Investigating CO₂ Replacement for the Exploitation of Natural Gas Hydrates: Characteristics and Control Parameters

Abstract

In response to escalating global energy demand and climate change mitigation needs, natural gas hydrates (NGHs) are gaining prominence as a clean energy source. The CO₂ replacement method is an innovative NGH extraction technique that reduces reservoir risks and enables CO₂ sequestration. However, our understanding of the dynamics and control parameters in the hydrate replacement process is limited. This study pioneers a kinetic analysis and conceptual model for a CO₂-driven hydrate replacement, dividing the process into three spatial realms and sequential stages. We identify the optimal injection temperature range for standard NGH reservoirs and highlight the interplay between the gas injection rate and bottom-hole pressure on CH₄ yield. Our findings offer insights on how to optimize production efficiency and gas separation, advancing CO₂ replacement technology for NGHs.

1. Introduction

Natural gas hydrates (NGHs), characterized by substantial reserves and a high energy content, are being recognized as a significant new energy resource in the 21st century. Notably, China is estimated to process 1.26 × 10¹⁴ m³ of NGHs, underscoring the critical importance of research on the exploitation of NGHs for enhancing national energy security. Among various production techniques, the depressurization method, thermal stimulation, chemical inhibitor injection, and gas replacement methods are prominent [1,2,3,4]. The CO₂ replacement method is especially noteworthy due to its minimal impact on the reservoir’s structural integrity and its potential role in preventing reservoir collapse [5]. Moreover, this method offers a feasible pathway for CO₂ sequestration, thus contributing to carbon neutrality objectives.

Following the introduction of the CO₂ replacement method by the American researcher Ebinuma [6] in 1993, there has been a marked increase in global scholarly efforts. Scholars have employed techniques such as molecular dynamics, Raman spectroscopy, experimental studies, and numerical simulation models to establish the feasibility of CO₂ replacement in the extraction of NGHs and elucidate the underlying mechanisms. Ohgaki et al. [7] performed comparative analyses of CH₄ and CO₂ diffusion in hydrates, preliminarily establishing the kinetic potential of replacement. Wang et al. [8] assessed the efficiency of CO₂ replacement in NGHs under various temperatures and pressures, finding that elevated temperatures and pressures enhance the reaction, thereby confirming the viability of the method. Zhou et al. [9], through the analysis of hydrate phase diagrams and geothermal gradients, identified an optimal replacement zone delineated by several key lines. Furthermore, Zhou et al. [10] noted that CO₂ microemulsions are more effective than liquid CO₂ in facilitating replacement. Wang et al. [11] employed Raman spectroscopy to monitor the CO₂ replacement process in hydrates, discerning a two-stage mechanism comprising an initial rapid reaction phase followed by a sustained reaction phase.

In a numerical simulation, Uddin et al. [12] employed CMG STARS to explore CO₂ hydrate formation in geological reservoirs via gas injection, revealing its capability to trap CO₂ and highlighting the challenges in hydrate formation for geological CO₂ sequestration. Qanbari et al. [13] also used CMG STARS to assess deep-sea sediments for CO₂ storage, finding that HFZ and NBZ act as thermodynamic barriers against CO₂ migration, thus enabling long-term CO₂ sequestration. Janicki’s team [14] combined STARS and HyReS to study methane recovery from gas hydrates and CO₂ storage as hydrates, showing that depressurization and CO₂ injection can enhance methane recovery and reduce CO₂ emissions. Wang et al. [15] utilized STARS and HyReS to investigate the simultaneous recovery of methane and storage of CO₂ as hydrates, emphasizing the impact of gas diffusion through hydrates and the influence of initial conditions on the efficiency of the process. Shanling Zhang et al. [16] utilized the CMG-STARS, 2020 edition software to study the numerical simulation of natural gas hydrate extraction by combining depressurization with CO₂ replacement. The research indicates that the well bottom pressure, the pressure differential between injection and production, and the injection temperature significantly impact methane extraction and CO₂ sequestration, with optimal conditions leading to maximum methane production and efficient CO₂ storage.

However, research into the CO₂-CH₄ hydrate replacement method remains nascent [17,18], with no comprehensive kinetic model yet developed to describe the process comprehensively. There is an urgent need for further in-depth exploration of the complex mechanisms of CO₂ replacement, hydrate storage, decomposition, and critical control parameters. This article analyzes the kinetic experimental data related to natural gas hydrates and CO₂ hydrates. Based on these experiments, a numerical simulation model for CO₂ replacement in natural gas hydrates has been developed using the CMG software, 2020 edition. Additionally, the study explores the production characteristics and spatial distribution of the CO₂ replacement process in natural gas hydrates, as well as the factors influencing conventional CO₂ replacement. The goal is to describe the intrinsic mechanisms driving CO₂ replacement in natural gas hydrates.

