Several researchers have acknowledged that storing CO₂ in deep salty aquifers represents one of the most successful strategies for reducing CO₂ in the atmosphere (Li et al., 2023; Javaheri & Jessen, 2011; Yang et al., 2013; Frerichs et al., 2014; Burnol et al., 2015) , due to its already available technological and significant possible storage capacity (Bachu et al., 2000) . However, most saline aquifers are presently unsuitable for other synergistic or competing uses (Trémosa et al., 2014) especially in highly populated nations (Procesi et al., 2013; Quattrocchi et al., 2013) . The absence of facilities including wells for CO₂ injection, surface handling equipment, and transportation pipeline networks makes many salty aquifers less desirable as potential storage reservoir formation alternatives at the moment (Li et al., 2023) .

Recently, the topic of discussion has been the potential for CO₂ to be stored in salty aquifers (Bachu, 2003; Wei et al., 2022) in combination with EOR storage (Boundary-Dam-Apache). These studies address topics including site description, as well as long-term planning, according to (Bachu, 2010) as well as the range of complementary and competing subterranean uses (Procesi et al., 2013) .

Because of their vast pore volume and high permeability, aquifer reservoir formations can hold massive amounts of CO₂, cutting down on an overall number of CO₂ injection wells required and easing pressure dissipation (Shukla et al., 2010) . Upon flowing into the storage reservoir formation, supercritical CO₂ dislocates brine in the pore spaces and initiates a chain reaction with the formation’s minerals (groundwater, gas, and rocks) that lead to either formation of different chemical substances or the breakdown of current minerals (Le Gallo et al., 2002; Cantucci et al., 2009) . Mineral formation and dissolution may alter rock porosity and, as a result, the capacity of the storage reservoir (Wdowin et al., 2013) .

Previous studies (Tapia et al., 2018) have shown that supercritical CO₂ has a density of approximately 0.6 - 0.7 g/cm³ in saline reservoirs, the low density can influence the uprise movement of CO₂ towards the cap-rock because of buoyancy forces due to density variation.

According to previous studies (Armitage et al., 2013) , a large aquifer storage basin with a high sealing capacity of the cap-rock is necessary for long-term and stable CO₂ storage. Given that cap-rock, a formation at the reservoir’s top with low to very low permeability (Fleury et al., 2010) should operate as a seal to prevent CO₂ migration from the storage deposit below. With its low permeability, cap-rock is crucial for preventing CO₂ from escaping the retention reservoir and minimizing leakage. Another essential element that may result in cap-rock integrity loss and CO₂ leakage is the existence of unrecognised fracturing and fault-plane. However, from the review, no previous researcher has investigated further study on the impacts of CO₂-brine reactivity on injectivity and the fracturing network and fault plane for CO₂ storage, as such, a thorough research study is required to investigate the effect of this reactivity and previous faults on cap-rock stability (Buttinelli et al., 2011) .

Figure 3 depicts the four major trapping processes that may safely handle CO₂ storage:

a) Structural/stratigraphic

b) Residual

c) Solubility

d) Mineral trapping.

Stratigraphical and/or Structural Trapping: When CO₂ is introduced into a geological formation, it may move to the top and get trapped behind an impermeable top seal (Kim et al., 2017) where it can remain as a free phase that cannot go beyond or access the cap-rock pore region except by slow diffusion or fractures as illustrated on Figure 3(a). It’s the most common kind of subsurface trapping system.

CO₂ Rock Pores Capturing: Injection of CO₂ into aquifer porous rock gives rise to fluid displacement due to differences in density. Figure 3(b) shows how the fluid displaced by the CO₂ flows, returns, disconnects, and traps the remaining CO₂ within pore spaces. It has been observed that the method occurs exclusively when water drainage processes occur during CO₂ injection, rather than inside structural and stratigraphic traps (Bachu et al., 2007) .

