Experimental Simulation of the Self-Trapping Mechanism for CO₂ Sequestration into Marine Sediments

Abstract

CO₂ hydrates are ice-like solid lattice compounds composed of hydrogen-bonded cages of water molecules that encapsulate guest CO₂ molecules. The formation of CO₂ hydrates in unconsolidated sediments significantly decreases their permeability and increases their stiffness. CO₂ hydrate-bearing sediments can, therefore, act as cap-rocks and prevent CO₂ leakage from a CO₂-stored layer. In this study, we conducted an experimental simulation of CO₂ geological storage into marine unconsolidated sediments. CO₂ hydrates formed during the CO₂ liquid injection process and prevented any upward flow of CO₂. Temperature, pressure, P-wave velocity, and electrical resistance were measured during the experiment, and their measurement results verified the occurrence of the self-trapping effect induced by CO₂ hydrate formation. Several analyses using the experimental results revealed that CO₂ hydrate bearing-sediments have a considerable sealing capacity. Minimum breakthrough pressure and maximum absolute permeability are estimated to be 0.71 MPa and 5.55 × 10⁻⁴ darcys, respectively.

1. Introduction

Carbon capture and storage (CCS) technology is essential for rapid CO₂ mitigation. The geological storage of carbon dioxide (CO₂) is a highly effective, long-term mitigation solution for the large quantities of CO₂ emissions [1,2]. For these reasons, to date, CO₂ geological sequestration (CGS) technology has been developed by several leading countries. However, most of existing CGS methods worldwide require particular geological structures to work, such as a highly pervious rock formation (e.g., sandstone layer) imbedded in impermeable layers (i.e., cap-rocks). This requirement leads to CGS application difficulties such as a shortage of proper sites, challenges in the long-range transport of CO₂, deep drilling and injection, and restricted storage capacity, which substantially increases the cost of using CGS. To overcome these limitations, several CGS methods that do not need cap-rock, such as carbonated water injection (CWI), have been suggested [3,4,5,6].

CO₂ can be stored in unconsolidated sediments under CO₂ hydrate-bearing sediments. CO₂ hydrates are ice-like solid lattice compounds composed of hydrogen-bonded water cages that encapsulate guest molecules of CO₂. CO₂ hydrates are formed in the seabed under low temperatures and high pressures [7,8]. Previous studies on natural gas hydrate-bearing sediments [9] and preliminary studies on CO₂ hydrate-bearing sediments [10,11] have shown that CO₂ migration is significantly hampered by the formation of gas hydrates, resulting in a self-trapping mechanism. Furthermore, the self-preservation response of CO₂ hydrates slows the CO₂ hydrate dissociation process [12], which serves to mend unintended fractures of CO₂ hydrate-bearing sediments, thereby severely diminishing the transport of CO₂ fluids [13,14]. Thus, it has been suggested that CO₂ hydrates can be used as primary or secondary safety factors for CO₂ geological storage in marine unconsolidated sediments [15,16,17]. Furthermore, unconsolidated sand sediments have advantages over consolidated rocks (e.g., sandstones) in that the CO₂ storage capacity of the former is higher than that of the latter due to the high porosity of unconsolidated sandy sediments (40–60%). In addition, the CO₂ injectability of unconsolidated sand sediments is superior because of their high permeability (0.1–10 darcys) resulting from wide and well-connected pore spaces.

Tohidi et al. (2010) performed experimental CO₂ leakage simulations through each type of unconsolidated sediment (glass-bead, sand, and sand–clay mixture), and using electrical resistance measurements and a CO₂ concentration analysis they confirmed the existence of the self-trapping effect of CO₂ hydrates [11]. Massah et al. (2018) demonstrated the sequestration of CO₂ through horizontal injection into a laboratory scale reservoir and revealed the large storage density of CO₂ hydrate formations [18]. Gauteplass et al. (2018) described CO₂ hydrate formation caused by liquid CO₂ injection into cold, water-saturated sandstone and reported that hydrate formation in the pore space resulted in blockage of CO₂ flow under most conditions [19]. However, more direct and comprehensive experimental data including temperature–pressure relations, elastic wave velocity, and dissociation tests are required for a better understanding of the behavior of CO₂ and CO₂ hydrate formation in unconsolidated sediments.

