Numerical Study of the Gas Production Enhancement Effect of Boundary Sealing and Wellbore Heating for Class 1 Hydrate Reservoir Depressurization with Five-Spot Wells

Abstract

Natural gas hydrates (NGHs) are a promising alternative energy source with huge global reserves, but they face significant challenges in commercial production and require more efficient exploitation methods. Based on field data from China’s first offshore NGH pilot production, this study systematically investigates the enhancement effect of boundary sealing and wellbore heating on the development of Class 1 hydrate reservoirs with five-spot wells. Numerical simulation findings illustrate that when the sealing layer thickness is 1 m and the permeability is 0.001 mD, it can effectively expand the radial propagation of pressure, promote the gas output, and significantly reduce water production. When the heating power is 100 W/m, the highest energy efficiency ratio can be achieved, which can promote dissociation and inhibit the secondary hydrate generation. The combination of two technologies shows a synergistic effect, which increases the cumulative gas production and gas-to-water ratio to 197.4% and 224.3% of the base case, respectively, achieving the optimal balance between high recovery rate and economic efficiency, which provides key insights for the effective development of Class 1 hydrate reservoirs.

1. Introduction

Natural gas hydrates (NGHs) are a compact crystalline substance composed of water and gas molecules under low-temperature, high-pressure environments. It is found extensively in the deep-sea, deep lake sediments, and permafrost areas on land [1,2]. It is estimated that there are approximately 10¹⁵–10¹⁸ m³ of CH₄ in the global NGH resources. As a highly promising alternative energy source, the strategic value of NGHs in the energy sector is becoming increasingly prominent [1,2,3,4]. The recent offshore NGH test conducted by China and Japan has confirmed the recoverability of this emerging resource, but the trial production results are far from commercial production capacity [5,6,7,8]. How to significantly increase gas production is currently a research hotspot. It is generally recognized that the depressurization method and its derivative improvement schemes are the optimal path to promote the industrial exploitation of marine hydrates. The production enhancement technologies mainly include complex structured wells (horizontal wells, multilateral wells, well-net, etc.), new mining methods like depressurization assisted with thermal stimulation, and a range of reservoir stimulation methods, including hydraulic fracturing, near-wellbore stimulation, etc. The mechanisms of these technologies include improving the drainage area, enhancing the efficiency of hydrate dissociation, and optimizing reservoir flow conditions [9,10].

Boundary sealing, as one of the important directions for reservoir stimulation, has received increasing attention in recent years. The primary principle is to manually reduce the permeability of the sealing layers, thereby preventing water invasion and improving pressure propagation. Zhao et al. (2020) [11] proposed forming artificial impermeable barriers via gel injection into sealing layers to improve the recovery rate of the Shenhu NGH reservoir. Numerical simulations showed that the barriers prevented water invasion and enhanced the depressurization effect; the hydrate dissociation degree increased by 36.5%, gas production increased 137.2%, and the water production decreased by 74.5%. Li et al. (2021) [12] proposed a novel approach integrating hydraulic fracturing with sealing layers to boost gas production. Numerical simulation results demonstrate that when sealing lengths exceed the fracturing radial length, this approach boosts gas production by 93.2% and reduces water production by 62.9%. Lv et al. (2022) [13] analyzed the adaptability of artificial barriers to depressurization production in vertical wells and found that artificial barriers can reduce cumulative water production by 20.88% and improve the gas-to-water ratio. Wang et al. (2024) [14] studied the effect of boundary sealing on the development of NGHs through horizontal wells combined with thermal injection. Numerical simulations revealed that the boundary sealing inhibited water invasion, resulting in an increase of 22.0~30.1% in hydrate dissociation and 63.9~85.1% in gas production efficiency, respectively. Nie et al. (2024) [15] put forward an innovative approach integrating boundary sealing and hot water injection. Numerical results showed their combination achieved a synergistic effect; Compared with three-spot horizontal well patterns, the five-spot horizontal well pattern reduced the production cycle by 680 days and improved the gas-to-water ratio by 17%. Guo et al. (2024) [16] evaluated the yield-increasing effect of network fracturing under boundary sealing and demonstrated that boundary sealing can prevent water invasion and improve pressure propagation, resulting in an increase of 11.1 times in gas production and 13.3 times in gas-to-water ratio. Qin et al. clarified the effect of sealing layer properties and proposed optimal vertical well sealing layer parameters, including a sealing radius of 150 to 200 m, a sealing thickness of 0.5 m, and a permeability ratio of 5000 [17]. The above work proposes a combination mode of boundary sealing and other technologies, optimizes the key parameters of sealing, and promotes in-depth research on boundary sealing technology.

