Typical Case Studies and Classification with Evaluation of Carbon Dioxide Geological Sequestration in Saline Aquifers

Abstract

To achieve carbon neutrality in China’s fossil energy sector, saline aquifer CO₂ geological storage has become a critical strategy. As research into carbon reduction and storage potential evaluation advances across various geological scales, the need arises for consolidating key CO₂ storage cases and establishing a standardized classification system and evaluation methodology. This paper provides a comprehensive review of notable CO₂ storage projects in saline aquifers, covering aspects such as project overviews, structural and reservoir characteristics, caprock integrity, and seismic monitoring protocols. Drawing on insights from mineral and oil and gas exploration, as well as international methods, this paper outlines the stages and potential levels of saline aquifer storage in China. It proposes an evaluation framework with formulas and reference values for key coefficients. The study includes successful global projects, such as Sleipner and Snøhvit in Norway, In Salah in Algeria, and Shenhua in China’s Ordos Basin, which provide valuable insights for long-term carbon capture and storage (CCS). By examining geological characteristics, injection, and monitoring protocols in these projects, this paper analyzes how geological features impact CO₂ storage outcomes. For example, the Sleipner project’s success is linked to its straightforward structure, favorable reservoir properties, and stable caprock, while Snøhvit illustrates diverse structural suitability, and In Salah demonstrates the influence of fractures on storage efficacy. CO₂ storage activities are segmented into four stages—survey, investigation, exploration, and injection—and are further categorized by storage potential: geological, technical, techno-economic, and engineering capacities. This study also presents evaluation levels (prediction, control, technically recoverable, and engineering) that support effective reservoir selection, potential classification, and calculations considering factors like reservoir stability and sealing efficacy. Depending on application needs, volumetric or mechanistic methods are recommended, with precise determination of geological, displacement, and cost coefficients. For China, a dynamic evaluation mechanism characterized by multi-scale, tiered approaches and increasing precision over time is essential for robust storage potential assessment. The levels and methods outlined here serve as a scientific foundation for regional and stage-based comparisons, guiding engineering approvals and underground space management. To align with practical engineering demands, ongoing innovation through laboratory experiments, simulations, and field practice is crucial, supporting continual refinement of formulas and key parameter determinations.

1. Introduction

Saline aquifer CO₂ geological sequestration is a critical element of carbon capture and storage (CCS) technology. This process involves injecting CO₂ captured from large industrial emission sources into deep saline aquifers, depleted oil and gas reservoirs, and other suitable geological formations, effectively isolating CO₂ from the atmosphere over the long term (Figure 1) [1]. As a fundamental geological solution supporting carbon peaking and neutrality goals, deep saline aquifer CO₂ geological sequestration is considered an indispensable and reliable technology for achieving carbon neutrality in the fossil fuel sector. Therefore, conducting scientifically robust and practically applicable evaluations of sequestration potential is of paramount importance [2,3].

Globally, the Sleipner and Snøhvit projects in Norway, along with In Salah in Algeria, are among the most well-known saline aquifer CO₂ geological sequestration initiatives. These projects have been operational for an extended period, demonstrating large-scale operations, substantial storage capacities, and proven commercial viability. In China, the Shenhua saline aquifer sequestration project in the Ordos Basin stands as a significant demonstration effort. Numerous studies have been conducted on the classification and evaluation of China’s saline aquifer sequestration potential, focusing primarily on macro or basin-scale regional assessments [4,5,6]. Some researchers have also used the Monte Carlo method to simulate a range of outcomes under varying geological conditions. This approach provides possible insights for optimizing sequestration efforts, ensuring effective risk management, and enhancing strategic planning for CO₂ storage both globally and within China’s unique geological contexts.

The Carbon Sequestration Leadership Forum classifies CO₂ geological sequestration potential into four levels, theoretical storage capacity, effective storage capacity, actual storage capacity, and matched storage capacity, supported by a calculation formula based on the mechanistic method theory [7]. Similarly, the US Department of Energy categorizes CO₂ geological sequestration potential into prospective storage volume, estimated storage volume, and actual storage volume, with a potential calculation formula derived from the volumetric method theory.

Given the complex geological background of China’s sedimentary basins and the current state of CO₂ geological sequestration research, Chinese scholars have divided the country’s CO₂ geological sequestration potential into predicted capacity (E-level), estimated capacity (D-level), controlled capacity (C-level), base storage capacity (B-level), and engineering storage capacity (A-level). This culminates in a nationwide assessment of saline aquifer sequestration potential in major sedimentary basins [8].

In the context of carbon peak and neutrality goals, as energy and chemical companies ramp up activities in carbon capture, saline aquifer sequestration planning, and demonstration experiments, the need for sequestration potential evaluation research at various geological scales is becoming increasingly urgent [9,10,11,12]. Consequently, there is a pressing need to establish unified potential levels or standards and to select scientific evaluation methods that can guide the identification and development of large-scale sequestration sites [13].

This paper, based on a comparative analysis of the geological characteristics of these cases, defines the stages of saline aquifer CO₂ geological sequestration, categorizes potential levels, and offers recommendations for applying volumetric methods, mechanistic method calculation formulas, and numerical simulation techniques [14,15]. These efforts are aimed at supporting the future large-scale planning and execution of major demonstration projects for saline aquifer CO₂ geological sequestration in China.

2. Representative Cases of CO₂ Geological Storage in Saline Aquifers

2.1. Project Overview

Sleipner, In Salah, and Snøhvit are among the longest-running and most successful cases in the field of offshore saline aquifer carbon capture and storage (Figure 2) [16]. The Sleipner CCS project, located in the Norwegian North Sea, is the world’s first CO₂ saline aquifer storage project, boasting the longest operational period and substantial storage capacity. Since its inception in 1996, it has become a pivotal case study for CO₂ storage, as CO₂ is injected into deep-sea saline aquifers.

The In Salah CCS project in Algeria is part of a natural gas field development initiative that includes a CO₂ capture and storage demonstration project [17,18]. Situated in the Sahara Desert at an elevation of approximately 470 m, the In Salah project injects captured CO₂ into a deep saline aquifer at a depth of 1900 m. Between 2004 and 2011, the project achieved an injection volume of approximately 38,000 t.