2. The Fundamental Kinetics of CO₂ Replacement in NGHs Systems

Sloan et al. [17] established experimental phase diagrams for CO₂ and CH₄ hydrates, as depicted in Figure 1. The phase boundaries are defined by equilibrium lines for the CH₄ hydrate, the CO₂ hydrate, and the gas–liquid equilibrium for CO₂ and CH₄. These lines segregate the diagram into four sectors: Area A, Area B, Area C, and Area D. Notably, in Areas A and B, the equilibrium line for the CH₄ hydrate is positioned above that of the CO₂ hydrate. This configuration suggests that injecting CO₂ into geological formations under specific temperature and pressure conditions initiates the decomposition of NGHs. This decomposition releases CH₄ and water, and concurrently, CO₂ interacts with the liberated water to form the CO₂ hydrate. The delineation of Areas A and B in the phase diagram highlights the thermodynamic viability of replacing NGHs with CO₂, proposing a viable method.

Scholars propose that the interaction between CO₂ and NGHs induces a transition from a stable to an unstable state [19,20,21,22]. The interaction destabilizes the hydrate’s cage-like structure, facilitating the breakdown and subsequent release of CH₄ and water molecules. Simultaneously, CO₂ molecules form hydrates by engaging with water molecules via van der Waals forces. Due to their larger size, CO₂ molecules are confined to the larger cavities, while water molecules, influenced by the hydrogen bonding memory effect, recombine with CH₄ to form smaller cavities. This cyclic process persists until the reaction concludes. Uchina et al. [20], Kim et al. [23], and Sun et al. [24] investigated the CO₂ replacement process in natural gas hydrates using in-situ Raman spectroscopy and experimental methods, developing kinetic models for decomposition and formation. However, significant variations were observed in the reported activation energies and pre-exponential factors among different studies. This study therefore surveyed and calculated these parameters for CH₄ and CO₂ hydrates, with the results summarized in

Table 1. Activation energy for the formation of NGHs.

Author	The Formation Activation Energy of NGHs, kJ/mol	Pre-Exponential Factor, mol/(m2·MPa·s)	Sediment Particle Size	Temperature, K	Pressure, MPa	Measurement Techniques
Huang et al. [25]	Stage I 70.1 Stage II 68.3		ice powder (154–200 $\mu$m) quartz sand (154–300 $\mu$m)	273–263	6.9	high-pressure reactor
Wang et al. [26]	61.74 (Structure I NGHs)	1.91 × 1010		253–273	6.9	neutron diffraction
Tian et al. [27]	84.16	5.43 × 1015	2–4 mm glass beads	263.15–273.15	5	high-pressure reactor
Liu et al. [28]	89.8	3.40 × 1010		276–265	0.1	high-pressure reactor
Vysniauskas et al. [29]	106.204			274–284	3–10	high-pressure reactor
Li et al. [30]	80.9	8.06 kg/(m2·Pa·s)	quartz sand (300–450 $\mu$m)	282.08–283.97		high-pressure reactor/simulation

,

Table 2. Activation energy for the decomposition of NGHs.

Author	The Dissociation Activation Energy of NGHs, kJ/mol	Pre-Exponential Factor, mol/(m2·MPa·s)	Sediment Particle Size	Additives Used	Temperature, K	Pressure, MPa	Measurement Techniques
Li [31]	SPC/FW-UA 84.3 SPC/E-UA 84.1 TIP4P-UA 86.2 Experiment 81	1.84 × 1013			290-32 (MD) 263–273	10 (MD)	MD high-pressure reactor
Clarke et al. [32]	81 (Structure I NGHs)	3.64 × 1011			274.65–281.15	3.3–6.36	high-pressure reactor
Myshakin et al. [33]	82.2 cage occupancy 100% 73.2 cage occupancy 95% 70.6 cage occupancy 85%	1.20 × 1016 mol/(m3·s) 1.20 × 1016 mol/(m3·s) 6.03 × 1017 mol/(m3·s)			265–300	6.8	MD
Kim et al. [23]	78.3	1.24 × 1011			274–283	0.179–6.79	high-pressure reactor
Tian et al. [34]	76.93	4.72 × 1011			273.15–279.15	0.1	high-pressure reactor
Sun et al. [24]	73.3	1.24 × 1011			273.65–278.95	1.0–3.0	high-pressure reactor
Clarke et al. [35]	77.33 (Structure II NGHs)	8.06 × 1011			274–278	0.6–1.4	high-pressure reactor
Cheng et al. [36]	82.75	8.06 × 1011			286.65–292.85	0.1–2.0	simulation
Li et al. [37]	83.9 (Structure I NGHs)				285–300	5–40	MD
English et al. [38]	82.2				276.65	6.8	MD
Li [39]	31.81	1.96 × 105			270.15–278.15	2.3–3.8	high-pressure reactor
Li [39]	61.44	1.96 × 105		NaCl	270.15–275.15	3	high-pressure reactor
Li [39]	28.81	96.54		SDS	271.2–276.0	2.8–3.25	high-pressure reactor
Lin [40]	165.1			SDS	260.3–271.8		high-pressure reactor
Uddin et al. [41]	59.8	5.10 × 1015			240–300	2–10	MD
Liang et al. [42]	96.12				264–269	0.1–2.2	high-pressure reactor
Liang et al. [42]	88.98			activated carbon	273–276	0.1–5.1	high-pressure reactor
Liang et al. [42]	96.43	1.84 × 1013		SDS	264–269	0.1–2.3	high-pressure reactor

