CO 2 gas hydrate for carbon capture and storage applications – Part 2

CO 2 hydrate offers some substantial applications for Carbon Capture and Storage (CCS). While CO 2 hydrate chemistry and CO 2 capture are reviewed in part 1 of this review, CO 2 transportation and storage are discussed in this part. Basically, CO 2 transportation is required between CO 2 capture plants and CO 2 sequestration sites. It is imperative to acknowledge that most strategies for achieving deep decarbonization are linked to the expansion of the current transport infrastructure. When dealing with substantial distances between CO 2 capture plants and CO 2 sequestration sites, the expenses associated with CO 2 transportation can surpass the capture process itself. Therefore, despite the benefits of CO 2 hydrates in CCS, challenges, such as flow assurance issues, may arise. For example, CO 2 hydrate formation can lead to pipeline blockages, emphasizing the need for CO 2 gas hydrate flow assurance study as discussed in this part. Additionally, site selection for CO 2 storage requires careful consideration. Geological storage, whether in hydrate form or through the injection of CO 2 or high-CO 2 content mixtures, offers potential advantages, such as long-term storage and self-sealing capabilities. However, there are some challenges like CO 2 hydrate processes in porous media, injectivity, flow behaviour in hydrate reservoirs, mechanical behaviour, etc., which are discussed in this review.


Introduction
Part 1 of this review provides a fundamental understanding of advancements in CO 2 gas hydrate chemistry and technologies, which hold significant potential for CO 2 capture applications.The increasing global attention towards Carbon Capture and Storage (CCS) has led to rapid growth in research, advances, and developments in sustainable hydratebased technologies.
The focus in this part is on CO 2 hydrate flow assurance, a key research area of hydrate aiming to prevent or minimize the risk of hydrate blockage in pipelines.There are still challenges in reducing the risk of CO 2 hydrate formation during transportation.CO 2 , typically captured from major point sources like power generation plants utilizing fossil fuels, is transported through pipelines or ships for secure storage.Consequently, this part provides CO 2 hydrate flow assurance challenges, including dehydration requirements for CO 2 hydrate inhibition, CO 2 hydrate inhibitors, and CO 2 hydrate slurry and blockage.Additionally, CO 2 hydrates present an opportunity for permanent CO 2 storage in geological formations, for example by CH 4 -CO 2 replacement in permafrost gas hydrate reservoirs.Therefore, this part also explores the potential advantages of CO 2 hydrates for long-term storage and reviews their formation in geological formations.It also explores the application of CO 2 injection, with a focus on CO 2 -rich injections into hydrate reservoirs.The analysis highlights the advantages of utilizing CO 2 hydrates for both storage and gas recovery from these reservoirs.Particular attention is also given to the understanding of fluid flow and mechanical properties of gas hydrate reservoirs, specifically in relation to CO 2 hydrates within porous media.A review is also conducted on several crucial field tests within the domain of CCS, focusing particularly on gas hydrates and recent studies investigating the stability of CO 2 hydrates.
Finally, as the focus is to narrow onto the promising avenue of hydrate-based technologies in-depth exploration of CCS, an outlook and perspective that underscores the significance of hydrate-based CCS are presented.

CO 2 hydrate flow assurance
CO 2 is usually transported from the carbon capture centre via a pipeline and injected into the storage site.While CO 2 transportation is the least costly part of CCS (carbon capture cost is more than 50 % of CCS cost [1]), it needs more planning, flow assurance, pipeline integrity, and suitable design [2][3][4].While Svensson et al. (2004) showed that pipelines could be an option for CO 2 transportation [5], other studies investigate CO 2 transportation cost [6][7][8][9].
Transportation of single-phase CO 2 (liquid or supercritical) is preferred due to the problems associated with two-phase flow [10].CO 2 should be transported at a high-density condition (liquid or supercritical state) to prevent bubble formation [6].The critical pressure and temperature of pure CO 2 are 7.38 MPa and 31.1 • C respectively.So, if the temperature is above the critical temperature (in most locations during the summer [6]), any pressure drops that result in pressure below 7.38 MPa trigger the formation of CO 2 bubbles.It is highlighted that the minimum pressure for CO 2 transportation should be higher than the critical pressure (7.38 MPa) to prevent two-phase mixture flow [6].Fig. 1 shows Temperature-entropy (T-S) diagram for CO 2 that identifies liquid and vapour regions.
The presence of impurities can also cause a two-phase flow and increase the pressure drop [11].In addition, dynamic simulation of CO 2 transport in the pipeline shows that some circumstances (e.g., shut-down and pipe cooling) can cause the formation of a two-phase mixture [12].Nevertheless, the phase envelop and thermophysical properties of CO 2 streams significantly influence the pipeline design for CO 2 transportation that should be cost-effective [13] and safe for normal operation [14].
Pipeline design, construction, and operation are the main three phases for CO 2 transportation that have been investigated in other studies [15][16][17][18][19].While there are some thermodynamic challenges for CO 2 pipeline design [20] and a great deal of considerations should be undertaken for CO 2 transportation [21], this section only reviews the fundamental flow assurance challenge related to CO 2 transportation focusing on CO 2 hydrate.

CO 2 hydrate flow assurance
Hydrate Risk is considered as the flow assurance problem that needs to be assessed for CO 2 transportation [22][23][24].Kvamme et al. investigated the upper limit of water content in dense CO 2 during pipeline transportation to prevent hydrate formation [25].They concluded that water adsorption on rusty pipeline walls increases CO 2 hydrate formation risk.They also examined different hydrate formation routes for transportation of dense CO 2 with water and some impurities such as hydrogen sulfide, methane, argon, and nitrogen [25,26].
CO 2 stream is practically transported under the supercritical condition using the pipelines that need to be buried in the land due to safety [27,28].Accordingly, the properties of surrounding soil (e.g., temperature and conductivity) influence the CO 2 pipeline operation [29] which can induce hydrate formation risk.Hydrate formation risk under the transient condition in the buried CO 2 pipeline was investigated for shut-in, start-up, and rapid depressurization [30].It is pointed out that hydrate formation risk depends on soil conductivity which has a higher risk in medium and high soil conductivity [30].There is also always a risk of hydrate formation during the start-up and shut-in conditions if the CO 2 stream is not dehydrated [30].
Operating conditions can also enter to the hydrate stability zone during CO 2 injection into geological storage.A typical schematic diagram of CO 2 hydrate formation risk in the well injection for CO 2 geological storage is shown in Fig. 2. Wang et al. investigated gas hydrate flow assurance problem during deep-water operation and developed a model for flow assurance design and optimization [31].A practical model was also developed by Zerpa to design the flow assurance strategies considering the hydrate formation, dynamic aggregation, and transportability in the pipelines [32].A transient simulation model for hydrate prediction and formation in the pipeline was also investigated by numerous studies [33][34][35][36][37].
Heat transfer, pressure drop, and flow characteristics of CO 2 hydrate mixture have been also investigated [35,[38][39][40][41]. Prah and Yun pointed out that the continuous CO 2 hydrate formation strongly depends on the temperature difference between CO 2 hydrate mixture and surrounding soil [40].They indicated that the pressure drop and heat transfer coefficient for CO 2 hydrate mixture in the buried pipeline can be in the range  of 101-996 KPa and 54-2883 W m − 2 K − 1 respectively [40].A reduction in heat transfer coefficient with increasing of CO 2 hydrate was reported by Park and Yun [42].Oignet et al. investigated the convective heat transfer coefficient of CO 2 hydrate mixture (0-14 % hydrate fraction) and reported that it is 2.5 times higher than that for liquid water [43].De Koeijer et al. also investigated heat transfer, impurities, depressurization, and the model for hydrate formation for CO 2 transportation [44].The heat transfer for the gas hydrate mixture for CO 2 -Ar and CO 2 -He in a continuous flow reactor was also investigated by Yang et al. [45].While Yang et al. concluded that high fluid velocity increases the mass and heat transfer in the continuous hydrate flow reactor [45], Prah and Yun showed that CO 2 hydrate particles are intended to settle down even at high velocity conditions by modelling using COMSOL [39].
The discussion on CO 2 hydrate flow assurance highlights that it is a technical discipline that needs to be considered for continuous CO 2 transportation.Accordingly, the challenge of induced CO 2 hydrate needs an understanding of the dehydration requirements for CO 2 stream, CO 2 hydrate slurry flow, CO 2 hydrate blockage, and inhibition method to prevent hydrate formation as discussed in the following subsections.