The above work proposes a combination mode of boundary sealing and other technologies, optimizes key parameters of sealing layers, and promotes in-depth research on boundary sealing technology. However, most of the well types involved are single vertical or single horizontal wells. There is a lack of research on the combination of well-net development modes, such as five-spot wells with boundary sealing and wellbore heating, their systematic integration and the quantitative analysis of their synergistic effect, which have great potential for large-scale exploitation of NGHs [18]. Therefore, this work established a 3D numerical model of five-spot wells, and the synergistic effect of boundary sealing and wellbore heating in the development of Class 1 hydrate reservoirs is systematically evaluated. It includes the influence of boundary sealing permeability and thickness, as well as heating power on pressure propagation. The results can provide new insights for the high-efficiency exploitation of Class 1 hydrate reservoirs.

2. Methodology

2.1. Geological Background

The SHSC4 well is located in the Shenhu area (Figure 1) [7]. The reservoir in this sea area is characterized by abundant gas supply and suitable geological and thermodynamic conditions, with a water depth of approximately 1266 m, seabed temperature around 3.0 °C, and a geothermal gradient of 43.653 °C/km [19]. The NGH reservoir system in this sea area is classified as a Class 1 NGH reservoir [20]. It can be categorized into three distinct layers: the upper Gas Hydrate-Bearing Layer (GHBL), rich in hydrate and water, occurs at 201–236 m below seafloor (mbsf) with a thickness of 35 m; the middle Three-Phase Layer (TPL), containing hydrate, high-saturation free gas, and water, is found at 236–251 mbsf and is 15 m thick; and the lower Free Gas Layer (FGL), composed of low-saturation free gas and water, extends from 251 to 278 mbsf with a thickness of 27 m [7].

2.2. Simulation Code

TOUGH + HYDRATE V1.0 combines both kinetic and equilibrium modeling approaches to characterize NGH formation and dissociation, supporting various dissociation strategies such as depressurization, thermal stimulation, salting-out effects, and inhibitor injection [22]. The simulation system incorporates four phases (gas, water, ice, and solid hydrate) and multiple components (water, methane, hydrate, and soluble inhibitors), with comprehensive phase behavior accounting for inter-phase mass transfer [22]. This code has been extensively validated against laboratory experiments and field tests [23,24]. The original version supports a maximum of 50,000 grids, limiting its applicability to large-scale field simulations. In order to improve computational efficiency, the parallel version pT + H V1.0 was used for production prediction [25]. The equilibrium model was adopted for simulating gas production under reservoir conditions [26]. The following assumptions were followed during the simulation process: Fluid migration in porous media is governed by Darcy’s law; Mechanical diffusion of dissolved gases and inhibitors is neglected; Geomechanical responses and stress coupling effects are not incorporated; The aqueous phase is assumed present in the presence of salt; Thermophysical properties of the aqueous phase are unaffected by dissolved inhibitors; Inhibitors are treated as non-volatile components. The governing equations are as follows [22]:

• Mass Conservation Equation:

$${\displaystyle \frac{d}{\mathit{dt}}}{\int }_{V_n}{M}^{\kappa }\mathit{dV}={\int }_{{\mathsf{\Gamma }}_n}{F}^{\kappa }\cdot \mathrm{n}d\mathsf{\Gamma }+{\int }_{V_n}{q}^{\kappa }\mathit{dV}$$

(1)

where M^κ is mass accumulation, F^κ denotes mass flux, and q^κ represents source/sink terms.

2.

Energy Conservation Equation:

$${\displaystyle \frac{d}{\mathit{dt}}}{\int }_{V_n}{M}^{\theta }\mathit{dV}={\int }_{{\mathsf{\Gamma }}_n}{F}^{\theta }\cdot \mathrm{n}d\mathsf{\Gamma }+{\int }_{V_n}{q}^{\theta }\mathit{dV}$$

(2)

where θ is heat component, is heat flux, M^θ, F^θ, and q^θ correspond to heat accumulation, flux, and source/sink ratio, respectively.

