Comprehensive Insights into Carbon Capture and Storage: Geomechanical and Geochemical Aspects, Modeling, Risk Assessment, Monitoring, and Cost Analysis in Geological Storage

Abstract

Carbon Capture and Storage (CCS) is a vital climate mitigation strategy aimed at reducing CO₂ emissions from industrial and energy sectors. This review presents a comprehensive analysis of CCS technologies, focusing on capture methods, transport systems, geological storage, geomechanical and geochemical aspects, modeling, risk assessment, monitoring, and economic feasibility. Among capture technologies, pre-combustion capture is identified as the most efficient (90–95%) due to its high purity and integration potential. Notably, most operational CCS projects in 2025 utilize pre-combustion capture, particularly in hydrogen production and natural gas processing. For geological storage, saline aquifers and depleted oil and gas reservoirs are highlighted as the most promising due to their vast capacity and proven containment. In the transport phase, pipeline systems are considered the most effective and scalable method, offering high efficiency and cost-effectiveness for large-scale CO₂ movement, especially in the supercritical phase. The study also emphasizes the importance of hybrid integrated risk assessment models, such as NRAP-Open-IAM, which combine deterministic simulations with probabilistic frameworks for robust site evaluation. In terms of monitoring, Seismic monitoring methods are regarded as the most reliable subsurface technique for tracking CO₂ plume migration and ensuring storage integrity. Economically, depleted reservoirs offer the most feasible option when integrated with existing infrastructure and supported by incentives like 45Q tax credits. The review concludes that successful CCS deployment requires interdisciplinary innovation, standardized risk protocols, and strong policy support. This work serves as a strategic reference for researchers, policymakers, and industry professionals aiming to scale CCS technologies for global decarbonization.

1. Introduction

A critical area of research that has drawn world attention is Carbon Capture and Storage (CCS). It entails four essential steps, which include locating sources of carbon dioxide (CO₂), capturing the gas, transporting it, and storing it underground. These stages are illustrated in Figure 1 [1], highlighting the comprehensive nature of CCS research and its importance in addressing environmental challenges. One of the most urgent problems we tackle today is climate change, primarily due to the increasing CO₂ levels in the atmosphere, which are caused by human activities. This issue has gained global attention, encouraging widespread efforts to search for effective ways to control CO₂ emissions [2,3,4,5,6,7]. The successful deployment of CCS is not only a technical challenge but also heavily influenced by policy and regulatory frameworks. The international CCS policy landscape is now anchored by generous fiscal incentives and strict regulations. For instance, the United States offers substantial financial support through Section 45Q tax credit, which provides up to $85 per metric ton of CO₂ stored in saline aquifers and $60 per metric ton for CO₂ used in enhanced oil recovery under the Inflation Reduction Act (IRA) [8]. The Bipartisan Infrastructure Law and IRA together dedicate roughly $12 billion to CO₂ capture, transport and storage projects [9], and EPA’s Class VI underground-injection rules require permits (and ongoing monitoring) for each CO₂ storage well [10]. In Canada, the federal government provides a refundable Carbon Capture, Utilization, and Storage (CCUS) Investment Tax Credit of up to 60% for direct-air capture (50% for other capture) of qualifying costs [11], while also imposing a steadily rising carbon pollution price (increasing C$15/t–year from 2023 to 2030) [12]. These measures plus rigorous federal and provincial environmental and safety approvals underpin Canada’s CCS rollout. In the EU, the CCS Directive (2009/31/EC) sets a comprehensive safety framework: any storage project must meet detailed site-selection and geological-assessment criteria, undergo an Environmental Impact Assessment, and then operate under strict monitoring, reporting and post-closure plans (with operators held liable for leakage) [13]. On top of this, the newly adopted Net-Zero Industry Act creates a binding EU-wide target of 50 million tonnes CO₂ storage capacity by 2030, assigning shares of this target to oil and gas producers [14]. At the international level, a 2009 amendment to the London Convention/Protocol now permits cross-border shipping of CO₂ for sub-seabed storage (provided exporting and importing states reach an agreement) [15]. The EU explicitly treats its Emissions Trading System (ETS) and CCS laws as a compliant “arrangement” under that Protocol, meaning companies can use EU storage sites for imported CO₂ under the existing legal framework [13]. Nationally, countries like Norway and the UK have translated these rules into domestic law (e.g., Norway’s CO₂ Storage Act and the UK’s offshore CO₂ licensing regime) to speed permitting and ensure long-term oversight [16,17]. Taken together, these tax credits, carbon prices, R&D grants and binding regulatory safeguards show how multi-level governance from bilateral treaties to national regulations and EU directives—is being used to enable and de-risk large-scale CCS deployment. In 2021, it was estimated that worldwide CO₂ emissions related to energy would hit 36.3 gigatons (Gt), emphasizing the scale of the problem and the need for immediate steps [18]. Each year, around 40 gigatons of CO₂ are released into the atmosphere, contributing remarkably to environmental concerns [19]. This staggering amount highlights the urgent need for strategies to minimize emissions and address their impact on the planet [19].

Over the past decade, researchers have explored several strategies to mitigate the increasing levels of CO₂ in the atmosphere. These efforts have incorporated initiatives such as reducing energy consumption, transitioning to lower-carbon fuels, and developing methods to capture and store CO₂ emissions. Each of these approaches focuses on tackling the issue from different angles, offering potential solutions to a complex global problem [20]. Over time, it became evident that CCS technology holds significant potential in tackling climate change by capturing CO₂ emissions and safely injecting them into subsurface geological formations [20]. If executed effectively, CCS has the potential to decrease atmospheric CO₂ levels to 450 ppm by the year 2100, offering an essential step toward stabilizing the climate [21]. There are various methods for storing carbon, including underground storage, ocean storage, and converting it into minerals [22]. The most common method is geological storage, which involves injecting CO₂ deep into the earth’s surface, such as into coal seams, depleted oil and gas fields, and saline aquifers. While these storage options demonstrate the technical feasibility of CCS, their successful implementation depends on a comprehensive understanding of geological storage processes, including geomechanical stability, geochemical interactions, risk assessment, monitoring and economic considerations. Therefore, this review aims to (i) synthesize current advancements in CCS technologies and processes; (ii) evaluate geological storage options with emphasis on safety and integrity; (iii) examine risk assessment and monitoring frameworks; and (iv) analyze economic drivers and highlight future research directions. By integrating these aspects, the study provides a comprehensive reference for researchers, policymakers, and industry professionals seeking to accelerate large-scale CCS deployment.

2. Phase Behavior of CO₂

Selecting an appropriate geological site for CO₂ storage involves evaluating multiple factors, including the physical properties of CO₂ and how it changes phases under varying temperature and pressure conditions. CO₂ exists in different states, such as Liquid, gas, solid, and supercritical, but when injected into deep geological formations (typically deeper than 800 m), it primarily remains in a supercritical state due to the high temperature and pressure at those depths [23]. This behavior is illustrated in the CO₂ phase diagram (Figure 2).

The effectiveness of CO₂ storage in geological formations is determined by how much CO₂ can be contained within a given volume. This efficiency improves as the density of CO₂ increases, as higher density reduces buoyancy forces, making storage more secure. Several factors influence CO₂ density, primarily geological conditions such as pressure and temperature. For example, depending on the temperature gradient, CO₂ density can either rise or drop significantly with depth [24]. Therefore, sedimentary basins with lower temperature gradients and cooler conditions are generally more suitable for CO₂ storage [20]. The ability of CO₂ to dissolve in water, along with the interfacial tension (IFT) between the two, plays a crucial part in the storage process both during and after injection. Generally, higher pressure enhances CO₂ solubility and strengthens interfacial tension, while rising temperatures tend to reduce both [25]. Therefore, after CO₂ is injected into deep geological formations, the main mechanisms governing its flow and movement will involve several factors, as depicted in Figure 3.

3. Key Components of Carbon Capture, Transport, and Storage

CCS includes three main steps: CO₂ capturing, moving it to a storage site, and storing it safely, as illustrated in Figure 4. Each of these steps plays a vital role in making technology work as intended.

3.1. CO₂ Capture

During combustion, carbon dioxide (CO₂) is produced, and capturing it requires an effective removal process. Many technologies are available for capturing CO₂; however, they significantly raise the overall cost of a CCS project by 70–80% [27]. There are four primary methods for capturing CO₂: post-combustion capture, pre-combustion capture, oxy-fuel combustion, and direct air capture. These methods capture CO₂ from industries such as oil refining, biogas processing, and the production of cement, ammonia, steel, and iron [28].

3.1.1. Pre-Combustion Capture

Pre-combustion capture removes CO₂ that is unintentionally produced during an intermediate phase of a chemical conversion process. This approach is commonly used in industries such as coal gasification and ammonia production [29]. During ammonia production, CO₂ is generated alongside hydrogen in the steam reforming process. Before ammonia synthesis can proceed, this CO₂ must be removed, typically through absorption using monoethanolamine (MEA) [30]. In an integrated gasification combined cycle (IGCC) power plant, CO₂ needs to be separated from hydrogen (Figure 5). It is usually done utilizing physical solvents like Rectisol and Selexol [29,31]. Pre-combustion capture is the most effective among the available CO₂ capture methods, but it is less favorable due to its high implementation cost.

3.1.2. Post-Combustion Capture

Post-combustion capture refers to the process of extracting CO₂ from waste gas streams after carbon sources have been converted into CO₂, such as through the combustion of fossil fuels or the digestion of wastewater sludge. This method is applicable across many industries, such as power generation, production of fuel, cement manufacturing, iron and steel processing, ethylene oxide production, and biogas purification [33]. Post-combustion CO₂ capture can be achieved through various techniques, including solvent absorption (Figure 6), solid sorbent adsorption (such as porous organic frameworks), membrane separation, cryogenic processes, and pressure or vacuum swing adsorption [34,35]. Monoethanolamine (MEA) absorption is the most widely used method for CO₂ capture. However, its high heat requirement for regeneration makes it less cost-effective for specific industries [36]. Post-combustion capture is the most affordable and commonly used for CO₂ removal, though it is less efficient compared to oxy-fuel combustion capture [37].

3.1.3. Oxy Fuel Combustion Capture

Oxy-fuel combustion capture works by burning fuels using oxygen, resulting in flue gas with a high CO₂ concentration, which makes it easier to capture. The capture efficiency is highest in this method, reaching around 85–90%and it is also cost-efficient [38]. As the name implies, oxy-fuel combustion is primarily used in processes that involve combustion, such as power generation in fossil-fuel plants, iron and steel industries, and cement manufacturing. One drawback of this method is the high cost of oxygen, along with the significant environmental impacts, including CO₂ emissions, caused by the energy-intensive air-separation needed for its production [39]. Figure 7 shows the schematic of oxy-fuel combustion capture.

3.1.4. Direct Air Capture (DAC)

Direct air capture (DAC) is an emerging technology that directly captures CO₂ from the ambient air utilizing chemical sorbents or filters [40,41,42,43,44,45,46]. DAC aims to target the diffuse CO₂ existing in the atmosphere, making it a flexible tool to achieve negative emissions. In 2025, DAC transitioned from hype to grounded realism, with over 130 pilot facilities in development globally reflecting a strategic shift toward scalable, modular systems and operational data generation [47]. DAC systems generally use either solid sorbents (e.g., amine-based materials) or liquid solvents (e.g., alkaline solutions) to bind with CO₂ [46,48], which is then released through pressure changes or heating, and later it can be utilized or stored according to project requirement (Figure 8). DAC systems are increasingly being co-located with industrial infrastructure to leverage waste heat and renewable energy, improving cost-efficiency and enabling integration into existing operations [41,42,43].

Table 1. Summary of different CO₂ capture methods (Appendix A).

Method	Source of CO2	Approx. Efficiency (%)	Typical Applications	Cost (USD/ton)	Solvent/Sorbent Examples	Energy Penalty	Integrated with Combustion?	Technology Readiness Level	Ref.
Pre-combustion capture	Before fuel is burned	90–95%	IGCC plants, hydrogen production.	50–100	Selexol, Rectisol, methanol-based solvents	2–4 GJ/t CO2	Yes	9 (commercially deployed in gas processing, hydrogen, ammonia); 7–8 for IGCC integration	[49,50,51,52,53]
Post-combustion capture	After fuel is burned	85–90%	Power plants, cement, steel	40–80	Monoethanolamine (MEA), 2-Amino-2-methyl-1-propanol (AMP), Piperazine (PZ), blended amines, biphasic solvents, non-aqueous amines	3–4 GJ/t CO2 is accurate for MEA-based systems; advanced blends like AMP/PZ can reduce it to ~2.8 GJ/tCO2	Yes	9 (full-scale systems proven and commercially deployed)	[27,51,52,53,54]
Oxy-fuel combustion	During fuel combustion	85–90%	Industrial heating systems	60–100	Oxygen from ASU, calcium looping for CO2 purification	200–300 kWh/t CO2 (ASU penalty)	Yes	6–7 (Scale-up to pilot or demonstration system)	[51,52,53,55,56]
Direct Air Capture	Atmospheric CO2	Solid sorbent:10–75%, Liquid solvent > 75%	Ambient air CO2 removal	600–1300	Solid amines, alkaline solvents (NaOH, KOH), metal–organic frameworks (MOFs), ionic liquids	Solid sorbent systems: 5–8 GJ/t CO2, Liquid solvent systems: often 6–8 GJ/t CO2	No	5–6 (Early pilot testing in realistic conditions)	[40,41,42,46,57,58,59,60,61,62]

presents a comprehensive comparative overview of the major CO₂ capture methods, including pre-combustion, post-combustion, oxy-fuel combustion, and direct air capture (DAC). It compares these technologies across several key dimensions such as the source of CO₂, capture efficiency, energy penalty (expressed in GJ/tCO₂), solvent or sorbent examples, typical applications, cost per ton of CO₂ captured, integration with combustion systems, and technology readiness level (TRL).

