Seafloor subsidence induced by gas recovery from a hydrate-bearing sediment using multiple well system

Marine and Petroleum Geology 107 (2019) 438–450

Contents lists available at ScienceDirect

Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo

Research paper

Seafloor subsidence induced by gas recovery from a hydrate-bearing sediment using multiple well system

T

Guangrong Jina,b, Hongwu Leic, Tianfu Xub,∗, Lihua Liua, Xin Xinb, Haizhen Zhaia, Changling Liud a

Key Laboratory of Gas Hydrate, Guangzhou Institute of Energy Conversion, Chinese Academy of Sciences, Guangzhou, 510640, China Key Laboratory of Groundwater Resources and Environment, Ministry of Education, Jilin University, Changchun, 130021, China c State Key Laboratory of Geomechanics and Geotechnical Engineering, Institute of Rock and Soil Mechanics, China Academy of Sciences, Wuhan, Hubei, 430071, China d Key Laboratory of Gas Hydrate, Ministry of Natural Resources, Qingdao Institute of Marine Geology, Qingdao, 266071, China b

ARTICLE INFO

ABSTRACT

Keywords: Natural gas hydrate Gas recovery Geomechanical response Multiple wells system Well spacing

The response behavior of the methane exploitation from natural gas hydrate (NGH) using multiple well system is complex and needs to be investigated, as gas production from a single vertical well generally cannot meet commercial demand. This study numerically investigates the production performance and geomechanical response of an unconfined hydrate deposit in Shenhu area, South China Sea, under single and multiple vertical well conditions. For a single vertical well with a mild constant bottom-hole pressure, gas production is relatively stable. However, seafloor subsidence exhibits an initial rapid drop and a subsequent mild drop stage. The vertical displacement is highly developed at the top and bottom of the production zone. The results from doublet and triplet vertical wells indicate that both the gas and water production and seafloor subsidence increase with the increase in number of production wells. The superimposition of subsidence leads to a deterioration in subsidence and the change in location for the largest subsidence, which may affect the risk location of well instability. The interference of pore pressure and subsidence increases with the decrease in well spacing. However, gas production decreases and water production changes insignificantly. Furthermore, a same subsidence at seafloor cannot indicate the same evolution of subsidence in the vertical and lateral direction. The results presented in this study help in balancing the production and subsidence of the NGH exploitation in complex well configurations.

1. Introduction Natural gas hydrate (NGH) is crystalline solid composed of water and gases (such as methane, ethane, and propane) under high pressure and low temperature conditions (Max and Johnson, 2014; Max et al., 2005). Naturally, NGH is widely deposited in permafrost regions and marine sediments, and methane takes an overwhelming part among the gas compositions in the NGH. The global natural gas trapped in the NGH was estimated to be within the range of 1015–1018 m3 (Klauda and Sandler, 2005; Milkov, 2004). The NGH is considered as a potential energy resource and gas recovery from NGH has been attracting attention from all around the world. Various methods, such as depressurization, thermal stimulation, gas exchange, and inhibitor injection, have been proposed to recover gas from NGH (Jin et al., 2016; Sun et al., 2014; Zhang et al., 2010). The feasibilities and energy efficiencies of these methods have been studied extensively by laboratory experiments and numerical simulations (Wu

∗

et al., 2018a, 2018b; Yang et al., 2018). Consequently, depressurization is considered as the most economic method (Li et al., 2016a). Therefore, in the past few years, depressurization was the main method, which was validated in the short-term field trials, including those at the Mallik site in Canada in 2002 and 2007/2008 (Collett et al., 2013), in Nankai Trough in Japan in 2013 and 2017 (Konno et al., 2017; Yamamoto, 2015; Yamamoto et al., 2017), and in Shenhu area in South China Sea in 2017 (Li et al., 2018). However, the engineering experiences of field trials show that large deformation and possible sand production are the geological risks for the gas recovery from NGH (Gupta et al., 2017; Yamamoto, 2015). Therefore, geomechanical issues are crucial for the safe recovery of NGH and should not be ignored, as they affect the duration of future long-term production. The geomechanical issues of hydrate-bearing sediment (HBS) are mainly attributed to pore pressure drawdown, temperature reduction, and decreased strength after the dissociation of hydrate (Gupta et al., 2017). The contribution of the NGH to the strength of HBS during

Corresponding author. E-mail address: [email protected] (T. Xu).

https://doi.org/10.1016/j.marpetgeo.2019.05.008 Received 21 September 2018; Received in revised form 8 May 2019; Accepted 9 May 2019 Available online 16 May 2019 0264-8172/ © 2019 Elsevier Ltd. All rights reserved.

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Table 1 Governing equations for fluid and heat flow in TOUGH + hydrate. Description

Equation

Mass and energy conservation

d dt

M dV =

Mass accumulation

M =

Mass flux (Aqueous phase)

FA =

Mass flux (Gas phase)

FG =

Heat flux

F =

hydrate dissociation decreases because the solid hydrate turns to mobile water and gas (Sun et al., 2019b). Recently, the deformation characteristics and failure strength of HBS have increasingly investigated using tri-axial experiments (Jang et al., 2018; Liu et al., 2018; Yoneda et al., 2017; Zhang et al., 2015). The results indicate that the HBS strength increases with hydrate saturation and confining pressure (Hyodo et al., 2014; Li et al., 2016b), whereas the hydrate dissociation could cause a great decrease in the mechanical strength. Although most of the experiments related to mechanical characteristics are based on man-made samples and remolded sediment, some experiments showed that, to some extent, artificial hydrate samples have similar mechanical behaviors to those of in situ sample (Luo et al., 2016; Zhang et al., 2015). Therefore, the mechanical properties and deformation patterns from these experiments provide basis for numerical evaluation of geomechanical issues encountered on a field-scale. With the increasingly attention about geomechanical responses, several simulation tools (Gupta et al., 2015; Jin et al., 2018; Kimoto et al., 2010; Klar et al., 2010; Moridis et al., 2017; Rutqvist, 2017) have been developed to study the geomechanical responses to gas recovery from hydrate reservoirs. The stress around wellbore is driven by pressure drop in HBS (Gupta et al., 2015; Klar et al., 2010; Rutqvist et al., 2012; Sun et al., 2019a), which causes sediment deformation (such as, seafloor subsidence) and may increase the risk of wellbore instability (Gupta et al., 2015; Klar et al., 2010; Rutqvist et al., 2012; Sun et al., 2019a). Rutqvist et al. (2012) investigated the geomechanical performance of HBS in Gulf of Mexico with a large pressure drop, and found that the subsidence (vertical compaction) may reach the order of 2–3 m. The geomechanical simulation of the production test of NGH in Nankai Trough shows that the subsidence could reach tens of centimeters in six days (Uchida et al., 2016; Zhou et al., 2014), although the stimulated pressure drop in lateral direction was quite small (Konno et al., 2017), which could results in high shearing deformation, thus further contributing to the sand migration (Uchida et al., 2016; Yamamoto, 2015). Recently, Lin et al. (2018) used the parameters calibrated using geomechanical test data and assessed the sediment stability of a thin interbedded HBS of India (Yoneda et al., 2018). Based upon the results, they reported the probable presence of a large subsidence during depressurization. Recently, feasibility studies considering the gas recovery and stability of HBS in Shenhu area, South China Sea, have been preliminary addressed (Jin et al., 2018; Sun et al., 2017). A high permeability of HBS is conducive to gas production, whereas it turns against the purpose of reducing subsidence (Sun et al., 2017). The permeable condition of the bounded layers may significantly affect the subsidence (Jin et al., 2018). The gas productivity and geomechanical response should be carefully balanced according to the geological conditions. However, previous studies have mainly focused on the geomechanical response of a single vertical or horizontal well (Rutqvist et al., 2012). Recently, Moridis et al. (2018) first studied the long-term potential under full-

krA A XA ( µA

k 1+

M = (1

Qdiss =

S

= A, G, I , H

k

q dV Vn

n

Energy accumulation Reaction heat of hydrate dissociation

F •nd +

Vn

PA

bslippage PG

)