Solubility trapping: CO₂ dissolves in brine through the chemical process of solubility, plummeting the quantity of CO₂ gas-phase (Figure 3(c)). The density

of brine is increased by the solubility of CO₂ and this may cause gravitational instability, hastening the transition of injected CO₂ to CO₂-lean brine (Kneafsey & Pruess, 2010) .

Trapping due to Mineral: CO₂ undergoes chemical interactions with minerals and salty water found around the rock’s periphery. Carbonate precipitation occurs as a consequence of these chemical reactivities and has the effect of sequestering CO₂ in an inert lesser phase across a specific subsurface geological timeframe, as demonstrated in Figure 3(d) above (Bachu, 1998) . It is a more gradual process than the solubility capturing that takes place over a longer geologic period (Gunter et al., 2004; Sundal et al., 2014) .

Although a number of studies have argued that storing CO₂ in salty aquifers would be more effective than CO₂ is often stored in depleted oil and gas fields, these assessments neglect to take into consideration the expenses connected as a result of the use of storage in saline reservoirs. In many instances, hydrocarbon fields already have production facilities in place, which, with only relatively modest adjustments, may be modified to meet storage operations. These changes can be made in order to accommodate storage activities. In addition, they have been well defined throughout the stages of crude oil exploitation, and they may employ CO₂ for storage as well as EOR. As a consequence, it is possible that storing CO₂ in hydrocarbon formations is better than storing it in saltwater aquifers.

The sequestration of CO₂ in depleted oil and gas reservoirs is widely recognised as one of the most efficient techniques of CO₂ storage. Among these advantages are the following: 1) Drained hydrocarbon reservoirs have been the subject of substantial research both before and during the hydrocarbon exploring period, including research about their storage capacity; 2) Both onshore and offshore infrastructural facilities, existing infrastructure, including CO₂ injection wells and transportation, may be used with little modification for the storage process (Sigman et al., 2021) ; 3) If this was not the case, CO₂ gas injection to enhance oil recovery would have been less attractive and ends many years ago. Suitable hydrocarbon field data as an analogue may be utilise in illustrating the efficacy of cap-rock across geologic timeframe to strengthen oil and gas reservoirs (Heinemann et al., 2016) .

Reservoir rocks and brine properties are similar and commonly found in both hydrocarbon reservoirs and deep aquifer storage systems (Li et al., 2014) . Oil and gas reservoirs, on the other hand, may be considered for EOR, making them more economically advantageous than saline aquifers (Zangeneh et al., 2013; Gao et al., 2016) . Because the worldwide average recovery factor from a typical oilfield is about 40% (BGS, 2017) , usually, many barrels of oil are still in the hydrocarbon reservoirs. It’s the primary motivation for the global deployment of EOR. However, technological deployment difficulties remain challenging, although these issues may have been foreseen and handled throughout the exploration and production phase of a field, they have just recently come to light.

Gas injection is the most frequently utilised among the current EOR alternatives such as gas, thermal, chemical, and plasma-pulse injection techniques. Miscible gases (CO₂, nitrogen, and natural gas) are injected into the reservoir using the gas injection process to decrease the interfacial tension between oil and water and increase oil displacement efficiency while preserving reservoir pressure. CO₂ injection seems to be the optimal choice because it may reduce oil viscosity and is less expensive than liquefied natural gas (Jaramillo et al., 2008) . More CO₂ for improved oil recovery is anticipated to be accessible from vital gathering point sources with the introduction of CCS technology (IPCC, 2005) . It has been claimed, for example, that the use of CO₂ for EOR has resulted in an increased output of about 260,000bopd in the U.S.A (GCCSI, 2017) .

The International Energy Agency (IEA) (2015) set out the following as the primary criteria for the implementation of CO₂ oil recovery support (EOR) projects:

1) Additional site characterization involves investigating potential leakage risks, such as the condition of the cap rock and any abandoned wells with integrity problems.

2) Additional evaluations of surface processing plants’ fugitive and discharging emissions

3) Leakage rates may be estimated from specific locations and the normality of the reservoir’s behaviour can be determined by increased monitoring and field surveillance.

