Numerical Simulation of Secondary Hydrate Formation Characteristics and Effectiveness of Prevention Methods

Abstract

The exploitation of natural gas hydrates by the pressure reduction method is affected by the decomposition heat absorption effect, and the range of the formation temperature reduction area is expanding. At the same time, the temperature reduction phenomenon is more significant around the production wells under the influence of gas throttling and expansion effects, and hydrate formation will occur under certain temperature and pressure conditions, leading to blockage of effective seepage channels in the reservoir in the region and elevation of seepage resistance, which may affect the output of hydrate decomposition gas. A numerical simulation model is constructed for the purpose of studying the secondary hydrate generation pattern around the well, analyzing the impact of secondary hydrates around wells on the production capacity, and assessing the effectiveness of prevention methods to inform the actual production of hydrates. The results demonstrate that secondary hydrate is typically formed in the near-well area of the upper part of the production well, and the secondary hydrate around the upper part of the production well is the first to be formed, exhibiting the highest saturation peak and the latest decomposition. The formation of the secondary hydrate can be predicted based on the observed change in temperature and pressure, and the rate of secondary hydrate formation is markedly rapid, whereas the decomposition rate, approximately 0.285 mole/d, is relatively slow. Additionally, the impact of secondary hydrates on cumulative gas production is insignificant, and the effect of secondary hydrates on capacity can be ignored. Hot water injection, wellbore heating, and reservoir reconstruction can effectively eliminate secondary hydrates around the well. Reservoir reconstruction represents a superior approach to the elimination of secondary hydrates, which can effectively enhance production capacity while preventing the generation of secondary hydrates.

1. Introduction

Natural gas hydrates are composed of cage-like structures formed by the combination of water molecules and gas molecules [1]. Due to their ice-like appearance and combustibility, natural gas hydrates are also commonly known as ‘combustible ice.’ Natural gas hydrates are predominantly found in marine sediments at water depths exceeding 300 m. Examples of such locations include the Black Sea, the South China Sea Trough of Japan, the Pearl River Estuary Basin, and the Qiongdongnan Basin of China [2,3,4,5,6,7,8,9,10,11,12,13]. Furthermore, natural gas hydrate possesses a high energy density. Under standard conditions, the decomposition of one cubic meter of hydrate can yield approximately 164 cubic meters of natural gas. Currently, the estimated global natural gas hydrate resources are approximately 2 × 10¹⁶ m³, which is equivalent to 2 × 10¹³ t of oil equivalent. This is approximately 40 times more than the conventional natural gas resources [14,15,16,17,18].

Due to the above characteristics, natural gas hydrate has emerged as a novel type of alternative energy source, with countries competing to conduct research on it. Some governments and enterprises have designated the industrialized exploitation of natural gas hydrate as a stage of scientific research and have set research objectives in this regard. A number of countries, including the United States and China, have carried out hydrate production trials, which have significantly advanced the commercialization of hydrates, particularly the hydrate production trial conducted by China in 2020, which established a new world record for average daily production of 2.87 × 10⁴ m³/d [19,20,21,22].

Nevertheless, the process of hydrate production testing still presents significant challenges, particularly in terms of low gas production from a single well and fast decay, which falls short of the daily gas production requirements necessary for industrialized development [23]. The decomposition of natural gas hydrates results in the production of gas and water, which are extracted through reservoir seepage to the wellbore. The temperature and pressure distribution within the reservoir are influenced by a number of factors, including the phase change in hydrates, heat and mass transfer, throttling expansion, and others [24,25]. The reforming of gas and water into hydrate within the reservoir, particularly in the vicinity of the well, results in a reduction in permeability around the production well, which hinders the continuous decomposition of natural gas hydrate [26,27,28]. The presence of secondary hydrates around wells is variable in time, and saturation is constantly changing. Difficulties in real-time monitoring and the lack of effective prevention measures have resulted in declining and cyclical daily gas production.