R CR T +

T+

= A, G

X ,

= w, m , i , h

A g),

krG G XG ( µG = A, G, H , I

= w, m , i

PG S

G g)

+ JG ,

= w, m

U + Qdiss

h F

( H SH UH ) for equilibrium dissociation QH UH for kinetic dissociation

field production using a system of multiple vertical wells. They found that the system of multiple vertical wells benefits the reduction of water production, but causes significant displacements, which can be challenging to well construction and stability (Moridis et al., 2018). Therefore, the geomechanical response to multiple well system is needed to be studied further. This study aims to understand the production performance and corresponding geomechanical responses due to the NGH exploitation using a single and multiple vertical wells in Shenhu area of South China Sea. The relationship between gas and water production and subsidence is investigated. The effects of number of wells and well spacing, and corresponding well interference are also discussed. 2. Materials and methodologies 2.1. Numerical simulator 2.1.1. Governing equations for the THM processes All simulations were performed using TOUGH + hydrate + Biot code (simply called as hydrateBiot), which is an extension of TOUGH2Biot and is capable of characterizing the geomechanical response associated to the NGH recovery (Jin et al., 2018; Lei et al., 2015). HydrateBiot was developed based on TOUGH + hydrate code (Moridis et al., 2008), which provides a reliable base to simulate the thermo-hydrological processes during NGH recovery. TOUGH + hydrate can simulate the transport of four components (water, CH4, hydrate, water-soluble inhibitors such as salts or alcohols) among four phases (gas, liquid, ice and hydrate phase), and also the non-isothermal dissociation of hydrate and heat flow. The governing equations of mass and energy balance are summarized in Table 1 (Moridis et al., 2008) (see Nomenclature for definitions of all symbols used). For mechanical deformation, although the tri-axial tests show that the stress-strain relationship of a hydrate-bearing sample is not expressed as elastic behavior (Liu et al., 2018; Luo et al., 2016; Masui et al., 2008; Miyazaki et al., 2010, 2011; Zhang et al., 2015), the HBS can be regarded as elastic material as long as the range of application is sufficiently limited to small-strain cases far away from the critical state (Gupta et al., 2015, 2017). Based on the principle of effective stress and the assumption of linear elasticity, the mechanical process was applied using an extended Biot consolidation model with the displacement as the primary unknown variable, as shown in Table 2 (Jin et al., 2018; Lei et al., 2015). The strength of HBS increases linearly with the hydrate saturation and also confining pressure. While the effect of confining pressure is ignored in this study. Therefore, the bulk modulus, shear modulus and cohesion are simply expressed as following equations, respectively (Rutqvist et al., 2012):

K = (KSH1 439

KSH0) × SH + KSH0

(1)

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Table 2 Three-dimensional (3D) extended Biot mechanical model. Description

Governing equations

Displacement

Stress and strain

G

2w

y

1

G 2

y

G

2w z

1

G 2

z

( ( ( x

G

c = (cSH1

GSH0) × SH + GSH0

cSH0) × SH + cSH0

x

z

( = 2G ( = 2G (

yz

=G

x y

G = (GSH1

2w

= 2G

1

G 2

x

1

2

v

+

1

2

v

+

y

1

2

v

+

z

yz, zx

(2)

=G

wx x wx x

+

wx x

+

)+3 )+3 )+3

zx , xy

wy

+

+

wz z

+

wz z

+

wz z

y wy y wy y

T

T

T

T

T

T

=G

xy

)+ )+ )+

x

=

y

=

z

=

Pa x

+3

T TK x

=0

Pa y

+3

T TK y

=0

Pa z

+3

T TK z

=

wx , yz x wy

zx

=

wz , xy z

=

y

,

=

(

(

(

wy

sat

+

wz y

wz x

+

wx z

wx y

+

z

wy x

)

)

)

Su et al., 2018). Moreover, gases contained in the hydrate in Shenhu area mainly consist of methane (96.10–99.91%) with minor ethane and propane (Liu et al., 2015a, 2015b).

(3)

Where GSH0 and GSH1 are the shear modulus without hydrate and full saturated with hydrate, respectively. KSH0 and KSH1 are the bulk modulus without hydrate and full saturated with hydrate, respectively. cSH0 and cSH1 are the cohesion without hydrate and full saturated with hydrate, respectively.

2.3. Model setup The sedimentary formation modeled consists of three horizontal layers, according to logs in SH2 site: the 44 m thick HBS, the overlying and underlying sedimentary formations with the thicknesses of 185 m (Fig. 2). The formation modeled begins from seafloor and extends downward, and the effect of dipping formation is ignored because of the small dip angle and its insignificant effect in an unconfined HBS (Yuan et al., 2018). The formation extends laterally 5.0 km, in x and y directions, from the production well. Considering the placement of a three vertical well system (as described in section 2.3.1), the modeled domain is 10.2 km × 10 km × 414 m (in x, y, and z directions).

2.1.2. Coupling TH with M The THM processes are decoupled into the fluid and heat flows models (TH) and the mechanical model (Gupta et al., 2015; Moridis et al., 2017; Rutqvist et al., 2012). The fully coupled TH processes of TOUGH + hydrate are inherited. The stress and strain are obtained by solving the extended Biot mechanical equations. The TH processes are solved first, and then sequentially the mechanical model in single time step. The TH model is spatially discretized using an integral finite different approach, and the fully implicit finite difference method is used for time discretization (Moridis et al., 2008). The mechanical model is implemented using the Galerkin finite element method as reported in Lei et al. (2015). The mechanical modular is developed using Fortran 90/95 and is integrated into the TOUGH + hydrate code, forming the TOUGH + hydrate + Biot simulator. The verifications of TOUGH + hydrate + Biot have been described in Lei et al. (2015) and Jin et al. (2018).

2.3.1. Well placement The seafloor subsidence and corresponding gas production for a single and multiple vertical wells will be studied. For gas production using single vertical well, the well is centered in the modeled domain (Fig. 3a). For the multiple vertical well system, the well spacing is 100 m and the vertical wells are located in the line along the x-axis direction (Fig. 3b and c). The modeled domain in the x-axis direction is 0.2 km greater than that in the y-axis direction. The perforation intervals of vertical wells are limited in the middle part of HBS, because the hydrate highly deposits there. The perforation intervals have the length of 20 m and a distance of 12 m from the overlying and underlying formations, which is also expected to help avoid excessive water production.