,

Table 3. Activation energy for the formation of the CO₂ hydrate.

Author	The formation Activation Energy of CO2 Hydrate, kJ/mol	Pre-Exponential Factor, mol/(m2·MPa·s)	Sediment Particle Size	Additives Used	Temperature, K	Pressure, MPa	Measurement Techniques
Li [39]	68.4	5.75 × 108		SDS	271.2–276.0	2.8–3.25	high-pressure reactor
Li [39]	72.56	6.62 × 107			270.15–278.15	2.3–3.8	high-pressure reactor
Li [39]	308.2	4.42 × 1052		NaCl	270.15–275.15	3	high-pressure reactor
Malegaonkar et al. [43]	53.7				274–278	1.6–2.8	high-pressure reactor
Lee et al. [44]	35.2			NaCl	273–277	2.5–3.4	high-pressure reactor
Clarke et al. [45]	45.2		1.25 $\mu$m		274–279	1.6–3.0	high-pressure reactor
Fukumoto et al. [46]	402				275–279	2.0–3.1	high-pressure reactor

and

Table 4. Activation energy for the decomposition of the CO₂ hydrate.

Author	The Dissociation Activation Energy of CO2 Hydrate, kJ/mol	Pre-Exponential Factor, mol/(m2·MPa·s)	Sediment Particle Size	Temperature, K	Pressure, MPa	Measurement Techniques
Wang et al. [47]	469.05 (block hydrate) 346.3 (cement hydrate)		340.59 $\mu$m	273.86–276.11	0	high-pressure reactor
Clarke et al. [48]	102.88	1.83 × 1011		274–281	1.4–3.3	high-pressure reactor
Sun et al. [49]	71.4			275.55–282.75	0.7–3.4	high-pressure reactor
Fukumoto et al. [46]	97.51			277.65–283.15	5	high-pressure reactor
Uddin et al. [41]	86.4 (Structure I CO2 hydrate)	4.69 × 1021		240–260	1–10	MD
Uddin et al. [41]	56.9 (Structure I CO2 hydrate)	7.77 × 1015		260–300	1–10	MD
Uddin et al. [41]	67.8 (Structure I CO2 hydrate)	6.00 × 1017		240–300	1–10	MD

. The analysis of these tables leads to the following conclusions:

• The activation energy of NGHs increases with the inclusion of more CH₄ molecules in the cavities.
• Different types of NGHs exhibit varying activation energies; hydrate formation in carbon or glass beads typically has a lower activation energy compared with NGHs. Although the Structure I hydrate usually presents a lower activation energy than Structure II, some results suggest the opposite, which may be attributed to variations in experimental methodologies and data interpretation.
• The decomposition rate of NGHs diminishes as temperatures approach the freezing point (260–270 K), resulting in an increased activation energy due to the inherent stabilizing mechanisms of the hydrate.
• The influence of NaCl on the activation energy of NGHs remains unclear, with the potential to either decrease or increase the energy, suggesting that its effect is situational and requires further investigation.

3. Simulation Models

3.1. Model Assumptions

The model integrates five distinct components: three gaseous phases—carbon dioxide (CO₂), methane (CH₄), and water (H₂O)—and two solid phases, which include methane hydrate (CH₄·H₂O) and carbon dioxide hydrate (CO₂·H₂O). It simulates the CO₂ replacement of CH₄·H₂O, encompassing the decomposition of CH₄·H₂O, the synthesis and phase transitions of CO₂·H₂O, and the associated heat and mass transfer dynamics. The model framework is built on several assumptions:

(1)

It includes solid, liquid, and gaseous phases, assuming that the fluid flow adheres to Darcy’s law.

