CO₂ Trapping Mechanisms in Geological Carbon Sequestration: A Critical Review of Multiscale Processes and Storage Security

Abstract

Geological carbon sequestration is a critical strategy for reducing atmospheric CO₂ emissions and mitigating climate change; however, its long-term effectiveness depends on a robust understanding of subsurface trapping mechanisms. This review synthesizes recent advances in evidence-based CO₂ trapping by systematically examining four primary mechanisms—structural/stratigraphic, residual (capillary), solubility, and mineral trapping—using insights from experimental studies, field observations, and numerical modeling. The analysis highlights that structural trapping provides immediate containment controlled by caprock integrity and reservoir geometry, while residual trapping immobilizes CO₂ at the pore scale through capillary forces and multiphase flow dynamics. Over longer timescales, solubility trapping enhances storage security via dissolution and density-driven convection, whereas mineral trapping offers the most permanent form of sequestration through geochemical conversion to stable carbonates, albeit with slower kinetics. Recent findings emphasize the strong coupling among trapping mechanisms, the influence of wettability, heterogeneity, and flow regimes, and the growing role of engineered injection strategies and enhanced mineralization approaches. Overall, the review demonstrates that secure and scalable CO₂ storage requires an integrated, multiscale understanding of these interacting processes, supported by improved monitoring, modeling, and experimental validation to reduce uncertainty and optimize storage performance.

1. Introduction

It is estimated that the global average surface temperature has increased by approximately 2 °F since the pre-industrial era. The increase in global temperature has contributed to reductions in snow covers, melting glaciers, and caused habitat changes for plants and animals [1]. Therefore, if global warming is not controlled, its effects on Earth’s ecosystems can be potentially catastrophic. Global warming is directly attributed to greenhouse gas emissions from both natural and anthropogenic sources [2,3,4,5,6]. It is suggested that the contributions of greenhouse gases such as CO₂, CH₄, and N₂O towards global warming are approximately 60%, 15%, and 5%, respectively [7]. It is estimated that if the greenhouse gas emissions are not controlled, the global surface temperature may rise by 1.4 °C to 5.8 °C within the next two centuries [3].

CO₂ dissolves in water, forming a weak acid called carbonic acid. With the splitting of the carbonic acid molecule, the pH of water is lowered, making it acidic. Therefore, when large amounts of CO₂ are present in the atmosphere, they can dissolve in ocean water, making it irreversibly acidic over time [8].

Carbon capture and sequestration (CCS) is a technology aimed at reducing the atmospheric carbon imprint, thereby mitigating the adverse effects of climate change. There are two major types of CCS, which are as follows:

(a)

Geological CCS: Geological CCS involves capturing CO₂ from various industrial sources and storing it in underground formations. The practice usually involves injecting supercritical CO₂ into porous rock formations such as saline aquifers, unusable coal seams, depleted oil and gas fields, and basalt formations [9]. Also, CO₂ is typically injected at depths greater than 3000 feet in presence of caprocks that seal the formations [10].

(b)

Biological CCS: This involves the storage of CO₂ in vegetation on land and in waterbodies, soils, and wetlands. For instance, trees and vegetation can absorb CO₂ and use it during the process of photosynthesis. Similarly sustainable agricultural practices such as no-till farming and cover cropping can significantly improve carbon sequestration.

Geological CCS generally involves the following steps:

i.

CO₂ Capture: CO₂ is captured from large point sources such as power plants, natural gas processing facilities, cement factories, and steel mills. CO₂ capture is performed through three different mechanisms which are as follows:

(a)

Pre-combustion capture: CO₂ is captured before combustion by converting fuel to a synthetic gas mixture (syngas) and CO₂ is separated after a chemical reaction. Figure 1 shows a diagram of pre-combustion capture of CO₂.

Fossil fuels are converted to syngas (synthetic gas) through incomplete combustion. Syngas is a mixture of CO and H₂ and it undergoes a water–gas shift reaction to produce CO₂ and H₂, following which CO₂ is separated from H₂ using physical or chemical reactions.

(b)

Post-combustion capture: CO₂ is captured after fuel is burned; it is separated from the flue gas using membranes, chemical solvents, and solid sorbents. As part of this process, fossil fuels are burned in air to produce flue gases containing CO₂, N₂, water vapor, O₂, and other pollutants. After the hot flue gas is cooled, particulates and other pollutants are removed from it. The cooled flue gas passes through an absorption column where it reacts with the solvent to produce a weakly bonded compound. Next, CO₂-rich solvent is heated in a regeneration column releasing pure CO₂ gas. Figure 2 shows post-combustion CO₂ capture.

(c)

Oxy-fuel combustion capture, where CO₂ is captured during combustion. As part of this process, fuel is burned in pure oxygen instead of air and it produces CO₂ and water vapor. While water is condensed, CO₂ is captured. Figure 3 shows a diagram of oxy-fuel combustion CO₂ capture process.

ii.

