ArticlePDF Available

Reservoir stability in the process of natural gas hydrate production by depressurization in the Shenhu area of the South China Sea

Authors:

Abstract and Figures

Reservoir stability is a key factor in the production of natural gas hydrate (NGH), and also a prerequisite to ensuring safe and efficient NGH production. However, it has been rarely discussed. To analyze the reservoir stability in the process of NGH production by depressurization in the Shenhu area of the South China Sea, we established a 3D geological model of NGH production by depressurization on the basis of NGH drilling data in this area, which was then discretized by means of nonstructural grid. Then, the mathematical model coupling four fields (i. e. thermal, hydraulic, solid and chemical) was established considering the heat and mass transfer process and sediment transformation process during NGH production. The model was solved by the finite element method together with the nonstructural grid technology, and thus the time-space evolution characteristics of reservoir pore pressure, temperature, NGH saturation and stress in the condition of NGH production by depressurization were determined. Finally, reservoir subsidence, stress distribution and stability in the process of NGH production by depressurization in the Shenhu area were analyzed. The results obtained are as follows. First, the higher the reservoir permeability and the larger the bottom hole pressure drop amplitude are, the larger the subsidence amount and the higher the subsiding speed. Second, as the reservoir pore pressure decreases in the process of production, the effective stress increases and the shear stress near the well increases obviously, resulting in shear damage easily. Third, the increase of effective reservoir stress leads to reservoir subsidence, which mainly occurs in the early stage of NGH production. After the production for 60 days, the maximum reservoir subsidence reached 32 mm and the maximum subsidence of seabed surface was 14 mm. In conclusion, the NGH reservoirs in the Shenhu area of the South China Sea are of low permeability and the effect range of reservoir pressure drop is limited, so the reservoirs would not suffer from shear damage in the sixty-day-production period. © 2018, Natural Gas Industry Journal Agency. All right reserved.
Content may be subject to copyright.
Research Article
Reservoir stability in the process of natural gas hydrate production by
depressurization in the shenhu area of the south China sea
*,**
Wan Yizhao
a,b,
*, Wu Nengyou
a,b
, Hu Gaowei
a,b
, Xin Xin
c
, Jin Guangrong
d
, Liu Changling
a,b
&
Chen Qiang
a,b
a
MLR Key Laboratory of Gas Hydrate//Qingdao Institute of Marine Geology, Qingdao, Shandong 266071, China
b
Laboratory for Marine Mineral Resources, Qingdao National Laboratory for Marine Science and Technology, Qingdao, Shandong 266071, China
c
College of Environment and Resources, Jilin University, Changchun, Jilin 130012, , China
d
Guangzhou Institute of Energy Conversion, Chinese Academy of Sciences, Guangzhou, Guangdong 510640, China
Received 5 March 2018; accepted 25 April 2018
Available online 7 December 2018
Abstract
Reservoir stability is a key factor in the production of natural gas hydrate (NGH), and also a prerequisite to ensuring safe and efficient NGH
production. However, it has been rarely discussed. To analyze the reservoir stability in the process of NGH production by depressurization in the
Shenhu area of the South China Sea, we established a 3D geological model of NGH production by depressurization on the basis of NGH drilling
data in this area, which was then discretized by means of nonstructural grid. Then, the mathematical model coupling four fields (i.e. thermal,
hydraulic, solid and chemical) was established considering the heat and mass transfer process and sediment transformation process during NGH
production. The model was solved by the finite element method together with the nonstructural grid technology, and thus the time-space
evolution characteristics of reservoir pore pressure, temperature, NGH saturation and stress in the condition of NGH production by depres-
surization were determined. Finally, reservoir subsidence, stress distribution and stability in the process of NGH production by depressurization
in the Shenhu area were analyzed. The results obtained are as follows. First, the higher the reservoir permeability and the larger the bottomhole
pressure drop amplitude are, the larger the subsidence amount and the higher the subsiding speed. Second, as the reservoir pore pressure de-
creases in the process of production, the effective stress increases and the shear stress near the well increases obviously, resulting in shear
damage easily. Third, the increase of effective reservoir stress leads to reservoir subsidence, which mainly occurs in the early stage of NGH
production. After the production for 60 days, the maximum reservoir subsidence reached 32 mm and the maximum subsidence of seabed surface
was 14 mm. In conclusion, the NGH reservoirs in the Shenhu area of the South China Sea are of low permeability and the effect range of
reservoir pressure drop is limited, so the reservoirs would not suffer from shear damage in the sixty-day-production period.
©2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND
license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Keywords: South China sea; Shenhu area; Natural gas hydrate (NGH); Natural gas hydrate production by depressurization; Effective stress; Reservoir stability;
Multi-field coupling numerical simulation
*
Project supported by Marine Geological Survey Program (No: DD20160219), National Key R&D Program of China (No. 2017YFC0307600), financially
supported by Qingdao National Laboratory for Marine Science and Technology (No. QNLM2016ORP0207), Taishan Scholar Special Experts Project (No.
ts201712079) and the Special Funding Project for Post-doctoral Innovation Project of Shandong Province funded the project.
**
This is the English version of the originally published article in Natural Gas Industry (in Chinese), which can be found at https://doi.org/10.3787/j.issn.1000-
0976.2018.04.014.
*Corresponding author.
E-mail address: yizhao_wan@126.com (Wan YZ).
Peer review under responsibility of Sichuan Petroleum Administration.
Available online at www.sciencedirect.com
ScienceDirect
Natural Gas Industry B 5 (2018) 631e643
www.elsevier.com/locate/ngib
https://doi.org/10.1016/j.ngib.2018.11.012
2352-8540/©2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license
(http://creativecommons.org/licenses/by-nc-nd/4.0/).
1. Introduction
Natural gas hydrate (NGH) is widely found in seabed
sediments and terrestrial permafrost zones, and it is expected
to become an efficient and clean energy to meet energy needs
of mankind for its wide distribution, huge resource quantity
and high energy density [1]. Currently, NGH is mainly pro-
duced by depressurization, heat injection, chemical injection
and carbon dioxide replacement. A few countries [2e6] have
carried out NGH pilot production, such as Japan and China [6]
which extract marine NGHs by depressurization. Typically,
the pilot production of marine NGHs implemented in China on
May 10, 2017 achieved the highest yield, with a cumulative
gas production of 30.9 10
4
m
3
and an average daily gas
production of 5151 m
3
[6]. This pilot production was stable for
60 days.
According to the above-mentioned pilot production prac-
tices worldwide, it is known that the overall NGH production
efficiency is still low, and the depressurization method is the
most effective production method. As to the NGH production
by depressurization, a pressure drop funnel is formed in the
reservoir by reducing bottom hole pressure, and NGH begins
to decompose when the reservoir pressure drops below the
hydrate phase equilibrium pressure. Theoretically, the greater
the bottom hole pressure drop, the larger the influence range of
the pressure drop funnel, and the higher the gas production
rate [7]. However, the reservoir pressure drop will lead to the
increase of effective stress and vertical deformation of the
reservoir. Moreover, the increase of reservoir stress may cause
reservoir instability and destruction due to the poor cementa-
tion and low strength of marine NGH reservoir; NGHs also
cement between reservoir sediment particles, and the decom-
position of hydrates caused by depressurization will reduce the
strength of the reservoir, which further exaggerates the reser-
voir instability. Therefore, reservoir stability is a key issue for
NGH production and a prerequisite for ensuring safe and
efficient NGH production.
According to the latest exploration results, the NGH res-
ervoirs in the Shenhu area in the northern South China Sea are
dominated by clay silt and silty clay. The reservoir, with
sediment size generally less than 20 mm, is a typical pore-filled
NGH reservoir [8,9], and it reflects a low permeability (<10
mD) in in-situ test. Many scholars have investigated the pro-
duction methods and potential of NGH in the Shenhu area by
numerical simulation. Zhang et al. [10,11] established single
horizontal well and double horizontal well models for NGH
production by depressurization þheat injection in the
Shenhu area, and used these models to evaluate the gas
production capacity. Li et al. [12e14] studied the NGH pro-
duction potential of the Shenhu area by the heat
injection þdepressurization method together with the huff and
puff method, and discussed the production effects of different
well types. Su et al. [15] also evaluated the development by
vertical well thermal stimulation in the Shenhu area. In these
numerical simulation studies, NGH production was analyzed
in detail in terms of well types (e.g. vertical well, horizontal
well and double horizontal wells) in the Shenhu area, and the
production methods such as depressurization, heat injection
and huff and puff were simulated.
The scholars around the world have also conducted pre-
liminary studies on reservoir deformation and destruction in
NGH production. Shen et al. [16] integrated the NGH
decomposition effect into the seepage field and the geotech-
nical deformation field, and established a fluid-solid coupling
mathematical model for NGH production; with the model,
they numerically simulated the reservoir stability in the near-
wellbore zone during the production by depressurization.
Cheng et al. [17] combined reservoir subsidence and borehole
stability with the production by depressurization, and estab-
lished a one-dimensional mathematical model of stability
during NGH production by depressurization, which does not
consider the influence of heat transfer process. Sun et al. [18]
established a thermal-hydro-mechanical coupling model that
reflects the deterioration of reservoir mechanical properties
caused by NGH decomposition, redeveloped the solution of
the model based on ABAQUS, and investigated the deforma-
tion and destruction of NGH reservoirs during the production
by thermal method.