2.2. Geological setting The Shenhu area in the northern slope of South China Sea is the first exploited natural gas hydrate (NGH) reservoir in China (Fig. 1). It is located in Pearl River Mouth Basin between Xisha Trough and Dongsha Islands (Wu et al., 2011; Yang et al., 2017). The drilling campaign by China Geological Survey in 2007 discovered the sediments rich with NGH in SH2, SH3 and SH7 drillholes. The thickness of HBS is estimated to be 10–44 m. The condition of hydrate at the bottom of the HBS is close to the equilibrium curve for the hydrate stabilization, which is suitable for exploitation (Wu et al., 2011). The lithology logs show the HBS of SH2 site sits at about 185 m below seafloor, and has the thickness of 44 m. The sea floor of SH2 site is about 1230 m below the sea level (Wang et al., 2014). The hydrate disseminates in the sediments that is mainly composed of silty clay and clay silt (Liu et al., 2015b; Wu et al., 2011), with the porosity from 0.33 to 0.48 and the hydrate saturation from 25% to 48% (Huang et al., 2015; Li et al., 2011; Wang et al., 2014; Wu et al., 2011). The HBS is overlain and underlain by permeable strata, which have the similar lithology as that of HBS layer but lack hydrate. This is due to the grain size analysis of sediment cores from drilling sites confirmed that the grain size distribution pattern of the HBS is similar to that of the sediments above and below the HBS (Chen et al., 2011; Liu et al., 2012;

2.3.2. Domain discretization The modeled domain is discretized into cuboids and the grid discretization schemes for gas production using single and multiple vertical wells are controlled to be consistent. The vertical grid size is 4 m for the HBS, and it increases gradually with distance from the HBS and the maximum size of grid is 65 m. In x- and y-axis direction, the grid size of 1 m is used close to the production well and the grid size increases with distance from the production well. Furthermore, the grid is refined between vertical wells (within the domain of x = 0–200 m) to obtain more detailed deformation between the wells. Finally, the modeled domain is discretized into 17871 grids (37 × 23 × 21 in x, y, and z directions), which is a relatively coarse discretization scheme for saving computational time and cost. 2.3.3. Initial and boundary condition The initial pore pressure increases with depth, and follows the hydrostatic pressure. The sea-water density is assumed to be 1020 kg/m3 and the gravitational acceleration is 9.806 m/s2. The initial 440

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Fig. 1. Location of the study area in South China Sea and the drilling sites (Wu et al., 2011).

overlying and underlying layers are sufficient for the thermal and flow process in HBS (Jin et al., 2016; Moridis et al., 2011). Neumann boundary conditions without mass and heat fluxes are applied at the position with the distance of 5 km from the production well, as the domain laterally extends enough to insignificantly affect the modeling results. The initial stress distribution is assumed to be isotropic because of the lack of field data. Furthermore, initial stress increases with depth, and follows the stress gradient of approximate 22.6 kPa/m. The zero displacement condition is assumed at the direction normal to the model sides and bottom. The top surface is freely moving. 2.3.4. Parameters The NGH is assumed to be pure methane hydrate. The hydrate saturation (SH) in vertical is set according to the analysis of samples recovered from field (Wu et al., 2011). The majority of the NGH (up to 48% in pore space) concentrates in the central part of HBS, and SH decreases towards both the shallow and deep parts. The aqueous saturation of HBS can be inferred by 1-SH. The layers overlying and underlying the HBS are saturated by water with an aqueous saturation of 1.0. The porosity in the sediment is assumed to be 0.38, and the intrinsic permeability is 10 millidracy (mD) (Su et al., 2012; Zhang et al., 2010). Other hydraulic and thermal parameters are summarized in Table 3. The strength of the artificial samples containing NGH (Luo et al., 2016; Zhang et al., 2015), which are similar to that of HBS from South China Sea, is lower than the sand sample obtained from either the

Fig. 2. Schematic setup of the sedimentary formation and the model geometry.

temperature increases with depth with a geothermal gradient of 0.047 °C/m (Wang et al., 2014). The constant temperature and pore pressure are assumed at the top and bottom of the model, because the 441

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Table 3 Main thermo-physical parameters of the formation. Parameter

Value a

HBS thickness (m) Hydrate saturationa,c

44 0.02–0.48

Initial pore pressure at the base of HBS (MPa)b Geothermal gradient (°C/m)b Wet thermal conductivity (W/ m/K)d Aqueous relative permeability model krA = (SA)nA

14.97

SA = (SA SirA)/(1 SirA ) nA d SirA d Capillary pressure model

Pcap = md SirA d a b c d

P0 ([SA]

1/ m

0.047 1.0

5.0 0.30

1 m

1)

0.45 0.29

Parameter

Value

b

Porosity Intrinsic permeability of all formation (mD)b Initial temperature at the base of HBS (°C)b Salinityb Dry thermal conductivity (W/m/K)d Gas relative permeability model krG = (SG )nG

SG = (SG nG d SirG d

SirG )/(1

SA = (SA

SirA)/(SmxA

0.38 10 14.87 0.03 3.0

SirG )

3.5 0.03

SirA)

P0 ( × 105 Pa)d SmxA d

1.0 1.0

Wu et al. (2011). Su et al. (2012). Jin et al. (2016). Zhang et al. (2010). Table 4 Mechanical parameters derived. Parameter

Value

Bulk modulus at SH = 0 Bulk modulus at SH = 1 Shear modulus at SH = 0 Shear modulus at SH = 1 Friction angle Cohesion at SH = 0 Cohesion at SH = 1 Thermal expansion coefficient Biot's coefficient (−)

12 MPa 91 MPa 36 MPa 121 MPa 5° 0.1 MPa 2.0 MPa 1 × 10−5 °C 1

−1

without and with the well interference of pore pressure drop and hydrate dissociation front, the following simulation scenarios (Table 5) are designed to comprehensively investigate the dynamic subsidence and the related gas and water production for a long-term operation. Among the scenarios, A1 and C1 represent the base-case for gas production using single and multiple vertical well system, and the case with different well spacing, respectively. The production pressure of 8 MPa is used, which is less than the production pressure in the field trial, to avoid a large subsidence in long-term production.

Fig. 3. Schematic of well placement. (a) Single vertical well, (b) doublet vertical wells, (c) triplet vertical wells.

artificial or natural core samples (Masui et al., 2008; Miyazaki et al., 2011; Yoneda et al., 2015, 2017). The strength increases with hydrate saturation and confining pressure, whereas the effect of confining pressure on strength is ignored in this study. The secant modulus can be calculated from the test data and it could be served as the elastic modulus. The mechanical properties (the bulk modulus and shear modulus) used are derived from Luo et al. (2016), as listed in Table 4. The artificial samples here could provide us a rough limitation of the mechanical properties due to the lack of the natural core sample from South China Sea. The friction is assumed to be independent of hydrate saturation and is equal to 5° (Luo et al., 2016; Zhang et al., 2015).

