An Innovative Solution Method for the Evaluation of CO2 Disposal in the Seafloor Environment

Abstract

Injecting carbon dioxide (CO₂) into underground geo-structures, such as depleted oil and gas reservoirs, reduces man-made CO₂ emissions into the atmosphere or removes what is already there. Studies have identified the risks of CO₂ leaks from these underground geo-structures through wellbores back into the atmosphere due to the high mobility of CO₂ in gaseous and supercritical states. This work aims at proposing a novel method of CO₂ storage using the Joule–Thomson cooling effect to effectively produce CO₂ hydrates on seafloors, with an objective to avoid the leakage risks of storage in depleted oil and gas reservoirs. Through the combination of thermodynamic data, analysis of hydrate stability, and engineering design with established working parameters, this study proposes an innovative concept and an enabling process for CO₂ placement onto seafloors for safe storage. The results of case analysis of typical seawater conditions reveal that the appropriate seafloor depth ranges for different applications (>1900 m for liquid CO₂ and 700–1900 m for CO₂ hydrate). An engineering design procedure for real applications is outlined.

1. Introduction

The geological storage of carbon dioxide (CO₂) is considered a major approach for reducing carbon content in the Earth’s atmosphere. Depleted oil and gas reservoirs are widely used as geological structures for CO₂ storage [1]. A major advantage of using depleted oil and gas reservoirs as CO₂ storage is the elimination of the cost of drilling new wells. Another advantage of oil and gas reservoirs is their high injectivity and high volumetric efficiency due to their high permeability and porosity. A disadvantage of using these wells is the risk of CO₂ leak through wellbores due to the high corrosivity and mobility of CO₂ in gaseous, liquid, and supercritical states [2,3,4]. Studies have shown that the risk of CO₂ leakage from subsea geological structures is lower than from onshore oil and gas reservoirs due to the low mobility of CO₂ in the liquid state in the former environment [5]. The pioneer process of CO₂ storage in the subsea water zone is the Sleipnir project in the Norwegian Sea [6]. Another example process is the Hokkaido project [7,8,9].

Several new offshore CCS projects are underway globally, including developments in the Gulf of Mexico, Europe, and Australia. These projects aim to permanently store captured CO₂ in depleted offshore reservoirs or saline aquifers. Large representative projects include the GeoDura Carbon Storage Hub project [10] and ExxonMobil’s Texas project [11] in the Gulf of Mexico region, and the Aramis project [12], the Bacton Thames Net Zero project [13], the Green Sands project [14], and the L10 project [15] in Europe.

Recent studies on offshore carbon capture and storage (CCS) have revealed great challenges [16]. Offshore CCS projects are costly and largely dependent on public subsidies. Similarly to onshore CCS, offshore CCS has been repeatedly proven to fail. Most flagship CCS projects have fallen short of their promised storage targets or failed to move forward due to cost overruns. From the 1990s and into the late 2010s, companies launched various projects in different parts of the world that installed carbon capture equipment at polluting facilities with plans to inject the captured CO₂ underground [17]. Some of these projects planned to use the captured CO₂ for EOR, extracting more hydrocarbons while purporting to provide “clean” energy [18]. Others sought to inject emissions underground for “permanent” storage [19]. But despite these efforts, most CCS projects have been abject failures, falling dramatically short of their capture targets or hitting cost overruns that made them financially unviable [17]. Offshore CCS using depleted oil and gas reservoirs also leads to potential CO₂ leaks. The single biggest risk of CO₂ leakage comes from the interaction of injected CO₂ with legacy oil and gas wells. Generally, CO₂ leaking from sub-seabed reservoirs risks harming benthic creatures and their habitats. Dissolved CO₂ causes seawater to become more acidic, which can damage marine ecosystems in the vicinity of the leak [17]. Also, if CCS is widely deployed onshore and offshore, even a 0.1 percent leakage rate could cause up to 25 gigatonnes of additional CO₂ emissions in the 21st century, posing a major risk to the climate [20]. Injecting CO₂ under the seabed presents uncalculated risks and untested monitoring challenges.