However, there are few studies on the mechanical stability
of the NGH reservoirs with clay silt and silty clay in the
Shenhu area [19]. In this paper, based on the drilling data of
NGH production in the Shenhu area of the South China Sea, a
three-dimensional geological model of NGH production by
depressurization is established. According to the multi-field
coupling process of NGH decomposition, heat transfer,
seepage and skeleton mechanical deformation in the reservoir,
the mathematical model and finite element method for the
stability analysis of reservoirs are established. With these
models, the spatialetemporal evolution characteristics of
reservoir pressure, temperature, saturation and stress during
the NGH production by depressurization are obtained, and
then reservoir subsidence, stress distribution and stability are
analyzed.
2. Physical model
In September 2015, the China Geological Survey
completed the third natural gas hydrate drilling voyage
(GMGS3) in the Shenhu area in the northern slope of the
South China Sea. The water depth of the GMGS3-W19 station
was 1273.9 m, and it was determined that there was a NGH
layer with a thickness of about 35 m in the range of
135e170 m below the sea floor. According to the drilling data,
a physical model (Fig. 1) was established. In the horizontal
direction, the model extends 400 m in the xand ydirections
around the wellbore. The top surface of the model is the sea
floor. NGH exists 135 m below the top surface, with a thick-
ness of 35 m. The overlying layer is 135 m thick, and the
underlying layer is 94 m thick, both of which contain no
NGHs. The penetrated well section is 135e162 m, that is, the
28 m interval below the top of the NGH reservoir penetrated
[20].
632 Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
3. Mathematical model and solution
3.1. Basic assumptions
NGH production is a complex heat and mass transfer pro-
cess, including seepage, thermal convection and heat transfer
of multiphase fluids in porous media, chemical reactions of
NGH decomposition, and mechanical deformation of hydrate
deposits. In order to establish a mathematical model
describing the physical process of NGH production, it is
assumed that: the hydrate is a pure Type-I hydrate, gas in
the hydrate is 100% methane, and the formation of ice is
ignored; the selected control body keeps thermal equilib-
rium locally, that is, the temperature of the sediment particles
and the fluids (gas and liquid) are the same; gas and water
flow in the porous media according to the Darcy's law; and
hydrate is pore-filled and adheres on to the surface of the
sediment particles, and the hydrate and sediment particles
constitute a continuous composite solid material, which is
jointly stressed, and presents a linear elasticity.
3.2. Mathematical model
Based on the above assumptions, a thermal-hydro-
mechanical-chemical (THMC or four-field) coupling model
is established, which comprehensively considers the thermal
field, gasewater two-phase seepage field, mechanical defor-
mation field of the sediment and chemical field of NGH
decomposition.
3.2.1. Chemical field of NGH decomposition kinetics
The mass conservation equation for NGH decomposition is:
vð4rhShÞ
vt¼mhð1Þ
Based on the Kin-Bishoni kinetic model [21], the gas
production rate at the time of NGH decomposition is:
mg¼kreacMCH4Ars pepgð2Þ
Correspondingly, water production rate and hydrate con-
sumption rate of NGH decomposition are:
mw¼mgNh
MH2O
MCH4
ð3Þ
mh¼mg
Mh
MCH4
ð4Þ
3.2.2. Gasewater two-phase seepage field
Gas and water flow in a porous medium in a hydrate deposit
can be expressed by a continuous equation and Darcy's law,
and finally a model equation for gasewater two-phase seepage
is obtained.
Gas phase:
v4rgSg
vtVKrgKrg
mgVpgþrgg¼mgð5Þ
Water phase:
vð4rwSwÞ
vtVKrwKrw
mw
ðVpwþrwgÞ¼mwð6Þ
The m
g
and m
w
in the right-hand term of Eqs. (5) and (6)
are calculated from the NGH decomposition kinetics model,
which are the key to coupling the seepage field and the
chemical field.
3.2.3. Thermal field
The thermal field during NGH decomposition can be rep-
resented by the energy conservation equation, which considers
the heat transfer and the thermal convection during NGH
decomposition is:
where,
leff ¼ð14Þlsþ4Sglgþ4Swlwþ4Shlh
Fig. 1. Schematic diagram of the GMGS3-W19 station model.
vrw4SwCwTþrg4SgCgTþrh4ShChTþrsð1fÞCsT
vtþVrw4Swv
!w;tCwTþrg4Sgv
!g;tCgT¼VleffVTþQhð7Þ
633Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
3.2.4. Mechanical deformation field of hydrate deposit
The equilibrium differential equation for composite me-
chanical deformation of the hydrate-sediment is:
Vsþrmg¼0ð8Þ
According to the Terzaghi effective stress principle, the
total stress of soil is equal to the sum of the effective stress and
the pore pressure of the composite solid composed of the
hydrate and sediment grain skeletons [22], then:
s¼s0þapeff ð9Þ
where,
peff ¼Sw
SwþSg
pwþSg
SwþSg
pg
According to the linear elasticity assumption, the
stressestrain relationship of the composite solid is:
s0¼2GmεþlmtrðεÞIð10Þ
ε¼1
2Vu
!þVTu
!ð11Þ
Gm¼Em
2ð1þvmÞð12Þ
lm¼Emvm
ð1þvmÞð12vmÞð13Þ
where, tr(ε)represents the diagonal element of ε. Finally the
deformation force field equation with the displacement of the
composite solid as a variable is obtained:
8
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
<
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
:
A1
v2ux
vx2þA3
v2ux
vy2þA3
v2ux
vz2þðA2þA3Þv2uy
vxvyþ
ðA2þA3Þv2uz
vxvzavpeff
vx¼0
A3
v2uy
vx2þA1
v2uy
vy2þA3
v2ux
vz2þðA2þA3Þv2ux
vxvyþ
ðA2þA3Þv2uz
vyvzavpeff
vy¼0
A3
v2uz
vx2þA3
v2uz
vy2þA1
v2uz
vz2þðA2þA3Þv2ux
vxvzþ
ðA2þA3Þv2uy
vyvzavpeff
vz¼0
ð14Þ
where,
A1¼2Gm
1vm
12vm
A2¼2Gm
vm
12vm
A3¼Gm
3.2.5. Auxiliary equation
In addition to the governing equations of physical fields,
auxiliary equations of physical parameters are required.
3.2.5.1. Absolute permeability equation [23].
K¼K0ð1ShÞnð15Þ
3.2.5.2. Capillary force and gasewater two-phase relative
permeability equations [24].
pgpw¼pcð16Þ
Krg ¼KrgoSng
ges ð17Þ
Krw ¼KrwoSnw
wes ð18Þ
where,
Swes ¼Swe Swre
1Swre Sgre
Sges ¼Sge Sgre
1Swre Sgre
Swe ¼Sw
1Sh
Sge ¼Sg
1Sh
Swre ¼Swr
1Sh
Sgre ¼Sgr
1Sh
3.2.5.3. Hydrate phase equilibrium pressure equation [25].
pe¼expA0þA1TþA2T2þA3T3þA4T4þA5T5ð19Þ
3.2.5.4. Hydrate phase change latent heat equation [26].
Qh¼mh
Mh
ðB1B2TÞð20Þ
3.2.5.5. Equation of mechanical properties of hydrate sedi-
ment particle composite solid. The result of triaxial experi-
ment shows that the presence of hydrate increases the strength
of hydrate deposits, but the effect of hydrate on Poisson's ratio
is small [27]. Therefore, assuming the Poisson's ratio is
634 Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
constant, the modulus of elasticity E
m
is represented by the
formula proposed by Santamarina and Ruppel [28]:
Em¼Es0sc
sc0b
þcEhðShÞdð21Þ
The above equations constitute a four-field coupling model
for the NGH production process.
3.3. Finite element solution
Through analysis, the THMC coupling model can be
divided into two subsystems: a flow system containing heat
and mass transfer and a mechanical deformation system. The
two subsystems are solved separately by the finite element
method.
For the flow system, p
g
,S
w
,S
h
and Tare selected as vari-
ables for independent solution. Particularly, S
h
can be directly
obtained by using Eqs. (1) and (4). The finite element equa-
tions of p
g
,S
w
and Tare derived below.