In addition to the criteria mentioned above, governments must address legal problems and enact laws to cover storage facility operations. These issues arise because CO₂-EOR and CO₂ permanent storage fall under two distinct regulatory umbrellas, the former focuses on resource recovery, whereas the latter is concerned with waste management Marston (2013) . Legal issues might arise, for instance, regarding the proper decontamination of oil left in situ after production ceases, if hydrocarbon recovery is prioritised. Such a scenario may be jurisdiction-specific and especially significant when onshore mineral and storage rights are owned privately.

One of the critical variables that must be rigorously defined before a CO₂-EOR project is initiated involves the kind and number of contaminants in CO₂ streams. Depending on the CO₂ source and the accompanying collecting procedures, a variety of contaminants might be contained as part of the CO₂ injection fluid (Porter et al., 2015) . The permissible impurities and concentrations are determined by a mix of transit, storage, and economic factors. CO₂ streams must meet a minimum purity standard of roughly 90% vol (Jarrell et al., 2002) . In the case of CO₂, increasing impurity levels may cause the phase boundaries to move to even higher pressures, which demonstrates the requirement for higher injection pressures to keep the injected CO₂ in a higher concentration. It has also been established that non-condensable contaminants lower CO₂ storage capacity by a factor that is larger as compared to the mole percentage of contaminants present in the CO₂ injection system (IEAGHG, 2011) .

The most typical issue connected to contaminants is corrosion. Due to the corrosive effects that impurities (such as SO₂, NO₂, CO, H₂S, and Cl) may have on transportation and injection systems, it is essential to limit the quantity of contaminants on a scenario rationale. Additionally, it is essential to develop feasible mitigation solutions for potential problems (Porter et al., 2015) . It is important to note that even though certain impurities such as CO, H₂S, and CH₄ have a naturally occurring propensity to be combustible, safety considerations for combustibility are not typically factored into the evaluation of safety measures. This is because it is highly unlikely that the CO₂ injection stream will be combustible due to the low quantities of the impurities in question. Another issue that may influence the effectiveness of the CO₂-EOR process is an excessive concentration of O₂ in CO₂ streams. The presence of O₂ in the reservoir may stimulate microbial activity (Porter et al., 2015) , which can ultimately lead to operational problems such as injection obstruction, oil deterioration and oil souring.

The previous studies (Igunnu & Chen, 2014) have connected environmental problems of EOR with volumes of water production that may include radioactive compounds and dangerous heavy metallic substances. Failure to implement an appropriate waste management and disposal strategy implemented, these chemicals may pollute drinkable water sources. Although restrictions exist, governments must ensure that operators follow current laws when brine re-injection for recovery is permitted. For example, White (2009) provided evidence to show that the Weyburn-Midale CO₂ storage project in Canada is an example of how collected in the Weyburn oilfield, CO₂ might be used for EOR and retention. Not only does this procedure recover a significant amount of previously unrecovered oil, but it also increases the oilfield’s useful lifespan by 20 - 25 years (Thomas, 2008) . According to Zaluski et al. (2016) , Verdon (2016) long-term surveillance, generated seismicity evaluation of CO₂’s impact on the reservoir and the fluids’ mutual effect, oil and minerals have been the primary focuses of CO₂-EOR research (Hutcheon et al., 2016) . The Weyburn case history inspired (Cantucci et al., 2009) to study the geochemical equilibrium between brine and oil and develop a biogeochemical model for CO₂ storage in underground reservoirs. A hundred years into the future, they predicted precipitation and disintegration processes based on research into reservoir formation during CO₂ injection. During the first year of the simulation, they discovered that the two most significant chemical processes taking place in the reservoir were those involving CO₂ and the dissolution of carbonate. Furthermore, the development of chemical characteristics over time indicated that CO₂ might be securely stored via mineral and solubility trapping.