3.2. CO₂ Conditioning and Transportation

CO₂ conditioning in CCS refers to the processing steps that immediately occur after capturing CO₂ to prepare the CO₂ stream for safe, efficient transport and underground injection. The captured CO₂ usually contains impurities such as carbon monoxide, water vapors, sulfur oxides, oxygen, hydrogen sulfide, hydrocarbons, and nitrogen, which notably change its thermophysical behavior and must be removed to meet transportation and storage standards [63]. Water vapor, particularly, should be controlled usually below tens of ppm to avoid issues like hydrate formation, corrosion, or acid generation when mixed with sulfur compounds [64]. Impurity removal and dehydration are essential prior to compression, which is required to bring CO₂ into the supercritical phase. In this state, CO₂ takes up less space and flows more efficiently through pipelines, which reduces transportation cost [65]. Impurities also influence pressure drop, viscosity, and the phase envelope, affecting compressor station spacing and energy required during transportation [63]. Compression can account for a considerable share of energy consumption (100 s to over 1000 kWh per ton), making it an essential economic driver in the CCS [66]. After conditioning, CO₂ is transported to storage sites. Pipelines are the most efficient means of CO₂ transport between their source and storage sites. Currently, these pipelines generally operate at a pressure of typically 10–16 MPa to ensure that CO₂ remains in the supercritical phase and to prevent two-phase flow that could compromise pipeline integrity and flow assurance [67]. Cost and safety are the primary concerns in CO₂ pipeline transport, mainly due to the potential hazards associated with high-pressure CO₂ release. The U.S. Department of Transportation’s PHMSA proposed a new rule in 2025 to strengthen safety standards in response to incidents such as the 2020 Satartia, Mississippi pipeline rupture. These standards include requirements for vapor dispersion modeling, emergency response training, and real-time monitoring systems [68]. Despite having challenges, the pipeline infrastructure of CO₂ has expanded significantly with over 2500 km of pipeline constructed in North America since the 1970s and more planned under the U.S. Bipartisan Infrastructure Law and Inflation Reduction Act [68]. The ships can also be utilized for transporting CO_2, especially for offshore storage or long distances where pipelines are not feasible [69]. Shipping is usually less energy efficient and more expensive than large-scale continuous transport via pipelines [67]. Additionally, trucks and tankers are used for transporting CO₂ over short distances or in pilot-scale projects, particularly when pipeline or shipping infrastructure is unavailable or economically impractical [70,71].

3.3. CO₂ Storage

CO₂ storage is a key component of the project aimed at reducing greenhouse gas emissions. After capturing CO₂ from various methods, it is then stored in different ways, mainly by injecting CO₂ into deep geological formations. Some common CO₂ storage methods have been explained below:

3.3.1. Ocean Storage

Ocean storage involves direct and indirect injection of captured CO₂ into the seafloor or the water column to isolate it from the atmosphere for several years [72]. Several techniques have been explored, such as deep ocean injections through ships or pipelines at depths greater than 1000 m, where CO₂ exists in a liquid-like state and is dispersed into sediments on the seafloor [73]. In such environments, CO₂ can dissolve slowly into seawater or form negatively buoyant CO₂ hydrates that may delay its return to the atmosphere [74]. The ocean’s natural buffering capacity and vast volume theoretically offer considerable storage potential, but this comes with serious ethical, environmental, and regulatory concerns [75]. The main problem lies in ocean acidification, as CO₂ dissolution decreases pH and may disturb the marine ecosystem, particularly calcifying organisms and deep-sea biodiversity [76]. Experimental field trials, such as the Japanese Nagaoka and Okinawa experiments and the Norwegian Sleipner CO₂ release, have helped to assess ecological risk and dispersion behavior [77]. However, widespread deployment remains scientifically and politically controversial, and as of 2025, ocean storage is not supported under major climate governance frameworks like IPCC’s primary mitigation pathways and the London Protocol [78,79]. While ocean storage has been extensively studied, it is still currently considered an experimental or legacy option rather than a front-line carbon sequestration method. This technique is currently under evaluation, and further research is required to evaluate its potential environmental impact and feasibility [80].

3.3.2. Bioenergy with Carbon Capture and Storage (BECCS)

Bioenergy with Carbon Capture and Storage (BECCS) is also a carbon storage method, in which CO₂ is captured while generating energy through biomass [81,82]. After that, CO₂ is stored in underground storage or underwater storage sites [83]. BECCS can be used with the other CO₂ storage methods to control the climate issue, but it needs a considerable amount of research to understand its potential fully [84,85].

3.3.3. Geological Storage

In geological storage, CO₂ is injected deep into the earth’s surface, like depleted hydrocarbon fields, coal seams, and deep saline aquifers [86]. Because of the significant number of geological structures available worldwide, this approach is convenient and widely used in different cases [87].

Deep Saline Aquifers

As compared to other geological storage techniques, saline aquifer formation has the highest salt sink for CO₂ storage due to its huge capacity [88]. The storage capacity of saline aquifers is estimated to be approximately 10,000 gigatons (GT) [89]. The Alberta Deep Saline basin is estimated to store 103 Gt of CO₂ due to the solubility trapping mechanism [90]. It is preferred to use saline aquifers for CO₂ storage because they cannot be used for industrial, agricultural, or other human purposes [91]. One of the main issues with CO₂ storage in saline aquifers is the buildup of pressure and migration of the plume, which may cause fractures in the formation, fault reactivation, and CO₂ leakage [92]. The main CCS projects to store CO₂ in saline aquifers are the Quest project [93], Sleipner project [94], Salah project [95], Snøhvit project [96] and Gorgon Project [97]. Several advantages and disadvantages of CO₂ storage in deep saline aquifers are discussed in detail in Table 2. As of 2025, around 10 large-scale CO₂ storage projects in saline aquifers are operational worldwide, and the details of these projects are provided in Table 3. Figure 9 illustrates the CO₂ storage in a deep saline aquifer.

Figure 9. CO₂ Storage in Deep Saline Aquifer (after [98]).

Figure 9. CO₂ Storage in Deep Saline Aquifer (after [98]).

Coal Beds

In Enhanced Coal Bed Methane (ECBM) recovery, CO₂ is utilized to produce coal seam gas [99]. In a Coal bed, diffusion of gas molecules takes place through a network of fractures that cause the desorption of tightly adsorbed methane. By injecting CO₂ into coal seams, the recovery of methane can be enhanced from 50% to around 90%. The CO₂ will remain absorbed in coal seams after the recovery of CH₄ [100]. CO₂ sequestration at coal beds occurs at shallow depths, with a depth range from 985 to 2953 ft [101]. The technology of CO₂ storage in Coal beds is in its early stages, and a couple of pilot studies have been conducted on its storage capacity and suitability. The first ECBM project was conducted in the San Juan basin. Some projects related to CO₂ storage in deep coal beds in Canada and Australia were also reported [102]. Globally, coal seams have an estimated CO₂ storage potential of around 200 Gt with significant contribution from China (~142.67 Gt) [103], Canada (~6.4 Gt) [101], and the USA (40–50 Gt) [104], which indicates that coal beds have the potential to store CO₂ in future.

Depleted Oil and Gas Reservoirs

The pressure inside the oil and gas reservoir decreases with time during the production phase. After all hydrocarbons have been extracted from the reservoir and there is no profitable way to extract more hydrocarbons, the reservoir is considered to be depleted or abandoned. The significant advantage of CO₂ sequestration in a depleted oil and gas well is that they already have a significant quantity of equipment installed on the surface and subsurface, which can be used for sequestration of CO₂ with slight modifications. Since these depleted oil and gas reservoir fields have already been used for the exploration and production phase, it provides a good understanding of their seal quality and caprock integrity [92]. Also, there is low pressure in depleted hydrocarbon reservoirs, so if we inject CO₂, there will be less stress and disturbance as compared to aquifers, which are naturally under high pressure [92]. Depleted gas reservoirs are much advantageous for storing CO₂ compared to depleted oil reservoirs due to the gas compressibility and its high ultimate recovery, resulting in a higher storage capacity [105,106]. A condensate gas reservoir is more favorable to store CO₂ as compared to wet and dry gas reservoirs because in a depleted condensate gas reservoir, there is more pore space available for injecting CO₂. Due to less interference from existing gas, it has better CO₂ injectivity and trapping [107]. The CO₂ storage capacity of depleted gas reservoirs is estimated to be around 390 Gt [108]. Although depleted oil and gas reservoirs are well-characterized and have existing infrastructure, their adequate CO₂ storage capacity relatively low because we cannot inject CO₂ at high pressure because it can fracture the cap rock, and high pressure can cause CO₂ to leak upwards through these wells, which can cause significant environmental risk [109]. CCS in depleted oil and gas reservoirs has the benefits of having less risk and being cost-effective, which is why it can play a significant role in global warming mitigation [110]. Along with storing CO₂ in depleted reservoirs, another practical method is CO₂ Enhanced Oil Recovery (CO₂-EOR). CO₂-EOR is a widely deployed method that serves as both a method to increase oil production and a viable pathway for geological CO₂ storage under storage CCS frameworks. In CO₂-EOR, captured CO₂ is injected into depleted oil reservoirs where it decreases oil viscosity and improves sweep efficiency, enabling additional oil recovery and allowing a significant portion of CO₂ to be trapped in the reservoir through structural, residual, and solubility mechanisms [111,112,113,114]. When utilized mainly for storing CO₂, CO₂-EOR can keep a significant amount of injected CO₂ stored underground, effectively transitioning the technology into a form of CCS. CO₂-EOR is the dominant contributor to operational CCS capacity in the USA, with CO₂ stored primarily in the Gulf Coast, Permian Basin, and Rocky Mountain region [115]. By using depleted reservoirs and CO₂-EOR, we are tapping into proven systems that not only help store carbon but also make use of existing oil and gas infrastructure, making it an innovative, affordable, and practical way to fight climate change, especially in places where we already understand the geology of the well.

Table 2 indicates that geological storage is the best for long-term CO₂ storage, so the next part of this paper will focus on CO₂ sequestration in geological storage only, and within geological storage, this paper will discuss saline aquifers and depleted oil and gas reservoirs. Around 43 commercial CCS projects were operational by 2024 (Figure 10 and Figure 11). Table 3 provides a comprehensive overview of global operational CCS projects, revealing key trends in carbon capture and storage. Depleted oil reservoirs (EOR) emerge as the most used storage type, reflecting their dual benefit of CO₂ sequestration and enhanced oil recovery. Saline aquifers remain a widely adopted option due to their vast capacity and geological suitability for long-term CO₂ storage. The USA leads in the number of operational projects, reflecting its substantial investment in CCS across sectors like natural gas processing, hydrogen production, and industrial manufacturing. Most projects utilize pre-combustion capture methods, especially in gas and hydrogen facilities, while industrial processes such as ethanol and ammonia production also contribute significantly. Post-combustion and oxy-fuel methods appear less frequently, mainly in coal and cement operations. Pipelines are the dominant mode of CO₂ transport, and several projects have achieved large-scale storage, with some surpassing 10 million tonnes, highlighting meaningful progress in global carbon mitigation.

Table 2. Advantages and Disadvantages of Different CO₂ Storage Types.

Method	Advantages	Disadvantages
Geological Storage	A substantial volume of CO2 can be stored in geological formations owing to their massive dimensions [116]. Carbon dioxide is sequestered inside geological formation reservoirs, so the risk of releasing it into the atmosphere is very low [117]. Geological formations are usually adjacent to the oil and gas fields, due to which carbon dioxide movement and storage are feasible [118]. Depleted oil and gas reservoirs are highly attractive for CO2 storage because they come with a wealth of geological data such as well logs, seismic surveys, and production history that significantly reduces uncertainty during site characterization. In many cases, existing wells and pipeline networks can be repurposed for CO2 injection and monitoring, which lowers capital costs compared to developing new sites. Moreover, the proven ability of these reservoirs to retain hydrocarbons over geological timescales provides strong confidence in their sealing integrity. Together, these factors accelerate project timelines and leverage decades of petroleum engineering expertise. Geological CO2 storage can provide additional financial incentives by coupling storage with resource recovery. In depleted oil reservoirs, CO2 injection can be used for Enhanced Oil Recovery (EOR), where additional hydrocarbons are mobilized and produced while simultaneously storing CO2. Similarly, coal beds enable Enhanced Coalbed Methane Recovery (ECBM), where CO2 injection displaces methane that can be captured and used as an energy resource. These co-benefits not only improve project economics but also provide a transition strategy for industries to adopt CO2 storage while still generating revenue.	Sometimes, there may be difficulties with selecting a site for carbon storage. Not every formation can be utilized for this purpose [119]. Geological storage has considerable cost implications because of the expenses associated with capture, compression, and transport of CO2, as well as the costs related to monitoring and maintaining storage sites [117]. Injection activities can cause pressure buildup, potentially activate faults or trigger earthquakes. This requires careful geomechanical monitoring and site-specific risk mitigation. Ensuring CO2 remains stored safely for centuries requires long-term monitoring commitments. Political or financial instability could jeopardize consistent oversight.
Ocean Storage	Carbon, as previously noted, is soluble in the ocean, facilitating the translocation of CO2 carried in seawater, which further enhances the ocean’s natural ability to draw down carbon from the atmosphere [120]. Unlike other geological formations, the mobility of the ocean increases the safety of CO2 storage in the sea by reducing leakage [121]. Very large theoretical capacity and potential for long-term storage as dissolved inorganic carbon or bicarbonate when alkalinity is increased, offering a pathway to durable sequestration if implemented responsibly [122].	Carbon sequestration involving CO2 injection in ocean processes requires an investigative setting and equipment, which may be costly and difficult to procure [123]. Ocean storage cannot be proven to inflict serious harm to the environment, but the mechanisms and ramifications remain misunderstood; therefore, this technology must be studied to determine its effective long-term use [124]. Ocean storage of CO2 raises significant ethical concerns because it involves large-scale manipulation of marine ecosystems, which could lead to irreversible ecological and biogeochemical impacts. Such interventions risk harming biodiversity, altering ocean chemistry, and exacerbating ocean acidification, thereby threatening marine life and food security for communities dependent on these ecosystems. Furthermore, these actions pose intergenerational justice issues, as the long-term consequences of ocean storage are uncertain and could impose risks on future generations without their consent. International governance frameworks, such as the London Convention and Protocol, strongly discourage or prohibit direct deep-water CO2 injection due to these ecological and ethical risks, reflecting a global consensus that the precautionary principle should guide such interventions [125].
BECCS	The significant advantage of this method is that it generates renewable energy while removing CO2 from the environment [126]. It is also an advantage that it can be utilized with existing infrastructure like power plants [127].	The drawback of this method is that it requires large areas to generate energy from biomass; this area can be used in other productive things like food production. In its early stages, there are concerns regarding efficiency and cost of the process [128]. Social, policy and market dependencies (sustainable biomass standards, carbon credits, long-term storage liability) make economic viability sensitive to policy design and public acceptance.

Table 2. Advantages and Disadvantages of Different CO₂ Storage Types.