After years of plundering the seas for oil and gas, the fossil fuel industry now plans to use the ocean floor as the final dumping ground for its waste. CO₂ can exist in the form of gas hydrates, which have no mobility or corrosivity. Li et al. [21] pointed out that CO₂ leakage during long-term sub-seabed sequestration can be prevented by CO₂-hydrates. Gas hydrates are solids where small-molecule gases are trapped inside the cages of water molecules in high-pressure and low-temperature conditions [22]. Numerous researchers have studied the formation of gas hydrates in static conditions in the past, both experimentally and theoretically. The kinetics of the formation of gas hydrates was formulated by Englezos et al. [23]. Gas hydrate formation rate was found to be directly proportional to the hydrate crystal particle area and the difference between the gas fugacity at the in situ condition and the gas fugacity at the three-phase equilibrium conditions. Englezos et al.’s formula was modified by Skovborg and Rasmussen [24] by replacing the particle area with a crystal film during hydrate formation. Chemical potential difference was used as the driving force for hydrate formation by Mohebbi [25] and Kashchiev [26]. The driving force was defined as the temperature difference between the equilibrium and testing conditions by Vysniauskas and Bishnoi [27], while it was defined as the pressure difference between the equilibrium and testing conditions by Natarajian [28]. Based on the knowledge accumulated in the past decades, the conditions (pressure and temperature) for CO₂ hydrate formation are accurately predictable. CO₂ hydrate formation pressure and temperature under static conditions are given by Sloan and Koh [22].

CH₄-CO₂ swapping is a process of CO₂ storage where one CO₂ molecule replaces one CH₄ molecule in natural gas reservoirs without destroying the hydrate structure. The process reduces the possibility of matrix collapse and stratum failure in the natural gas reservoirs [29,30]. This process can lock the CO₂ in the reservoir permanently with a low probability of leaking into the atmosphere. Pilot studies have been conducted over a decade [31,32,33]. All these studies concluded that the swapping efficiency for CH₄ production and CO₂-storage is low due to the mass transfer barriers caused by the formation of CO₂-hydrates without external energy added to delay the formation of CO₂-hydrates.

Previous studies also proposed storing CO₂ in hydrate (solid) forms in subsea formations where the geological temperatures are below the hydrate-forming temperature of CO₂ [34,35]. This can greatly reduce the leak probability because CO₂ is locked inside its hydrates, eliminating the problems of its high corrosivity and high mobility. However, the efficient placement of CO₂ in the formation is a big issue. The low injectivity of CO₂ into the formations is due to the low permeability of the formations (normal silt-sand) [36]. Use of radial-lateral wells for placing CO₂ in marine gas hydrate reservoirs may partially solve the injectivity problem, but it will induce additional cost of well drilling [37]. In this case, CO₂ can form hydrates in the formations during injection, which reduces injectivity [38]. Although using geothermal energy to enhance natural gas production from gas hydrate reservoirs by CO₂ swapping can be a long-term solution to the injectivity problem [39], a significant amount of initial investment is required.

This study proposes an innovative process to permanently store CO₂ in solid form on the sea floor to solve the problems of injectivity and risk of CO₂ leakage. Site selection criteria and required technologies are discussed.

2. Identification of Suitable Seawater Depths

This section describes the required pressures and temperatures for stable CO₂ hydrates: seawater temperature, and densities of seawater, CO₂ liquid, and CO₂ hydrates. The favorable seawater depths for the disposal of CO₂ will be identified accordingly.

CO₂ Hydrate Forming Condition. Figure 1 presents a contour map of pressure and temperature for stable CO₂ hydrates as compared to that of methane hydrates [40]. This graph was established for CO₂ in fresh water under pressure and temperature conditions. Considering the effect of seawater salinity on CO₂ hydrate stability, the curves should be shifted to the left slightly to determine the required pressure for stable CO₂ hydrates in seawater.