The Snøhvit field, an offshore oil field, features a CO₂ injection site at a water depth of around 330 m. In this field, CO₂ separated from methane, which contains 5–8% CO₂, is re-injected, with a planned injection volume of approximately 23 million tons over 30 years [4,19,20].

The Shenhua CCS project in China is a deep saline aquifer CO₂ geological storage project situated in a continental sedimentary formation spanning 11,200 square meters. Since the start of injections in 2011, the project has operated without any leakage incidents, marking a significant achievement in CO₂ storage [21].

2.2. Characteristics of Geological Structure

Sleipner is located in the Norwegian offshore area and is part of a large dome structure characterized by the absence of significant fault development. The reservoir is composed of Utsira sandstone, situated 800–1000 m below sea level, with a gentle southward dip and a smooth top structure featuring slight local undulations [22]. The Sleipner region contains two main sedimentary centers, with thicknesses reaching up to 300 m in the south and nearly 200 m in the north. The Utsira sand body in this area forms an unconformity surface at depths of 900 to 1100 m, primarily due to localized activity within the underlying shale.

The In Salah reservoir belongs to the Krechba formation, which takes the shape of a gentle anticline formed during the compressional tectonic phase in the Late Carboniferous [23]. Compression in this phase caused deformation in the reservoir, leading to a series of folds. Continuous compression resulted in some folds being disrupted by strike-slip faults. The Krechba formation is approximately 20 m thick, with subtle faults near the seismic resolution limit. Uplift in the region has led to the formation of fractures, adding complexity to the structural modeling [24,25,26].

Snøhvit is situated within the central-eastern block system of the Hammerfest Basin, which spans 150 km in length and 70 km in width. The basin’s rifting began in the Late Carboniferous to Early Permian, leading to the formation of NE–SE trending boundary faults. A second phase of rifting from the Late Jurassic to Early Cretaceous reactivated these boundary faults, causing significant subsidence. The Hammerfest Basin broadens and deepens toward the west, with sediment thickness increasing in that direction. Some areas feature strike-slip faults with displacements of up to 200 m [27,28,29]. The basin has undergone multiple uplift events, resulting in maximum burial depths and higher temperatures.

The Shenhua CCS project is located in China’s Ordos Basin, characterized by a gentle monocline structure with minor local uplifts caused by differential compaction. Faults are not well-developed in this area, and the structural influence is relatively weak. Generally, anticline and monocline structures are most favorable for CO₂ geological storage, with ideal sites being free of faults [30,31,32]. However, the cases of In Salah and Snøhvit suggest that blocks and fractures can also be suitable as long as the faults possess good sealing properties, controllable geostress, and sufficient caprock thickness. In such instances, block structures can also serve as viable storage sites.

2.3. Reservoir Characteristics

Carbonate rocks possess a unique chemical reactivity that allows them to interact with injected carbon dioxide, forming stable carbonate minerals. This mineralization process effectively locks CO₂ in a solid state, ensuring its long-term confinement and preventing leakage, thus enhancing the safety and stability of the storage. In natural conditions, the reaction with carbonic acid can form dissolution cavities and fractures in carbonate rocks, potentially enhancing their storage capacity and ability for large-scale sequestration. On the other hand, sandstone generally has greater porosity and permeability, allowing it to better effectively accommodate and transport injected carbon dioxide, making it well-suited for large-scale sequestration initiatives. The uniformity in sandstone’s composition and structure simplifies the prediction and modeling of reservoir properties, improving the controllability and efficiency of the sequestration process. Moreover, the relatively simple and predictable pore structure of sandstone aids in geological modeling and reservoir simulation, making it one of the ideal choices for CO₂ geological storage.

In the Sleipner area, the Utsira sandstone reservoir lies at a depth of 800 to 1000 m below sea level. Core analysis reveals that the reservoir is primarily composed of quartz and feldspar, with abundant bioclasts and chlorite, which are indicative of typical marine sedimentary characteristics (Figure 3). Well log data further show that the Utsira sandstone exhibits low gamma ray responses and features interbedded clay layers separating thick sandstone units, suggesting a predominantly marine turbidite deposition. This stable, large-scale sand body deposition provides highly favorable conditions for high-quality CO₂ geological storage [17].

Based on core and sediment analysis, the Utsira sandstone is predominantly composed of unconsolidated fine-grained sand, with medium and a minor proportion of coarse-grained sand. Microscopic analysis indicates porosity typically ranges from 27% to 31%, with some areas reaching up to 42%. Core experiments confirm this, showing measured porosity values between 35% and 42.5% [33,34,35,36]. The reservoir has a thickness of 200 to 300 m, stretches over 400 km in the north–south direction, and has a width of 50 to 100 km in the east–west direction. The average porosity of this high-quality reservoir can reach 36%, and its permeability ranges from 1 to 8 millidarcies, indicating excellent reservoir properties (Figure 4).

In contrast, the Tournaisian sandstone reservoir at the In Salah injection site, a tidal deltaic deposit, is primarily composed of quartz. Diagenesis processes include mineral cementation with chlorite and siderite, followed by the dissolution of detrital clay, chlorite, and pyrite [37,38,39,40]. This reservoir is buried at a depth of 1880 m, with a relatively dense lithology and a porosity of only 17%. The permeability ranges from 10 to 100 millidarcies. Although the matrix permeability is low, the fractures developed within the reservoir provide essential pathways for CO₂ injection [41,42,43].

The Snøhvit reservoir, located in the Upper Triassic to Middle Jurassic formations, primarily consists of thinly interbedded sandstone and shale. Influenced by deltaic and fluvial depositional environments, this area exhibits significant facies variations, with intercalations of siltstone and mudstone. The thickness of the saline water zone is approximately 45 to 75 m, with a burial depth of 2600 m. The reservoir’s sandstone component has a porosity ranging from 10% to 15% and a permeability between 185 and 883 millidarcies [44,45,46,47]. The reservoir conditions include a pressure of 28.5 megapascals and a temperature of 98 degrees Celsius, with high salinity levels of 160 g per liter. Fractures in the Snøhvit reservoir, likely associated with Late Cenozoic uplift, exhibit permeability exceeding 500 millidarcies.