The objective of this study was to simulate CO₂ geological storage into marine unconsolidated sediments using CO₂ hydrates as a cap-rock. A large reaction cell was used to experimentally verify the CO₂ self-trapping mechanism in marine sediments and to evaluate the behavior of CO₂-stored unconsolidated sediment during CO₂ hydrate formation and dissociation.

2. Experimental Program

2.1. Soil Used

The strata of unconsolidated marine sediments typically consist of multiple layers of a different sediment types such as sand-rich sediment layers and fine-grained sediment layers. The permeability of fine-grained sediments is very low (i.e., 10⁻³–10⁻⁷ darcys; [20]), therefore, fine-grained sediments can be practically considered as impermeable layers, which obstruct the upward flow of CO₂. Meanwhile, sand-rich sediments are suitable as CO₂ storage host sediments because of their relatively high permeability (0.1–10 darcys), while they are ready for permeation of CO₂. The effect of the self-trapping mechanism on a sand-rich layer is, therefore, important to CO₂ geological storage into unconsolidated sediments. In this study, fine sand (Ottawa F110; mean particle size = 120 μm, specific gravity = 2.65, permeability = 5–6 darcys, quartz 99%) was used as the host sediment sample.

2.2. Experiment Setup

The experimental design simulated CO₂ injection into a shallow marine sediment (i.e., high water pressure, low temperature) and CO₂ hydrate formation. The experimental design used in this study is shown in Figure 1. A cylindrical and rigid-wall reaction cell was made of an aluminum alloy (duralumin, AA2024). The inner diameter of the cell was 20 cm, the height of the interior was 100 cm, and the internal volume was 31.4 L. The reaction cell was originally developed for an experimental simulation of thermal stimulation on gas hydrate-bearing sediments [21]. Water and liquid CO₂ were injected from the bottom of the reaction cell using a water pump and gas booster. Pressure inside the reaction cell was controlled using a back-pressure regulator at the top of the cell. The quantities of CO₂ gas and water that flowed out of the reaction cell were measured using a water substitution system.

Various types of sensors were installed at predetermined layers (every 10 cm) within the reaction cell as shown in Figure 2. The cell contained five T-type thermocouples for temperature measurements of the cell interior, five pressure transducers for fluid pressure measurements, five pairs of piezoelectric ceramic disks (diameter: 20 mm) for compressional wave (P-wave) measurements at layers A1–A5, and four pairs of electrodes for electrical resistance measurements at layers B1–B4. For P-wave velocity measurements, square-shaped pulses with amplitude of 10 V (peak-to-peak) were used for excitation, and the input frequency ranged from 1 to 10 kHz. The electrodes were connected to an LCR meter in order to measure the electrical resistance (frequency = 50 kHz).

Cool water was circulated through copper tubes that coiled around the reaction cell. The temperature inside the reaction cell was controlled by two water coolers, which had different temperatures (i.e., Water cooler 1 at 3 °C, and Water cooler 2 at 15 °C). Figure 3 shows the temperature gradient of the inside of the reaction cell, which was formed by two separated cooling systems. The CO₂ hydrate stability zone was developed in the middle part of the reaction cell (i.e., height of 0.35–0.75 m in the reaction cell).

2.3. Experimental Procedure

The experiment involved three procedures: (1) The preparation of a water-saturated sample; (2) the injection of the CO₂ liquid; and (3) the depressurization of the cell. When the CO₂ liquid was injected from the bottom of the cell, the injected CO₂ moved upward in the water-saturated sediment sample due to its buoyancy. Then, CO₂ hydrates formed within the CO₂ hydrates stable zone, which was located at the middle part of the cell (refer to Figure 3). The depressurization test was performed after CO₂ hydrate formation to evaluate the behavior of CO₂ during hydrate dissociation. These procedures are detailed within this subsection.