3. Results and discussion 3.1. Single vertical well 3.1.1. Gas and water production The long-term production behavior of gas and water under the production pressure of 8 MPa is selected as the base-case scenario (Fig. 4). The initial gas production of 8 MPa reaches 235m3/day, which is due to the rapid dissociation under initial large differences in the pore pressure between the wellbore and the region around the well and the quick migration of gas towards the production well, and the hypothesis of the equilibrium model in this study. As shown in Fig. 5, pore pressure at the depth of the middle of production interval (z = 207 m, with the distance of 0.5 m from the production well) decreases rapidly in the initial stage, and the pressure driving force causes the rapid dissociation of hydrate and temperature reduction. However, the released methane from hydrate exceeds the methane removed from the dissociation zone,

2.4. Simulation scenarios The production performance and corresponding geomechanical responses relate to sediment properties (hydrate saturation, mechanical properties, drainage conditions), well configurations (well type, number of wells and well spacing), and the artificial operations (production pressure and rate of pressure reduction). In order to investigate the relationships between gas and water production and subsidence 442

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Table 5 Simulation scenarios. Simulation ID

Number of well

PW (MPa)

Well spacing (m)

Produced gas and water 4

A1 A2 A3 B1 C1 C2 C3

1 2 3

8 5 10 8 8 8 8

– – – 100 100 50 20

3

Sub (m) 4

3

Gas (10 m )

Water (10 m )

84.9 116.6 59.6 167.9 250.6 245.1 218.9

21.6 32.7 14.0 43.2 64.6 65.5 65.6

0.071 0.102 0.049 0.128 0.184 0.212 0.215

Note that PW is production pressure at well bottom, the perforation length of vertical well is 20 m, in the middle of HBS. The produced gas and water for multiple vertical wells are the sum of cumulative water and gas of each vertical well after 15-years production. Sub is the subsidence at seafloor (at x = 5.1 km, y = 5 km, and z = 0 m), which corresponds to the location of well for single vertical well, location of the right well along x-axis direction for doublet vertical wells, and the middle well for triplet vertical wells system, respectively.

and accumulates to form the gaseous methane (Fig. 5e). The released methane cannot be fully extracted at the well because of the capillary pressure. After the initial high gas production, the gas production rate decreases rapidly to about 120 m3/day (Fig. 4). The gas production rate increases gradually due to the increasing dissociation zone of hydrate around the well and the increasing migration of the released methane towards the well. The temperature recovers gradually (Point B in Fig. 5b) after the hydrate at the depth of the middle of production interval (with 0.5 m from the well) decreases completely. The pore space freed due to the hydrate dissociation contributes to fluid flow and the increase in gas and water production. The pore pressure at the depth of production interval (z = 207 m), which is 0.5 m laterally from the well, recovers gradually after 95 days. This is mainly caused by the dissociation of hydrate at the top and bottom parts of the HBS (Point A and C in Fig. 5), and the increases in the hydraulic connection between the HBS and the bounded layers. Therefore, water in the bounded layers flows into HBS and contributes to the increase in water production. The recovery rate of pore pressure decreases after the complete dissociation of hydrate around the well. With the migration of dissociation front from well and the decrease in content of hydrate at the top and bottom of the HBS, the pressure driving force for hydrate dissociation decreases and causes a decrease in release rate of methane from the hydrate. The gas production in gaseous phase gradually decreases to zero, while gas production in dissolved methane becomes stable because of the stable water production. Both the gas and water production increase with the decrease in production pressure. A lower production pressure results in a larger pressure drop (differences between the production pressure and initial pore pressure), the dissociation of hydrate and an enhanced fluid flow. Therefore, the range of pressure drop and the dissociation front increase, and more hydrates are stimulated to dissociate, whereas the duration of the production stage with gaseous methane extends.

3.1.2. Sediment deformation The long-term evolution of seafloor subsidence is shown in Fig. 6a. The seafloor first drops rapidly in response to the initial dramatic drop in pore pressure at the well (Figs. 5a and 7b). The drop in pore pressure at well results in an increase in the effective stress around the well, and decreases in the temperature and sediment strength because of the hydrate dissociation (Fig. 7c and d), which causes the compaction of sediment and drops of seafloor. The estimated seafloor subsidence of 8 MPa production pressure within the initial 40 days reaches 0.034 m (3.4 cm), which is about half of the total seafloor subsidence for 15 years. Therefore, the evolution of seafloor subsidence can be divided into the initial quick drop stage and the later stage of slow subsidence (Fig. 6). The sharp shift of seafloor subsidence is mainly attributed to a stable influence of effective stress, which is in response to the stable spatial distribution of pore pressure (Fig. 5a). The decrease in the rate of seafloor subsidence after the sharp shift is caused by the changes in effective stress and the softened sediment strength. The effective permeability increases with hydrate dissociation, which is conducive to fluids flow. Meanwhile, the water-trappedeffect of hydrate in HBS weakens. Consequently, the hydraulic connection between the HBS and the top and bottom bounded layers enhanced. The pore pressure and temperature recover slightly (Fig. 5a and b), due to which, the effective stress around the well decreases. However, because of the expansion of hydrate dissociation front, the influence range of effective stress increases as a response to the increase in influence range of pore pressure. The dissociation of hydrate that far away from the well becomes slow after the pore pressure stabilizes. The changes in strength of sediment containing the NGH and the influence range of effective stress are little. Therefore, the recoveries of pore pressure and temperature around the well mainly contribute to the decreasing rate of seafloor subsidence. The seafloor subsidence increases with the decrease in the production pressure. A high production pressure of 10 MPa results in a small

Fig. 4. Evolution of (a) gas production rate (QP) and gas production rate in gaseous phase (QPG) and (b) water production rate (QW) in a single vertical well system under different production pressures (PW). The volumetric rate is measured at standard temperature and pressure. 443

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Fig. 5. (a) Pore pressure, (b) temperature, (c) hydrate and (d) gas saturation at different depths of A, B and C (with the same distance of 0.5 m from the production well) in a single vertical production well with the bottom-hole pressure of 8 MPa. Fig. 6. (a) Evolution of vertical displacement at seafloor (at x = 5100 m, y = 5000 m, z = 0 m), (b) vertical displacement along the wellbore and (c) lateral displacement (movement towards the well is positive) at a 50 m distance from the well (the intersecting line of plane x = 4600 m and y = 4450 m) after 15 years. The PW is production pressure.

drawdown of pore pressure and the range of effective stress. Due to these, a low seafloor subsidence and gas production are obtained. By lowing the production pressure from 8 MPa to 5 MPa, the gas production after 15 years increases by 38%. However, the seafloor subsidence and water production increase by 46% and 51%, respectively. Although gas production increases with the decrease in production pressure, the corresponding increments in subsidence and water production exceed that of the gas production. Therefore, artificial engineering measures are needed to control the subsidence. The early stage of several tens of days is the hardest period to control the seafloor subsidence, which is due to the rapid subsidence. The subsidence (vertical displacement) in space after 15 years production of 8 MPa (Fig. 7a) is developed as a series of “cone” shaped iso-surface. Horizontally, the largest seafloor subsidence is developed at the well location (x = 5100 m and y = 5000 m), moreover, the seafloor subsidence in a plane view (x-y plane) forms circles centered on the well location. Vertically, sediments above the production zone drop in a large domain, because of the free movement of the seafloor and the gravity of the overburden layer. However, the sediment below the

production zone uplifts slightly because of the seepage force. Furthermore, the vertical displacement is significantly developed at the top and bottom of the production zone, which could be supported by the subsidence (vertical displacement) along the wellbore after 15 years (Fig. 6b), and the risk of shear failure or well instability at those locations increases. Furthermore, the possibility of wellbore instability increases with the decrease in production pressure because of the increased vertical displacement. The depressurization also results in the lateral movement of a large amount of sediment towards the well (Fig. 6c). The lateral movement increase with decrease in production pressure. A severe lateral movement in the vicinity of well increases the risk of sediment moving toward the production interval (Lin et al., 2018). This indicates that without appropriate sand control screen, sand particles may be produced. 3.2. Multiple vertical well system 3.2.1. Gas and water production The gas and water production increase linearly with the number of 444

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Fig. 7. Spatial distribution of (a) vertical displacement, (b) pore pressure, (c) hydrate saturation and (d) temperature after 15 years. The production pressure is 8 MPa.