CO₂ Compression and Transport:

The captured CO₂ is transported to a storage site. The transportation takes place through pipelines, on ships, on trucks, or through railroads. CO₂ is typically transported in the supercritical state to reduce volume.

iii.

CO₂ Sequestration:

As mentioned earlier, the main types of CO₂ sequestration processes are either geological or biological sequestration. The focus of this review is geological sequestration and therefore the discussions will be limited to it. Geological CO₂ sequestration involves storing CO₂ in deep underground rock formations in an attempt to prevent its leakage into the atmosphere. CO₂ can be stored in formations such as saline aquifers, depleted oil and gas fields, and unmined coal seams.

When CO₂ is injected into the subsurface porous reservoirs, it displaces resident fluids such as brine. In closed systems with low permeability boundaries, this process can lead to increase in pressure over time. Over-pressurization can cause excessive mechanical stress to develop. Therefore, CO₂ injection rates are constrained by pressure limits that can be safely accommodated without risk of caprock fracture [11]. Pressure evolution over the long term also affects CO₂ storage capacity. Therefore, owing to the maximum allowable pressure, all available pore-spaces within the reservoir may not be filled.

On the other hand, higher pressure gradients tend to accelerate plume migration through high-permeability pathways. During long-term CO₂ injection, pressure evolution can redistribute the fluids and influence the CO₂ trapping mechanisms. Therefore, monitoring pressure rises and identifying potential leakage paths are effective management strategies in geological CO₂ sequestration.

For CO₂ sequestration to be a highly successful technology, it is extremely important that the geological storage sites should be robust. The storage sites can be compromised because of potential leakage pathways, faults, degraded wells, and caprocks. Therefore, this article focuses on the various CO₂ trapping mechanisms to assess the effectiveness and the current technology readiness levels (TRLs) of each mechanism and explores potential areas of improvement.

1.1. Review Methodology

This manuscript reviews the published literature on geological CO₂ sequestration. The primary goal of this work is to perform a scoping review of the literature on subsurface CO₂ trapping mechanisms to identify any knowledge gaps and to direct future researchers towards areas that may require further investigation [12]. This article also examines each trapping mechanism and suggests a technology readiness level (TRL). The methodological framework of the scoping review is as follows:

• Identification: At this stage, the objective was to identify an area of carbon capture and sequestration that was not adequately explored in the current body of knowledge. The main keywords for the literature survey were determined, which were related to CO₂ sequestration and subsurface CO₂ trapping mechanisms. Some examples of the keywords identified for the search were “carbon sequestration”, “carbon capture and storage (CCS)”, “structural trapping”, “mineralization”, “residual trapping”, “capillary trapping”, and “solubility trapping”. The identified keywords were then used to search for articles on databases such as ScienceDirect, Wiley Online Library, SpringerLink, the American Chemical Society, and OnePetro, which is managed by Society of Petroleum Engineers (SPE). In addition, the keywords were also entered on ‘Google Scholar’ to review a large spectrum of journal articles, conference papers, and book chapters that dealt with the areas of interest. The time range for the web search was between April 2025 and May 2026.
• Screening: All articles gathered through the search were screened by carefully reading the titles and abstracts. Therefore, the articles that were not aligned with the scope of review were discarded.
• Eligibility: At this time, a secondary-level assessment was conducted and the articles selected after the initial screening were reviewed by reading through results, discussions, and conclusions. Only those articles that discussed CO₂ trapping mechanisms were selected for review.
• Inclusion and Analysis: At this stage, the manuscripts that passed the eligibility criteria were included and subsequent analyses were performed to identify trends, projections, or any knowledge gaps.
• Preparation of Manuscript: The manuscript was carefully prepared with the aim of providing an overview of the established CO₂ trapping mechanisms, summarizing some of the latest developments reported by researchers in recent years, and evaluating any knowledge gaps to direct future researchers. Finally, each trapping mechanism was evaluated for their current technology readiness level based on the available evidence.

1.2. Objectives and Novelty of the Review

One of the primary objectives of this review is to provide an overview of the subsurface CO₂ trapping mechanisms in a lucid yet comprehensive manner with suitable illustrations, such that the information is useful to students, professionals, researchers, and policy makers associated with the area of carbon capture and sequestration. In addition, this paper also highlights some of the very recently published articles and identifies knowledge gaps and potential areas of future research. Finally, the established CO₂ trapping mechanisms are assigned to a technology readiness level (TRL) based on scoring criteria developed by the authors. To the best of our knowledge, other contemporary review articles in this subject area have not reported TRLs associated with CO₂ trapping mechanisms.

2. Mechanisms of CO₂ Trapping

Currently, the established methods of carbon dioxide trapping are as follows: (a) structural or stratigraphic trapping, (b) mineralization, (c) solubility trapping, and (d) residual trapping.