In summary, the Utsira sandstone reservoir in the Sleipner area is particularly favorable due to its shallow burial depth (approximately 800 m), high porosity, and permeability, making it an excellent candidate for CO₂ geological storage. In contrast, the reservoirs in the In Salah and Snøhvit areas, while deeper and with relatively dense lithology, are slightly less favorable in terms of reservoir properties compared to Sleipner. However, the fractures developed within these reservoirs offer advantages for CO₂ injection and storage [48,49,50].

2.4. Caprock Characteristics

Permeability and hydraulic conductivity are both critical factors in CO₂ geological storage, as they jointly affect injectivity, distribution, and long-term containment. Permeability allows CO₂ to be injected and flow through the reservoir, influencing storage volume and enhancing trapping mechanisms for secure containment. Hydraulic conductivity, which measures the ability of fluid to move through the reservoir under a hydraulic gradient, is equally essential. It provides a realistic assessment of how CO₂ will migrate through subsurface water-saturated formations, affecting both the speed and distribution of CO₂ within the aquifer. High hydraulic conductivity, alongside adequate permeability, ensures efficient injection and dispersal of CO₂ while helping to maintain stable pressure within the reservoir. However, for effective containment, the caprock must maintain low hydraulic conductivity and low permeability to prevent CO₂ leakage. The balance of permeability and hydraulic conductivity between the reservoir and caprock is thus crucial for the safe and effective long-term storage of CO₂ [51,52]. The top cap layer of the Utsira sand unit in Sleipner can be categorized into three primary units: the lower seal, middle seal, and upper seal. The lower seal is a shale basin limit unit with a thickness of approximately 50–100 m. The middle seal is a sediment wedge composed of Upper Jurassic shale, which is richer in the center of the basin and thickens upwards and towards the basin margin. The upper seal mainly consists of Quaternary glacial-marine clay sediments. In the Sleipner area, the lower seal of the Nordland Group comprises clay sediments with a thickness of around 250 m. This cap layer extends over 50 km to the west and more than 40 km to the east of the injection zone, serving as the primary cap layer [18].

Caprock samples from Sleipner are characterized by gray clay silt or silt clay, which is unconsolidated with poorly developed bedding. The composition is predominantly illite, with smaller amounts of kaolinite, chlorite, and montmorillonite. In comparison, the caprocks in In Salah and Snøhvit are thicker and more resistant than those in Sleipner. Most structures in the Barents Sea are covered by Upper Jurassic shales and thick layers of Cretaceous shales, which function as the sealing or capping rocks in the region. These rocks are primarily composed of sandstones interbedded with thin shale layers.

In the Shenhua demonstration project, CO₂ injection is carried out in various reservoirs. The upper parts of the Liujiagou Formation and the Heshanggou Formation, mainly composed of mudstone and sandy mudstone, act as effective caprocks. The bottom of the Benxi Formation consists of residual aluminum-rich shale, while the middle parts of the Shihetazi Formation and the Shiqianfeng Formation contain thick deposits of mudstone and sandy mudstone [53,54].

In general, a thicker caprock is more favorable for CO₂ geological sequestration. Among these four typical cases, the caprock thickness is generally greater than 100 m, primarily composed of mudstone, sandy mudstone, and marine shale, with permeability mostly within the range of 1 × 10⁻²⁰ m² (Figure 5).

2.5. Earthquake Monitoring Program

Earthquake monitoring plays a crucial role in the success of CO₂ geological storage projects [55,56,57]. Through this process, the distribution and dynamic behavior of CO₂ plumes can be accurately tracked, as illustrated in Figure 6. The monitoring data reveal that CO₂ plumes rise vertically over 200 m from the injection point, passing through thin shale interlayers and forming nine vertically stacked accumulations. Each accumulation is approximately 7 to 20 m thick and extends laterally for several hundred m. Earthquake monitoring efficiently captures these CO₂ plumes and can also detect potential leaks above the Utsira sandstone. However, current techniques are unable to accurately measure the amount of dissolved CO₂ in water.

In regions such as In Salah and Snøhvit, various monitoring techniques have been employed, including time-lapse seismic surveys, microseismic monitoring, CO₂ gas tracers for wellhead sampling, downhole logging, core analysis, surface gas monitoring, groundwater monitoring, and satellite-based InSAR data [58,59,60]. These methods, which include 3D seismic surveys, synthetic aperture radar, and satellite monitoring, are conducted with intervals ranging from 30 to 8 days. These technologies can detect surface uplift above injection wells with a magnitude of 1 to 2 cm. Although time-lapse seismic surveys have their limitations, variations in amplitude are linked to pressure changes. In the Snøhvit region, multiple 4D seismic surveys have been carried out to monitor CO₂ distribution and pressure fluctuations in the reservoir. Pressure and temperature measurements, taken 800 m above the reservoir with remote monitoring capability, are critical. The combination of 4D seismic survey data indicates CO₂ presence in NW–SE trending channels, where amplitude variations are more related to reservoir heterogeneity than pressure changes [61,62,63].

In the Shenhua CO₂ geological storage project, monitoring also includes atmospheric CO₂ concentration, surface soil, and radar deformation, as well as subsurface monitoring methods such as VSP seismic surveys, groundwater quality assessments, temperature and pressure readings, and in situ soil CO₂ flux measurements. Continuous monitoring in this project has not detected any CO₂ leakage or raised environmental concerns.

Experience from oil and gas production shows that effective reservoir characterization and monitoring techniques can significantly improve recovery rates. A detailed CO₂ reservoir monitoring plan is essential for accurately describing the reservoir characteristics and CO₂ plume distribution, thereby enhancing injection efficiency and storage capacity. Gravity and seismic monitoring provide valuable insights into CO₂ mass changes and its dissolution in formation water. Repeated seismic surveys are crucial for verifying the integrity of the reservoir seal and ensuring consistent monitoring. On-site measurements of downhole pressure and temperature are indispensable for controlling injection and making reliable long-term predictions [64,65,66].