2.3. Model and Case Design

The schematic diagram of the model is shown in Figure 2a. The geological model spans 800 m in both the X and Y directions (Figure 2b), with a vertical extent (Z) of 137 m (Figure 2c). The domain was discretized using a structured grid system comprising 47 layers in the X-axis, 47 layers in the Y-axis, and 95 layers in the Z-axis, with a total of 209,855 grids. A local grid refinement strategy was employed, particularly in the vicinity near the wellbore, to enhance resolution in regions experiencing significant changes in physical properties during gas production. The refinement follows with varying grid sizes, including 1 m, 2 m, 4 m, 8 m, and 12 m, to accurately capture multiphase flow and heat transfer dynamics.

Eight simulation cases were established, as summarized in

Table 1. Simulation cases.

Cases	Boundary Sealing	Sealing Permeability (mD)	Sealing Thickness (m)	Heating Power (W/m)	Pressure Difference (MPa)
Case 1	No	-	-	-	4.0
Case 2	Yes	0.0001	1	-	4.0
Case 3	Yes	0.001	1	-	4.0
Case 4	Yes	0.01	1	-	4.0
Case 5	Yes	0.001	2	-	4.0
Case 6	Yes	0.001	1	100	4.0
Case 7	Yes	0.001	1	200	4.0
Case 8	Yes	0.001	1	300	4.0

. Case 1 serves as the reference case without any sealing layers. Sealing layers are located at the top of the GHBL and the bottom of the FGL. Cases 2 to 4 are designed to investigate the effect of sealing permeability, which ranges from 0.0001 to 0.01 mD, with a thickness of 1 m. Case 5 was designed to investigate the influence of sealing thickness (permeability of 0.001 mD and thickness of 2 m). Cases 6 to 8 introduce thermal stimulation by applying wellbore heating at power levels of 100 W/m, 200 W/m, and 300 W/m, respectively, with a fixed sealing configuration (permeability of 0.001 mD and thickness of 1 m).

2.4. Initial and Boundary Conditions

The model initialization begins with defining the pore water pressure. Considering the connectivity of the overlying layer, this pressure is given by the hydrostatic pressure formula [27,28,29]:

P_pw = P_atm + ρ_swg(H + Z) × 10⁻⁶

(3)

Within the formula, each parameter is defined as follows: P_pw: Porewater pressure (MPa), P_atm: Normal atmospheric pressure (MPa), ρ_sw: Average density of seawater (kg/m³), g: Gravitational acceleration (m/s²), H: Water depth (m), Z: Sediment depth from the seabed (m). Subsequently, the simulator’s self-balancing function was used to calculate a stable initial temperature and pressure profile consistent with the geothermal gradient (Figure 3) [30]. The model boundaries were set as the first type boundary [31]. The production wellbore was conceptualized as an internal boundary, and the well grids maintain a fixed pressure difference of 4.0 MPa.

Key model parameters for multiphase flow were set based on previous research. The parameters for the van Genuchten model were set as: the maximum reference water saturation (S_mxA) was assigned a value of 1.0, the irreducible water saturation (S_irA) was fixed at 0.30, the pore size distribution index (λ) was designated as 0.45, and the initial capillary pressure (P₀) was set to 1 × 10⁴ Pa. The parameters for the Stone model were set as: the irreducible water saturation (S_irA) remained consistent at 0.30, the irreducible gas saturation (S_irG) was defined as 0.03, the water-phase permeability reduction exponent (n_A) was assigned a value of 3.5, and the gas-phase permeability reduction exponent (n_G) was set to 2.5 [32,33,34].

Table 2. Basic physical properties for the model.