Temperature of Sea Water. Previous investigations show variations in the ocean’s temperature and salinity with latitude [41,42]. The temperatures of the sea surfaces around these oceans are similar. Figure 2 shows an example of variation in ocean water temperature with depth [42]. In low-altitude regions, the surface layer water is an epipelagic zone, also called the sunlight zone, extending from the surface to about 200 m (660 feet). Most of the sunlight is visible in this zone, where the sea surface temperature is as high as 97 °F (36 °C) in the Persian Gulf. In high-altitude regions, the sea surface temperature is as low as 28 °F (−2 °C) near the North Pole. Below the epipelagic zone is the mesopelagic zone (twilight zone or the midwater zone), which extends from about 200 m (660 feet) to about 1000 m (3300 feet). Water temperature decreases rapidly with increasing depth. The depth of the thermocline varies seasonally.

Guo and Mahmood [44] proposed a symmetric model for the seawater temperature profile. The symmetric model was modified in our study to obtain an asymmetric model as follows:

(1)$t=t_b+{\displaystyle \frac{t_0-t_b}{2}}\left[2-\left[1+\mathrm{erf}\left(2\left[{\left({\displaystyle \frac{D}{D_m}}\right)}^{\alpha }-1\right]\right)\right]\right]$

where t is water temperature at depth of interest in °C, t₀ is the seasonal-averaged water temperature at sea surface in °C, t_b is the stable water temperature below the mesopelagic zone in °C, erf is Error function, D is water depth of interest in meters, D_m is the water depth at the mid-point of the mesopelagic zone, and a is a tuning factor for asymmetry which is determined by minimizing the root mean square error (RMSE) defined by

(2)$E_r=\sqrt{{\displaystyle \frac{\sum _1^n{\left(t_{x,i}-t_{m,i}\right)}^2}{n-1}}}$

where E_r is the RMSE, t_x is measured water temperature in °C, t_m is modeled water temperature in °C, and n is the number of data points. The RMSE of Equation (1) for the data in Figure 1 was found to be 0.31 with a = 1.19. Figure 3 shows a comparison of the data given in Figure 1 and that by Equation (1).

Density of Seawater, CO₂ Liquid and CO₂ Hydrates. The data presented by Klemm et al. [42] shows that seawater density depends on seawater temperature at a particular depth. Seawater density is determined by the temperature-dependent salinity [41]. It varies in a narrow range between 1.025 g/cc at the sea surface and 1.028 g/cc at depths greater than 1000 m. Calsep [45] shows the density data of CO₂ at various pressures and temperatures. Guo and Mahmood [44] presented a chart for the minimum required pressure and the corresponding water depth for CO₂ liquid to reach a density of 1.028 g/cc based on the interpolation of data given by Calsep [45]. The chart is partially reproduced and presented in Figure 4.

Favorable Seawater Depths for CO₂ Disposal. Because CO₂ hydrate is always heavier than seawater and liquid CO₂ is heavier than seawater in certain pressure conditions, CO₂ can be disposed of on the seafloor in both hydrate and liquid forms. Figure 5 illustrates the procedure to determine the minimum seafloor depth for CO₂ disposal in hydrate form. The procedure involves plotting the minimum required pressure data for hydrate formation at various seawater depths by combining the data in Figure 1 and Figure 2. Also plotted in the third column graph is the hydrostatic pressure of seawater. The (c)-column graph identifies a curve intersection (cross-over) point at a depth of about 700 m, suggesting that CO₂ hydrates should form below a water depth of about 700 m, which is called the critical disposal water depth. It is understood that the minimum required seafloor depth should be greater than the critical disposal water depth. Figure 6 shows the procedure to determine the minimum seafloor depth for CO₂ disposal in liquid form. The procedure involves plotting the minimum required pressure data for liquid CO₂ formation at various seawater depths by combining the data in Figure 2 and Figure 4. Also plotted in the third column graph is the hydrostatic pressure of seawater. The (c)-column graph identifies a curve intersection (cross-over) point at depth about 700 m, suggesting that CO₂ liquid should form below a water depth of about 1900 m, which is called the critical disposal water depth. It is understood that the minimum required seafloor depth should be greater than the critical disposal water depth.