Method	Advantages	Disadvantages
Geological Storage	A substantial volume of CO2 can be stored in geological formations owing to their massive dimensions [116]. Carbon dioxide is sequestered inside geological formation reservoirs, so the risk of releasing it into the atmosphere is very low [117]. Geological formations are usually adjacent to the oil and gas fields, due to which carbon dioxide movement and storage are feasible [118]. Depleted oil and gas reservoirs are highly attractive for CO2 storage because they come with a wealth of geological data such as well logs, seismic surveys, and production history that significantly reduces uncertainty during site characterization. In many cases, existing wells and pipeline networks can be repurposed for CO2 injection and monitoring, which lowers capital costs compared to developing new sites. Moreover, the proven ability of these reservoirs to retain hydrocarbons over geological timescales provides strong confidence in their sealing integrity. Together, these factors accelerate project timelines and leverage decades of petroleum engineering expertise. Geological CO2 storage can provide additional financial incentives by coupling storage with resource recovery. In depleted oil reservoirs, CO2 injection can be used for Enhanced Oil Recovery (EOR), where additional hydrocarbons are mobilized and produced while simultaneously storing CO2. Similarly, coal beds enable Enhanced Coalbed Methane Recovery (ECBM), where CO2 injection displaces methane that can be captured and used as an energy resource. These co-benefits not only improve project economics but also provide a transition strategy for industries to adopt CO2 storage while still generating revenue.	Sometimes, there may be difficulties with selecting a site for carbon storage. Not every formation can be utilized for this purpose [119]. Geological storage has considerable cost implications because of the expenses associated with capture, compression, and transport of CO2, as well as the costs related to monitoring and maintaining storage sites [117]. Injection activities can cause pressure buildup, potentially activate faults or trigger earthquakes. This requires careful geomechanical monitoring and site-specific risk mitigation. Ensuring CO2 remains stored safely for centuries requires long-term monitoring commitments. Political or financial instability could jeopardize consistent oversight.
Ocean Storage	Carbon, as previously noted, is soluble in the ocean, facilitating the translocation of CO2 carried in seawater, which further enhances the ocean’s natural ability to draw down carbon from the atmosphere [120]. Unlike other geological formations, the mobility of the ocean increases the safety of CO2 storage in the sea by reducing leakage [121]. Very large theoretical capacity and potential for long-term storage as dissolved inorganic carbon or bicarbonate when alkalinity is increased, offering a pathway to durable sequestration if implemented responsibly [122].	Carbon sequestration involving CO2 injection in ocean processes requires an investigative setting and equipment, which may be costly and difficult to procure [123]. Ocean storage cannot be proven to inflict serious harm to the environment, but the mechanisms and ramifications remain misunderstood; therefore, this technology must be studied to determine its effective long-term use [124]. Ocean storage of CO2 raises significant ethical concerns because it involves large-scale manipulation of marine ecosystems, which could lead to irreversible ecological and biogeochemical impacts. Such interventions risk harming biodiversity, altering ocean chemistry, and exacerbating ocean acidification, thereby threatening marine life and food security for communities dependent on these ecosystems. Furthermore, these actions pose intergenerational justice issues, as the long-term consequences of ocean storage are uncertain and could impose risks on future generations without their consent. International governance frameworks, such as the London Convention and Protocol, strongly discourage or prohibit direct deep-water CO2 injection due to these ecological and ethical risks, reflecting a global consensus that the precautionary principle should guide such interventions [125].
BECCS	The significant advantage of this method is that it generates renewable energy while removing CO2 from the environment [126]. It is also an advantage that it can be utilized with existing infrastructure like power plants [127].	The drawback of this method is that it requires large areas to generate energy from biomass; this area can be used in other productive things like food production. In its early stages, there are concerns regarding efficiency and cost of the process [128]. Social, policy and market dependencies (sustainable biomass standards, carbon credits, long-term storage liability) make economic viability sensitive to policy design and public acceptance.

Table 3. Global Commercial CCS Projects: Operational as of 2025.

No#	Project Name	Operator	Country	CO2 Source—Capture Type	Storage Type	Capture Capacity (Mt/Year)	CO2 Transport	Geological CO2 Stored (Reported)	Project Status	Ref.
Saline aquifer
1	Quest	Shell Canada	Canada	The Quest CCS project captures CO2 from hydrogen production via steam methane reformers at the Shell Scotford Upgrader in Alberta, Canada. (Pre-combustion)	Saline Aquifer	1.3	Pipeline	Over 9 million tonnes (End of 2024)	Operational since 2015	[129,130,131]
2	Entropy Glacier Gas Plant	Entropy Inc.	Canada	CO2 is captured during natural gas processing at the Entropy Glacier Gas Plant, where it is separated from the raw gas stream before further treatment and compression. (Pre-combustion)	Saline Aquifer	0.32	Pipeline	Around 63,000 tonnes (2025)	Operational since July 2022 (Phase 1); Phase 1b by 2023; Phase 2 under construction (FID July 2024)	[131,132,133]
3	Snøhvit	Equinor	Norway	The Snøhvit CCS project captures CO2 from natural gas processing at the Hammerfest LNG plant on Melkøya Island, where 5–8% CO2 is removed from Snøhvit field gas before liquefaction. (Pre-combustion)	Saline Aquifer	0.7	Pipeline	Around 6.5 million tonnes (~1.1 million tonnes from Tubåen Formation and ~5.4 million tonnes from Stø Formation) (2019)	Operational since 2008, the project is now entering a new phase of expansion under the name Snøhvit Future.	[131,134,135]
4	Sleipner	Equinor	Norway	The Sleipner CCS project captures CO2 from natural gas processing at the Sleipner T platform in the North Sea, where CO2 is separated from produced gas from the Sleipner West field due to its high CO2 content (~9%). (Pre-combustion)	Saline Aquifer	1	Pipeline	Over 17 million tonnes (January 2022)	Operational since 1996	[131,136]
5	Gorgon	Chevron Australia	Australia	The Gorgon CCS project captures CO2 during natural gas processing at the Chevron-operated Barrow Island facility, where CO2 naturally present in the Gorgon field gas (approximately 14% by volume) and the Jansz-Io field gas (less than 1%) is removed using an amine-based solvent system prior to liquefaction. (Pre-combustion)	Saline Aquifer	4	Pipeline	More than 11 million tonnes (May 2025)	Operational since 2019	[131,137,138]
6	CNOOC Enping	CNOOC	China	CO2 is captured during natural gas processing at the Enping 15-1 platform operated by CNOOC, where it is separated from production gas streams. (Pre-combustion)	Saline Aquifer	0.30	Pipeline	Around 0.2 million tonnes (2023)	Operational since 2013	[131,139,140]
7	Qatar Energy LNG CCS	Qatar Energy	Qatar	The Qatar Energy LNG CCS project captures CO2 during natural gas processing at the Ras Laffan Industrial City in Qatar, where CO2 is separated from produced gas streams during the liquefaction process across multiple LNG trains. (Pre-combustion)	Saline Aquifer	2.2	Pipeline	Around 7.5 million tonnes (2025)	Operational since 2019	[131,141,142]
8	ADM Illinois Industrial Carbon Capture and Storage	Archer Daniels Midland (ADM)	USA	CO2 is captured during ethanol production at the ADM facility in Decatur, Illinois, where it is separated from fermentation gas streams. (Industrial process)	Saline Aquifer	1	Pipeline	Around 4.5 million tonnes (2025)	Operational since 2017	[131,143]
9	Blue Flint Ethanol CCS	Harvestone Low Carbon Partners	USA	CO2 is captured during ethanol production at the Blue Flint Ethanol facility in Underwood, North Dakota, where it is separated from fermentation gas streams. (Industrial process)	Saline Aquifer	0.20	On-site injection	More than 0.125 million tonnes (September 2024)	Operational since 2023	[131,144,145]
10	Red Trail Energy CCS	Red Trail Energy, LLC	USA	CO2 from ethanol fermentation and associated combustion processes at a corn-based ethanol plant. (Industrial + post-combustion)	Saline Aquifer	0.18	On-site injection	Not publicly disclosed	Operational since 2022	[131,146]
Active oil reservoir
11	Petrobras Santos Basin Pre-Salt Oil Field CCS	Petrobras	Brazil	CO2 is sourced primarily from the separation of CO2-rich natural gas produced in the pre-salt oil reservoirs of the Santos Basin during oil and gas processing operations. (Pre-combustion)	Active oil reservoir (EOR)	10.60	Pipeline	Around 61.61 million tonnes (May 2024)	Operational since 2013	[131,147,148]
12	Air Products and Chemicals Valero Port Arthur Refinery	Air Products and Chemicals, Inc.	USA	CO2 is captured at Air Products’ hydrogen production units within the Valero Port Arthur Refinery in Texas, as a byproduct of steam methane reforming for hydrogen production. (Pre-combustion)	Active oil reservoir (EOR)	0.9	Pipeline	More than 3.64 million tonnes (2017)	Operational since 2013	[149,150,151]
13	Coffeyville Gasification Plant	Coffeyville Resources Nitrogen Fertilizers, LLC	USA	CO2 is captured at the Coffeyville Gasification Plant in Kansas, as a byproduct of petroleum coke gasification used to produce hydrogen for fertilizer manufacturing. It is then transported via pipeline to the North Burbank oil field in Oklahoma, where it is injected into active oil reservoirs for enhanced oil recovery (EOR). (Pre-combustion)	Active oil reservoir (EOR)	0.9	Pipeline	It uses the captured CO2 for Enhanced Oil Recovery (EOR) not for permanent storage	Operational since 2013	[131,152]
14	Contango Lost Cabin Gas Plant	ConocoPhillips (gas plant), Denbury Resources (CO2 transport and EOR)	USA	CO2 is captured at the Lost Cabin Gas Plant in Wyoming, as a byproduct of natural gas processing involving gas streams containing approximately 20% CO2 and 12% H2S. (Pre-combustion)	Active oil reservoir (EOR)	0.9	Pipeline	More than 5 million tonnes (2017)	Operational since 2013	[153,154]
15	Arkalon CO2 Compression Facility	CapturePoint LLC	USA	Industrial CO2 emissions captured from bio-ethanol production at Arkalon ethanol plant. (Industrial process)	Active oil reservoir (EOR)	0.5	Pipeline	Not publicly disclosed	Operational (new compression facility began in April 2023)	[131,155]
16	Al Reyadah CCUS Project	ADNOC	UAE	CO2 is captured at the Emirates Steel Industries facility in Abu Dhabi, as a byproduct of steel manufacturing. (Industrial process)	Active oil reservoir (EOR)	0.8	Pipeline	Not publicly disclosed	Operational since 2016	[156]
17	Sinopec Qilu-Shengli CCS	Sinopec Group	China	CO2 is captured at the Qilu Petrochemical plant in Zibo, Shandong Province, and the source is indeed industrial processes, specifically the coal-to-hydrogen (or coal gasification) operations at the refinery. (Pre-combustion)	Low permeability active oil reservoir (EOR)	1	Pipeline	Not publicly disclosed; likely a few million tonnes over years	Operational since 2022	[157]
18	Yangchang Yulin CO2-EOR	Shaanxi Yanchang Petroleum Group	China	CO2 is captured at the Yulin Coal Chemical Company in Shaanxi Province, China, as a byproduct of methanol and acetic acid production from coal. (Industrial process)	Low permeability active oil reservoir (EOR)	0.3	Truck	Around 41,000 tonnes (2015)	Pilot Phase (Phase 1 completed): CO2 injection began in 2012 and ended around 2015. Partially operational since 2015	[70,131]
Depleted oil reservoir
19	Longfellow WTO Century Plant	Longfellow Energy	USA	CO2 is sourced primarily from natural gas processing at the Century Plant in West Texas, where CO2 is separated from produced gas streams as part of natural gas treatment operations. (Pre-combustion)	Depleted oil reservoir (EOR)	5	Pipeline	Not publicly disclosed	Operational since 2013	[131,158]
20	Northern Reef Trend	Core Energy, LLC	USA	Core Energy’s Antrim Shale gas processing plant. (Pre-combustion)	Depleted oil reservoir (EOR)	0.331	Pipeline	Over 1.3608 million tonnes (2021)	Operational since 2013	[159]
21	Great Plains Synfuels Plant and Weyburn-Midale	Dakota Gasification Company	USA	CO2 is sourced primarily from the coal gasification process at the Great Plains Synfuels Plant in North Dakota, where CO2 is captured as a byproduct during the production of synthetic natural gas from lignite coal. (Pre-combustion)	Depleted oil reservoir (EOR)	3	Pipeline	Around 40 million tonnes in Weyburn (2023) and Around 2 million tonnes in Weyburn (2010)	Operational since 2000	[131,160,161,162]
22	Petra Nova Carbon Capture	ENEOS Xplora Inc.	USA	CO2 is captured at the W.A. Parish coal-fired power plant near Houston, Texas, as a byproduct of coal combustion for electricity. It is then transported to the West Ranch oil field for enhanced oil recovery (EOR) as part of the Petra Nova Carbon Capture Project. (Post-combustion)	Depleted oil reservoir (EOR)	1.4	Pipeline	More than 5 million tonnes (2025)	The Petra Nova Carbon Capture Project began operations in January 2017, capturing CO2 from the W.A. Parish coal-fired power plant for enhanced oil recovery. It was shut down in May 2020 due to economic challenges, mainly falling oil prices. After a three-year hiatus, the project was restarted in September 2023 under the sole ownership of ENEOS Xplora Inc. As of 2025, Petra Nova is fully operational	[131,163]
23	Core Energy CO2-EOR	Core Energy, LLC	USA	CO2 is captured as a byproduct during natural gas processing at facilities in Michigan, where raw gas streams containing 18–53% CO2 undergo acid gas removal. (Pre-combustion)	Depleted oil reservoir (EOR)	0.35	Pipeline	Around 0.462 million tonnes (2015)	Operational since 2013	[131,164]
24	Enid Fertilizer	Koch Nitrogen Company	USA	CO2 is captured as a byproduct during ammonia production at the Koch Nitrogen Plant in Enid, Oklahoma. (Pre-combustion)	Depleted oil reservoir (EOR)	0.2	Pipeline	Not publicly disclosed	Operational since 1982	[131,165]
25	MOL Szank Field CO2 EOR	MOL Hungarian Oil & Gas PLC	Hungary	CO2 from a nearby CO2 sweetening plant (treating natural gas feed ~81% CO2 content). (Pre-combustion)	Depleted oil reservoir (EOR)	0.16	Pipeline	Not publicly disclosed	Operational since 1990	[131,166,167]
26	Guohua Jinjie CCS Demonstration Project	Shaanxi Guohua Jinjie Energy Co., Ltd.	China	CO2 is captured at the Jinjie coal-fired power plant in Shaanxi Province, China, as a byproduct of post-combustion flue gas treatment. (Post-combustion)	Depleted oil reservoir (EOR)	0.15	Road Tanker	Not publicly disclosed	Operational since 2021	[71,131]
27	Yangchang Yan’an CO2-EOR	Shaanxi Yanchang Petroleum Group	China	CO2 is captured at coal-to-chemical plants in Yulin and Yan’an, Shaanxi Province, China, as a byproduct of industrial processes. (Industrial process)	Depleted oil reservoir (EOR)	0.10	Truck	Not publicly disclosed	Operational since 2009	[131,168]
28	WCS Redwater	Enhance Energy Inc.	Canada	CO2 is captured at the Sturgeon Refinery in Alberta, Canada, as a byproduct of bitumen upgrading and hydrogen production. (Industrial process)	Depleted oil reservoir (EOR)	0.3	Pipeline	More than 3.5 million tonnes (End of 2022)	Operational since 2014	[131,169,170]
29	Boundary Dam CCS (Weyburn for EOR and Aquistore Permanent CO2 storage).	SaskPower	Canada	CO2 is captured at the Boundary Dam coal-fired power plant near Estevan, Saskatchewan, as a byproduct of coal combustion for electricity. (Post-combustion)	Depleted oil reservoir (EOR) + Saline aquifer for storage	1	Pipeline	Around 0.5 million tonnes in Saline aquifer (2023)	Operational since 2014	[131,171,172,173]
30	NWR Sturgeon Refinery + Nutrien Redwater Fertilizer Facility + Alberta Carbon Trunk Line (ACTL) system	North-West Redwater Partnership (NWRP)	Canada	CO2 is captured at the NWR Sturgeon Refinery during hydrogen production from bitumen gasification, with a capture capacity of 1.6 Mt/year, of which 70% is sent via the Alberta Carbon Trunk Line (ACTL) for enhanced oil recovery and permanent geological storage. The Nutrien Redwater Fertilizer Facility captures CO2 from ammonia production, with a capacity of 0.3 Mt/year, and exports it into the ACTL system. (Industrial process + Pre-combustion)	Depleted oil reservoir (EOR)	1.9	Pipeline	In 2024, the NWR Sturgeon Refinery transferred approximately 3.66 million tonnes of CO2, while the Nutrien Redwater Fertilizer Facility contributed around 600,000 tonnes to the Alberta Carbon Trunk Line (ACTL) system. The ACTL is the world’s largest carbon capture and storage (CCS) project, with the capacity to transport and store up to 14.6 million tonnes of CO2 annually, supporting both enhanced oil recovery and permanent geological.	Operational since 2019	[131,174,175,176,177]
Depleting oil reservoir
31	Terrell Natural Gas Processing Plant CO2-EOR Project (formerly Val Verde Gas Plant)	Occidental Petroleum Corporation	USA	CO2 captured as a byproduct during natural gas processing (acid gas removal from raw gas streams containing 18–53% CO2). (Pre-combustion)	Depleting oil reservoir (EOR)	0.5	Pipeline	Not publicly disclosed	Operational since 1972	[131,178,179]
32	Bonanza BioEnergy CCS	Conestoga Energy Partners LLC (capture); PetroSantander (storage); Gary Climate Solutions (transport and operations)	USA	CO2 captured from ethanol fermentation at a corn and sorghum-based ethanol plant. (Industrial process)	Depleting oil reservoir (EOR)	0.10	Pipeline	Not publicly disclosed	Operational since 2011	[131,180]
33	Uthmaniyah CO2 EOR Demonstration Project	Saudi Aramco	Saudi Arabia	CO2 is captured at the Hawiyah gas plant in Saudi Arabia, as a byproduct of natural gas processing. (Pre-combustion)	Depleting oil reservoir (EOR)	0.8	Pipeline	Not publicly disclosed	Operational since 2015	[131,181]
34	Jilin Oil Field CO2-EOR	CNPC	China	CO2 is captured at the Changchun gas processing facility in Jilin Province, China, as a byproduct of natural gas processing. (Pre-combustion)	Depleting oil reservoir (EOR)	0.6	Pipeline	More than 3.5 million tonnes (End of 2024)	Operational since 2018	[131,182,183]
35	Sinopec Jinling Petrochemical	Sinopec	China	CO2 is captured at the Jinling Petrochemical Refinery in Nanjing, Jiangsu Province, China, as a byproduct of hydrogen production and refining processes. (Industrial process)	Low permeability Depleting oil reservoir (EOR)	0.3	Pipeline	Not publicly disclosed	Operational since 2022	[131,184]
36	Sinopec Nanjing Chemical or Sinopec Eastern China CCS	Sinopec	China	High-concentration CO2 extracted from syngas by-products at coal and refinery gasification plants, used for hydrogen, methanol, fertilizers, etc. (Pre-combustion)	Depleting oil reservoir (EOR)	0.20	Pipeline	Not publicly disclosed	Operational since 2022	[131,185]
37	Qingzhou Oxy-Fuel Combustion Carbon Capture Project	China United Cement Company (CNBM)	China	CO2 is captured at the Qingzhou Cement Plant in Shandong Province, China, where it is separated from flue gas produced during cement manufacturing using oxy-fuel combustion technology. (Oxy-fuel combustion)	Depleting oil reservoir (EOR)	0.20	On-site or local	Not publicly disclosed	Operational since 2024	[131,186,187]
38	Xinjiang Dunhua Karamay	Xinjiang Dunhua Petroleum Technology Co., Ltd.	China	CO2 is captured at a coal-fired power plant in Karamay, Xinjiang, China, as a byproduct of flue gas treatment. (Post-combustion)	Low permeability Depleting oil reservoir (EOR)	0.10	Road Tanker	Not publicly disclosed	Partially operational since 2016	[131,188,189]
39	Guanghui Energy Methanol Plant	Xinjiang Guanghui Carbon Technology Comprehensive Utilization Co., Ltd.	China	High-concentration CO2 (~82–85%) emitted during coal gasification to methanol production and other coal-chemical operations. (Pre-combustion)	Depleting oil reservoir (EOR)	0.10	Pipeline	Not publicly disclosed	Partially operational since 2009	[131]
40	Yanchang Integrated Demonstration	Shaanxi Yanchang Petroleum Group	China	Byproduct CO2 from coal-to-chemicals plants (methanol/acetic acid) via Rectisol capture system. (Pre-combustion)	Low permeability Depleting oil reservoir (EOR)	0.05	Truck	Not publicly disclosed	Operational since 2012	[131,190]
Others
41	Shute Creek Gas Processing Plant	ExxonMobil	USA	CO2 is sourced primarily from natural gas processing at the Shute Creek Gas Processing Plant in Wyoming, where CO2 is separated from produced gas streams during the treatment of raw gas extracted from the LaBarge field, which contains a high concentration of CO2. The separated CO2 is then compressed and transported in larger quantities for EOR and small quantities for sequestration. (Pre-combustion)	EOR	7	Pipeline	Around 6 million tonnes (March 2022)	Operational since 1986	[131,191,192]
42	Barnett Zero CCS	BKV and EnLink Midstream	USA	CO2-rich waste from EnLink’s Bridgeport natural gas processing plant (handling gas from Barnett Shale production). (Pre-combustion)	Purpose-drilled Class II injection well	0.19	Pipeline	Not publicly disclosed	Operational since 2023	[131,193]
43	CarbFix–Mammoth DAC + S Project	Climeworks (capture) and CarbFix (storage)	Iceland	CO2 captured directly from ambient air (Direct Air Capture) via Climeworks’ Mammoth plant. (Direct Air Capture)	Geological storage via mineralization in basalt	0.03	On-site injection	Not publicly disclosed	Operational since 2024	[131,194,195]