Parameter Type	Parameters	Value and Unit
Formation thickness	OB/UB	30 m
	GHBL	35 m
	TPL	15 m
	FGL	27 m
Initial permeability	OB/UB	2.0 mD
	GHBL	2.9 mD
	TPL	1.5 mD
	FGL	7.4 mD
Porosity	OB/UB	0.30
	GHBL	0.35
	TPL	0.33
	FGL	0.32
Initial saturation	Hydrate saturation of GHBL and TPL	cited from logging data
	Free gas saturation of FGL	cited from logging data
Multiphase flow	Capillary pressure model [32,33,34]	$P_{cap}=-P_0{[{\left(S^{*}\right)}^{-1/\lambda }-1]}^{1-\lambda }$, $S^{*}={\displaystyle \frac{(S_A-S_{irA})}{(S_{mxA}-S_{irA})}}$
	Relative permeability model [32,33,34]	KrA = [(SA − SirA)/(1 − SirA)]nA, KrG = [(SG − SirG)/(1 − SirA)]nG
	SmxA (Maximum aqueous saturation)	1
	λ (Capillary pressure exponent)	0.45
	P0 (Capillary pressure reference value)	104 Pa
	nA (Aqueous relative permeability exponent)	3.5
	nG (Gas relative permeability exponent)	2.5
	SirG (Gas irreducible saturation)	0.03
	SirA (Aqueous irreducible saturation)	0.30
Production well	Production pressure	4.0 MPa
	Wellbore radius	0.1 m
Others	Geothermal gradient	43.653 °C/km
	Grain specific heat	1000 J·kg−1·K−1
	Dry thermal conductivity	1.0 W·m−1·K−1
	Wet thermal conductivity	3.1 W·m−1·K−1
	Grain density	2600 kg/m3
	Salinity	3.5%
	Gas composition	100% CH4
	Location of sealed burdens	Top of GHBL, Bottom of FGL

specifies the physical properties of the model. The formation thicknesses are configured as follows: overburden (OB) and underburden (UB) are 30 m each, GHBL is 35 m, TPL is 15 m, and FGL is 27 m. The permeability and porosity of each layer are directly adopted from field data: GHBL has 2.9 mD and a porosity of 0.35, TPL has 1.5 mD and a porosity of 0.33, and FGL has 7.4 mD and a porosity of 0.32. The OB and UB layers follow conventional assumptions with a permeability of 2.0 mD and porosity of 0.30 [7]. Sealing layers are located at the top of the GHBL and the bottom of the FGL. Other properties include a grain density of 2600 kg/m³ and a geothermal gradient of 43.653 °C/km, and the gas composition is 100% methane.

2.5. Model Validation

To validate the numerical model, a 70 m vertical well was implemented at the model’s center, replicating the design of the production well from China’s first NGH trial production. The well was perforated from −201 to −271 mbsf and operated under a constant pressure differential of 3 MPa [35]. As shown in Figure 4, the close agreement between the simulated 60-day cumulative gas production and the field data confirms the model’s accuracy for subsequent work.

3. Results and Analysis

3.1. Gas and Water Production

Figure 5a depicts the trends of gas production rate (Q_g) and cumulative gas production (V_g) with or without boundary sealing and wellbore heating within 360 days. Under the conditions of a boundary sealing permeability of 0.001 mD, a thickness of 1 m, and heating power set to 100 W/m, the Q_g of Case 6 is significantly higher than that of Case 1 (base case). In comparison to Case 1, the V_g of Case 6 increased from 744.3 × 10⁴ to 1469.4 × 10⁴ ST m³, an increase of 197.4%. This is because when both boundary sealing and wellbore heating are used simultaneously, the boundary sealing at the top of GHBL and the bottom of FGL makes the radial propagation of pressure more uniform, thereby promoting hydrate dissociation and gas production. And wellbore heating helps to promote the dissociation of hydrates around the wellbore, while effectively preventing and eliminating secondary hydrates, ensuring smooth channels for free gas.

Figure 5b presents the variation in water production rate (Q_w) and gas-to-water ratio (R_gw) over 360 days. The trend of Q_w curves in the two cases is different from Q_g; the R_gw of the base case is only 142.6, while the case with boundary sealing and wellbore heating maintains a high R_gw during the whole production cycle. By the end of production, the Rgw reaches 319.9, which is 224.3% of the base case. The sealing layer serves to reduce water production by inhibiting water flow into the wellbore from both the top of the GHBL and the bottom of the FGL. Simulation results demonstrate that integrating boundary sealing and wellbore heating significantly improves gas output in five-spot wells.