(2)

It excludes the influence of inhibitors and the effect of salinity on gas hydrate stability.

(3)

It accounts for heat conduction and convection, alongside hydrate decomposition and formation.

(4)

It omits the formation of ice from free water.

(5)

It assumes that the decomposition and formation of gas hydrates are predominantly governed by reaction kinetics.

(6)

It posits that NGHs are present in the formation as a solid, with the saturation relationship: S_w + S_g = 1, where S_w represents water saturation and S_g denotes gas saturation.

3.2. Mathematical Model

TOUGH-HYDRATE, v1.2 edition and CMG-STARS, 2020 edition are the primary software tools utilized for simulating the extraction of NGHs [16]. CMG-STARS models complex reservoir dynamics and facilitates the simulation of chemical reactions in a non-equilibrium state, thus supporting various hydrate recovery techniques. It is easier to use and features enhanced post-processing capabilities compared with TOUGH-HYDRATE. Investigating the CO₂ hydrate replacement process is complex and challenging through conventional experimental approaches. CMG-STARS effectively visualizes this process and has been chosen for studying CO₂ hydrate replacement. Here, we use the CMG-STARS software to simulate the process of carbon dioxide displacing natural gas hydrates.

The chemical equations that describe the formation and decomposition of NGHs and CO₂ hydrate are presented in (1) and (2), respectively.

$$1{\mathrm{CH}}_4-\mathrm{HyD}\left(\mathrm{s}\right)\leftrightarrows 6.75{\mathrm{H}}_2\mathrm{O}+1{\mathrm{CH}}_4\left(\mathrm{g}\right)$$

(1)

$$1{\mathrm{CO}}_2-\mathrm{HyD}\left(\mathrm{s}\right)+1{\mathrm{H}}_2\mathrm{O}\rightleftarrows 7.7{\mathrm{H}}_2\mathrm{O}+1{\mathrm{CO}}_2\left(\mathrm{g}\right)$$

(2)

The kinetic equations for the decomposition of both CO₂ hydrate and NGHs are presented in (3).

$$-{\displaystyle \frac{d{n}_H}{dt}}=\left({\displaystyle \frac{K_d^0{A}_{sh}}{{\rho }_w{\rho }_h}}\right)\left(\varphi s_w{\rho }_w\right)\left(\varphi s_h{\rho }_h\right)\left(y_i{P}_g\right)\left(1-{\displaystyle \frac{1}{K}}\right)\exp \left(-{\displaystyle \frac{△E}{RT}}\right)$$

(3)

where ${\displaystyle \frac{d{n}_H}{dt}}$ is rate of NGH decomposition, mol/min; $K_0^d$ is the hydrate decomposition rate constant mol/(m²∙Pa∙s); $\Delta E$ is the activation energy for the decomposition, kJ/mol; R is the ideal gas constant, J/(mol∙K); T is temperature; $\rho$ is density, kg/m³; $\varphi$ is porosity; S is saturation; the subscript ‘w’ and ‘h’ correspond to water and hydrate; K is the gas–liquid equilibrium constant; $y_i$ is the mole fraction of CH₄ in the gas phase, %.

The mass conservation equation is given in (4)–(6).

$${\displaystyle \frac{\partial \left({\rho }_g\varphi S_g\right)}{\partial t}}+{\rho }_g\varphi S_g\nabla v_s={\stackrel{·}{m}}_g$$

(4)

$${\displaystyle \frac{\partial \left({\rho }_w\varphi S_w\right)}{\partial t}}+{\rho }_w\varphi S_w\nabla v_w={\stackrel{·}{m}}_w$$

(5)

$${\displaystyle \frac{\partial \left({\rho }_h\varphi S_h\right)}{\partial t}}+{\rho }_h\varphi S_h\nabla v_h={\stackrel{·}{m}}_h$$

(6)

where $\rho$ is density, kg/m³; $\varphi$ is porosity; $S$ is saturation; $v$ is flow rate, m/s; the subscript ‘w’, ‘h’, and ‘g’ correspond to water, hydrate, and gas.

When the reservoir rock is classified as water-wet, the Brooks–Corey equation is applied to determine the phase infiltration parameters. This model, outlining the phase infiltration behavior for both gas and water, is presented in (7) and (8).

$$k_{rw}=k_{rw,\max }{\left({\displaystyle \frac{s_w-s_{wr}}{1-s_{wr}-s_{gr}}}\right)}^{c_w}$$

(7)

$$k_{rg}=k_{rg,\max }{\left({\displaystyle \frac{s_g-s_{gr}}{1-s_{wr}-s_{gr}}}\right)}^{c_g}$$

(8)

where $k_r$ is the relative permeability, dimensionless; $k_{r,\max }$ is the maximum relative permeability, dimensionless; $c$ is the relative permeability decreasing index, dimensionless; $s_{wr}$ is the bound water saturation; $s_{gr}$ is the bound gas saturation.