2.3.1. Water-Saturated Sample Preparation

To simulate deep-marine sediments, a water-saturated fine sand (i.e., Ottawa F110 sand) sample was prepared. First, the sample was mixed with distilled water and packed into the cell by hand tamping. The cell was fully filled with moist sand and the porosity of the sample was 0.40. Then, the cell was slowly flushed with distilled water at pressure of ~0.5 MPa for several hours to remove remaining air bubbles. During the water flushing, a cooling process was initiated. After the completion of water flushing, the cell was pressurized to 5.5 MPa with distilled water and left for about 16 h to stabilize the temperature throughout the sample.

Our primary goal was to study the self-trapping effect induced by CO₂ hydrates, and because of that, distilled water was used as pore water instead of saline water (it allows easier hydrate formation). However, this decision means that the electrical and geochemical behavior in this experiment was different from the real behavior in the marine sediments.

2.3.2. Injection of CO₂ Liquid

Liquid CO₂ was introduced into the cell from the bottom using the gas booster. The injection pressure was 5.6 MPa, and the backpressure at the top of the cell was 5.0 MPa. Thirty-four hours later, the injection pressure and backpressure increased to 6.2 and 5.6 MPa, respectively. The CO₂ liquid was injected for more than 17 days while the temperature, pressure, P-wave velocity, and electrical resistance were measured. The formation of CO₂ hydrates during the CO₂ injection process was expected (refer to Section 3).

2.3.3. Depressurization

The cell was depressurized stepwise using a back-pressure regulator while the inlet valve was closed. Each depressurization step was 0.5 MPa for more than 16 hours. Temperature, pressure, P-wave velocity, and electrical resistance during the depressurization process were measured in the same manner as during CO₂ injection process.

3. Experimental Results

3.1. Liquid CO₂ Injection Process

When the CO₂ liquid was injected from the bottom of the cell, a CO₂ liquid plume moved upward because of a buoyancy force. Eventually, the CO₂ liquid front reached the CO₂ hydrate stability zone, and then CO₂ hydrates formed. The CO₂ hydrate-bearing sediment layer then obstructed the upward flow of the CO₂ liquid. While water and CO₂ were consumed in the CO₂ hydrate formation process in the hydrate stability zone, the CO₂ hydrate-bearing sediment layer prevented CO₂ supply. Thus, a pressure difference between the upper and lower part of the cell appeared. The P-wave velocity and electrical resistance monitoring results indicated the formation of CO₂ hydrates and the blockage of the CO₂ flow. Detailed experimental results are shown in the following sections.

3.1.1. Temperature and Pressure

Figure 4 shows the pressure of each layer in the cell over time. The CO₂ liquid was injected at 1300 min after data logging started. The pressure in each layer was scattered until 5000 min because of a difference in pressure between the injection pressure and backpressure (i.e., ~0.6 MPa, refer to Section 2.3.2), and volume change of pore fluids due to CO₂ dissolution into pore water. The pressure in each layer was very similar to one another because the pore space was well connected throughout the sample. CO₂ hydrates started to form when the injected CO₂ reached the CO₂ hydrate stability zone (herein, between layers A3 and A4; Figure 3). Then, the pressure in layers A1, A2, and A3 rapidly dropped to 3.3 MPa after 5000 min while the pressure of layers A4 and A5 were nearly constant and identical to the injection pressure. The difference in pressure between the upper and lower part of the cell was induced by the sealing (i.e., pore clogging) effect of the CO₂ hydrate bearing-sediments layer.

The sealing capacity of the CO₂ hydrate-bearing sediment layer gradually increased during the growth of CO₂ hydrates in the pore space of the sample. Meanwhile, water and CO₂ were consumed during CO₂ hydrate formation. For a constant-volume process, the consumption of CO₂ and water during CO₂ hydrate formation leads to a pressure decrease because the molar volume of the CO₂ hydrates is smaller than the original molar volume of the consumed fluids. For the lower part of the cell (represented by layers A4 and A5) the pressure was preserved because CO₂ was supplied continuously from the bottom of the cell during the experiment. For the upper part of the cell (represented by layers A1, A2, and A3), however, the pressure decreased because the CO₂ hydrate-bearing sediment layer prevented the CO₂ to be supplied from the lower part of the cell.