3. Capacity Classification and Grading

3.1. Classification of CO₂ Geological Storage Capacity

According to the economic-technical attributes, the potential of CO₂ geological storage is divided into four categories: theoretical storage capacity, effective storage capacity, actual storage capacity, and matched storage capacity (Figure 7). This model provides a theoretical basis for the assessment of CO₂ geological storage potential. Based on the assessment purposes and understanding of the storage geological formations, the CO₂ geological storage potential is classified into four levels. As the level increases, the certainty of the storage capacity gradually increases, and the demand for storage cost decreases [67,68,69]. The theoretical storage capacity refers to the maximum theoretical amount of CO₂ that can be stored in the geological formation, representing the physical space limit of CO₂ that can be provided by the storage geological formation. The effective storage capacity is a subset of the theoretical storage capacity, considering the impact of geological and engineering conditions on the storage capacity. The actual storage capacity is a subset of the effective storage capacity, further considering the impact of technology, legal, infrastructure, and economic conditions on the storage potential. The matched storage capacity is a subset of the actual storage capacity, obtained through detailed matching of CO₂ emission sources and storage sites [19].

3.2. Exploration Injection Phase

The exploration and injection of CO₂ geological storage in saline aquifers can be divided into four stages: reconnaissance, detailed investigation, exploration, and injection. The reconnaissance stage is a preliminary investigation conducted on specific sedimentary basins or geological structural units, using methods such as seismic surveys to initially determine prospective storage areas and study the reservoir and caprock with an accuracy of 1:100,000 to 1:250,000. During this stage, the regional structural morphology, distribution of saline aquifers and caprocks, and potential geological storage layers and lithology can be preliminarily understood. Information about the exploration and development of important energy and mineral resources can also be obtained. The detailed investigation stage involves more detailed exploration work within favorable storage areas and includes detailed geophysical surveys with an accuracy of 1:25,000 to 1:50,000 [70,71,72]. At this stage, further research can be conducted on reservoir types, reservoir properties, reservoir thickness, and heterogeneity. For fractured-porous reservoirs, preliminary understanding of fracture systems, identification of injection layers, determination of reservoir fluid properties, temperature, pressure systems, caprock properties, thickness, sealing capacity, and dissolution risk can be obtained. Simultaneously, continued understanding of the exploration and development of important energy and mineral resources is necessary to ensure the rational allocation of storage and resource development. The exploration stage involves further exploration work within favorable storage targets, including two-dimensional or three-dimensional seismic surveys, and evaluation well drilling under conditions of corrosion and leakage prevention. At this stage, the morphology of structures and the distribution of major faults can be further studied, and the accuracy of reservoir and caprock studies can reach 1:5000 to 1:10,000. In fractured-porous reservoirs, a deeper understanding of fracture systems, identification of injection layers, and detailed investigation of reservoir fluid properties, temperature, pressure systems, caprock properties, thickness, sealing capacity, and dissolution risk can be achieved. Furthermore, acquiring knowledge of the exploration and development of crucial energy and mineral resources is essential to ensure the rational allocation of CO₂ geological storage and resource development. The injection stage takes place within the designated storage site. After formulating site evaluation and injection plans, corresponding monitoring and emergency response plans should be developed, and additional monitoring well drilling should be conducted [73,74,75]. CO₂ injection is then implemented, and the injection effect is evaluated to assess the corresponding level of storage potential. Through the stages and corresponding exploration and injection works mentioned above, comprehensive assessment and management of CO₂ geological storage projects in saline aquifers can be achieved.

3.3. Classification and Grading of Potential

Based on the geological, technical, economic, and engineering conditions for CO₂ geological storage in saline aquifers, the storage potential can be classified into four categories: geological potential, technical capacity, technical-economic capacity, and engineering storage volume. The reconnaissance stage corresponds to the presumed level (D-level), the detailed investigation stage aligns with the controlled level (C-level), the exploration stage matches the basic level (B-level), and the injection stage is associated with the engineered level (A-level) (Figure 8).

Geological potential refers to the static theoretical storage capacity of reservoirs, without considering technological, economic, or other factors. It is divided into three levels: predicted geological potential, controlled geological potential, and proven geological potential. Technical capacity represents the effective storage capacity, controlled by factors such as injection plans and technological advancements. It also includes three levels: predicted technical capacity, controlled technical capacity, and proven technical capacity. Technical-economic capacity denotes the storage capacity that enterprises can manage within acceptable cost ranges, taking into account CO₂ transport and storage costs, as well as policy-driven incentives, under the condition of source-sink matching. It is categorized into two levels: controlled technical-economic capacity and proven technical-economic capacity. Engineering storage volume refers to the storage capacity of specific projects, encompassing both the design storage volume and the actual storage volume achieved during implementation.

4. Evaluation and Exploration of Storage Potential

4.1. Overall Approach

The process of potential evaluation involves three key steps: reservoir screening, potential grading, and potential calculation, all conducted sequentially. Firstly, reservoir screening is carried out to determine the effective range of reservoirs by considering factors such as reservoir conditions, caprock integrity, the stability of the storage formation, and the impact of deep resource development. This step ensures that only the most suitable reservoirs are selected for further analysis. Next, potential grading is performed to classify the storage potential by determining the desired levels of potential to be evaluated, based on the stages of saline aquifer research or specific research objectives. This grading helps to organize the reservoirs according to their suitability and capacity at various levels of accuracy. Finally, potential calculation is executed using scientifically validated formulas and parameters that are aligned with the geological understanding or the specific requirements of the exploration or injection stages. Lower accuracy potential zones may include higher accuracy zones, and vice versa. However, once high-accuracy potential data are obtained, recalculating the lower accuracy levels is unnecessary. The steps of reservoir screening, potential grading, and potential calculation should be followed in sequence, with the specific potential levels determined based on the project’s or research’s specific requirements.

4.2. Reservoir Screening

4.2.1. Reservoir Conditions

Given that CO₂ must reach a supercritical state, the reservoir depth is generally required to exceed 800 m [20]. Additionally, actual formation pressure and temperature measurements obtained through drilling are essential to ensure that CO₂ can reach a supercritical state during injection. When selecting reservoir types, consideration can be given to clastic rocks, carbonate rocks, and special rock types such as igneous rocks. Effective reservoir data can be statistically analyzed by examining groups, sections, or specific sandstone layers. Individual reservoir layers should generally have a thickness of no less than 1 m, with a cumulative thickness of at least 5 m. The average porosity should not be less than 5%, and the average permeability should not be less than 1 × 10⁻³ μm².