Fig. 8. Evolution of (a) gas production rate (QP) and gas production rate in gaseous phase (QPG) and (b) water production rate (QW) in single, doublet, and triplet vertical well systems under the production pressure (PW) of 8 MPa.

production wells (well spacing is 100 m and the production pressure is 8 MPa), as shown in Fig. 8, and their evolutions are similar to those in the single well. However, the percentage of extracted gaseous methane in the total gas production changes insignificantly with the number of production wells (Fig. 8). Furthermore, the gaseous methane in multiple well system disappears at the same time. Therefore, the depressurization through vertical wells (including doublet and triplet well systems) with the spacing of 100 m cannot significantly stimulate the hydrate between the wells to dissociate, which have been supported by the spatial distribution of hydrate content shown in Fig. 9c. The dissociated hydrate is limited to a zone surrounding the production well. The water from the overburden and underburden flows into the HBS formation after the dissociation of hydrate at the top and bottom of HBS, and results in the temperature distribution (Fig. 9d). The influence

range of pore pressure is larger than those of both hydrate dissociation zone and temperature. However, the well interference of pore pressure is relative weak because the pore pressure between the vertical wells decreases just a little. The weakened well interference contributes insignificantly to the hydrate dissociation. As a consequence, the gas and water production for the triplet vertical wells with 100 m spacing roughly equals the sum of that through the three single vertical wells. Similar results are obtained for the doublet vertical wells. 3.2.2. Sediment deformation For the production using a multiple vertical wells system with 100 m spacing and a production pressure of 8 MPa, the seafloor subsidence increases with the number of production wells (Fig. 10). The behavior of seafloor subsidence exhibits similarly as that in a single 445

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Fig. 9. Spatial distribution of (a) vertical displacement, (b) pore pressure, (c) hydrate saturation and (d) temperature after 15 years. Depressurization is performed in the triplet vertical wells placed in a line.

vertical well. However, although a weak well interference of pore pressure for 100 m spacing is obtained, a longer time is needed to build a stable pore pressure distribution when increasing the number of production wells. Therefore, the shift of seafloor subsidence from the quick drop stage to slow stage is postponed slightly. The spatial subsidence (vertical displacement) for the triplet vertical wells placed in a line is shown in Fig. 9a. In horizontal direction, the largest seafloor subsidence is developed at the middle vertical well (x = 5100 m and y = 5000 m), which is the midpoint of the line connecting the three vertical wells. Moreover, the subsidence along the line connecting the vertical wells is developed more than that at both the sides away from the line. The superimposition of subsidence is heavily occurred along the line connecting the vertical wells, and the effect of superimposition decreases with the distance from the production well. This happened despite the weak well interference of pore pressure, hydrate saturation, and temperature. Finally, a larger domain of sediment is subjected to subsidence, and the final subsidence increases.

In vertical direction, the subsidence along the middle wellbore shows that the sediment above the production zone drops entirely, and the subsidence increases with the number of the production wells (Fig. 10b). However, the largest vertical displacement is developed at the depths of 100 m and 330 m, rather than at the top and the bottom of the production zone in a single vertical well. This may be due to the superimposition of subsidence, and the effect of superimposition in vertical direction enhances with distance to the production zone. Increasing the number of production wells also significantly causes a large lateral movement of sediment towards the well (Fig. 6c), which is because of the superimposition effect. Therefore, the increasing lateral movement of sediment indicates that adding production wells aggravate the migration potential of sand towards the production interval. 3.2.3. Effect of well spacing The effect of well spacing on the production performance and subsidence are further studied based on the triplet vertical well system. By Fig. 10. (a) Evolution of the vertical displacement at seafloor (at x = 5100 m, y = 5000 m, z = 0 m), (b) vertical displacement along the wellbore and (c) lateral displacement (movement towards the well is positive) at a 50 m distance from well (the intersecting line of plane x = 4600 m and y = 4450 m) after 15 years. The PW is production pressure.

446

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Fig. 11. Evolution of (a) gas production rate (QP) and gas production rate in gaseous phase (QPG) and (b) water production rate (QW) for a triplet vertical well system under different well spacings. The production pressure (PW) is 8 MPa.

because of the superposition of subsidence, although the hydrate between wells does not dissociate completely (Fig. 12c). For the triplet vertical wells with spacings of 50 m and 20 m, the spatial subsidence shows that the subsidence in a plane view (x-y plane) are almost identical (Fig. 12a and b). The largest seafloor subsidence is developed at the middle vertical well. However, the subsidence along the line connecting the vertical wells is not developed as significantly as that in a 100 m well spacing. The subsidence along and at the sides of the line connecting the vertical wells are developed similar to that in a short well spacing. This means that the superposition of subsidence has a similar effect in any direction for an intensive interference of pore pressure, regardless of whether the hydrate is fully dissociated. In vertical direction, the superposition of subsidence leads to the largest subsidence at the depth of about 100 m for different well spacings. However, the sediment between the location of largest subsidence and the top of HBS subsides more by decreasing the well spacing. Decrease in sediment strength because of hydrate dissociation contributes to the greater subsidence above the top of the HBS and below the bottom of the HBS. The subsidence for a three vertical wells placed in line may exhibit a near-same seafloor subsidence. However, the difference in subsidence along the wellbore means a short well spacing may increase the risk of well instability. Similarly, the sediment moves laterally more towards the well. The lateral movement of 20 m spacing is high in HBS, because of the intensive interference between the production wells and weakened sediment strength after hydrate dissociation. By comparing the increased value in lateral movement of single and multiple vertical wells system (Figs. 6c, 10c and 13c), the well spacing has a significant influence on lateral movement. Therefore, shorting well spacing may highly accelerate the potential of sand migrate toward the production interval.