Figure 5 shows the pressure–temperature evolution during the CO₂ injection test. Note that layers A2 and A3 were in the CO₂ hydrate stable condition while the others were not. The pressure of the upper part of the cell (i.e., layers A1, A2, and A3) decreased when the sealing capacity of the CO₂ hydrate-bearing sediment layer increased to a level that prevented flow. Note that there were no CO₂ hydrates in layer A2 because the injected CO₂ did not reach it, even though this layer is in the CO₂ hydrate stability zone. Meanwhile, the lower part of the cell (i.e., layers A4 and A5) maintained a constant pressure level. Then, the pressure of the upper part of the cell gradually increased. There are two mechanisms for the pressure recovery of the upper part of the cell: (1) The uppermost CO₂ hydrates dissociated with the pressure decrease. Therefore, pressure was recovered restrictively via emitted CO₂ and water from the CO₂ hydrates, and (2) CO₂ hydrate saturation is limited by capillary pressure, which is determined by the pore size [23].

In the central part of the CO₂ hydrate-bearing sediment layer, CO₂ hydrates grew until the CO₂ hydrate saturation reached maximum CO₂ hydrate saturation. Thus, the consumption of CO₂ and water diminished because any additional formation of CO₂ hydrates was restricted. Finally, the pressure of the upper part of the cell increased to 5.2–5.5 MPa. However, the pressure of the upper part of the cell was still lower than that of the lower part of the cell. The repetitive ascending and descending pressure could be due to the continuous repetition of the CO₂ formation and dissociation process at the CO₂ hydrates front.

3.1.2. P-Wave Velocity

Figure 6 shows the results of the P-wave velocity measurements during the CO₂ injection process. Before the water injection process, the cell was partially saturated, and the P-wave velocity was about 900 m/s. When the sediment sample was saturated by distilled water, the P-wave velocity of all the layers was about 1600 m/s. Then, when the CO₂ liquid was injected, the P-wave velocities of the lower part of the cell (i.e., layers A4 and A5) decreased because the bulk modulus of the CO₂ liquid was much lower than that of the water [24,25]. Meanwhile, the P-wave velocity of layer A3 gradually increased because of the stiffening effect induced by CO₂ hydrate formation. This P-wave velocity increase in layer A3 indicates that the CO₂ hydrate bearing-sediment layer is between layers A3 and A4. On the other hand, the P-wave velocity of layer A1 and A2 did not change during CO₂ injection. This is evidence that the CO₂ hydrate-bearing sediment layer prevents any upward flow of the CO₂ liquid.

3.1.3. Electrical Resistance

Figure 7 shows the normalized electrical resistance (R/R₀) during the CO₂ injection process, where R is the measured electrical resistance and R₀ is the initial electrical resistance of the distilled water-saturated sample at each layer (i.e., layers B1–B4). For the lower part of the cell (i.e., layers B3 and B4), the electrical resistance decreased with CO₂ injection because of the dissolution of CO₂.

Electrical resistance increased in-situ in the marine sediments because the conductive pore water (i.e., brine) was replaced by CO₂, which is a nonpolar molecule. This electrical resistance increase induced by the CO₂ replacement was weakened by the dissolution of CO₂ and the surface effect of the mineral grains [26]. For typical brine, the effect of CO₂ dissolution on electrical resistance is negligible because the concentration of salt (i.e., NaCl) is much larger than the ionic concentration increased by CO₂ dissolution [27]. However, if the salt concentration is low (e.g., onshore sediments), electrical resistance of in-situ sediments can decrease during the CO₂ permeation [28]. In this experiment, the effect of dissolved CO₂ was dominant on electrical resistance because the pore water was distilled.

Meanwhile, the electrical resistance of the upper part of the cell (i.e., layers B1 and B2) showed minor changes during CO₂ injection. This is additional evidence demonstrating that CO₂ liquid did not reach the upper part of the cell. Based on the change of the pressure, P-wave velocity and electrical resistance, we can presume that the CO₂ hydrate formation front is located between layers A3 and B3. Meanwhile, CO₂ hydrates formation was not observed in the electrical resistance data. The electrical resistance of in-situ water-saturated sediments increased when CO₂ hydrates formed because the electrical resistance of CO₂ hydrates is higher than pore water [29,30]. In this study, however, the change in electrical resistance was insignificant in spite of the presence of CO₂ hydrates, because distilled water was used as pore water in this experiment. This is the one of the limitations of this experiment.