Extensive research has been conducted to investigate the characteristics of secondary hydrate formation around wells and their impact on production capacity [29,30,31,32,33,34,35,36]. Li et al. [37] analyzed the clogging problem of anti-sand screens and found that hydrate reformation would largely lead to a decrease in screen permeability. Alp et al. [38] analyzed the gas production characteristics of hydrate reservoirs and found the phenomenon of secondary hydrate formation along the wellbore. Hou et al. [39] employed pressure transient analysis to ascertain the existence of secondary hydrates in the vicinity of the wellbore. In their study, Wang et al. [40] analyze the characteristics of secondary hydrate formation during the production process and propose that the formation of secondary hydrates in the vicinity of the wellbore be prevented by meticulously regulating the wellbore pressure through the injection of hot water or the heating of the wellbore.

In conclusion, there is little research on the impact of secondary hydrates around wells on production capacity and prevention methods. In order to address the above problems, the authors used numerical simulation to investigate the formation law of secondary hydrates, to quantitatively describe the time, location, and saturation degree of formation of secondary hydrates around wells, and to analyze the impact of secondary hydrates around wells on the production capacity and the effectiveness of prevention methods to help the actual production of hydrates.

2. Mathematical and Geological Model

2.1. Mathematical Model

In this study, commercial software CMG STARS2021.10 is employed to examine the patterns of change in gas production, reservoir temperature, and pressure during production in hydrate reservoirs [41,42]. The numerical simulation model CMG STARS incorporates the following equations: the material conservation equation, relative permeability functions, the energy conservation equation, and the kinetic equation for the formation and dissociation of hydrate. Furthermore, it is capable of effectively dealing with the mathematical operations and calculations associated with multi-million-grid systems. This simulator participated in the first international hydrate simulator comparison project, and the accuracy of hydrate simulation calculation is recognized by many scholars, which is a more mature hydrate mining simulator [43,44,45,46].

Based on the above model, the hydrate is designated as an immobile oil phase. The permeability of the sediments does not change with the hydrate saturation during the exploitation of the hydrate reservoir. Nevertheless, due to the modification of hydrate saturation in the phase permeability equation, the flow capacity of gas and water is subject to constant variation. Important equations are described as follows:

• Relative Permeability Functions

Equations (1)–(4) are the relative permeability models used in this paper.

$$K_{rG}={\left(S_G^{*}\right)}^n$$

(1)

$$K_{rA}={\left(S_A^{*}\right)}^n$$

(2)

$$S_A^{*}=(S_A-S_{irA})/(1-S_{irA})$$

(3)

$$S_G^{*}=(S_G-S_{irG})/(1-S_{irA})$$

(4)

• Material Conservation Equation

During the process of hydrate decomposition, the mobile and non-mobile phases undergo continuous transformation due to changes in temperature and pressure. Mobile phases are defined as CH₄ and H₂O in this study, whereas the non-mobile phase is classified as hydrate. Equation (5) is the mass conservation equation for the mobile phase. Equation (6) is the mass conservation equation for the immobile phase.

$$V{\displaystyle \frac{\partial }{\partial t}}\left({\mathrm{\varnothing }}_f\sum _{j=1}^{n_{\mathrm{p}}}{\rho }_j{S}_j{x}_i^j\right)=\sum _{n=1}^{n_g}\left[\sum _{j=1}^{n_p}\left(T_j{\rho }_j{x}_i^j∆P\right)\right]+\sum _{j=1}^{n_{\mathrm{p}}}{\rho }_j{q}_{jL}{x}_i^j+V\sum _{k=1}^{n_{\mathrm{r}}}\left({S_{ki}^{\prime }-S}_{ki}\right)r_k$$

(5)

$$V{\displaystyle \frac{\partial }{\partial t}}\left(\varphi {\displaystyle \sum _{k=1}^{n_{\mathrm{r}}}{c}_{kl}}\right)=V{\displaystyle \sum _{k=1}^{n_{\mathrm{r}}}\left(s_{kl}^{,}-s_{kl}\right)}{r}_k$$

(6)

Please refer to the nomenclature for an explanation of the symbols used in the formulas. The symbols V, ρ_j, q_jL, r_k, and C_kl have the following units: m³, kg/m³, m³, mol/(m³·d), and mol/m³.