decreasing the well spacing from 100 m to 50 m, the gas and water production become nearly identical in the early stage, and changes slightly in the later stage (Fig. 11). The dissociation of hydrate at the top and bottom parts of the HBS induces a slight difference in gas and water production in the later stage. By comparing the distribution of pore pressure (Figs. 9b and 12c), the interference of 50 m spacing becomes more intensive than that of 100 m spacing. However, after 15 years of depressurization, the hydrate between vertical wells for 50 m spacing (Fig. 12e) is not completely stimulated to dissociate under the enhanced well interference of pore pressure. This is mainly attributed to the constrained hydrate dissociation because of the endothermic reaction. When further decreasing the well spacing to 20 m, the water production changes insignificantly, while the gas production decreases after an initial increase. The spatial distribution of pore pressure of 20 m well spacing indicates a strong interference between the vertical wells (Fig. 12d). However, the strong well interference could not induce a significant increase in the water production (Fig. 11b). Hydrate between vertical wells are completely stimulated to dissociate under the strong well interference. Therefore, the water production becomes similar once the top and bottom parts of HBS dissociate, because of the similar effective permeability without hydrate. While the short well spacing means a smaller influence range of pore pressure drawdown, less hydrate dissociates. The gas production decreases because of the exhaustion of hydrate between the three vertical wells. For a production system using three vertical wells placed in a line, the seafloor subsidence increases with the decrease in well spacing. The seafloor of a 50 m well spacing drops more than that of 100 m well spacing, and the difference in seafloor subsidence increases as production proceeds. This is caused by the fact that the interference of subsidence in a short well spacing is more intensive than that of a wider well spacing. The effect of superposition of subsidence increases with the decrease in well spacing. However, when decreasing the well spacing from 50 m to 20 m, the seafloor subsidence exhibits a similar evolution in the initial stage and increases slightly with the decrease in well spacing. As a result, a similar seafloor subsidence is obtained after 15 years (Fig. 12a and b, and 13). The similar evolution of seafloor subsidence in the initial stage can be attributed to that the influence ranges of superposed pore pressure and subsidence extend outward inadequately to affect the subsidence. The total quantity of hydrate available for dissociation decreases with well spacing, due to the decrease in influence range of pore pressure drawdown. Hydrate between the wells dissociates under a strong interference of pore pressure, and results in significant decrease in the sediment strength. As a consequence, the seafloor of 20 m well spacing drops more during the hydrate dissociation. However, the seafloor subsidence becomes stable after the complete dissociation of hydrate between the wells. Therefore, the seafloor subsidence of 50 m well spacing reaches that of 20 m

4. Conclusions The relationships between the production and the corresponding subsidence for NGH exploitation under a single and multiple vertical wells system were studied using the TOUGH + hydrate + Biot simulator. Based on the available data from Shenhu area, South China Sea, the numerical models are built to characterize the distribution characteristics of hydrate. The following conclusions can be drawn from this study: 1 For depressurization with constant bottom-hole pressure in a single vertical well, gas production is relatively stable in a mild production pressure. However, water production increases to approach stability in the later stage. The evolution of seafloor subsidence can be divided into the initial quick drop stage and the later stage of slow subsidence with a decreasing rate. The shift of the subsidence mainly relates to the stable pore pressure distribution. The vertical 447

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

Fig. 12. Spatial distribution of (a) and (b) vertical displacement, (c) and (d) pore pressure, (e) and (f) hydrate saturation after 15 years under the well spacings of 50 m and 20 m, respectively.

Fig. 13. (a) Evolution of vertical displacement at seafloor (at x = 5100 m, y = 5000 m, z = 0 m), (b) vertical displacement along the wellbore and (c) lateral displacement (movement towards the well is positive) at a 50 m distance from well (the intersecting line of plane x = 4600 m and y = 4450 m) after 15 years.

448

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

displacement is significantly developed at the top and bottom of the production zone. By decreasing the production pressure, the percentage increase in water production and subsidence exceeds that in gas production. 2 . For a multiple vertical well system with 100 m spacing and 8 MPa of bottom-hole pressure, the gas and water production and seafloor subsidence increase with the number of production wells. The well interference of pore pressure is relatively weak for 100 m spacing. However, the superimposition of subsidence is heavily occurred along the line connecting the vertical wells. The largest vertical displacement is developed above the top or below the bottom of production zone, which differs from that in a single vertical well system. 3 . A smaller well spacing causes a strong well interference of pore pressure, while the gas production decreases and water production changes insignificantly, because of the increase in effective permeability after hydrate dissociation and the reduced amount of hydrate between the wells. Moreover, the effect of superposition of subsidence and subsidence itself increase. With further decreasing well spacing, a nearly same seafloor subsidence may be obtained. However, the evolution of subsidence exhibits a similar trend and differs in the later stage. The hydrate dissociation and the decrease in sediment strength contribute to the evolution of subsidence. The subsidence for a smaller well spacing develops more above the top of HBS and below the bottom of HBS. Furthermore, the well spacing affects highly the lateral moment, and the migration potential of sand particles toward the production interval may increases.

Klinkenberg b factor accounting for gas slippage effects mass diffusion of component in phase [kg/(m2·s)] specific heat of rock grain [J/(kg·°C)] internal energy of phase [J/kg] average thermal conductivity of grid [W/(K·m)] T temperature [°C] h specific enthalpy of phase [J/kg] QH mass change of hydrate component under kinetic dissociation UH specific enthalpy of hydrate dissociation/formation G shear modulus [Pa] K bulk modulus [Pa] v Poisson ratio [-] wl displacement, l = x , y , z [m] Pa Averaged pressure [Pa] Thermal expansion [1/K] T effective stress l = x , y , z [Pa] l normal strain l = x , y , z [-] l shear stress l = xy, yz , zx [Pa] l shear strain l = xy, yz , zx [-] l Rock weight with saturated fluid kg/(m2·s2) sat c cohesion [Pa] internal friction angle [°] Superscripts

bslippage J CR U

Subscripts

References Chen, F., Zhou, Y., Su, X., Liu, G., Lu, H., Wang, J., 2011. Gas hydrate saturation and its relation with grain size of the hydrate-bearing sediments in the Shenhu area of northern South China Sea. Mar. Geol. Quat. Geol. 31, 95–100. Collett, T., Bahk, J.-J., Frye, M., Goldberg, D., Husebo, J., Koh, C., Malone, M., Shipp, C., Torres, M., 2013. Historical Methane Hydrate Project Review. pp. 187 Washington D.C. Gupta, S., Deusner, C., Haeckel, M., Helmig, R., Wohlmuth, B., 2017. Testing a thermochemo-hydro-geomechanical model for gas hydrate-bearing sediments using triaxial compression laboratory experiments. Geochem. Geophys. Geosyst. 18, 3419–3437. Gupta, S., Helmig, R., Wohlmuth, B., 2015. Non-isothermal, multi-phase, multi-component flows through deformable methane hydrate reservoirs. Comput. Geosci. 19, 1063–1088. Huang, L., Su, Z., Wu, N.-Y., 2015. Evaluation on the gas production potential of different lithological hydrate accumulations in marine environment. Energy 91, 782–798. Hyodo, M., Li, Y., Yoneda, J., Nakata, Y., Yoshimoto, N., Nishimura, A., 2014. Effects of dissociation on the shear strength and deformation behavior of methane hydratebearing sediments. Mar. Petrol. Geol. 51, 52–62. Jang, J., Dai, S., Yoneda, J., Waite, W.F., Stern, L.A., Boze, L.-G., Collett, T.S., Kumar, P., 2018. Pressure core analysis of geomechanical and fluid flow properties of seals associated with gas hydrate-bearing reservoirs in the Krishna-Godavari Basin, offshore India. Mar. Petrol. Geol (in press). https://doi.org/10.1016/j.marpetgeo.2018.1008. 1015. Jin, G., Lei, H., Xu, T., Xin, X., Yuan, Y., Xia, Y., Huo, J., 2018. Simulated geomechanical responses to marine methane hydrate recovery using horizontal wells in the Shenhu area, South China Sea. Mar. Petrol. Geol. 92, 424–436. Jin, G., Xu, T., Xin, X., Wei, M., Liu, C., 2016. Numerical evaluation of the methane production from unconfined gas hydrate-bearing sediment by thermal stimulation and depressurization in Shenhu area, South China Sea. J. Nat. Gas Sci. Eng. 33, 497–508. Kimoto, S., Oka, F., Fushita, T., 2010. A chemo–thermo–mechanically coupled analysis of ground deformation induced by gas hydrate dissociation. Int. J. Mech. Sci. 52, 365–376. Klar, A., Soga, K., Ng, M.Y.A., 2010. Coupled deformation–flow analysis for methane hydrate extraction. Geotechnique 60, 765–776. Klauda, J.B., Sandler, S.I., 2005. Global distribution of methane hydrate in ocean sediment. Energy Fuels 19, 459–470. Konno, Y., Fujii, T., Sato, A., Akamine, K., Naiki, M., Masuda, Y., Yamamoto, K., Nagao, J., 2017. Key findings of the world's first offshore methane hydrate production test off the coast of Japan: toward future commercial production. Energy Fuels 31, 2607–2616. Lei, H., Xu, T., Jin, G., 2015. TOUGH2Biot – a simulator for coupled thermal–hydrodynamic–mechanical processes in subsurface flow systems: application to CO2 geological storage and geothermal development. Comput. Geosci. 77, 8–19. Li, G., Moridis, G.J., Zhang, K., Li, X.-s., 2011. The use of huff and puff method in a single