2.1. Structural or Stratigraphic Trapping

Structural or stratigraphic trapping is a primary and one of the most significant methods of CO₂ trapping. Various subsurface geological features such as faults and folds are known to contribute to structural trapping of CO₂. Within a fault system, structural trapping may occur when the fault intersects with the dipping zone of a reservoir. Such a system involves a highly impermeable matrix within the fault and a sealing caprock [13,14]. The injected CO₂ has lower density than the resident brine and therefore is more buoyant and travels upwards. The buoyant CO₂ can be trapped by tight and low porosity formations called caprocks. The caprocks create large capillary entry pressures and therefore restrict the migration of buoyant CO₂ [15]. It is estimated that the porosity of shale caprocks is in the range of 5–100 nm. The structural integrity and the ability of the caprock to keep the trapped CO₂ sealed is dependent on a balance between the CO₂ buoyant force and the capillary force of the caprock, shown by Equations (1)–(3):

$$P_b=∆\rho gh,$$

(1)

$$P_c={\displaystyle \frac{2\gamma cos\theta }{r}},$$

(2)

$$h={\displaystyle \frac{2\gamma cos\theta }{∆\rho gr}},$$

(3)

where $P_b$ is the buoyant pressure, $P_c$ is the capillary pressure, $∆\rho$ is the density difference between CO₂ and brine, $h$ is the CO₂ column height, $\gamma$ is the CO₂ brine interfacial tension, $\theta$ is the contact angle between CO₂ and brine, $r$ is the average pore radius of the caprock, and $g$ is acceleration due to gravity. Structural or stratigraphic trapping of CO₂ can be attributed to faults, which act as physical barrier to the migration of CO₂ towards Earth’s surface.

There are five major types of fault seals that enable structural trapping of CO₂. They are as follows [16]:

(a)

Cataclastic fault seals: These are formed from pure sandstones with low clay content. These are formed due to the mechanical crushing, grinding, and fracturing of rocks during fault movement.

(b)

Cement seals: These are formed through the precipitation of minerals that fill in the pore spaces and therefore block fluid flow.

(c)

Juxtaposition seals: These types of seals are formed when fault movement causes different rock layers to be juxtaposed or placed next to each other. When the rock layer on one side of the fault is permeable, the layer on the other side is impermeable. So, the impermeable rock acts as a barrier to the flow.

(d)

Phyllosilicate fault seals: These are seals formed through the deformation of fault seals that are rich in phyllosilicate materials such as clay, chlorite, smectite, serpentine, etc. The fault zone becomes concentrated with these materials and its permeability is reduced.

(e)

Clay smears: These are formed when the faulting process deforms clay units within the fault zone. Therefore, a low permeability clay layer is formed.

Figure 4 shows structural trapping by subsurface fault structure.

While faults are associated with the brittle deformation of rocks, folds are formed through ductile deformation of rocks due to compression stresses caused by tectonic activities. Brittle deformation of rocks occurs when temperatures are low. On the other hand, ductile deformations are caused by high temperatures in addition to adequate confining pressure. Also, deformation of rocks is subject to several rock characteristics such as porosity, permeability, grain size and grain size distribution, and mineral composition and distribution [14]. The following types of folds are effective towards storing CO₂:

(a)

Anticlines: These are upward-arching folds with rock layers bending upwards like an inverted bowl. As buoyant CO₂ migrates upwards through the porous rock, they are trapped at the crest of the anticline. An overlying impermeable caprock prevents CO₂ from escaping.

(b)

Domes: These are special types of anticlines with elliptical or circular cross-sections. They are completely closed from all directions.

Figure 5 shows structural trapping of CO₂ using a subsurface fold system with an impermeable sealing rock.

Historically structural trapping is assessed through the height of CO₂ columns. A research group suggested that the actual mass of CO₂ that can be trapped is a more important parameter than the CO₂ column height, towards determining the efficacy of structural trapping. They also indicated that a maximum depth exists below which structural trapping fails. The depth at which maximum mass of CO₂ can be trapped and immobilized is approximately 1300 m. At depths lower than 2400 m, caprocks cannot successfully trap CO₂ owing to a phenomenon called wettability reversal [17]. Wettability reversal may be defined as the transition of a solid surface’s fluid affinity from one phase to another.

Szulczewski et al. studied dissolution of CO₂ in porous layers that were representative of CO₂ storage in structural or stratigraphic traps. They concluded that although dissolution of CO₂ was strongly dependent on reservoir properties, reservoirs with permeability exceeding 1000 mD, which were also thick, and several kilometers wide, had great dissolution capabilities [13].

2.2. Mineralization

This process involves transforming CO₂ into carbonate materials and the rate of mineralization is dependent on factors such as the frequency of cation release and abundance. Mineralization is considered as the most effective form of CO₂ trapping in the form of carbonate materials, (Ca, Mg, Fe)CO₃. However, the process is slow since mineralization depends on the release of cations through dissolution of silicates and oxides in rocks. Mineral trapping of CO₂ via silicate dissolution and carbonate precipitation is highly efficient under mildly acidic conditions (pH ≈ 4.5–6) and low fluid-flow velocities. This ensures sufficient residence time for cation release, alkalinity generation, and interface-coupled carbonate precipitation in diffusion-dominated subsurface domains [18,19,20,21,22].