Water content and its effect on CO 2 hydrate formation
Accurate prediction of pipeline conditions that lead to hydrate formation is a complex endeavour.Kvamme et al. used a modified phase field theory (PFT) to analyse the thermodynamics and the kinetics formation of CO 2 hydrate to determine the most probable transition of hydrate phase [46].They concluded that CO 2 hydrate formation is thermodynamically feasible above a certain limit of water concentration.
The CO 2 streams may have various impurities such as moisture, therefore, dehydration and reducing the water dew point is one of the options to prevent CO 2 hydrate formation.Hydrate equilibrium temperature significantly depends on water content in the absence of free water phase, i.e., the hydrate phase boundary shifts to the lower temperature and higher pressure by reducing the water content.While significant works have been advocated to study the CO 2 hydrate in the presence of free water phase, there are limited data on equilibrium CO 2 hydrate dissociation point in the absence of free water.
The hydrate equilibrium temperature of CO 2 in the absence of free water could be determined by measurement of water content in the vapour or liquid CO 2 phase in equilibrium with hydrate.In this method, a small fraction of water is initially injected into the cell at a temperature well above the hydrate formation temperature.The water content of vapour or liquid CO 2 phase is then measured at different temperatures by the stepwise temperature reduction (pressure is kept constant by adjusting the volume).Following this stepwise temperature reduction, the temperature is decreased significantly to convert all water to hydrate at a high subcooling temperature.The water content of vapour or liquid CO 2 phase is then measured by the stepwise increase of temperature once it reaches the equilibrium.The water content is then plotted as a function of temperature; and the hydrate equilibrium dissociation temperature can be determined by the intersection of water content curves from step-heating and step-cooling points as shown in Fig. 3.
Fig. 3 shows an example of water content in CO 2 -rich liquid with 1100 ppm mol water as a function of temperature at 8.89 MPa.While the water content remains constant outside the hydrate stability zone (all water is dissolved in the CO 2 phase), it exponentially increases with temperature inside the hydrate region due to the increasing of water vapour pressure in the hydrate phase and decreasing of hydrate fraction [47].This method was used by Chapoy et al. [47] and Youssef et al. [48] to measure the CO 2 hydrate equilibrium temperature without free water.
As discussed, the hydrate dissociation point in the absence of free water notably depends on the water content.Therefore, accurate prediction of water content in the vapour/liquid CO 2 in the presence of hydrate is essential to assess the dehydration requirement to prevent CO 2 hydrate formation.An accurate model for the prediction of CO 2 hydrate in the absence of free water requires the highly precise prediction of water content.Consequently, there have been numerous research investigated the water content in the CO 2 -rich fluid in equilibrium with hydrate [49][50][51][52][53].A large discrepancy in the water content of CO 2 -rich phase in the hydrate stability zone was reported due to the metastable of the hydrate phase, slow process of hydrate formation, and presence of an unexpected phase [53].However, all experimental data demonstrate a sharp discontinuity in water content in the CO 2 rich phase in equilibrium with hydrate (or liquid water) when the CO 2 phase is changed from vapour to liquid [50,[54][55][56][57].The equilibrium water content in the CO 2 -rich phase increases in step change when the CO 2 phase is changed from vapour to liquid.It is reported that the pressure has very little effect on the water content in the liquid CO 2 in equilibrium with CO 2 hydrate [52].
Fig. 4 also shows the CO 2 hydrate-vapour equilibrium at different water contents.It indicates that the hydrate phase boundary shifts to a lower temperature and higher pressure (in the absence of free water) as the CO 2 stream is dehydrated.This determines the amount of dehydration requirement to prevent hydrate formation.It has been noted in some studies that the CPA equation of state combined with classical Platteeuw and van der Waals model can properly predict the hydrate phase boundary of CO 2 in the absence of free [47,48].

CO 2 hydrate inhibition
Chemical injection is the most popular techniques to prevent hydrate formation.Thermodynamic hydrate inhibitors (THIs) and low dosage hydrate inhibitors (LDHIs) (kinetic hydrate inhibitors (KHIs) and antiagglomerants (AAs)) are two types of chemicals for hydrate inhibition.These chemicals, particularly focused on CO 2 hydrate inhibition, are discussed in this section.
(a) Thermodynamic hydrate inhibitors (THIs) THIs (e.g., mono-ethylene glycol (MEG), methanol, and ethanol) disrupt the hydrogen bonding and reduce the hydrate equilibrium temperature at a particular pressure [74].Specifically, when considering ethanol as a THI, powder X-ray diffraction and molecular dynamics simulations demonstrated that in the CO 2 + ethanol + water, both CO 2 and ethanol can act as guest formers in hydrate lattice.The Fig. 3.An example of water content in CO 2 liquid with 1100 ppm mole water as a function of temperature at 8.89 MPa to determine hydrate equilibrium point without free water.Data is taken from Chapoy et al. [47].
M. Aminnaji et al. results showed different hydrate lattices, with a lattice constant of 1.8577(5) Å at 113 K for the system with ethanol, which is larger than the pure CO 2 lattice constant of 11.8434(8) Å [58].
Fig. 5 shows various THIs that have been studied for CO 2 hydrate inhibition.Some organic solvents such as dimethyl sulfoxide have also THIs inhibitory effect on CO 2 hydrate [59].In addition to alcohol and glycol, ionic salts such as NaCl can act as THIs.The inhibition and induction time of CO 2 hydrate are influenced by salts i.e., while salts can act as THIs, they have some effect on CO 2 hydrate nucleation and growth.Farhang et al. investigated the effect of sodium halides (NaF, NaCl, NaBr, and NaI) on the CO 2 hydrate kinetic and concluded that while salts are known as THIs, they can increase the kinetics formation of CO 2 hydrate at low concentration (e.g., 50 mM) [75].In contrast, it is reported that CO 2 hydrate growth rate in 3.5 % electrolyte solution of NaCl, KCl, CaCl 2 , and MgCl 2 is slower than in deionized water [76].
Some ionic liquids (ILs) also have THIs properties.For example, morpholinium and piperidinium ionic liquids have THIs inhibition effect on CO 2 hydrate [60].Cha et al. showed that smaller anionic species in morpholinium and piperidinium ionic liquids have a better inhibition effect [60].The inhibition performance of various ions on CO 2 hydration inhibition has been summarised by Liu et al. [77].In addition to ILs, quaternary ammonium salts (QAS) have also THI properties.For example, the THI properties of three QAS (tetra ethyl ammonium iodide, tetra methyl ammonium bromide, and tetraethyl ammonium bromide) with and without MEG were reported for the CO 2 hydrate [61].Some amino acids may also act as THIs.For example, glycine, L-alanine, and L-valine show THIs inhibition properties in the CO 2 hydrate system [62].Manner et al. also studied the effect of lysine as amino acid on CO hydrate and showed that 10 wt% lysine can reduce the equilibrium temperature of CO 2 hydrate by 1.49 K [63].However, some amino acids have some properties to increase gas uptake capacity and kinetics during gas hydrate formation [78].
(b) Kinetic hydrate inhibitors (KHIs) KHIs are water-soluble polymers that can increase the induction time by inhibiting of hydrate nucleation and preventing catastrophic hydrate growth [79].Molecular dynamic simulation shows that KHIs affect the water molecule arrangement and increase the induction time by the interaction between KHI molecules and hydrate nuclei surface [80,81].It is proposed that KHIs reduce the supersaturation of gas and reduce the gas migration to the hydrate nucleus which results in hydrate growth inhibition [81].Induced hydrate dissociation by KHIs inside hydrate stability zone has been also reported [82,83].It has also shown that KHIs can inhibit the growth of pre-formed hydrates [83].In the past decade, significant advances have been achieved in both developments of KHIs polymers [84,85] and biodegradable KHIs [86][87][88].
Some poor biodegradable commercial KHIs, e.g., poly(vinylpyrrolidone) (PVP) [89] and polyvinylcaprolactam (PVCap) [90], can inhibit the CO 2 hydrate nucleation and growth.Due to the low biodegradation of these KHI polymers, various eco-friendly KHIs such as ILs [91][92][93], QAS [94], and amino acids [95] have been also studied for CO 2 hydrate inhibition.It has been showed that those amino acids that have shorter alkyl chains can better inhibit CO 2 hydrate [96].Another study also showed that the amino acids with lower hydrophobicity have better KHIs properties for CO 2 hydrate inhibition [96].In fact, the water structure for the formation of hydrate cavity is disrupted by amino acids that have hydrophilic or electrically charged alkyl chains [97].Some biodegradable polymers such as pectin and starch were also investigated for CO 2 hydrate inhibition [90,98].Some ILs and QAS have been identified as dual functional hydrate inhibitors that show both KHIs and THIs properties.Khan et al. investigated the dual functional hydrate inhibitor properties of tetramethyl ammonium hydroxide, tetraethyl ammonium hydroxide, tetrapropyl ammonium hydroxide, and tetrabutyl ammonium hydroxide [99].Fig. 6 shows various KHIs studied for CO 2 hydrate inhibition.These KHIs generally are divided into four categories: non-biodegradable polymers, green polymers and amino acids, ILs, and QAS.
Inhibitor effect of KHIs on CO 2 hydrate is significantly influenced by subcooling temperature (i.e., a temperature difference between operating condition and hydrate equilibrium).KHIs can induce different inhibition regions as a function of subcooling temperatures including complete inhibition region (CIR), slow growth region (SGR), and rapid growth region (RGR), i.e., these regions which are induced by crystal growth inhibition intensity of KHIs are identified by crystal growth inhibition (CGI) method [101,102].Moreover, the hydrate growth rate may also affected by stirring RPM in the laboratory experiments [103].Noticeably, the inhibition performance of KHIs on CO 2 hydrate and the induction time increase with the chemical dosage [89,100].The CO consumption through hydrate formation is another factor that is influenced and could be decreased by inhibition additives.Lie et al., summarised CO 2 gas consumption in the presence of various additives that  M. Aminnaji et al. are reported in the literature [77].KHIs also show some synergistic effect when they combined with THIs [74,104].The synergistic effect of diethylene glycol and glycine has been shown for CO 2 hydrate inhibition [105].