The simulation employs the Kozeny equation to clarify the relationship between porosity and permeability, as expressed in (9) and (10).

$${\varphi }_t={\varphi }_i\left(1-s_h\right)$$

(9)

$$k\left({\varphi }_t\right)=k_0{\left({\displaystyle \frac{{\varphi }_i}{{\varphi }_t}}\right)}^3{\left[\left({\displaystyle \frac{1-{\varphi }_i}{1-{\varphi }_t}}\right)\right]}^2$$

(10)

where ${\varphi }_t$ is the current porosity, dimensionless; ${\varphi }_i$ is the original porosity, dimensionless; $k\left({\varphi }_t\right)$ is the current permeability, mD; $k_0$ is the original permeability, mD.

4. Numerical Model Settings

4.1. Numerical Model Configuration

The simulation of the CO₂ replacement process in NGH reservoirs utilizes the CMG-STARS software. It specifically targets the decomposition of NGHs and the subsequent CO₂ hydrate formation. The computational domain, segmented into a grid of 5 m × 5 m × 5 m dimensions, consists of 4000 cells arranged in a 20 × 20 × 10 geometric configuration. Injection and production utilize a staggered well pattern. The model designates a CO₂ injection rate of 10,000 m³/d, with an injection temperature and pressure of 10.15 °C and 10 MPa, respectively. The production well bottom-hole pressure is maintained at 4.5 MPa, ceasing production when the gas production declines below 2000 m³/d. Additional model specifics are illustrated in Figure 2, and

Table 5. NGH reservoir properties.

Parameters	Value
Porosity	0.28
Permeability	20 mD
Stratigraphic thermal conductivity	10
Water saturation	0.98
Gas saturation	0.02
NGH concentration	4616.8 gmol/m3
Reservoir temperature	10.15 °C
Reservoir pressure	7 MPa
Rock compression coefficient	1 × 10−6 MPa−1
Rock heat capacity	8 × 105 J/(m3·°C)
Rock thermal conductivity	1.5 × 105 J/(m3·°C)
Thermal conductivity of water	6 × 104 J/(m3·°C)
Hydrate thermal conductivity	3.93 × 104 J/(m3·°C)
Gas thermal conductivity	2.93 × 103 J/(m3·°C)
Overlying and underlying rock heat capacity	2.347 × 106 J/(m3·°C)
Thermal conductivity of overlying and underlying formations	1.496 × 105 J/(m3·°C)

presents a detailed list of the reservoir properties. We will simulate the replacement process of different types of natural gas hydrates in the next article based on the conclusions of the second part by modifying the parameters related to the activation energy. Here, the decomposition activation energy for natural gas hydrates and carbon dioxide hydrates is 89.6 kJ/mol.

4.2. Simulation Scenarios

To clarify the factors influencing the CO₂ replacement process in conventional NGHs, multiple simulations were executed to evaluate the effects of the gas injection rate, the injected gas temperature, and the bottom-hole pressure on the displacement efficiency. The gas injection rates under consideration are 10,000 m³/d, 7000 m³/d, 5000 m³/d, 2000 m³/d, and 1000 m³/d. The injection temperatures assessed are 30 °C, 20 °C, 10.15 °C, 5 °C, and 0 °C. The bottom-hole pressures investigated are 7 MPa, 6 MPa, 5 MPa, 4.5 MPa, and 2 MPa. The results of the detailed analysis are presented below.

5. Results and Discussion

5.1. Analysis of the Production Dynamics of CO₂ Replacement in a Conventional NGH Reservoir

Figure 3 and Figure 4, respectively, illustrate the cumulative graphs of the injection and production rates throughout the CO₂ replacement process in NGHs. Figure 5 and Figure 6 depict the average temperature and the concentration distribution graphs of conventional NGHs. A visual analysis of these figures segments the replacement process into three distinct stages: Stage I (lasting 51 days), Stage II (spanning 158 days), and Stage III (extending over 944 days of production).

In Stage I, the production from the conventional NGH reservoir features substantial daily water production, peaking at 226 m³/d. As the production progresses, the daily water production notably declines, whereas the daily CH₄ production increases. On the 15th day, tCH₄ production reaches a peak of 30,000 m³/d, which is sustained until the 51st day, followed by a subsequent decline. Figure 6 and Figure S1 show that the NGH concentration near the production well decreases significantly more than near the injection well during this phase, suggesting that pressure reduction plays a greater role in CH₄ production than the CO₂ replacement process. After replacement, the concentration and temperature fields show an elongated “nail-like” distribution, with the vertical expansion of the temperature and CH₄ concentration fields being more pronounced than the horizontal. Additionally, there is a general downward trend in both the average pressure and temperature within the conventional NGH reservoir, with a temperature increase only near the injection well, attributed to CO₂ hydrate formation, which releases more heat than NGH decomposition, thereby cooling most areas of the reservoir.

