## Numerical study on gas production via a horizontal well from hydrate reservoirs with different slope angles in the South China Sea

## Abstract

It is important to study the effect of hydrate production on the physical and mechanical properties of low-permeability clayey–silty reservoirs for the large-scale exploitation of hydrate reservoirs in the South China Sea. In this study, a multiphysical-field coupling model, combined with actual exploration drilling data and the mechanical experimental data of hydrate cores in the laboratory, was established to investigate the physical and mechanical properties of low-permeability reservoirs with different slope angles during 5-year hydrate production by the depressurization method via a horizontal well. The result shows that the permeability of reservoirs severely affects gas production rate, and the maximum gas production amount of a 20-m-long horizontal well can reach 186.8 m3/day during the 5-year hydrate production. Reservoirs with smaller slope angles show higher gas production rates. The depressurization propagation and hydrate dissociation mainly develop along the direction parallel to the slope. Besides, the mean effective stress of reservoirs is concentrated in the near-wellbore area with the on-going hydrate production, and gradually decreases with the increase of the slope angle. Different from the effective stress distribution law, the total reservoir settlement amount first decreases and then increases with the increase of the slope angle. The maximum settlement of reservoirs with a 0° slope angle is up to 3.4 m, and the displacement in the near-wellbore area is as high as 2.2 m after 5 years of hydrate production. It is concluded that the pore pressure drop region of low-permeability reservoirs in the South China Sea is limited, and various slope angles further lead to differences in effective stress and strain of reservoirs during hydrate production, resulting in severe uneven settlement of reservoirs.

## Highlights

The response of hydrate reservoirs with various angle slopes to gas production is predicted.

Low permeability would limit the long-term gas recovery rates of clayey reservoirs.

Reservoirs without slope angle show the highest gas production and seabed settlement.

There is a risk of potential damage of the production wellbore during long-term gas production.

## 1 INTRODUCTION

The deep sea contains a large number of energy and mineral resources, such as oil and natural gas (Du et al., 2024; Rui, Zhang, et al., 2023). Natural gas hydrate, a new kind of deep-sea energy source, has attracted considerable attention due to their large reservoirs, wide distribution, and clean combustion (Li et al., 2010; Song, Zhu, et al., 2014). Natural gas hydrate is a white crystalline compound composed of water molecules forming a cage structure and enclosing natural gas molecules under high-pressure and low-temperature conditions (Sloan, 2003; Sloan & Kou, 2007). It is identified as one of the most promising fuel resources in the 21st century (Wang & Sun, 2018; Wu et al., 2017). It has been estimated that the carbon reserves of natural gas hydrate are more than twice that of conventional fossil fuels. The South China Sea contains abundant natural gas hydrate resources, with proven reserves of up to 70 billion tons of oil equivalent. Large-scale development and commercial utilization of natural gas hydrate resources are important to ensure energy supply and meet the demand for clean energy in China.

The primary method to exploit natural gas hydrate is breaking the hydrate phase equilibrium and dissociating it by changing the temperature and pressure conditions of hydrate reservoirs (Li, Li, et al., 2022; Li, Zhou, et al., 2022). So far, researchers have proposed the following four main development methods: depressurization, heat injection, chemical reagent injection, and CH4–CO2 replacement (Chong et al., 2016; Kamath et al., 1991). Depressurization is the most widely used method of natural gas hydrate (Tang et al., 2020). At present, all the marine natural gas hydrate trial exploitations (a total of four times) have been carried out worldwide using the method of depressurization. Among them, two trials of exploitation were accomplished via a vertical well in Japan using the depressurization method in 2013 and 2017 and the maximum production amount of natural gas is about 200 000 m3 (Zhang et al., 2017). Two trial exploitations using the depressurization method in the Shenhu area of the South China Sea were conducted in 2017 and 2020 and the daily production amount in the second trial using a horizontal well is 5.57 times that in the first trial, and the maximum gas production amount is up to 860 000 m3 (Li et al., 2018; Ye et al., 2020). The depressurization method via a horizontal well could be a promising hydrate production method in the future.