3.2. Spatial Distribution of Reservoir Physical Parameters

3.2.1. Pore Pressure

The spatial distribution of pore pressure within 360 days is shown in Figure 6. In Case 1, the pressure gradient of the reservoir around the wellbore located in the GHBL is greater compared to the TPL and FGL. Solid hydrates in the GHBL lower its permeability, while the gas expansion effect of free gas of the TPL and FGL limits pressure propagation. Moreover, due to the lack of boundary sealing, the rapid invasion of top and bottom water into the wellbore causes the pressure propagation range to remain almost unchanged throughout the entire production period. In case 6 with boundary sealing and wellbore heating, the presence of the sealing layer greatly reduces the invasion of water, and heating accelerates the hydrates’ dissociation. The combination of the two methods maintains a more uniform distribution of pressure propagation in the reservoir. Furthermore, the area influenced by pressure around the wellbore expands over time.

3.2.2. Reservoir Temperature

The spatial distribution of reservoir temperature within 360 days is shown in Figure 7. In Case 1, a decrease in reservoir temperature near the wellbore can be observed due to the dual effects of heat absorption of hydrate dissociation and the Joule-Thomson effect caused by a large amount of free gas entering the wellbore. As production proceeds, the high-temperature bottom water gradually moves towards the bottom of the wellbore. In Case 6, with boundary sealing and wellbore heating, wellbore heating caused an increase in reservoir temperature around the wellbore. In addition, the presence of a sealing layer effectively weakens the invasion of water.

3.2.3. Hydrate and Gas Saturation

The spatial distribution of saturation of hydrates and gas within 360 days is shown in Figure 8 and Figure 9. In Case 1, the dissociation of hydrates is limited to the near-wellbore area, and the gas saturation around the wellbore is lower. The formation of secondary hydrates in the reservoir near the TPL’s wellbore is also observed in the initial production period. As production proceeds, the quantity and saturation of secondary hydrates increase. In Case 6 with boundary sealing and wellbore heating, the hydrate dissociation front is wider, and the gas saturation is higher. Wellbore heating effectively avoids the generation of secondary hydrates. The combination of boundary sealing and wellbore heating can promote more effective pressure propagation in the radial direction of the reservoir, facilitate efficient dissociation of hydrates, and maximize recovery efficiency.

4. Discussion

This work further investigated the effects of different sealing parameters, including permeability and thickness, and different heating powers on production capacity.

4.1. Effects of Boundary Sealing Parameters

Figure 10a shows the effects of different sealing parameters on gas production within 360 days. The thickness of the sealing layer in Cases 2 to 4 is 1 m, and the permeability is set to 0.0001, 0.001, and 0.01 mD, respectively. The thickness of the sealing layer in Case 5 is 2 m, and the permeability is set to 0.001 mD. The simulation results show that the V_g in cases 2 to 5 is 866.1, 863.9, 846.9, and 864.9 × 10⁴ ST m³, respectively, which is 116.3%, 116.1%, 113.7%, and 116.2% higher than Case 1. Figure 10b shows the effects of different sealing parameters on water production. Simulation results show that the R_gw of Cases 2 to 5 are 241.1, 237.9, 216.2, and 239.9, respectively, which are 169.1%, 166.8%, 151.6%, and 168.2% higher than Case 1. From the simulation results of Case 2 to Case 4, it can be concluded that as the permeability of the sealing layer increases, the V_g and R_gw both decrease. In terms of the above three sealing layer permeability settings, Case 3 performs the best. From the simulation results of Cases 3 and 5, it can be seen that as the thickness of the sealing layer increases, the V_g and R_gw both increase, but the magnitude of the change is small. In terms of the above two sealing layer thickness settings, Case 3 performs the best. This work is similar to previous research results in terms of the optimal sealing thickness and significant reduction in water production [11,17]. It is worth noting that compared with the research work of Lv et al. (2022), the multi-well system has achieved greater improvement in gas-to-water ratio [13].

4.2. Effects of Heating Power

Sealing layer parameter setting based on Case 3. Figure 11a presents the impacts of various heating powers on gas output within 360 days. The heating power of cases 6 to 8 is set to 100, 200, and 300 W/m, respectively. The simulation results show that the V_g in cases 6 to 8 is 1469.4, 1483.9, and 1492.2 × 10⁴ ST m³, respectively, which is 169.6%, 171.3%, and 172.2% higher than Case 2. Figure 11b shows the effects of different heating powers on water production. Simulation results show that the R_gw of cases 6 to 8 are 319.9, 318.8, and 317.6, respectively, which are 132.6%, 132.2%, and 131.7% higher than Case 2. From the simulation results of Case 6 to Case 8, it can be concluded that as the heating power increases, the V_g slightly increases and R_gw slightly decreases. In terms of the above three heating power settings, Case 6 performs the best.