Acknowledgements This work is jointly supported by the National Natural Science Foundation of China (41602255, 41776071), the National Key Research and Development Program of China (2017YFC0307304), and the Foundation of Chinese Academy of Sciences Key Laboratory of Gas Hydrate (y807jd1001, y807je1001). Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.marpetgeo.2019.05.008. Nomenclature

t S

X k kr µ P g

,

R

= w, i , g is water, salt and gas, respectively

Phase, = A, G, H , I is aqueous, gas, hydrate and ice phase, respectively

The range of problems concerning the processes of gas recovery from HBS is very broad. The present modeling results are specific to the conditions and parameters considered. The “numerical experiments” do give a detailed understanding of the dynamic evolution, and provide useful insight into hydrate dissociation, multi-phase fluid flow, geomechanics and seafloor subsidence processes in single and multiple well system.

M F q V

component,

mass or energy accumulation [kg/m3 or J/m3] flux of mass or energy of component [kg/(m2· s)] sink/source volume [m3] surface area [m2] time [s] porosity [-] saturation of phase [-] density of phase or rock grain [kg/m3] mass fraction of component in phase [-] permeability [m2] relative permeability of phase [-] viscosity of phase [Pa·s] pressure of phase [Pa] gravitational acceleration vector 449

Marine and Petroleum Geology 107 (2019) 438–450

G. Jin, et al.

hydrate of the first experimental exploitation region in the Shenhu area, northern South China sea. J. Asian Earth Sci. 168, 57–76. Su, Z., Moridis, G.J., Zhang, K., Wu, N., 2012. A huff-and-puff production of gas hydrate deposits in Shenhu area of South China Sea through a vertical well. J. Petrol. Sci. Eng. 86–87, 54–61. Sun, J., Zhang, L., Ning, F., Lei, H., Liu, T., Hu, G., Lu, H., Lu, J., Liu, C., Jiang, G., Liang, J., Wu, N., 2017. 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. 86, 447–473. Sun, X., Luo, H., Luo, T., Song, Y., Li, Y., 2019a. Numerical study of gas production from marine hydrate formations considering soil compression and hydrate dissociation due to depressurization. Mar. Petrol. Geol. 102, 759–774. Sun, X., Wang, L., Luo, H., Song, Y., Li, Y., 2019b. Numerical modeling for the mechanical behavior of marine gas hydrate-bearing sediments during hydrate production by depressurization. J. Petrol. Sci. Eng. 177, 971–982. Sun, Y., Li, B., Guo, W., Lü, X., Zhang, Y., Li, K., Wang, P., Jin, G., Jia, R., Qu, L., 2014. Comparative analysis of the production trial and numerical simulations of gas production from multilayer hydrate deposits in the Qilian Mountain permafrost. J. Nat. Gas Sci. Eng. 21, 456–466. Uchida, S., Klar, A., Yamamoto, K., 2016. Sand Production Modeling of the 2013 Nankai Offshore Gas Production Test, Energy Geotechnics. CRC Press, pp. 451–458. Wang, X., Collett, T.S., Lee, M.W., Yang, S., Guo, Y., Wu, S., 2014. Geological controls on the occurrence of gas hydrate from core, downhole log, and seismic data in the Shenhu area, South China Sea. Mar. Geol. 357, 272–292. Wu, N., Zhang, H., Yang, S., Zhang, G., Liang, J., Lu, J., Su, X., Schultheiss, P., Holland, M., Zhu, Y., 2011. Gas hydrate system of Shenhu area, northern South China Sea: geochemical results. J. Geol. Res 2011. Wu, Z., Li, Y., Sun, X., Li, M., Jia, R., 2018a. Experimental study on the gas phase permeability of montmorillonite sediments in the presence of hydrates. Mar. Petrol. Geol. 91, 373–380. Wu, Z., Li, Y., Sun, X., Wu, P., Zheng, J., 2018b. Experimental study on the effect of methane hydrate decomposition on gas phase permeability of clayey sediments. Appl. Energy 230, 1304–1310. Yamamoto, K., 2015. Overview and introduction: pressure core-sampling and analyses in the 2012–2013 MH21 offshore test of gas production from methane hydrates in the eastern Nankai Trough. Mar. Petrol. Geol. 66 (2), 296–309. Yamamoto, K., Kanno, T., Wang, X.X., Tamaki, M., Fujii, T., Chee, S.S., Wang, X.W., Pimenov, V., Shako, V., 2017. Thermal responses of a gas hydrate-bearing sediment to a depressurization operation. RSC Adv. 7, 5554–5577. Yang, L., Ai, L., Xue, K., Ling, Z., Li, Y., 2018. Analyzing the effects of inhomogeneity on the permeability of porous media containing methane hydrates through pore network models combined with CT observation. Energy 163, 27–37. the GMGS4 Science TeamYang, S., Liang, J., Lei, Y., Gong, Y., Xu, H., Wang, H., Lu, J., Melanie, H., Peter, S., Wei, J., 2017. GMGS4 gas hydrate drilling expedition in the South China sea. Fire Ice 17, 7–11. Yoneda, J., Masui, A., Konno, Y., Jin, Y., Egawa, K., Kida, M., Ito, T., Nagao, J., Tenma, N., 2015. Mechanical behavior of hydrate-bearing pressure-core sediments visualized under triaxial compression. Mar. Petrol. Geol. 66 (2), 451–459. Yoneda, J., Masui, A., Konno, Y., Jin, Y., Kida, M., Katagiri, J., Nagao, J., Tenma, N., 2017. Pressure-core-based reservoir characterization for geomechanics: insights from gas hydrate drilling during 2012–2013 at the eastern Nankai Trough. Mar. Petrol. Geol. 86, 1–16. Yoneda, Y., Oshima, M., Kida, M., Kato, A., Konno, Y., Jin, Y., Tenma, N., Waite, W., Jang, J., 2018. Pressure core based analysis of mechanical properties of hydrate-bearing sediments recovered during India's India National Gas Hydrate Program Expedition, NGHP-02. Mar. Petrol. Geol (in press). https://doi.org/10.1016/j.marpetgeo.2018. 1009.1005. Yuan, Y., Xu, T., Xia, Y., Xin, X., 2018. Effects of formation dip on gas production from unconfined marine hydrate-bearing sediments through depressurization. Geofluids 11 2018. Zhang, K., Moridis, G.J., Wu, N., Li, X., Reagan, M.T., 2010. Evaluation of alternative horizontal well designs for gas production from hydrate deposits in the Shenhu area, South China sea. In: International Oil and Gas Conference and Exhibition in China. Society of Petroleum Engineers, Beijing, China, pp. 8–10. Zhang, X.H., Lu, X.B., Shi, Y.H., Xia, Z., 2015. Study on the mechanical properties of hydrate-bearing silty clay. Mar. Petrol. Geol. 67, 72–80. Zhou, M., Soga, K., Xu, E., Uchida, S., Yamamoto, K., 2014. Numerical study on eastern Nankai Trough gas hydrate production test. In: Offshore Technology Conference.