3.2. Depressurization Process

3.2.1. Temperature and Pressure

Figure 8 shows the pressure of each layer in the cell over time. The pressure of the cell was reduced step-wise using a back-pressure regulator. Pressure differences between the upper and lower part of the cell remained, even though CO₂ was vaporized. This pressure discrepancy indicated that the sealing capacity of the CO₂ hydrate-bearing sediment layer was preserved. When the CO₂ hydrate dissociated completely, the pressure of each layer became equal.

Figure 9 shows the pressure–temperature relationship during the depressurization test. The pressure of the cell dropped with the pressure release using the back-pressure regulator. When the pressure of layers A4 and A5 reached the CO₂ vapor pressure, their pressure and temperature relation moved along the CO₂ vapor pressure (Figure 9a). The path of the pressure and temperature relationship of layers A4 and A5 was similar to that of the isometric process because the flow of fluids was obstructed by the remaining CO₂ hydrate-bearing sediment layer (Figure 9b). Then, the pressure and temperature relationship of layer A2 moved along the CO₂ hydrate equilibrium line (Figure 9c). This is evidence that the CO₂ hydrates re-formed and dissociated in layer A2. In the previous CO₂ injection process, CO₂ liquid did not reach layer A2 because of the sealing effect of the CO₂ hydrate-bearing sediment layer, which was located between layers A3 and B3. However, CO₂ was supplied to layer A2 when the existing CO₂ hydrates partially dissociated by depressurization. CO₂ hydrates then re-formed because layer A3 is in the CO₂ hydrate stability zone. Then, CO₂ hydrates in layer A3 dissociated by additional depressurization. During the dissociation of CO₂ hydrates in layer A3, a self-preservation effect was observed in the pressure and temperature relationship as seen in previous experimental studies on CO₂ hydrate dissociation [12,31]. Finally, CO₂ hydrates completely dissociated with step-wise depressurization (Figure 9d).

3.2.2. P-Wave Velocity

Figure 10 shows the results of the P-wave velocity measurements taken during the depressurization process. The sealing effect of the original CO₂ hydrate-bearing sediment layer reduced because some portion of the original CO₂ hydrates dissociated. Thus, the P-wave velocity of layer A1 decreased because CO₂ intruded the upper part of the cell. On the other hand, the P-wave velocity of layers A2 and A3 suddenly increased because CO₂ hydrates formed using the CO₂ supply from the lower part of the cell. Note that layers A2 and A3 were in the CO₂ hydrate stability zone until 3300 minutes (refer to Figure 9). Meanwhile, the P-wave velocity of layers A4 and A5 decreased because CO₂ vaporized during depressurization. When the pressure was lower than the equilibrium pressure of the CO₂ hydrates (i.e., 4000–6000 min, refer to Figure 9d), the P-wave velocity of layers A2 and A3 suddenly decreased because reformed CO₂ hydrates in these layers dissociated.

3.2.3. Electrical Resistance

Figure 11 shows the normalized electrical resistance (R/R₀) during the depressurization process. The results of the electrical resistance measurements indicated that CO₂ intruded the upper part of the cell. For layers B1 and B2, electrical resistance exhibited complex behavior due to the formation of CO₂ hydrates and the movement of CO₂ gas bubbles. However, the electrical resistance decreased generally because of CO₂ dissolution. As stated before, electrical resistance of distilled water-saturated sediment decreased with CO₂ intrusion because of dissolved CO₂. Meanwhile, the electrical resistance of the lower part of the cell (i.e., layers B3 and B4) was barely affected by depressurization because the pore water of the lower part of the cell was already saturated by dissolved CO₂.

4. Discussion: Simple Analysis on the Sealing Capacity of CO₂ Hydrate-Bearing Sediments

There are two major sealing mechanisms for CO₂ structural trapping. One is the capillary seal, which occurs by capillary pressure between CO₂ and water in pores. The other sealing mechanism is the permeability seal, which is related to the laminar flow velocity of CO₂ in pores due to a pressure gradient. In view of the two sealing mechanisms, a simple analysis on the sealing capacity of the CO₂ hydrate-bearing sediment was performed using the experimental results.