The process of mineralization is further classified as (1) Direct Carbonation and (2) Indirect Carbonation.

2.2.1. Direct Carbonation

It involves a single process stage for carbonation, and it is further classified as (i) Direct Gas–Solid Carbonation and (ii) Direct Aqueous Carbonation methods [20]. Direct Gas–Solid Carbonation is a simple method where CO₂ directly reacts with a solid material, to form stable carbonates. The following is an example of direct gas–solid carbonation:

Mg₂SiO₄ (s)+ 2CO₂ (g) → 2 MgCO₃ (s) + SiO₂ (s)

Direct aqueous carbonation involves carbonation of the silicates of calcium or magnesium in an aqueous solution. The following are the three reaction stages associated with direct aqueous carbonation:

(i)

Leaching of minerals: During this process, metal ions such as Ca²⁺ and Mg²⁺ are extracted from the solid mineral into the aqueous phase such that they can react with the carbonate ions to form solid carbonates. The following is an example of leaching.

Mg₂SiO₄ (s)+ 4 H⁺(aq) → 2Mg⁺² (aq)+ 2H₂O (l) + SiO₂ (s)

(ii)

Release of carbonate ions: CO₂ reacts with liquid water to release carbonate atoms:

CO₂ (g) + H₂O (l) CO₃²⁻ (aq) + 2H⁺ (aq)

CO₂ (g) + H₂O (l) → CO₃²⁻ (aq) + 2H⁺ (aq)

(iii)

Formation of carbonate atoms: During this step, the nucleation and the growth of mineral carbonates take place.

Mg²⁺ (aq) + CO₃²⁻ (aq) → MgCO₃ (s)

While the direct gas–solid carbonation employs a simple process design, it is characterized by slow reaction rates. However, several methods for improvement of reaction kinetics have been suggested by previous researchers:

(a)

Addition of complexing agents: Agents such as HCl (hydrochloric acid), CH₃COOH (acetic acid), and HCOOH (formic acid) can accelerate reactions [23,24,25].

(b)

Addition of other organic acids: A combination of oxalic acid, ethylenediaminetetraacetic acid, and orthophosphoric acid is known to increase dissolution rates of Mg₂SiO₄ [24].

(c)

Addition of alkali metal hydroxides: An addition of alkali metal hydroxides increases pH within the solution and enhances absorption of CO₂ [20].

(d)

Addition of sodium carbonate: Dissolution of Mg₂SiO₄ can be enhanced by raising its pH and by adding Na₂CO₃ [25].

2.2.2. Indirect Carbonation

The method of indirect carbonation employs several stages where Mg and Ca ions are extracted from their respective mineral ores. Following this, they are converted into their respective oxides or hydroxides. Finally, CO₂ reacts with these oxides or hydroxides to form stable carbonates. Usually, indirect methods of carbonation tend to be faster than the direct methods. Indirect carbonation can further be classified into (a) Indirect gas–solid carbonation and (b) Indirect aqueous carbonation.

As shown using the following equations, during indirect gas–solid carbonation, silicates of Ca or Mg may be used to produce their corresponding hydroxides, which may then be reacted with CO₂ to produce stable carbonates:

MgSiO₃ + 2HCl → MgCl₂ +H₂O + SiO₂ (s)

MgCl₂ + 2H₂O → Mg(OH)₂ + 2HCl (aq)

Mg(OH)₂ + CO₂ → MgCO₃ + H₂O (l)

Indirect aqueous carbonation involves two steps where Ca or Mg are extracted and subsequently carbonated in an aqueous solution. The optimization of the silicate rock dissolution is obtained through addition of acids and bases.

Several research groups studied the process of high carbonation rates. Butt observed that it took only 30 min to convert 90% of Mg(OH)₂ to MgCO₃ when a particle size of 0.1 µm was used at a pressure and temperature of 5300 kPa and 838 K, respectively [20]. On the other hand, Lackner et al. reported a total time of 2 h for 100% conversion of Mg(OH)₂ to MgCO₃ at a pressure and temperature of 340 bars and 773 K [23].

2.2.3. Economic Implications Associated with Mineralization

Mineralization is the most stable form of CO₂ trapping mechanism that can provide permanent storage on geological timescales, eliminates long-term leakage concerns, and minimizes regulatory and environmental liability. However, there are scale-up challenges associated with this mechanism. For instance, mineralization often depends on the interaction between gas, liquid, and solids. At larger scales, the associated mass transfer rates become slower and therefore, there may be a need for larger reactors or longer residence times. Likewise, since mineralization reactions are slow under ambient conditions, replicating these conditions on an industrial scale is energy-intensive and expensive. In summary, although mineralized CO₂ has negligible risk of leakage, currently mineralization is more expensive than structural or residual trapping mechanisms. Therefore, higher costs remain a major barrier to practical deployment.