Moreover, the reservoir should be a semi-sealed or fully sealed hydrogeological structure, characterized by slow or extremely slow groundwater movement, which reduces the risk of CO₂ leakage. Regarding caprock integrity, the primary types include low-permeability gypsum, mudstone, siltstone, and other rock layers. These caprock layers should be continuous and stable regional formations without pervasive tensile fractures, ensuring they can effectively contain the CO₂ plume.

4.2.2. Stability Conditions of the Storage Formation

The risk of induced seismicity or seismic damage in large-scale CO₂ geological storage within saline aquifers is a critical consideration [25,26,27,28,29]. Therefore, it is essential to assess the impact of active faults on CO₂ geological storage, which must be considered during various exploration and injection stages. In the exploration phase, especially when selecting onshore reservoirs, seismic tectonic classification principles should be referenced. Specifically, the requirements include ensuring that within a 25 km radius from the vertical projection of the reservoir on the surface, there are no primary fault zones (i.e., fault zones involving boundaries of first- and second-level blocks). Additionally, within a 5 km radius, there should be no tertiary faults (i.e., smaller-scale active faults within first- and second-level blocks, as well as certain-scale Quaternary faults). The regional peak ground acceleration due to seismic activity should also be less than or equal to 0.15g. When predicting geological potential and assessing technical capacity, the selection of reservoirs may disregard factors influenced by deep mineral resource development. However, during more advanced potential assessments, it is crucial to consider that CO₂ underground plumes at depths below 800 m could overlap with mineral resources and may also be affected by the development of overlying resources, including oil, natural gas, shale gas, coal, groundwater, and brine resources. Therefore, a comprehensive risk analysis is necessary to select suitable reservoirs.

4.2.3. Impact of Deep Resource Development

When evaluating geological potential and predicting technical capacity on a macro scale, the influence of deep mineral resource development can generally be disregarded in reservoir selection. However, in more detailed potential assessments, it becomes necessary to consider the possibility of CO₂ plumes below 800 m overlapping with mineral resources and the impact of overlying resource development, particularly concerning oil, natural gas, shale gas, coal, groundwater, and brine resources. Conducting a thorough risk analysis ensures the selection of suitable reservoirs, helping to minimize redundancy.

5. Formula for Calculating Storage Potential/Capacity

5.1. Geological Potential

5.1.1. Volumetric Method

The U.S. Department of Energy has developed a calculation method for CO₂ geological storage in saline aquifers based on the volumetric method theory [4]. This method is used to define the boundary conditions of the saline aquifer. It assumes that the reservoir functions as an open boundary system, where CO₂ injection displaces groundwater within the evaluation unit into the surrounding hydrogeological units. This process occurs without causing a significant increase in fluid pressure within the boundary formations, thus enabling effective CO₂ geological storage. This calculation formula is applicable for predicting geological potential, controlled geological potential, and contingent geological potential.

$$P_{\mathrm{geol}}=A\cdot h\cdot \varphi \cdot {\rho }_{{\mathrm{CO}}_2}\cdot E_{\mathrm{geol}}$$

(1)

where P_geol represents geological potential in kg; A represents reservoir area in m²; h represents reservoir thickness in m; ϕ represents reservoir porosity in percentage; ρ_CO2 represents density of CO₂ in the layer in kg/m³; E_geol represents geological factor, which is dimensionless.

5.1.2. Mechanism

The Carbon Sequestration Leadership Forum (CSLF) classifies CO₂ geological storage mechanisms into two main categories: physical and chemical storage mechanisms. Physical storage mechanisms include structural trapping, capillary trapping, and hydrodynamic trapping, while chemical storage mechanisms encompass dissolution trapping and mineralization trapping (Figure 9). The CSLF has developed specific potential calculation formulas based on these mechanistic methods. For CO₂ geological storage in saline aquifers, potential calculation formulas have been established for structural trapping, capillary trapping, and dissolution trapping. The total geological potential can be considered the sum of the potentials corresponding to these three mechanisms.

Structural trapping is a primary mechanism for CO₂ geological storage in saline aquifers. By working in tandem with hydrodynamic trapping, CO₂ is effectively captured and stored within the aquifer. The following are the calculation formulas used to estimate the CO₂ sequestration potential under these mechanisms:

$$P_{{\mathrm{geol}}_{\mathrm{ts}}}=V_{\mathrm{trap}}\cdot \varphi \cdot (1-S_{\mathrm{wirr}})\cdot {\rho }_{{\mathrm{CO}}_2}=A\cdot h\cdot \varphi \cdot (1-S_{\mathrm{wirr}})\cdot {\rho }_{{\mathrm{CO}}_2}\cdot E_{\mathrm{geol}}$$

(2)

where P_geolts represents the CO₂ sequestration potential through structural trapping in deep saline aquifers, in kg. V_trap is the volume of the structural or reservoir trap in m³. ϕ represents the reservoir porosity in %. S_wirr is the residual water saturation, which is the volume of water in the rock pores after CO₂ displacement divided by the total pore volume, expressed as %. ρ_CO2 is the density of CO₂ in the reservoir, in kg/m³. A represents the reservoir area in square m². h is the reservoir thickness in m. E_geol is the geological coefficient, dimensionless.

Capillary trapping is a mechanism that takes place during the migration of CO₂ in saline aquifers. Due to the interfacial tension between the gas and liquid phases, a portion of the CO₂ becomes trapped on mineral surfaces or within rock pores, remaining in a discontinuous state for an extended period. The following formulas are used to calculate the potential of capillary trapping:

$$P_{{\mathrm{geol}}_{\mathrm{tr}}}=\mathsf{\Delta }{V}_{\mathrm{trap}}\cdot \varphi \cdot S_{{\mathrm{CO}}_2\mathrm{t}}\cdot {\rho }_{{\mathrm{CO}}_2}\cdot E_{\mathrm{geol}}$$

(3)

where P_geoltr represents the geological potential of CO₂ sequestration through capillary trapping in saline aquifers, in kg. ΔV_trap is the volume of rock that was initially saturated with CO₂ and then invaded by water, in m³. S_CO2t represents the saturation of residual CO₂ after immiscible displacement, expressed as %. ϕ represents the reservoir porosity, in %. ρ_CO2 is the density of CO₂ in the reservoir, in kg/m³. E_geol is the geological coefficient, dimensionless.