(c) Anti-agglomerants (AAs)
The KHIs performance is subjected to subcooling temperature and may not inhibit the hydrate nucleation or growth at high subcooling temperature.Therefore, AAs (mostly oil-soluble surfactants) can be employed to avoid hydrate agglomeration/blockage [106].Various mechanisms have been proposed to reduce hydrate agglomeration tendency by AAs.In the most common mechanism, AAs bind to the hydrates through their hydrate-philic head penetration to the hydrate cavities and make the oil-wet hydrate crystals by their hydrophobic tail [107,108].In this mechanism, the hydrate agglomeration tendency is reduced by disruption of the capillary water bridge that can link up the hydrate crystals [109].In another word, AAs can reduce the interfacial tension which results in decreasing in capillary forces and attraction forces between hydrate crystals [110].It was also reported that functionalized nanoparticles could prevent hydrate agglomeration [111].For example, silica nanoparticles show anti-adhesive effect on gas hydrate particles [112,113].
Notwithstanding the mechanisms, AAs form a hydrate slurry flow in the pipelines and various studies were done to evaluate CO 2 hydrate slurry in the presence of AAs (Fig. 7).Therefore, the rheology of hydrate slurries in the presence of various AAs has received considerable attention [114,115], and different rheology models have been proposed for hydrate slurry flow [116].These mechanisms that are suggested for AAs indicate the crucial function of oil phase and water cut.However, in the absence of oil phase, AAs can also prevent hydrate agglomeration [117,118], (i.e., hydrophobic tails of AAs pass through the hydrate particle surface and prevent agglomeration [119]).Some other factors, including concentration [120], gas composition [121,122], alkyl tail chain length of AAs [123], and salinity [117] can also affect AAs performance.

CO2 hydrate slurry flow and blockage
CO 2 transportation in the hydrate slurry form reduces the required energy for transportation and prevent hydrate blockage.Moreover, the application of CO 2 hydrate slurry for refrigeration has inspired many researchers to investigate the flow characteristic and rheological properties of CO 2 hydrate slurry.Oignet et al. [125], Delahaye et al. [126,132], Jerbi et al. [133], investigated the rheological properties (e.g., viscosity, shear stress, rheograms) of CO 2 hydrate slurry through the flow loop and tank reactor.
Hu et al. [134] experimentally investigated the flow characteristics of CO 2 hydrate slurry such as viscosity and density that are increased with solid mass fraction.They showed that CO 2 hydrate crystals has a slightly influence on the increasing of viscosity for the range of 1.59 %-28 % solid mass fraction [134].Moreover, adding AAs makes the hydrate slurry and changes its rheological properties.Wu et al. experimentally showed that while CO 2 hydrate blockage occurred easily in the water, adding Tween-80 prevented hydrate blockage [131].Moreover, while AAs significantly improve the flow of CO 2 hydrate slurry, they affect the hydrate slurry density, kinetics of hydrate formation, and hydrate fraction [127].Lv et al. showed that increasing of surfactant hydrophile− lipophilic balance (HLB) of AAs results in decreasing of apparent viscosity of CO 2 hydrate slurry [128].
The sheer-thinning behaviour (similar to pseudoplastic fluid) was observed in the CO 2 hydrate slurry in the presence of AAs [128].Similarly, Wu et al. showed that while the slurry form of CO 2 hydrate in the pure water is a dilatant fluid (shear-thickening behaviour), adding Tween-80 makes CO 2 hydrate slurry to a pseudoplastic fluid (shear-thinning behaviour) [131].Shear-thinning behaviour observed by adding AAs is the main factor to form the CO 2 hydrate slurry and prevent hydrate blockage, i.e., moving from dilatant fluid to pseudoplastic fluid by adding AAs [131].Moreover, increasing of SDS concentration reduces the yield stress of CO 2 hydrate slurry (i.e., shear-thinning pseudoplastic behaviour) [135].Increasing the hydrate fraction also makes the hydrate slurry to have more non-Newtonian behaviour with decreasing of apparent viscosity.Fu et al. experimentally showed CO hydrate slurry as a shear-thickening power law fluid [136].
Prah and Yun [130] identified three different flow regimes (homogeneous, heterogeneous, and bedding flow) for CO 2 hydrate slurry in the flow loop, which depends on hydrate fraction.They showed two different regions (active formation and less active formation) for CO hydrate formation in the presence of AAs [130].Prah and Yun [129] also investigated the pressure, temperature, density, and flow rate of CO hydrate slurry in the scaled-up flow loop in the presence of Tween 80.They suggest that CO 2 hydrate slurry can be transported over a long distance in the presence of appropriate AAs [129].
Despite the advantages of CO 2 transportation in the form of hydrate slurry, there is always a risk of hydrate blockage in the pipeline [137][138][139][140][141][142].Therefore, understanding of CO 2 hydrate accumulation and blockage mechanism is crucial to prevent the severe economic impact on the operation.The CO 2 hydrate blockage is very likely to occur after the onset of CO 2 hydrate formation even at small hydrate fraction [143].It is proposed that CO 2 hydrate blockage may occur by sticking and growing of CO 2 hydrate particles on the pipe wall during four stages: induction time, formation of CO 2 hydrate layer, thickening of hydrate layer, and hydrate blockage [143].Lv et al. experimentally investigated the effect of flow rate, pressure, and pump restarting on the CO 2 hydrate blockage in a flow loop using Focused Beam Reflectance Measurement [144].They showed that while CO 2 hydrate blockage tendency increases with  pressure, the time required for hydrate blockage increases with flow rate [144].They also showed that pump restarting after CO 2 hydrate blockage makes the problem worse [144].Shi et al. also showed that the rapid restart process after CO 2 hydrate blockage can increase hydrate regrowth resulting in secondary blocking [143].The Chord Length Distribution of CO 2 hydrate particles shows that hydrate particle coalescence causes the hydrate blockage which is time dependent [144].

