130
34
3.61
308.15
0.56
40
6.1
40
130
35
0.53
308.15
0.91
83
2.4
42.1
130
36
13.97
313.15
0.07
12
17.1
27.5
130
37
10.61
313.15
0.18
26
13.1
29.8
130
38
7.18
313.15
0.34
44
11.8
35
130
39
3.69
313.15
0.46
58
8.9
38.7
130
10
ACS Paragon Plus Environment
Page 11 of 25
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Energy & Fuels
40
0.54
313.15
0.78
55
4.8
40.6
130
41
14.15
318.15
0.09
14
18.4
25.9
130
42
10.54
318.15
0.23
17
15.0
27.8
130
43
7.03
318.15
0.32
21
12.0
32.6
130
44
3.70
318.15
0.54
39
9.8
37.3
130
45
0.52
46
318.15
0.66
46
5.7
38.8
130
#
358.15
0.40
22
32.0
12.5
360
#
13.82
47
10.27
358.15
0.59
24
26.2
19.5
360
48
#
358.15
0.69
42
18.7
21.1
360
49
#
3.35
358.15
0.72
45
14.4
23.4
360
50
0.18#
358.15
1.10
58
10.3
25.9
360
308.15
0.27
340
8.90
48.8
1420
6.93
*,#
51
3.40
52
0.20
303.15
0.95
36
3.0
43.6
130
53
0.20
308.15
0.79
25
6.5
41.9
130
54
0.20
313.15
0.68
22
12.5
40.3
130
55
0.20
318.15
0.62
15
19.0
39.0
130
56
0.20
323.15
0.58
14
21.3
34.6
130
57
0.20
328.15
0.49
8
25.2
29.7
130
58
0.20
333.15
0.36
4
27.1
24.1
130
243
*
saturation pressure is 4.2 MPa; # the TOC for these tests is 4.7%, that of the others is 1.7%
244
4.1 Pore Structure Analysis
245
The pore structure of the sample was detected using SEM with argon ion-beam milling. Figure 2 shows the
246
SEM image displaying the distribution of kerogen in shale and the image for the pore structure of kerogen.
247
Figure 2a illustrates that considerably more organic material is distributed in inorganic matter. Figure 2b is a
248
magnified image of the observation in the red circle of Figure 2a, showing the existence of nano-pores in
249
kerogen. It shows that there are many pores in kerogen, the majority of which are on the order of nanometers.
250
SEM can provide images only on the surface; thus, the relationship between the SEM results and the above
251
measurement can be described only qualitatively. It is crucial to obtain the exact pore size and pore size
252
distribution because different mechanisms occur in pores with different diameters.49
253
Figure 3 shows a pore size distribution with diameters ranging from 0.3 to 200 nm by BJH calculation with
254
a N2 desorption isotherm.50 A smaller pore diameter and larger pore volume will lead to a greater specific
255
surface area. Haber suggested that pores could be divided into three types: macropores (>50nm), mesopores
256
(between 2nm and 50nm) and micropores (