Dissolution trapping refers to the process where CO₂ is sequestered by dissolving into the formation water of deep saline aquifers. The amount of CO₂ that can be trapped through this mechanism is considered the maximum amount that can dissolve when the formation water reaches CO₂ saturation. The calculation formula is as follows:

$$P_{{\mathrm{geol}}_{\mathrm{bl}}}=A\cdot h\cdot \varphi \cdot \left({\rho }_{\mathrm{s}}{X}_{\mathrm{s}}^{{\mathrm{CO}}_2}-{\rho }_{\mathrm{i}}{X}_{\mathrm{i}}^{{\mathrm{CO}}_2}\right)\approx A\cdot h\cdot \varphi \cdot {\rho }_i\cdot R_{{\mathrm{CO}}_2}\cdot m_{{\mathrm{CO}}_2}\cdot E_{\mathrm{geol}}$$

(4)

where P_geoltd represents the geological potential of CO₂ sequestration through dissolution in deep saline aquifers, in kg. A is the reservoir area in m²_. h is the reservoir thickness in m. φ is the reservoir porosity in %. ρ_s is the average density of the formation water when it is saturated with CO₂, in kg/m³. ρ_i is the density of the initial formation water, in kg/m³. X_s^CO₂ is the average mass fraction of CO₂ in the formation water when it is saturated, expressed as %. X_i^CO₂ is the average mass fraction of the initial CO₂ in the formation water, dimensionless. R_CO2 is the solubility of CO₂ in the formation water, in mol/kg. m_CO2 is the molar mass of CO₂, 0.044 kg/mol. E_geol is the geological coefficient, dimensionless.

5.1.3. Potential and Geometric Heads in CO₂ Injection

In evaluating pressure build-up in CO₂ injection for geological storage, it is essential to understand the roles of the potential head and the geometric head [76]. The pressure build-up, as outlined in the equation, is determined by several factors, including the extent of the injected CO₂ plume (potential head) and the fixed boundary within which pressure changes are significant (geometric head). This relationship can be formalized as follows:

$$\mathrm{}\mathsf{\Delta }p(r,t)={\displaystyle \frac{Q{\mu }_w}{2\pi kH}}\times \left\{\begin{array}{ll}{\displaystyle \frac{{\mu }_c}{{\mu }_w}}\ln \left({\displaystyle \frac{\psi }{r}}\right)+\ln \left({\displaystyle \frac{R}{\psi }}\right),\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}& \mathrm{for} r\le \psi \\ \\ \ln \left({\displaystyle \frac{R}{r}}\right),\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}& \mathrm{for} \psi <r<R\\ 0,\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}& \mathrm{for} r\ge R\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}\hspace{0.25em}\end{array}\right.$$

(5)

where $\mathsf{\Delta }p(r,t)$: The pressure build-up at time $t$ and radial distance $r$ from the injection well. $Q$: The volumetric injection rate of CO₂ in m³/s. ${\mu }_w$: The dynamic viscosity of the resident brine in Pa·s. $k$: The reservoir’s absolute permeability in m². $H$: The average thickness of the reservoir in m. ${\mu }_c$: The dynamic viscosity of CO₂ in Pa·s. $\psi$: The potential head, representing the dynamic radius of the CO₂ plume as it displaces brine over time. $r$: The radial distance from the injection well in m. $R$: The geometric head, or radius of influence, which denotes the boundary beyond which the effects of pressure from CO₂ injection are negligible.

The roles of the potential and geometric heads are fundamental in managing pressure build-up during CO₂ injection into geological reservoirs. The potential head ψ represents the dynamically expanding front of the injected CO₂ plume. It characterizes the moving boundary of CO₂ saturation within the reservoir, which depends on time, injection rate, and fluid properties. As CO₂ is injected, the potential head advances outward, influencing the region’s pressure distribution. In contrast, the geometric head R defines the outermost limit of the pressure impact due to injection, beyond which reservoir conditions remain stable. The interplay between these two heads ensures that injected CO₂ is optimally stored while keeping pressure within safe operational limits. The potential head’s dynamic nature indicates that injection strategies must adapt to ongoing reservoir changes, while the geometric head provides a reference for the maximum safe distance for CO₂ displacement. These concepts are crucial for understanding CO₂ storage efficiency, containment security, and environmental safety. Together, they guide effective CO₂ sequestration practices by balancing injection rates and monitoring pressure distribution.

5.2. Technical Capacity

Technical capacity is determined by multiplying the geological potential by a coefficient that accounts for technical factors. This coefficient, often referred to as the effective coefficient, currently lacks a universally accepted method for its determination. Various organizations recommend different parameter values. For instance, the Carbon Sequestration Leadership Forum suggests setting the coefficient E within a range of 1% to 4%. The U.S. Department of Energy recommends a range of 0.8% to 6%, while the International Energy Agency Greenhouse Gas R&D Programme advises a range of 2.4% to 10% for E [4]. The U.S. Department of Energy has also provided recommended values for E_sweep for three different types of rocks: clastic rocks, dolomite, and limestone (

Table 1. Recommended values of E_sweep [4].

Lithology	P10	P50	P90
clastic rock	7.4%	14%	24%
dolomite	16%	21%	26%
limestone	10%	15%	21%

Note: P₁₀, P₅₀, and P₉₀ represent confidence levels, indicating that there is a 10% probability that the value is less than or equal to P₁₀, a 50% probability that the value is less than or equal to P₅₀, and a 90% probability that the value is less than or equal to P₉₀.