3.3.1. Finite element equation of p
g
The first item of Eq. (5) is expanded:
v4rgSg
vt¼4rg
vSg
vtþrgSg
vð4Þ
vtþ4Sg
vrg
vtð22Þ
According to the gas state equation:
rg¼pg
ZRgTð23Þ
Replace the density in Eq. (5) with pressure, then the
pressure equation of gas phase can be obtained as follows:
4Sg
ZRgT
vpg
vtþ4
ZRgT
vSg
vtþSg
ZRgT
v4
vtpgVKrgKrg
mg
Vpg
¼mg
ð24Þ
The above equation is multiplied by dp
g
and integrated, and
the order is reduced by the Gaussian formula, then:
The pressure is represented by the interpolation function on
the unit:
pg¼Npgeð26Þ
dpg¼Ndpgeð27Þ
Substitute it into the original formula, the finite element
solution equation for the final gas phase pressure is obtained:
Ae_
pgeþQepge¼fgeð28Þ
where,
Ae¼ZN4Sg
ZRgTNTdV
Qe¼ZN4
ZRgT
vSg
vtþSg
ZRgT
v4
vtNTþ
VNTKrgKrg
mg
VNdV
fge¼ZmgNTdVþZqmgNTds
3.3.2. Finite element equation of S
w
Using the capillary force equation, we can get:
VpgVpw¼Vpc¼pc0VSwð29Þ
The water phase pressure in Eq. (6) is expressed by gas
phase pressure and water phase saturation, then
4rw
4Sw
vtþrw
v4
vtSwþVKrwKrw
mw
pc0VSw
VKrwKrw
mw
Vpg¼mw
ð30Þ
The above equation is multiplied by dp
w
and integrated,
and the order is reduced by the Gaussian formula, then:
Z4rw
vSw
vtþrw
v4
vtSwdSwdV
ZKrwKrw
mw
pc0VSwVðdSwÞdVþZKrwKrw
mw
VpgVðdSwÞ¼
ZmwdSwdVþZKrwKrw
mw
vpw
vndSwds
ð31Þ
The saturation is represented by the interpolation function
on the unit:
Sw¼NfSwgeð32Þ
dSw¼NfdSwgeð33Þ
Substitute it into the original formula, then the finite
element solution equation for the final saturation is obtained:
Be_
SweþCefSwge¼ffwgeð34Þ
Z4Sg
ZRgT
vpg
vtþ4
ZRgT
vSg
vtþSg
ZRgT
v4
vtpgdpgdVþZKrgKrg
mg
VpgVdpgdV¼ZmgdpgdVþZKrgKrg
mg
vpg
vndsð25Þ
635Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
where,
Be¼ZN4rwNTdV
Ce¼ZNrw
v4
vtNTdVZKrwKrw
mw
pc0VNVNTdV
ffwge¼ZmgNTdVZKrwKrw
mw
VpgVNTdVþZqmwNTds
3.3.3. Finite element equation of T
Eq. (7) is multiplied by dTand integrated to obtain:
ZðrCÞt
vT
vtþrgCgþrwCwVTVðlVTÞdTdV
¼ZQhþðqmCÞtðTT0ÞdTdVð35Þ
Reduce the order and substitute the interpolation function
T¼NfTge
;dT¼NfdTge, then the finite element solution of
Tis obtained:
De_
TeþEefTge¼ffTgeð36Þ
where,
De¼ZNðrCÞtNTdV
Ee¼ZVNrgCgþrwCwNTdVþZlVN$VNTdV
ffTge¼ZQhNTdVþZlvT
vnNTds
The second subsystem is a mechanical deformation model
and its governing equation is Eq. (14). Take the xdirection as
an example, the equilibrium differential equation in the xdi-
rection is multiplied by du
x
and integrated; after the order is
reduced, then:
ZA1
vux
vxþA2
vuy
vyþA2
vuz
vzpvdux
vxþ
A3
vux
vyþA3
vuy
vxvdux
vyþ
A3
vux
vzþA3
vuz
vxvdux
vzdV¼ZFxduxds
ð37Þ
From the interpolation function, we can obtain:
ux¼Nfuxgeð38Þ
dux¼Nfduxgeð39Þ
The finite element equation in the xdirection is:
½k11fuxgþ½k12uyþ½k13 fuzgþ½k14fpg¼ff1gð40Þ
where,
½k11¼ZA1
vNi
vx
vNj
vxþA3
vNi
vy
vNj
vyþA3
vNi
vz
vNj
vzdV
½k12¼ZA2
vNi
vy
vNj
vxþA3
vNi
vx
vNj
vydV
½k13¼ZA2
vNi
vz
vNj
vxþA3
vNi
vx
vNj
vzdV
½k14¼ZNi
vNj
vxdV
ff1g¼ZFxNjds
Similarly, the finite element equations in the ydirection and
the zdirection can be obtained.
3.4. Model grid division
The physical model shown in Fig. 1 is divided into grids by
a tetrahedral unstructured grid, and the grid diagram is shown
in Fig. 2. For accurate calculation, more dense grids are
divided in the NGH layer, and there are totally 38068 grids.
3.5. Initial conditions and boundary conditions
According to the survey results of the GMGS3-W19 sta-
tion, the temperature at the sea floor is 3.75 C and the
geothermal gradient is 0.045 C/m. According to the reservoir
depth, the initial reservoir temperature is linearly distributed in
longitudinal direction. The pore pressure at the initial moment
of the formation gradually increases with depth, which is
consistent with hydrostatic pressure balance. The initial hy-
drate saturation of the NGH layer is 0.45, and both the over-
lying layer and the underlying layer contain water with a
saturation of 1. The bottomhole pressure remains constant
during production and the outer boundary of the reservoir
follows the constant pressure boundary condition to maintain
the original formation pressure.
The initial in-situ stress can be calculated by the self-
weight of the saturated soil. The water depth at the top sur-
face of the model is 1273.9 m, the converted top pressure is
12.86 MPa, and the sediment density is 2650 kg/m
3
; then, the
formation stress increases vertically at a gradient of 25.97 kPa/
m. As to the boundary conditions of the mechanical defor-
mation field, the upper top surface is the free surface bound-
ary, and the bottom surface of the reservoir is fixed vertically;
the side surface is fixed with the horizontal displacement, that
is, for the side surface perpendicular to x¼0 m and
x¼800 m, the displacement in the xdirection is 0, and for the
side surface perpendicular to y¼0 m and x¼800 m, the
displacement in the ydirection is 0.
3.6. Physical parameters
For this model, the water depth is 1273.9 m, the thickness
of the overlying layer is 135 m, the thickness of the under-
lying layer is 94 m, the bottomhole pressure during
636 Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
production is 5.0 MPa, the initial pressure at the bottom of the
NGH layer is 14.3 MPa, and the initial temperature at the
bottom of the NGH layer is 14.0 C. The thermal and phys-
ical properties, permeability and other parameters are shown
in Tab l e 1 .
The mechanical properties of the hydrate sediments are
shown in Table 2.
4. Model verification
In order to verify the correctness of the numerical model
and the program, we compared the model calculation results
with the results of the Masuda experiment [23]. Masuda
adopted Berea sandstone synthetic hydrate in production by
depressurization, as shown in Fig. 3.
The Berea core, 30 cm long and 5.1 cm in diameter, was
placed in a constant temperature air bath with a temperature of
2.3 C. Its initial temperature (T
i
) was 2.3 C, initial pore
pressure ( p
gi
) was 3.75 MPa, initial hydrate saturation (S
hi
)
was 0.443, water saturation (S
wi
) was 0.351, porosity (4
i
) was
0.182 and permeability (K
i
) was 98 mD. During the experi-
ment, the A-end maintained a constant pressure of 2.84 MPa
as an outlet and the cumulative gas production of the outlet
was recorded.
By using the finite element calculation program estab-
lished in this paper, the above example was calculated to
obtain the cumulative gas production variation at the outlet
with time, and compared with the experimental results, as
shown in Fig. 4. It can be seen that the multi-field coupling
model can be in good agreement with the experimental re-
sults, which proved the validity and reliability of the model
and algorithm.
5. Results and discussion
5.1. Water production and gas production
Fig. 5 shows the variation of water and gas production rate
with time at the bottomhole pressure of 5 MPa. It can be
known that the formation pressure near the wellbore decreases
with the decrease of the bottomhole pressure, which leads to
the decomposition of the hydrate near the wellbore at first, the
water and gas production rate of the wells maintains a high
value and then decrease rapidly. When the water production
increases, the gas production increases gradually. Due to a
faster pressure conduction, the water production can quickly
reach a relatively stable state, and the gas production can also
reach a relatively stable fluctuation state.
5.2. Physical field distribution
Under the assumption of homogeneity of the model, the
predicted spatial variation of pressure, hydrate saturation,
temperature and gas saturation on the 60
th
day of production is
obtained (Fig. 6).
It can be seen from Fig. 6-a that the depressurization area is
mainly concentrated around the wells; the pressure in the well
center is the lowest, about 9 MPa lower than the initial formation
pressure. The horizontal influence range is about 35m around the
well, that is, the interval where the pressure drop ranges from
9 MPa to 0 MPa in the well center is 35 m. Under the production
pressure of 5 MPa, the decomposition zone of hydrate saturation
is restricted to zones around the well, and the decomposition zone
of hydrate is approximately within 2 m from the well in the
horizontal direction. Due to the low permeability of the reservoir,
Fig. 2. Grid division of NGH production model in the Shenhu area.
637Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
the hydrate at the bottom of the reservoir has not completely
decomposed, which has played a certain role in water resistance.
It can be seen from Fig. 6-c that the endothermic effect
during NGH decomposition does not cause a significant
change of temperature spatially on the 60
th
day of production,
the temperature in the well center is reduced by a maximum of
about 4C. In the horizontal direction, the temperature
decrease range is small, which proves that the NGH decom-
position range is small. A part of the methane gas generated by
the NGH decomposition is migrated to the well, and the other
part accumulates in the pore space. Due to the increase of gas
saturation, under the capillary force of the two-phase fluid
flow, the gas cannot be completely produced, so gas saturation
distribution as shown in Fig. 6-d is formed.
5.3. Mechanical response
Two points were selected in the reservoir to monitor the
changes of pore pressure, temperature and stress with time.
The coordinates at the near-wellbore zone and the far-wellbore
zone are (x¼0.3 m, z¼149 m) and (x¼8.1 m, z¼149 m),
respectively.
It can be seen from Fig. 7-a that the pore pressure near the
wellbore reduces rapidly and reaches a stable value due to the
bottomhole depressurization. The pore pressure far away from
wellbore shows a gentle downward trend, and it is much higher
than the pore pressure near the wellbore. The reduction of pore
pressure near the wellbore results in NGH decomposition, and
the NGH decomposition and heat absorption cause its tempera-
ture to decrease (Fig. 7-b). When the decomposition is over, the
temperature gradually rises due to the surrounding heat transfer.
In zones far away from the wellbore, the pore depressurization is
not enough to cause a huge amount of NGH decomposition, so
the temperature remains basically unchanged.