Table 3. Global Commercial CCS Projects: Operational as of 2025.

No#	Project Name	Operator	Country	CO2 Source—Capture Type	Storage Type	Capture Capacity (Mt/Year)	CO2 Transport	Geological CO2 Stored (Reported)	Project Status	Ref.
Saline aquifer
1	Quest	Shell Canada	Canada	The Quest CCS project captures CO2 from hydrogen production via steam methane reformers at the Shell Scotford Upgrader in Alberta, Canada. (Pre-combustion)	Saline Aquifer	1.3	Pipeline	Over 9 million tonnes (End of 2024)	Operational since 2015	[129,130,131]
2	Entropy Glacier Gas Plant	Entropy Inc.	Canada	CO2 is captured during natural gas processing at the Entropy Glacier Gas Plant, where it is separated from the raw gas stream before further treatment and compression. (Pre-combustion)	Saline Aquifer	0.32	Pipeline	Around 63,000 tonnes (2025)	Operational since July 2022 (Phase 1); Phase 1b by 2023; Phase 2 under construction (FID July 2024)	[131,132,133]
3	Snøhvit	Equinor	Norway	The Snøhvit CCS project captures CO2 from natural gas processing at the Hammerfest LNG plant on Melkøya Island, where 5–8% CO2 is removed from Snøhvit field gas before liquefaction. (Pre-combustion)	Saline Aquifer	0.7	Pipeline	Around 6.5 million tonnes (~1.1 million tonnes from Tubåen Formation and ~5.4 million tonnes from Stø Formation) (2019)	Operational since 2008, the project is now entering a new phase of expansion under the name Snøhvit Future.	[131,134,135]
4	Sleipner	Equinor	Norway	The Sleipner CCS project captures CO2 from natural gas processing at the Sleipner T platform in the North Sea, where CO2 is separated from produced gas from the Sleipner West field due to its high CO2 content (~9%). (Pre-combustion)	Saline Aquifer	1	Pipeline	Over 17 million tonnes (January 2022)	Operational since 1996	[131,136]
5	Gorgon	Chevron Australia	Australia	The Gorgon CCS project captures CO2 during natural gas processing at the Chevron-operated Barrow Island facility, where CO2 naturally present in the Gorgon field gas (approximately 14% by volume) and the Jansz-Io field gas (less than 1%) is removed using an amine-based solvent system prior to liquefaction. (Pre-combustion)	Saline Aquifer	4	Pipeline	More than 11 million tonnes (May 2025)	Operational since 2019	[131,137,138]
6	CNOOC Enping	CNOOC	China	CO2 is captured during natural gas processing at the Enping 15-1 platform operated by CNOOC, where it is separated from production gas streams. (Pre-combustion)	Saline Aquifer	0.30	Pipeline	Around 0.2 million tonnes (2023)	Operational since 2013	[131,139,140]
7	Qatar Energy LNG CCS	Qatar Energy	Qatar	The Qatar Energy LNG CCS project captures CO2 during natural gas processing at the Ras Laffan Industrial City in Qatar, where CO2 is separated from produced gas streams during the liquefaction process across multiple LNG trains. (Pre-combustion)	Saline Aquifer	2.2	Pipeline	Around 7.5 million tonnes (2025)	Operational since 2019	[131,141,142]
8	ADM Illinois Industrial Carbon Capture and Storage	Archer Daniels Midland (ADM)	USA	CO2 is captured during ethanol production at the ADM facility in Decatur, Illinois, where it is separated from fermentation gas streams. (Industrial process)	Saline Aquifer	1	Pipeline	Around 4.5 million tonnes (2025)	Operational since 2017	[131,143]
9	Blue Flint Ethanol CCS	Harvestone Low Carbon Partners	USA	CO2 is captured during ethanol production at the Blue Flint Ethanol facility in Underwood, North Dakota, where it is separated from fermentation gas streams. (Industrial process)	Saline Aquifer	0.20	On-site injection	More than 0.125 million tonnes (September 2024)	Operational since 2023	[131,144,145]
10	Red Trail Energy CCS	Red Trail Energy, LLC	USA	CO2 from ethanol fermentation and associated combustion processes at a corn-based ethanol plant. (Industrial + post-combustion)	Saline Aquifer	0.18	On-site injection	Not publicly disclosed	Operational since 2022	[131,146]
Active oil reservoir
11	Petrobras Santos Basin Pre-Salt Oil Field CCS	Petrobras	Brazil	CO2 is sourced primarily from the separation of CO2-rich natural gas produced in the pre-salt oil reservoirs of the Santos Basin during oil and gas processing operations. (Pre-combustion)	Active oil reservoir (EOR)	10.60	Pipeline	Around 61.61 million tonnes (May 2024)	Operational since 2013	[131,147,148]
12	Air Products and Chemicals Valero Port Arthur Refinery	Air Products and Chemicals, Inc.	USA	CO2 is captured at Air Products’ hydrogen production units within the Valero Port Arthur Refinery in Texas, as a byproduct of steam methane reforming for hydrogen production. (Pre-combustion)	Active oil reservoir (EOR)	0.9	Pipeline	More than 3.64 million tonnes (2017)	Operational since 2013	[149,150,151]
13	Coffeyville Gasification Plant	Coffeyville Resources Nitrogen Fertilizers, LLC	USA	CO2 is captured at the Coffeyville Gasification Plant in Kansas, as a byproduct of petroleum coke gasification used to produce hydrogen for fertilizer manufacturing. It is then transported via pipeline to the North Burbank oil field in Oklahoma, where it is injected into active oil reservoirs for enhanced oil recovery (EOR). (Pre-combustion)	Active oil reservoir (EOR)	0.9	Pipeline	It uses the captured CO2 for Enhanced Oil Recovery (EOR) not for permanent storage	Operational since 2013	[131,152]
14	Contango Lost Cabin Gas Plant	ConocoPhillips (gas plant), Denbury Resources (CO2 transport and EOR)	USA	CO2 is captured at the Lost Cabin Gas Plant in Wyoming, as a byproduct of natural gas processing involving gas streams containing approximately 20% CO2 and 12% H2S. (Pre-combustion)	Active oil reservoir (EOR)	0.9	Pipeline	More than 5 million tonnes (2017)	Operational since 2013	[153,154]
15	Arkalon CO2 Compression Facility	CapturePoint LLC	USA	Industrial CO2 emissions captured from bio-ethanol production at Arkalon ethanol plant. (Industrial process)	Active oil reservoir (EOR)	0.5	Pipeline	Not publicly disclosed	Operational (new compression facility began in April 2023)	[131,155]
16	Al Reyadah CCUS Project	ADNOC	UAE	CO2 is captured at the Emirates Steel Industries facility in Abu Dhabi, as a byproduct of steel manufacturing. (Industrial process)	Active oil reservoir (EOR)	0.8	Pipeline	Not publicly disclosed	Operational since 2016	[156]
17	Sinopec Qilu-Shengli CCS	Sinopec Group	China	CO2 is captured at the Qilu Petrochemical plant in Zibo, Shandong Province, and the source is indeed industrial processes, specifically the coal-to-hydrogen (or coal gasification) operations at the refinery. (Pre-combustion)	Low permeability active oil reservoir (EOR)	1	Pipeline	Not publicly disclosed; likely a few million tonnes over years	Operational since 2022	[157]
18	Yangchang Yulin CO2-EOR	Shaanxi Yanchang Petroleum Group	China	CO2 is captured at the Yulin Coal Chemical Company in Shaanxi Province, China, as a byproduct of methanol and acetic acid production from coal. (Industrial process)	Low permeability active oil reservoir (EOR)	0.3	Truck	Around 41,000 tonnes (2015)	Pilot Phase (Phase 1 completed): CO2 injection began in 2012 and ended around 2015. Partially operational since 2015	[70,131]
Depleted oil reservoir
19	Longfellow WTO Century Plant	Longfellow Energy	USA	CO2 is sourced primarily from natural gas processing at the Century Plant in West Texas, where CO2 is separated from produced gas streams as part of natural gas treatment operations. (Pre-combustion)	Depleted oil reservoir (EOR)	5	Pipeline	Not publicly disclosed	Operational since 2013	[131,158]
20	Northern Reef Trend	Core Energy, LLC	USA	Core Energy’s Antrim Shale gas processing plant. (Pre-combustion)	Depleted oil reservoir (EOR)	0.331	Pipeline	Over 1.3608 million tonnes (2021)	Operational since 2013	[159]
21	Great Plains Synfuels Plant and Weyburn-Midale	Dakota Gasification Company	USA	CO2 is sourced primarily from the coal gasification process at the Great Plains Synfuels Plant in North Dakota, where CO2 is captured as a byproduct during the production of synthetic natural gas from lignite coal. (Pre-combustion)	Depleted oil reservoir (EOR)	3	Pipeline	Around 40 million tonnes in Weyburn (2023) and Around 2 million tonnes in Weyburn (2010)	Operational since 2000	[131,160,161,162]
22	Petra Nova Carbon Capture	ENEOS Xplora Inc.	USA	CO2 is captured at the W.A. Parish coal-fired power plant near Houston, Texas, as a byproduct of coal combustion for electricity. It is then transported to the West Ranch oil field for enhanced oil recovery (EOR) as part of the Petra Nova Carbon Capture Project. (Post-combustion)	Depleted oil reservoir (EOR)	1.4	Pipeline	More than 5 million tonnes (2025)	The Petra Nova Carbon Capture Project began operations in January 2017, capturing CO2 from the W.A. Parish coal-fired power plant for enhanced oil recovery. It was shut down in May 2020 due to economic challenges, mainly falling oil prices. After a three-year hiatus, the project was restarted in September 2023 under the sole ownership of ENEOS Xplora Inc. As of 2025, Petra Nova is fully operational	[131,163]
23	Core Energy CO2-EOR	Core Energy, LLC	USA	CO2 is captured as a byproduct during natural gas processing at facilities in Michigan, where raw gas streams containing 18–53% CO2 undergo acid gas removal. (Pre-combustion)	Depleted oil reservoir (EOR)	0.35	Pipeline	Around 0.462 million tonnes (2015)	Operational since 2013	[131,164]
24	Enid Fertilizer	Koch Nitrogen Company	USA	CO2 is captured as a byproduct during ammonia production at the Koch Nitrogen Plant in Enid, Oklahoma. (Pre-combustion)	Depleted oil reservoir (EOR)	0.2	Pipeline	Not publicly disclosed	Operational since 1982	[131,165]
25	MOL Szank Field CO2 EOR	MOL Hungarian Oil & Gas PLC	Hungary	CO2 from a nearby CO2 sweetening plant (treating natural gas feed ~81% CO2 content). (Pre-combustion)	Depleted oil reservoir (EOR)	0.16	Pipeline	Not publicly disclosed	Operational since 1990	[131,166,167]
26	Guohua Jinjie CCS Demonstration Project	Shaanxi Guohua Jinjie Energy Co., Ltd.	China	CO2 is captured at the Jinjie coal-fired power plant in Shaanxi Province, China, as a byproduct of post-combustion flue gas treatment. (Post-combustion)	Depleted oil reservoir (EOR)	0.15	Road Tanker	Not publicly disclosed	Operational since 2021	[71,131]
27	Yangchang Yan’an CO2-EOR	Shaanxi Yanchang Petroleum Group	China	CO2 is captured at coal-to-chemical plants in Yulin and Yan’an, Shaanxi Province, China, as a byproduct of industrial processes. (Industrial process)	Depleted oil reservoir (EOR)	0.10	Truck	Not publicly disclosed	Operational since 2009	[131,168]
28	WCS Redwater	Enhance Energy Inc.	Canada	CO2 is captured at the Sturgeon Refinery in Alberta, Canada, as a byproduct of bitumen upgrading and hydrogen production. (Industrial process)	Depleted oil reservoir (EOR)	0.3	Pipeline	More than 3.5 million tonnes (End of 2022)	Operational since 2014	[131,169,170]