CO 2 hydrate in sediment
The initial stages of CO 2 sequestration in reservoirs typically involve evaluating geologic formations, including factors such as volume, injection rate, capping mechanisms, and capacity characteristics.These evaluations serve as crucial phases in understanding the feasibility of CO 2 storage in reservoirs.While the primary risk associated with every CCS project is CO 2 leakage from storage sites [145][146][147], multiple capping mechanisms may stop the CO 2 plume from migration.One of these mechanisms is CO 2 hydrate formation which is induced by the thermodynamic conditions in sediments and can stop CO 2 leaks through the top seal.This suggests that CO 2 hydrate self-sealing mechanism can be used for CO 2 storage in permafrost.The CO 2 hydrate's ability to preserve itself can also aid in lowering the danger associated with the geological setting for CO 2 sequestration [148].
Chemical additives have a significant effect on hydrate formation in sediment.While they have minimal effect on the properties of water, they can improve hydrate formation by approximately 50 % (0.15 wt% SiO 2 ) and 25 % (0.05 wt% SDS) compared to pure sea water [149].The in-situ magnetic resonance imaging (MRI) demonstrated that the rate of hydrate dissociation in sediments-carrying organisms can be four times faster for the sample with 23 % saturation than for the sample with 38 % saturation [150].CO 2 hydrate dissociation rate can be also decreased by 0.12, 0.12, and 0.16 mMole.min− 1 compared to pure water with silica gel powder, SDS, and their mixture respectively [151].When the effects of acid-soluble organic materials, such as lignin and protein/amino sugars, were examined, it became clear that their presence on the seafloor would kinetically enhance hydrate formation [152].Hydrophilic silica nanoparticles was also used for CO 2 storage as a highly porous CO 2 hydrate structure, i.e., they provide numerous CO 2 hydrate nucleation sites [153].
The difference in saturation between primary and secondary hydrate formation in porous media results in two types of hydrate: hydrate filled inside the pores (filling model) and hydrate adhering to the surface (coating model).The free gas in large pores preferentially synthesises hydrate, which fills the pores during hydrate formation.This process creates a "hydrate layer" that blocks CO 2 from entering the porous medium.The "hydrate layer" also reduces CO 2 hydrate formation.Wen et al. (2021) [154] stated that the formation of hydrate in seabed sediments mainly consumes water in large pores, followed by a diffusion limitation process in which the hydrate layer acts as a mass transfer barrier, making it difficult for water in small pores to participate in the reaction.In secondary formation, CO 2 gas can enter all pores to produce hydrate, therefore the hydrate accumulates on the porous medium particles.The formation of CO 2 hydrates alongside frozen quartz sands demonstrated how smaller particle sizes could boost gas storage capabilities [155].

CO 2 hydrate self-sealing
One critical aspect of geological CO 2 storage is the caprock integrity for safe CO 2 storage [156][157][158].The self-sealing mechanism through CO 2 hydrate formation is a process that not only ensures the caprock's integrity but also enhances the overall effectiveness and security of geological CO 2 storage.This natural process plays an important role in the seal of the geological reservoir and supporting the long-term stability of the storage site.As shown in Fig. 8, if CO 2 is stored below the gas hydrate stability zone, the leaked CO 2 (through vertical migration of CO 2 ) can form hydrate in the CO 2 hydrate stability zone resulting in permeability reduction.It is pointed out that the temperature below 5 • C at higher hydrostatic pressure (e.g., few hundred meters of water) could initiate CO 2 hydrate formation in the gaps of rock to prevent CO leakage [159].Another study indicated that CO 2 hydrate and storage in the cool underground sediment enhances the CO 2 trapping which have some advantages including physical, chemical, and mineralogical processes [160].
Tohidi et el.showed CO 2 hydrate formation in synthetic porous media through visual observation without the presence of a free-gas phase.They showed hydrate formation in the centre of pore spaces providing potential cementing effect and reducing permeability [161].Tohidi et el.also showed the upward migration of CO 2 into the hydrate stability zone can form hydrates and provide a secondary safety factor to prevent CO 2 leakage [162].They showed that formation of CO 2 hydrates significantly reduced the CO 2 diffusion rate by three orders of magnitude [162].A pore-filling hydrate morphology is suggested as a mechanism to reduce the rock permeability even at low water saturation (36 %) [163].It has been showed that temperature and salinity affect the hydrate induction time in the sediments [163].However, experimental works showed that CO 2 hydrates are sufficiently stable inside the deep oceanic saline sediments (3.5 wt% NaCl) [164].The CO 2 hydrate stability in the oceanic sediments was also confirmed through a laboratory-scale high-pressure reactor [165].Moreover, Gauteplass et al. experimentally showed that the integrity of the CO 2 hydrate seal is strongly affected by fluid-rock interactions and initial water distribution [166].Their research demonstrated that CO 2 leakage rate is ten times slower in sandstone compared to limestone, through CO 2 hydrate formation.The presence of CO 2 may also change fluid-rock interactions such as the degree of swelling and transport properties of clay mineral-water-CO 2 systems [167].
Monte Carlo study also showed coexistence of CO 2 -free gas, CO hydrate, and dissolved CO 2 in the hydrate stability zone [168].In this three-phase zone, the entrapped CO 2 bubble due to the capillary pressure reduce the effective permeability [168].The coexisting of CO bubbles and hydrates to reduce the permeability has been also confirmed in another study [169].
Fig. 8. CO 2 hydrate self-sealing mechanism in the hydrate stability zone.