It can be seen from Fig. 7-c that the decrease in pore pressure
causes an increase in the effective principal stress. The effective
stress near the wellbore increases rapidly due to the rapid
decrease of the pore pressure, and finally remains unchanged
(due to the production at constant bottomhole pressure). The pore
pressure in the far-wellbore zone decreases little, and the effec-
tive principal stress increases slowly. The pressure drop makes
the difference between the maximum and minimum principal
stress in the near-wellbore zone larger than that in the far-
wellbore zone, so the increases of shear stress in the near-
wellbore zone ismore obvious than that in the far-wellbore zone.
Fig. 7-d shows the variation of the maximum and minimum
effective principal stresses at the two points with the production
time, i.e. the effective stress path. It can be seen that the stress
state at the two points is outside the rupture line of Mole-
Coulomb shear strength line of sediment [30] at the time
Table 1
Physical parameters of the NGH reservoir in the W19 station of the Shenhu
area.
Parameter Value
Initial hydrate saturation 0.45
Absolute permeability (without hydrate) 2.50 mD
Porosity (without hydrate) 0.48
Permeability decline index 7.00
Gas thermal conductivity 0.06 W/(m$K)
Water thermal conductivity 0.50 W/(m$K)
Hydrate relative permeability model S
wr
¼0.3,S
gr
¼0.05,K
wro
¼0.3,
K
gro
¼0.1, n
g
¼4, n
w
¼4
Coefficient of hydrate phase change
latent heat equation
B1¼3527000, B1¼1050
NGH decomposition rate constant [29] kreac ¼k0
dexpDEa
RT
k
d
0
3.6 10
4
mol/(m
2
$Pa$s)
DEa
R
9752.73 K
Volume specific surface area of
NGH decomposition [24] Ars ¼4Shffiffiffiffiffiffiffi
43
eff
2K
s;
4eff ¼4ð1ShÞ
Gas specific heat capacity C
g
¼2180 J/(kg$K)
Water specific heat capacity C
w
¼4200 J/(kg$K)
Hydrate specific heat capacity C
h
¼2220 J/(kg$K)
Specific heat capacity of sediment particles C
s
¼2180 J/(kg$K)
Hydrate thermal conductivity 2.0 W/(m$K)
Thermal conductivity of sediment particles 1.0 W/(m$K)
Table 2
Mechanical parameters of hydrate sediments in the Shenhu area.
Parameter Value
Cohesion When S
h
¼0, C
m
¼0.5 MPa
When S
h
¼1, C
m
¼2 MPa and C
m
varies linearly with S
h
Internal friction angle 30
Elasticity modulus When S
h
¼0, E
m
¼95 MPa
When S
h
¼1, E
m
¼670 MPa and E
m
varies linearly with S
h
Poisson ratio 0.15
Biot coefficient a¼1
Fig. 3. Diagram of the Berea core experimental model.
Fig. 4. Comparison of cumulative gas production calculated in this paper and
experimental result. *Note: The Masuda experimental data is from Dr. Shi-
gemi Naganawa (Tokyo University).
638 Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
t¼0, which means that it is already in a compression-stable
state in the sediment history. The stress path shows a rapid
change within 0e1 day near the wellbore and a slow change
after the 1st day, the stress change in the far-wellbore zone lags
behind that near the wellbore. Since the stress paths at both
points appear to deviate from the Moore-Coulomb strength line,
they do not approach or reach the rupture line, indicating that
no damage has occurred. Therefore, the preliminary prediction
results based on this model show that the reservoir will not be
destroyed within 60 days of production.
5.4. Reservoir subsidence
Fig. 8 shows the vertical displacement during the production
process, that is, the production depressurization causes
sedimentation of seafloor sediments. It can be seen from Fig. 8-a
and c that the depressurization in the well causes a funnel-like
spatial subsidence. From the overlooking view (xOy plane), the
subsidence is circularly distributed around the well position, and
the subsidence at the well position is the largest. From the section
diagram (Fig. 8-b&d), it can be seen that the subsidence at the
production section is small, and the vertical displacement above
and below the production section is the largest. Therefore, the
subsidence near the upper part of the production section is the
largest, and the local uplift occurs under the osmotic pressure
below the production section. Under the overlying stress, the
subsidence of soil above the well is larger than the uplift below
the well. Since the soil above the well section is totally settled
under the stress, the influence range of subsidence caused by the
depressurization is greater than that by the pore pressure.
Fig. 5. Variation of water and gas production rate with time at the GMGS3-W19 station.
Fig. 6. Physics field variation around the wellbore after 60 days of pilot production (negative values indicate that they are lower than the initial values).
639Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
Fig. 7. Mechanical response at (x, z)¼(0.3 m, 149 m) and (x, z) ¼(8.1 m, 149 m); and. s
1
0and s
3
0are the corresponding maximum and minimum effective
principal stresses.
Fig. 8. Distribution of subsidence space caused by production section (135e162 m).
640 Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
In Fig. 8, the maximum subsidence at the well location is
0.032 m (or 32 mm) on the 30
th
day, while the subsidence at
the seafloor is about 0.014 m, and the seafloor subsidence
range (>5 mm) has a radius of about 166 m. During the
production, the maximum subsidence of the production well is
0.035 m on the 60
th
day, the seafloor subsidence is about
0.018 m, and the seafloor subsidence range (>5 mm) has a
radius of about 232 m. Subsidence and subsidence range
gradually increase with production.
Fig. 9-a shows the variation of the seafloor subsidence in
the production well (vertical displacement) with time. In the
first 15 days, the subsidence was about 0.009 m (i.e. 9 mm).
Subsequently, as the pore pressure gradually became a state of
dynamic equilibrium in space, the sedimentation rate at the
seafloor decreased. After 60 d, the subsidence gradually
became slow and eventually reached 0.018 m. It can be seen
that the subsidence in the first 15 days accounts for 1/2 of the
total subsidence. Therefore, under the conditions of constant
pressure production, the subsidence mainly occurs in the early
production period.
Fig. 9-b shows the subsidence (vertical displacement) at
different moments in the production well. It can be seen that
stress changes caused by the depressurization are mainly
concentrated around the production well, so large displace-
ment occurs near the depressurization point. Since the bottom
of the depressurization point is fixed and does not move
vertically, the uplift at the bottom of the depressurization point
will be 0 due to the boundary effect. The top of the model is a
free surface that can move freely, and the sediment within a
certain depth range below the seafloor is overall subsidence.
5.5. Influence of permeability on reservoir subsidence
Permeability is a key factor affecting the range of gas and
water migration and pressure. Fig. 10 shows the variation of
seafloor subsidence in the production well with time at
different permeability.
When the permeability is low, the depressurization range is
small, and the decline rate of the seafloor subsidence remains
basically unchanged. When the permeability increases, the
depressurization range increases, and the subsidence occurs at
a higher rate and then at a lower rate, and finally the seafloor
subsidence occurs at a lower rate. For the permeability of 1.0
mD, 2.5 mD and 5.0 mD, based on the subsidence on the 60
th
day, the time required for half sedimentation is 24 d, 15 d and
9.5 d, respectively. As permeability increases, the sedimenta-
tion rate increases, and the time to reach the same subsidence
is advanced.
5.6. Influence of bottomhole pressure on reservoir
subsidence
Bottomhole pressure directly affects the distribution of pore
pressure in the formation, causing changes in the effective
stress of the framework, which in turn affects the subsidence
of the reservoir. Fig. 11 shows the variation of the seafloor
subsidence in the production well with time during the pro-
duction at different pressures. It can be seen that in the early
stage of production, the subsidence under different production
pressures is basically the same; in the stage of stable gas
production, the seafloor subsidence is gradually different. On
the 60
th
day, the subsidence is 0.016 m, 0.018 m and 0.020 m,
respectively, and the time required for half sedimentation is
approximately 15 d. The production pressure is reduced, the
subsidence rate is increased, and the time required to reach the
same subsidence is advanced, but the influence degree is less
than that of permeability.
Fig. 9. Variation of the seafloor subsidence in the production well with time and reservoir burial depth.
Fig. 10. Variation of seafloor subsidence with permeability in the production
well.
641Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
6. Conclusions
1) Based on the drilling data of NGH production in the
Shenhu area of the northern South China Sea, the
physical model of NGH production by depressurization
in a single vertical well is established, and the model is
divided by unstructured grid. Considering the heat
transfer and sediment deformation in the NGH produc-
tion, a four-field (THMC) coupling model is established.
Based on the unstructured grid, the model is solved by
the finite element method to obtain the pore pressure,
temperature, saturation and spatialetemporal evolution
of stress.
2) The permeability of hydrate reservoirs in the Shenhu
area is low, and the influence of pressure drop on the
production by depressurization is limited mainly to the
vicinity of a wellbore, and the decomposition range of
hydrate is also small.
3) During the NGH production process, the decrease of
pore pressure in the reservoir leads to the increase of
effective stress. The increase of effective stress is mainly
concentrated near the wellbore, and the difference be-
tween the maximum and minimum principal stresses
near the wellbore are larger than that in the far-wellbore
zone. Therefore, the shear stress in the near-wellbore
zone is large, so shear damage is likely to occur. The
stress path line near the wellbore after 60-d production is
far away from the Moore-Coulomb strength envelope,
which indicates that the reservoir will not be destroyed
under the assumptions of this model.
4) The effective stress increase results in reservoir subsi-
dence. After 60 days of production, the maximum
reservoir subsidence is 32 mm, and the maximum sea-
floor subsidence is 14 mm; reservoir subsidence mainly
occurs in the early stage of production.