4.1. Capillary Sealing Capacity

Capillary pressure is the difference in pressure across the interface between two fluids. In petroleum reservoirs, capillary pressure between oil and water in rock pores is responsible for trapping oil [32,33]. In the same manner, capillary pressure between water and CO₂ can trap CO₂. For a given pore structure, the CO₂ breakthrough pressure (P_C^*) induced by capillarity can be described using the Young–Laplace equation:

$${P_C}^{*}=\frac{4\gamma cos\theta }{d^{*}},$$

(1)

where γ is interfacial tension between water and CO₂, θ is wetting angle, and d^* is the critical pore throat diameter. Several researchers have measured various temperatures and pressures for the interfacial tension between water and CO₂ [34,35,36].

In this study, the CO₂ hydrate-bearing sediment layer could maintain about 0.71 MPa of pressure difference between the upper and lower part of the cell (Figure 12). Thus, the minimum breakthrough pressure (P_C^*_min) can be assumed as the average pressure difference between the upper and lower parts of the cell (ΔP_average), which is described in Figure 12 (i.e., P_C^* ≥ P_C^*_min = ΔP_average). Then, the maximum critical pore throat diameter of CO₂-hydrate bearing sediments (d*_max) was calculated as 132 nm using Equation (1). The values used in this calculation are summarized in

Table 1. Assumed values for the calculation of d_max.

Coefficient	Value	Remark
γ	25 × 10−3 N/m	At a pressure of 6 MPa and temperature of 15 °C [35]
θ	20°	At a pressure of 6 MPa and temperature of 15 °C, on quartz [35]

.

If the pressure difference between the fluid interface exceeds P_C^*, then CO₂ breaks through the interface, and laminar flow occurs [35,37,38]. Thus, in order for the capillary sealing mechanism to work, the breakthrough pressure (P_C^*) must be larger than the buoyancy pressure of the CO₂ plume. The buoyancy pressure (P_B) that is induced by the density difference between water and CO₂ can be described as

$$P_B=gh\left({\rho }_{water}-{\rho }_{C{O}_2}\right),$$

(2)

where g is the acceleration of gravity, h is the thickness of the CO₂-stored layer, and ρ_water and ρ_CO2 are the density of water and CO₂, respectively. In a similar manner to the calculation of d*_max, the minimum buoyancy pressure (P_Bmin) which could be maintained by the CO₂ hydrate-bearing sediment can be assumed as ΔP_average (i.e., P_B ≥ P_Bmin = ΔP_average). At a similar thermodynamic condition of the experiment in this study (i.e., pressure of 6 MPa and temperature of 15 °C), ρ_CO2 was 784 kg/m³ [39]. Then, the minimum thickness of the CO₂-stored layer (h_min) was calculated as 335 m according to Equation (2). Thus, we can presume that the capillary trapping capacity of the CO₂ hydrate-bearing sediment is high enough.

The wettability (i.e., wetting angle) could be altered by the increase of the gas hydrate saturation because the solid materials contacting pore fluids are changed from sand particles to CO₂ hydrates. For simplicity, this wettability alteration was not considered in this study. Further studies are required to evaluate the effect of wettability iteration on CO₂ capillary sealing capacity.

4.2. Permeability Sealing Capacity

When the buoyancy pressure (P_B) is higher than breakthrough pressure (P_C^*), CO₂ flow occurs. Fluid flow through soils finer than coarse gravel is laminar [40]. For laminar flow in CO₂-saturated sediments the flow velocity, v, can be expressed by Darcy’s law as follows:

$$\nu =K\frac{{\rho }_{C{O}_2}g}{{\mu }_{C{O}_2}}i,$$

(3)

where K is absolute or intrinsic permeability of the sediments, ρ_CO2 is the density of CO₂ fluids, g is the gravity constant, μ_CO2 is the viscosity of CO₂ fluids, and i is the hydraulic gradient which is expressed by the difference between two hydraulic heads over the flow length. Note that the hydraulic gradient (i) is 1 for a vertical flow. Meanwhile, the average flow velocity for flow through a round capillary tube (v₀) can be described by Poiseuille’s law as follows:

$${\nu }_0=\frac{{\rho }_{C{O}_2}g{d}^2}{32{\mu }_{C{O}_2}}i,$$

(4)

where d is the diameter of the capillary tube. The flow velocity determined by Poiseuille’s law (v₀) is the upper limit of the flow velocity (i.e., v ≤ v₀) in porous media because flow velocity in sediments decreases by the tortuosity of the flow channel. Therefore, the upper limit of the absolute permeability of sediments can be defined using Equations (3) and (4) as

$$K\le \frac{d^2}{32}.$$

(5)