2.3. Solubility Trapping

This method involves the dissolution of carbon dioxide in the resident brine at the interface. The process involves injecting CO₂ into the subsurface reservoir such that part of it dissolves in reservoir brine, forming different species such as CO₃²⁻ (aq), HCO₃⁻ (aq), and CO₂ (aq), preventing any CO₂ leakage in the discrete phase [14]. Brine saturated with CO₂ will sink because it may have larger density than formation brine. Several factors influence the dissolution of CO₂ in brine such as the reservoir porosity, absolute permeability, CO₂ flowrate within the reservoir, and the diffusion coefficients of the species in the reactions [26]. The other factors influencing dissolution are reservoir temperature and salinity, and with increase in temperature and salinity, CO₂ solubility decreases. The following equation shows the process of CO₂ dissolution in reservoir brine [27]:

CO₂ (aq) + H₂ O → H₂ CO₃

H₂ CO₃ → H⁺ + HCO₃⁻

HCO₃⁻ → H⁺ + CO₃²⁻

When CO₂ dissolves in brine, it no longer exists as a separate phase and therefore does not move upwards due to the buoyant force. Also, only a part of CO₂ dissolves in brine while the rest is converted to stable minerals.

Previous researchers suggested that solubility trapping is the second most dominant mechanism of CO₂ trapping after structural trapping, with 10–50% of CO₂ being stored across whole reservoirs [28]. Recent studies showed density-driven convection-enhanced dissolution rates. CO₂ dissolved in brine increases its density and triggers downward convective fingering, which dramatically speeds up mixing [29,30]. Also, heterogeneity significantly influences dissolution rates as high permeability anisotropy or layering reduces convection efficiency and therefore slows down dissolution [31]. Figure 6 shows a schematic of solubility trapping.

2.4. Residual (Capillary)Trapping

It is one of the most important mechanisms of CO₂ capture, by which CO₂ is immobilized within the rock pore spaces because of large capillary forces. After CO₂ is injected into porous rocks, the CO₂ plume migrates and portions of it may disconnect as droplets and bubbles, which are trapped by surface tension.

Residual trapping occurs when the buoyant force of CO₂ is unable to overcome the capillary entry pressure of the adjacent upper pores within the reservoir rock. This results in the trapping of CO₂ in large concentrations at locations below the caprock. However, there are two basic requirements of residual trapping: (a) It requires the fluid to be the non-wetting phase [32] and (b) the effectiveness of residual trapping is independent of the integrity of the caprock [33]. Figure 7 shows a schematic diagram of residual trapping of CO₂. It is a conceptualized model adapted from Massarweh and Abushaikha [14].

Figure 7 shows residual trapping of CO₂ after it is injected below an impermeable rock layer. Three layers of saturation are shown with the level of CO₂ saturation varying from low to high.

Residual trapping of CO₂ is associated with two fundamental multiphase flow processes, which are as follows: (a) drainage and (b) imbibition. When CO₂ is injected below an impermeable rock layer, it displaces brine from the reservoir rock until the irreducible saturation of brine and the maximum CO₂ saturation is reached. This process is termed as drainage. Irreducible brine saturation may be defined as the minimum brine saturation which cannot be removed from the rock during the process of drainage. When irreducible brine saturation is reached, the process of imbibition starts with brine flowing back into the rock pores until the relative permeability of CO₂ is reduced to zero [34,35,36,37,38].

Relative permeability is defined as the ratio of effective permeability associated with a fluid phase to the absolute permeability of the porous medium, and it is given by Equation (4):

$$k_{r\alpha }={\displaystyle \frac{k_{\alpha }}{k}},$$

(4)

where $k_{r\alpha }$ is relative permeability of phase $\alpha$ in presence of a second fluid, $k_{\alpha }$ is the effective permeability of phase $\alpha$, and $k$ is the absolute permeability of the rock. The process of drainage followed by imbibition facilitates residual trapping of CO₂. However, residual trapping efficiency is a function of the irreducible brine saturation in reservoir rocks. The lower the irreducible brine saturation, the higher the trapped CO₂ saturation. During the processes of drainage and imbibition, brine is termed as the wetting phase while supercritical CO₂ is the non-wetting phase. The relationship between the non-wetting and the wetting phases are governed by Equation (5):

$$S_w+S_{nw}=1,$$

(5)

where $S_w$ is the irreducible brine saturation (wetting phase) and $S_{nw}$ is the maximum CO₂ saturation (non-wetting phase). Several variables influence the effectiveness of residual trapping. These are porosity; absolute permeability of the rock material, which is a function of the rock type; pore geometry; viscosity of CO_2; hysteresis; flow rate; and pore pressure. For example, the increase in porosity is correlated with a decrease in CO₂ residual saturation [39]. Likewise, the residual CO₂ saturation increases with the initial saturation of CO₂ [40]. Another research group reported a decrease in the residual saturation of CO₂ with an increase in porosity [41]. To understand residual trapping performance, it is imperative to assess the relative permeability characteristics of CO₂ and brine during both drainage and imbibition. Many research groups performed core-flooding experiments in the laboratory to evaluate relative permeability. Akbarabadi and Piri performed 30 steady state and unsteady state core-flooding experiments and reported that as much as 83% of the initial CO₂ saturation could be trapped through residual trapping [42]. Ni et al. reported increase in residual saturation of CO₂ with an increase in the degree of heterogeneity and a decrease in porosity [43]. Several researchers suggested that there was no universally accepted relative permeability curves even for similar rock types. However, the endpoint relative permeability during drainage generally varied from 0.3 to 0.7 [44,45,46,47,48]. During the mid-2000s through 2010, Bachu and his research group performed pioneering studies in relative permeability [49,50,51,52]. Several other research groups studied relative permeability characteristics of both non-wetting and wetting phases during drainage and imbibition [53,54,55,56]. While many research groups reported experimental results associated with residual trapping of CO₂, limited studies report numerical analyses [57,58,59,60,61,62].