• Energy Conservation Equation

The formation and dissociation of hydrates are associated with changes in energy, which can result in an increase or decrease in reservoir temperature. The temperature change that occurs during the process of hydrate extraction can be expressed using the following equation (Equation (7)).

$$\begin{array}{l}V{\displaystyle \frac{\partial }{\partial t}}\left({\varphi }_f{\displaystyle \sum _{j=1}^{n_{\mathrm{p}}}{\rho }_j{S}_j{U}_j+\varphi c_h{U}_h+\left(1-\varphi \right)U_r}\right)=\\ {\displaystyle \sum _{n=1}^{n_{\mathrm{f}}}\left({\displaystyle \sum _{j=1}^{n_{\mathrm{p}}}\left(T_j{\rho }_j{H}_j\Delta P+K\Delta T\right)}\right)}+{\displaystyle \sum _{j=1}^{n_{\mathrm{p}}}{\rho }_j}{q}_{j\mathrm{L}}{x}_i^j{H}_j+V{\displaystyle \sum _{k=1}^{n_{\mathrm{r}}}{H}_{rk}}{r}_k\end{array}$$

(7)

Please direct your attention to the nomenclature for a detailed explanation of the symbols employed in the formulas. The symbols U_j, U_h, H_j, and K have the following units: J, J, J/mol, and W/(m·K).

• Kinetic Equation for the Formation and Dissociation of Hydrate

Please find below a representation of the equations governing the formation and dissociation of hydrates (Equations (8) and (9)), which are derived from the Vysniauskas–Bishnoi model [47] and the Kim–Bishnoi model [48].

$$n_f=k_f^0\exp \left(-{\displaystyle \frac{E}{RT}}\right)\left({\varphi }^2{A}_{HS}{c}_h{S}_w+\varphi A_{HS}{S}_w\right)\left(p_g-p_e\right)$$

(8)

$$n_d=k_d^0\exp \left(-{\displaystyle \frac{E}{RT}}\right)\left({\varphi }^2{A}_{HS}{c}_h{S}_w\right)\left(p_e-p_g\right)$$

(9)

The symbols n_f, n_d, $k_f^0$, $k_d^0$, E, A_hs, R, P_e, P_g, T have the following units: mol/m³, mol/m³, mol/(m²·kPa·d), mol/(m²·kPa·d), J/mol, m³/m³, J/(mol·K), kPa, kPa, K. The values of the parameters in the kinetic model are shown in

Table 1. Parameter values in the kinetic model.

Basic Parameters	Value
Hydrate Type	CH4·5.75 H2O
Molecular weight ρm/kg/mol	119.543 × 10−3
The mass density of hydrate ρ/kg/m3	919.7
The rate of decay λd/mol/(day·kPa·m2)	1.21 × 1013
The rate of formation λf/mol/(day·kPa·m2)	1.21 × 1013
Reaction enthalpy H/J/mol	51,858
Activation energy E/J/mol	89,660

.

2.2. Geological Model of Base Case

The Shenhu Sea is situated in a northerly location within the South China Sea, situated in the Baiyun Depression area of the Pearl River Estuary Basin. The Cenozoic sedimentary layer in the Baiyun Depression is more than 11 km thick, which creates favorable geological conditions for oil and gas generation. In this paper, based on the geological data of SH2 [49] and SH7 [50] in the Shenhu Sea, a geological model is built. Figure 1 illustrates a schematic diagram of the geological model, which is cylindrical in shape with a total number of grids of 32 × 12 × 54 = 20,736. The number of longitudinal (K-direction) grids is 54, with an upper and lower range of 104 m; a non-uniform grid section is used with a maximum longitudinal grid of 10 m and a minimum longitudinal grid of 1 m. The number of axial (I-direction) grids is 32, with a minimum mesh of 0.1 m and a maximum radius of 250 m; the radial (J-direction) grids are uniformly divided, with a number of 12.