CO 2 /CO 2 -rich injection into gas hydrate reservoirs
Methane extraction from hydrate reservoir remains largely unexplored due to low production efficiency [170,171].Applying chemical, thermal stimulation, and pressure reduction may not be a practical options for production from hydrate reservoir [172,173].In contrast, CH 4 -CO 2 swapping by injection of CO 2 or CO 2 -N 2 mixture into hydrate reservoir allows CH 4 recovery and CO 2 storage at the same time as shown in Fig. 9 [174][175][176].CO 2 hydrates are more thermodynamically stable than CH 4 hydrates, therefore they spontaneously exchange [177].Swapping between CH 4 and CO 2 retains adequate hydrates and stabilizes hydrate-bearing sediments [178,179].The process of CH 4 -CO 2 exchange was also confirmed by injection of liquid CO 2 through methane hydrate sediment [180].MRI imaging also approved the CO 2 /CH 4 substitution in sandstone core plugs [181].Furthermore, field simulation was used to evaluate the replacement process of CH 4 hydrate with CO 2 when the CO 2 liquid is present [182].The possibility of CO 2 hydrate nucleation and replacement in the CH 4 -CO 2 sweeping process was also confirmed through a theoretical approach by using the density functional theory (DFT) coupled with the reference interaction site model (RISM) [183].Qta et al. [184] employed Raman spectroscopy to study liquid CO 2 and CH 4 replacement in the hydrate.They found that CH 4 molecules may fit into relatively narrow gaps.Kvamme et al. [185] combined MRI and Phase Field Theory to create the model needed to visualize the conversion of CH 4 hydrate into CO 2 hydrate in the sandstone.These techniques (MRI and Phase Field Theory) were also used to identify kinetics of CO 2 hydrate formation in porous media [186].
The replacement of CH 4 hydrate with CO 2 is controlled by the chemical potential of gas molecules, mass transfer, and hydrate history [188].The efficiency of CO 2 replacement for extracting natural gas hydrates is influenced primarily by injection rate and total amount of injected CO 2 , along with the thermodynamic conditions [147].It was also proposed that low-concentration and biocompatible hydrate inhibitory chemicals could induce CH 4 recovery and confine CO 2 in hydrate consortiums [189].Inhibitors like NaCl may also help to accelerate the process of replacing CO 2 , and improve the prospects of diverting thermodynamic equilibrium conditions outside the CH 4 hydrate stability zone [190].
Molecular dynamic simulation shows that this process is followed by dissociation of methane hydrates and then formation of an amorphous CO 2 hydrate layer, i.e., the formation of CO 2 hydrate as the amorphous layer results in a constraint on the mass transfer [188].However, while some studies show the transition of guests between adjacent cages through their faces only by destroying their water structure, density functional theory shows a direct transition mechanism [191].In another study, molecular dynamics simulation shows that CO 2 promotes early nucleation of CH 4 bubbles during the methane hydrate decomposition [192].This process leads to form mixed CO 2 -CH 4 bubbles with a high concentration of CO 2 .This CO 2 stabilizes the interface by reducing surface tension and lowering the bubble's critical size, facilitating methane hydrate decomposition.
A high occupancy ratio of large to small cages of methane sI hydrate has been reported in the sediment which might affect CH 4 -CO 2 swapping [193].The morphology of hydrate crystals may also affect this process.The crystal morphology of the CH 4 + CO 2 hydrates is affected by the composition in the liquid phase, i.e., it changes from polygons to sword-like as subcooling temperature increases [194].
CH 4 -CO 2 swapping uses little energy and produces little water, making it competitive with other exploitation methods [195,196].Nevertheless, the commercial utilization of CH 4 -CO 2 swapping is hindered by the limitation imposed by mass transfer constraints, leading to a slow process [197,198].Experimental data showed that CH 4 might be selectively replaced with CO 2 , with an estimated CH 4 average distribution coefficient of 2.5 between gas and hydrate states [199].The hydrate kinetics can also be improved by adding water infusions during CO sequestration in hydrate reservoir [200].Moreover, thermal stimulation and higher sediment hydrate fraction can increase the process methane hydrate replacement with CO 2 [179].
After the replacement process, the 13C NMR spectroscopy showed the existence of CH 4 in the tiny cages of structure II, but only a small number were found in the hydrate of structure I [201].The quantity of CO 2 captured during the hydrate phase depends on the reservoir's temperature, pressure, and hydrate saturation.After dissociation, gas composition examination of the hydrate showed a significant amount of CO 2 , which is moderately affected by temperature [202].Another important factor is the pressure of the injected CO 2 .For instance, the higher CO 2 injection pressure results in higher replacement rate and CH recovery [201].
There may be some unfavourable effects of this phenomenon.For instance, the recovery of CH 4 can cause shrinkage, whereas the injection of CO 2 can cause swelling and permeability reduction [203].Furthermore, even though researchers have verified the CO 2 /CH 4 exchange in the pore space and the reservoir's mechanical stability for a period of h, the rate of a gas exchange over 24 h could not be very high [204].Therefore, hydrate stability in porous media should be experimentally determined, i.e., optical pore-scale observations can be used as a procedure to map hydrate transition and hydrate stability zones in the sediments [205].
Additionally, CO 2 +N 2 mixture is preferred over pure CO 2 injection into the hydrate reservoirs [206].CH 4 recovery from hydrate reservoir by flue gas injection (CO 2 + N 2 ) is highly affected by its composition and pressure [207][208][209].The composition of injected gas has a minor impact on displacement efficiency at high flow rates [210], whereas semi-continuous gas injection significantly improves recovery of CH when CO 2 levels are low [211].The molecular dynamic simulation also showed that the higher ratio of CO 2 : N 2 increases the nanobubbles nucleation which may affect the replacement process of CH 4 with CO and the structural ordering of water molecules [212].A study showed that the maximum concertation of N 2 in the CO 2 -N 2 mixture should be around 30 mol% [172].Saeidi et al. also showed that the methane production increases by injection of CO 2 -N 2 mixture rather than injection of pure CO 2 into the CH 4 hydrate in the sediment, i.e., the maximum release of CH 4 was observed at 20 mol% N 2 in the flue gas [213].

Mechanical properties of gas hydrate in sediment
Gas hydrates naturally exist in the oceanic sediments and permafrost locations [214].Gas hydrates are stable in nature, with methane as the main gas, along with traces of other gases such as ethane, CO 2 , and H 2 S Fig. 9. CH 4 -CO 2 swapping or exchange by CO 2 injection in hydrate reservoir, allowing CH 4 recovery and CO 2 storage.Reprinted with permission of Elsevier [187].
M. Aminnaji et al. [215][216][217][218][219]. Approximate global gas hydrate inventory is estimated to be around 1.8 × 103 Gt of carbon, which is equivalent to a methane volume of 3.0 × 1015 m 3 [171].The substantial quantities of carbon present have led to the recognition of methane hydrate as a prospective energy source and a geological hazard [220][221][222].The process of gas extraction from methane hydrates (for example using CO 2 injection) has the potential to trigger various geological hazards, including subsea landslides, casing deformation, and production platform collapse [223,224].Therefore, it is crucial to conduct a comprehensive investigation into the mechanical characteristics of hydrates sediments.However, in the context of CO 2 hydrate formation in the geological formations, understanding the mechanical assessments of hydrate-bearing sediment (HBS) based on the geotechnical testing at macroscopic and microscopic levels is important to provide insights into the stability of CO 2 hydrate in sediment.This section summarizes mechanical assessments of hydrate-bearing sediment and how some factors such as hydrate saturation, confining pressure, and sediment composition affect HBS mechanical performance.

HBS's mechanical behaviour
Safety assessment of methane hydrate reservoirs is essential, with particular emphasis on the analysis of their strength characteristics in the case of CO 2 or CO 2 /N 2 injection.The evaluation of mechanical characteristics of sediment-containing hydrates primarily involves the utilization of two methods: the elastic property test, which is an indirect approach, and the mechanical strength test, which is a direct approach [223].
Triaxial test is one of the most common methods for mechanically assessment of hydrate-free sediment (HFS) and hydrate-bearing sediment (HBS).In this regard, the volumetric strain is the ratio of the sediment's modified volume to its initial volume.In addition, the axial strain is defined as the ratio of the sediment's changed length to its principal length.The difference between major and minor primary stress in a triaxial test is also defined as deviator stress.During the triaxial test conducted on the specimen (a sample of HBS), both normal stress and shear stress are normally applied.
In the zone where the deviator stress increases with axial strain at a slower rate, HBS deforms plastically.Although higher axial strain increases the deviator stress rate, shearing sand particles may generate more significant rotation, slippage, and rearrangement.This phase crushes and sheds the cemented sand particles around the hydrate particles.Moreover, the separated hydrate particles will keep the sand particles near to their original position [225].The preservation of hydrate particles prevents sand particle rearrangement; thus, the particles must manoeuvre around neighbouring particles.Consequently, HBS may exhibit dilatancy [225] (dilatancy is the volume change in shear-deformed granular materials).In the hydrate-cemented cluster, wedge-shaped hydrates hardly deform, preventing sand particle rearrangement [226].At the yielding zone, deviator stress hardly varies and may even decrease with axial strain.This disperses the hydrate-cemented cluster and disrupts the cementation structure.The shear band is the primary location of deformation [227].
Numerous triaxial testing apparatuses have been developed specifically for HBS analysing.Notably, Yamaguchi University [228,229], Kyoto University [230], National Institute of Advanced Industrial Science and Technology (AIST) [231], University of Calgary [232], and Dalian University of Technology [233,234] have made significant contributions in uncovering the macroscopic mechanical characteristics in assessing the geotechnical implications associated with gas hydrate production.X-ray CT was utilized to conduct a series of experiments aimed at elucidating the microscopic structural properties of HBS [235].Additionally, a pressurized sub-sampling system was developed specifically for X-ray CT scanning purposes.In this study, Takeya et al. reported that hydrate, which was stored under preservation conditions that deviated from the norm, exhibited complete envelopment and stabilization due to the presence of a thin layer of ice [236].Nevertheless, due to the challenging nature of achieving X-ray penetration under high-pressure conditions, only a limited number of mechanical studies have been conducted at the microscopic level.
Shear strength and pore pressure of sediments hold significant importance in ensuring the stability of sediments [237].The available literature suggests a positive correlation between shear strength of sediments containing methane hydrates and several factors, namely methane hydrate saturation [231], effective confining pressure [238], pore pressure [229], and fines content [239].Sediments containing methane hydrates also demonstrate elevated shear strength at reduced temperatures, as reported by Jiang et al. [240] and Shen et al. [241].Furthermore, numerical simulations showed that an increase in salinity has a detrimental effect on the shear strength of HBS [242].This decrease in shear strength can be attributed to the inhibitory effect of salinity on the formation of hydrates, as highlighted by Chen et al. [243].However, the primary cause of macroscopic deformation in hydrate sediments is attributed to the migration or slip between individual sand grains [244].
Moreover, as the degree of deformation increases, the localized tensile/shear stresses surpass the strength threshold of the hydrate cement, thereby resulting in the inevitable occurrence of damage or failure in the hydrate cementation process [245].In the separate studies, Ghiassian and Grozic [246] and Grozic and Ghiassian [247] performed undrained triaxial shear tests on sand containing methane hydrates.The findings of these experiments indicated that the presence of hydrates led to enhancements in the strength, stiffness, cohesion, and internal friction angle of the sediment.
Hydrates have been observed to provide cementation [248,249].However, the dissociation of hydrates can potentially lead to a reduction in the stiffness of sediment layers [250], ("stiffness" is the sediment's early deformation resistance as seen by the deviator stress-axial strain curve's first slope).Moreover, liberation of gas and water resulting from hydrate dissociation would compromise the interparticle bonding, thereby exacerbating the reduction in the rigidity of sediments containing hydrates.Therefore, it is crucial to ensure the preservation of the rigidity of HBS to prevent geological hazards during the process of gas hydrate extraction by CO 2 injection [223].