29	Boundary Dam CCS (Weyburn for EOR and Aquistore Permanent CO2 storage).	SaskPower	Canada	CO2 is captured at the Boundary Dam coal-fired power plant near Estevan, Saskatchewan, as a byproduct of coal combustion for electricity. (Post-combustion)	Depleted oil reservoir (EOR) + Saline aquifer for storage	1	Pipeline	Around 0.5 million tonnes in Saline aquifer (2023)	Operational since 2014	[131,171,172,173]
30	NWR Sturgeon Refinery + Nutrien Redwater Fertilizer Facility + Alberta Carbon Trunk Line (ACTL) system	North-West Redwater Partnership (NWRP)	Canada	CO2 is captured at the NWR Sturgeon Refinery during hydrogen production from bitumen gasification, with a capture capacity of 1.6 Mt/year, of which 70% is sent via the Alberta Carbon Trunk Line (ACTL) for enhanced oil recovery and permanent geological storage. The Nutrien Redwater Fertilizer Facility captures CO2 from ammonia production, with a capacity of 0.3 Mt/year, and exports it into the ACTL system. (Industrial process + Pre-combustion)	Depleted oil reservoir (EOR)	1.9	Pipeline	In 2024, the NWR Sturgeon Refinery transferred approximately 3.66 million tonnes of CO2, while the Nutrien Redwater Fertilizer Facility contributed around 600,000 tonnes to the Alberta Carbon Trunk Line (ACTL) system. The ACTL is the world’s largest carbon capture and storage (CCS) project, with the capacity to transport and store up to 14.6 million tonnes of CO2 annually, supporting both enhanced oil recovery and permanent geological.	Operational since 2019	[131,174,175,176,177]
Depleting oil reservoir
31	Terrell Natural Gas Processing Plant CO2-EOR Project (formerly Val Verde Gas Plant)	Occidental Petroleum Corporation	USA	CO2 captured as a byproduct during natural gas processing (acid gas removal from raw gas streams containing 18–53% CO2). (Pre-combustion)	Depleting oil reservoir (EOR)	0.5	Pipeline	Not publicly disclosed	Operational since 1972	[131,178,179]
32	Bonanza BioEnergy CCS	Conestoga Energy Partners LLC (capture); PetroSantander (storage); Gary Climate Solutions (transport and operations)	USA	CO2 captured from ethanol fermentation at a corn and sorghum-based ethanol plant. (Industrial process)	Depleting oil reservoir (EOR)	0.10	Pipeline	Not publicly disclosed	Operational since 2011	[131,180]
33	Uthmaniyah CO2 EOR Demonstration Project	Saudi Aramco	Saudi Arabia	CO2 is captured at the Hawiyah gas plant in Saudi Arabia, as a byproduct of natural gas processing. (Pre-combustion)	Depleting oil reservoir (EOR)	0.8	Pipeline	Not publicly disclosed	Operational since 2015	[131,181]
34	Jilin Oil Field CO2-EOR	CNPC	China	CO2 is captured at the Changchun gas processing facility in Jilin Province, China, as a byproduct of natural gas processing. (Pre-combustion)	Depleting oil reservoir (EOR)	0.6	Pipeline	More than 3.5 million tonnes (End of 2024)	Operational since 2018	[131,182,183]
35	Sinopec Jinling Petrochemical	Sinopec	China	CO2 is captured at the Jinling Petrochemical Refinery in Nanjing, Jiangsu Province, China, as a byproduct of hydrogen production and refining processes. (Industrial process)	Low permeability Depleting oil reservoir (EOR)	0.3	Pipeline	Not publicly disclosed	Operational since 2022	[131,184]
36	Sinopec Nanjing Chemical or Sinopec Eastern China CCS	Sinopec	China	High-concentration CO2 extracted from syngas by-products at coal and refinery gasification plants, used for hydrogen, methanol, fertilizers, etc. (Pre-combustion)	Depleting oil reservoir (EOR)	0.20	Pipeline	Not publicly disclosed	Operational since 2022	[131,185]
37	Qingzhou Oxy-Fuel Combustion Carbon Capture Project	China United Cement Company (CNBM)	China	CO2 is captured at the Qingzhou Cement Plant in Shandong Province, China, where it is separated from flue gas produced during cement manufacturing using oxy-fuel combustion technology. (Oxy-fuel combustion)	Depleting oil reservoir (EOR)	0.20	On-site or local	Not publicly disclosed	Operational since 2024	[131,186,187]
38	Xinjiang Dunhua Karamay	Xinjiang Dunhua Petroleum Technology Co., Ltd.	China	CO2 is captured at a coal-fired power plant in Karamay, Xinjiang, China, as a byproduct of flue gas treatment. (Post-combustion)	Low permeability Depleting oil reservoir (EOR)	0.10	Road Tanker	Not publicly disclosed	Partially operational since 2016	[131,188,189]
39	Guanghui Energy Methanol Plant	Xinjiang Guanghui Carbon Technology Comprehensive Utilization Co., Ltd.	China	High-concentration CO2 (~82–85%) emitted during coal gasification to methanol production and other coal-chemical operations. (Pre-combustion)	Depleting oil reservoir (EOR)	0.10	Pipeline	Not publicly disclosed	Partially operational since 2009	[131]
40	Yanchang Integrated Demonstration	Shaanxi Yanchang Petroleum Group	China	Byproduct CO2 from coal-to-chemicals plants (methanol/acetic acid) via Rectisol capture system. (Pre-combustion)	Low permeability Depleting oil reservoir (EOR)	0.05	Truck	Not publicly disclosed	Operational since 2012	[131,190]
Others
41	Shute Creek Gas Processing Plant	ExxonMobil	USA	CO2 is sourced primarily from natural gas processing at the Shute Creek Gas Processing Plant in Wyoming, where CO2 is separated from produced gas streams during the treatment of raw gas extracted from the LaBarge field, which contains a high concentration of CO2. The separated CO2 is then compressed and transported in larger quantities for EOR and small quantities for sequestration. (Pre-combustion)	EOR	7	Pipeline	Around 6 million tonnes (March 2022)	Operational since 1986	[131,191,192]
42	Barnett Zero CCS	BKV and EnLink Midstream	USA	CO2-rich waste from EnLink’s Bridgeport natural gas processing plant (handling gas from Barnett Shale production). (Pre-combustion)	Purpose-drilled Class II injection well	0.19	Pipeline	Not publicly disclosed	Operational since 2023	[131,193]
43	CarbFix–Mammoth DAC + S Project	Climeworks (capture) and CarbFix (storage)	Iceland	CO2 captured directly from ambient air (Direct Air Capture) via Climeworks’ Mammoth plant. (Direct Air Capture)	Geological storage via mineralization in basalt	0.03	On-site injection	Not publicly disclosed	Operational since 2024	[131,194,195]

4. Geomechanical and Geochemical Aspects of CCS in Depleted Hydrocarbon Reservoirs and Deep Saline Aquifers

Geological carbon storage (GCS), the subsurface storage phase of CCS, is becoming a crucial way to tackle greenhouse gas emissions, which involves injecting supercritical CO₂ into a geological formation, including saline aquifers, depleted oil and gas reservoirs, and unmineable coal mines, at a depth of 800 m or more [196,197]. CO₂ can also be stored in hydrates, where it will be trapped as a solid hydrate crystal under high-pressure and low-temperature conditions in deep ocean sediments [198]. CO₂-EOR (CO₂ Enhanced Oil Recovery) is another mechanism for long-term CO₂ storage, where 30–50% of the injected CO₂ will permanently be stored and result in a 63% net reduction in CO₂ emissions for every barrel of oil produced [199].

Due to their proven storage capacity, widespread availability, and sufficient depth, deep saline aquifers and depleted hydrocarbon reservoirs are the most promising geological formations for large-scale CO₂ sequestration. Depleted hydrocarbon reservoirs have well-documented geological properties and well-established infrastructure, which is helpful in the management and monitoring of prolonged CO₂ storage [200,201]. For these underground geological storage sites, a rigorous understanding of the geomechanical and geochemical aspects plays a vital role in ensuring efficient and safe CO₂ storage.

4.1. Geomechanical Aspects

Even though the idea of storing CO₂ in deep saline aquifers and depleted reservoirs is a promising solution to the mitigation of greenhouse gas emissions, concerns exist regarding geomechanical risks due to pore pressure buildup from CO₂ injection, unless a comprehensive site characterization, monitoring, and pressure management strategy is implemented. These risks consist of loss of rock, caprock failure, well integrity, leakage of CO₂, unwanted reactivation of existing faults, surface uplift, and seismicity, which lead to environmental issues and a loss of public trust in CCS projects [202,203]. Thus, studying the geomechanical aspects of the process is essential to ensure safe and long-term CO₂ storage. Geomechanical analysis examines how the storage formation physically behaves under stress. This includes assessing the reliability and strength of the caprock, analyzing in situ stress conditions, checking for wellbore stability, and identifying any risk of fault movement or induced seismicity. It also considers how CO₂ may chemically interact with surrounding rock, potentially altering the mechanical properties of the formation over time [204,205].

The primary geomechanical processes involved in geologic carbon storage are illustrated in Figure 12 below. The upper figure represents the pressure buildup caused by CO₂ injection, and the lower parts show the geomechanical changes at the storage site as a result of this pressure buildup. As shown, the geomechanical effects occur not only at the injection area but also well beyond the boundaries of the CO₂ plume, where the pressure and temperature are changed, resulting in a change in effective stress in the surrounding rock. The change in stress results in deformation and affects the porosity and permeability of the storage site. The change in pore pressure and stress in the storage site can compromise the caprock integrity, which leads to fault reactivation and induced seismicity [205,206].

Depleted hydrocarbon fields offer favorable geomechanical conditions for CO₂ storage, thanks to existing geological characterization, infrastructure, and a proven sealing capacity. The injection of CO₂ will repressurize the reservoir, which enhances fault stability and reduces the risk of fault reactivation. In addition, unlike a saline aquifer, the change in pressure is confined to the reservoir block in the case of depleted reservoirs, which reduces the risk of fault reactivation and reduces unintended CO₂ plume migration. However, the history of production followed by CO₂ injection in such reservoirs requires unique geomechanical considerations. The reasons include: first the reservoir undergone significant pressure depletion which leads to the compaction of the reservoir rock and potential surface subsidence, second the existence of wellbores that penetrated the reservoir and caprock which could be a potential leakage pathways if the new stress regime and CO₂ exposure compromises the mechanical integrity over time, third existence legacy wells that does not meet the standard for containment of CO₂ may pose a significant CO₂ leakage risk. Therefore, for secured and long-term storage of CO₂ in depleted hydrocarbon reservoirs, it is necessary to have hydraulic integrity of the storage site and the wellbores [92].