In order to further explore the association between the increasing gas output and the extra heat demanded, a custom production efficiency index, EROI_custom, is introduced, which is defined as follows:

EROI_custom = E_O/E_I

(4)

E_O (Energy Output): Refers to the gas output increased throughout the production period multiplied by the natural gas calorific value (approximately 35.8 MJ/m³); E_I (Energy Input): Refers to the total energy consumed by wellbore heating throughout the entire production period. The EROI_custom curves corresponding to the increase in heating power from 100 to 300 W/m are shown in Figure 12. Among them, Case 6 corresponds to the optimal energy output-input ratio. Unlike the hot water injection method used by Nie et al. (2024), this work employs wellbore heating, which has a stronger inhibitory effect on the formation of secondary hydrates and is more favorable for energy output balance [15]. The custom production efficiency index quantifies this trade-off, which has been less emphasized in previous research.

4.3. Implications and Future Recommendations

Although this work confirms that the combination of boundary sealing and wellbore heating has great potential for increasing production, its engineering application and conclusion interpretation need to consider multiple limitations. At the engineering level, building an effective seal layer (such as by injecting gel, polymer, cement, etc.) faces challenges such as accurate deployment of vertical and large horizontal distances, material stability under long-term low temperature/high pressure conditions, and substantial costs [36,37,38]. At the simulation level, the current model carries several simplifying assumptions. First, it does not consider the coupling effect of geomechanics, making it impossible to evaluate the potential deformation of the formation, permeability evolution, and their impact on wellbore stability, sand production, and sealing component integrity caused by depressurization. Second, the model operates with a fixed initial salinity and does not track the dynamic changes in produced water salinity. Consequently, it cannot account for the risk of salting out effect in the vicinity of the wellbore during production [39]. In addition, the energy efficiency indicators (EROI_custom) used are simplified screening tools and do not include the full cycle energy consumption and costs of sealing construction, fluid pumping, subsea facility construction, and operation. Therefore, the optimal parameters obtained in this work (such as sealing layer permeability of 0.001 mD and heating power of 100 W/m) are only applicable to the specific geological conditions and parameter ranges simulated. To promote the on-site application of this technology, future work needs to focus on the research and development of sealing materials and process optimization, consider numerical models coupled with geomechanics and salting out effects, and conduct comprehensive technical and economic evaluations covering the entire life cycle to support site scheme design and feasibility decision-making.

5. Conclusions

Based on China’s initial NGH trial production field data, the enhancement effect of boundary sealing and wellbore heating on the gas production with five-spot wells was systematically analyzed. The research’s findings can offer theoretical support for the effective development of Class 1 NGH reservoirs in different regions. The key conclusions are summarized below:

(1)

The low-permeability sealing layer allows pressure to propagate more widely in the radial direction of the reservoir, effectively promoting the gas production. The presence of a sealing layer can effectively reduce the entry of top and bottom water into the wellbore, thereby significantly reducing water production and effectively improving the gas-to-water ratio. Under different reservoir and engineering conditions, there exists an optimal solution for the sealing parameters. In this work, it was found that a permeability of 0.001 mD and a thickness of 1 m are optimal.

(2)

Heating the wellbore can not only accelerate hydrate dissociation but also prevent the secondary hydrate formation around the wellbore located in the TPL, ensuring a smooth channel for free gas and improving overall productivity. Under different reservoir and engineering conditions, there exists an optimal solution for wellbore heating power. In this work, a thermal power of 100 W/m is optimal, and higher heating power results in lower energy efficiency ratios.

(3)

There is a synergistic effect between boundary sealing and wellbore heating. In this work, when using a boundary seal with a permeability of 0.001 mD and a thickness of 1 m, combined with a wellbore heating power of 100 W/m, the optimal balance between high gas recovery rate and economy can be achieved. Compared with the base case, the V_g and R_gw increase to 197.4% and 224.3%, respectively.