Hydrate saturation effects
Sediment strength is highly affected by hydrate saturation.Iwai et al. conducted undrained triaxial tests on sandy sediments containing CO 2 hydrates [251].Their findings revealed a positive correlation between hydrate saturation and the strength and stiffness.Sun et al. conducted undrained triaxial experiments on sand containing methane hydrate [252].Their findings revealed a positive correlation between failure strength and both methane hydrate saturation and effective confining pressure.The effect of hydrate saturation on HBS strength has been studied by numerous researchers which are summarised by Wu et al. (2020) [253].
It has been observed that hydrate saturation has a minimum effect on the HBS strength at low hydrate saturation.This can be attributed to the formation of hydrate only on the sand particle surface with minimal interaction between adjacent sand particles.Consequently, the shear force can exceed the cementation strength of the hydrate, leading to minimal strength of the sediment [254].In contract, at higher hydrate saturation, the presence of cementing due to pore-filled hydrates may prevent sand particle displacement and provide increased resistance to pressure.A substantial cluster of sand particles cemented by hydrates can create localized challenges for shearing.Experimental studies on triaxial compression tests for CO 2 -hydrate sand have demonstrated a similar trend aligning with the discussion on the effect of hydrate saturation on the strength of HBS [255].
The significance of hydrate saturation and hydrate pore habit in relation to permeability and water retention characteristics has been well-established in previous studies [256][257][258].The permeability of HBS can exhibit significant variations by several orders of magnitude, even when the hydrate saturation remains constant [259,260].The pore structure HBS has been determined to exhibit a pore-filling pattern through in-situ seismic analysis conducted at the Blake Ridge [261] and the Mallik sites [262], as well as wave velocity measurements performed on pressure cores obtained from the Nankai Trough [263].Moreover, it is worth noting that most HBS created in laboratory settings tend to display pore structures characterized by either grain-coating or contact-cementing patterns.This is particularly observed when these sediments are formed under unsaturated conditions, specifically through the utilization of the excess-gas method [264].
Hydrate saturation plays a crucial role in determining the quantity of gas that can be dissociated from the hydrate.Additionally, it can have substantial impacts on the physical characteristics of the hydrate reservoir, including permeability and thermal conductivity.These factors influence the behaviour of both dissociated gas and flow of water within the reservoir.Hence, the assessment of hydrate saturation holds significant importance in determining the economic viability of industrial operations pertaining to the extraction of natural gas hydrate.Xiong et al. provided a concise discussion on the influence of hydrate saturation on the dissociation behaviours of methane hydrates within a one-dimensional experimental setup [265].

Confining pressure effects
Adequate confining pressure can increase HBS strength.At enough confining pressure, sand and hydrate particles may interlock more forcefully, increasing internal sediment friction.However, higher confining pressure may impede fracture development and reduce sand and hydrate mobility [228].In triaxial tests employing on frozen HBS, HBS deviator stress shows an increase and subsequent fluctuation with increasing confining pressure [233].Winters et al. examined the impact of pore pressure on methane hydrate bearing sandy and silty sediments under undrained shear conditions [266].The results indicated a decrease in pore pressures for sandy sediments, while silty sediments exhibited a positive pore pressure response.
Previous studies have indicated that an elevation in effective stress can result in various consequences, such as increased deformation, reduced permeability, volumetric yield, and even particle fragmentation [267][268][269].It has been observed that the complete conversion of hydrates into gas and water doesn't occur instantaneously upon reduction of pore pressure below the equilibrium state [270,271].The process of dissociation in hydrate reservoirs involves a temporal duration from initiation to completion, with an intermediate region existing between the dissociated and undissociated areas [272].The findings above suggest that the sediments containing hydrates in the transition zone exhibit low pore pressures and high effective stresses, accompanied by a gradual decline in saturation.
Several well-documented hydrate reservoirs, including various locations in the Nankai Trough (offshore Japan), the Gulf of Mexico, and the Krishna-Godavari Basin (offshore India), predominantly consist of sandy formations situated at depths exceeding 2000 m below the water surface [273,274].It is anticipated that particle fragmentation is expected to take place in these regions during the process of depressurization, potentially influencing the mechanical characteristics of the sediments.Furthermore, it should be noted that the generation of fine particles, which are smaller than the pore throat, can occur as a result of particle breakage.The movement of these particles potentially cause blockages.This phenomenon has been reported in studies conducted by Uchida et al. [275], Cohen et al. [276] and Lei and Seol [277].It is important to recognize that such occurrences can have detrimental effects on the long-term production of gas.According to Zhou et al. [278], the long-term gas production leads to an elevation in effective stress.Hence, it is imperative to investigate the mechanical properties of sediments containing hydrates across a diverse range of effective confining pressures particularly in the context of CO 2 injection to the hydrate reservoir.

Sediment composition effects
Factors such as particle shape, size distribution, and percentage of fine components can impact the mechanical behaviour of HBS.Since breaking and rearranging of larger particles is more difficult, HBS is more influential in host sediments with more large particles.When the sediments have equal average particle sizes, a broader particle size distribution can potentially increase the HBS strength [279,280], although hydrate coordination number and sand particle surface area can influence this strength.Apart from the pore size distribution, sand particle roundness affects HBS strength.For example, for the same grain size, hydrate saturation, and effective stress, HBS strength increases with sand particle roundness.Under appropriate confining pressure, rounder sand particle shapes show less strain-softening [254].A higher proportion of fine components may also result in the formation of large clusters of hydrate-cemented sand and fine particles with intergranular strengthening [279].These hydrate-cemented clusters interact with nearby sand particles to prevent "force chains" from bending during shearing, enhancing microscale dilatation and strength.
The analysis conducted at site 570 of the Deep Sea Drilling Project, located in the Middle America Trench, revealed that sediments containing hydrates exhibited significantly larger particle sizes compared to those lacking hydrates in both the upper and lower strata [281].Additionally, a substantial proportion of sand and silt was observed in these sediments.Nevertheless, it is worth noting that in the continental slope of the South China Sea, specifically at a depth of 200 m, the sediments predominantly consist of silty sand and clay, with a minimal presence of sand.Based on findings from the Ocean Drilling Program Leg, it was observed that the lower boundary of gas hydrate stability was situated at a depth 40-100 m shallower than the bottom simulating reflection [282].This discrepancy was attributed to the impact of sediments on the hydrate equilibrium.Furthermore, pore water contains a diverse range of salt ions.The interactions between these ions and water molecules have a significant impact on the hydrates stability [283].