). The displacement coefficient E_sweep is calculated as the product of the volumetric sweep efficiency E_v and the microscopic displacement efficiency E_d. Several factors, including reservoir properties, water chemistry, pressure, temperature, and relative permeability, can influence the value of the displacement coefficient E_sweep.

$$E_{\mathrm{sweep}}=E_{\mathrm{v}}·E_{\mathrm{d}}$$

(6)

where E_sweep refers to the volumetric sweep efficiency, and E_v represents the ratio of the CO₂ reservoir volume within the effective thickness range, influenced by the density difference between CO₂ and formation water, to the total reservoir volume. Meanwhile, E_d is the microscopic displacement efficiency, indicating the proportion of pore space in the reservoir that remains unsequestered due to the presence of stagnant fluid. Although the values of E_sweep are available in Table 1, they may vary depending on geological conditions and injection processes.

To obtain more reliable technical capacity estimates, it is recommended to conduct targeted studies, including laboratory experiments, statistical analyses, and numerical simulations. Considering the complexity of China’s geological background and the significant variations in reservoir parameters across different sedimentary basins and saline aquifers, it is crucial to perform relevant laboratory and numerical modeling studies. These efforts will aid in developing evaluation methods tailored to China’s specific conditions, facilitating the determination of more accurate and reliable sequestration coefficients.

5.3. Technical and Economic Capacity

The cost coefficient E_cost reflects the economic feasibility of CO₂ geological storage in saline aquifers. It can be derived from economic budgets, cost estimation models, and policy documents. During the demonstration phase of CO₂ geological storage in saline aquifers, where carbon pricing or carbon trading policies are not yet established, the cost coefficient E_cost is estimated to be around 0. However, as efforts toward carbon neutrality progress, it is anticipated to approach 1 by 2060. Li et al. (2019) put forward recommended values for E_cost pertaining to high- and low-concentration industrial carbon sources, utilizing a carbon capture and storage matching model. For specific values, please consult

Table 2. Recommended values of E_cost [1].

Carbon Trading Price (CNY Per Ton)	High-Concentration Carbon Sources (Coal Chemical Industry)	Low-Concentration Carbon Sources (Industrial Emissions Excluding Coal Chemical Industry)
200	70%	1–5%
350	80%	20–40%
500	90%	40–60%

, which presents benchmarks as of 2020 [1].

5.4. Engineering Storage Volume

5.4.1. Design Storage Capacity

Assessing the design storage volume requires detailed data, including the spatial extent of the storage site, injection duration, and the planned CO₂ injection quantity. Additionally, information on the layout of injection wells and monitoring wells is crucial. Numerical simulation techniques play a vital role in evaluating the design storage volume. For instance, in the Shenhua CCS Demonstration Project—the first saline aquifer storage demonstration project in China—researchers utilized three-dimensional seismic data, drilling records, logging, and experimental test results to estimate a design storage volume of 100,000 tons per year over a 3-year injection period [2,3]. They also investigated the migration and distribution characteristics of CO₂ within the underground reservoir.

5.4.2. Actual Storage Capacity

To ensure the safety, stability, and prevention of CO₂ leakage in a storage project, the wellhead injection volume can be regarded as the actual amount of carbon dioxide injected. Due to uncertainties in geological formations, the actual storage capacity may sometimes fall short of the design storage capacity. Conversely, dynamic monitoring results may reveal that the final actual storage capacity exceeds the initially planned design capacity. When planning or implementing new storage projects near a closed and sealed storage site, it is advisable to reference the actual storage capacity of the closed site. This helps adjust the design storage capacity to ensure the safety and stability of the underground CO₂ reservoir. To balance safety, stability, and enhance the efficiency of reservoir utilization, it is crucial to perform timely dynamic assessments of the technically recoverable capacity and the economically viable capacity. These assessments should be based on data collected during the injection process and practical experience, ensuring the feasibility of the storage project and providing valuable guidance for future planning and implementation.

6. Discussion

This study has systematically reviewed the characteristics of key saline aquifer CO₂ storage projects and outlined a robust framework for categorizing, evaluating, and implementing CO₂ sequestration in saline aquifers. Saline aquifer CO₂ storage represents a critical component of carbon capture and storage (CCS) technologies, which are increasingly recognized as indispensable for meeting global carbon reduction goals. By focusing on geological structures, reservoir properties, caprock integrity, and seismic monitoring, this study provides a comprehensive foundation for advancing CO₂ storage solutions in complex geological formations. The proposed classification and evaluation model, structured across geological, technical, economic, and engineering dimensions, enables a more nuanced approach to evaluating storage potential and aligns with key phases of geological exploration, from survey through to injection. This multi-dimensional model stands to improve CCS strategy at local and national scales, supporting efficient, secure, and scalable CO₂ storage solutions.

The four-tier classification system—encompassing geological potential, technical capacity, technical-economic capacity, and engineering storage capacity—has significant implications for the planning and scaling of CCS technologies. This model enables stakeholders to delineate and prioritize sites based on current geological understanding, technical feasibility, and economic viability, providing a tailored approach to CCS deployment. In addition, this classification aids in aligning CCS practices with regional or national carbon neutrality goals by allowing engineers and policymakers to assess which levels of capacity are suitable for immediate implementation versus long-term development. In regions with high carbon output but limited geological data, this model serves as a flexible and scalable tool, enabling stakeholders to initiate CCS projects with an understanding of both immediate and evolving capacity considerations. The categorization into potential levels also underscores the foundational role of geological and technical assessments, which provide crucial data on static storage capacity. Static storage potential, derived from theoretical geological estimates, serves as the baseline for understanding a reservoir’s sequestration ability before more dynamic evaluations. However, by integrating technical, economic, and engineering considerations, this study highlights the importance of moving beyond static capacity estimates toward dynamic, real-time assessments that account for injection rates, pressure impacts, and ongoing economic factors. This approach not only informs initial project planning but also ensures sustainable, adaptable management of CO₂ storage projects over time.

While this study offers a structured classification model, practical implementation of CCS in saline aquifers still faces notable challenges. One significant issue is the inherent variability in geological formations across different sedimentary basins, which impacts the reliability and comparability of storage potential estimates. The study’s emphasis on site-specific classification helps address this by encouraging regional adaptations; however, significant work remains in standardizing approaches to deal with reservoir heterogeneity and uncertainty. To this end, this study recommends the use of advanced laboratory experiments, extensive numerical simulations, and pilot projects to validate and refine theoretical capacity estimates, especially in regions like China, where diverse sedimentary environments complicate predictions. Another challenge lies in calculating technical capacity, which incorporates variable coefficients influenced by fluid and reservoir properties, caprock stability, and injection dynamics. Parameters such as the displacement coefficient and cost coefficient are not fixed and require adaptation based on site-specific conditions. Additionally, technical-economic capacity is impacted by external factors such as carbon pricing, policy incentives, and infrastructure costs, which vary globally and can shift over time. Further research to refine these coefficients will be critical for achieving accurate, reliable, and cost-effective CCS operations, particularly in emerging economies with fluctuating market and regulatory environments.