However, natural gas hydrate, different from conventional fossil fuels such as coal and oil, mainly exists in the pore space of the reservoir skeleton and plays a vital role in cementing soil particles, filling pore space, and improving sediment density (Li et al., 2011; Rui, Guo, et al., 2023). In the exploitation process using the depressurization method, hydrate dissociation would weaken the cementation and strength of sediments and lead to a large-scale migration of gas, water, and soil particles in reservoirs (Clayton et al., 2010; Li et al., 2011; Tian et al., 2023). Similar to the principle of stratum settlement caused by coal mining, hydrate reservoirs would show uneven settlement due to double-deficit effects of reservoirs' energy and material during the large-scale natural gas hydrate production. Besides, hydrate reservoirs in the South China Sea present typical characteristics, such as low permeability, clayey–silty skeleton, and a nonhorizontal seabed (Guan et al., 2019; Sultan et al., 2004; Tian et al., 2024; Wu & Wang, 2018). The deformation and settlement of low-permeability clayey–silty reservoirs would be more evident and disorderly, leading to damages such as the reservoir's settlement and wellbore instability during long-term hydrate production (Li et al., 2023, Wang et al., 2023, 2024). Therefore, it is an essential prerequisite for safe, efficient, and sustainable hydrate production in the South China Sea to study the evolution laws of physical and mechanical properties of low-permeability reservoirs during hydrate production by the depressurization method via a horizontal well.

A series of numerical simulations have been conducted to study the evolution laws of the physical and mechanical properties of reservoirs during hydrate production. Kim et al. (2017) studied the geomechanical stability of hydrate reservoirs in the Ulleung Basin of the East China Sea during hydrate production and found that most of the sediment samples are high-plasticity silty soils and show high porosity. Then, they proposed a comprehensive process for determining the model parameters and properties of the horizontal seabed based on the vast data set obtained through the Second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2). Subsequently, Kim et al. (2018) studied the reservoir's geomechanical response and wellbore stability during gas production using the above model and found that the lower bottom-hole pressure would lead to a larger pore pressure drop, and the faster the hydrate dissociation, the greater the reservoir's settlement. Merey and Sinayuc (2017) developed a cylindrical hydrate reservoir model with a radius of 250 m based on field survey data and simulated the change of gas production in reservoirs with hydrate saturation of about 50% in the Black Sea under different depressurization pressure conditions. As reported in their study, the depressurization pressure of hydrate dissociation depends on whether the clayey sediments above the upper hydrate-bearing layer are geomechanically stable and impermeable. Ghosal et al. (2018) developed a horizontal seabed hydrate reservoir model based on drilling data of the NGHP-01-19 site and analyzed the effect of changes in pressure and temperature on the gas production behaviors in a multiphase fluid system. In this way, they assessed and determined the gas production characteristics of hydrate reservoirs in the Mahanadi basin of Eastern India. The above studies have contributed to the research and development of hydrate production simulation worldwide.

With the continuous development of natural gas hydrate field research in China, a series of numerical simulations for hydrate reservoir development in the South China Sea have been conducted as well. Yin et al. (2022) established a geological model in which the water depth is 1225.2 m, and reservoirs consist of an overlying layer (207.8 m) and a hydrate-bearing layer without slope angle (45.6 m). They found that the reservoirs' compaction effect on the horizontal well is obvious with an increase in production time, which is also an important reason for the decline of gas production. Wan et al. (2018) established a horizontal seabed hydrate reservoir model with a length of 400 m and a width of 400 m to explore the strata deformation rules and influencing factors at the GMGS3-W19 site in the Shenhu area of the South China Sea during the depressurized dissociation process of natural gas hydrate using a vertical well. They reported that strata deformation occurs mainly in the early stage of depressurized dissociation, and the leading cause of settlement is the increase in effective stress. According to the drilling data in the GMGS1-SH2 site in the Shenhu area of the South China Sea, Yuan et al. (2020) and Sun, Ning, et al. (2018) generalized the model into horizontal extended strata, with a model size of 200 m × 255 m, to study the trend of strata deformation during the dissociation process of natural gas hydrate by a vertical well. They found that the leading cause of strata settlement is the increase of effective stress and the weakening of strength caused by rapid depressurization. Jin et al. (2018) used the hydrate Biot simulator to establish a system of parallel horizontal wells based on horizontal reservoirs. By studying the strata settlement characteristics at GMGS1-SH2, SH3, and SH7 sites in the Shenhu area of the South China Sea during the dissociation process of natural gas hydrate, they found that the strata settlement in the initial stage could be half of the total settlement. The above studies provide significant research reference and direction for exploring the strata settlement laws of reservoirs during hydrate production in the South China Sea.