The thickness of the hydrate layer, overburden layer, and underburden layer is 44 m, 30 m, and 30 m. The temperature at the bottom interface of the hydrate layer is 13.90 °C, and the pressure is 15.22 MPa. The pressures at the top and bottom of the model are 14.47 MPa and 15.49 MPa, and the temperatures are 10.72 °C and 15.06 °C, respectively. The hydrate layer contains two phases, the aqueous phase and the hydrate phase, in which the initial saturation of hydrate is 40%. The overburden layer and underburden layer are completely saturated with water, the overall density of the reservoir is 2600 kg/m³, and the initial permeability of the entire model is 100 mD. The overburden and underburden layers are characterized as impermeable. Accordingly, mass transfer is not permitted through these layers. However, heat is transferred from the overburden and subburden to the HBL. The relevant geological parameters and physical properties are shown in

Table 2. Table of physical parameters of the geological model of the hydrate reservoir.

Parameters	Value
Hydrate-bearing layer (HBL) thickness/m	44
The thickness of overburden layer/m	30
The thickness of underburden layer/m	30
Model Radius/m	250
Initial pressure-1464 m/MPa	15.22
Initial Temperature-1464 m/°C	13.90
Permeability/mD	100
Porosity	0.4
Well, bottom hole pressure/MPa	3
Perforation section	44 m
Initial hydrate saturation	0.4
Initial water saturation	0.6
Gas composition	100%CH4
Rock density (kg/m3)	2600
Rock thermal conductivity (W/m/K)	3.1

.

2.3. Production Well Design

In the middle of the model, there is a vertical well, and the hydrate layer is fully perforated. The length of the perforated section is 44 m, and the radius of the production well borehole is 0.1 m. Production is carried out by the method of fixed-pressure bucking. In this paper, the focus is on analyzing the factors of secondary hydrates, and a bucking regime with a fixed wellbore flow pressure of 3 MPa is established. The simulation time is 1400 days.

3. Results and Discussion

3.1. Numerical Results of Geological Model

3.1.1. Features of Hydrate Dissociation and Gas Production

The curves illustrating the gas production characteristics are presented in Figure 2. During the 1400-day production period, the hydrate continued to decompose, and the gas production rate peaked around the 1000th day and then declined rapidly, with approximately 9.68 × 10⁴ m³/d at the 1400th day and cumulative gas production of 1.27 × 10⁸ m³. As illustrated in Figure 3, the hydrate undergoes decomposition throughout the production process, with approximately 80% of the hydrate decomposing into methane and water.

Figure 4 illustrates the S_h distribution on the vertical cross-section on 30, 365, 730, and 1400 days, respectively. Horizontal and vertical coordinates are in meters. The hydrate reservoir initially decomposes around the production well because the pressure in the model first decreases from the production well. Subsequently, the hydrate near the upper and lower cap layers decomposes under the effect of heat transfer between the upper and lower cap layers, and the whole hydrate reservoir shows a typical “shrinkage core” decomposition pattern.

This section has analyzed gas production characteristics from hydrate reservoirs, which is consistent with the simulations of Wang et al. [40] and proves the validity of the model. The following section will focus on the pattern of secondary hydrate formation in the vicinity of the well, laying the foundation for subsequent analysis of the impact of secondary hydrates on production capacity.

3.1.2. Characteristics of Hydrate Saturation Evolution around the Production Well

The main formation area of secondary hydrate is around the production well, as shown in Figure 5. Horizontally, secondary hydrate is mainly in the range of 0.1 m around the well; vertically, secondary hydrate is predominantly concentrated within the upper 0–8 m. As shown in Figure 6, the process of hydrate saturation change in the secondary hydrate formation region can be classified into three stages. In stage N1, the hydrate saturation around the well has been decreasing, and it has been completely decomposed by day 31, which consistently lasted until day 547. In stage N2, the phenomenon of secondary hydrate formation occurs, and the saturation of secondary hydrate reaches 0.46, and then it gradually decomposes. Hydrate saturation in stage N3 is always 0, indicating that the hydrate near the wellbore has decomposed completely. The formation of secondary hydrate in this area will reduce the permeability around the well and block the flow channel of gas and water, which will directly affect gas production.