horizontal well in gas production from marine gas hydrate deposits in the Shenhu Area of South China Sea. J. Petrol. Sci. Eng. 77, 49–68. Li, J.-f., Ye, J.-l., Qin, X.-w., Qiu, H.-j., Wu, N.-y., Lu, H.-l., Xie, W.-w., Lu, J.-a., Peng, F., Xu, Z.-q., Lu, C., Kuang, Z.-g., Wei, J.-g., Liang, Q.-y., Lu, H.-f., Kou, B.-b., 2018. The first offshore natural gas hydrate production test in South China Sea. China Geol. 1, 5–16. Li, X.-S., Xu, C.-G., Zhang, Y., Ruan, X.-K., Li, G., Wang, Y., 2016a. Investigation into gas production from natural gas hydrate: a review. Appl. Energy 172, 286–322. Li, Y., Liu, W., Zhu, Y., Chen, Y., Song, Y., Li, Q., 2016b. Mechanical behaviors of permafrost-associated methane hydrate-bearing sediments under different mining methods. Appl. Energy 162, 1627–1632. Lin, J.-S., Uchida, S., Myshakin, E.M., Seol, Y., Rutqvist, J., Boswell, R., 2018. Assessing the geomechanical stability of interbedded hydrate-bearing sediments under gas production by depressurization at NGHP-02 Site 16. Mar. Petrol. Geol (in press). https://doi.org/10.1016/j.marpetgeo.2018.1008.1018. Liu, C., Meng, Q., He, X., Li, C., Ye, Y., Lu, Z., Zhu, Y., Li, Y., Liang, J., 2015a. Comparison of the characteristics for natural gas hydrate recovered from marine and terrestrial areas in China. J. Geochem. Explor. 152, 67–74. Liu, C., Meng, Q., He, X., Li, C., Ye, Y., Zhang, G., Liang, J., 2015b. Characterization of natural gas hydrate recovered from Pearl River Mouth Basin in South China sea. Mar. Petrol. Geol. 61, 14–21. Liu, C., Ye, Y., Meng, Q., He, X., Lu, H., Zhang, J., Liu, J., Yang, S., 2012. The characteristics of gas hydrates recovered from Shenhu area in the South China sea. Mar. Geol. 307–310, 22–27. Liu, Z., Dai, S., Ning, F., Peng, L., Wei, H., Wei, C., 2018. Strength estimation for hydratebearing sediments from direct shear tests of hydrate-bearing sand and silt. Geophys. Res. Lett. 45, 715–723. Luo, T., Song, Y., Zhu, Y., Liu, W., Liu, Y., Li, Y., Wu, Z., 2016. Triaxial experiments on the mechanical properties of hydrate-bearing marine sediments of South China Sea. Mar. Petrol. Geol. 77, 507–514. Masui, A., Miyazaki, K., Haneda, H., Ogata, Y., Aoki, K., 2008. Mechanical characteristics of natural and artificial gas hydrate bearing sediments. In: The 6th International Conference on Gas Hydrates. The 6th International Conference on Gas Hydrates, (Vancouver, British Columbia, Canada). Max, M.D., Johnson, A.H., 2014. Hydrate petroleum system approach to natural gas hydrate exploration. Petrol. Geosci. 20, 187–199. Max, M.D., Johnson, A.H., Dillon, W.P., 2005. Economic Geology of Natural Gas Hydrate. Springer Science & Business Media. Milkov, A.V., 2004. Global estimates of hydrate-bound gas in marine sediments: how much is really out there? Earth Sci. Rev. 66, 183–197. Miyazaki, K., Masui, A., Aoki, K., Sakamoto, Y., Yamaguchi, T., Okubo, S., 2010. Strainrate dependence of triaxial compressive strength of artificial methane-hydrate–bearing sediment. Int. Soc. J. Offshore Polar Eng. 20, 256. Miyazaki, K., Masui, A., Sakamoto, Y., Aoki, K., Tenma, N., Yamaguchi, T., 2011. Triaxial compressive properties of artificial methane‐hydrate‐bearing sediment. J. Geophys. Res. Solid Earth 116. Moridis, G.J., Kowalsky, M.R., Preuess, K., 2008. TOUGH+HYDRATE v1.0 User's Manual: A Code for the Simulation of System Behavior in Hydrate-Bearing Geological Media, Repoet LBNL-00149E. Lawrence Berkeley National Laboratory, Berkeley, CA, USA. Moridis, G.J., Quieruga, A.F., Reagan, M.T., 2017. The T+H+M code for the analysis of coupled flow, thermal, chemical and geomechanical processes in hydrate-bearing geologic media. In: Kon, C., Sloan, D., Collett, T. (Eds.), The 9th International Conference on Gas Hydrate, (Denver, Colorado, USA). Moridis, G.J., Reagan, M.T., Boyle, K.L., Zhang, K., 2011. Evaluation of the gas production potential of some particularly challenging types of oceanic hydrate deposits. Transport Porous Media 90, 269–299. Moridis, G.J., Reagan, M.T., Queiruga, A.F., Boswell, R., 2018. Evaluation of the performance of the oceanic hydrate accumulation at site NGHP-02-09 in the KrishnaGodavari Basin during a production test and during single and multi-well production scenarios. Mar. Petrol. Geol (In pressure). https://doi.org/10.1016/j.marpetgeo. 2018.1012.1001. Rutqvist, J., 2017. An overview of TOUGH-based geomechanics models. Comput. Geosci. 108, 56–63. Rutqvist, J., Moridis, G.J., Grover, T., Silpngarmlert, S., Collett, T.S., Holdich, S.A., 2012. Coupled multiphase fluid flow and wellbore stability analysis associated with gas production from oceanic hydrate-bearing sediments. J. Petrol. Sci. Eng. 92–93, 65–81. Su, P., Liang, J., Peng, J., Zhang, W., Xu, J., 2018. Petroleum systems modeling on gas

450