So far, most scholars have studied the effect of natural gas hydrate dissociation on the physical and mechanical properties of the horizontal seabed. However, hydrate reservoirs in the South China Sea present nonhorizontal seabed characteristics (Wu et al., 2008; Yu et al., 2014), and the study of slope stability is also important for the realization of commercial production. He et al. (2023) constructed a three-dimensional numerical model of hydrate reservoirs with a slope angle of 14.04° based on ABAQUS software to explore the slope and wellbore deformation driven by hydrate dissociation within a subsea environment. It was found that hydrate production in 1 year would cause a maximum displacement of up to 7 m in the wellbore and reservoirs. Zheng et al. (2023) established a geological model with a length of 2500 m, a thickness of 1200 m, and a slope angle of 15°. By studying the stability of the submarine slope during the dynamic gas production of vertical multi-wells, they revealed that the stability of submarine slope would be reduced due to hydrate dissociation. Song et al. (2019) established a substantial three-dimensional numerical model of a hydrate submarine slope with an angle of 18° to explore how the large-scale hydrate dissociation affects the stability of the submarine slope and landslides. Their study revealed that the severe reduction of hydrate-bearing sediment strength is the ultimate cause of the seabed settlement and slope instability.

However, up to date, studies on the physical and mechanical properties of low-permeability clayey–silty reservoirs during depressurization via a horizontal well are still rare. The overall slope angle of the northern continental slope in the South China Sea is approximately 2° and the secondary slopes on the continental slope that have steeper angles are about 10° (Liu et al., 2022; Wan et al., 2018; Yi et al., 2020). In fact, the influence of slope angle on reservoir settlement during hydrate production via a horizontal well has not been systematically investigated. Thus, based on reservoirs' drilling data from the GMGS3-W19 site and laboratory mechanical experiment results, this study established a multiphysical-field coupling model and conducted a numerical simulation of long-term hydrate production by the depressurization method via a horizontal well. The gas production characteristics, spatio-temporal evolution laws of settlement, and stress distribution of reservoirs with 0°, 5°, and 10° slope angles over 5 years were obtained and analyzed.

## 2 NUMERICAL MODEL

### 2.1 Model description

Natural gas hydrate production in the deep sea is a complex mass and heat transfer process involving multi-physical-field changes such as heat convection and conduction, seepage, sediment deformation, and hydrate dissociation. The following assumptions are made in this numerical model: (1) all hydrates belong to type I, which exists in the region with sufficient gas sources and suitable temperature and pressure conditions, and (2) the flow of gas and water in reservoirs conforms to Darcy's law.

*T*(temperature) by combining all energy equations and the method of eliminating heat dispersion between phases. Then, the mass conservation equation and the Kim–Bishnoi reaction kinetic model are used to describe the hydrate dissociation; the stress–strain relation constitutive model is established based on the elastic–plastic theory, and the relationship of stress–strain increment satisfies the Mohr–Coulomb criterion. Based on the above methods and previous studies (Kim et al., 1987; Yin et al., 2018), a multi-physical-field coupling model describing hydrate production is established. Hydrate dissociation, and water and gas generation rates are calculated using Equations ( 1)–( 3), respectively, and other governing equations can be found in our previous work (Sun et al., 2019).

*m*h,

*m*w, and

*m*g denote the mass sources of hydrate, water, and gas, respectively;

*R*h is Avogadro's constant;

*M*g and

*M*w represent the molar mass of gas and water, respectively; and

*t*is the time.

### 2.2 Parametric study

In marine hydrate reservoirs, the deposited natural gas hydrate would interact with soil particles to cement the skeleton and enhance the sediments' density. When the pore pressure of reservoirs is reduced and crosses the phase equilibrium value of natural gas hydrate, a mass of hydrates begins to dissociate into gas and water. Then, soil particles begin to move and rearrange due to the increase of effective stress and loss of cement, which leads to the reduction of pore space and affects the gas production, and further causes reservoir deformation and slope slide.

To analyze the effect of hydrate dissociation via a horizontal well on the deformation and stress distribution of low-permeability reservoirs with different slope angles, a two-dimensional numerical model, as shown in Figure 1, was constructed. This reservoir and wellbore model consists of four parts: the upper layer is a seawater layer with a thickness of 1273.9 m (not shown in the figure); the second layer is the overlying layer with a thickness of 135 m; the third layer is the hydrate-bearing layer with a thickness of 35 m; and the bottom layer is the underlying layer. In the horizontal direction, the slope length is 400 m, which extends to ±300 m on both sides. The horizontal well is located in the center of the hydrate-bearing layer, with a radius of 0.15 m. The reservoir slope angles are set to 0°, 5°, and 10°.