Figure 7 shows the hydrate saturation of the secondary hydrate formation region with time, and horizontal coordinates are the key time points. The hydrate of the secondary hydrate formation region has been completely decomposed at 30 d. There is secondary hydrate formation in the 0–2 m at 578 d, and the saturation ranges from 0.11 to 0.47. The region of secondary hydrate formation is further expanded, and the saturation is increased at 700 d. The closer to the upper part, the greater the saturation of secondary hydrates. The hydrate saturation at 0–1 m is the highest, about 0.54. The hydrate saturation at 5–6 m is the lowest, about 0.36. At 821 d, the range of hydrate reformation reaches the maximum, but the hydrate saturation in the range of 0–6 m decreases. At 943 d, the secondary hydrate region does not change, but the hydrate saturation gradually decreases, with the saturation between 0.24 and 0.45. At 1065 d, the secondary hydrate region decreases, and the saturation further decreases, with the hydrate saturation in the region of 0–7 m ranging from 0.05 to 0.3. At 1186 d, all the secondary hydrates are decomposed.

The analysis revealed that the formation of secondary hydrates is predominantly concentrated within the 0–8 m area in the upper part of the well. As shown in Figure 6, one monitoring point is set every one meter in the range of 0–8 m, and a total of eight monitoring points are set A, B, C, D, E, F, G, and H. Changes in secondary hydrate saturation around the well are analyzed through the monitoring points.

As shown in Figure 8, at 547 d, secondary hydrate formation starts. The rate of secondary hydrate formation is very fast. Taking monitoring point A as an example, the hydrate saturation increases from 0 to 0.47 in 30 d time and then increases to 0.54, and the saturation decreases to 0 in about 550 d time. The rate of secondary hydrate formation is approximately four and a half times that of decomposition, with a decomposition rate of approximately 0.285 mole/d. The hydrate saturation trends at the seven monitoring points are basically the same as those at monitoring point A. The rate of secondary hydrate production is much greater than the rate of decomposition. Moreover, the further down the monitoring points are, the later the secondary formation of hydrate is, the lower the saturation peak is, and the earlier the hydrate is completely decomposed.

3.1.3. Characteristics of Pressure and Temperature Changes

In order to study the conditions of secondary hydrate formation, the pressure, temperature, and phase equilibrium temperature (calculated from pressure, Equations (4) and (5), i.e., the temperature required to reach the phase equilibrium state just under the actual pressure) at monitoring point A are plotted as shown in Figure 9.

From Figure 8 and Figure 9, the phase equilibrium temperature is higher than the actual temperature at monitoring point A in the initial state, which is conducive to the stabilization of the hydrate. From 0 d to 31 d, the pressure at monitoring point A decreases rapidly, and the hydrate continuously decomposes and absorbs heat, and the temperature continues to decrease.

During the period of 31–547 days, the pressure slowly decreased, and the temperature continuously dropped to the phase equilibrium temperature. The decomposition of the hydrate reservoir resulted in the production of low-temperature gas and water, which continuously converged around the well and caused a reduction in the temperature at monitoring point A. Additionally, the dramatic Joule–Thompson effect of the gas caused the temperature at point A to drop further. During the period between 547 d and 650 d, the temperature coincided with the phase equilibrium temperature, which reached the condition of secondary hydrate production, and a large amount of secondary hydrate was produced at the monitoring point A, and the pressure and temperature increased continuously. From 650 d to 1065 d, the temperature remained consistent with the phase equilibrium temperature. However, the hydrate is in the process of continuous decomposition. Between 1065 d and 1400 d, the temperature is above the phase equilibrium temperature, indicating that the secondary hydrate has been fully decomposed.