3. Analytical Method

Although the graphical solution method for determining the critical seawater depth is transparent, it takes a lengthy procedure to obtain results. If the curves in these graphs can be described by equations, solving these equations simultaneously should allow a quick solution to the problem. In fact, Kamath [46] gives:

(3)$p_h=\mathrm{E}\mathrm{x}\mathrm{p}\left(44.58-{\displaystyle \frac{\mathrm{10,246}}{t+273.15}}\right)$

where p_h is the CO₂ hydrate-forming pressure in kPa and t is temperature in the range of 0 to 11 °C. The curve in Figure 4 is expressed as

(4)$p_L=10t+170$

where p_L is CO₂-liquid-forming pressure in bar and t is temperature in °C. The hydrostatic pressure of seawater is expressed by

(5)$p_s=\rho gD$

where p_s is the hydrostatic pressure of seawater in Pa, r is density in kg/m³, g is gravitational acceleration (9.81 m/s²), and D is water depth in m.

To predict the CO₂ hydrate-forming pressure in a given seawater temperature profile, substituting Equation (1) into Equation (3) gives

(6)$p_h=\mathrm{E}\mathrm{x}\mathrm{p}\left(44.58-{\displaystyle \frac{\mathrm{10,246}}{{\mathit{t}}_{\mathit{b}}+\frac{{\mathit{t}}_{\mathbf{0}}-{\mathit{t}}_{\mathit{b}}}{\mathbf{2}}\left[\mathbf{2}-\left[\mathbf{1}+\mathbf{erf}\left(\mathbf{2}\left[{\left(\frac{\mathit{D}}{{\mathit{D}}_{\mathit{m}}}\right)}^{\mathit{\alpha }}-\mathbf{1}\right]\right)\right]\right]+273.15}}\right)$

Equating the right-hand sides of Equations (5) and (6) with unit conversion results in

(7)${\displaystyle \frac{\rho gD}{1000}}=\mathrm{E}\mathrm{x}\mathrm{p}\left(44.58-{\displaystyle \frac{\mathrm{10,246}}{{\mathit{t}}_{\mathit{b}}+\frac{{\mathit{t}}_{\mathbf{0}}-{\mathit{t}}_{\mathit{b}}}{\mathbf{2}}\left[\mathbf{2}-\left[\mathbf{1}+\mathbf{erf}\left(\mathbf{2}\left[{\left(\frac{\mathit{D}}{{\mathit{D}}_{\mathit{m}}}\right)}^{\mathit{\alpha }}-\mathbf{1}\right]\right)\right]\right]+273.15}}\right)$

which can be solved numerically for the critical depth D. For the temperature profile in Figure 2, the numerical solution of Equation (7) for the critical seawater depth is 688 m, which confirms the graphical solution of 700 m given in Figure 5.

To predict the minimum required pressure for forming CO₂ liquid of density 1.028 g/cc in a given seawater temperature profile, substituting Equation (1) into Equation (4) gives

(8)$p_L=10\left\{{\mathit{t}}_{\mathit{b}}+{\displaystyle \frac{{\mathit{t}}_{\mathbf{0}}-{\mathit{t}}_{\mathit{b}}}{\mathbf{2}}}\left[\mathbf{2}-\left[\mathbf{1}+\mathbf{erf}\left(\mathbf{2}\left[{\left({\displaystyle \frac{\mathit{D}}{{\mathit{D}}_{\mathit{m}}}}\right)}^{\mathit{\alpha }}-\mathbf{1}\right]\right)\right]\right]\right\}+170$