The mesh in this model is shown in Figure 2, where the *y*-axis represents the distance from sea level and the *x*-axis represents the distance from the center of the horizontal well; the same applies to Figures 4-7. The meshing method from fine to sparse is used to divide the near-wellbore area and far field. The near-wellbore area contains 14 440 element units with an average size of 0.1 m. For the far field, the mesh size is as large as hundreds of meters. The mesh size of the global model network is distributed logarithmically, and the whole element number is 17 969. The initial temperature at the top of the overlying layer is 3.75°C and the geothermal gradient is 0.045°C/m; the temperature distribution in the model is linear. Initial hydrate saturation equals 0.45 and initial porosity equals 0.33. The downhole pressure is set to 5 MPa. The phase equilibrium pressure around the wellbore is about 7 MPa. The initial pressure is equal to 14 MPa around the wellbore. All boundary conditions, except the bottom, are equal to their initial value. The wellbore pressure is reduced from 14 to 5 MPa over 12 h. The main parameters of the physical properties of reservoirs and the details of the implementation of this model have been described in our previous work (Sun et al., 2019). The main mechanical parameters of the hydrate-bearing sediment involved were obtained from our previous mechanical experimental data in the laboratory (Li et al., 2019) and previous work (Sun et al., 2019), as shown in Table 1, where the initial cohesion of sediment is 0.04 MPa and the initial elastic model of sediment is 245 MPa. The applicability and accuracy of this numerical model have been verified in previous studies (Sun et al., 2019; Sun, Luo, et al., 2018; White et al., 2020).

Parameter | Value |
---|---|

Initial cohesion of sediment c0 (MPa) |
0.04 |

Cementation correlation coefficient a |
1.86 |

Cementation correlation coefficient b |
1.00 |

Poisson's ratio of sediment v |
0.25 |

Initial elastic model of sediment E0 (MPa) |
245 |

Initial saturation of hydrate Sh0 |
0.45 |

Initial sediment porosity n0 |
0.33 |

## 3 RESULTS AND DISCUSSION

### 3.1 Gas production characteristics

As can be seen from the 5-year gas production rate curves of hydrate reservoirs with different slope angles in Figure 3, the gas production rate of hydrate reservoirs would increase rapidly in 30 days with the continuous reservoir pressure reduction. It is calculated that the maximum gas production amount of a 20-m-long horizontal well can reach 186.8 m3/day. The possible reason for this phenomenon is that the initial hydrate dissociation is less affected by the inherent permeability and thermal conductivity. Thus, with the stimulation of a high-pressure gradient, the hydrate around the wellbore dissociates rapidly. With the increase of the hydrate dissociation region, the gas production increases gradually. During the period from 30 to 360 days, the gas production rate decreases gradually and after 360 days, the gas production rate gradually stabilizes. This may be because with the decrease of pore pressure in hydrate reservoirs, the gradual decrease of the pressure gradient leads to insufficient power of hydrate dissociation. Meanwhile, hydrate dissociation is an endothermic reaction, and the heat transfer efficiency in reservoirs limits rapid hydrate dissociation to some extent. Due to the partial deformation of reservoirs surrounding the wellbore caused by the hydrate dissociation, the porosity of sediments reduces and leads to a decrease of permeability, which inhibits the distribution of the depressurization gradient and the transfer rates of gas and water, and also leads to a continuous decrease of the hydrate dissociation rate. With the continuous hydrate dissociation process, the dynamic adjustment of depressurization and heat transfer of reservoirs reaches an equilibrium state and then the hydrate dissociation rate gradually begins to stabilize.

Meanwhile, it can be found that the gas production curves of hydrate reservoirs with slope angles of 0°, 5°, and 10° are similar. This may be justified by the fact that the main difference between these three types of reservoirs is the slope angle, and this parameter may slightly influence the pore pressure drop process of reservoirs and hydrate dissociation. Besides, the gas production rate of reservoirs decreases with the increase of the slope angle, which finally stabilizes at about 17.2, 14.3, and 13.5 m3/day and is mainly governed by the final pore pressure drop rate.

### 3.2 Pore pressure and temperature distribution

As shown in Figure 4, as the depressurization continues, the pore pressure drop region spreads from the near-wellbore area to the far field. This region transforms from a circular to irregular oval shape (more widely distributed parallel to the slope). This may be due to the combined effect of effective permeability of reservoirs and gravity gradients. Due to the abundant water supply at the top area of reservoirs and the higher pore pressure at the bottom area, the spread of depressurization tends to occur toward both sides of reservoirs. Besides, the maximum pore pressure drop area of reservoirs is concentrated in the near-wellbore area. It can be observed that the radius of the pore pressure drop region reaching the predetermined 5 MPa during the 5 years is only about 10 m under low-permeability conditions, indicating that the depressurization propagation is mainly limited by the low effective permeability.