5) Reservoir permeability and bottomhole pressure during
production by depressurization have obvious effects on
reservoir subsidence. The greater the reservoir perme-
ability, the greater the bottomhole pressure drop, the
greater the reservoir subsidence and the faster the
subsidence.
Acknowledgement
We appreciate Dr. Shigemi Naganawa from Tokyo Uni-
versity for providing us the Masuda experimental data.
Symbols
ttime, s
p
w
and p
g
water phase and gas phase pressure, Pa
p
c
capillary pressure, Pa
p
e
hydrate phase equilibrium pressure, Pa
S
h
,S
g
and S
w
hydrate saturation, gas phase and water phase,
respectively
r
h
,r
w
,r
s
and r
g
density of hydrate, water phase, sediment
particles and gas phase, respectively, kg/m
3
r
m
represents the density of complex solids composed of
hydrate and sediment particles, kg/m
3
,rm¼4rhShþ
ð14Þrs
K
reac
NGH decomposition rate constant, mol/(m
2
$Pa$s)
A
rs
surface area of the reservoir NGH decomposition per
unit volume, m
1
m
w
,m
h
and m
g
water production rate of NGH decomposition,
NGH decomposition rate per unit volume, gas pro-
duction rate of NGH decomposition per unit volume
of reservoir, respectively, kg/(m
3
$s)
N
h
number of hydrates
MCH4Moore mass of methane gas, kg/mol
MH2Omolarity of the water phase, kg/mol
M
h
Moore mass of hydrate, kg/mol
K
rg
and K
rw
relative permeability of gas phase and water
phase for gasewater two-phase percolation,
respectively
Kand K
0
sediment porous medium and non-hydrated absolute
permeability, respectively, m
2
K
rgo
and K
rwo
relative permeability of gas phase and oil phase
end points without hydrate
npermeability decline index
n
g
and n
w
relative permeability index of gas phase and water
phase, respectively
S
gr
and S
wr
saturation of gas phase and the water phase at
relative permeability end points
m
g
and m
w
viscosity of methane gas and water phase,
respectively, Pa$s
4porosity of the hydrate deposit
ggravitational acceleration, m/s
2
Treservoir temperature, K
C
w
,C
g
,C
h
and C
s
specific heat capacity of the water phase,
gas phase, hydrate phase and sediment particle phase,
respectively, J/(kg$K)
v
!w;tand v
!g;tvelocity of water phase and the gas phase
relative to the control body, m/s
Fig. 11. Variation of seafloor subsidence with production pressure ( p
w
) in the
production well.
642 Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
l
s
,l
g
,l
w
and l
h
heat transfer coefficients of sediment parti-
cles, methane gas phase, water phase and hydrate,
respectively, W/(m$K)
Q
h
latent heat of phase change of NGH decomposition,
W/m
3
Stotal stress tensor of the hydrate sediment, MPa
seffective stress of the composite solid, MPa
s
c0
reference confining pressure, MPa
aBiot coefficient
εstrain tensor
Iunit vector
u
!deformation and displacement of the sediment solid, m
G
m
and l
m
Lame constant of the composite solid composed of
hydrate and sediment particles
E
m
,E
s0
and E
h
composite solid, non-hydrated sediment under
the reference confining pressure s
c0
, the elastic
modulus of pure hydrate, respectively, MPa
v
m
composite solid Poisson's ratio
bsensitivity coefficient of the sediment elastic modulus
under confining pressure of s
c
chydrate elastic modulus coefficient
dhydrate saturation nonlinear effect coefficientA
0
-A
5
,
B
1
and B
2
represent the constant coefficients
References
[1] Klauda JB &Sandler SI. Global distribution of methane hydrate in ocean
sediment. Energy Fuels 2016;19(2):459e70.
[2] Dubreuil-Boisclair C, Gloaguen E, Bellefleur G &Marcotte D. Non-
Gaussian gas hydrate grade simulation at the Mallik site, Mackenzie
Delta, Canada. Mar Petrol Geol 2012;35(1):20e7.
[3] Uddin M, Wright F, Dallimore S &Coombe D. Gas hydrate dissociations
in Mallik hydrate bearing zones A, B, and C by de-pressurization: effect
of salinity and hydration number in hydrate dissociation. J Nat Gas Sci
Eng 2014;21:40e63.
[4] Schoderbek D, Martin KL, Howard J, Silpngarmlert S &Hester K. North
slope hydrate field trial: CO
2
/CH
4
exchange//OTC arctic technology
conference, 3e5 December. 2012. Houston, Texas, USA, https://doi.org/
10.4043/23725-MS.
[5] Yamamoto K, Terao Y, Fujii T, Terumichi I, Seki M, Matsuzawa M, et al.
Operational overview of the first offshore production test of methane
hydrates in the Eastern Nankai Trough. Offshore Technology Confer-
ence, 5e8 May, Texas, USA.
[6] Chen Huiling &Zhu Xia. The trial production well of gas hydrate from
Shenhu area, South China Sea, shut down on the 60th day of production.
China Land Res Rep 2017.07-10(13):6-6.
[7] Kurihara M, Sato A, Ouchi H, Narita H, Masuda Y, Saeki T, et al. Pre-
diction of gas productivity from eastern Nankai trough methane-hydrate
reservoirs. SPE Reservoir Eval Eng 2009;12(3):477e99.
[8] Liang Jinqiang, Wang Hongbin, Su Xin, Fu Shaoying, Wang Lifeng,
Guo Yiqun, et al. Natural gas hydrate formation conditions and the
associated controlling factors in the northern slope of the South China
Sea. Nat Gas Ind 2014;34(7):128e35.
[9] Yu Xinghe, Wang Jianzhong, Liang Jinqiang, Li Shunli, Zeng Xiaoming,
Sha Zhibin, et al. Depositional accumulation characteristics of gas hy-
drate in the northern continental slope of South China Sea. Acta Petrolei
Sinica 2014;35(2):253e64.
[10] Zhang KN, Moridis GJ, Wu NY, Li XS &Reagan MT. Evaluation of
alternative horizontal well designs for gas production from hydrate de-
posits in the Shenhu area, South China Sea//International Oil and Gas
Conference &Exhibition, 8e10 June. 2010. Beijing, China, https://doi.
org/10.2118/131151-MS.
[11] Hu Litang, Zhang Keni &Gao Tong. Numerical studies of gas production
from gas hydrate zone using heat injection and depres-surization in
Shenhu area, the South China Sea. Geoscience 2011;25(4):675e81.
[12] Li Gang, Li Xiaosen, Zhang KN &Moridis GJ. Numerical simulation of
gas production from hydrate accumulations using a single horizontal well
in Shenhu area, South China Sea. Chin J Geophys 2011;54(9):2325e37.
[13] Li Gang, Li Xiaosen, Qi Chen &Chen Zhaoyang. Numerical simulation
of gas production from gas hydrate zone in Shenhu area, South China
Sea. Hua Hsueh Hsueh Pao 2010;68(11):1083e92.
[14] Li G, Moridis GJ, Zhang KN &Li XS. Evaluation of gas production
potential from marine gas hydrate deposits in Shenhu area of South
China Sea. Energy Fuels 2010;24(11):6018e33.
[15] Su Zheng, He Yong &Wu Nengyou. Numerical simulation on production
potential of hydrate deposits by thermal stimulation. Journal of Tropical
Oceanography 2012;31(5):74e82.
[16] Shen Haichao, Cheng Yuanfang &Hu Xiaoqing. Numerical simulation
of near wellbore reservoir stability during gas NGH production by
depressurization. Petroleum Drilling Techniques 2012;40(2):76e81.
[17] Cheng Jiawang, Su Zheng &WuNengyou. A geomechanicalstability model
analysisof hydrate reservoirfor gas hydrate pro-duction by depressurization.
Advances in New and Renewable Energy 2016;4(1):33e41.
[18] Sun Keming, Wang Tingting, Cheng Zhai &Luo Huiyu. Patterns of
reservoir deformation due to thermal decomposition of natural gas hy-
drates. Special Oil Gas Reservoirs 2017;24(5):91e6.
[19] Sun JX, Zhang L, Ning FL, Lei HW, Liu TL, Hu GW, et al. Production
potential and stability of hydrate-bearing sediments at the site GMGS3-
W19 in the South China Sea: a preliminary feasibility study. Mar Petrol
Geol 2017;86:447e73.
[20] Yang S, Zhang M, Liang J, Lu J, Zhang Z, Melanie H, et al. Preliminary
results of China's third gas hydrate drilling expedition: a critical step
from discovery to development in the South China Sea. Fire in the Ice
2015;15(2):1e5.
[21] Kim HC, Bishnoi PR, Heidemann RA &Rizvi SSH. Kinetics of methane
NGH decomposition. Chem Eng Sci 1985;42(7):1645e53.
[22] Biot MA &Willis DG. The elastic coefficients of the theory of consol-
idation. J Appl Mech 1957;15(2):594e601.
[23] Masuda Y, Naganawa S &Ando S. Numerical calculation of gas pro-
duction performance from reservoirs containing natural gas hydrates.
SPE J 1997;29(3):201e10.
[24] Sun XF &Mohanty KK. Kinetic simulation of methane hydrate forma-
tion and dissociation in porous media. Chem Eng Sci 2006;61(11):
3476e95.
[25] Duan ZH &Sun R. A model to predict phase equilibrium of CH4 and
CO
2
clathrate hydrate in aqueous electrolyte solutions. Am Mineral
2006;91(8/9):1346e54.
[26] Esmaeilzadeh F, Zeighami ME &Fathi J. 1-D modeling of NGH
decomposition in porous media//. Proc World Acad Sci Eng Technol
2013;43:648.