The study’s focus on mechanistic methods for calculating CO₂ sequestration capacity within saline aquifers offers valuable insights into the long-term dynamics of CCS. Mechanistic methods account for capture mechanisms such as structural, capillary, dissolution, and mineralization trapping. Each of these mechanisms operates on a different time scale, impacting the effectiveness and security of CO₂ storage over both short and extended periods. For example, structural and hydrodynamic trapping are immediately effective, helping to stabilize injected CO₂ within the reservoir and maintain pressure. In contrast, dissolution trapping and mineralization trapping unfold gradually, with mineralization processes taking centuries to millennia. This time-lagged process, while slow, ultimately locks CO₂ in a highly stable solid form, offering long-term sequestration security. This study’s mechanistic model emphasizes that while immediate capture methods like structural trapping provide initial storage, the cumulative impact of slower processes like mineralization contributes to the sustainability of CCS projects. This layered approach to storage offers a strategic advantage in managing long-term CO₂ containment, especially in settings where extended monitoring and adaptive management are feasible. The findings highlight the need to account for the temporal dynamics of capture mechanisms when evaluating storage potential, ensuring that CCS projects not only achieve immediate sequestration targets but also contribute to long-term carbon reduction goals.

An innovative aspect of this study is the exploration of artificial aquifer recharge as a complementary strategy for CO₂ storage. Controlled aquifer recharge involves injecting treated water—such as reclaimed wastewater or desalinated water—into reservoirs, which can stabilize pressure and enhance mineralization reactions by promoting favorable chemical conditions. In arid or water-stressed regions, this approach offers a dual benefit: it augments water resources while supporting CO₂ sequestration efforts. This dual functionality aligns with broader sustainability and climate resilience goals, providing a model for multi-purpose reservoir management. However, this technique requires rigorous water quality monitoring and advanced filtration processes to prevent contamination, along with adaptive management to mitigate potential risks such as land subsidence and aquifer clogging. The integration of water management and CCS thus presents an opportunity for advancing sustainable practices in both resource conservation and carbon reduction. As climate change intensifies global water scarcity, techniques like artificial recharge may play an increasingly vital role, especially in regions where the demand for water and the need for carbon mitigation converge.

The study reinforces the importance of comprehensive monitoring systems for ensuring the effectiveness and safety of saline aquifer CO₂ storage. The use of multi-modal seismic surveys, satellite-based monitoring, and wellhead sampling offers an effective approach to track CO₂ plume migration, detect potential leaks, and measure pressure changes in real time. By capturing temporal variations in reservoir conditions, these technologies enable operators to make informed adjustments to injection rates, pressure thresholds, and other operational parameters, preventing environmental risks such as induced seismicity and leakage. Furthermore, adaptive management strategies, such as periodic recalibration of injection protocols and updating capacity estimates based on real-time data, will enhance the resilience and flexibility of CCS projects. The implementation of advanced monitoring techniques is also critical for regulatory compliance, public transparency, and stakeholder confidence in CCS technologies. Continuous monitoring and data sharing with regulatory agencies and local communities can mitigate concerns regarding environmental safety, thereby promoting wider acceptance and adoption of CCS as a climate solution.

7. Conclusions

The Sleipner CO₂ geological storage project injects hundreds of thousands of tons of CO₂ per year into each well. The project area is large, the structure is simple without faults, the interbeds are well-developed, and the sealing properties are excellent. The reservoir sand bodies are stable, thick, and possess good physical properties, injection capacity, and storage capacity. The caprock is also stable and thick.

By comparing the geological characteristics—including structure, sedimentation, reservoir, and caprock—of important saline aquifer storage projects such as Sleipner, In Salah, Snøhvit, and Shenhua, it becomes evident that the presence of a large anticline structure in the Sleipner project is key to the successful geological storage of CO₂. In contrast, the presence of faults in the Snøhvit project and fractures in the In Salah project highlight the potential for CO₂ geological storage in different structural types. Additionally, the actual distribution of CO₂ plumes is largely controlled by geological features. Further, 3D/4D seismic monitoring provides detailed information on CO₂ plume distribution and reservoir characteristics, while continuous measurements of downhole temperature and pressure help eliminate uncertainties in wellbore calculations. High-quality monitoring data can also significantly reduce the risk of potential leakage.

As a critical technology supporting China’s carbon neutrality goals, it is essential to establish a unified evaluation framework and methodology for assessing the potential of saline aquifer CO₂ geological storage. This evaluation should occur across four stages—survey, detailed investigation, exploration, and injection—considering geological, technical, economic, and engineering conditions. Storage potential/capacity can be classified into four categories: geological potential, technical capacity, technical-economic capacity, and engineering storage capacity. The survey stage corresponds to the prediction level (D-level), the detailed investigation stage corresponds to the control level (C-level), the exploration stage corresponds to the technically recoverable level (B-level), and the injection stage corresponds to the engineering level (A-level).

Evaluating the potential for saline aquifer CO₂ geological storage requires establishing a dynamic, multi-scale, and multi-level mechanism that ranges from low to high accuracy. The evaluation process includes reservoir selection, potential classification, and potential/capacity calculation. Reservoir selection must consider reservoir conditions, caprock integrity, storage stability, and the impact on deep resource exploitation (such as coal, oil, and gas) to determine effective reservoirs for potential calculations.

Currently, potential calculations mainly utilize volumetric and mechanistic methods, but the application scenarios for different levels of potential/capacity calculations vary. At the technically recoverable level, assessing storage technical capacity requires numerical simulation and predictive evaluation based on various injection scenarios. A key research challenge in this field is determining the values of the displacement coefficient and cost coefficient, which necessitates extensive laboratory testing, numerical simulation, and engineering practice data for accurate determination.