Equating the right-hand sides of Equations (5) and (8) with unit conversion results in

(9)${\displaystyle \frac{\rho gD}{\mathrm{100,000}}}=10\left\{{\mathit{t}}_{\mathit{b}}+{\displaystyle \frac{{\mathit{t}}_{\mathbf{0}}-{\mathit{t}}_{\mathit{b}}}{\mathbf{2}}}\left[\mathbf{2}-\left[\mathbf{1}+\mathbf{erf}\left(\mathbf{2}\left[{\left({\displaystyle \frac{\mathit{D}}{{\mathit{D}}_{\mathit{m}}}}\right)}^{\mathit{\alpha }}-\mathbf{1}\right]\right)\right]\right]\right\}+170$

which can be solved numerically for the critical depth D. For the temperature profile in Figure 2, the numerical solution of Equation (9) for the critical seawater depth is 1893 m, which confirms the graphical solution of 1900 m given in Figure 5.

4. System Requirement

The deposition of CO₂ in hydrates on the seafloor below the critical depth requires that CO₂ hydrates are formed instantly in seawater unless the water depth is greater than the depth for stable CO₂ liquid, where hydrates can form slowly without hydrate floating up. To generate CO₂ hydrates instantly, a super-cooling technique is proposed using the Joule–Thomson cooling effect. Figure 7 presents a schematic diagram of a CO₂ hydrate generation process using a jet-cooling method. Ship 1 is loaded with liquid CO₂ from the carrier connector 2 or pipeline hose to the CO₂ tank 3. The liquid CO₂ is cooled by cooler 4 to increase its density. The cooled CO₂ is pumped by pump 5 into hose 6, leading to the injection head 7, where the CO₂ is expanded through the jetting nozzles 8. Due to the Joule-Thomson cooling effect, the jetted CO₂ stream should be further cooled below the seawater temperature, causing the formation of CO₂ hydrates immediately. The remaining CO₂, if any, will form hydrates in the buffer chamber 9. The depth control room 10 receives seawater depth data from the sonar depth surveyor 11 and adjusts the location of the injection head 7 to keep it close to the seafloor. The CO₂ monitoring room 12 receives data from the CO₂ detector 13 and sends a signal to the CO₂ pump control for reducing the CO₂ injection rate if free CO₂ is detected. The generated CO₂ hydrate should remain on the seafloor due to its high density relative to seawater. The ship moves forward slowly as needed.

The total cross-sectional area of the nozzles should be designed to cause a significant pressure drop at the nozzles to generate adequate Joule–Thomson cooling effect. The temperature at the downstream of the nozzles can be estimated based on choke-flow theory [47]:

(10)$T_{dn}=T_{up}{\displaystyle \frac{z_{up}}{z_{outlet}}}{\left({\displaystyle \frac{p_{outlet}}{p_{up}}}\right)}^{{\displaystyle \frac{k-1}{k}}}$

where z_up and z_outlet are compressibility factors at upstream and outlet conditions, p_outlet is the pressure at the nozzles’ outlet, p_up is the upstream pressure, and k is the specific heat ratio of CO₂. The outlet pressure is equal to the sea water pressure in subsonic (subcritical) flow conditions. To achieve the maximum temperature drop, sonic (critical) flow conditions can be used. The critical pressure ratio through the nozzles is expressed as

(11)${\left({\displaystyle \frac{p_{outlet}}{p_{up}}}\right)}_c={\left({\displaystyle \frac{2}{k+1}}\right)}^{{\displaystyle \frac{k}{k-1}}},$

where the value of k for CO₂ is about 1.28. Thus, the critical pressure ratio is about 0.55 for CO₂. This requires that the upstream pressure be more than double that of the downstream pressure, which is the in situ seawater pressure. For example, if the in situ seawater temperature is 276 °K (3 °C), the in situ seawater pressure should be selected to be at least 16.6 bar for hydrate formation. The nozzle size should be designed to create an upstream pressure of at least 13.2 bar for instant hydrate formation. The relationship between the upstream pressure, CO₂ flow rate, and total nozzle area can be found in the literature [47].