Perera (2016) acknowledges that though the CO₂-EOR method has substantially improved oil recoveries, further improvement is needed using the following strategies: 1) Using numerical evidence (Tenasaka 2011) proved that this was possible within the normal range of CO₂ injection. In the San Joaquin basin, scientists injected around 2.0HCPV (hydrocarbon pore volume) of CO₂ to prove that there was a greater possibility to extract more oil, almost 67% of the originally present oil (OOIP) was recovered. In addition (Tenasaka 2011) demonstrated that there was a greater recovery of oil from his numerical methodology; 2) Using a better and innovative CO₂ flooding design and well management can positively influence more oil recovery from the reservoir; 3) Increasing the mobility-ratio by raising water’s viscosity (Thomas, 2008) . Minimising miscibility pressure using miscibility-enhancing agents (Kuuskraa & Ferguson, 2008) .

An additional option for sequestering human-caused CO₂ is the use of inaccessible coal seams. Since cleats are present inside the coal matrix, the system is somewhat permeable. In addition, the matrix of coal is full of tiny holes (micropores) that may take in a lot of air. Coal has a greater affinity for CO₂ in the gas phase than methane, and this is the basis for the CO₂ trapping process. According to (Shukla et al., 2010) , this means that the methane output could be increased while the CO₂ was permanently stored. Thus, large amounts of CO₂ may be stored while commercial unconventional shale methane (CBM) processes are made more productive and profitable (Krooss et al., 2002; Gilliland et al., 2013) . It should be underlined that although CO₂ increases CBM synthesis, the overall quantity of methane generated is not always higher than without the addition of CO₂. The International Energy Agency Working Group on Greenhouse Gases (IEAGHG, 2009b) provided an overview of the essential technical parameters needed for the effective implementation of enhanced coal seam production, which include: 1) The homogeneity Reservoir; 2) Threshold of fractures and fault planes; 3) Upper depth limit; 4) Coal geomorphology; 5) Permeability adequacy.

Two experimental locations, the Alberta Carbon Trunk Line (ACTL) in Canada with the San Juan Basin pilot in the United States, have reportedly used the ECBM approach, the conclusion of the evaluations for the Alberta project (Krooss et al., 2002) : 1) Even in constrained reservoirs, continuous CO₂ injection is feasible; 2) Injection may be performed notwithstanding a decrease in injectivity; 3) Expected Significantly Enhanced CBM Production; 4) The injected carbon dioxide stays in the reservoir, boosting sweep efficiency (Lakeman, 2016) .

Key findings from the San Juan Basin pilot study revealed that methane recovery exceeded the predicted ultimate primary production. Second, the pilot project was not cost-effective because of the price of gas at the time it launched. However, if the price of gas continues to climb in the years to come, the pilot project may end up being lucrative; thirdly, because fuel prices were high when the project was first implemented, the trial project was not profitable. An additional pilot study of a Coal field is being done in the Appalachian Basin, with a focus on a variety of surveillance and verification techniques, and accounting (MVA) methods are being utilised to understand better storage complexity, (Gilliland et al., 2012) . Furthermore, the possible ECBM implementation, as well as the significant variations in output across nearby wells with the same stratigraphic, has been studied in the beginning. However, further research is needed to characterise and portray such disparities adequately.

While CO₂ EOR has been used successfully for years in the upstream oil and gas sector, the utilisation of CO₂ during ECBM is still limited in its recognition. There are still many unknowns when it comes to ECBM recovery, however, the current understanding of how the CO₂ EOR process works could help alleviate some of those worries. For example, the creation of technically recoverable shale in ECBM could need a look at already-existing technology from the oil industry that might be converted with very little work. Existing well materials may be utilised as a baseline for good integrity in ECBM production following suitable changes. Furthermore, field and reservoir management techniques processes, such as risk monitoring and evaluation may be modified from those already in place and used at any point in the lifetime of a project.