4.2. Geochemical Aspects

In addition to geomechanical considerations, the safe and secure sequestration of CO₂ in both depleted hydrocarbon reservoirs and saline aquifers rely on a comprehensive understanding of the complex geochemical interactions between the injected CO₂, formation fluids, and the host rock. It is the interactions that govern the long-term storage of CO₂, the storage capacity, the injectivity, and the overall effectiveness and safety of the CO₂ sequestration process. The interactions include dissolution of CO₂ in which injected CO₂ is dissolved in brine to form carbonic acid, mineral dissolution and precipitation in which carbonic acid dissolves minerals like carbonates and promotes precipitation of secondary minerals, and the adsorption of CO₂ onto the mineral surface [207,208,209].

The sequestration of CO₂ injected into these geological formations is driven by many chemical and physical mechanisms, which include structural trapping, capillary residual gas trapping, solubility or dissolution trapping, and mineralization trapping. The first two are classified as physical, and the latter two are chemical trapping mechanisms. In structural trapping CO₂ is physically contained by geological formations which include impermeable caprocks, which prevent the upward migration of CO₂. This mechanism is highly dependent on the integrity of the impermeable caprock layer. In case of residual trapping CO₂ becomes trapped in the pore spaces of or in the pore throats of the rock as immobile droplets due to the capillary forces. These two physical trapping mechanisms play a significant role in the immediate containment of CO_2, especially at the early stage of storage.

Solubility Trapping involves the dissolution of CO₂ in the formation of water or brine, resulting in the formation of carbonic acid. This trapping mechanism reduces the dependency of the trapping process on sealing integrity and enhances the mineralization processes. In case of mineralization or mineral trapping, the dissolved CO₂ can react with rock minerals over time to form minerals of stable carbonate. This mechanism is the most secure and permanent solution for long-term storage of CO₂ in geological formations and will take hundreds of years to happen [210,211,212]. Figure 13 below illustrates the interaction between CO₂, brine, and rock during the four trapping mechanisms.

A case study by Bohloli et al. [213] highlighted the practical geomechanical challenges in injection wells at the In Salah CCS project, Algeria. According to this study, a surface uplift of 15 to 22 mm was observed because of pressure buildup during CO₂ injection. The monitoring was performed between 2004 and 2011 using InSAR (Interferometric Synthetic Aperture Radar). The rate of uplift increased with the injection rate, being higher when the injection started, and then gradually slowed and leveled off over time.

Another study by Jun et al. [214] predicted the surface uplift in the Pohang basin, which is a potential CCS site in South Korea, using the Gaussian pressure transient (GPT) method. The study found a surface uplift of up to 25.42 mm, where the maximum value occurred at the injection well.

Glubokovskikh et al. [215] did seismic monitoring on the CO₂CRC Otway Project—Stage 2C in Otway Basin, Victoria, Australia, and concluded that a leakage from a commercial-scale storage site could still cause noticeable seismic activity in the overlying rock layers even without significant overpressure.

5. Computer Modeling and Simulation

CCS projects generally incorporate a series of repeating steps to determine whether CO₂ storage is adequate, practical, and feasible. These steps include studying the properties of storage sites, running models and simulations, risk assessment and monitoring, verification, and tracking during CO₂ storage (Figure 14). Numerical and analytical models are both necessary essential tools in simulating CCS processes, but they vary significantly in application and complexity (

Table 4. Key differences between analytical and numerical models.

Feature	Analytical Model	Numerical Model
Solution type	Exact (closed form)	Approximate (discrete)
Assumptions	Requires strong simplifications	Fewer simplifying assumptions
Complexity Handling	Limited	High (handles real-world complexity)
Computation Time	Extremely low	Moderate to high
Scalability	Poor	Excellent (suitable for 3D domains)
Use Case in CCS	Preliminary screening, verification	Full-field simulations, risk assessment

). Analytical models produce exact and closed-form solutions to governing equations, such as Darcy’s law or mass-conservative equations, typically under simplified assumptions like isotropy, homogeneity, and steady-state conditions. Analytical models are efficient in computation and useful for early-stage screening, quick estimates, and model validation, but the drawback of these models is that they are limited in their ability to handle heterogeneities, complex geometries, and non-linear processes [216]. On the contrary, numerical models employ discretization methods, such as finite element, finite difference, or finite volume methods, to approximate solutions for the same governing equations. Numerical models can include reactive transport, multiphase flow, geomechanics, and complex boundary conditions, making them suitable for field-scale simulations [217]. Some standard numerical modeling methods that have been used for CO₂ sequestration modeling are vertical equilibrium models, streamline simulations and grid-based numerical models [218,219]. Key difference between analytical and numerical models are explained in Table 3. A common workflow for CCS modeling in geological storage is shown on Figure 15. Modeling in CCS is carried out in three phases (capture, transport, and storage), some common software/tool used in these phases are listed in

Table 5. Standard modeling tools used in the three Phases of CCS.

Software/Tool	Phase(s)	Purpose and Use Case	Ref.
Aspen Adsorption/ProSim DAC	Capture (Adsorption/Direct Air Capture)	Pressure Swing Adsorption (PSA)/Temperature Swing Adsorption (TSA) cycle modeling for post-combustion capture or direct air capture	[220,221,222]
Molecular Dynamics (MD)/Density Functional Theory (DFT tools)	Capture (Molecular level)	Molecular-scale modeling of sorption, solvent optimization, and material design	[223,224,225]
CMG (IMEX, GEM, STARS)	Capture and Storage	Multiphase flow, geochemistry, thermal, and Equation of State (EOS)-based modeling; CO2 trapping, mineralization, healthy interactions	[226,227]
Pipesim	Transport	Steady-state multiphase flow modeling: pipeline hydraulics, heat transfer, phase- and PVT-based flow assurance (CO2-rich fluids)	[228,229]
OLGA	Transport	Dynamic multiphase flow simulation: depressurization, transient operations, hydrate prediction, two-/three-phase CO2 flow	[230,231]
CMG CoFlow	Transport and Storage	Wellbore + pipeline flow modeling; real-time monitoring/alerting of temperature, pressure, corrosion	[232,233,234]
TOUGH2/TOUGHREACT	Storage	Non-isothermal, multicomponent transport, fracturing, reactive transport modeling	[235,236,237,238]
CCSNet (ML surrogate)	Storage	Deep-learning model for pressure/plume forecasting, trapping prediction (~103–104× faster than numeric)	[239]
Vertical Equilibrium (VE) Models	Storage	Fast large-scale reservoir simulations relying on VE approximations for structural and residual trapping	[240,241]
PFLOTRAN + Gas Hydrate	Storage	Modeling CO2 phase transitions and hydrate formation in marine Gas Hydrate Stability Zone (GHSZ), temperature-pressure effects	[242]
PFLOTRAN (generic)	Storage	Mass/heat transport, geochemical reactions, multiphase subsurface flow, fracture coupling	[243,244]
ECLIPSE/ECLIPSE 300	Storage	Compositional/black-oil reservoir simulation: CO2 plume migration, dissolution, phase behavior	[226,245]
Large-scale compositional simulator (PRSI-CGCS)	Storage	Parallel/EOS-based CO2 geological storage modeling on High-Performance Computing (HPC) platforms	[246]
GWB (Geochemist Workbench)	Storage	Reactive transport simulations: mineral trapping, dissolution/precipitation, complex fluid chemistry	[247]
FEHM (LANL flow code)	Storage	Multiphase heat and mass transport with stress coupling, used in CCS site risk and integrity assessment	[247]

.

6. Risk Assessment in Geological Storage

The effective long-term performance of CO₂ sequestration in geological storage requires a Risk Assessment with a robust and consistent framework for the deployment of CCS technologies [248]. A site is considered safe for storage if it can store a large quantity of CO₂ for hundreds of years without causing any hazard. In the context of safety engineering, risk is usually defined as the product of the likelihood of an event occurring and the potential consequences of that event if it happens. This idea is normally relevant to a system that is well defined. Still, it cannot be used in CO₂ storage in geological formations because many of its components are not well known, which means there is uncertainty in the system. Risk is directly proportional to the amount of knowledge a system has: the more you know about a system, the better you will understand the applied risk. In CO₂ sequestration through geological storage, the risk level is higher during the early phase of the project [249]. Uncertainties are also high in the early phase of the project, resulting in higher risks [249].

Risk assessment strategy can be divided into 4 groups:

• Qualitative;
• Quantitative;
• Semi-Quantitative;
• Hybrid Model.

6.1. Qualitative Risk Assessment

Qualitative Risk Assessment is utilized when there is insufficient data, expertise, particular knowledge, or time. It does not give any fixed or numerical result. Some standard Qualitative Risk Assessment methods are explained below:

6.1.1. Features, Events, and Processes (FEP) Analysis

FEP Analysis is a framework utilized to recognize and categorize the features (Site characteristics like reservoir permeability, porosity of caprock, quantity of wells, etc.), events (Discrete occurrences, processes like well blowouts and seismic), and processes (It may be geochemical or geomechanical processes) [250]. The approach is applied in 2 ways: bottom-up or top-down, as shown on Figure 16.

6.1.2. Vulnerability Evaluation Framework (VEF)

The VEF was invented by the EPA (U.S. Environmental Protection Agency) in 2008. It is a qualitative risk assessment tool that is designed to assess the possible vulnerabilities related to CO₂ storage in geological formations [253]. It provides a framework to assess site-specific risk by inspecting factors such as geological characteristics, potential migration pathways, and the presence of sensitive receptors (Figure 17). VEF analysis helps identify areas where further data collection or mitigation strategies may be required to ensure long-term storage integrity. VEF Analysis helps in making decisions for site selection, risk management and monitoring. VEF has a few features, like Certification Framework Approach (CFA) [254].

6.1.3. The Structured What-If Technique (SWIFT)

SWIFT is a hazard analysis method that is based on brainstorming. It utilizes structured prompts and guidewords to determine possible hazards and ways in which they could occur [255]. It is commonly used at the start of a CCS project to help quickly identify various hazards using limited information. This method can serve as an alternative to Failure Modes and Effects Analysis (FMEA) and Hazard and Operability (HAZOP) for providing effective hazard identification when these two methods are not feasible. [256,257]. The SWIFT method consists of a series of questions, such as “What if or How could” to recognize threats that have the potential to cause harm. No proper standards are defined for SWIFT; it can be updated to personal requirements [258].

6.1.4. Hazard Identification (HAZID)

HAZID is a systematic and structured method used to identify potential hazards related to specific operations, particularly in complex systems such as Carbon Capture and Storage (CCS). HAZID approach is used to identify and assess the risk related to CO₂ capture, transport, and geological storage. In this approach, a multidisciplinary team analyzes various scenarios to specify the possible risk, its cause, and consequences, helping in the development of mitigation strategies. The importance of HAZID is emphasized by the International Energy Agency Greenhouse Gas Research and Development Programme (IEAGHG) for ensuring the safety of CO₂ storage, as it systematically identifies potential hazards and their impacts [259].

6.1.5. Risk Matrix for Legacy Wells

A risk matrix was developed by [260]. To evaluate the risk of legacy wells within the Area of Review (AoR) in CCS projects (Figure 18). This approach helps in categorizing different types of wells, from poorly documented to ones that are non-penetrating, based on their probable risk to sealing rock, underground source of drinking water, and storage formations. It is in the early stage of site screening, helping operators to identify the wells that require remediation quickly. This approach was successfully applied in the Illinois Basin, but it is restricted to Legacy Wells assessments and does not give a comprehensive evaluation for the entire storage site.

6.2. Quantitative Risk Assessment

Quantitative Risk Assessment is utilized in systems that are well established and known, and thus, the level of uncertainty is relatively low. Some standard Quantitative Risk Assessment methods are explained below:

6.2.1. Fault Tree Analysis

Fault Tree Analysis (FTA) is a top-down, deductive analytical method used to identify various combinations of human errors, software failures, hardware failures, and other factors that may cause a predefined undesired event. In carbon capture and storage, the FTA helps in identifying probable causes of CO₂ leakage by mapping out the logical relationship between failures of system [261].

6.2.2. Monte Carlo Simulation

Monte Carlo Simulation uses arbitrary sampling and statistical modeling to approximate the probability distributions of unknown parameters [262]. In the risk analysis of CCS, Monte Carlo Simulation is utilized to model uncertainties in the behavior of the reservoir, plume migration of CO₂, and the leakage scenarios. It provides a probabilistic understanding of possible risks [263].

6.2.3. Deterministic Risk Assessment (DRA)

The Deterministic Risk Assessment (DRA) utilized fixed input parameters to model and forecast the CO₂ behaviors in storage systems. This model assumes specific values for variables such as injection rates, reservoir properties, and caprock integrity, which lead to a single predicted outcome. DRA provides a straightforward analysis, but it does not account for the inherent uncertainties in operational conditions and geological formations. Therefore, it might not completely capture the range of possible scenarios that would impact the effectiveness and safety of CO₂ storage [264].

6.2.4. Probabilistic Risk Assessment (PRA)

The Probabilistic Risk Assessment (PRA) incorporates the uncertainties related to different input parameters by utilizing probability distributions. This Analysis assesses a range of possible outcomes and their associated probability, providing a more detailed understanding of potential risks. In risk assessment for CCS, PRA can be used to model uncertainties in factors such as injection dynamics, fault permeability, and reservoir heterogeneity. By quantifying the likelihood of various leakage scenarios and their possible impacts, PRA helps in developing strong risk management strategies [264,265].

6.3. Semi-Quantitative Risk Assessment

A semi-quantitative risk assessment method merges elements of both quantitative (numerical) and qualitative (descriptive) risk assessments. These methods utilize judgments from experts and structured scoring to prioritize risk without using any full probabilistic models. Some standard Semi-Quantitative Risk Assessment methods are explained below:

6.3.1. Method Organized for a Systematic Analysis of Risk (MOSAR)

MOSAR is a structured approach that should be applied to risk analysis in CCS, especially when we are uncertain about what might happen in the future. Leakage of CO₂ from storage sites could cause serious problems. It can identify and assess technical risks within a system. After identifying the risk, it develops protective and preventive measures to eliminate them. MOSAR consists of 10 steps for analyzing risk in complex systems like the CCS project (Figure 19). These 10 steps are grouped into two steps, that is step A and step B. Step A is used to identify major risks, such as pipeline ruptures or CO₂ leakage, by inspecting worst-case scenarios. After that, Step B provides detailed solutions that specify safety measures, such as reinforced storage wells or leak detectors, to prevent technical failures [266].