Economic Implications Associated with Residual Trapping

CO₂ is immobilized after injection during residual trapping. Therefore, residual trapping improves long-term storage security, which is associated with lower risk of leakage liabilities. This also suggests that there is a reduced need for expensive remediation contingency plans. Also, with immobilized CO₂, migration of plume is reduced. This suggests that monitoring areas can be smaller and adequate residual trapping may reduce the need for intensive long-term monitoring programs. With residual trapping acting on smaller timescales, confidence in storage security may be achieved sooner. However, maximizing the efficiency of residual trapping may require higher operational complexity and costs as shown as in

Table 1. Timescales and security potential of CO₂ trapping mechanisms.

Trapping Mechanism	Typical Timescale	Storage Security Over Time
Structural/Stratigraphic	Immediate to years	Dependent on caprock integrity
Residual/Capillary	Years to decades	Increased security as CO2 is immobilized
Solubility	Decades to centuries	Greater security with further immobility of CO2
Mineralization	Centuries to thousands of years	Highest security

.

Figure 8 shows the evolution of four CO₂ trapping mechanisms across pore, core, reservoir, and basin scales at different timescales [14]. The trapping contribution percentage is the highest for structural trapping immediately after stopping injection. Through decades, residual trapping is the dominant mechanism. The contribution from mineral trapping is significant only after a hundred years after injection stops.

3. Recent Advances in CO₂ Trapping Technologies

3.1. Dominance of Trapping Mechanisms at Different Time Scales

Recent studies reveal that CO₂ trapping mechanisms co-exist but shift in dominance at different time scales.

• Injection Phase (days to years): At this stage, the most dominant trapping mechanisms are structural trapping and residual trapping. While structural trapping begins with immediate accumulation of CO₂ beneath caprock due to buoyancy, residual trapping begins concurrently as CO₂ displaces brine and starts building immobile fractions [63].
• Early Post-injection Phase (1–50 years): During this stage, although structural trapping still controls global containment boundaries, residual trapping develops over months to years as soon as injection stops [63].
• Intermediate phase (50–100 years): A recent numerical study suggested that residual or capillary trapping dominates solubility trapping over time. For instance, residual trapping volumes may be twice the solubility trapping volumes after approximately 50 years. However, it is estimated that immediately after the injection phase, solubility trapping may be able to trap more volumes than residual trapping [64]. This suggests that residual trapping is not simply a short-term mechanism. It evolves and strengthens over time and depends on the microstructure and flow-regime. Contradictory to this article, another recent study reported solubility trapping along with mineralization as the most dominant trapping mechanisms during this stage [65].
• Long-term Phase (>100 years–1000 years): Mineralization or mineral trapping is the most dominant trapping mechanism in the long term [66].

3.2. Evidence of Pore-Scale Experimental Observations Translating to Field-Scale

Several research groups through the past decade showed that pore-scale experiments and simulations were continuously being upscaled to improve predictions of field scale plume migration, trapping efficiency and storage capacity.

(a)

Residual Trapping is a Scalable, Dominant Mechanism: Pore-scale imaging such as micro-CT has revealed that CO₂ becomes immobilized as disconnected ganglia due to capillary forces. These observations are consistently observed from pore to field scale [32]. Residually trapped CO₂ in the form of droplets, ganglia, and connected networks strongly affect flow behavior and trapping efficiency. With increase in pressure, there is more droplet formation, and it improves residual saturation. However, with increase in temperature, droplet formation increases but residual saturation decreases. Therefore, in addition to the amount of CO₂, the morphology and topology of CO₂ govern residual trapping efficiency [67].

(b)

Pore-scale Flow Regimes Predict Plume Migration Patterns: Viscous fingering, snap off, and heterogeneity govern trapping efficiency. At low capillary numbers, viscous fingering produces preferential flow paths and limits the efficiency of sweeping. Also, snap-off in small pore throats enhances residual trapping [68].