Following the analysis presented in Section 3.1, it is possible to summarize the characteristics of the secondary hydrate around the well:

(1)

The formation of the secondary hydrate can be predicted based on the observed change in temperature and pressure, as the secondary hydrate is formed when the temperature gradually drops to the phase equilibrium temperature.

(2)

The secondary hydrate is typically formed in the near-well area of the upper part of the production well, with the area of secondary hydrate formation gradually expanding from the top to the bottom. In this study, the area of secondary hydrate formation is within the range of 0–8 m. The formation of secondary hydrates can be predicted based on changes in temperature and pressure.

(3)

The secondary hydrate around the upper part of the production well is the first to be formed, exhibiting the highest saturation peak and the latest decomposition.

(4)

The rate of secondary hydrate formation is markedly rapid, whereas the decomposition rate is relatively slow.

3.2. Effectiveness of Prevention Methods

The formation rate of secondary hydrates is rapid, which reduces the reservoir permeability in a short time, blocks the channels for gas and water transportation, and thus reduces gas production, which is unfavorable to the efficient development of hydrates. Hot water injection, wellbore heating, and reservoir reconstruction in the near-well region are effective methods to increase gas production, which can change the seepage field or temperature field in the near-well region [51,52,53,54,55,56,57,58,59,60,61].

This section, based on the base case, adopts the above three prevention methods and uses numerical simulation to compare the effect of prevention on secondary hydrates.

3.2.1. Comparison of Hot Water Injection

Six groups of hot water injection schemes have been established, with varying injection durations, injection rates, and injection temperatures, as illustrated in

Table 3. Cases of hot water injection.

	Injection Duration (d)	Injection Rate (m3/d)	Injection Temperature (°C)
Case 0	-	-	-
Case 1	7	1000	50
Case 2	7	2000	50
Case 3	7	2000	80
Case 4	7	3000	80
Case 5	10	3000	80
Case 6	15	3000	80

. The reference group, designated Case 0, represents a scenario without any secondary hydrate prevention method.

The injection layer of all six schemes is the upper 0–8 m (referring to Figure 5). The commencement of the hot water injection process is scheduled to occur on the 547th day, which is the time when the secondary hydrate starts to be generated. During the hot water injection, the production well is shut down. The injection pressure of the wellbore is 25 MPa, and the potential heat loss of hot water in the wellbore is not included in the calculations.

The results of the simulation for the hot water injection are presented in Figure 10. A comparison of Case 0 and Case 1 reveals that Case 1 reduces the saturation of secondary hydrate and delays the formation time of secondary hydrate. However, the effect is not significant, with the peak of the secondary hydrate saturation reduced by only 5%. Furthermore, the hydrate saturation for Case 6 is 0 from 31 to 1400 d, indicating that there is no secondary hydrate formation. The simulation results for the six scenarios demonstrate that the injection of hot water can reduce the volume of secondary hydrates and shorten the duration of their existence. Furthermore, increasing the injection temperature, the number of injection days, and the injection rate can reduce the saturation of secondary hydrates.

Define the heat utilization rate ${\mathsf{\eta }}_1$ for the hot water injection method:

$${\mathsf{\eta }}_1={\displaystyle \frac{{\mathrm{Q}}_1}{{\mathrm{Q}}_2}}={\displaystyle \frac{\mathrm{W}\mathrm{H}}{\mathrm{c}\mathrm{m}∆\mathrm{t}}}$$

(10)

In the above equation, c, the symbol “c” is the heat capacity of water in $\mathrm{J}/°\mathrm{C}/\mathrm{k}\mathrm{g}$. The variable “m” denotes the mass of water in kg. The variable “∆t“ represents the difference in temperature between the initial and final states of the water prior to and following its heating. Finally, the variable “W” denotes the amount of substance of the secondary hydrate in a mole.