In Stage II, both CH₄ and water production decline yet remain relatively stable. CH₄ production averages around 10,000 m³/d, with water production at approximately 5 m³/d. The analysis of Figure 6 and Figure S1 reveals that this phase sees expanding areas of increased temperature, reflecting the growth of the CO₂ hydrate formation zone and a decrease in the CH₄ hydrate concentration. Notably, the spatial distribution of CO₂ hydrate formation in Stage II differs markedly from Stage I, forming an “inverted thumbtack” shape with a broader upper and narrower lower section. A superimposition effect is observed in the upper layer of the replacement zone, where the process primarily occurs. This configuration results from the lower density of gaseous CO₂, which drives its ascent to the upper layer, thus concentrating the replacement zone into the observed inverted “thumbtack” pattern.

Stage III is characterized by the initial breakthrough of injected CO₂, leading to a fluctuating pattern in daily CH₄ and CO₂ production. An increase relationship is observed: an increase in daily CO₂ production correlates with a decrease in CH₄ production, and vice versa. To elucidate this dynamic, samples were obtained from four locations within the first stratum of the NGH reservoir at distances of 75 m, 90 m, 95 m, and 121 m from the injection point. The concentration profiles of CO₂ and CH₄ molar fractions at these locations are illustrated in Figure 7 and Figure 8.

The analysis of Figure 7 and Figure 8 indicates a competitive relationship between CO₂ and CH₄ molar fractions during Stage III: a reduction in the CO₂ molar fraction is paralleled by an enhancement in the CH₄ molar fraction, and vice versa. This interaction occurs as excessive injected CO₂ displaces natural gas, which is then released back into the formation post breakthrough. Thus, controlling the rate of injected CO₂ is crucial for optimizing the CO₂ replacement process in conventional NGH reservoirs.

5.2. Analysis of the Spatial Characteristics of CO₂ Displacement in a Conventional NGH Reservoir

The spatial distribution of the CO₂ replacement process within the NGH reservoir is characterized by three distinct regions: the competitive gas zone, the replacement domain, and the depressurization sector, as illustrated in Figure 9. Figure 10, Figure 11, Figure 12 and Figure 13 show the detailed visual data on permeability, the molar fraction distributions of CO₂ and CH₄ at various distances—75 m, 90 m, 95 m, and 121 m—from the injection well in the upper stratum of the conventional NGH reservoir, as well as the changes in the formation temperature.

(1)

Analysis of the spatial profile in the depressurization sector.

The initiation of a depressurization sector occurs near the production well due to the decreasing surrounding pressure. This zone significantly impacts a wide area, possibly extending to the injection well. As illustrated in Figure 6, Figure 10, Figure 11, Figure 12 and Figure 13, deploying conventional NGHs within this zone leads to several critical observations.

①

Within the depressurization sector, the reservoir pressure of conventional NGHs falls below the phase equilibrium curve required for stability. This decline triggers the decomposition of NGHs into water and CH₄, resulting in a marked reduction in the NGH concentration and a corresponding decrease in the water saturation in the affected area.

②

The depressurization process is associated with a temperature decrease in the conventional NGH reservoir. This cooling is attributed to the endothermic nature of NGH decomposition, which absorbs heat from the surrounding formation, thus lowering the reservoir temperature.

③

Post decomposition, an increase in the formation permeability is noted. The decomposition process enlarges the contact area between particles, creating greater pore spaces and enhancing the formation porosity.

(2)

Analysis of the spatial characteristics in the replacement domain.

The replacement domain is located at the forefront of the injected gas, forming a relatively narrow band. Initially, this zone expands in a conical pattern; however, as the replacement process progresses, it assumes a sector-like shape. The vertical extent of the affected region gradually contracts, while the horizontal span widens. By the mid-to-late stages of the replacement process, the zone retains some vertical reach, although the horizontal extent remains more pronounced. As illustrated in Figure 6, Figure 10, Figure 11, Figure 12 and Figure 13, the observations indicate that NGHs within the replacement domain exhibit distinctive characteristics:

①

There is a gradual decrease in the concentration of NGHs, accompanied by a steady increase in the CO₂ hydrate concentration and a corresponding reduction in the water saturation. This shift is attributed to the thermodynamic stability of the CO₂ hydrate, which promotes replacement reactions with NGHs.