(c)

Mapping of Pore Variables to Storage Efficiency: Recently published research articles reported the importance of variables such as wettability, capillary pressure, heterogeneity, and salinity towards improving model reliability and accurate assessment of storage efficiency. The following is some evidence that has been provided:

• Wettability: Recent experiments in limestone show that residual trapping drops as rocks become CO₂ wet. Rocks wetted by CO₂ provide continuous wetting layers offering flow pathways, thus preventing residual trapping. Results showed that while water-wet rocks enabled more than 20% residual saturation, CO₂-wet rocks were associated with 8% saturation only [69].
• Capillary Hysteresis: Increasing capillary hysteresis can enhance trapping [70,71]. Injection technologies such as water-alternating gas (WAG) or controlled imbibition cycles are now recognized as key methods towards maximizing residual trapping.
• Heterogeneity: Heterogeneity creates spatially variable trapping. For instance, clasts and permeability contrasts may result in localized CO₂ trapping zones [72]. Therefore, heterogeneous pore networks may lead to higher trapped saturations due to snap off and fragmentation [73].
• Gravity: Another recent article reported that downward (gravity-assisted) imbibition resulted in more fragmentation and therefore, higher residual trapping [74].
• Salinity: Higher salinity increases interfacial tension and therefore may improve residual trapping [68]. In addition, the transition from capillary flow regime to viscous flow regime may reduce fragmentation and result in lower residual trapping [73].

(d)

Interdependence of Residual and Solubility Trapping Mechanisms

A 2025 study of capillary-trapped CO₂ dissolution shows that dissolution is non-linear and convection-driven, and it accelerates over 10–1000 years. Therefore, solubility trapping is strongly coupled with residual trapping, with trapped CO₂ dissolving faster, making the two mechanisms interdependent [30].

(e)

Strategies for Accelerating Mineralization

Recent studies in mineralization suggest that it is an increasingly engineerable process. For example, several strategies towards accelerating mineralization have been identified such as co-injecting brine along with CO₂, using reactive minerals and microbes, and increasing mineral surface area. In addition, mineral composition such as Ca²⁺, Mg²⁺, and silicates strongly affect carbonate precipitation and therefore long-term storage stability [75].

(f)

Factors Affecting Structural Trapping

A recent modeling study showed that long-distance migration can improve structural trapping of CO₂ [76]. Structural trapping is also dependent on the caprock composition. Multi-layer caprocks that are composed of shale and mudstone may further improve the sealing capacity. Also, the proximity to a fault or the caprock thickness are important parameters governing the trapping capacity [77].

4. Influence of Uncertainty in Pore Variables on Model Reliability

As CO₂ is less dense than brine, it rises due to buoyancy. Reservoir heterogeneity may cause irregular plume spreading and an imbalance between lateral and vertical migration. Therefore, it will be hard to predict plume footprint and extent. This, in turn, will lead to increased uncertainty in evaluation of storage capacity and containment. Heterogeneity also impacts fluid contact area and sweep efficiency and this will lead to uncertainty in the estimation of residual and solubility trapping efficiency. It also suggests that models assuming homogeneity and using Darcy equation without the spatial variation in permeability may need to be revised. Therefore, heterogeneity leads to variation in permeability within the reservoir rock.

Similarly, uncertainty in wettability may impact residual trapping capacity through inaccurate evaluation of the relative permeability curves.

Likewise, capillary pressure governs CO₂ entry into pores. So, uncertainty in capillary pressure impacts the ability to evaluate the thickness of CO₂ plume and subsequently, the assessment of residual trapping.

The uncertainty in salinity may interfere with the ability to evaluate interfacial tension and therefore influences assessment of residual trapping. Similarly, uncertainty also impacts dissolution rates and solubility trapping.

With temperature being responsible for changes in CO₂ density and viscosity, uncertainties associated impact the evaluation of buoyant forces, migration speeds and geochemical reactions. As thermal gradients affect plume stability, these uncertainties may also increase leakage risks. Also, if CO₂ reaches the storage formation at a temperature lower than the reservoir temperature at high flowrates, the thermo-mechanical effects may jeopardize caprock integrity and cause induced seismicity. Uncertainties in caprock integrity leads to long-term leakage risks [78].

5. Technology Readiness Levels of CO₂ Trapping Mechanisms

Technology Readiness Levels (TRLs) are used to measure the maturity of the technology from concept to full operation. TRL 1–3 suggests that a technology is at its earliest phase of innovation covering basic scientific research and proof-of-concept. At TRL 4–6, validation and pilot testing stages are completed and at TRL 7–9, the technology has been deployed on field and is in operation [79]. This scale is widely used by NASA, U.S. Department of Energy, and the EU to track technology development.

The CO₂ trapping mechanisms have been rated using the following scale:

(a)

Observability (2 points): If direct measurement technologies are available, then the mechanism receives more TRL points. Likewise, inferred behaviors receive less points.

(b)

Scale Validation (2 points): If a mechanism is restricted to pore or core scales only, they receive less points. Reservoir or basic scale demonstrations are assigned more points.

(c)

Predictive Capabilities (2 points): If the outcomes through a trapping mechanism can be reliably forecasted, then it receives more points, while a higher degree of uncertainty results in less points.