The following procedure is recommended to design and optimize the performance of the jet-cooling process.

1. Select a seafloor site that is deeper than the critical water depth determined in the procedure shown in Figure 5. Designthe seawater depth for CO₂ placement.

2. Calculate the hydrostatic pressure of seawater p_dn at the water depth of CO₂ placement. This pressure is considered to be the downstream pressure of the jetting nozzles.

3. Calculate the required upstream pressure p_up of the jetting nozzles using

(12)${\mathit{p}}_{\mathit{u}\mathit{p}}={\displaystyle \frac{{\mathit{p}}_{\mathit{d}\mathit{n}}}{{\mathit{R}}_{\mathit{c}}}}$

where the critical pressure ratio R_c is given by

(13)${\mathit{R}}_{\mathit{c}}={\left({\displaystyle \frac{\mathbf{2}}{\mathit{k}+\mathbf{1}}}\right)}^{{\displaystyle \frac{\mathit{k}}{\mathit{k}-\mathbf{1}}}}$

The total area of the nozzles should be designed through the use of the following equation [46]:

(14)$q=879CA{p}_{up}\sqrt{\left({\displaystyle \frac{k}{{\gamma }_g{T}_{up}}}\right){\left({\displaystyle \frac{2}{k+1}}\right)}^{{\displaystyle \frac{k+1}{k-1}}}}$

where q is the CO₂ flow rate in Mscf/d, C is the nozzle discharge coefficient (close to unity for highly compressed CO₂ streams in low-temperature conditions), A is the total cross-sectional area of the nozzles in in², p_up is upstream pressure in psi, γ_g is the CO₂ specific gravity relative to air, and T_up is the CO₂ temperature in °R at the upstream of the nozzles (very close to the seawater temperature at the nozzle depth).

To achieve the desired upstream pressure of the nozzles, the surface injection pressure should reach a minimal value given by

(15)$p_{inj}=p_{up}-p_h+p_f$

where p_inj is the surface injection pressure, p_h is the hydrostatic pressure of the CO₂ inside the injection pipe, and p_f is the frictional pressure loss of the CO₂ inside the injection pipe.

5. Discussion

This study proposes an efficient method and technology suite for the evaluation of safe disposal of CO₂ on the seafloors. The proposed process will replace the need for drilling CO₂ injection wells by using disposing ships, which should be more economical. However, this document provides an early technical assessment of the process only. Economic analysis is beyond the scope of this document.

Instead of using disposal ships, the proposed idea of CO₂ storage in liquid and hydrate forms can be realized using existing subsea structures such as water/CO₂ injection wells if the wellheads at the seabed are below the critical disposal water depth. CO₂ can be released to the sea floor around the subsea wellheads. However, additional structures/equipment are required to manage hydrate piles, which will incur additional cost.

It is understood that this study does not provide any new data but derives data. The applicability and accuracy of the calculated seawater depths for carbon dioxide disposal are limited by the reliability and accuracy of the input data from the published literature. Significant error in the calculations is not expected. However, it is advised that recalculations are suggested for the researchers and engineers in their location applications.

More research work needs to be conducted to support the engineering design of the system and assess the potential impact of the process on the environment of seafloors. The following work is specially recommended for future focus:

Conducting experimental investigations of the proposed jet-cooling process to validate the concept. This is being designed and prepared using a high-pressure–low-temperature windowed cell to observe the settling of CO₂ hydrates and CO₂ liquid due to gravitational segregation.