②

A significant increase in the formation temperature is observed within the replacement domain. The formation of the CO₂ hydrate is an exothermic process that releases more heat than the decomposition of the CH₄ hydrate absorbs, resulting in elevated temperatures in this region.

③

Additionally, a gradual decrease in the formation permeability is noted within the replacement domain. This reduction is due to the decreased contact area between particles following CO₂ hydrate formation, which narrows the pore spaces and consequently lowers both the porosity and permeability.

(3)

Analysis of the spatial characteristics of the gas competition zone.

In the initial phase of the replacement process, the gas competition zone is delineated by a conical shape that extends both horizontally and vertically. As the process progresses, this zone tends to widen laterally, while its vertical dimension remains relatively unchanged. Figure 6, Figure 10, Figure 11, Figure 12 and Figure 13 provide visual data that highlight the unique characteristics of this zone.

①

Within this region, CO₂ and CH₄ compete spatially; a decrease in the mole fraction of CO₂ is associated with an increase in CH₄, and vice versa. This interaction results from maintaining a constant bottom-hole pressure with a fixed total gas output, establishing a zero-sum dynamic between the two gases.

②

The mole fractions of CO₂ and CH₄ are influenced by temperature. At 10.5 °C, the mole fraction of CO₂ peaks, whereas CH₄ reaches its minimum. In contrast, at 8.6 °C, the minimum mole fraction of CO₂ and the maximum of CH₄ are observed. According to Figure 1, the conditions at 10.5 °C and 4.5 MPa correspond to Region C of the phase diagram, where the CO₂ hydrate phase is predominant. This suggests that CH₄ is more likely to replace the CO₂ hydrate, leading to higher CO₂ and lower CH₄ mole fractions. Conversely, at 8.6 °C and the same pressure, the conditions align within Region B, where NGHs predominate over the CO₂ hydrate. This implies that CO₂ is more likely to displace NGHs, reflecting the competitive gas interactions noted in this zone.

5.3. Effect of Gas Injection Rate

Cumulative production graphs for CH₄, CO₂, and water are depicted in Figures S2–S4 for varying gas injection rates. These figures establish a direct correlation between the gas injection rate of CO₂ and the cumulative production of CH₄, CO₂, and water. An increased gas injection rate results in earlier CO₂ breakthroughs at the production well. For example, at an injection rate of 1000 m³/d, cumulative CH₄ production totals 2 × 10⁶ m³, with negligible CO₂ production and a cumulative water production of 4800 m³. In contrast, at an injection rate of 10,000 m³/d, cumulative production escalates to 6.3 × 10⁶ m³ for CH₄, 5.5 × 10⁶ m³ for CO₂, and 8600 m³ for water, compared with an injection volume of 1.08 × 10⁷ m³.

Based on the data presented in Figure 14, it can be observed that during the initial 40 days of production, the methane-to-water ratio and methane yield remain consistent across various injection rates. This suggests that methane production during this phase is predominantly derived from methane released through the depressurization process. As the production period extends, the methane-to-water ratio tends to increase, yet it remains relatively stable at an injection rate of 1000 m³/d. At lower injection velocities, methane and water are produced in proportion, indicating that insufficient gas injection fails to effectively displace the methane. Upon integrating the data from Figure 14 and Figures S2–S4, it is evident that at an injection rate of 10,000 m³/d, while the methane production is maximized, the concurrent water production is also significantly higher. This leads to a decrease in the gas-to-water ratio in the later stages, which is conducive to the expulsion of methane from the reservoir in the later phases of production. Although a higher CO₂ injection rate can result in increased methane production, an excessive injection rate may cause the premature breakthrough of CO₂, thereby increasing the costs associated with subsequent gas separation. Consequently, the optimization of the injection rate is of paramount importance for enhancing the recovery rate of conventional natural gas hydrate reservoirs and reducing the costs of gas separation. The judicious selection of injection rates can balance methane production with water generation, prevent premature CO₂ breakthrough, and ultimately maximize economic efficiency.

5.4. Effect of CO₂ Temperature

Figures S5–S7 depict the cumulative production curves for CH₄, CO₂, and water under varying injection temperatures. The analysis of these figures reveals that the maximal cumulative volumes of CH₄ and CO₂ are obtained at an injection temperature of 10.15 °C, with volumes reaching 6.2 × 10⁶ m³ and 6.0 × 10⁶ m³, respectively. Notably, the second highest CH₄ production occurs at 5 °C, with subsequent decreases noted at 20 °C and 30 °C; the lowest production is observed at 0 °C. Additionally, a direct relationship exists between the injection temperature and CO₂ production, with elevated temperatures resulting in increased CO₂ production.