[27] Soga K, Lee SL, Ng MYA &Klar A. Characterization and engineering
properties of methane hydrate soils//proceedings of the 2nd international
workshop on characterization and engineering properties of natural soils,
29 November-1 december 2006. Singapore. London: CRC Press; 2006.
[28] Santamarina JC &Ruppel C. The impact of hydrate saturation on the
mechanical, electrical, and thermal properties of hydrate-bearing
sand, silts, and clay//Proceedings of the 6th International Confer-
ence on Gas Hydrate, 6e10 July. Vancouver: British Columbia,
Canada; 2008.
[29] Clarke M &Bishnoi PR. Determination of the intrinsic rate of gas NGH
decomposition using particle size analysis. Ann N Y Acad Sci
2000;912:556e63.
[30] Rutqvist J, Moridis GJ, Grover T, Silpngarmlert S, Collett TS &
Holdich SA. Coupled multiphase fluid flow and wellbore stability anal-
ysis associated with gas production from oceanic hydrate-bearing sedi-
ments. J Petrol Sci Eng 2012;(92/93):65e81.
643Wan YZ. et al. / Natural Gas Industry B 5 (2018) 631e643
... During drilling operations in gas hydrate reservoirs, invasion of drilling fluid filtrate into the formation occurs when applying pressure is higher than pore pressure [11]. Meanwhile, hydrate formation and dissociation induced by the drilling fluid [12,13] make the drilling process challenging attributing to changes in physical properties of sediments [14e16], variation of stress state [17,18], phase change [19], multiphase flow characteristics [20], and induced wellbore stability [21,22]. Thus, the invasion characteristics and reservoir responses are essential for geological risk analysis and well control during drilling. ...
... The gas generation rate during hydrate dissociation is described by Kim-Bishoni kinetic model [22,38], as follows; ...
... To give the flexibility of physical properties and boundary conditions, the mesh is imported through ASCII files. Besides, The solutions are obtained by solving linear equations with the finite element method (FEM) [22]. The flowchart of model solving is displayed in Fig. 3. ...
Article
The drilling fluid invasion into hydrate-bearing sediments (HBS) would trigger geological risks. However, invasion mechanisms and formation responses during drilling the gas hydrate reservoirs, especially the fluid-loss characteristics and control mechanisms of hydrate dissociation, remain poorly understood. Thus, we develop a three-dimensional (3-D) coupled thermal-hydro-chemical model to investigate the drilling fluid invasion process and dynamic responses of gas hydrate reservoirs. This model deals with the fluid-loss and flow field characteristics as well as well-formation interactions considering the effect of hydrate dissociation. The results indicate that the invasion characteristics mainly depend on drilling fluid pressure and permeability, while the temperature influences the hydrate dissociation. Besides, the fluid-loss velocity increases slowly after a sharp decrease at initial stage of invasion due to the increase of permeability induced by hydrate dissociation. Afterward, characteristics and mechanisms of drilling fluid invasion into hydrate reservoirs are determined by the invasion process coupled with hydrate dissociation. Given the unique characteristics of HBS, the invaded formation is divided into flushed zone, transition zone, and undisturbed zone, presenting a better description of the dynamic filtration process. Moreover, optimization strategies and drilling technology are proposed to prevent hydrate dissociation and control geological risks during drilling hydrate.
... The water depth of site W19 is 1273.9m, and the survey results show that the pressure and temperature at the seafloor are 12.86 MPa and 3.75 • C, respectively, with a geothermal gradient of 45 • C/km (Wan et al., 2018). The initial porosity and permeability values refer to the average values measured from the formations without hydrates. ...
Article
Methane hydrates (MH) are widely distributed below seafloor at marine locations. Most MH bearing geological deposits have dip angles because of the complicated geological structure and diagenesis. In this study, the impact of formation dip on CH4 migration and the associated MH formation was systematically investigated numerically. A numerical model was setup based on the geological information in the Shenhu area of Baiyun Sag in the northern South China Sea (SCS) to simulate the long-term transport of CH4 and the associated MH formation with formation dip. We further conducted a sensitivity analysis and a statistical analysis on three key geological parameters (i.e., dip angle, CH4 leakage rate, and water salinity). The results indicate that the dip angle (θ) of the reservoir promotes the lateral migration of CH4. The total accumulated amount of MH decreases 2.45% with θ increasing from 0° to 10°. Sensitivity analysis suggested that the formation of MH predominantly depends on the CH4 leakage rate (RCH4) in inclined reservoirs. The lateral migration distance of CH4 increases 13.1% but the total accumulated amount of MH decreases 8.8% with increasing water salinity (Xi) from 3.0 wt% to 3.5wt%. We further analyzed the effect of heterogeneity, which shows that the inclined reservoir with alternating sand and clay layers favor MH formation more than a uniform reservoir with an 8.8% increase in the total MH. Understanding the effect of formation dip on the transport of CH4 and MH formation provide useful reference in identification of marine MH resources and in design of safe and effective exploration strategies.
... In order to produce methane from the gas hydrates reservoir, technologies like depressurization, thermal stimulation, chemical injection and carbon dioxide replacement are mainly analyzed globally. Among the abovementioned technologies, the depressurization is considered as the highly efficient productive method [8] with or without the support of thermal stimulation. ...
Conference Paper
Full-text available
As a non-conventional promising energy resource, methane hydrates research is gaining momentum globally as alternate resource with low carbon foot print. Many challenges are to be addressed for gas hydrates extraction feasibility approach in deep water marine settings. The reaction of the reservoir soil during methane gas production from the Natural Gas Hydrate (NGH) reservoir is the most important aspect to understand for the sea floor stability. Present study numerically investigates the surface settlement of the sea floor using PLAXIS 3D due to tunnel like structure formation by spherical dissociation front propagation around the well in Krishna Godavari basin of Indian deep water gas hydrate reservoir. In addition, analyses had also brought out the variation in subsidence characteristics due to changing tunnel parameters such as tunnel size and placing depth of tunnel, for optimizing the design parameter for methane hydrate spherical dissociation front. Results show maximum surface soil settlement in the tunnel size of 4m (diameter) while placing the dissociation front depth at 50 meter below sea floor (mbsf) at 1050 m water depth. Results recommend this proposed technique for safe production of methane gas from hydrates.
... In order to produce methane from the gas hydrates reservoir, technologies like depressurization, thermal stimulation, chemical injection and carbon dioxide replacement are mainly analyzed globally. Among the abovementioned technologies, the depressurization is considered as the highly efficient productive method [8] with or without the support of thermal stimulation. ...
Conference Paper
Full-text available
As a non-conventional promising energy resource, methane hydrates research is gaining momentum globally as alternate resource with low carbon foot print. Many challenges are to be addressed for gas hydrates extraction feasibility approach in deep water marine settings. The reaction of the reservoir soil during methane gas production from the Natural Gas Hydrate (NGH) reservoir is the most important aspect to understand for the sea floor stability. Present study numerically investigates the surface settlement of the sea floor using PLAXIS 3D due to tunnel like structure formation by spherical dissociation front propagation around the well in Krishna Godavari basin of Indian deep water gas hydrate reservoir. In addition, analyses had also brought out the variation in subsidence characteristics due to changing tunnel parameters such as tunnel size and placing depth of tunnel, for optimizing the design parameter for methane hydrate spherical dissociation front. Results show maximum surface soil settlement in the tunnel size of 4m (diameter) while placing the dissociation front depth at 50 meter below sea floor (mbsf) at 1050 m water depth. Results recommend this proposed technique for safe production of methane gas from hydrates.
... Besides, the initial water and hydrate saturation are 0.5 and 0.5, respectively. The parameters are determined according to the previous studies and geological data in the South China Sea [11,12], as shown in Table 1. Figure 2 shows the distribution of pore pressure during gas hydrate production. The pore pressure increases from near-well region to far well formation. ...
Chapter
The velocity of dissociation front is key factor to reflect the hydrate production process. However, the characteristics of dissociation front and formation responses during hydrate production are not studied in detail. To investigate the dissociation performance of gas hydrate, we conduct a numerical model to simulate the process of gas extraction from formation by depressurization. The distribution of hydrate, water, and gas saturation varies during production process. The hydrate saturation decreases in near-well region, while the gas saturation increases. The dissociation zone expands and dissociation front moves from well to formation. This work can provide a reference for natural gas development.
... Jin et al. [19] used a direct coupling method to discuss the influences of warm water injection and the horizontal well placements on gas production. Some coupled mathematical methods were proposed to investigate borehole stability and identify the key factors affecting formation responses, such as hydrate dissociation, fluid-solid coupling and borehole effect [20,21]. Although above researches were completed in 2D planar model, they would provide reference for 3D modeling of multi-field coupled process in present work. ...
Article
During marine hydrate production, some potentially undesirable consequences of casing failure and deformation are prone to occur. However, conventional planar model used in oil-gas production casing analysis is unable to handle failure and deformation of the casing, as the temporal-spatial evolution of formation caused by hydrate decomposition could not be calculated. This paper aimed at proposing a methodology to research 3D stress distribution and deformation of casing. In the proposed approach, a multi-field coupled algorithm of seepage-mechanics-decomposition was developed, and a 3D interaction model of casing-formation was established, in which dynamic characteristics of formation deformation could be considered. The effect of slanting formation on casing behaviors was investigated by improving the established 3D model. A case study illustrated the application of the proposed methodology. Results indicated that casing strength yielding was dominated by axial stress, which increased first and then gradually stabilized as production advanced. When formation inclination changed from 0° to 5°, axial stress would increase by 15%, the recommended differential pressure of production should be decreased from 10 MPa to 8 MPa, and the casing deformation pattern changed from diameter reduction to bending. The proposed approach could be used to provide theoretical reference for casing design of marine hydrate production.