Performing a quantitative hydrate formation kinetics analysis to determine the minimum required residence time of the jet plume for full solidification under the seawater conditions of the proposed process. This information will be used for designing the geometry (diameter and length) of the buffer chamber to ensure 100% conversion of CO₂ to hydrates before the CO₂ plume exits the buffer chamber.

Carrying out research work to analyze how CO₂ liquid and hydrates might be disturbed by bottom sea currents, interact with sediments and nearby man-made structures, warming scenarios of geological events (e.g., earthquake and volcano rupture), extreme weather (e.g., hurricanes and tsunamis), and human activities such as the aviation of artificial objects.

It is understood that Equation (1) was established based on the data in Figure 2. Under other seawater conditions, either the actual temperature data from local survey or Equation (1) validated using the actual data should be used to determine the critical water depth for CO₂ hydrate formation.

Application of the proposed technique is limited to disposal water depths greater than the critical disposal water depths, typically 700 m for storage in hydrate form and 1900 m for storage in liquid form. Local studies need to be conducted in real applications. The major drawback of the technique is that it requires significant investment in building the CO₂-disposing ship for CO₂ disposal and CO₂ carrier for CO₂ delivery.

6. Conclusions

An efficient method and technology suite to realize the process for safe disposal of CO₂ on the seafloor is presented in this study. The following conclusions are drawn.

CO₂ can be stored on the seafloor in its liquid-to-hydrate form if the seawater is deep enough. In a typical seawater environment, if the seafloor depth is greater than 6200 ft (1900 m), CO₂ can be injected directly onto the seafloor in liquid form. The liquid CO₂ will then form hydrates and stay on the seafloor.

CO₂ can be stored on the seafloor in its hydrate form if the seafloor is deep enough. In a typical seawater environment, if the seafloor depth is greater than 700 m, CO₂ can be injected through nozzles to reduce its temperature and generate hydrates. The generated hydrates will then be deposited on the sea floor.

The nozzle for reducing the CO₂ temperature to generate hydrate is the key component of the proposed technology suite. The nozzles should be sized based on the required upstream pressure and CO₂ flow rate. Sonic (critical) flow condition is preferred to maximize the cooling efficiency.

Author Contributions

Conceptualization, B.G.; methodology, M.T.I.; software, V.N.B.A.; validation, B.G.; formal analysis, M.T.I.; investigation, V.N.B.A.; resources, B.G.; data curation, M.T.I.; writing—original draft preparation, V.N.B.A.; writing—review and editing, B.G.; visualization, M.T.I.; supervision, B.G.; project administration, B.G.; funding acquisition, B.G. All authors have read and agreed to the published version of the manuscript.

Data Availability Statement

No new data was created.

Acknowledgments

The authors are grateful to BIRD for funding the project “Safe, sustainable, and resilient development of offshore reservoirs and natural gas upgrading through innovative science and technology: Gulf of Mexico—Mediterranean,” through grant No. EC-19 Fossil Energy.

Conflicts of Interest

The authors declare no conflict of interest.

Footnotes

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Figures

Figure 1 Static conditions for forming CO₂ hydrate and methane hydrate [40].

Figure 2 Variation in ocean water temperature with depth [43].

Figure 3 Comparison of data given by Klemm [43] and that by Equation (1) with a = 1.19.

Figure 4 Required pressures at various temperatures for liquid CO₂ to reach a density of 1.028 g/cc.

Figure 5 Procedure for determining the minimum seawater depth of CO₂ storage in hydrate form. (a) seawater temperature, (b) hydrate formation pressure, and (c) seawater pressure and hydrate formation pressure.

Figure 6 Procedure for determining the minimum seawater depth of CO₂ storage in liquid form. (a) seawater temperature, (b) liquid CO₂ formation pressure, and (c) seawater pressure and liquid CO₂ formation pressure.

Figure 7 A schematic diagram of a CO₂ hydrate generation process using a jet-cooling method.

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