6.3.2. Bow-Tie Analysis

Bow-Tie Analysis is a combination of fault tree and event tree analysis, providing a visual representation of risk pathways from the causes of a hazard to their consequences (Figure 20). It recognizes mitigative and preventive controls of a central event, offering a clear view of how risk can be managed. In CCS project, this method is effective in communicating complex risk scenarios.

6.3.3. Risk Identification and Strategy Using Quantitative Evaluation (RISQUE)

Risk Identification and Strategy using Quantitative Evaluation (RISQUE) approach was used in the GEODISC program in Australia to evaluate CO₂ storage sites. It is a structured process where expert panels assess each specific feature of the site using an event tree method, which is similar to a list of Features, Events, and Processes (FEPs). RISQUE utilizes logarithmic square matrices to rate how acceptable a site is based on 6 key factors: its CO₂ content, effectiveness, self-funding potential, wider community benefit, and community safety/amenity. This approach was tested and validated in 4 sites in Australia: Dongara, Gippsland, Petrel, and Carnarvon [267].

6.4. Hybrid Integrated Risk Assessment Model

The Hybrid Model integrates various types of risk assessment methods, combining qualitative, quantitative, and semi-qualitative methods into a single framework. Some standard Hybrid Integrated Risk Assessment models are explained below:

6.4.1. NRAP-Open-IAM (National Risk Assessment Partnership—Open Integrated Assessment Model)

NRAP-Open IAM is an open-source hybrid risk assessment tool developed by the U.S. Department of Energy’s National Risk Assessment Partnership [268]. It combines monitoring data, mechanistic models, and probabilistic simulations to evaluate the risks associated with CO₂ leakage, induced seismicity, and pressure buildup in geological storage sites. NRAP-Open IAM combines deterministic process models with probabilistic risk analysis to provide a flexible framework for assessing the risks related to specific sites and informing the decision-making process.

6.4.2. Artificial Neural Networks (ANNs) Integrated with Simulation Data

Integrating ANNs with simulated data is a hybrid approach that uses machine learning and traditional modeling techniques. Datasets generated from experimental observation or numerical simulations are utilized for training ANNs to predict the storage behavior of CO₂ in geological formations. By this integration, it increases the ability to forecast long-term CO₂ injection outcomes, efficiency of sequestration, and identify possible risks like cap rock leakage or surface migration. This hybrid integrated method enhances the accuracy of prediction and assists in the development of efficient monitoring strategies [269].

6.4.3. GoldSim-Based Probabilistic Simulation Framework

GoldSim is a powerful probabilistic simulation software that merges system dynamics with discrete event simulation and Monte Carlo methods. GoldSim can be used in a CCS project to model complicated subsurface processes, operational parameters, including uncertainties in geological properties, and environmental conditions. This model enables the simulation of numerous scenarios, facilitating risk assessments that account for both stochastic variations and deterministic behaviors. GoldSim allows stakeholders to construct and analyze comprehensive models for CO₂ storage systems by providing a hierarchical and visual modeling environment [270].

Table 6. Risk Assessment Methods.

RA Methods		Goal	Data Needed	Application in CO2 Storage	Time Consumption	Ease to Use	Strength/Robustness	Application for Actual CCS Projects
Qualitative	FEP	Identify and classify factors influencing the system.	Expert knowledge, geological and operational data	Scenario development and safety analysis.	High	Moderate	Strong for systematic identification	Used to build exhaustive scenario/FEP registers for long-term safety studies (foundational for site screening and scenario development). Example: Sleipner/generic FEP database used across CCS assessments [271].
	VEF	Evaluate system vulnerability across scenarios.	Geological, operational, and exposure data	Identify vulnerable zones.	Moderate	Moderate	Moderate to strong.	VEF was designed to support site-specific risk assessments for geological CO2 sequestration. However, based on the available documentation, VEF has not been directly applied to a named commercial CCS project.
	SWIFT	Identify hazards via structured brainstorming.	Process details, expert opinion	Early-phase CCS planning.	Low	Easy	Moderate, expert-dependent	Rapid workshop-style hazard identification used in early-phase CCS screening (used in Norway/North Sea screening and DNV workflows). Example: DNV/early offshore screening workshops [272].
	HAZID	Systematic hazard identification.	Project/design docs, expert input	Identify CO2 leakage paths.	Moderate	Moderate	Strong in early design	Standard project HSE hazard identification applied in large commercial CCS projects (used during permitting/EMP development). Example: Gorgon CO2 Injection project HAZID/EMP documents [273].
	Risk Matrix for Legacy Wells	Categorize and assess legacy well risks.	Well records, AoR characteristics	Risk ranking for permitting (Class VI wells).	Low	Easy	Moderate	Semi-qualitative triage to prioritize legacy wells in an Area-of-Review (AoR). Example: Illinois Basin–Decatur AoR legacy-well screening/triage study [260].
Quantitative	Fault Tree Analysis	Analyze causes of system failure.	Failure probabilities, system design	CO2 leakage path analysis.	High	Complex	Strong if data available	No explicit CCS project was found using FTA; however, it is conceptually included in broader FEP/PRA frameworks for life-cycle risk scenarios.
	Monte Carlo Simulation	Quantify uncertainty probabilistically.	Probabilistic distributions	Leakage/plume prediction.	High	Moderate	Very strong	Used in modeling the Ketzin pilot site (Germany): Monte Carlo assessed heterogeneity’s impact on CO2 arrival times in observation wells [274].
	DRA	Evaluate the worst case without uncertainty.	Point estimates	Bounding case analysis.	Low	Easy	Limited, no uncertainty	DRA used in project permitting/MMV documents as conservative checks (e.g., stakeholder/regulator bounding analyses in the Quest MMV and project safety documentation) [275].
	PRA	Quantify risk including uncertainties.	Distributions, system models	Full leakage risk assessment.	High	Complex	Very strong	Probabilistic quantification of leak frequencies and impacts over life cycle (used to compare mitigation measures/monitoring designs). Example: Advanced probabilistic/geosphere risk work for the Weyburn-Midale project [276].
Semi-Qualitative	MOSAR	Analyze risks using event sequences.	Accident sequences, safety barriers	Limited CCS use; potential in system safety.	Moderate	Moderate	Moderate	Not explicitly tied to a real-world CCS project; originally used in EU CCS feasibility studies [266].
	Bow-Tie (with FTA and ETA)	Visualize causes and consequences with barriers.	Event/fault data	CO2 leakage scenarios.	Moderate to High	Moderate	Strong if quantified	Adopted at Quest (Canada), Peterhead/Goldeneye, and other field CCS projects to map containment risk pathways and control barriers [277].
	RISQUE	Evaluate sites via expert scoring and matrixes.	Site indicators, expert judgment	Used in GEODISC for comparison.	Moderate	Moderate	Good for screening, less for numbers	Applied under Australia’s GEODISC program to conceptual CCS projects in Dongara, Petrel, Gippsland and Carnarvon basins to compare storage risks and engage stakeholders [267].
Hybrid Integrated Model	NRAP-Open-IAM	Assess long-term integrated risk.	Simulation outputs, site parameters	Used in U.S. risk analysis.	High	Complex	Very strong	Deployed to real U.S. candidate sites (incl. Illinois Basin/Decatur) to estimate project risk area/AoR and quantify potential impacts from legacy-well leakage; supporting risk-based monitoring [278].
	ANNs with Simulation Data	Predict trends using AI.	Training datasets	ROP, pressure, and leakage prediction.	High	Complex	Very strong with data	Machine-learning surrogate models trained on field + simulated data for well-leakage screening and accelerated uncertainty quantification. Example: ANN well-leakage prediction trained on two sequestration-field datasets [279].
	GoldSim-Based Probabilistic Framework	Simulate system risk dynamically.	Input distributions, process models	System leakage and plume modeling.	High	Moderate	Very strong	Used in decision-support modeling for CCS uncertainty analysis. However, no specific project was found.

indicates that Quantitative and Hybrid Integrated Models have strong strength/robustness, but they are generally time-consuming and complex to use. In contrast, Qualitative and Semi-Quantitative methods have moderate to strong strength/robustness, with usually low to strong time consumption, and are relatively easy to moderate in use.

7. Monitoring and Verification Methods

Monitoring CO₂ plume migration, especially after injection has stopped, is essential to ensure there is no risk of leakage. Underground water and the environment can be protected if leaks are detected in early stages through proper monitoring. Monitoring is helpful to validate the predictions of computer simulation by tracking the buildup of pressure in the formation. Another primary reason to monitor is to keep track of how the volume of CO₂ has been injected and stored. This makes sure that the CO₂ stays within the targeted storage zone and fulfills the emission reduction target that was agreed upon at the start of the project. When monitoring validates and confirms that the simulations are correct, the trust in the simulation tools increases. This is the primary reason scientists are continually working to develop more accurate monitoring methods. Monitoring can be classified into two types: subsurface monitoring and atmospheric modeling.

7.1. Sub-Surface Monitoring

Sub-surface monitoring is essential in the CCS project to track the behavior, migration, and long-term stability of injected CO₂ within geological formations. A wide range of geochemical and geophysical tools are utilized for this purpose, including the seismic method. Seismic methods are used as strong tools for assessing and monitoring geophysical CO₂ trapping within the geological formations. Seismic monitoring methods are most effective in post-closure monitoring when CO₂ injection is stopped, and the storage site is sealed to evaluate the CO₂ storage effectiveness [280]. Seismic methods utilize 3D methods to assess subsurface structures and fault distribution. They also employ multiple approaches based on 4D techniques [281]. The 4D seismic technology incorporates time lapse seismic monitoring to track the gas leakages, and vertical and horizontal movement of the injected CO₂ plume [282]. 2D time lapse seismic monitoring can also be used when cost consideration is a significant factor; it is utilized to give data on the plume injected. The disadvantage of 2D techniques is that they cannot trace the movement of the CO₂ plume in complex geometry formations. The information on the migration path of CO₂ and leakages can also be obtained by using a vertical seismic profile [283]. Baseline seismic surveys and monitoring are used in CCS projects worldwide to assess the appropriateness of geologic storage sites [280]. To estimate the quantity of CO₂ injected into geological storage sites, seismic methods are utilized in conjunction with Gassmann modeling, where the density of CO₂ must be known at reservoir conditions. However, determining this density is quite tricky. To improve accuracy, seismic tools are combined with gravimetry, which utilizes gravity to detect changes in the density of CO₂ in underground geological storage sites. Time-lapse well logging can also be used for monitoring the saturation of water, oil, and CO₂ during CO₂ miscible flooding for Enhanced Oil Recovery (EOR) [284]. The field use of seismic technology and time-lapse well logging is listed in Table 7.

Electrical and electromagnetic techniques also have significant importance as a monitoring tool; these techniques include Electrical Resistivity Tomography (ERT), Magneto-telluric Sounding, and Electromagnetic Induction Tomography (EMIT), which evaluates the variations in electrical properties that can be correlated with saturation levels of CO₂. Geophysical logs, including neutron, density, and sonic logs, are also helpful in motoring, offering insight into wellbore integrity, saturation changes, and corrosion. A sonic logging tool is utilized to monitor the underground changes that are caused by the injection of CO₂ in the subsurface formation, replacing the formation fluids [284,285]. Data obtained from sonic logging tools are used to recognize many geological characteristics such as fractures, formation porosity, and compaction. Sonic logging tools also give details on the microstructure and composition of the rock matrix [286]. Tiltmeters are used to detect geomechanical deformation, mainly in caprock. Whereas InSAR (Interferometric Synthetic Aperture Radar) techniques such as CR-InSAR (Corner Reflector InSAR), PS-InSAR (Permanent Scatterer InSAR), and D-InSAR (Differential InSAR) are used to monitor millimeter-scale deformation on the surface, providing indirect estimation of subsurface pressure changes. Shallow groundwater tracking is also utilized to monitor the effects of CO₂ leakage on groundwater.

Table 7. Field use of seismic technology and time-lapse logging.

Field	Monitoring Technique	Ref.
In Salah Site, Algeria	Micro-seismic, Wireline logging, and Repeat 3D seismic	[287]
Naylor Field, Australia	Time lapse 3D surface and 2D and 3D VSP seismic	[288]
Weyburn Field, Canada	3D Time-lapse	[282]
Bell Creek oil field, USA	Time-lapse pulsed neutron log	[289]
Frio Formation, USA	VSP Seismic	[290]
Tuscaloosa Formation, USA	Well Logging and 3D time-lapse seismic	[291]
Stuttgart Formation, Germany	Pulsed neutron gamma well logging, 3D time-lapse seismic, and petrophysical test on core samples	[292]
Nagaoka Test Site, Japan	Time-lapse cross-well seismic tomography	[293]
Jingbian Field, China	Time-lapse well logging and 4D seismic	[294,295]
Sleipner Field, Norway	2D time-lapse seismic	[296]

Table 7. Field use of seismic technology and time-lapse logging.

Field	Monitoring Technique	Ref.
In Salah Site, Algeria	Micro-seismic, Wireline logging, and Repeat 3D seismic	[287]
Naylor Field, Australia	Time lapse 3D surface and 2D and 3D VSP seismic	[288]
Weyburn Field, Canada	3D Time-lapse	[282]
Bell Creek oil field, USA	Time-lapse pulsed neutron log	[289]
Frio Formation, USA	VSP Seismic	[290]
Tuscaloosa Formation, USA	Well Logging and 3D time-lapse seismic	[291]
Stuttgart Formation, Germany	Pulsed neutron gamma well logging, 3D time-lapse seismic, and petrophysical test on core samples	[292]
Nagaoka Test Site, Japan	Time-lapse cross-well seismic tomography	[293]
Jingbian Field, China	Time-lapse well logging and 4D seismic	[294,295]
Sleipner Field, Norway	2D time-lapse seismic	[296]

7.2. Atmospheric Monitoring

The potential for CO₂ leakage from geological storage sites to the atmosphere is a growing concern among the public. To detect this leakage, atmospheric monitoring tools are utilized while CO₂ is being injected into a geological storage site [297]. Atmospheric monitoring tools are very sensitive because CO₂ will disperse very fast into the atmosphere as soon as it leaks from the subsurface. These tools are installed at probable CO₂ leakage zones to enhance their detection capability [298]. These tools generally consist of CO₂ detectors [299], laser systems [299], flux chambers [300], advanced leak detection systems [298], optical sensors [301], eddy covariance tools [302], and atmospheric tracers [302]. The amount of CO₂ in the atmosphere must remain under certain limits to ensure that CO₂ detectors can be used to detect the surplus CO₂ above a specific limit in the atmosphere. The use of CO₂ detectors is not so common because to effectively detect CO₂, a large number of CO₂ detectors need to be installed [299]. Another method used to detect CO₂ in the atmosphere is laser systems. This method utilizes technology to emit a laser of a wavelength that is absorbed by CO₂ molecules [299]. Advanced leak detection systems are also used to detect CO₂ in the atmosphere; in this method, terrestrial vehicles (aircraft) consist of GPS mapping technology, and three sensitive gas detectors are used for carrying out monitoring [299]. Flux chambers are also an important tool used in projects for monitoring the emission of CO₂ at the soil-atmosphere interface, to detect the CO₂ leakage from geological storage sites. These chambers operate by enclosing a small surface and measuring the depletion or accumulation of concentrations of CO₂ with time, which can be utilized for near-surface CO₂ flux rate calculations. Flux chambers are used in CCS sites because of their cost-effectiveness, simplicity, and sensitivity to small fluxes [303]. Eddy covariance systems can also be utilized to quantify the surface fluxes of gases over a large area [304]. The eddy covariance tool is used to measure water vapor, CO₂ fluxes, and sensible heat [305]. Several factors can affect the flux maps resolution and accuracy, some of these factors are atmospheric conditions [306], Terrain complexity and heterogeneity at surface [307], height measurement [308], Instrumentation [309], averaging periods length [310], amount of Eddy covariance stations [311], data processing application [312,313], and spatial arrangement of Eddy covariance terminals [314]. Atmospheric tracers are also widely utilized in the monitoring of CO₂ for CCS projects to detect and quantify the probable leaks by distinguishing the stored background atmospheric levels. Such tracers are perfluorocarbons (PFCs), sulfur hexafluoride (SF₆), or isotopically labeled CO₂ (e.g., ¹³CO₂). These tracers are co-injected with CO₂ or injected independently, and then they are monitored in the atmosphere. Their concentration patterns help in estimating leakage rates, identifying leakage pathways, and validating atmospheric transport models. Tracers are effective in the near surface, complementing other tools such as flux chambers or eddy covariance. The Frio project is one of the significant CO₂ injection projects that utilize the tracers for monitoring purposes [315].