Creep test
Creep, where a geo-strain material increases over time under a specific load, is essential in long-term HBS mechanical behaviour forecasts.HBS creep has four steps: (a) transient creep stage, where elastic or plastic deformation may occur as soon as a load is applied, (b) damping creep stage, where the strain rate is initially high but gradually falls, (c) steady-state creep stage, where the strain rate almost completely stabilizes, and (d) accelerating creep stage, where the material fails quickly as the strain rate index rises.The strain rate is high at transient and damping creep stages but decreases as the creep test advances [234].
Mountjoy et al. demonstrated the potential for creep deformation in methane hydrate-bearing layers [284].There have been limited reports on creep tests conducted on sediments containing methane hydrates, despite the significance of understanding their creep behaviours in order to forecast the enduring stability of these layers accurately [285].Parameswaran et al. conducted initial creep tests on frozen sand samples that contained tetrahydrofuran (THF) hydrate at a temperature of 270 K [286].They successfully obtained creep curves and creep rates for different levels of axial stress.Cameron et al. examined creep characteristics of sands consolidated with THF hydrate under uniaxial compression [287].They reported that the strength of the hydrate-consolidated sands surpassed that of the sands consolidated with ice.Durham et al. conducted creep tests on high-purity methane hydrate and found that methane hydrate exhibits over 20 times greater strength and resistance to creep compared to ice [288].The drained triaxial compression creep tests were conducted by Miyazaki et al. on methane hydrate-bearing sand [289].These tests were then compared to the strain rate dependence of strength observed in constant-strain-rate tests.Their findings indicated that the sand specimen containing methane hydrate exhibited characteristic creep curves and exhibited significant time-dependent behaviour.Miyazaki et al. introduced a nonlinear viscoelastic constitutive equation for sand containing methane hydrate, which was derived from the analysis of creep phenomena [290].Li et al., also performed a series of experiments to investigate the creep properties of methane hydrate in the presence of ice [291].The study focused on examining the influence of deviator stress, confining pressure, and temperature on the creep behaviour of the material.
Based on existing sources [292,293], it has been established that methane hydrate, which is present in Arctic and permafrost regions, has the potential to exist in conjunction with ice.Therefore, it is essential to investigate the creep characteristics of frozen sediments containing methane hydrates (in conjunction with ice) prior to engaging in commercial methane hydrate extraction in Arctic and permafrost areas through different methods including CO 2 injection.

Effect of CO 2 replacement on the mechanical behaviour of HBS
Natural gas hydrates extraction and CO 2 replacement involves disrupting its thermodynamic equilibrium.When considering cost, complexity, and ecological issues, depressurization, thermal stimulation, and CO 2 replacement are the key options.As discussed, CO 2 replacement method stores CO 2 and releases trapped gas from hydrates.It is carried by exerting precise pressure and temperature and adding gas/liquid CO 2 to the HBS [294].Tri-axial or other geo-mechanical devices have never employed CO 2 replacement due to their operating complexity and low efficiency.CO 2 -HBS and CH 4 -HBS mechanical characteristics were compared in early testing.In terms of stiffness, strength, stress-strain response, and consolidation properties, CO 2 -HBS appears more stable than CH 4 -HBS, regardless of whether the temperature is above or below the freezing point (oceanic or permafrost zone) [295].With the same temperature and pressure, the CO 2 hydrate may have a higher subcooling temperature than the CH 4 hydrate, making it more stable.

Fluid flow through gas hydrate in the sediment
To investigate economic viability though the CO 2 -CH 4 hydrate replacement process, the effect of gas hydrates on permeability must be understood [296].Shen et al. examined how appropriate confining pressure and triaxial compression affect methane hydrate permeability [297].Shear band creates a large permeability increase when axial strain exceeds a certain magnitude during shear.Li et al. reported water relative permeability for silts with various methane hydrate saturations [298].Kneafsey et al. also examined gas permeability of sand and sand-powder mixes in methane hydrate-containing medium [299].As water content increases, the moist sand's gas permeability drops.
Moreover, as pore space increases, methane hydrate sand deposits' effective permeability often decreases.Zhao et al. injected methane into the sea sediments to test gas permeability [300].Confining pressure, hydrate saturation, and initial water saturation affect gas permeability.The microscopic process through which hydrate changes flow characteristics were also investigated by Xu et al. [301].They found five hydrate occurrence methods in sediments with hydrates: particle inclusion, pore filling, throat filling, particle cementation, and bearing.
Zhao et al. developed a Masuda permeability correction model to evaluate dynamic permeability during the depression-reduction process by varying effective stress (0.2-5.0 MPa) and hydrate saturation (36.6-53.1 %) [302].Deng et al. also formulated the pore compressibility index (PCI) for hydrate sediments [303].PCI is theoretically linked to permeability.Using logging data, sediments with high permeability showed lower PCI values and higher porosity.Even low hydrate saturation reduces permeability and PCI.Hence, accurate permeability prediction enhances hydrate detection and identification for CO 2 -CH 4 hydrate replacement process.
Cui et al. examined methane hydrate dissociation spatially using an L-shaped hydrate simulator [304].Experiments showed that water migration unevenly emptied sediment pore spaces and affected hydrate breakdown geography.Water seepage and migration trap gas in pores to stop gas production, limiting active fluid migration to a narrow zone [304].With an increase in flow space, gas flow rate can be kept very low to reduce hydrate formation and resolve the blockage [305,306].Konno et al. [307] found that hydrate-saturated layers with higher permeability increases the production fluid's gas-to-water ratio.However, water seepage may have transferred sediment and sand from the overlying to the production well, clogging it quickly.Using controlled drawdown rates, Yin et al. examined the cumulative water and gas generation during methane hydrate decomposition [308].A slow decomposition rate can also regulate the water-gas ratio and increase water production.Gao et al. [309] used multi-stage depressurization to reduce water production and hydrate breakdown, but it reduces gas production efficiency.Nonetheless, several studies on gas hydrate extraction and multiphase flow contain inconsistencies.Therefore, comprehensive studies are required to identify the flow characteristics in the HBS during CO 2 injection.