(d)

Deployment Reliance (3 points): If a mechanism is being actively used in the field, then it receives maximum points using this criterion. If the mechanism can be reliably tested only in the long term, then it receives less points.

Based on the scoring criteria mentioned above, the CO₂ trapping mechanisms are assigned to the TRLs as shown in

Table 2. TRL of CO₂ trapping mechanisms.

Trapping Mechanism	TRL
Structural/Stratigraphic	8–9
Residual/Capillary	6–8
Solubility	6–7
Mineralization	3–6

.

Structural trapping relies on the reservoir geometry and caprock seals, which operate on the same principle as natural gas storage. This technology has been fully operational since the 1970s in saline aquifers, depleted oil and gas fields, and CO₂-EOR projects [80]. This technology has also been deployed at the commercial level. Therefore, this technology is at a TRL of 8–9.

Residual trapping offers passive stabilization, and it is independent of caprock integrity. However, residual trapping is hard to measure in field. Also, recent studies showed that residual trapping is strongly dependent on reservoir heterogeneity [81]. There is a need to conduct more research to understand the dependence of CO₂ saturation on variables such as rock porosity, permeability, pore geometry, brine salinity, injection pressure, and temperature. There is a requirement for improved pore-scale imaging and development of more robust models. Therefore, residual trapping technology is at a TRL of 6–8.

Solubility trapping functions through reducing buoyancy. However, the process is slow, and it is governed by diffusion and convective mixing [82]. Important areas of current research are associated with enhancing convective mixing and using coupled thermal–hydrodynamic modeling. Therefore, solubility trapping technology is at a TRL of 6–7.

Although mineral trapping or mineralization offers the most permanent form of trapping and CO₂ storage, the process is extremely slow [83]. The process is also strongly dependent on rock geochemistry. Also, mineral trapping works the best in reactive formations such as Basalts, Ultramafic rocks, etc. Unfortunately, most existing CO₂ storage projects use sedimentary basins such as sandstones and saline aquifers where mineralization is much slower. The lower TRL can be attributed to the long reaction timescales, limited number of globally suitable sites, and a lack of standard, widely applicable deployment model.

6. Environmental Implications

CO₂ sequestration is widely accepted as an important climate mitigation strategy. However, there are several environmental concerns associated with this technology, which are as follows:

• CO₂ Leakage Risks: One of the most important environmental concerns is the possibility of CO₂ leakage back into the atmosphere owing to caprock failure, or through potential leakage pathways such as faults and fractures.
• Groundwater Contamination: Groundwater quality can be impacted by the leakage of brine or CO₂ into groundwater resources [84,85,86,87]. Researchers established that CO₂ infiltrating an unconfined freshwater aquifer at atmospheric pressure and under oxidizing conditions can lower pH and increase the concentration of dissolved solids such as Al, Mn, Fe, Zn, Cd, Se, Ba, and U [88]. Therefore, the leakage of CO₂ or brine can compromise the quality of potable water resources, rendering them unsuitable for human consumption.
• Induced Seismicity: Injection of large volumes of CO₂ can change pore pressure, which may cause deformation or fracture. In addition, this may also reactivate faults and induce seismicity [89,90,91]. Although induced seismicity is a serious concern, researchers conclude that careful project design and meticulous site selection is the key to mitigating the risks [92].
• Brine Displacement: CO₂ injection at large pressure gradients can cause brine to move upwards and infiltrate into freshwater aquifers. This can cause high salt concentrations or increase the concentration of toxic elements in water. Therefore, intrusion of brine in underground drinking water sources is a major risk [93].

7. Conclusions

In summary, the long-term effectiveness of geological CO₂ storage relies on the synergistic interplay of multiple trapping mechanisms operating across spatial and temporal scales. Structural and stratigraphic trapping provide immediate containment following injection, while residual trapping immobilizes CO₂ through capillary forces at the pore scale. The importance of injection technologies such as water alternating gas (WAG) has been proposed as one of the methods to improve trapping efficiency.

Over longer timescales, solubility trapping enhances storage security by dissolving CO₂ into formation fluids, thereby reducing its buoyancy and migration potential.

However, contrary to the established belief, a recent study reported dominance of the residual trapping mechanism over solubility trapping within a period of 50 years after injection stops. On the other hand, a second article suggested solubility trapping as the dominant trapping mechanism over the same period. Therefore, more research is needed to understand how the mechanisms of residual trapping and solubility trapping evolved over decades and centuries.

Ultimately, mineral trapping offers the most permanent form of sequestration through geochemical reactions that convert CO₂ into stable carbonate phases. A comprehensive understanding of these mechanisms, their relative contributions, and their evolution under site-specific conditions is essential for accurate prediction of storage performance and risk. Future research integrating advanced monitoring, modeling, and laboratory studies will be critical to reducing uncertainties and optimizing CO₂ storage strategies for safe and scalable climate mitigation. Finally, even though mineralization promises near perfect CO₂ trapping, it is assigned to the lowest TRL among all trapping mechanisms. Future research in the direction of speeding up the process of mineralization may be extremely useful.