The slope angle has a significant influence on the depressurization propagation. It can be found that the pore pressure drop region and the amplitude of reservoirs with a 0° slope angle are more obvious than those of other reservoirs, especially for the pore pressure drop region of 12 MPa (light yellow area). The radius of the pore pressure drop region of 11 MPa reaches 50 m and that of 5 MPa is about 10 m. With the increase of the slope angle, the pore pressure drop region gradually decreases. For reservoirs with a slope angle of 10°, the radius of the pore pressure drop region of 11 MPa is about 39 m and that of 5 MPa is about 8.3 m. This may be due to the fact that the depressurization in reservoirs preferentially propagates to the area with lower pore pressure, which can be confirmed by the larger pore pressure drop region in reservoirs above the wellbore. As the slope angle increases, the pore pressure distribution in reservoirs with the same length also changes. The pore pressure increases with the increase of length, affecting the direction of depressurization propagation. Moreover, the propagation in hydrate reservoirs extends to the upper left corner, which can be obviously observed in hydrate reservoirs with 5° and 10° slope angles. Meanwhile, the increase of the slope angle in reservoirs leads to the increase of the gravity gradient to a certain extent, which makes hydrate dissociation and migration of fluid more difficult and then reduces the depressurization propagation to a certain extent.

As shown in Figure 5, hydrate dissociation leads to continuous temperature drop in the region where it occurs. The higher the amount of hydrate dissociation, the lower the temperature in the dissociation area. For instance, the temperature drop in the near-wellbore area is most apparent, ranging from 283 to 280 K over the 5 years. Meanwhile, it can be found that the temperature drop region is similar to the hydrate dissociation region (where the pore pressure is lower than the phase equilibrium value of natural gas hydrate), which proves that the hydrate dissociation mainly drives the temperature drop of reservoirs. Interestingly, as the gas production continues, the lower wellbore area experiences a temperature rebound in the 3rd year. The possible reason is that with the gradual stability of the heat required for hydrate dissociation, the temperature of hydrate reservoirs will increase according to the geothermal gradient, especially for the area below the wellbore, where hydrate dissociation is relatively insufficient.

From the perspective of the temperature drop region in hydrate reservoirs with different slope angles, the influence of slope angle on reservoirs' temperature is not apparent, which may be governed by the combined action of heat absorption, fluid heat transfer, and heat conduction of hydrate dissociation. The temperature distribution of reservoirs with relatively similar total amounts of hydrate dissociation will be similar. This phenomenon is also consistent with that of the above gas production results.

### 3.3 Mean effective stress and displacement field distribution

Figure 6 shows the mean effective stress distribution of hydrate reservoirs with different slope angles during the 5 years. The initial effective stress of reservoirs is calculated by the initial force balance and boundary conditions. With continuous hydrate production, the mean effective stress in the near-wellbore area rapidly increases and shows a circular distribution, while the overall stress change area presents an oval shape, which is similar to the pore pressure distribution. With further development of hydrate production, stress relaxation occurs obviously in the wellbore-edge area, while the effective stress in the rest of the near-wellbore area and the far field area continues to increase. This may be because the decrease of the initial pore pressure leads to an increase of effective stress in the near-wellbore area. Specifically, as depressurization propagation and hydrate dissociation proceed, the pore pressure drop region in reservoirs also becomes increasingly extensive, leading to severe stress concentration in some areas near the wellbore. The stress relaxation phenomenon occurs in the wellbore-edge area due to the stress redistribution. Overall, the pore pressure of hydrate reservoirs continuously decreases, and the reservoir deformation leads to stress concentration in the pore pressure drop region. In other words, the mean effective stress continuously increases.

It can be found that the mean effective stress distribution shows a significant difference in different directions for all hydrate reservoirs. The mean effective stress at the top and bottom areas in the hydrate dissociation region is lower than that on both sides. The possible reason for this phenomenon is that the compaction effect caused by depressurization and gravity enhances the density of the top and bottom areas in the hydrate dissociation region, which laterally shears the sediments on both sides and finally leads to the increase of effective stress on both sides of the hydrate dissociation region. However, the uneven distribution of the mean effective stress in the horizontal direction of the wellbore would have a particular impact on the safety of the wellbore. Besides, it can be observed that the effective stress distribution area in reservoirs gradually decreases with the increase of the slope angle, which is closely related to the pore pressure drop region.