Taking Case 6 as an example, assuming that the offshore platform heats water at 15 degrees Celsius to 80 degrees Celsius for injection into the hydrate reservoir, the total energy consumption is 1.2285 × 10¹³ J. The peak volume of the secondary hydrate at the periphery of the well in Figure 5 is 0.139 m³, and it takes 5.5 × 10⁷ J to decompose 0.139 m³ of hydrate, so the energy utilization is only 4.514 × 10⁻⁴%. This is due to the fact that the majority of the injected hot water is transported to regions within the reservoir that are distant from the wellbore. As a result, it is not possible to gather the water around the well in order to effectively increase the temperature in the vicinity of the well, which ultimately limits the utilization efficiency.

3.2.2. Comparison of Wellbore Heating

Six groups of schemes for wellbore heating are set up, considering different heating power and heating time, as shown in

Table 4. Cases of wellbore heating.

	Heating Power (J/d)	Heating Time/d
Case 0	-	-
Case 11	1 × 106	600 d
Case 12	1 × 107	600 d
Case 13	1 × 108	600 d
Case 14	1 × 109	300 d
Case 15	1 × 109	450 d
Case 16	1 × 109	600 d

. The heating start time of all six groups of schemes is 547th day, and the heating layer is the upper 0–8 m (referring to Figure 5).

The results of the wellbore heating simulation are presented in Figure 11. The secondary hydrate saturation of the Case 0 and Case 11 schemes is essentially identical, indicating that the heating power of 1 × 10⁶ J/d is insufficient to effectively increase the temperature around the well. Increasing the heating power, the secondary hydrate saturation of Case 12 and Case 13 decreases. However, the formation and decomposition times of the secondary hydrate remain unchanged and are comparable to those observed in Case 0. Upon increasing the heating power to 1 × 10⁹ J/d, the hydrate saturation of the Case 16 scheme is observed to be 0 between 31 and 1400 days, indicating the absence of secondary hydrate formation. The results of Case 14 and Case 15 demonstrate that the application of wellbore heating is an effective method for preventing the formation of secondary hydrates. However, upon cessation of the heating process, the secondary hydrate rapidly forms and follows a similar reorganization path as observed in the Case 0 scheme.

In conclusion, it can be stated that the wellbore heating method is also effective in reducing the volume of secondary hydrates. As with the hot water injection method, it is necessary to calculate the heat utilization of the wellbore heating method. Define the wellbore heating method heat utilization ${\mathsf{\eta }}_2$:

$${\mathsf{\eta }}_2={\displaystyle \frac{{\mathrm{Q}}_1}{{\mathrm{Q}}_2}}={\displaystyle \frac{\mathrm{W}\mathrm{H}}{{\mathrm{W}}_1{\mathrm{T}}_1}}$$

(11)

In the above equation, W₁ represents the power of wellbore heating in J/d and T₁ denotes the heating time in days.

In the case of Case 16, the wellbore is subjected to a heating power of 1 × 10⁹ J/d for 600 days, resulting in a total energy consumption of 6 × 10¹¹ J. Decomposing 0.139 m³ of hydrate requires 5.5 × 10⁷ J, thus the energy utilization rate is 9.24 × 10⁻³%. In comparison to the method of hot water injection, the energy utilization rate is increased by a factor of 20. From the perspective of heat utilization efficiency, wellbore heating is a more efficient method than hot water injection. This is because wellbore heating is capable of concentrating the heat in the area of secondary hydrate formation around the well, which can then be utilized more effectively.

3.2.3. Comparison of Reservoir Reconstruction

A total of six reservoir reconstruction scenarios are established. All six scenarios resulted in alterations to the permeability within the 2.5-m zone surrounding the well. Modifications to the seepage field in the proximate area of the well result in a reduction or elimination of secondary hydrates. The specific scenarios are presented in

Table 5. Cases of reservoir reconstruction.

	Permeability (mD)	Layers of Reservoir Reconstruction (m)
Case 0	-	-
Case 21	100	0–8
Case 22	300	0–8
Case 23	500	0–8
Case 24	100	0–44
Case 25	300	0–44
Case 26	500	0–44

.