8. Economic Analysis of the CCS Process

CCS technology plays a crucial role in the decarbonization of power generation, thereby reducing greenhouse gas emissions. There are approximately 620 CCS projects globally that serve this role, with over 50 operational facilities. However, regular and rigorous economic evaluations remain crucial to supporting more CCS initiatives, utilizing resources wisely, and reducing costs further to accelerate CCS deployment worldwide. It is also essential for decision makers to invest their time and resources in the most promising and profitable technologies [316]. The economic feasibility of CCS projects relies on a detailed understanding of the expenses associated with each segment of the CCS process, which includes capturing, compression, transportation, storage, and monitoring. It is influenced by various factors within the CCS value chain, including the type of capturing technology employed, the proximity of the storage site to the CO₂ source, the geological characteristics of the storage site, and regulatory policies.

The economic analysis of CCS encompasses the evaluation of costs, benefits, and environmental implications of the capture, compression, transport, injection, storage, and monitoring. It can be broadly categorized into Capital Expenditure (CAPEX) and Operational Expenditure (OPEX). CAPEX costs refer to the one-time and fixed expenses required to design, build, and install the CCS system. Multiplication of CAPEX by the annualized factor will give us the annualized expenditure cost (ACAPEX), where the annualized factor is calculated as follows [317].

$$Annualized factor=\sum _{n=1}^{OY}{\displaystyle \frac{1}{{(1+r)}^n}}$$

(1)

where $OY$ is the operation year and r is the discount rate.

In contrast, OPEX costs encompass the ongoing costs associated with operating and maintaining the plant. The capturing segment takes up most of the CCS cost (approximately 70%), followed by monitoring expenses [318] and it can be calculated as follows.

$${CO}_2 capturing cost\left(in USD/ton of {CO}_2\right)={\displaystyle \frac{ACAPEX+OPEX}{{CO}_{2,cap}}}$$

(2)

where ${CO}_{2, cap}$ is the captured CO₂ per annum.

The TEA of CCS project requires a consistent set of underlying assumptions which include discount rate, project lifetime, capacity factor and plant scale, energy price, and carbon price. The significant costs involved during the CCS process are summarized in Figure 21 [319].

A detailed understanding of the different cost components is crucial for a comprehensive evaluation of CCS costs, and there should be novel advancements in every sector of the CCS process to lower the CCS costs. These include innovative solvents that enhance the absorption and desorption efficiency of CO_2, for capturing: an improved CO₂ compression and water removal system, for compression and dehydration: advanced liquification and pipeline technologies, for transportation/shipping: selection of optimized storage site and advanced monitoring techniques for storage.

In geological carbon storage (GCS), the cost includes the cost for site selection and characterization, drilling, injection, monitoring, reporting, and verification (MRV), land leasing, insurance and bonding, project closure, community benefits, and regulatory and permit-related costs [320]. These costs varied based on the type of geological formation used for the storage. A study by Enab et al. [321] conducted on the techno-economic analysis of CO₂ sequestration in depleted oil and gas reservoirs, saline aquifers, and CO₂-EOR to investigate the most valuable CO₂ sequestration strategies based on the net present value (NPV); found out that depleted oil and gas reservoirs are the most economically feasible for CCS application when integrated with direct air capture (DAC) and compliant with Section 45Q (a performance based tax credit for carbon management projects). Saline aquifers and CO₂-EOR, on the other hand, are feasible, but with a lower economic return, unless maximizing storage capacity is the primary goal.

Under the Inflation Reduction Act (IRA), the 45Q tax credit provided $60 per metric ton of CO₂ for EOR and $85 per ton for storage in saline aquifers [8].

Another study by Hong [322], the techno-economic review of CCUS proposed that repurposing depleted hydrocarbon could help reduce the cost of the CCS process. The study also suggested that storing CO₂ in saline aquifers and depleted fields is a technologically and financially feasible option. The storage cost per ton of CO₂ significantly varies based on factors including types of reservoirs, location of the reservoir, and presence of legacy wells. Based on these and other factors the CO₂ storage cost per ton of CO₂ varies from $1.3 to $13 for onshore and from $16 to $29 [323]. In general, these storage choices are economically appealing for large-scale CO₂ reduction in CCUS systems and play a crucial role in achieving net-zero goals.

9. Discussion

The review of 43 operational commercial CCS projects reveals clear and consistent patterns in technology choices and deployment pathways. Pre-combustion capture, which is best suited to industrial gas-processing streams, underpins many commercially mature projects. Pipelines remain the dominant and most economical transport mode for large, continuous CO₂ flows. Storage is concentrated in two pragmatic options: depleted petroleum reservoirs, which benefit from extensive subsurface data and existing infrastructure, and deep saline aquifers, which offer the greatest capacity but require more intensive characterization and pressure management. Depleted oil reservoirs (EOR) emerge as the most used storage type, reflecting their dual benefit of CO₂ sequestration and EOR. However, these storage strategies are not without challenges. Injection activities can cause pressure buildup, potentially activate faults, or trigger earthquakes, requiring careful geomechanical monitoring and site-specific risk mitigation. Ensuring CO₂ remains stored safely for centuries demands long-term monitoring commitments, and political or financial instability could jeopardize consistent oversight. These considerations highlight the importance of robust regulatory frameworks, advanced monitoring technologies, and risk management strategies to ensure the integrity and sustainability of CCS projects.

This review shows that geomechanical stability and geochemical interactions are critical to the long-term success of CCS projects in both depleted hydrocarbon reservoirs and deep saline aquifers. From a geomechanical perspective, CO₂ injection alters the in situ stress regime, which can lead to pressure buildup, fault reactivation, or even induced seismicity if not properly managed. These risks are generally lower in depleted reservoirs because prior production has reduced formation pressure, but legacy wells and compromised wellbore integrity remain potential leakage pathways. In contrast, saline aquifers offer vast storage capacity but require careful pressure management and robust monitoring strategies to prevent caprock failure. Geochemically, the interaction between injected CO₂, formation brine, and reservoir rock governs long-term containment. Processes such as CO₂ dissolution in brine, mineral dissolution, and secondary mineral precipitation enhance storage security over time by promoting solubility and mineral trapping. However, these reactions can also alter porosity and permeability, influencing injectivity and plume migration. While these mechanisms provide multiple layers of containment, they occur over different timescales—physical trapping dominates initially, while chemical trapping becomes significant over decades to centuries. Overall, successful CCS deployment in these formations depends on integrated site characterization, coupled geomechanical-geochemical modeling, and continuous monitoring to ensure storage integrity and mitigate risks.

This review highlights key differences between analytical and numerical models used in CCS simulations. Analytical models are fast and provide exact solutions, making them useful for early-stage screening and quick checks. However, they rely on strong simplifications and cannot capture the complexity of real geological systems. Numerical models, on the other hand, are more flexible and can handle detailed reservoir characteristics, multiphase flow, and coupled geomechanical or geochemical processes. While they require more computational time and resources, their scalability and ability to simulate full-field conditions make them essential for risk assessment and long-term performance prediction. In practice, analytical models are best suited for preliminary feasibility studies, whereas numerical models are indispensable for detailed design, optimization, and regulatory compliance in large-scale CCS projects.

Risk assessment is most effectively approached as a phased or stepwise process. Qualitative methods such as FEP analysis and HAZID are widely used in early project stages because they rely on expert judgment and require less data, making them suitable for screening and scenario development. However, they lack numerical precision and cannot fully capture uncertainty. Quantitative methods like Monte Carlo simulation and Probabilistic Risk Assessment (PRA) provide a more rigorous evaluation by incorporating probability distributions and modeling uncertainties, but they demand extensive data and computational resources. Semi-quantitative approaches, such as MOSAR and Bow-Tie analysis, bridge the gap by combining structured scoring with visual representation of risk pathways, offering a balance between complexity and usability. Hybrid integrated models, including NRAP-Open-IAM and AI-based frameworks, represent the most advanced category, integrating deterministic simulations with probabilistic analysis for comprehensive risk evaluation. While these models deliver robust insights, they are time-consuming and require specialized expertise. Overall, the choice of RA method depends on project maturity, data availability, and regulatory requirements.

Monitoring and verification play a critical role in ensuring the long-term safety and effectiveness of CO₂ storage. Our review shows that subsurface monitoring techniques, such as 4D seismic imaging, vertical seismic profiling, and time-lapse well logging, are widely adopted because they provide detailed insights into plume migration and reservoir integrity. These methods allow operators to validate simulation models, detect leakage risks early, and confirm that CO₂ remains within the designated storage zone. Complementary geophysical tools like Electrical Resistivity Tomography (ERT) and electromagnetic surveys add another layer of assurance by tracking saturation changes in the subsurface. Surface and atmospheric monitoring methods, including flux chambers, eddy covariance systems, and tracer studies, are essential for detecting potential leaks at or near the ground level. While these technologies have proven effective, they require significant investment and long-term commitment, as monitoring obligations often extend for decades after site closure. The integration of multiple monitoring techniques, combined with real-time data analytics, is emerging as best practice to meet regulatory requirements and maintain public confidence in CCS projects.

The economic analysis of CCS highlights that cost remains one of the most significant barriers to large-scale implementation. Our review shows that capture accounts for the largest share of total CCS costs, typically around 70% due to the energy-intensive nature of separation and solvent regeneration. Transportation and storage costs are comparatively lower, especially when existing pipeline infrastructure and depleted oil and gas reservoirs can be repurposed. Among storage options, depleted oil/gas reservoirs often provide the most cost-effective solution because they leverage existing wells and surface facilities, reducing capital expenditure. Saline aquifers, while offering vast storage capacity, require extensive site characterization and monitoring, which increases upfront costs. Policy incentives such as the U.S. 45Q tax credit and Canada’s Investment Tax Credit significantly improve project economics, while carbon pricing under the EU ETS creates additional revenue streams. Despite these measures, long-term monitoring obligations and liability provisions add financial complexity, emphasizing the need for stable regulatory frameworks and innovative financing models. Overall, achieving cost reductions will depend on scaling up projects, advancing capture technologies, and integrating CCS with complementary processes like enhanced oil recovery (EOR) and direct air capture (DAC).

10. Conclusions

Carbon Capture and Storage (CCS) stand as a cornerstone in the global strategy to mitigate climate change, offering a scalable and effective solution for reducing CO₂ emissions from industrial and energy sectors. This review has provided a comprehensive overview of CCS technologies covering capture methods, transportation, geological storage, modeling, geomechanical and geochemical aspects, risk assessment, monitoring, and economic analysis. Key takeaways of this paper are listed below:

• Technology Choices: Pre-combustion capture and pipeline transport are the most common in commercial CCS projects.
• Storage Strategies: Depleted oil/gas reservoirs are widely used due to EOR benefits and existing infrastructure; saline aquifers offer large capacity but require intensive monitoring.
• Geomechanical and Geochemical Stability: Long-term containment depends on managing pressure buildup, fault activation, and chemical interactions that affect porosity and injectivity.
• Modeling Approaches: Analytical models are useful for early screening; numerical models are essential for detailed design and risk prediction.
• Risk Assessment: A phased approach is best—qualitative methods for early stages, quantitative and hybrid models for advanced evaluation.
• Monitoring and Verification: Integrated subsurface and surface monitoring ensures CO₂ containment and supports regulatory compliance.
• Economic Considerations: Capture is the most expensive phase (~70% of total cost); reuse of infrastructure and policy incentives improve project viability.
• Path Forward: Although CCS technologies have matured significantly, challenges remain in cost reduction, infrastructure development, and regulatory alignment. Moving forward, interdisciplinary collaboration, technological innovation, and strong policy support will be essential to accelerate CCS deployment and achieve global decarbonization goals.

11. Future Recommendations

• Integration of Artificial Intelligence (AI) and Machine Learning (ML): Future research should explore the integration of AI/ML algorithms with CCS simulation tools for predictive modeling, anomaly detection, and optimization of injection strategies.
• Improved Geomechanical-Geochemical Coupling: Advanced Multiphysics models that better couple stress-induced changes with reactive transport are needed to predict long-term site stability more accurately.
• Legacy Infrastructure Assessment: More comprehensive frameworks are needed to assess and remediate legacy wells beyond initial risk matrices, integrating real-time data and dynamic monitoring to ensure effective remediation.
• Standardized Risk Protocols: Global standardization of CCS risk assessment methods should be pursued to ensure consistent evaluation, especially across jurisdictions and storage environments.
• Cost Reduction Innovations: Investment in novel capture materials, efficient compressors, and automated monitoring technologies can significantly reduce capital and operational costs, enhancing economic viability.
• Public Engagement and Policy Development: Successful implementation of CCS requires public trust and supportive regulatory frameworks. Policies should incentivize CCS development, ensure long-term liability management, and promote transparent data sharing.
• Pilot and Field-Scale Projects: More field validation studies, particularly in underexplored regions and geological settings, will help improve modeling accuracy and stakeholder confidence in large-scale deployment.