In the early stages of natural gas hydrate production, the influence of varying injection temperatures on methane yield is not significant, with the methane-to-water ratio and methane production remaining consistent over the first 100 days (Figure 15 and Figures S5–S7). This phenomenon suggests that during the initial production phase, the temperature of the injected carbon dioxide does not affect methane production. However, as the production process continues, the methane-to-water ratio exhibits a trend of increasing initially and then decreasing, with the curve at an injection temperature of 0 °C being notably higher than at other temperatures and its decline phase being shorter.

Further analysis indicates that the optimal injection temperature range for natural gas hydrates is 5–10 °C, with the effect of temperature on the displacement effect being complex. When the injection temperature is relatively high, the production well yields larger amounts of CO₂ and CH₄. Conversely, at lower injection temperatures, the production of CO₂ and CH₄ is smaller. The presence of a gas competition zone leads to a competitive relationship between CO₂ and CH₄, which under certain production pressure differentials, manifests as a “zero-sum” dynamic. Therefore, when the production well’s CO₂ yield is high, the CH₄ yield decreases, and vice versa. When the injection temperature is too low, the reaction rate slows down, limiting the ability to displace CH₄, which explains the lower methane production in the production well at an injection temperature of 0 °C.

In summary, the injection temperature has a significant impact on methane production and displacement effects. While the temperature has little effect on methane production in the initial stage of production, its influence on the methane-to-water ratio and production becomes apparent as the production time extends. Therefore, in practical operations, the injection temperature should be adjusted according to specific conditions to optimize methane production and displacement efficiency. This finding has important theoretical and practical significance for the efficient exploitation of natural gas hydrates.

5.5. Effect of Bottom-Hole Pressure

Figures S8–S10 illustrate the cumulative production curves for CH₄, CO₂, and water across different bottom-hole pressures. The analysis of these figure indicates an inverse relationship between the bottom-hole pressure and the cumulative production of CO₂ and CH₄, as well as water. Elevated bottom-hole pressures correlate with delayed CO₂ breakthroughs, whereas reduced pressures result in earlier breakthroughs at the production well. For example, at a bottom-hole pressure of 7 MPa, the cumulative production values measure 7.2 × 10⁵ m³ for CO₂, 5.1 × 10⁶ m³ for CH₄, and 6426 m³ for water. At 4 MPa, these values rise to 5.4 × 10⁶ m³ for CO₂, 6.2 × 10⁶ m³ for CH₄, and 9377 m³ for water. Notably, at the minimum pressure of 2 MPa, the cumulative CH₄ production escalates rapidly but is short-lived, enduring only 140 days due to enhanced decomposition.

From Figure 16, it is evident that as the bottom-hole pressure decreases, the slope of the methane-to-water ratio increases, indicating that the lower the bottom-hole pressure, the faster the decomposition rate of the natural gas hydrate. When the bottom-hole pressure was 2 MPa, methane production ceased by the 32nd day. This phenomenon arises from an insufficient interaction between the injected CO₂ and NGHs under low bottom-hole pressures, leading to premature migration towards the production well and early CO₂ breakthrough. In such cases, the depressurization effect dominates, increasing the cumulative outputs of CH₄ and water. Consequently, establishing an optimal bottom-hole pressure is essential when employing the CO₂ replacement method in NGH reservoir development to avert formation collapse and early CO₂ breakthrough.

6. Conclusions

This study represents a significant leap forward in the understanding of the CO₂ replacement of natural gas hydrates (NGHs), introducing innovative aspects and addressing key hot topics in the field. By employing a synergistic blend of experimental and numerical simulation methods, we have:

• Developed a groundbreaking conceptual model for CO₂-driven hydrate replacement, providing a robust framework to comprehend the complex kinetics of hydrate decomposition and CO₂ hydrate formation, which has been a major knowledge gap in the scientific community.
• Unveiled the optimal injection temperature range of 5–10 °C for standard NGH reservoirs, a critical parameter that maximizes CH₄ production efficiency and minimizes the environmental impact, offering practical guidance for real-world extraction operations.
• Highlighted the intricate relationship between the gas injection rate and the bottom-hole pressure, demonstrating their combined influence on CH₄ yield and presenting a balanced optimization strategy that enhances production and economic efficiency while reducing gas separation costs.
• Advanced the theoretical foundation for CO₂ replacement technology in NGH extraction, contributing to the ongoing discourse on unconventional gas resources and offering valuable insights for future research and development endeavors. This study’s innovative approach and focus on hot topics position it at the forefront of NGH research, paving the way for more efficient and sustainable energy extraction practices.