The results of the reservoir reconstruction simulation are presented in Figure 12. The secondary hydrate saturation of Case 0, Case 21, and Case 24 is essentially identical (the three curves are superimposed), which is attributable to the insufficient increase in permeability of the modified area in comparison to the initial permeability. This is insufficient to alter the flow line around the well and effectively influence the temperature and pressure field. A comparison of Case 21, Case 22, and Case 23 revealed that an enhancement in the permeability of the reconstruction area can diminish the secondary hydrate saturation and abbreviate the existence time of the secondary hydrate. However, complete elimination is not achievable. The scope of reconstruction is expanded in Cases 24, 25, and 26, with reformatting in the longitudinal range of production wells from 0 to 44 m. This resulted in a more effective reduction in secondary hydrate saturation. The hydrate saturation of the Case 26 scheme is 0 between 31 and 1400 days, indicating the absence of secondary hydrate formation. The results of the six scenarios demonstrate that reservoir reconstruction can effectively reduce the volume of secondary hydrate and shorten the time frame in which secondary hydrate is present. Increasing permeability and extending the scope of modification are effective strategies for achieving this outcome.

In Section 3.2, 18 sets of simulations have been conducted, with cases 1–6 comparing and analyzing the effectiveness of hot water injection, cases 11–16 comparing and analyzing the effectiveness of wellbore heating, and cases 21–26 comparing and analyzing the effectiveness of reservoir reconstruction. It is possible to summarize the effectiveness of prevention methods:

(1)

Three prevention methods can be effective in reducing the formation of secondary hydrates around the well. However, it should be noted that basic parameters necessitate a specific threshold. To illustrate, when the permeability is less than 100 mD, the reservoir reconstruction method does not alter the timing and quantity of secondary hydrate.

(2)

Three prevention methods can be effective in eliminating the formation of secondary hydrates around the well. In the case of the hot water injection method, the water temperature should be at least 80 degrees Celsius, with the injection volume increased in order to guarantee the elimination of secondary hydrates. In the case of the wellbore heating method, the wellbore heating power should be increased and maintained continuously throughout the period of secondary hydrate formation. The permeability in the reservoir reconstruction method should be greater than 500 mD for all shothole layers;

(3)

Wellbore heating is more energy efficient than hot water injection.

3.3. Impact of Secondary Hydrate on Gas Production

Figure 13 illustrates the cumulative gas production values for the four programmes. A comparison of the cumulative gas production of the four scenarios reveals that the production increase of Case 6 and Case 16 is minimal, at less than 5%. This indicates that the influence of secondary hydrates on production capacity is limited and that the influence of secondary hydrates around It can be concluded that the wells in question have a negligible impact on production capacity. Case 26, however, has the potential to significantly enhance cumulative gas production by up to 30%. This is due to the fact that the reservoir reconstruction process was able to increase permeability around the well over the course of the full production cycle, thereby markedly increasing production capacity. In the event that secondary hydrate prevention is required, near-well modification represents the optimal approach.

4. Summary and Conclusions

In this work, a coupled simulation model is proposed to observe secondary hydrate formation around the production well during the process of dissociation induced by depressurization. Then, the effectiveness of three secondary hydrate prevention methods is analyzed. Finally, the impact of secondary hydrates on capacity is discussed. The conclusions are as follows:

(1)

The secondary hydrate is typically formed in the near-well area of the upper part of the production well, with the area of secondary hydrate formation gradually expanding from the top to the bottom. The secondary hydrate around the upper part of the production well is the first to be formed, exhibiting the highest saturation peak and the latest decomposition.

(2)

The formation of the secondary hydrate can be predicted based on the observed change in temperature and pressure. The rate of secondary hydrate formation is markedly rapid, whereas the decomposition rate is relatively slow.

(3)

The impact of secondary hydrates on cumulative gas production is insignificant, and the effect of secondary hydrates on capacity can be ignored.

(4)

Hot water injection, wellbore heating, and reservoir reconstruction can effectively eliminate secondary hydrates around the well. Reservoir reconstruction represents a superior approach to the elimination of secondary hydrates, which can effectively enhance production capacity while preventing the generation of secondary hydrates.