There exists a considerable body of literature on subsurface basalt deposits within central igneous provinces, and many researchers McGrail et al. (2006) , Pollyea et al. (2014) and Matter et al. (2016) have suggested subsurface basalt deposits as a possible CO₂ storage solution. Basaltic rocks make up around 8% of the continents and a large portion of the ocean bottom. As a result, basaltic rocks have a massive theoretical CO₂ storage capacity (Anthonsen et al., 2014) . One of the most important advantages of such rocks’ potential to store CO₂ is that their physical and chemical characteristics, as well as the amount of divalent metal ions they contain, may fix CO₂ during past geological periods (Van Pham et al., 2012) . Permeability and porosity of Basalt flows, on the other hand, are very variable and often consist of an interior low-permeability region surrounded by periphery regions with high permeability. That said, the rubbly zones between separate flows are the most critical portions of a basalt sequence for CO₂ storage.

Complimentary CO₂ injected into subsurface basalts (the CarbFix pilot scheme, Iceland) may replace water in the rock’s pore spaces and cracks (Matter et al., 2011) . The decrease in water content may impede basalt carbonation and hydration. Therefore, it may be possible to inject CO₂ and the right amount of water into the same reservoir based on the following points: 1) Because it offers sufficient depth, denser CO₂ liquid may sink, which delays the release of CO₂ back into the atmosphere; 2) It makes it possible to form stable carbonates in a shorter amount of time than would normally be required by geologic processes; 3) It prevents acidic basement fluids from rising via an impervious sediment layer; 4) It can be converted into a stable hydrate; 5) It is essential to remember that a small quantity of CO₂ leaking does not inevitably damage the sea bottom ecosystems.

Because of the anticipated development of dolomitic carbonate minerals, with the possibility of CO₂ being trapped in basalts for thousands of years, analysing changes in rock volume and the chance of fracture self-healing are key issues to consider. Quantitative research on such issues has been conducted (Van Pham et al., 2012) . These researchers found out that at 40˚C, oxide consumed a significant amount of calcium, limiting its use to the creation of siderite and ferromagnesian carbonates. Magnesite formed with ankerite and siderite at temperatures between 60˚C and 100˚C. In addition, they found that the carbonation and hydration processes both increased solid volume and inhibited pore access, decreasing the maximum quantity of CO₂ stored.

In addition to studying the mineral assemblages present in basalt, researchers have looked at the mechanisms of mineral carbonation in serpentinites, intending to acquire a more thorough comprehension of the fundamentals of CO₂ storage for the future utilising basic magnesium silicates. In serpentinites, rocks that are both plentiful and thermodynamically suitable for the production of magnesium carbonates, CO₂ combines with magnesium silicates to produce magnesium carbonates (Seifritz 1990) . Andreani et al. (2009) conducted an analysis of the carbonation process using flow parameters that were optimised. They found out that low-flow or low-diffusion regions are the only ones where porosity and permeability decrease. In contrast, higher flow rates contribute to armouring of mineral surfaces associated with the initial disintegration.

And further reason for alarm has been the occurrence of fractures in the basalt formations’ protective cap-rock. Due to the possibility of leakage via the fissures, basalts are not likely to be suitable for CO₂ storage. However, CO₂ seeping via fissures has the potential to mineralize and be trapped inside the formation, delaying its escape to the surface (IEAGHG, 2011) . As such, further research is required to characterise the kinetics of CO₂-basalt interactions.

Alternate storage alternatives, including serpentinite and basaltic reservoir formations, could be necessary; knowledge improvement is required to identify possible uncertainties and investigate mitigation techniques. To do so, it may be necessary to apply computational techniques and to research the impact of carbon dioxide and rock contact on the ease or difficulty of migration, as well as to clarify CO₂ migration in the presence of likely fault plane, fractures.

Previous studies Yang et al., (2008) have shown that subsurface CO₂ storage systems as hydrates is another potential, modern strategy that uses a lattice of water molecules to capture CO₂ molecules. When water and the right level of pressure and temperature are present, CO₂ hydrate may form rapidly (Circone et al., 2003) . Furthermore, its rapid formation kinetics may allow for some self-sealing in the rare crack development in the hydrate top layer formation. The development of CO₂ hydrate might have applications in both underground geology and the storage of CO₂ in the ocean. Because the formation of hydrate turns out to be very stable at higher pressure and low temperature of about 10˚C (Rochelle et al., 2009) they can only be used in certain situations, such as shallower sediments under cold oceans bed and under extensive areas of icy hydrate formation, where it’s possible that there is a lack of sufficient space for a CO₂ collecting plant.