Field scale test for hydrate-based CCS
CO 2 storage in the ocean as gas hydrates for CCS is appealing due to the several key factors, such as the vast size of the ocean, the ability of wet sediments to store CO 2 as gas hydrates, large CO 2 storage capacity offered by gas hydrates, the circulating currents of the ocean, and a favourable equilibrium conditions and hydrate stability zones existing in ocean [177].In the past, some field tests were carried out to extend lab-based gas hydrate studies to real-world applications.Currently, exploratory studies are highly active in the area of natural gas hydrate extraction [310].A summary of the field scale tests conducted for CCS as gas hydrates in the deep ocean is provided in this section.
Initially, Brewer et al. [311] used the remotely operated vehicle (ROV) to observe methane hydrate formation at a depth of 910 m in Monterey Bay's deep waters.In free seawater, a buoyant mass of transparent CH 4 hydrate was observed to form quickly at the gas-water interface.The pore spaces of a coarse sand matrix were filled with CH hydrates, and the sand column was cemented.Then Brewer et al. [312] later used the same ROV to discharge hydrocarbon gases and liquid CO into natural seawater and marine sediments.Hydrate formation was virtually instantaneous for some gases at 910 m depth and 3.9 • C. Brewer et al. [313] also conducted trials at depths ranging from 349 to 3627 m and at temperatures 8 • to 1.6 • C. Hydrate formation occurred promptly from the gaseous state at a depth of 349 m and the seawater-carbon dioxide interface at a depth of 3627 m had a rapid increase due to the formation of significant amounts of hydrates.A reservoir of liquid carbon dioxide expanded more than four times with the formation of hydrate, which would dissolve later.
Brewer et al. [314], later conducted a series of in situ experiments to investigate the formation of a CO 2 hydrate using an ROV in Monterey Bay at a depth of 619 m.The pH measurements made near the hydrate-seawater interface showed a wide range of values, conditional to the method of injection and the surface area of the hydrate formed.Brewer et al. [315] then measured the rise and dissolution rates of freely released CO 2 droplets in the open ocean by releasing liquid CO 2 at 800 m [4.4 • C] and imaging the rising droplet stream.The initial rise rate for 0.9 cm diameter droplets was 10 cm/s at 800 m, and the dissolution rate was 3.0 μmol cm − 2 s − 1 .Brewer et al. [316] also developed a carbon-fiber composite accumulator of 56L internal capacity for safely delivering CO 2 in the deep sea.This technique confirmed the rapid re-building of the hydrate skin in which surface cracks are quickly annealed.A small-scale CO 2 sequestration experiment in northern California (684 m depth, ~5 • C, pH ~7.7) was also carried out by Brewer et al. [317].Their results indicated the rapid CO 2 dissolution, with all CO 2 being depleted in a little more than 2 days.Tsouris et al. [318] injected particulate composites of CO 2 hydrate/liquid CO 2 /seawater phases in seawater at depths between 1100 and 1300 m.An ROV tracked the resultant composite particles, and the composite particles' dissolution rate was reported higher than that of pure CO 2 droplets.Rehder et al. [319], measured the dissolution rates of pure methane and CO 2 hydrates directly on the seafloor within the gas hydrate stability zone.They reported dissolution rates of 4.15 ± 0.5 mmol CO 2 /m 2 s and 0.37 ± 0.03 mmol CH 4 /m 2 s.Hester et al. [320], measured the dissolution of natural hydrate cores on the seafloor at Barkley Canyon (850 m depth and 4.17 • C).The flux of gas from the shrinking yellow hydrate core was 0.15 ± 0.01 mmol gas/m 2 s, while the white hydrate dissolved faster at 0.25 ± 0.02 mmol gas/m 2 s.In years later, Brewer et al. [321], carried out a small-scale deep-sea field test to extract CH 4 gas from CH 4 hydrate by injection of a CO 2 /N 2 gas mixture.However, they reported a complete and rapid dissociation of the CH 4 hydrate with the release of liquid water and the creation of a mixed gas phase.
It was indicated in earlier field tests that it's not favourable to form CO 2 hydrates on the ocean floor due to susceptible perturbations.This shifted the research interest towards forming and storing CO 2 as gas hydrates in oceanic sediments.However, the long-term stability of these hydrates is the key issue.Recently, Qureshi et al. [164,165,322,323] provided the first-ever experimental evidence of the CO 2 hydrates stability in the sediments at the simulated depth of 1 Km [10 MPa, 4 • C] on the laboratory scale by evaluating their stability in brine/fresh water for 15-30 days using both gas and liquid CO 2 .Their experimental results indicate that the formation of CO 2 hydrates is faster with liquid CO 2 , and CO 2 hydrates are more stable inside the sediments.Moreover, the use of amino acid [86,324,325] gas hydrate promoters or additives like L-tryptophan [326,327] can significantly enhance the kinetics of CO 2 hydrate formation [328,329].Hence, many field scale and lab scale studies related to CCS in ocean at depths ranging from 300 to 3600 m have indicated a good potential for CO 2 storage as gas hydrates.However, further large-scale technological demonstrations are still needed to develop a full-scale commercial hydrate-based CCS process.

Outlook
Industrial-point-source CCS, Direct Air Capture (DAC), and Bioenergy with Carbon Capture and Storage (BECCS) are today's three primary technological approaches to carbon capture.Of these, Industrial-point-source CCS holds immediate promise for decarbonization, particularly for industries with limited alternative options.By 2030, around 110 million tons per annum (MTPA) of CO₂ is projected to be captured, but to meet the COP26 commitments, this needs to increase to 715 MTPA by 2030 and 4200 MTPA by 2050.However, the adoption and scaling of CCUS face significant challenges [330].
Although there are various approaches for adoption and scaling of CCS, CO 2 hydrate offers the substantial applications for CCS.While this review (part 1 and part 2) shows a significant understanding of CO 2 hydrate and its applications in CCS, there are still various challenges that need to be further investigated.In this closing section, some potential and challenge of hydrate-based CCS are overlooked for future research and development.
Hydrate-based carbon capture (HBCC) presents a promising solution for the efficient CO 2 capture.However, researchers should explore novel materials and operational strategies that not only improve the efficiency of HBCC processes but also reduce energy consumption.It is essential to ensure that this technology is economic and scalable for CCS solutions.Based on estimations, the cost of avoiding 1 tonne of CO 2 through HBCC technology ranges from 20 to 40 US dollars, with an associated energy penalty of 15 %.In comparison, the conventional absorption method currently incurs a cost of 40-100 US dollars per tonne of CO 2 , accompanied by an energy penalty of 30 % [331].Therefore, HBCC exhibits potential competitiveness relative to the conventional absorption approach.HBCC possess a distinct advantage in industrial scales due.Firstly, its utilization of a water-based process sets it apart.Secondly, it exhibits a tolerance towards impurities present in the feed gas.Lastly, there is potential for energy savings through the integration of hydrate formation and dissociation enthalpies.However, the current obstacles to implementation include slow kinetics and a lack of extensive industrial experience [331].Furthermore, there is limited research pertaining to the assessment of costs associated with HBCC.
The site selection for CCS is another important factor which requires consideration of several economic factors.The injection flow rate, location, pipeline size, and operational conditions all contribute towards the economics of CCS.For example, non-condensable pollutants like N 2 , O 2 , and Ar, which are often captured with CO 2 , may increase storage project costs.These impurities may also reduce site's storage capacity [332].The costs associated with CO 2 storage rely upon the specific attributes of the geological reservoir.The most cost-effective approach for CO 2 storage involves utilizing onshore depleted oil and gas fields by leveraging pre-existing wells [333].However, as this review paper shows, there is a potential application for permanently CO 2 storage through CO 2 hydrate formation in geological reservoirs or CO 2 /CO 2 -rich injection into gas hydrate reservoirs (CO 2 -CH 4 exchange process).Furthermore, although the concept of CO 2 -CH 4 hydrate replacement process has been proved, further comprehensive studies are required to characterise this concept and flow behaviour in the hydrate bearing sediment.
To enhance the feasibility of CO 2 injection into hydrate reservoirs for the CO 2 -CH 4 exchange process, it is essential for the CO 2 capture hub to be in close to the hydrate reservoir.This ensures cost-effectiveness in terms of CO 2 transportation and injection.When dealing with substantial distances between CO 2 capture plants and CO 2 sequestration sites, the expenses associated with CO 2 transportation can surpass the capture process itself [334].Fig. 10 shows the global map of CCS projects and hydrate reservoirs.This provides an insight into the suitability of the location for CO 2 storage within the gas hydrate reservoir.
It is imperative to acknowledge that most strategies for achieving deep decarbonization are intricately linked to the expansion of the current transport infrastructure and the development of new infrastructure.It can be postulated that the establishment of CO 2 pipeline network would likely entail a comparatively streamlined, cost-effective, and expeditious process in contrast to the development of a hydrogen infrastructure [337].According to IPCC [338], considerable expertise has been acquired globally in the development and operation of CO 2 pipelines, encompassing both terrestrial and subsea installations.Nevertheless, However, the gas hydrate flow assurance study for the feasibility of CO 2 transportation is required.

Declaration of competing interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

Fig. 1 .
Fig. 1.CO 2 Temperature-entropy (T-S) diagram predicted by PVTsim.Note: the value of entropy depends on the reference state.

Fig. 2 .
Fig. 2. Typical schematic diagram of CO 2 hydrate formation risk in the well injection.75 bar is assumed at the wellhead for the prediction of CO 2 hydrate equilibrium temperature.

Fig. 4 .
Fig. 4. CO 2 hydrate phase boundary at different water contents predicted with PVTsim.A few experimental data from Youssef et al. [48] are added for comparison.

Fig. 10 .
Fig. 10.Global map of CCUS projects and gas hydrate reservoirs.Data for the World Map of CCS Facilities has been extracted from the Global Status of CCS 2022 Report [335].World Map of gas hydrate has been extracted from United States Geological Survey [336].