Figure 7 shows the displacement field distribution of hydrate reservoirs with different slope angles during the 5 years. As the depressurization propagation and hydrate dissociation proceed, the reservoirs' strain continues to increase. During the 5-year natural gas production, large-scale strain occurs in whole hydrate reservoirs, and the strain variable gradually increases from the bottom area to the top area, which would be mainly caused by the reservoirs' stress relaxation. From the perspective of the whole slope, the overlying layer above the horizontal well has a local uneven settlement with a maximum amount of 3.4 m, which proves that the slope is unstable in the 5 years of natural gas production. Meanwhile, it can be observed that the displacement in the near-wellbore area is about 2.2 m, indicating that with continuous hydrate production, the reservoirs near the wellbore may move down about 2.2 m, which is far more than the radius of the wellbore of 0.15 m. Therefore, long-term hydrate production would cause large-scale settlement in the near-wellbore area, which may bend the wellbore and then severely affect the stability of the horizontal well.

When the slope angle increases, the maximum strain of reservoirs is not concentrated in the overlying layer, but mainly occurs in the near-wellbore area. From Figure 7d–f, it can be observed that the settlement in the near-wellbore area of reservoirs with 0°, 5°, and 10° slope angles is approximately 2.20, 1.92, and 2.04 m, respectively, after 5 years of continuous hydrate production. The settlement first decreases and then increases with the increase of the slope angle. The possible reasons for this phenomenon are as follows: on the one hand, with the increase of the slope angle, the daily and maximum gas production of reservoirs gradually decrease and the pore pressure drop region also gradually reduces, which leads to a decrease of the hydrate dissociation region and the strain of hydrate reservoirs. On the other hand, with the increase of the slope angle, the instability of hydrate reservoirs gradually increases and the possibility of slope sliding increases with the increase of the slope angle. Therefore, even though the daily and maximum gas production gradually decrease, the maximum settlement in the near-wellbore area of reservoirs would gradually increase with further increase of the slope angle.

Therefore, when the horizontal well is used for large-scale and long-term natural gas production, the relationships between gas production, slope safety, and reservoir settlement should be specifically considered, and specific casing and wellbore treatments should be comprehensively conducted so as to improve the stability of the horizontal well.

## 4 CONCLUSION

1.

The gas production amount of reservoirs first increases and then decreases and finally begins to stabilize, and the maximum gas production amount of a 20-m-long horizontal well can reach 186.8 m3/day during 5-year hydrate production. The gas production amount decreases with the increase of the reservoir's slope angle. The effecitve permeability of reservoirs markedly affects the gas production, and the gas production of low-permeability reservoirs is relatively low.

2.

Depressurization propagation and hydrate dissociation mainly develop along the direction parallel to the slope. Due to the low permeability of reservoirs, the pore pressure drop region over 5 years is limited, and the radius of the pore pressure drop region of 5 MPa is about 10 m. The larger the slope angle, the more limited the pore pressure drop region and the smaller the temperature drop region.

3.

The mean effective stress of reservoirs is concentrated in the near-wellbore area with on-going hydrate production, while the stress relaxation occurs in the far field. For reservoirs with slope angles, the effective stress concentration first occurs and then stress relaxation occurs after 3 years in the near-wellbore area. The effective stress distribution area in reservoirs gradually decreases with the increase of the slope angle.

4.

Long-term hydrate production would result in obvious strain and uneven seabed settlement in reservoirs. After 5 years of hydrate production, the displacement in the near-wellbore area of reservoirs with 0°, 5°, and 10° slope angles is approximately 2.20, 1.92, and 2.04 m, respectively. This is much larger than the radius of the wellbore of 0.15 m and thus adversely affects the stability of the horizontal well.

## ACKNOWLEDGMENTS

This study was supported by the National Natural Science Foundation of China (Grant No. 42106210).

## CONFLICT OF INTEREST STATEMENT

The authors declare no conflict of interest.

## Biography

Jianlin Song is pursuing his master's degree at the School of Mechanics and Civil Engineering, China University of Mining and Technology (Xuzhou, Jiangsu Province), majoring in Geotechnical Engineering. He is mainly engaged in research on natural gas hydrate production. He participated in one National Natural Science Foundation of China (42106210) and one Natural Science Foundation of Jiangsu Province (BK20200653).