The process of CO₂ hydrate storage mechanism involves buoyancy and drives the migration of liquid CO₂, which is capped by a developing impermeable CO₂ hydrate cap (Figure 4). The CO₂ hydrate equilibrium zone is lowered by injecting liquid carbon dioxide into deep water or sub-permafrost sediments (Rochelle et al., 2009) . As more liquid CO₂ moves into the colder hydrate stable zone, a layer of impenetrable CO₂-hydrates builds inside the pore holes of the sedimentary reservoir rock. The US Department of Energy (DOE) on the other hand proposed a CO₂-EGR-based hydrate storage technology (enhanced gas recovery). CO₂ is injected into sediments that contain methane hydrates, releasing the methane from the hydrates and forming CO₂ hydrates in its place (Burnol et al., 2015) . Because CO₂-EGR is still a novel idea, research into its effectiveness has been limited so far. According to Oldenburg (2003) , one of the primary issues is the use of Methane which might in turn react with the injected CO₂ in an enhanced gas cycle, resulting in the gas resources being depleted.

Presently, the technology required to store CO₂ in hydrates is not very advanced with most researchers (Jemai et al., 2014; Talaghat et al., 2009) focusing on theoretical modelling and lab-scale experiments (Ghavipour et al., 2013; Ruffine et al., 2010; Rehder et al., 2009) . For this reason, there are still a number of challenges to be solved, especially with CO₂-EGR. However, local temperature and pressure fluctuations caused by drilling through hydrate-bearing

sediments may destabilise the hydrate formation in its entirety (Khabibullin et al., 2011) . How the CO₂-CH₄ hydrate exchange mechanism affects methane production, and how hydrate cap development may be shown as the major outstanding problems that need to be solved to improve the evaluation of hydrate storage viability.

Previous studies (Garapati et al., 2015; Pruess, 2006; Song & Zhang, 2013) have emphasized that dense-phase CO₂, like water, has thermal characteristics that allow it to transfer large quantities of heat. However, it has better physical characteristics, such as substantially lower viscosity, more excellent compressibility, and expansibility. As a result, CO₂ may be utilised in the process of geothermal energy by extracting heat from the ground. CO₂ can efficiently reach the rock mass due to its low viscosity and may be considered a medium for enhanced geothermal systems’ operating fluid (Pruess, 2006) . Enhanced geothermal systems that use water as the heat transmission fluid experience drawback of fluid loss. The inability to provide adequate water supplies is associated with financial difficulties because of the value placed on this resource. On the other hand, if upgraded geothermal systems (EGS) were to lose their reliance on CO₂, this would make underground geological storage of CO₂ possible, which might have further benefits.

It is essential for the effectiveness of CO₂-EGS storage that the rock mass loaded with CO₂ be separated from the surrounding rock mass, which is filled with water. These conditions are maintained in large part due to the formation of crystals of carbonate minerals at the interface between the CO₂-heavy centre of EGS with the brine-rich outside. Only countries having subsurface resources at economically feasible depths where the temperature is high enough would be able to use this technology. Additionally, synergistic use of the subsurface may be more complicated and need more collaboration in heavily populated nations.

The technique is still in its early stages of technology readiness (TRL), with most research so far focused on theoretical modelling (Plaksina & White, 2016) and small-scale laboratory experiments. The main challenge to this method’s development is the lack of clarity about the efficiency of closing off the area surrounding the CO₂ source. To top it all off, nothing is known about the interactions between CO₂ and rocks at high temperatures. Understanding how CO₂ affects dissolution and precipitation, and how that affects changes in fracture permeability and EGS functioning, requires further study