Article
The majority of marine hydrates are buried in unconsolidated or poorly consolidated marine sediments with limited cementation and strength. As a result, hydrate decomposition during production may cause the significant subsidence of the formation, necessitating a halt in production. The numerical model of unconsolidated hydrate formation, based on geomechanics, was established in order to elucidate the depressurization production process. The sensitive factors of unconsolidated hydrate production were determined by analyzing the influence of formation parameters and production parameters on gas production. Then, a safety formation subsidence was proposed in this paper, and the appropriate well type and parameters for the safe and efficient production of hydrates in unconsolidated formations of various saturations were determined. The sensitivity of gas production to the formation parameters was in the order of formation porosity, hydrate saturation, and buried depth, while the effects of the production parameters were BHP (bottom hole pressure), horizontal length, and the heat injection, in descending order. For hydrate reservoirs in the South China Sea, when the hydrate saturation is 20%, a horizontal well is necessary and the appropriate horizontal length should be less than 80 m. However, when hydrate saturation is more than 30%, a vertical well should be selected, and the appropriate bottom hole pressure should be no less than 3800 kPa and 4800 kPa for 30% and 40% saturation, respectively. Based on the simulation results, hydrate saturation was the key factor by which to select an appropriate production technique in advance and adjust the production parameters. The study has elucidated the depressurization production of marine unconsolidated hydrate formations at depth, which has numerous implications for field production.
Article
Methane hydrates are a huge potential resource that could overturn the world energy balance. Various geophysical, geochemical, microbial indicators serve as a tool for studying subsurface methane fluxes and seep zones. Bottom simulating reflector (BSR) used to infer the presence of offshore methane hydrates is discussed. Geochemical data studies indicate methane enrichment and sulphate reduction around the globe. Lower chlorinity of pore water is onsidered as an indirect geochemical proxy of methane hydrates. Total organic carbon (TOC) analysis provides the clue for methane-rich seep zones. Deep-sea benthic foraminifera found in different marine settings including gas seepages, gas hydrates have great potential to reconstruct the past climate and oceanic changes owing to their wide distribution. The detection and assessment of gas hydrates are essential to evaluate future energy resources and environmental changes. Therefore the key intuition of the present review article is to make the reader understand the concept and background of the gas hydrates scenario and the implemented proxy techniques to infer the subsurface gas hydrates.
Article
Two successful trials in South China Sea show that low-permeability hydrate reservoirs have broad exploitation prospects. Currently, gas production efficiency and reservoir stability are key factors restricting the commercial exploitation. For improving development efficiency and evaluating reservoir stability, it is necessary to comprehensively evaluate different depressurization schemes. Based on the drilling data of hydrate reservoirs in South China Sea, a thermal-fluid-solid-chemical multi-field coupling model was established to analyze temporal and spatial evolution characteristics with three depressurization modes: regular depressurization(RD), step-wise depressurization(SD) and cycling depressurization(CD). The results show that compared with RD, SD and CD can improve production capacity in different degrees. Due to the limitation of convective heat transfer in low-permeability reservoir, RD productivity is mainly affected by formation sensible heat. SD and CD are mainly affected by formation sensible heat in early stage and formation latent heat plays a role in later stage. The formation deformation degree is positively correlated with hydrate decomposition radius. After 180 days, the maximum subsidence at reservoir and mudline is 0.0609 m and 0.0135 m respectively. Production and subsidence ratio(PSR) is proposed to evaluate different depressurization schemes. Finally, CD2 is the best scheme for low-permeability hydrate reservoir and PSR value is 20298.3 m³/cm.
Conference Paper
Full-text available
In any geologic settings, the complete characterization of the natural gas hydrate system requires an overlapping approach that includes direct sampling, downhole logging, and geophysical remote sensing. Due to the difficulty and cost of obtaining seafloor samples, scientists ultimately aspire to extract maximum information from downhole logs and geophysical data. Unfortunately, the inherent complexity and heterogeneity of natural systems often renders the interpretation of such indirect data difficult. As a means of calibrating logs and geophysical techniques, there is an important role for laboratory studies on controlled systems with known grain characteristics, formation history, and gas hydrate concentration. Such laboratory efforts lead not only to new effective media and mixture models that can be extended to interpret natural sediments, but also to a better mechanistic description of the interaction between hydrate and sediments. We have conducted an extensive series of laboratory experiments to measure the thermal, electrical, and mechanical properties of fully saturated, homogeneous sediments containing synthesized THF hydrate, with support from the ChevronTexaco Joint Industry Project (JIP) on Methane Hydrates. Test conditions span most of the range represented in natural marine sediments (grain sizes of 1 to 120 µm), gas hydrate concentrations of 0% to 100% in pore space, and effective confining pressures of up to 2 MPa. The suite of laboratory measurements is summarized in the table on the last page. Various cells are used to simulate the stress and strain fields in situ. These cells include a zero-lateral strain oedometer and axisymmetric triaxial and isotropic loading devices. Care has been taken to demonstrate reproducibility of the results, to calibrate equipment, and to maintain close temperature control on samples. The laboratory experiments have produced data that constrain many key parameters, including thermal conductivity; electrical resistivity, and real permittivity in the 200 MHz to 1.3 GHz range; small-strain mechanical properties such as P-and S-wave velocities; volume change during compaction and during phase transformation; and large-strain mechanical properties including stress-strain curves and failure envelopes. In addition, the laboratory program includes a significant number of low-perturbation process monitoring studies, where hydrate formation and dissociation in sediment are carefully followed. Finally, we have conducted detailed specimen dissection to explore the
Article
According to the preliminary geological data of gas hydrate bearing-sediments (GHBS) at site GMGS3-W19 in the third Chinese expedition to drill gas hydrates in 2015, a production model using three different recovery pressures was established to assess the production feasibility from both production potential and geomechanical response. The simulation results show that for this special Class 1 deposit, it is a little hard for gas production rate to reach the commercial extraction rate because the degree of hydrate dissociation is limited due to the low reservoir permeability and the permeable burdens. However, the free gas accumulating in the lower part of the GHBS can significantly increase gas-to-water ratio. It also generates many secondary hydrates in the GHBS at the same time. Decreasing the well pressure can be beneficial to gas recovery, but the recovery increase is not obvious. In term of geomechanical response of the reservoir during the gas recovery, the permeable burdens are conducive to reduction of the sediment deformation, though they don't facilitate the gas recovery rate. In addition, significant stress concentration is observed in the upper and lower edges of GHBS around the borehole during depressurization because of high pressure gradient, and the greater the well pressure drop, the more obvious the phenomenon. Yield failures and sand production easily take place in the edges. Therefore, in order to achieve the purpose of safe, efficient and long-term gas production, a balance between the production pressure and reservoir stability should be reached at the hydrate site. The production pressure difference and sand production must be carefully controlled and the high stress concentration zones need strengthening or sand control treatment during gas production. Besides, the sensitivity analyses show that the hydrate saturation heterogeneity can affect the production potential and geomechanical response to some extent, especially the water extraction rate and the effective stress distribution and evolution. Increasing GHBS and its underlying free gas formation permeabilities can enhance the gas production potential, but it probably introduces geomechanical risks to gas recovery operations.
Article
Bottom simulating reflections (BSR) are important geophysical markers of gas hydrate and widely present in the northern continental slope of South China Sea (SCS) since the late Miocene. In this study, we systematically analyze the depositional accumulation characteristics of gas hydrate in the northern continental slope of SCS in accordance with the distribution pattern of BSR in three third-order sequence stratum since the late Miocene, and combined with an integrated study of regional thermodynamic background as well as the depositional conditions (depositional facies, depositional rate, sand content, and lithology) and typical depositional bodies (structural slope, slumping block, and sediment waves). Under preferential conditions of temperature, pressure and gas source, the distribution of BSR is obviously constricted by the expansion of depositional system and the background of geological structure. That is, temperature, pressure, and gas source are necessary rather than sufficient conditions for the distribution of BSR. Following the above findings, a typical depositional accumulation model for the northern continental slope of SCS is established. The proposed model summarizes the distribution of depositional systems in continental structures (shelf, slope, and rise) with increasing water depth and their relationship with BSR and gas hydrate stability zones, displaying the typical elements of gas hydrate accumulation. The presence of BSR is closely related to structural slope break zones, deep-water gravity flow, and contourites. The majority of BSR are distributed in clay silt and silt deposits in seaward areas with steep and rough relief and long-term successive uplift and subsidence. In the frontier of continental shelf, BSR are laterally continuous but extend in a short distance, where the key of gas hydrate accumulation lies in the transport conditions for deep gas source. In the slope-trough and diapir development zones, BSR show discontinuous distribution as divided by faults and diapirs, where rapid unloading of deposits provides preferential depositional accumulation conditions for gas hydrate. In the continental rise to deep-sea areas with the development of submarine fans, turbidity currents and contour currents, BSR are laterally continuous and extends in a long distance with shallow biogas as the major source and mainly through lateral mitigation.