The maximum absolute permeability of CO₂ hydrate-bearing sediment (K_max) can, therefore, be calculated using the d^*_max, which was obtained before. K_max is about 5.55 × 10⁻⁴ darcy. This value is similar to the permeability of fine-grained sediments (i.e., 10⁻³–10⁻⁷ darcys [20]), and can be considered as “very low” permeability [41].

4.3. Comparison with Other Materials

Estimated maximum absolute permeability (K_max) and minimum breakthrough pressure (P_C^*_min) are compared with measured absolute permeability (K) and breakthrough pressure (P_C^*) of various sediment samples, as shown in Figure 13. We presumed that the breakthrough pressure of F110 sand increases by more than 10² times with CO₂ hydrate formation. The minimum breakthrough pressure (P_C^*_min) of the CO₂ hydrate-bearing sediments estimated in this study is comparable with that of unconsolidated clays and the shale sample. Meanwhile, the actual P_C^* of CO₂ hydrate-bearing sediments in this experimental simulation may be higher than the estimated P_C^*_min because the latter was estimated conservatively using the pressure difference between upper and lower parts of the cell, instead of being measured directly. In the same manner, actual K of CO₂ hydrate-bearing sediments in this experimental simulation may be lower than estimated K_max. This might be attributed to the K_max being calculated conservatively using the assumption of fluid flow in a round capillary tube without any tortuosity. To determine the range of absolute permeability and breakthrough pressure of CO₂ hydrate-bearing sediments, further experimental studies are required.

5. Conclusions

We performed an experimental simulation of CO₂ geological storage in marine unconsolidated sediments in this study. CO₂ hydrates were formed during the CO₂ liquid injection process, and we observed the self-trapping effect of CO₂ hydrates. In addition, simple analyses were conducted using the experimental results. The feasibility of CO₂ geological storage in marine unconsolidated sediments was experimentally verified using 1-m-height high-pressure cell. CO₂ hydrates instantly formed in the unconsolidated sediments with CO₂ introduction, and prevented any upward leakage of CO₂. The main findings are summarized as follows:

• CO₂ hydrates formed in the CO₂ hydrate stability zone of the cell during the CO₂ liquid injection process. The CO₂ hydrate-bearing sediment layer prevented any upward flow of CO₂. This self-trapping effect was confirmed by monitoring pressure, P-wave velocity, and electrical resistance.
• The original CO₂ hydrates partially dissociated during the depressurization process, and additional CO₂ hydrates instantly formed in the upper layer, which was in the CO₂ hydrate stability zone. When CO₂ hydrates dissociated, CO₂ hydrates could re-form in the upper layer (i.e., cooler layer for marine sediments) instantly. This behavior is a positive characteristic of CO₂ hydrates for use as cap-rock in CGS applications.
• The CO₂ hydrate-bearing sediment layer maintained a pressure of 0.71 MPa during the experiment. Simple analyses revealed that the capillary and permeability sealing capacity of CO₂ hydrate-bearing sediments are considerably high.

Permeability and breakthrough pressure of CO₂ hydrate-bearing sediments depend on the saturation of CO₂ hydrates in the pore system. However, CO₂ hydrate saturation was not analyzed in detail in the present study, as sufficient information regarding maximum CO₂ hydrate saturation via experimental simulation was lacking. We expect that a geophysical analysis using experimental data from a denser sensor array could overcome this limitation. Meanwhile, the electrical and geochemical behavior of the CO₂-containing sediments in this study was different from that in real marine sediments because distilled water was used as pore water instead of saline water. To overcome this limitation, an experiment using saline water will be performed for further study.