Article
Natural gas hydrate resources are thought to be extremely rich in the northern slope area of the South China Sea, where the geological conditions, however, were quite complex indeed for the hydrate formation. Therefore, from the viewpoints of regional geological settings such as stability condition, origin of source gas, gas migration and reservoir characteristics, we discussed the gas hydrate formation conditions and the associated controlling factors in this study area on the basis of recent years' research achievements. As a result, we obtained the following findings. (1) The complexity of the heat-flow distribution in the northern South China Sea has a great impact on the special extension of hydrate stability domain, while the geological tectonic evolution in this area controls the hydrate origin, gas channel system, storage space, and reservoir petrophysical properties. (2) Three distinct types of gas hydrate reservoirs identified with different formation conditions and controlling factors are distributed along the western, middle and eastern parts in this study area respectively. (3) In general, from east to west in this slope area, new tectonic activities are decreasing gradually, while the thickness of gas hydrate stability zone is becoming thinner both from east to west and from south to north. In the eastern part, the typical gas hydrate occurrence is located in the deep water slope of Southwestern Taiwan Basin where gas hydrates are accumulated as both diffusive and seepage types in several sediment layers. In the middle part, the typical occurrence, which is mainly dominated by dispersed gas hydrates often in single sediment layer, is represented by the southern slope of the Baiyun Sag, Shenhu Area. In the western part, especially the deep water slope of the Qiongdongnan Basin provides favorable condition for the accumulation of seepage gas hydrates.
Article
Considerable hydrate deposits are proved to exist by drilling in-situ in the Shenhu Area of South China Sea in China, and the survey and evaluation as a potential energy resource has been carried out. In May, 2007, gas hydrate samples have been collected in the Shenhu Area, which will become a strategical area of gas hydrate exploitation in China. TOUGH+HYDRATE is employed to simulate the hydrate dissociation and water/gas production process with the single depressurization and the depressurized+thermal stimulation, based on the geological data of the SH2, SH3 and SH7 site in the Shenhu Area in South China Sea. The simulation results indicate that the hydrate dissociate at the area surrounding the production well, the boundary area of the bottom and top of the hydrate bearing layer (HBL). There is an inversion of the geothermal gradient at the interface between the overburden (OB) and the HBL because of hydrate dissociation- induced cooling in the HBL. Practically impermeable secondary hydrate barrier evolves around the wellbore, which sealed the hydrate body and prevented communication with the evolving upper dissociating interface at the end of the depressurization process. With the hot water injected from the top of the HBL, the secondary hydrate can be eliminated during the depressurization+thermal stimulation process.
Article
In 2007, gas hydrate samples were recovered during the scientific expedition conducted by the China Geological Survey in the Shenhu Area. It is expected that Shenhu will become a strategic area of gas hydrate exploitation in China. However, evaluation of the hydrate deposits in the area as a potential energy resource has not been completed. Based on currently available data from site measurements, it is possible to develop preliminarily estimates of the gas production potential by numerical simulation. The hydrate accumulations in Shenhu Area are similar to Class 3 deposits (involving only a HBL) , and the overburden and underburden layers are assumed to be permeable. In this study, we estimated gas production from hydrates in the Shenhu Area using the depressurization method with a single horizontal well. The simulation results indicated that the hydrate dissociation occurs on the cylindrical interface around the well, and along the horizontal dissociation interfaces at the top and bottom of the HBL. The gas production rate in the Class 3 hydrate deposit at site SH7 in Shenhu Area is not suitable for commercial production using the depressurization method.
Article
We conducted numerical modeling of coupled multiphase fluid-flow, thermal, and geomechanical processes during gas production from an oceanic hydrate deposit to study the geomechanical performance and wellbore stability. We investigated two alternative cases of depressurization-induced gas production: (1) production from horizontal wells in a Class 3 deposit (a hydrate layer sandwiched between two low-permeability layers); and (2) production from vertical wells in a Class 2 deposit (a hydrate layer with an underlying zone of mobile water). The analysis showed that geomechanical responses around the wellbore are driven by reservoir-wide pressure depletion, which in turn, depends on production rate and pressure decline at the wellbore. The calculated vertical compaction of the relatively soft sediments and increased shear stress caused local yielding of the formation around the well assembly for both the horizontal and vertical well cases. However, the analysis also showed that the extent of the yield zone can be reduced if using overbalanced drilling (at an internal well pressure above the formation fluid pressure) and well completion that minimizes any annular gap between the well assembly and the formation. Our further analysis indicated that the most extensive yield zone would occur around the perforated production interval of a vertical well, where the pressure gradient is the highest. In the field, such yielding and shearing of the sediments could lead to enhanced sand production if not prevented with appropriate sand control technology. Moreover, our analysis shows that the vertical compaction of the reservoir can be substantial, with subsidence on the order of several meters and vertical compaction strain locally exceeding 10%. In the field, such substantial compaction strain will require appropriate well design (such as slip joints or heavy wall casing) to avoid tensile or buckling failure of the well assembly.
Article
In March 2013, the world's first field trial of gas production from marine methane hydrate deposits was conducted in the Daini Atsumi Knoll area of the Eastern Nankai Trough off the Pacific coast of Japan as a process to bring gas hydrates under seafloor to valuable energy resource. The technique used to dissociate the ice-like material was "depressurization method" that had been applied in the previous production test in Mallik site, the Northwest Territories, Canada in 2007-2008. Japan Oil, Gas and Metals National Corporation (JOGMEC) as a part of MH21, the Research Consortium for Methane Hydrate Resources in Japan planed and supervised the project with the funding of the Ministry of Economy, Trade and Industry (METI), and scientific supports from the National Institute of Advance Industrial Science and Technology (AIST). One production well with two monitoring boreholes were drilled in the test site for the test. Along with the flow test operation, intensive data acquisition program was planned and implemented to understand behavior of methane hydrate dissociation- bearing sediments against depressurization. To realize high degree of drawdown in relatively shallow formation below deepwater, several downhole devices were designed and installed. The flow test started in the morning of March 12 and lasted until severe sand production forced to terminate the operation six days later. During the stable production term, gas flow rate was approximately 20,000m³ under atmospheric condition, and gas liquid ratio was larger than 100. A lot of data including formation temperatures, fluid pressure and temperature, and physical property changes in the formation were obtained. The data taken are under studies to verify applicability of the depressurization technique as a methane hydrate production technologies.
Article
For the past decades, gas hydrate reservoirs have beneficiated from an increasing attention in the academic and industrial worlds. As a result, there is a growing need to develop specific and comprehensive gas hydrate reservoir characterization methods. This study explores the use of a stochastic Bayesian algorithm to integrate well-logs and 3D acoustic impedance in order to estimate gas hydrate grades (product of saturation and total porosity) over a representative volume of the Mallik gas hydrate field, located in the Mackenzie Delta, Northwest Territories of Canada. First, collocated log data from boreholes Mallik 5L-38 and 2L-38 are used to estimate the statistical relationship between acoustic impedance and gas hydrate grades. Second, conventional stochastic Bayesian simulation is applied to generate multiple gas hydrate grade 3D fields integrating log data and lateral variability of 3D acoustic impedance. These equiprobable scenarios permit to quantify the uncertainty over the estimation, and identify zones where this uncertainty is greater. Contrary to conventional stochastic reservoir modeling workflows, the proposed method allows integrating non Gaussian and non linear distributions. This permits to handle bimodal distributions without using complex stochastic transforms. The results present gas hydrate grade values that are in accordance with well-log data. The relatively low standard deviation calculated at each pixel using all realizations suggests that gas hydrate grades is well explained by acoustic impedance and log data.
Article
MH21 Research Consortium of Japan has been evaluating methane hydrate (MH) reservoirs located in the Eastern Nankai Trough from the viewpoints of geology, geophysics, petrophysics and reservoir/production engineering. As one of these studies, we have been predicting gas/water production performances from these MH reservoirs showing diverse characteristics. This paper presents the results of our examinations on the applicability of a variety of MH dissociation/production methods to these MH reservoirs and on the feasibility of the future development in terms of gas production and economics. Eastern Nankai Trough MH reservoirs, which are composed of alternating beds of sand, silt and clay in turbidite sediments, have various conditions of clay distribution as well as of initial pressure, temperature, permeability and MH saturation. Some of these reservoirs contain MH of high saturation at a certain interval (MH concentrated reservoir), while in the others MH is deposited sparsely (MH non-concentrated reservoir). Detailed numerical reservoir models were constructed for both MH concentrated and non-concentrated reservoirs, consulting the well log and seismic interpretation results. MH dissociation/production performances were then predicted through numerical simulation assuming the application of various MH dissociation methods such as depressurization, wellbore heating, hot water huff & puff and hot water flooding. The simulation studies clarified the difference in the gas production between MH concentrated and non-concentrated reservoirs. These studies also revealed that the permeability not only of sand layers but also of clay layers significantly affected the gas productivity from MH concentrated reservoirs. Furthermore, it was suggested that the hot water injection was effective when it was applied as a secondary recovery method after depressurization. Simple economic analysis based on these simulation results exhibited the promise that some MH reservoirs in the Eastern Nankai Trough could be economically developed if the well spacing and MH dissociation/production methods were appropriately designed. Introduction Background The Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium), which was organized to accomplish the exploration and exploitation of methane hydrate (MH) in the Nankai Trough of offshore Japan, has been implementing a variety of research projects toward the assessment of MH resources, establishment of MH production methods and examination of impacts of MH development on the environment. As part of such research projects, we have been developing the state-of-the-art numerical simulator (MH21-HYDRES) for rigorously predicting MH dissociation and production behaviors both at core and field scales. Using this numerical simulator, we have been implementing numerical simulation studies predicting MH reservoir performances in order to examine the effectiveness of a variety of production methods in terms of the gas producability from MH reservoirs with diverse characteristics (Kurihara et al., 2005a). These studies, however, have been conducted targeting imaginary reservoirs as well as those roughly mimicking Eastern Nankai Trough reservoirs by simplifying reservoir properties.